Exhibit 99.01

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

Restatement of Prior Financial Information

The following discussion should be read in conjunction with our Consolidated Financial Statements and the notes related to those consolidated financial statements contained in “Item 8. Financial Statements and Supplementary Data” of this Current Report on Form 8-K/A. All applicable disclosures in the following discussion have been modified to reflect the restatement, as described in Note 2 to the Consolidated Financial Statements.

Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Forward Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of PSCo during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the respective accompanying Consolidated Financial Statements and Notes to the Consolidated Financial Statements.

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of PSCo to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership, structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under “Risk Factors” in Item 1A and Exhibit 99.01 of PSCo’s Form 10-K for the year ended Dec. 31, 2006.

Results Of Operations

PSCo’s net income was approximately $241.5 million for 2006, compared with approximately $211.4 million for 2005.

Electric Utility, Short-Term Wholesale and Commodity Trading Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for customers, most fluctuations in these costs do not materially affect electric utility margin.

PSCo has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy-related purchase and sales activity and the use of certain financial instruments associated with the fuel required for, and energy produced from, PSCo’s generation assets or the energy and capacity purchased to serve native load. Commodity trading is not associated with PSCo’s generation assets or the energy and capacity purchased to serve native load. Short-term wholesale and commodity trading activities are considered part of the electric utility segment.

Margins from commodity trading activity conducted at PSCo are partially redistributed to Northern States Power Company, a Minnesota Corporation (NSP-Minnesota) and Southwestern Public Service Company, a New Mexico Corporation (SPS), both wholly owned subsidiaries of Xcel Energy, pursuant to the JOA approved by the FERC. Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenue. Short-term wholesale and commodity trading margins reflect the impact of regulatory sharing, if applicable. Trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Income. Commodity trading costs include purchased power, transmission, broker fees and other related costs. Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of margins, if applicable.

The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities:

	Base
	Electric			Short-Term			Commodity			Consolidated
(Millions of Dollars)	Utility			Wholesale			Trading			Totals
2006
Electric utility revenue (excluding commodity trading)	$	2,472		$	29		$	—		$	2,501
Fuel and purchased power	(1,465		)	(25		)	—			(1,490		)
Commodity trading revenue	—			—			466			466
Commodity trading costs	—			—			(461		)	(461		)
Gross margin before operating expenses	$	1,007		$	4		$	5		$	1,016
Margin as a percentage of revenue	40.7		%	13.8		%	1.1		%	34.2		%

2005
Electric utility revenue (excluding commodity trading)	$	2,486		$	17		$	—		$	2,503
Fuel and purchased power	(1,491		)	(16		)	—			(1,507		)
Commodity trading revenue	—			—			600			600
Commodity trading costs	—			—			(599		)	(599		)
Gross margin before operating expenses	$	995		$	1		$	1		$	997
Margin as a percentage of revenue	40.0		%	5.9		%	0.2		%	32.1		%

The following summarizes the components of the changes in base electric revenue and base electric margin for the year ended Dec. 31:

Base Electric Revenue

(Millions of Dollars)	2006 vs 2005
Sales growth	$	12
Non-fuel riders	11
Service quality adjustment	8
Gain on sale of SO2 allowances	4
Retail fuel cost recovery	(15		)
Firm wholesale revenue, including fuel	(13		)
Sales mix	(10		)
Capacity sales	(10		)
Other	(1		)
Total base electric revenue decrease	$	(14	)

Base Electric Margin

(Millions of Dollars)	2006 vs 2005
Fuel and purchased power cost recovery	$	21
Sales growth	12
Non-fuel riders	11
Service quality adjustment	8
Gain on sale of SO2 allowances	4
ECA incentive	(20		)
Fuel handling & procurement costs	(10		)
Capacity sales	(10		)
Sales mix and other	(4		)
Total base electric margin increase	$	12

Natural Gas Utility Revenue and Margins — The following table details the change in natural gas revenue and margin. The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. PSCo has a GCA mechanism for natural gas sales, which recognizes the majority of the effects of changes in the cost of natural gas purchased for resale and adjusts revenues to reflect such changes in costs upon request by PSCo. Therefore, fluctuations in the cost of natural gas have little effect on natural gas margin.

(Millions of Dollars)	2006			2005
Natural gas utility revenue	$	1,262		$	1,329
Cost of natural gas purchased and transported	(938		)	(1,032		)
Natural gas utility margin	$	324		$	297

The following summarizes the components of the changes in natural gas revenue and margin for the year ended Dec. 31:

Natural Gas Revenue

(Millions of Dollars)	2006 vs 2005
Base rate change	$	18
Transportation	9
Sales growth (excluding weather impact)	2
Purchased gas adjustment clause recovery	(87		)
Other	(9		)
Total natural gas revenue decrease	$	(67	)

Natural Gas Margin

(Millions of Dollars)	2006 vs 2005
Base rate change	$	18
Transportation	8
Sales growth (excluding weather impact)	1
Estimated impact of weather	1
Other	(1		)
Total natural gas margin increase	$	27

Non-Fuel Operating Expense and Other Costs — Other operating and maintenance expenses for 2006 increased $22 million, or 4.1 percent, compared to 2005. The following summarizes the components of the changes for the year ended Dec. 31:

(Millions of Dollars)	2006 vs 2005
Higher employee benefit costs	$	19
Higher plant costs	7
Higher materials costs	2
Higher uncollectible receivable costs	2
Higher transportation fleet costs	2
Lower consulting/contractor costs	(6		)
Gains/losses on sale or disposals of assets, net	(6		)
Other	2
Total non-fuel operating expense increase	$	22

Depreciation and amortization expense increased by approximately $1.5 million, or 0.6 percent, for 2006 compared with 2005, primarily due to plant additions and higher regulatory amortization of demand side management costs, offset by lower amortization related to Fort. St. Vrain, which was fully amortized at the end of 2005.

Taxes (other than income taxes) decreased by approximately $2.6 million, or 2.8 percent, for 2006 compared with 2005, primarily due to lower property taxes relating to a change in 2005 valuation and the 2006 estimate.

Interest and other income (expense), net, decreased by approximately $2.3 million primarily due to higher interest expense on COLI loans, partially offset by higher interest income from the COLI life insurance investments.

Interest charges and financing costs decreased by approximately $7.3 million, or 5.1 percent, for 2006 compared with 2005, primarily due to the retirement of long-term debt in November 2005 and June 2006, partially offset with increased short-term borrowings.

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. Of this amount, debt related AFDC increased

by approximately $8.8 million and equity related AFDC was consistent with 2005 levels.

Income tax expense increased by approximately $11.5 million in 2006, compared with 2005. The increase was primarily due to higher pretax income. The effective tax rate was 25.3 percent for 2006, compared with 24.9 percent for 2005.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, PSCo is exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity related instruments, including derivatives, are subject to market risk. These risks, as applicable to PSCo, are discussed in further detail below.

Commodity Price Risk — PSCo is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products, and for various fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. PSCo’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists, as allowed by regulation.

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various short-term wholesale and commodity trading activities, including the purchase and sale of capacity, energy and energy related instruments. These marketing activities generally have terms of less than one year in length. PSCo’s risk management policy allows management to conduct the marketing activities within guidelines and limitations as approved by the company’s risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

Certain contracts within the scope of these activities qualify for hedge accounting treatment under SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activities”.

See Note 11 to the Consolidated Financial Statements for a discussion of the various trading and hedging contracts of PSCo.

PSCo’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given confidence interval under normal market conditions. PSCo utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and a three-day holding period for both electricity and natural gas.

VaR is calculated on a consolidated basis. The VaRs for the commodity trading operations were:

	Year ended		During 2006
(Millions of Dollars)	Dec. 31, 2006		Average		High		Low

Commodity trading (a)	$	0.49	$	1.32	$	2.60	$	0.39

	Year ended		During 2005
(Millions of Dollars)	Dec. 31, 2005		Average		High		Low

Commodity trading (a)	$	2.06	$	1.44	$	4.43	$	0.26

(a) Comprises transactions for NSP-Minnesota, PSCo and SPS.

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars)

	Year Ended Dec. 31
	2006			2005			2004
	(As Restated See Note 2)			(As Restated See Note 2)			(As Restated See Note 2)
Operating revenues
Electric utility	$	2,505,445		$	2,504,028		$	2,194,628
Natural gas utility	1,262,295			1,329,034			1,073,989
Steam and other	38,089			33,501			27,825
Total operating revenues	3,805,829			3,866,563			3,296,442

Operating expenses
Electric fuel and purchased power	1,489,714			1,507,248			1,242,684
Cost of natural gas sold and transported	938,380			1,032,504			785,055
Cost of sales — steam and other	21,043			19,231			17,383
Operating and maintenance expenses	569,059			546,608			510,157
Depreciation and amortization	239,916			238,402			223,442
Taxes (other than income taxes)	88,878			91,438			86,671
Total operating expenses	3,346,990			3,435,431			2,865,392

Operating income	458,839			431,132			431,050

Interest and other income (expense), net	(14,223		)	(11,884		)	24
Allowance for funds used during construction - equity	2,650			2,655			9,809

Interest charges and financing costs
Interest charges — including financing costs of $6,029, $6,744, and $7,353, respectively	137,493			144,835			157,447
Allowance for funds used during construction - debt	(13,386		)	(4,589		)	(7,425		)
Total interest charges and financing costs	124,107			140,246			150,022

Income before income taxes	323,159			281,657			290,861
Income taxes	81,701			70,240			72,856
Net income	$	241,458		$	211,417		$	218,005

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

	Year Ended Dec. 31
	2006			2005			2004
	(As Restated See Note 2)			(As Restated See Note 2)			(As Restated See Note 2)
Operating activities
Net income	$	241,458		$	211,417		$	218,005
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	253,725			251,668			234,164
Deferred income taxes	76,040			111,455			79,493
Amortization of investment tax credits	(3,949		)	(3,971		)	(4,000		)
Allowance for equity funds used during construction	(2,650		)	(2,655		)	(9,809		)
Net realized and unrealized hedging and derivative transactions	(19,497		)	17,684			(31,251		)
Changes in operating assets and liabilities
Accounts receivable	133,691			(137,782		)	(107,652		)
Accrued unbilled revenues	35,253			(61,760		)	(17,819		)
Inventories	34,865			(56,043		)	(31,781		)
Recoverable purchased natural gas and electric energy costs	72,566			(58,178		)	(27,068		)
Other current assets	(2,591		)	(2,901		)	29,691
Accounts payable	(187,571		)	154,481			22,894
Net regulatory assets and liabilities	(36,008		)	(68,504		)	(119,867		)
Other current liabilities	19,256			6,193			(5,222		)
Change in other noncurrent assets	(2,154		)	(5,181		)	61,609
Change in other noncurrent liabilities	(29,893		)	29,870			45,672
Net cash provided by operating activities	582,541			385,793			337,059

Investing activities
Capital/construction expenditures	(537,920		)	(424,292		)	(457,365		)
Proceeds from disposition of property, plant and equipment	—			—			11,682
Allowance for equity funds used during construction	2,650			2,655			9,809
Other investments	9,869			6,520			(1,691		)
Net cash used in investing activities	(525,401		)	(415,117		)	(437,565		)

Financing activities
Short-term borrowings — net	36,896			138,649			182,914
Proceeds from issuance of long-term debt	—			129,500			—
Borrowings under utility money pool arrangement	1,426,800			—			—
Repayments under utility money pool arrangement	(1,426,800		)	—			—
Borrowings under 5-year unsecured credit facility	—			293,000			—
Repayments under 5-year unsecured credit facility	—			(293,000		)	—
Repayment of long-term debt, including reacquisition premiums	(126,334		)	(375,354		)	(147,000		)
Capital contribution from parent	227,272			202,029			184,123
Dividends paid to parent	(195,625		)	(62,564		)	(243,906		)
Net cash provided by (used in) financing activities	(57,791		)	32,260			(23,869		)

Net increase (decrease) in cash and cash equivalents	(651		)	2,936			(124,375		)
Cash and cash equivalents at beginning of year	3,662			726			125,101
Cash and cash equivalents at end of year	$	3,011		$	3,662		$	726

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	125,284		$	139,414		$	151,424
Cash paid for income taxes (net of refunds received)	(6,640		)	(16,042		)	16,203

Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	5,367		$	13,404		$	14,291

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)

	Dec. 31,
	2006			2005
	(As Restated See Note 2)			(As Restated See Note 2)
ASSETS
Current assets:
Cash and cash equivalents	$	3,011		$	3,662
Accounts receivable — net of allowance for bad debts: $18,415 and $19,381, respectively	355,738			451,944
Accounts receivable from affiliates	8,621			47,746
Accrued unbilled revenues	199,361			234,614
Recoverable purchased natural gas and electric energy costs	157,827			230,393
Materials and supplies inventories — at average cost	43,029			42,602
Fuel inventory — at average cost	40,997			19,582
Natural gas inventory — at average cost	155,567			212,274
Derivative instruments valuation-at market	28,111			78,064
Deferred income taxes	62,791			19,781
Prepayments and other	14,654			15,437
Total current assets	1,069,707			1,356,099
Property, plant and equipment, at cost:
Electric utility plant	6,409,194			6,275,046
Natural gas utility plant	1,825,560			1,793,240
Common utility and other property	725,864			745,894
Construction work in progress	429,878			209,721
Total property, plant and equipment	9,390,496			9,023,901
Less accumulated depreciation	(2,912,233		)	(2,854,757		)
Net property, plant and equipment	6,478,263			6,169,144
Other assets:
Regulatory assets	589,016			231,801
Derivative instruments valuation-at market	161,502			164,251
Other investments	19,347			29,465
Other	45,784			35,191
Total other assets	815,649			460,708
Total assets	$	8,363,619		$	7,985,951

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	101,379		$	126,334
Short-term debt	372,500			335,604
Accounts payable	385,724			578,722
Accounts payable to affiliates	30,291			26,388
Taxes accrued	84,960			81,638
Dividends payable to parent	64,778			—
Derivative instruments valuation-at market	38,616			66,463
Accrued interest	35,362			36,498
Other	74,381			71,206
Total current liabilities	1,187,991			1,322,853
Deferred credits and other liabilities:
Deferred income taxes	1,004,027			811,961
Deferred investment tax credits	59,035			62,984
Regulatory liabilities	470,255			492,335
Pension and Employee Benefit Obligations	301,277			148,255
Customers advances for construction	279,011			288,397
Asset retirement obligations	43,335			41,968
Derivative instruments valuation-at market	156,623			170,849
Other liabilities	7,750			18,387
Total deferred credits and other liabilities	2,321,313			2,035,136
Commitments and contingent liabilities
Capitalization (See Statements of Capitalization):
Long-term debt	1,845,278			1,945,973
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares	—			—
Additional paid in capital	2,411,204			2,183,932
Retained earnings	585,219			604,163
Accumulated other comprehensive income (loss)	12,614			(106,106		)
Total common stockholder’s equity	3,009,037			2,681,989
Total liabilities and equity	$	8,363,619		$	7,985,951

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME

(Dollars in Thousands)

									Accumulated
									Other			Total
	Common Stock			Additional		Retained			Comprehensive			Stockholder’s
	Shares	Amount		Paid in Capital		Earnings			Income (loss)			Equity
Balance at Dec. 31, 2003	100	$	—	$	1,797,780	$	421,614		$	(79,426	)	$	2,139,968
Net income						218,005						218,005
Minimum pension liability adjustment, net of tax of $(4,202)									(7,317		)	(7,317		)
Net derivative instrument fair value changes during the period, net of tax of $(947)									(1,475		)	(1,475		)
Unrealized gain — marketable securities, net of tax of $74									121			121
Comprehensive income for 2004												209,334
Common dividends declared to parent						(246,873		)				(246,873		)
Contribution of capital by parent				184,123								184,123
Balance at Dec. 31, 2004	100	$	—	$	1,981,903	$	392,746		$	(88,097	)	$	2,286,552
Net income						211,417						211,417
Minimum pension liability adjustment, net of tax of $(9,898)									(16,644		)	(16,644		)
Net derivative instrument fair value changes during the period, net of tax of $(936)									(1,482		)	(1,482		)
Unrealized gain — marketable securities, net of tax of $71									117			117
Comprehensive income for 2005												193,408
Contribution of capital by parent				202,029								202,029
Balance at Dec. 31, 2005	100	$	—	$	2,183,932	$	604,163		$	(106,106	)	$	2,681,989
Net income						241,458						241,458
Minimum pension liability adjustment, net of tax of $19,239									31,589			31,589
Net derivative instrument fair value changes during the period, net of tax of $(981)									(1,607		)	(1,607		)
Unrealized loss — marketable securities, net of tax of $(46)									(75		)	(75		)
Comprehensive income for 2006												271,365
SFAS No. 158 adoption, net of tax of $53,995									88,813			88,813
Common dividends declared to parent						(260,402		)				(260,402		)
Contribution of capital by parent				227,272								227,272
Balance at Dec. 31, 2006	100	$	—	$	2,411,204	$	585,219		$	12,614		$	3,009,037

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Thousands of Dollars)

	Dec. 31
	2006			2005
Long-Term Debt
First Mortgage Bonds, Series due:
June 1, 2006, 7.125%	$	—		$	125,000
Oct. 1, 2008, 4.375%	300,000			300,000
Oct. 1, 2012, 7.875%	600,000			600,000
March 1, 2013, 4.875%	250,000			250,000
April 1, 2014, 5.5%	275,000			275,000
Sept. 1, 2017, 4.375% (a)	129,500			129,500
Jan. 1, 2019, 5.1% (a)	48,750			48,750
Unsecured Senior A Notes, due July 15, 2009, 6.875%	200,000			200,000
Secured Medium-Term Notes, due March 5, 2007, 7.11%	100,000			100,000
Capital lease obligations, 11.2% due in installments through 2028	46,247			47,581
Unamortized discount	(2,840		)	(3,524		)
Total	1,946,657			2,072,307
Less current maturities	101,379			126,334
Total long-term debt	$	1,845,278		$	1,945,973

Common Stockholder’s Equity
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares in 2006 and 2005	$	—		$	—
Additional paid in capital	2,411,204			2,183,932
Retained earnings	585,219			604,163
Accumulated other comprehensive income (loss)	12,614			(106,106		)
Total common stockholder’s equity	$	3,009,037		$	2,681,989

(a) Pollution control financing.

See Notes to Consolidated Financial Statements

Public Service Company of Colorado

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — Public Service Company of Colorado (PSCo), a wholly owned subsidiary of Xcel Energy, Inc. (Xcel Energy), is principally engaged in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. PSCo is subject to the regulatory of the FERC and state utility commissions. All of PSCo’s accounting records conform to the Federal Energy Regulatory Commission (FERC) uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material aspects.

Principles of Consolidation — PSCo has subsidiaries, which have been consolidated and for which all significant intercompany transactions and balances have been eliminated.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated.

PSCo has various rate-adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. In addition, PSCo presents its revenue, net of any excise or other fiduciary-type taxes or fees. A summary of significant rate adjustment mechanisms follows:

· PSCo generally recovers all prudently incurred electric fuel and purchased energy costs through the retail electric commodity adjustment (ECA). The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA also provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate. The current ECA mechanism expired Dec. 31, 2006. Effective Jan. 1, 2007 the ECA has been modified to include an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy. The total incentive payment to PSCo in any calendar year will not exceed $11.25 million. The ECA mechanism will be revised quarterly and interest will accrue monthly on the average deferred balance. The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.

· In Colorado, PSCo operates under an annual earnings test in which earnings above the authorized return on equity are refunded to customers. PSCo operates under various service quality standards, which could require customer refunds if certain criteria are not met. PSCo’s rates also include monthly adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually. PSCo is allowed to recover certain costs associated with renewable energy resources through a specific retail rate rider.

· PSCo sells firm power and energy in wholesale markets, which are regulated by the FERC. Certain of these rates include monthly wholesale fuel cost-recovery mechanisms.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the Consolidated Statements of Income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value in accordance with SFAS 133. In addition, commodity trading results include the impacts of all pertinent margin-sharing mechanisms. For more information, see Note 11 to the Consolidated Financial Statements.

Derivative Financial Instruments — PSCo utilizes a variety of derivatives, including commodity forwards, futures and options, index or fixed price swaps and basis swaps, to mitigate market risks and to enhance its operations. For further discussion of PSCo’s risk management and derivative activities see Note 11 to the Consolidated Financial Statements.

Property, Plant, and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. Removal costs associated with regulatory obligations are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repair and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with other property held for future use.

PSCo records depreciation expense related to its plant by using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a period basis and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2006, 2005 and 2004 was 2.6 percent, 2.6 percent and 2.5 percent, respectively.

AFDC — AFDC represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other income (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates.

Environmental Costs — Environmental costs are recorded on an undiscounted basis when it is probable PSCo is liable for the costs and the liability can be reasonably estimated. Costs may be deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If several designated responsible parties exist, costs are estimated and recorded only for PSCo’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.

Legal Costs — Legal costs are expensed as incurred.

Income Taxes — Xcel Energy and its utility subsidiaries, including PSCo, file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss. The holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company in the consolidated federal or combined state returns. PSCo defers income taxes for all temporary differences between the book and tax bases of assets and liabilities. The tax rates used are those that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Investment tax credits are deferred and their benefits amortized over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 15 to the Consolidated Financial Statements. For more information on income taxes, see Note 8 to the Consolidated Financial Statements.

Use of Estimates — In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, asset retirement obligations, decommissioning, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information is obtained or actual amounts are determinable. Those revisions can affect operating results. Each year the depreciable lives of certain plant assets are reviewed and revised, if appropriate.

Cash and Cash Equivalents — PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Inventory — All inventories are recorded at average cost.

Regulatory Accounting — PSCo accounts for certain income and expense items in accordance with statement of financial accounting standards (SFAS) No. 71 — “Accounting for the Effects of Certain Types of Regulation.” Under SFAS No. 71:

· certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and

· certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they will be returned to customers in future rates.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment.

If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on PSCo’s results of operations in the period the write-off is recorded. See more discussion of regulatory assets and liabilities at Note 15 to the Consolidated Financial Statements.

Deferred Financing Costs — Other assets include deferred financing costs, which are amortized over the remaining maturity periods of the related debt. PSCo’s deferred financing costs, net of amortization, at Dec. 31, 2006 and 2005 were $11.4 million and $13.5 million, respectively.

Accounts Receivable and Allowance for Uncollectibles — Accounts receivable are stated at the actual billed amount net of the allowance for uncollectibles. PSCo establishes an allowance for uncollectibles based on a reserve policy that reflects its expected exposure to the credit risk of customers.

Emission Allowances — Emission allowances are recorded at cost, including the annual SO₂ and NOx emission allowance entitlement received at no cost from the Federal EPA. PSCo follows the inventory model for all allowances. The sales of allowances are reported in the Operating Activities section of the Consolidated Statements of Cash Flows. The net margin on sales of emission allowances is included in Operating Revenues as it is integral to the production process of energy and our revenue optimization strategy for our utility operations.

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

2. Restatement of Financial Statements

Subsequent to the issuance of PSCo’s consolidated financial statements for the year ended December 31, 2006 included in a Current Report on Form 8-K filed August 8, 2007, management determined that PSRI should not have been presented as a discontinued operation, as previously reported in the Form 8-K, rather, PSRI should have been included as part of continuing operations. As a result, the accompanying consolidated financial statements have been restated.

As previously reported in our Current Report on Form 8-K filed on June 20, 2007, a settlement in principle was reached between Xcel Energy and representatives of the United States government on June 19, 2007 concerning a tax dispute related to corporate-owned life insurance (COLI) policies purchased on the lives of PSCo employees. PSRI, a wholly owned subsidiary of PSCo, owned and managed these COLI life insurance policies.

The terms of the settlement are discussed in Note 14. The settlement has been implemented and the policies have been surrendered.

As a result of the settlement in principle, which required the surrender of the COLI policies, PSCo had previously classified all amounts related to PSRI as discontinued operations for all periods presented in its Forms 10-Q for the periods ended June

30, 2007 and September 30, 2007. On August 8, 2007, PSCo filed a Current Report on Form 8-K to update historical information included in its Annual Report on Form 10-K for the year ended December 31, 2006 to present PSRI as a discontinued operation. The new presentation had no effect on PSCo’s reported net income for any annual reporting period.

Pursuant to a routine review of PSCo’s periodic reports by the staff of the Securities and Exchange Commission management reassessed the appropriateness of the treatment of PSRI as discontinued operations under SFAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” and determined that PSRI operations, including the impact of the IRS settlement, should be presented as part of continuing operations for financial reporting purposes. The effect of presenting PSRI as part of continuing operations, rather than as discontinued operations as previously reported in the Form 8-K, and an immaterial change related to the classification of certain activities of PSRI within the statements of cash flows, are reflected in the tables below:

	Consolidated Statement of Income
	For the Year Ended Dec.31, 2006
(Thousands of dollars)	As Previously Reported		Adjustment			As Restated
Operating and maintenance expenses	$	564,555	$	4,504		$	569,059
Taxes (other than income taxes)	88,873		5			88,878
Total operating expenses	3,342,481		4,509			3,346,990
Operating income	463,348		(4,509		)	458,839
Interest and other income (expense), net	4,972		(19,195		)	(14,223		)
Interest charges	137,418		75			137,493
Total interest charges and financing costs	124,032		75			124,107
Income from continuing operations before income taxes	346,938		(23,779		)	323,159
Income taxes	125,952		(44,251		)	81,701
Income from continuing operations	220,986		20,472			241,458
Income (loss) from discontinued operations	20,472		(20,472		)	—

	Consolidated Statement of Income
	For the Year Ended Dec.31, 2005
(Thousands of dollars)	As Previously Reported		Adjustment			As Restated
Operating and maintenance expenses	$	543,877	$	2,731		$	546,608
Taxes (other than income taxes)	91,435		3			91,438
Total operating expenses	3,432,697		2,734			3,435,431
Operating income	433,866		(2,734		)	431,132
Interest and other income (expense), net	5,654		(17,538		)	(11,884		)
Interest charges	144,660		175			144,835
Total interest charges and financing costs	140,071		175			140,246
Income from continuing operations before income taxes	302,104		(20,447		)	281,657
Income taxes	109,764		(39,524		)	70,240
Income from continuing operations	192,340		19,077			211,417
Income (loss) from discontinued operations	19,077		(19,077		)	—

	Consolidated Statement of Income
	For the Year Ended Dec.31, 2004
(Thousands of dollars)	As Previously Reported		Adjustment			As Restated
Operating and maintenance expenses	$	508,888	$	1,269		$	510,157
Taxes (other than income taxes)	86,668		3			86,671
Total operating expenses	2,864,120		1,272			2,865,392
Operating income	432,322		(1,272		)	431,050
Interest and other income, net	15,738		(15,714		)	24
Interest charges	157,425		22			157,447
Total interest charges and financing costs	150,000		22			150,022
Income from continuing operations before income taxes	307,869		(17,008		)	290,861
Income taxes	102,638		(29,782		)	72,856
Income from continuing operations	205,231		12,774			218,005
Income from discontinued operations	12,774		(12,774		)	—

	Consolidated Balance Sheet
	December 31, 2006							December 31, 2005
(Thousands of dollars)	As Previously Reported		Adjustment			As Restated		As Previously Reported		Adjustment			As Restated
Cash and cash equivalents	$	3,011	$	—		$	3,011	$	2,848	$	814		$	3,662
Accounts receivable	332,933		22,805			355,738		420,720		31,224			451,944
Deferred income taxes	47,075		15,716			62,791		14,370		5,441			19,781
Prepayments and other	14,284		370			14,654		14,986		451			15,437
Current assets held for sale and related to discontinued operations	52,593		(52,593		)	—		41,092		(41,092		)	—
Total current assets	1,083,409		(13,702		)	1,069,707		1,359,291		(3,192		)	1,356,099
Other investments	11,136		8,211			19,347		22,004		7,461			29,465
Other assets	45,785		(1		)	45,784		35,191		—			35,191
Noncurrent assets held for sale and related to discontinued operations	15,779		(15,779		)	—		35,359		(35,359		)	—
Total other assets	823,218		(7,569		)	815,649		488,606		(27,898		)	460,708
Total assets	8,384,890		(21,271		)	8,363,619		8,017,041		(31,090		)	7,985,951


Accounts payable	385,054		670			385,724		578,173		549			578,722
Taxes accrued	98,662		(13,702		)	84,960		84,830		(3,192		)	81,638
Other current liabilities	74,381		—			74,381		71,205		1			71,206
Current liabilities held for sale and related to discontinued operations	670		(670		)	—		549		(549		)	—
Total current liabilities	1,201,693		(13,702		)	1,187,991		1,326,044		(3,191		)	1,322,853
Deferred income taxes	1,011,591		(7,564		)	1,004,027		839,860		(27,899		)	811,961
Total deferred credits and other liabilities	2,328,882		(7,569		)	2,321,313		2,063,035		(27,899		)	2,035,136
Total liabilities and equity	8,384,890		(21,271		)	8,363,619		8,017,041		(31,090		)	7,985,951

	Consolidated Cash Flow Statement
	For the Year Ended Dec. 31 ,2006
(Thousands of dollars)	As Previously Reported			Adjustment			As Restated
Remove loss (income) from discontinued operations	$	(20,472	)	$	20,472		$	—
Deferred income taxes	66,011			10,029			76,040
Change in accounts receivable	125,272			8,419			133,691
Change in other current assets	(2,604		)	13			(2,591		)
Change in accounts payable	(187,692		)	121			(187,571		)
Change in other current liabilities	29,698			(10,442		)	19,256
Change in other noncurrent assets	(2,153		)	(1		)	(2,154		)
Change in other noncurrent liabilities	(29,889		)	(4		)	(29,893		)
Operating cash flows provided by discontinued operations	29,486			(29,486		)	—
Net cash provided by operating activities	583,420			(879		)	582,541
Other investments	10,618			(749		)	9,869
Net cash used in investing activities	(524,652		)	(749		)	(525,401		)
Net increase (decrease) in cash and cash equivalents	977			(1,628		)	(651		)
Net increase (decrease) in cash and cash equivalents-discontinued operations	(814		)	814			—
Cash and cash equivalents at beginning of year	2,848			814			3,662

	Consolidated Cash Flow Statement
	For the Year Ended Dec. 31 ,2005
(Thousands of dollars)	As Previously Reported			Adjustment			As Restated
Remove loss (income) from discontinued operations	$	(19,077	)	$	19,077		$	—
Deferred income taxes	114,085			(2,630		)	111,455
Change in accounts receivable	(107,787		)	(29,995		)	(137,782		)
Change in other current assets	(2,878		)	(23		)	(2,901		)
Change in accounts payable	154,057			424			154,481
Change in other current liabilities	(19,213		)	25,406			6,193
Change in other noncurrent assets	(5,182		)	1			(5,181		)
Operating cash flows provided by discontinued operations	10,280			(10,280		)	—
Net cash provided by operating activities	383,813			1,980			385,793
Other investments	6,889			(369		)	6,520
Net cash used in investing activities	(414,748		)	(369		)	(415,117		)
Net increase in cash and cash equivalents	1,325			1,611			2,936
Net increase (decrease) in cash and cash equivalents-discontinued operations	806			(806		)	—
Cash and cash equivalents at beginning of year	717			9			726
Cash and cash equivalents at end of year	2,848			814			3,662

	Consolidated Cash Flow Statement
	For the Year Ended Dec. 31 ,2004
(Thousands of dollars)	As Previously Reported			Adjustment			As Restated
Remove loss (income) from discontinued operations	$	(12,774	)	$	12,774		$	—
Deferred income taxes	99,029			(19,536		)	79,493
Change in accounts receivable	(95,034		)	(12,618		)	(107,652		)
Change in other current assets	29,633			58			29,691
Change in accounts payable	22,757			137			22,894
Change in other current liabilities	13,737			(18,959		)	(5,222		)
Change in other liabilities	33,496			12,176			45,672
Operating cash flows provided by discontinued operations	(26,693		)	26,693			—
Net cash provided by operating activities	336,334			725			337,059
Other investments	(975		)	(716		)	(1,691		)
Net cash used in investing activities	(436,849		)	(716		)	(437,565		)
Net increase in cash and cash equivalents	(124,384		)	9			(124,375		)
Net increase (decrease) in cash and cash equivalents-discontinued operations	4			(4		)	—
Cash and cash equivalents at beginning of year	125,097			4			125,101
Cash and cash equivalents at end of year	717			9			726

3. Recently Issued Accounting Pronouncements

FASB Interpretation No. 48 (FIN 48) — In July 2006, the Financial Accounting Standards Board (FASB) issued FIN 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109.” FIN 48 prescribes 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 its effective date. Initial derecognition amounts would be reported as a cumulative effect of a change in accounting principle. Following implementation, the ongoing recognition of changes in the measurement of uncertain tax positions could be reflected as a component of income tax expense.

FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. See additional information in Note 19.

Fair Value Measurements (SFAS No. 157) — In September 2006, the FASB issued SFAS No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007. PSCo is evaluating the impact of SFAS No. 157 on its financial condition and results of operations and does not expect the impact of implementation to be material.

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

4. Short-Term Borrowings

Commercial Paper — At Dec. 31, 2006 and 2005, PSCo had commercial paper outstanding of approximately $372.5 million and $335.6 million, respectively. The weighted average interest rates at Dec. 31, 2006 and 2005 were 5.43 percent and 4.48 percent, respectively.

Money Pool - Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory approvals. Approval was also granted by the FERC in a July 18, 2006 order. The utility money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company. PSCo has approval to borrow up to $250 million under the arrangement. PSCo had no borrowings or loans outstanding under the arrangement at Dec. 31, 2006.

5. Long-Term Debt

Effective Oct. 14, 2005, PSCo discharged its Indenture, in accordance with its terms, dated as of Dec. 1, 1939, as supplemented (1939 Indenture). As a result, PSCo’s Indenture, dated as of Oct. 1, 1993, as supplemented (1993 Indenture), became the first lien on PSCo’s electric properties subject to certain permitted liens as provided in the 1993 Indenture. PSCo’s outstanding first collateral trust bonds issued under the 1993 Indenture are no longer secured by bonds issued under the 1939 Indenture and are first mortgage bonds entitled to the benefit of the lien on PSCo’s electric properties under the 1993 Indenture and have been renamed “first mortgage bonds” to reflect this status.

Credit Facilities — At Dec. 31, 2006, PSCo had the following committed credit facility in effect, in millions of dollars:

Credit Facility	Credit Facility Borrowings		Available*		Term	Maturity
$ 700	$	—	$	321.5	Five year	December 2011

* Net of credit facility borrowings, issued and outstanding letters of credit and commercial paper borrowings.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. PSCo has the right to request an extension of the final maturity date by one year. The maturity extension is subject to majority bank group approval. The credit facility has one financial covenant requiring that PSCo’s debt to total capitalization ratio be less than or equal to 65 percent with which PSCo was in compliance at Dec. 31, 2006. The interest rate is based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as determined by PSCo’s senior unsecured credit ratings from Moody, Standard & Poor and Fitch.

As of Dec. 31, 2006, PSCo had no direct borrowings on this line of credit; however, this credit facility was used to provide back-up support for PSCo commercial paper and letters of credit. Also, $6.0 million of letters of credit were outstanding at Dec. 31, 2006, as discussed in Note 12 to the Consolidated Financial Statements, of which approximately $6.0 million were outstanding under the above credit facility.

Maturities of long-term debt are:

(Millions of Dollars)
2007	$	101.4
2008	301.4
2009	201.5
2010	1.6
2011	1.6

6. Preferred Stock

PSCo has authorized the issuance of preferred stock.

Preferred Shares Authorized	Par Value		Preferred Shares Outstanding
10,000,000	$	0.01	None

7. Joint Plant Ownership

Following are the investments by PSCo in jointly owned plants and the related ownership percentages as of Dec. 31, 2006:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		Construction Work in Progress		Ownership%
Hayden Unit 1	$	87,051	$	45,840	$	371	75.5
Hayden Unit 2	81,467		47,021		544		37.4
Hayden Common Facilities	28,270		6,343		—		53.1
Craig Units 1 and 2	52,872		27,061		316		9.7
Craig Common Facilities, Units 1, 2 and 3	31,888		10,158		323		6.5-9.7
Comanche Unit 3	—		—		215,557		66.7
Transmission and other facilities, including substations	139,725		49,846		488		11.6-68.1
Total	$	421,273	$	186,269	$	217,599

PSCo’s current operational assets include approximately 320 MWs of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. PSCo began major construction on a new jointly owned 750 MW coal-fired unit in Pueblo, Colo. in January 2006. Major construction on the new unit, Comanche 3, is expected to be completed in the fall of 2009. PSCo is the operating agent under the joint ownership agreement. Each of the respective owners is responsible for funding its portion of the construction costs. For Comanche unit 3, the ownership percentage for Xcel Energy decreased in May 2006 from 74.7 percent to 66.7 percent for the project life-to-date and going forward.

8. Income Taxes

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following is a table reconciling such differences for the years ending Dec. 31:

	2006		2005		2004
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	4.3		2.3		3.4
Regulatory differences — utility plant items	0.2		0.3		1.5
Life insurance policies	(10.6	)	(10.8	)	(9.4	)
Tax credits recognized	(2.0	)	(2.5	)	(2.1	)
Resolution of income tax audits	(1.1	)	0.5		(4.9	)
Other — net	(0.5	)	0.1		1.5
Effective income tax rate	25.3	%	24.9	%	25.0	%

Income taxes comprise the following expense (benefit) items for the years ended Dec. 31:

(Thousands of Dollars)	2006			2005			2004
Current federal tax expense	$	(2,691	)	$	(32,833	)	$	(2,866	)
Current state tax expense	12,301			(4,411		)	2,229
Current tax credits	—			—			(2,000		)
Deferred federal tax expense	71,756			102,132			67,700
Deferred state tax expense	6,807			12,512			11,793
Deferred tax credits	(2,523		)	(3,189		)	—
Deferred investment tax credits	(3,949		)	(3,971		)	(4,000		)
Total income tax expense	$	81,701		$	70,240		$	72,856

The components of deferred income tax at Dec. 31 were:

(Thousands of Dollars)	2006			2005
Deferred tax expense excluding items below	$	149,056		$	89,333
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(808		)	4,801
Tax expense (benefit) allocated to other comprehensive income and other	(72,208		)	17,321
Deferred tax expense	$	76,040		$	111,455

The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

(Thousands of Dollars)	2006	2005
Deferred tax liabilities:
Differences between book and tax basis of property	$995,760	$912,876
Deferred costs	57,518	84,685
Regulatory assets	51,723	47,937
Employee benefits	20,907	20,356
Other comprehensive income	7,669	—
Other	4,088	12,143
Total deferred tax liabilities	$1,137,665	$1,077,997

Deferred tax assets:
Unbilled revenue	$71,986	$90,379
Other comprehensive income	—	64,538
Net operating loss carryforward	59,362	66,917
Deferred investment tax credits	22,242	23,680
Regulatory liabilities	13,626	13,479
Other	29,213	26,824
Total deferred tax assets	$196,429	$285,817
Net deferred tax liability	$941,236	$792,180

9. Benefit Plans and Other Postretirement Benefits

Pension and other postretirement disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to PSCo.

Xcel Energy offers various benefit plans to its benefit employees, including those of PSCo. Approximately 56 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2006, PSCo had 2,165 bargaining employees covered under a collective-bargaining agreement, which expires in May 2009.

Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (SFAS No. 158) — In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income. The following table shows the impact of the implementation on the consolidated statement of financial position. PSCo applied regulatory accounting treatment, which allowed recognition of this item as a regulatory asset rather than as a charge to accumulated other comprehensive income, as future costs are expected to be included in rates. The table reflects the deferral of these amounts as regulatory assets. This table also includes noncontributory, defined benefit supplemental retirement income plans.

Balance Sheet Line	Pre-SFAS No. 158			SFAS No. 158 Adjustment			SFAS No. 71 Adjustment		After SFAS No. 158

Regulatory assets	$	226,013		$	—		$	363,003	$	589,016
Other (long-term assets)	48,417			(2,633		)	—		45,784
Prepayments and other (current deferred taxes)	14,339			315			—		14,654
Total Assets	$	288,769		$	(2,318	)	$	363,003	$	649,454

Other (current liabilities)	$	73,549		$	832		$	—	$	74,381
Pension and employee benefit obligations	84,547			216,730			—		301,277
Deferred income taxes	949,717			(82,939		)	137,249		1,004,027
Total Liabilities	$	1,107,813		$	134,623		$	137,249	$	1,379,685

AOCI-net of tax	$	(76,199	)	$	(136,941	)	$	225,754	$	12,614
Total Equity	$	(76,199	)	$	(136,941	)	$	225,754	$	12,614

Pension Benefits

Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees, including those of PSCo. Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits.

Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Pension Plan Assets — Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. The target range for our pension asset allocation is 60 percent in equity investments, 20 percent in fixed income investments and 20 percent in nontraditional investments, such as real estate, private equity and a diversified commodities index.

The actual composition of pension plan assets at Dec. 31 was:

	2006		2005
Equity securities	63	%	65	%
Debt securities	22		20
Real estate	4		4
Cash	2		1
Nontraditional investments	9		10
	100	%	100	%

Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over

the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 11.3 percent, which is greater than the current assumption level. The pension cost determination assumes the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments. A higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year. Investment returns in 2006, 2005 and 2004 exceeded the assumed level of 8.75, 8.75 and 9.0 percent, respectively. Xcel Energy continually reviews its pension assumptions. In 2007, Xcel Energy will continue to use an investment-return assumption of 8.75 percent.

Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets, on a combined basis, is presented in the following table:

(Thousands of Dollars)	2006			2005
Accumulated Benefit Obligation at Dec. 31	$	2,486,370		$	2,642,177

Change in Projected Benefit Obligation
Obligation at Jan. 1	$	2,796,780		$	2,732,263
Service cost	61,627			60,461
Interest cost	155,413			160,985
Plan amendments	(16,569		)	300
Actuarial (gain) loss	(82,339		)	85,558
Benefit payments	(248,357		)	(242,787		)
Obligation at Dec. 31	$	2,666,555		$	2,796,780

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	3,093,536		$	3,062,016
Actual return on plan assets	306,196			254,307
Employer contributions	32,000			20,000
Benefit payments	(248,357		)	(242,787		)
Fair value of plan assets at Dec. 31	$	3,183,375		$	3,093,536

Funded Status of Plans at Dec. 31
Funded status	$	516,820		$	296,756
Noncurrent assets	586,713			685,028
Noncurrent liabilities	(69,893		)	(90,595		)
Net pension amounts recognized on Consolidate Balance Sheets	$	516,820		$	594,433

PSCo Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	164,970		$	210,085
Prior service cost	24,387			26,057
Total	$	189,357		$	236,142

SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	189,357		N/A
Total	$	189,357		N/A

PSCo accrued benefit liability recorded	$	(68,513	)	$	(88,414	)

Measurement Date	Dec. 31, 2006			Dec. 31, 2005

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	6.00		%	5.75		%
Expected average long-term increase in compensation level	4.00		%	3.50		%

During 2002, PSCo’s pension plans became underfunded, and at Dec. 31, 2006, had projected benefit obligations of $728.1 million, which exceeded plan assets of $658.2 million. At Dec. 31, 2005, the projected benefit obligations of $739.5 million,

exceeded plan assets of $609.8 million. All other Xcel Energy plans in the aggregate had plan assets of $2.5 billion and projected benefit obligations of $1.9 billion on Dec. 31, 2006.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in the years 2004 through 2006 for Xcel Energy’s pension plans, and are not expected to require cash funding in 2007. PSCo elected to make voluntary contributions to its pension plan for bargaining employees of $29 million, $15 million and $10 million in 2006, 2005 and 2004, respectively. During 2007, Xcel Energy expects to voluntarily contribute approximately $20 million to the PSCo pension plan for bargaining employees.

Plan Changes — The Pension Protection Act of 2006 (PPA) was reflected effective December 31, 2006. PPA requires a change in the conversion basis for lump-sum payments, three-year vesting for plans with account balance or pension equity benefits, as well as the repeal of the Economic Growth and Tax Relief Reconciliation Act of 2001 sunset provisions. These changes are reflected as a plan amendment for purposes of SFAS No. 87.

Benefit Costs — The components of net periodic pension cost (credit) are:

(Thousands of Dollars)	2006			2005			2004
Service cost	$	61,627		$	60,461		$	58,150
Interest cost	155,413			160,985			165,361
Expected return on plan assets	(268,065		)	(280,064		)	(302,958		)
Settlement gain	—			—			(926		)
Amortization of transition asset	—			—			(7		)
Amortization of prior service cost	29,696			30,035			30,009
Amortization of net (gain) loss	17,353			6,819			(15,207		)
Net periodic pension credit under SFAS No. 87	$	(3,976	)	$	(21,764	)	$	(65,578	)

PSCo
Net periodic pension cost (credit)	$	18,666		$	14,252		$	7,141

Significant Assumptions Used to Measure Costs
Discount rate	5.75		%	6.00		%	6.25		%
Expected average long-term increase in compensation level	3.50		%	3.50		%	3.50		%
Expected average long-term rate of return on assets	8.75		%	8.75		%	9.00		%

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2007 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.

Xcel Energy also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy’s operating cash flows.

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for PSCo were approximately $6.2 million in 2006, $6.2 million in 2005 and $7.2 million in 2004.

Postretirement Health Care Benefits

Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees. Employees of the former New Century Energies, Inc. (NCE) who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE, who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.

In conjunction with the 1993 adoption of SFAS No. 106 — “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106. PSCo transitioned to full accrual accounting for SFAS No. 106 costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional SFAS No. 106 costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012.

Plan Assets — Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of SFAS No. 106 costs. PSCo is required to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. In 2004, the investment strategy for the union asset fund was changed to increase the investment mix to equity funds. Also, a portion of the assets contributed on behalf of non-bargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

The actual composition of postretirement benefit plan assets at Dec. 31 was:

	2006		2005
Equity and equity mutual fund securities	67	%	61	%
Fixed income/debt securities	21		17
Cash equivalents	11		21
Nontraditional Investments	1		1
	100	%	100	%

Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Investment-return volatility is not considered to be a material factor in postretirement health care costs.

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:

(Thousands of Dollars)	2006			2005
Change in Benefit Obligation
Obligation at Jan. 1	$	938,172		$	929,125
Service cost	6,633			6,684
Interest cost	52,939			55,060
Medicare subsidy reimbursements	3,561			—
Plan amendments	(945		)	—
Plan participants’ contributions	11,870			12,008
Actuarial gain	(27,511		)	(3,175		)
Benefit payments	(66,026		)	(61,530		)
Obligation at Dec. 31	$	918,693		$	938,172

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	351,863		$	318,667
Actual return on plan assets	41,409			14,507
Plan participants’ contributions	11,870			12,008
Employer contributions	67,188			68,211
Benefit payments	(66,025		)	(61,530		)
Fair value of plan assets at Dec. 31	$	406,305		$	351,863

Funded Status at Dec. 31
Funded status	$	(512,388	)	$	(586,309	)
Current liabilities	(2,211		)	—
Noncurrent assets	—			15,736
Noncurrent liabilities	(510,177		)	(150,014		)
Net amounts recognized on Consolidated Balance Sheets	$	(512,388	)	$	(134,278	)

PSCo Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	106,450		$	164,158
Prior service cost (credit)	(2,613		)	(3,041		)
Transition obligation	66,809			77,813
Total	$	170,646		$	238,930

SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	170,646		N/A
Total	$	170,646		N/A

PSCo accrued benefit liability recorded	$	207,992		$	39,503

Measurement Date	Dec. 31, 2006			Dec. 31, 2005

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	6.00		%	5.75		%

Effective Dec. 31, 2004, Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0 percent and lowered the ultimate trend assumption from 5.5 percent to 5.0 percent. The period until the ultimate rate is reached was also increased from two years to six years. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

A 1-percent change in the assumed health care cost trend rate would have the following effects on PSCo:

(Millions of Dollars)
1-percent increase in APBO components at Dec. 31, 2006	$	59.7
1-percent decrease in APBO components at Dec. 31, 2006	(49.9		)
1-percent increase in service and interest components of the net periodic cost	4.9
1-percent decrease in service and interest components of the net periodic cost	(4.0		)

Plan Changes - The employer subsidy for retiree medical coverage was eliminated for former New Century Energies, Inc. non-bargaining employees who retire after July 1, 2003.

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $61 million during 2007.

Benefit Costs — The components of net periodic postretirement benefit cost are:

(Thousands of Dollars)	2006			2005			2004
Service cost	$	6,633		$	6,684		$	6,100
Interest cost	52,939			55,060			52,604
Expected return on plan assets	(26,757		)	(25,700		)	(23,066		)
Amortization of transition obligation	14,444			14,578			14,578
Amortization of prior service credit	(2,178		)	(2,178		)	(2,179		)
Amortization of net loss	24,797			26,246			21,651
Net periodic postretirement benefit cost (credit) under SFAS No. 106	$	69,878		$	74,690		$	69,688

PSCo
Net periodic postretirement benefit cost recognized — SFAS No. 106	39,976			43,841			42,248
Additional cost recognized due to effects of regulation	3,891			3,891			3,891
Net cost recognized for financial reporting	$	43,867		$	47,732		$	46,139

Significant assumptions used to measure costs (income)
Discount rate	5.75		%	6.00		%	6.25		%
Expected average long-term rate of return on assets (before tax)	7.5		%	5.5%-8.5		%	5.5%-8.5		%

Projected Benefit Payments

The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans.

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2007	$	217,236	$	65,355	$	5,358	$	59,997
2008	215,815		67,110		5,755		61,355
2009	220,843		68,911		6,115		62,796
2010	227,528		70,457		6,430		64,027
2011	225,446		71,924		6,665		65,259
2012-2016	1,195,629		368,206		36,592		331,614

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

Interest and other income, net of nonoperating expenses, for the years ended Dec. 31 consists of the following:

(Thousands of Dollars)	2006			2005			2004

Interest income	$	4,462		$	2,801		$	9,194
Other nonoperating income	2,581			3,621			8,346
Interest expense on corporate-owned life insurance and other employee-related insurance policies	(20,404		)	(18,273		)	(17,075		)
Other nonoperating expense	(862		)	(33		)	(441		)
Total interest and other (expense) income — net	$	(14,223	)	$	(11,884	)	$	24

11. Derivative Instruments

In the normal course of business, PSCo is exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. PSCo utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance its operations. The use of these derivative instruments is discussed in further detail below.

Utility Commodity Price Risk — PSCo is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric

capacity, energy and other energy-related products, and for various fuels used in the generation of electricity and natural gas utility operations. Commodity risk also is managed through the use of financial derivative instruments. PSCo utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of its retail customers even though regulatory jurisdiction may provide for a dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments is done consistently with the local jurisdictional cost-recovery mechanism. PSCo’s risk management policy allows it to manage market price risk within each rate-regulated operation to the extent such exposure exists.

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and other energy-related instruments. PSCo’s risk management policy allows management to conduct the marketing activity within guidelines and limitations as approved by our risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Interest Rate Risk — PSCo is subject to the risk of fluctuating interest rates in the normal course of business. PSCo’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

Types of and Accounting for Derivative Instruments

PSCo uses derivative instruments in connection with its 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, are recorded at fair value. The classification of the fair value for 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 specific regulation. This includes certain instruments used to mitigate market risk for PSCo 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.

SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. PSCo formally documents hedging relationships, including, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedged transaction. PSCo also formally assesses, both at inception and on a regular basis, if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily 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 natural gas purchased for resale are recorded as a component of natural gas costs; and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility.

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 that PSCo is currently engaged in are discussed below.

Cash Flow Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a cash flow hedge is recorded as a component of Other Comprehensive Income or deferred as a regulatory asset or liability, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.

Commodity Cash Flow Hedges — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes. At Dec. 31, 2006, PSCo had various commodity-related contracts classified as cash flow hedges extending through December 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 Dec. 31, 2006, PSCo had no amounts in Accumulated Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

PSCo had immaterial ineffectiveness related to commodity cash flow hedges during the year ended Dec. 31, 2006 and no ineffectiveness during the year ended Dec. 31, 2005.

Interest Rate Cash Flow Hedges — PSCo enters into interest rate lock agreements, including treasury-rate locks and forward starting swaps that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes.

As of Dec. 31, 2006, PSCo had net gains of approximately $1.5 million in Accumulated Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.

PSCo had no ineffectiveness related to interest rate cash flow hedges during the years ended Dec. 31, 2006 and 2005, respectively.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying cash flow hedges on PSCo’s Other Comprehensive Income, included in the Consolidated Statements of Stockholder’s Equity, is detailed in the following table:

(Millions of Dollars)
Accumulated other comprehensive loss related to hedges at Dec. 31, 2003	$	17.2
After-tax net unrealized gains related to derivative accounted for as hedges	8.6
After-tax net realized gains on derivative transactions reclassified into earnings	(10.1		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2004	$	15.7

After-tax net unrealized gains related to derivatives accounted for as hedges	11.9
After-tax net realized gains on derivative transactions reclassified into earnings	(13.4		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2005	$	14.2

After-tax net unrealized losses related to derivatives accounted for as hedges	(0.1		)
After-tax net realized gains on derivative transactions reclassified into earnings	(1.5		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2006	$	12.6

Normal Purchases or Normal Sales Contracts

PSCo enters into contracts for the purchase and sale of commodities for use in its business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales.

PSCo 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. 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, PSCo 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, PSCo 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.

Commodity Trading Contracts - The fair value of commodity trading contracts as of Dec. 31, 2006 and 2005 was $(0.6) million and $2.1 million, respectively.

Hedging Contracts - The fair value of qualifying cash flow hedges at Dec. 31, 2006 and 2005 was $3.1 million and $1.0 million, respectively.

For a further discussion of other financial instruments at PSCo, see Note 12 to the Consolidated Financial Statements.

12. Financial Instruments

The estimated Dec. 31 fair values of PSCo’s recorded financial instruments were as follows:

	2006				2005
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term investments	$	11,144	$	11,144	$	12,877	$	12,877
Long-term debt, including current portion	1,946,657		2,023,551		2,072,307		2,187,802

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts. The fair value of PSCo’s long-term investments are estimated based on quoted market prices for those or similar investments. The fair value of PSCo’s long-term debt is estimated based on the quoted market prices for the same or similar issues or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2006 and 2005. These fair value estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current estimates of fair values may differ significantly.

Letters of Credit

PSCo use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2006, there was $6.0 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

13. Rate Matters

Pending and Recently Concluded Regulatory Proceedings - FERC

FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of both PSCo and 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. On April 5, 2006, the FERC issued an order approving the uncontested settlement. PSCo placed the final rates in effect on June 1, 2006 and made refunds of approximately $3.7 million.

Pending and Recently Concluded Regulatory Proceedings - CPUC

Electric Rate Case — In April 2006, PSCo filed with the CPUC to increase electricity rates by $208 million annually, beginning Jan. 1, 2007. The request was based on two components, including an increase in base rate revenues of $178 million and an estimated $30 million increase in PCCA revenue. The base rate request was 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 was implemented. The PCCA request was based on 2007 projected costs.

On Oct. 20, 2006, PSCo entered into a comprehensive settlement agreement with several of the parties to the case. On Nov. 20, 2006, the CPUC issued a written order approving the settlement with new rates effective Jan. 1, 2007. The settlement provides for an increase in base rates of $107 million, based on a 10.50 percent return on equity, an estimated $39.4 million in PCCA revenue and an estimated $4.6 million in ECA revenue to recover certain WindSource program costs for a total increase of $151 million. In addition, PSCo is permitted an incentive for its performance on achieving fuel and purchased energy savings as well as for its generation based wholesale margins.

Natural Gas Rate Case — On Dec. 1, 2006, PSCo filed with the CPUC a request to increase natural gas rates by $41.5 million, annually, representing an overall increase of 2.96 percent. The request is based on a requested capital structure of 60.17 percent common equity, a return on common equity of 11 percent and a rate base of approximately $1.1 billion. It is anticipated that new rates will become effective in the third quarter of 2007.

Quality of Service Plan — The PSCo QSP provides for bill credits to Colorado retail customers, if PSCo does not achieve certain operational performance targets. During the second quarter of 2006, PSCo filed its calendar year 2005 operating performance results for electric service unavailability, phone response time, customer complaints, accurate meter reading and

natural gas leak repair time measures. PSCo did not achieve the 2005 performance targets for the electric service unavailability measure creating a bill credit obligation of $13.6 million. Additionally, in accordance with a prior agreement, PSCo invested an additional $11 million in 2006 toward improving reliability. As a result, PSCo will not be required to pay any bill credits that may be owed for 2006 performance results for electric service unavailability. The maximum potential bill credit obligation for 2006 related to permanent natural gas leak repair and natural gas meter reading errors is approximately $1.6 million. PSCo does not anticipate any bill credits will be due customers based on the 2006 performance targets.

14. Commitments and Contingent Liabilities

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

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

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

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

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

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

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

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

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

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

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

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

Leases — PSCo leases a variety of equipment and facilities used in the normal course of business. Two of these leases qualify as capital leases and are accounted for accordingly. The capital leases contractually expire in 2025 and 2028. The assets and liabilities acquired under capital leases are recorded at the lower of fair-market value or the present value of future lease payments and are amortized over their actual contract term in accordance with practices allowed by regulators.

Following is a summary of property held under capital leases:

(Millions of Dollars)	2006			2005
Storage, leaseholds and rights	$	40.5		$	40.5
Gas pipeline	20.7			20.7
	61.2			61.2
Less: Accumulated amortization	(15.0		)	(13.6		)
Total property held under capital leases	$	46.2		$	47.6

The remainder of the leases, primarily for office space, railcars, generating facilities, trucks, cars and power-operated equipment are accounted for as operating leases. Rental expense under operating lease obligations was approximately $17.1 million, $19.6 million and $17.6 million for 2006, 2005 and 2004, respectively.

Future commitments under noncancellable operating and capital leases with terms in excess of one year are:

(Millions of Dollars)	Operating Leases		Capital Leases
2007	$	8.8	$	6.3
2008	8.2		6.1
2009	8.1		6.0
2010	8.0		5.8
2011	7.9		5.6
Thereafter	34.0		62.4
Total minimum obligation			$	92.2
Interest component of obligation			(46.0		)
Present value of minimum obligation			$	46.2

Capital Commitments — The estimated cost, as of Dec. 31, 2006, of the capital expenditure programs and other capital requirements of PSCo was approximately $690 million in 2007, $635 million in 2008 and $515 million in 2009. PSCo’s capital expenditure forecast includes the following major project:

Comanche 3 - Comanche 3, a 750-MW coal-fired plant being built in Colorado is expected to cost approximately $1.35 billion, with major construction initiated in 2006 and completed in the fall of 2009. The CPUC has approved sharing one-third ownership of this plant with other parties. Consequently, PSCo’s investment in Comanche 3 will be approximately $1 billion.

The capital expenditure programs of PSCo are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth regulatory decisions, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting PSCo’s long-term energy needs. In addition, PSCo’s ongoing evaluation of compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

Fuel Contracts — PSCo has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2007 and 2025. In addition, PSCo may be required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass through of most fuel, storage and transportation costs.

The estimated minimum purchase obligation for PSCo under these contracts as of Dec. 31, 2006, is as follows:

Coal		Natural Gas Supply		Gas Storage & Transportation
		(Millions of Dollars)
$	632	$	766	$	730

Purchased Power Agreements — PSCo has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. PSCo has various pay-for-performance contracts with expiration

dates through the year 2027. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indices. However, the effects of these price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.

At Dec. 31, 2006, the estimated future payments for capacity that PSCo is obligated to purchase, subject to availability, were as follows (Millions of Dollars):

2007	$	410.1
2008	401.3
2009	411.9
2010	399.5
2011	392.1
2012 and thereafter	2,353.6
Total	$	4,368.5

Environmental Contingencies

PSCo has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo 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 PSCo, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense.

Site Remediation — PSCo must pay all or a portion of the cost to remediate sites where past activities of PSCo and some other parties have caused environmental contamination. Environmental contingencies could arise from various situations including the following categories of sites:

· site of a former manufactured gas plant (MGP) operated by PSCo or its predecessors; and

· third party sites, such as landfills, to which PSCo is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.

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

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

Estimates are revised as facts become known.. At Dec. 31, 2006, the liability for the cost of remediating these sites was estimated to be $1.3 million, of which $0.4 million was considered to be a current liability. Some of the cost of remediation may be recovered from:

· insurance coverage;

· other parties that have contributed to the contamination; and

· customers.

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

Manufactured Gas Plant Site

Fort Collins Manufactured Gas Plant Site — Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold most of the property. An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo performed remediation and monitoring work. PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring. In May 2005, PSCo filed a natural gas rate case with the CPUC requesting recovery of cleanup costs at the Fort Collins MGP site spent through March 2005, which amounted to $6.2 million, to be amortized over four years. PSCo reached a settlement agreement with the parties in the case. The CPUC approved the settlement agreement on Jan. 19, 2006 and the final order became effective on Feb. 3, 2006, with rates effective Feb. 6, 2006. In November 2006, PSCo filed a natural gas rate case with the CPUC requesting recovery of additional clean-up costs at the Fort Collins MGP site spent through September 2006, plus unrecovered amounts previously authorized from the last rate case, which amounted to $10.8 million to be amortized over four years. The total amount PSCo is requesting be recovered from customers is $13.1 million.

In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases caused MGP byproducts to migrate to the Cache La Poudre River, thereby substantially increasing the scope and cost of remediation. PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache la Poudre River. On Dec. 14, 2005, the court denied Schrader’s request to dismiss the PSCo suit. On Jan. 3, 2006, Schrader filed a response to the PSCo complaint and a counterclaim against PSCo for its response costs under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) and under the Resource Conservation and Recovery Act (RCRA). Schrader has alleged as part of its counterclaim an “imminent and substantial endangerment” of its property as defined by RCRA. In September 2006, PSCo filed a Motion For Partial Summary Judgment to dismiss Schrader’s RCRA claim. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. PSCo has recorded an estimate for final removal of the asbestos as an asset retirement obligation. See additional discussion of asset retirement obligations below. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

Regional Haze Rules — On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Some PSCo generating facilities will be subject to BART requirements.

The EPA requires states to develop implementation plans to comply with 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. 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 $211 million in capital costs, which includes approximately $62 million in environmental upgrades for the existing Comanche Station project, which are included in the capital budget. PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2010 and 2012.

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. PSCo 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. In February 2007, the Colorado Air Quality Control Commission passed a mercury rule. The rule was based on a negotiated rule that was agreed upon by participating environmental groups, utilities, local government coalitions, and the Colorado Air Pollution Control Division. The rule requires controls to be installed at Pawnee Station in 2012 and all other Colorado units

by 2014. PSCo is evaluating the emission controls required to meet the new rule and is currently unable to provide a capital cost estimate.

Federal Clean Water Act — The federal Clean Water Act requires EPA to regulate cooling water intake structures to assure that these structures reflect the “best technology available” for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit challenging the phase II rulemaking. On Jan. 25, 2007, the court issued its decision and remanded virtually every aspect of the rule to the EPA for reconsideration. It is unclear whether EPA will stay the deadlines in the rule until the remanded rulemaking is finished. As a result, the rule’s compliance requirements and associated deadlines are currently unknown. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved.

Notice of Violation — On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the New Source Review (NSR) requirements of the Clean Air Act (CAA) at the Comanche and Pawnee plants in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo also believes that the projects would be expressly authorized under the EPA’s NSR equipment replacement rulemaking promulgated in October 2003. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

Asset Retirement Obligations

PSCo records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with SFAS No. 143 — “Accounting for Asset Retirement Obligations” (SFAS No. 143). This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.

Recorded Asset Retirement Obligations (ARO) — Asset retirement obligations have been recorded for steam production, electric transmission and distribution and natural gas distribution. The steam production obligation includes asbestos and ash-containment facilities. The asbestos recognition associated with the steam production includes certain plants at PSCo. Generally, this asbestos abatement removal obligation originated in 1973 with the Clean Air Act, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. Asset retirement obligations also have been recorded for PSCo steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination date on the ARO recognition for ash-containment facilities at steam plants was the in-service date of various facilities.

PSCo recognized an ARO for the retirement costs of its natural gas mains. In addition, an ARO was recognized for the removal of electric, transmission and distribution equipment. The electric transmission and distribution ARO consists of many small potential obligations associated with polychlorinated biphenyls (PCBs), mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. These electric and natural gas assets have many in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.

If PSCo had implemented FASB Interpretation No. 47— “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47) at Jan. 1, 2005, the liability for asset retirement obligations would have increased by $12.1 million.

A reconciliation of the beginning and ending aggregate carrying amounts of PSCo’s asset retirement obligations is shown in the table below for the 12 months ended Dec. 31, 2006 and Dec. 31, 2005, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2006		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates			Ending Balance Dec. 31, 2006

Electric Utility Plant:
Steam production asbestos	$	9,099	$	—	$	—	$	535	$	—		$	9,634
Steam production ash containment	3,720		—		—		230		(44		)	3,906
Electric transmission and distribution	700		—		—		18		(125		)	593
Gas Utility Plant:
Gas transmission and distribution	28,449		—		—		706		47			29,202
Total liability	$	41,968	$	—	—		$	1,489	$	(122	)	$	43,335

(Thousands of Dollars)	Beginning Balance Jan. 1, 2005		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates		Ending Balance Dec. 31, 2005

Electric Utility Plant:
Steam production asbestos	$	—	$	1,462	$	—	$	7,637	$	—	$	9,099
Steam production ash containment	—		882		—		2,838		—		3,720
Electric transmission and distribution	—		700		—		—		—		700
Gas Utility Plant:
Gas transmission and distribution	—		28,449		—		—		—		28,449
Total liability	$	—	$	31,493	—		$	10,475	$	—	$	41,968

Indeterminate Asset Retirement Obligations — PSCo has underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined.

Removal Costs - PSCo accrues an obligation for plant removal costs for generation, transmission and distribution facilities. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs as of Dec. 31, 2006 and Dec. 31, 2005 were $389 million and $377 million, respectively.

Legal Contingencies

In the normal course of business, PSCo is party to routine claims and litigation arising from prior and current operations. PSCo is actively defending these matters and has recorded a liability related to the probable cost of settlement or other disposition when it can be reasonably estimated.

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. Although PSCo is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on PSCo. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or natural gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and 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 Court of Appeals. Oral arguments were presented on June 7, 2006 and a decision on the appeal is pending.

(Thousands of Dollars)	See Note	Remaining Amortization Period	2006		2005
Regulatory Assets:
Pension and employee benefit obligations	9	Various	$	386,346	$	27,234
Conservation programs (a)		Various	70,572		59,114
AFDC recorded in plant (a)		Plant lives	39,722		40,168
Contract valuation adjustments (b)	11	Term of related contract	39,131		58,214
Losses on reacquired debt		Term of related debt	24,315		26,228
Net asset retirement obligations		Plant lives	13,664		11,789
Environmental costs	14	Four years	8,522		—
Plant asset recovery (Pawnee II and Metro Ash)		Six months	2,452		7,355
Rate case costs	1	Various	2,190		1,699
Other		Various	2,102		—
Total regulatory assets			$	589,016	$	231,801
Regulatory Liabilities:
Plant removals costs	14		$	389,056	$	377,343
Investment tax credit deferrals			35,764		38,134
Contract valuation adjustments (b)	11		—		46,827
Deferred income tax adjustments			31,146		30,031
Renewable resource requirements			14,289		—
Total regulatory liabilities			$	470,255	$	492,335

(a)		Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.
(b)		Includes the fair value of certain long-term contracts used to meet native energy requirements.

16. Segments and Related Information

PSCo has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility.

·	PSCo’s Regulated Electric Utility generates, transmits and distributes electricity in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated Electric Utility also includes PSCo’s commodity trading operations.

·	PSCo’s Regulated Natural Gas Utility transports, stores and distributes natural gas in portions of Colorado.

Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All Other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities.

To report net income for Regulated Electric and Regulated Natural Gas Utility segments, PSCo must assign or allocate all costs and certain other income. In general, costs are:

·	directly assigned wherever applicable;

·	allocated based on cost causation allocators wherever applicable; or

·	allocated based on a general allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery which are separately determined for each segment.

			Regulated
	Regulated		Natural		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric Utility		Gas Utility		Other			Eliminations			Total
2006
Operating revenues from external customers	$	2,505,445	$	1,262,295	$	38,089		$	—		$	3,805,829
Intersegment revenues	201		90		—			(291		)	—
Total revenues	$	2,505,646	$	1,262,385	$	38,089		$	(291	)	$	3,805,829
Depreciation and amortization	$	177,329	$	56,054	$	6,533		$	—		$	239,916
Financing costs, mainly interest expense	95,674		26,984		1,750			(301		)	124,107
Income tax expense (benefit)	93,429		30,049		(41,777		)	—			81,701
Segment net income	$	170,997	$	57,475	$	12,986		$	—		$	241,458

2005
Operating revenues from external customers	$	2,504,028	$	1,329,034	$	33,501		$	—		$	3,866,563
Intersegment revenues	263		97		—			(360		)	—
Total revenues	$	2,504,291	$	1,329,131	$	33,501		(360		)	$	3,866,563
Depreciation and amortization	$	179,774	$	52,009	$	6,619		$	—		$	238,402
Financing costs, mainly interest expense	108,824		30,150		2,241			(969		)	140,246
Income tax expense (benefit)	89,579		23,112		(42,451		)	—			70,240
Segment net income	$	153,436	$	43,458	$	14,523		$	—		$	211,417

2004
Operating revenues from external customers	$	2,194,628	$	1,073,989	$	27,825		$	—		$	3,296,442
Intersegment revenues	180		69		—			(249		)	—
Total revenues	$	2,194,808	$	1,074,058	$	27,825		$	(249	)	$	3,296,442
Depreciation and amortization	$	170,337	$	47,167	$	5,938		$	—		$	223,442
Financing costs, mainly interest expense	116,686		32,033		2,409			(1,106		)	150,022
Income tax expense (benefit)	80,578		19,437		(27,159		)	—			72,856
Segment net income	$	152,870	$	58,513	$	6,622		$	—		$	218,005

17. Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including PSCo. The services are provided and billed to each subsidiary in accordance with Service Agreements executed by each subsidiary. Costs are charged directly to the subsidiary which uses the service whenever possible, and are allocated if they cannot be directly assigned.

Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required FERC and state regulatory approvals. See Note 4 for further discussion of this borrowing arrangement.

Utility Engineering Corp. (UE), a former Xcel Energy subsidiary, provides construction services to PSCo, for which it was paid $3.3 million in 2005 and $12.9 million in 2004. UE was sold in April 2005.

Cheyenne Light, Fuel and Power (Cheyenne), a former Xcel Energy subsidiary, purchased all of its electricity requirements from PSCo. During 2004, Xcel Energy reached an agreement to sell Cheyenne. The sale was completed in January 2005.

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Thousands of Dollars)	2006		2005		2004
Operating revenues:
Electric utility	$	—	$	2,378	$	48,666
Operating expenses:
Other operations — paid to Xcel Energy Services Inc	267,307		256,290		298,124
Interest expense	4,894		725		886

Accounts receivable and payable with affiliates at Dec. 31, was:

	2006				2005
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable

NSP-Minnesota	$	6,598	$	—	$	22,356	$	162
NSP-Wisconsin	1,285		—		—		2,281
SPS	—		1,189		86		—
Other subsidiaries of Xcel Energy Inc.	738		29,102		25,304		23,945
	$	8,621	$	30,291	$	47,746	$	26,388

18. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended (As restated See Note 2)
(Thousands of Dollars)	March 31, 2006		June 30, 2006		Sept. 30, 2006		Dec. 31, 2006

Revenue	$	1,267,025	$	767,231	$	793,724	$	977,849
Operating income	133,087		105,348		99,504		120,900
Net income	76,846		52,193		47,358		65,061

	Quarter Ended (As restated See Note 2)
(Thousands of Dollars)	March 31, 2005		June 30, 2005		Sept. 30, 2005		Dec. 31, 2005

Revenue	$	1,039,277	$	783,208	$	782,723	$	1,261,355
Operating income	125,713		95,931		99,273		110,215
Net income	65,607		47,188		45,678		52,944

The effect of presenting PSRI as part of discontinued operations, rather than continuing operations, as previously reported in the Form 8-K is reflected in the tables below:

	Quarter Ended
(Thousands of Dollars)	March 31, 2006		June 30, 2006		Sept. 30, 2006		Dec. 31, 2006

Revenue	$	1,267,025	$	767,231	$	793,724	$	977,849
Operating income	134,065		106,393		100,642		122,248
Income from continuing operations	68,867		50,073		42,781		59,265
Income from discontinued operations, net of tax	7,979		2,119		4,578		5,796
Net income	76,846		52,193		47,358		65,061

	Quarter Ended
(Thousands of Dollars)	March 31, 2005		June 30, 2005		Sept. 30, 2005		Dec. 31, 2005

Revenue	$	1,039,277	$	783,208	$	782,723	$	1,261,355
Operating income	126,250		96,245		99,936		111,435
Income from continuing operations	59,029		41,551		44,761		46,999
Income from discontinued operations, net of tax	6,578		5,637		917		5,945
Net income	65,607		47,188		45,678		52,944

19. Subsequent Events

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

adjustment to the beginning balance of retained earnings, was not material. Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.

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

As previously disclosed, Xcel Energy has been in litigation with the federal government to establish its right to deduct interest expense on COLI policy loans incurred since 1993. Xcel Energy and the IRS have reached a final settlement regarding this litigation (see discussion of COLI at Note 14).

PSCo is also currently under examination by the state of Colorado for years 2002 through 2005. No material adjustments have been proposed as of Sept. 30, 2007. As of Sept. 30, 2007, PSCo’s earliest open tax year in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2002.

The amount of unrecognized tax benefits was $11.4 million on Jan. 1, 2007 and $10.5 million on Sept. 30, 2007. These amounts were offset against the tax benefits associated with net operating loss and tax credit carryovers of $7.5 million on Jan. 1, 2007 and $6.5 million on Sept. 30, 2007.

Included in the unrecognized tax benefit balance for continuing operations was $4.5 million and $1.2 million of tax positions on Jan. 1, 2007 and Sept. 30, 2007, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance for continuing operations included $6.9 million and $9.3 million of tax positions on Jan. 1, 2007 and Sept. 30, 2007, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The decrease in the unrecognized tax benefit balance for continuing operations of $11.0 million from July 1, 2007 to Sept. 30, 2007, was due to the addition of similar uncertain tax positions relating to third quarter activity, the resolution of certain federal audit matters, and the final settlement of the COLI litigation. PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state tax audits progress. However, at this time due to the nature of the audit process, it is not reasonably possible to estimate a range of the possible change.

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

Operating Leases – During the second and third quarters of 2007, PSCo commenced purchased power agreements that are being accounted for as operating leases in accordance with Emerging Issues Task Force 01-8, “Determining Whether an Arrangement Contains a Lease” and SFAS 13 –“Accounting for Leases”. These agreements require capacity payments of $30.2 million, $35.7 million, $32.0 million, $21.3 million, $17.1 million and $355.6 million for 2007, 2008, 2009, 2010, 2011 and thereafter, respectively. For more information, see Note 14 to the Consolidated Financial Statements.

Qwest vs. Xcel Energy Inc. - As discussed in Note 14 to the Consolidated Financial Statements, a PSCo employee had sued Qwest relating to injuries suffered when a pole owned by Qwest malfunctioned. Qwest filed a third party claim against PSCo. On May 22, 2007, a jury verdict found Qwest solely liable for the accident and damages. Qwest has filed post —trial motions, and if unsuccessful, has indicated it will appeal the verdict.

Natural Gas Rate Case - On June 18, 2007, the CPUC approved a settlement between PSCo, the CPUC staff and the Colorado Office of Consumer Council (OCC), which granted the following:

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

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

Final rates were implemented effective July 30, 2007.

SCHEDULE II

PUBLIC SERVICE COMPANY OF COLORADO

VALUATION AND QUALIFYING ACCOUNTS

Years Ended Dec. 31, 2006, 2005 and 2004

(Thousands of Dollars)

			Additions
	Balance at		Charged		Charged		Deductions		Balance
	beginning		to costs &		to other		from		at end
	of period		expenses		accounts (1)		reserves (2)		of period

Reserve deducted from related assets:
Provision for uncollectible accounts:
2006	$	19,381	$	26,944	$	7,375	$	35,285	$	18,415
2005	$	14,734	$	24,214	$	6,216	$	25,783	$	19,381
2004	$	12,852	$	12,823	$	4,742	$	15,683	$	14,734

(1)	Recovery of amounts previously written off.
(2)	Principally uncollectible accounts written off or transferred.

001-3280		84-0296600
(Commission File Number)		(IRS Employer Identification No.)

1225 17^th St., Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

Exhibit No.		Description
23.01		Consent of Independent Registered Public Accounting Firm
99.01		Restated Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosure About Market Risk, and Financial Statements and Supplementary Data (Part II, Items 7, 7A and 8 of PSCo’s Annual Report on Form 10-K for the year ended December 31, 2006).
12.01		Restated Computation of Ratio of Earnings to Fixed Charges previously included in PSCo’s Annual Report on Form 10-K for the year ended December 31, 2006

	Public Service Company of Colorado (a Colorado Corporation)


	/S/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III
	Vice President and Chief Financial Officer
December 17, 2007

/s/ Deloitte & Touche

Minneapolis, Minnesota
December 12, 2007

	Year ended Dec. 31,
	2006		2005		2004		2003		2002
	(As restated)		(As restated)		(As restated)		(As restated)		(As restated)
Earnings as defined:
Pretax income	$	323,159	$	281,657	$	290,861	$	316,144	$	393,366
Add: Fixed Charges	264,672		263,516		266,231		270,051		244,269
Earnings as defined	$	587,831	$	545,173	$	557,092	$	586,195	$	637,635
Fixed charges:
Interest charges	$	264,672	$	263,516	$	266,231	$	262,679	$	229,525
Distributions on redeemable preferred securities of subsidiary trust	—		—		—		7,372		14,744
Total fixed charges	$	264,672	$	263,516	$	266,231	$	270,051	$	244,269
Ratio of earnings to fixed charges	2.2		2.1		2.1		2.2		2.6

Natural Gas Margin

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY AND COMPREHENSIVE INCOME

Projected Benefit Payments

Types of and Accounting for Derivative Instruments

Cash Flow Hedges

Letters of Credit

Pending and Recently Concluded Regulatory Proceedings - FERC

Manufactured Gas Plant Site

PUBLIC SERVICE COMPANY OF COLORADO

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME