Table ofContents

 

 

 

**UNITED STATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

**FORM 10-Q**

 
| **x**                                                                                              | ** ** | **QUARTERLY  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE   SECURITIES EXCHANGE ACT OF 1934**  |
|----------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------|
|                                                                                               |       |                                                                                                      |
| **For the quarterly period ended June 30,  2008**                                             |
| ** **                                                                                         | ** ** | ** **                                                                                                |
| **or**                                                                                             |
|                                                                                               |       |                                                                                                      |
| **o**                                                                                              | ** ** | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE   SECURITIES EXCHANGE ACT OF 1934** |
|                                                                                               |       |                                                                                                      |
| **For the transition period from            to** |

 

#### **Commission File Number: 001-3280**

#### ** **

**PublicService Company of Colorado**

**(Exact name of registrant as specified in itscharter)**

** **

| **Colorado**                                | ** ** | **84-0296600**                        |
|---------------------------------------------|------------|---------------------------------------|
| (State or other  jurisdiction of            |       | (I.R.S. Employer  Identification No.) |
| incorporation or  organization)             |       |                                  |
|                                        |       |                                  |
| **1225  17th Street, Denver**               |       |                                  |
| **Colorado**                                | ** ** | **80202**                             |
| (Address of  principal executive   offices) |       | (Zip Code)                            |

 

Registrant’stelephone number, including area code **(303)571-7511**

 

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

 

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer,a non-accelerated filer or a smaller reporting company. See the definitions of “largeaccelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2of the Exchange Act.  (Check one):

 
| Large accelerated filer  o                     |   | Accelerated filer o          |
|------------------------------------------------|--------|-----------------------------------|
|                                           |   |                              |
| Non-accelerated filer x                        |   | Smaller reporting  company o |
| (Do not check if a  smaller reporting company) |   |                              |

 

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of theExchange Act). Yes  o   No  x

 

Indicate the number of shares outstanding of each ofthe issuer’s classes of common stock, as of the latest practicable date.

 
| **Class**                      | ** ** | **Outstanding at Aug. 1, 2008** |
|--------------------------------|------------|-----------------------------------------------------|
| Common Stock,  $0.01 par value |       | 100 shares                                          |

 

Public Service Company ofColorado meets the conditions set forth in General Instruction H (1)(a) and(b) of Form 10-Q and is therefore filing this Form 10-Q with thereduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

 

 

 

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**Table of Contents**

** **

**TABLEOF CONTENTS**

** **
| **PART I - FINANCIAL INFORMATION**     | ** **                                                                                  | ** ** |
|---------------------------------------------|---------------------------------------------------------------------------------------------|------------|
|                                        |                                                                                        |       |
| Item l.                                     | Financial Statements (Unaudited)                                                            |       |
| Item 2.                                     | Management’s  Discussion and Analysis of Financial Condition and Results of Operations |       |
| Item 4                                      | Controls and  Procedures                                                                    |       |
|                                        |                                                                                        |       |
| **PART II  - OTHER INFORMATION**       | ** **                                                                                  |
|                                        |                                                                                        |       |
| Item 1.                                     | Legal Proceedings                                                                           |       |
| Item  1A.                                   | Risk  Factors                                                                               |       |
| Item  6.                                    | Exhibits                                                                                    |       |
|                                        |                                                                                        |       |
| **SIGNATURES**                              | ** **                                                                                  | ** ** |
|                                        |                                                                                        |       |
| Certifications Pursuant to Section 302 |                                                                                        |       |
| Certifications Pursuant to Section 906 |                                                                                        |       |
| Statement Pursuant to Private Litigation    |                                                                                        |       |
|                                             |                                                                                             |            |  |

 

This Form 10-Q is filedby Public Service Co. of Colorado (PSCo). PSCo is a wholly owned subsidiary ofXcel Energy Inc. (Xcel Energy). Additional information on Xcel Energy isavailable on various filings with the Securities and Exchange Commission (SEC).

 

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##### **Table of Contents**

 

##### **PART 1. FINANCIAL INFORMATION**

##### ** **

**Item 1. FINANCIAL STATEMENTS**

 

**PUBLIC SERVICE CO. OF COLORADO ANDSUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)**

**(Thousands of Dollars)**

 
| ** **                                                                                                 | ** ** | **Three Months Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                                                                 | ** ** | **2008**                                            | ** ** | **2007**                                          | ** ** | **2008** | ** ** | **2007** | ** ** |
| **Operating revenues**                                                                                     |       |                                                |       |                                              |       |   |   |   |   |
| Electric utility                                                                                           |       | $                                                   | 738,357    |                                              | $          | 638,142 |   | $ | 1,392,853 |   | $ | 1,274,642 |   |
| Natural gas utility                                                                                        |       | 249,302                                             |       | 190,157                                           |       | 812,254 |   | 706,551 |   |
| Steam and other                                                                                            |       | 7,648                                               |       | 7,299                                             |       | 18,678 |   | 18,096 |   |
| Total operating revenues                                                                                   |       | 995,307                                             |       | 835,598                                           |       | 2,223,785 |   | 1,999,289 |   |
|                                                                                                       |       |                                                |       |                                              |       |   |   |   |   |
| **Operating expenses**                                                                                     |       |                                                |       |                                              |       |   |   |   |   |
| Electric fuel and purchased power                                                                          |       | 458,991                                             |       | 350,397                                           |       | 828,494 |   | 718,130 |   |
| Cost of natural gas sold and transported                                                                   |       | 168,969                                             |       | 118,155                                           |       | 611,060 |   | 526,510 |   |
| Cost of sales — steam and other                                                                       |       | 2,859                                               |       | 2,165                                             |       | 7,060 |   | 7,011 |   |
| Other operating and maintenance expenses                                                                   |       | 155,140                                             |       | 143,148                                           |       | 303,514 |   | 288,344 |   |
| Demand-side management program expenses                                                                    |       | 7,225                                               |       | 4,660                                             |       | 19,927 |   | 9,319 |   |
| Depreciation and amortization                                                                              |       | 63,342                                              |       | 62,234                                            |       | 126,552 |   | 122,613 |   |
| Taxes (other than income taxes)                                                                            |       | 20,685                                              |       | 21,646                                            |       | 44,235 |   | 45,488 |   |
| Total operating expenses                                                                                   |       | 877,211                                             |       | 702,405                                           |       | 1,940,842 |   | 1,717,415 |   |
|                                                                                                       |       |                                                |       |                                              |       |   |   |   |   |
| **Operating income**                                                                                       |       | 118,096                                             |       | 133,193                                           |       | 282,943 |   | 281,874 |   |
|                                                                                                       |       |                                                |       |                                              |       |   |   |   |   |
| Interest and other income (expense), net                                                                   |       | 4,091                                               |       | (3,358                                            | )          | 7,311 |   | (5,482 | ) |
| Allowance for funds used during construction — equity                                                 |       | 8,048                                               |       | 2,697                                             |       | 15,626 |   | 4,742 |   |
|                                                                                                       |       |                                                |       |                                              |       |   |   |   |   |
| **Interest charges and financing costs**                                                                   |       |                                                |       |                                              |       |   |   |   |   |
| Interest charges — includes other financing costs of $1,425, $1,368,  $2,848 and $2,750, respectively |       | 35,719                                              |       | 32,573                                            |       | 72,869 |   | 66,674 |   |
| Interest and penalties related to COLI settlement                                                          |       | —                                              |       | 41,211                                            |       | — |   | 41,211 |   |
| Allowance for funds used during construction — debt                                                   |       | (4,410                                              | )          | (3,037                                            | )          | (8,510 | ) | (5,168 | ) |
| Total interest charges and financing costs                                                                 |       | 31,309                                              |       | 70,747                                            |       | 64,359 |   | 102,717 |   |
|                                                                                                       |       |                                                |       |                                              |       |   |   |   |   |
| Income before income taxes                                                                                 |       | 98,926                                              |       | 61,785                                            |       | 241,521 |   | 178,417 |   |
| Income taxes                                                                                               |       | 32,587                                              |       | 47,647                                            |       | 80,878 |   | 78,530 |   |
| **Net income**                                                                                             |       | $                                                   | 66,339     |                                              | $          | 14,138 |   | $ | 160,643 |   | $ | 99,887 |   |

 

**See Notes to Consolidated Financial Statements**

 

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**PUBLICSERVICE CO. OF COLORADO AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF CASH FLOWS(UNAUDITED)**

**(Thousands of Dollars)**

 
| ** **                                                                         | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2008**                                          | ** ** | **2007** | ** ** |
| **Operating activities**                                                           |       |                                              |       |   |   |
| Net income                                                                         |       | $                                                 | 160,643    |   | $ | 99,887 |   |
| Adjustments to reconcile net income to net cash provided by operating  activities: |       |                                              |       |   |   |
| Depreciation and amortization                                                      |       | 150,624                                           |       | 137,121 |   |
| Deferred income taxes                                                              |       | 70,091                                            |       | 6,125 |   |
| Amortization of investment tax credits                                             |       | (1,568                                            | )          | (1,962 | ) |
| Allowance for equity funds used during construction                                |       | (15,626                                           | )          | (4,742 | ) |
| Net realized and unrealized hedging and derivative transactions                    |       | 3,779                                             |       | 3,420 |   |
| Changes in operating assets and liabilities:                                       |       |                                              |       |   |   |
| Accounts receivable                                                                |       | 10,419                                            |       | 25,209 |   |
| Accrued unbilled revenues                                                          |       | 117,149                                           |       | (51,144 | ) |
| Inventories                                                                        |       | 8,540                                             |       | 69,661 |   |
| Recoverable purchased natural gas and electric energy costs                        |       | (44,434                                           | )          | 156,337 |   |
| Prepayments and other                                                              |       | 6,427                                             |       | 5,303 |   |
| Accounts payable                                                                   |       | (80,523                                           | )          | (63,277 | ) |
| Net regulatory assets and liabilities                                              |       | (4,399                                            | )          | 1,702 |   |
| Other current liabilities                                                          |       | (64,791                                           | )          | 85,845 |   |
| Change in other noncurrent assets                                                  |       | 5,644                                             |       | (38,104 | ) |
| Change in other noncurrent liabilities                                             |       | (33,942                                           | )          | (8,515 | ) |
| Net cash provided by operating activities                                          |       | 288,033                                           |       | 422,866 |   |
|                                                                               |       |                                              |       |   |   |
| **Investing activities**                                                           |       |                                              |       |   |   |
| Utility capital/construction expenditures                                          |       | (353,030                                          | )          | (330,465 | ) |
| Allowance for equity funds used during construction                                |       | 15,626                                            |       | 4,742 |   |
| Investments in utility money pool                                                  |       | (199,900                                          | )          | (147,100 | ) |
| Repayments from utility money pool                                                 |       | 300,500                                           |       | 147,100 |   |
| Other investments                                                                  |       | 1,489                                             |       | (6,787 | ) |
| Net cash used in investing activities                                              |       | (235,315                                          | )          | (332,510 | ) |
|                                                                               |       |                                              |       |   |   |
| **Financing activities**                                                           |       |                                              |       |   |   |
| Proceeds from (repayment of) short-term borrowings, net                            |       | 46,638                                            |       | (197,850 | ) |
| Borrowings under utility money pool arrangement                                    |       | 447,200                                           |       | 367,800 |   |
| Repayments under utility money pool arrangement                                    |       | (426,200                                          | )          | (268,800 | ) |
| Repayment of long-term debt, including reacquisition premiums                      |       | (717                                              | )          | (100,691 | ) |
| Capital contribution from parent                                                   |       | 13,174                                            |       | 240,176 |   |
| Dividends paid to parent                                                           |       | (136,597                                          | )          | (130,292 | ) |
| Net cash used in financing activities                                              |       | (56,502                                           | )          | (89,657 | ) |
|                                                                               |       |                                              |       |   |   |
| Net increase (decrease) in cash and cash equivalents                               |       | (3,784                                            | )          | 699 |   |
| Cash and cash equivalents at beginning of period                                   |       | 7,650                                             |       | 3,011 |   |
| Cash and cash equivalents at end of period                                         |       | $                                                 | 3,866      |   | $ | 3,710 |   |
|                                                                               |       |                                              |       |   |   |
| Supplemental disclosure of cash flow information:                                  |       |                                              |       |   |   |
| Cash paid for interest (net of amounts capitalized)                                |       | $                                                 | 62,481     |   | $ | 59,779 |   |
| Cash paid (received) for income taxes (net of refunds received)                    |       | 28,662                                            |       | 39,816 |   |
|                                                                               |       |                                              |       |   |   |
| Supplemental disclosure of non-cash investing transactions:                        |       |                                              |       |   |   |
| Property, plant and equipment additions in accounts payable                        |       | $                                                 | 16,588     |   | $ | 11,798 |   |

 

See Notes to Consolidated Financial Statements

 

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**PUBLICSERVICE CO. OF COLORADO AND SUBSIDIARIES**

**CONSOLIDATEDBALANCE SHEETS (UNAUDITED)**

**(Thousandsof Dollars)**

 
| ** **                                                                            | ** ** | **June 30, 2008** | ** ** | **Dec. 31, 2007** | ** ** |
|---------------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| **ASSETS**                                                                            | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| Current assets:                                                                       |       |                        |       |                        |       |
| Cash and cash equivalents                                                             |       | $                           | 3,866      |                        | $          | 7,650 |   |
| Investments in utility money pool  arrangement                                        |       | —                      |       | 100,600                     |       |
| Accounts receivable, net                                                              |       | 352,189                     |       | 375,265                     |       |
| Accounts receivable from affiliates                                                   |       | 47,241                      |       | 34,584                      |       |
| Accrued unbilled revenues                                                             |       | 243,042                     |       | 360,191                     |       |
| Inventories                                                                           |       | 201,380                     |       | 209,920                     |       |
| Recoverable purchased natural gas and  electric energy costs                          |       | 58,291                      |       | 13,857                      |       |
| Deferred income taxes                                                                 |       | 13,814                      |       | 59,564                      |       |
| Derivative instruments valuation                                                      |       | 50,966                      |       | 33,635                      |       |
| Prepayments and other                                                                 |       | 32,364                      |       | 17,851                      |       |
| Total current assets                                                                  |       | 1,003,153                   |       | 1,213,117                   |       |
|                                                                                  |       |                        |       |                        |       |
| Property, plant and equipment, net                                                    |       | 7,250,756                   |       | 7,029,155                   |       |
|                                                                                  |       |                        |       |                        |       |
| Other assets:                                                                         |       |                        |       |                        |       |
| Regulatory assets                                                                     |       | 508,385                     |       | 539,989                     |       |
| Derivative instruments valuation                                                      |       | 130,475                     |       | 141,410                     |       |
| Other                                                                                 |       | 46,127                      |       | 55,759                      |       |
| Total other assets                                                                    |       | 684,987                     |       | 737,158                     |       |
| Total assets                                                                          |       | $                           | 8,938,896  |                        | $          | 8,979,430 |   |
| ** **                                                                            | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| **LIABILITIES AND EQUITY**                                                            | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| Current liabilities:                                                                  |       |                        |       |                        |       |
| Current portion of long-term debt                                                     |       | $                           | 301,484    |                        | $          | 301,445 |   |
| Short-term debt                                                                       |       | 317,645                     |       | 271,007                     |       |
| Borrowings under utility money pool  arrangement                                      |       | 21,000                      |       | —                      |       |
| Accounts payable                                                                      |       | 386,703                     |       | 466,710                     |       |
| Accounts payable to affiliates                                                        |       | 32,276                      |       | 27,445                      |       |
| Taxes accrued                                                                         |       | 41,056                      |       | 76,569                      |       |
| Dividends payable to parent                                                           |       | 67,111                      |       | 68,453                      |       |
| Derivative instruments valuation                                                      |       | 20,581                      |       | 21,521                      |       |
| Accrued interest                                                                      |       | 44,664                      |       | 45,486                      |       |
| Other                                                                                 |       | 80,655                      |       | 108,979                     |       |
| Total current liabilities                                                             |       | 1,313,175                   |       | 1,387,615                   |       |
|                                                                                  |       |                        |       |                        |       |
| Deferred credits and other liabilities:                                               |       |                        |       |                        |       |
| Deferred income taxes                                                                 |       | 1,131,428                   |       | 1,090,740                   |       |
| Deferred investment tax credits                                                       |       | 53,598                      |       | 55,166                      |       |
| Regulatory liabilities                                                                |       | 526,320                     |       | 516,401                     |       |
| Pension and employee benefit obligations                                              |       | 187,089                     |       | 231,232                     |       |
| Customer advances                                                                     |       | 288,211                     |       | 280,270                     |       |
| Derivative instruments valuation                                                      |       | 63,269                      |       | 84,190                      |       |
| Asset retirement obligations                                                          |       | 45,057                      |       | 44,267                      |       |
| Other                                                                                 |       | 16,291                      |       | 12,063                      |       |
| Total deferred credits and other  liabilities                                         |       | 2,311,263                   |       | 2,314,329                   |       |
|                                                                                  |       |                        |       |                        |       |
| Commitments and contingent liabilities                                                |       |                        |       |                        |       |
| Capitalization:                                                                       |       |                        |       |                        |       |
| Long-term debt                                                                        |       | 1,891,261                   |       | 1,891,644                   |       |
| Common stock — authorized 100 shares of  $0.01 par value; outstanding 100 shares |       | —                      |       | —                      |       |
| Additional paid in capital                                                            |       | 2,772,302                   |       | 2,759,128                   |       |
| Retained earnings                                                                     |       | 639,038                     |       | 614,267                     |       |
| Accumulated other comprehensive income                                                |       | 11,857                      |       | 12,447                      |       |
| Total common stockholder’s equity                                                |       | 3,423,197                   |       | 3,385,842                   |       |
| Total liabilities and equity                                                          |       | $                           | 8,938,896  |                        | $          | 8,979,430 |   |

 

See Notes to Consolidated FinancialStatements

 

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**PUBLICSERVICE CO. OF COLORADO AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)**

** **

In the opinion of management, the accompanying unaudited consolidatedfinancial statements contain all adjustments necessary to present fairly thefinancial position of PSCo and its subsidiaries as of June 30, 2008, and Dec. 31,2007; the results of its operations for the three and six months ended June 30,2008 and 2007; and its cash flows for the six months ended June 30, 2008and 2007.  Due to the seasonality ofelectric and natural gas sales of PSCo, such interim results are notnecessarily an appropriate base from which to project annual results.

 

**1.****              SignificantAccounting Policies**

 

Except to the extent updated or described below,the significant accounting policies set forth in Note 1 to the consolidatedfinancial statements in PSCo’s Annual Report on Form 10-K for the yearended Dec. 31, 2007, appropriately represent, in all material respects,the current status of accounting policies and are incorporated herein byreference.

 

***Fair ValueMeasurements******—*** PSCo presentscommodity derivatives at estimated fair values in its consolidated financialstatements.  The most observable inputsavailable are used to determine the fair value of each contract.  In the absence of a quoted price for anidentical contract in an active market, PSCo may use broker quotes foridentical or similar contracts, or internally prepared valuation models todetermine fair value.

 

**2.****              Recently IssuedAccounting Pronouncements**

 

***Statement ofFinancial Accounting Standards (SFAS) No. 157********Fair ValueMeasurements**********(****SFAS No. 157)****** —***In September 2006,the Financial Accounting Standards Board (FASB) issued SFAS No. 157,which provides a single definition of fair value, together with a framework formeasuring it, and requires additional disclosure about the use of fair value tomeasure assets and liabilities. SFAS No. 157 also emphasizes that fairvalue is a market-based measurement, and sets out a fair value hierarchy withthe highest priority being quoted prices in active markets. Fair valuemeasurements are disclosed by level within that hierarchy. SFAS No. 157was effective for financial statements issued for fiscal years beginning after Nov. 15,2007.

 

Asof Jan. 1, 2008, PSCo adopted SFAS No. 157 for all assets andliabilities measured at fair value except for non-financial assets andnon-financial liabilities measured at fair value on a non-recurring basis, as permittedby FASB Staff Position No. 157-2. The adoption did not have a material impact on its consolidatedfinancial statements.  For additionaldiscussion and SFAS No. 157 required disclosures see Note 9 to theconsolidated financial statements.

 

***The Fair Value Option for Financial Assetsand Financial Liabilities - Including an Amendment of FASB Statement No. 115(SFAS No. 159)*** — In February 2007, the FASB issuedSFAS No. 159, which provides companies with an option to measure, atspecified election dates, many financial instruments and certain other items atfair value that are not currently measured at fair value.  A company that adopts SFAS No. 159 willreport unrealized gains and losses on items, for which the fair value optionhas been elected, in earnings at each subsequent reporting date.  This statement also establishes presentationand disclosure requirements designed to facilitate comparisons between entitiesthat choose different measurement attributes for similar types of assets andliabilities.  This statement waseffective for fiscal years beginning after Nov. 15, 2007.  Effective Jan. 1, 2008, PSCo adoptedSFAS No. 159 and the adoption did not have a material impact on itsconsolidated financial statements.

 

***BusinessCombinations (SFAS No. 141 (revised 2007)) —***InDecember 2007, the FASB issued SFAS No. 141R, which establishesprinciples and requirements for how an acquirer in a business combinationrecognizes and measures in its financial statements the identifiable assetsacquired, the liabilities assumed, and any noncontrolling interest; recognizesand measures the goodwill acquired in the business combination or a gain from abargain purchase; and determines what information to disclose to enable usersof the financial statements to evaluate the nature and financial effects of thebusiness combination. SFAS No. 141R is to be applied prospectively tobusiness combinations for which the acquisition date is on or after thebeginning of an entity’s fiscal year that begins on or after Dec. 15, 2008.PSCo will evaluate the impact of SFAS No. 141R on its consolidatedfinancial statements for any potential business combinations subsequent to Jan. 1,2009.

 

***Noncontrolling Interests inConsolidated Financial Statements, an Amendment of Accounting Research Bulletin(ARB) No. 51 (SFAS No. 160)*** — In December 2007, the FASBissued SFAS No. 160, which establishes accounting and reporting standardsthat require the ownership interest in subsidiaries held by parties other thanthe parent be clearly identified and presented in the consolidated balancesheets within equity, but separate from the parent’s equity; the amount ofconsolidated net income attributable to the parent and the noncontrollinginterest be clearly identified and presented on the face of the 

 

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consolidated statement of earnings; and changes in a parent’s ownershipinterest while the parent retains its controlling financial interest in itssubsidiary be accounted for consistently. This statement is effective forfiscal years beginning on or after Dec. 15, 2008. PSCo is currentlyevaluating the impact of SFAS No. 160 on its consolidated financialstatements.

 

***Disclosures aboutDerivative Instruments and Hedging Activities (SFAS No. 161)***— In March 2008, the FASB issued SFAS No. 161, which is intendedto enhance disclosures to help users of the financial statements betterunderstand how derivative instruments and hedging activities affect an entity’sfinancial position, financial performance and cash flows.  SFAS No. 161 amends and expands thedisclosure requirements of SFAS No. 133, *Accountingfor Derivative Instruments and Hedging Activities*, to require disclosuresof objectives and strategies for using derivatives, gains and losses onderivative instruments, and credit-risk-related contingent features inderivative agreements.  SFAS No. 161is effective for financial statements issued for fiscal years and interimperiods beginning after Nov. 15, 2008, with early applicationencouraged.  PSCo is currently evaluatingthe impact of adoption of SFAS No. 161 on its consolidated financialstatements.

 

***The Hierarchy of Generally AcceptedAccounting Principles (GAAP) (SFAS No. 162)  —***In May 2008, the FASBissued SFAS No. 162, which establishesthe GAAP hierarchy, identifying the sources of accounting principles and theframework for selecting the principles to be used in the preparation offinancial statements.  SFAS No. 162is effective 60 days following the SEC’s approval of the Public CompanyAccounting Oversight Board amendments to AU Section 411, *The Meaning of Present Fairly in Conformity withGenerally Accepted Accounting Principles.*PSCo does notbelieve that implementation of SFAS No. 162will have any impact on its consolidated financial statements.

 

***Accounting for Deferred Compensationand Postretirement Benefit Aspects of Endorsement Split-Dollar Life InsuranceArrangements (Emerging Issues Task Force (EITF) Issue No. 06-4)*** — In June 2006, the EITF reached aconsensus on EITF No. 06-4, which provides guidance on the recognition ofa liability and related compensation costs for endorsement split-dollar lifeinsurance policies that provide a benefit to an employee that extends topostretirement periods. Therefore, this EITF would not apply to a split-dollarlife insurance arrangement that provides a specified benefit to an employeethat is limited to the employee’s active service period with an employer.  EITF No. 06-4 was effective for fiscalyears beginning after Dec. 15, 2007, with earlier applicationpermitted.  Upon adoption of EITF No. 06-4on Jan. 1, 2008, PSCo recorded a liability of $0.6 million, net of tax, asa reduction of retained earnings.  Thereafter,changes in the liability are reflected in operating results.

 

***Accountingfor Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF No. 06-11)****—*InJune 2007, the EITF reached a consensus on EITF No. 06-11, whichstates that an entity should recognize a realized tax benefit associated withdividends on nonvested equity shares and nonvested equity share units chargedto retained earnings as an increase in additional paid in capital. The amountrecognized in additional paid in capital should be included in the pool ofexcess tax benefits available to absorb potential future tax deficiencies onshare-based payment awards. EITF No. 06-11 should be applied prospectivelyto income tax benefits of dividends on equity-classified share-based paymentawards that are declared in fiscal years beginning after Dec. 15, 2007.The adoption of EITF No. 06-11 did not have a material impact on PSCo’sconsolidated financial statements.

** **

**3.****              Selected BalanceSheet Data**

 
| **(Thousands of Dollars)** | ** ** | **June 30, 2008** | ** ** | **Dec. 31, 2007** | ** ** |
|--------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| Accounts receivable, net:            |       |                        |       |                        |       |
| Accounts receivable                  |       | $                           | 374,784    |                        | $          | 398,566 |   |
| Less allowance for bad debts         |       | (22,595                     | )          | (23,301                     | )          |
|                                 |       | $                           | 352,189    |                        | $          | 375,265 |   |
|                                 |       |                        |       |                        |       |
| Inventories:                         |       |                        |       |                        |       |
| Materials and supplies               |       | $                           | 42,339     |                        | $          | 40,409 |   |
| Fuel                                 |       | 48,584                      |       | 40,811                      |       |
| Natural gas                          |       | 110,457                     |       | 128,700                     |       |
|                                 |       | $                           | 201,380    |                        | $          | 209,920 |   |

 

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| **(Thousands of Dollars)** | ** ** | **June 30, 2008** | ** ** | **Dec. 31, 2007** | ** ** |
|--------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| Property, plant and equipment, net:  |       |                        |       |                        |       |
| Electric utility plant               |       | $                           | 6,766,680  |                        | $          | 6,633,695 |   |
| Natural gas utility plant            |       | 1,917,913                   |       | 1,887,824                   |       |
| Common utility and other property    |       | 739,951                     |       | 726,049                     |       |
| Construction work in progress        |       | 991,898                     |       | 864,517                     |       |
| Total property, plant and equipment  |       | 10,416,442                  |       | 10,112,085                  |       |
| Less accumulated depreciation        |       | (3,165,686                  | )          | (3,082,930                  | )          |
|                                 |       | $                           | 7,250,756  |                        | $          | 7,029,155 |   |

 

**4.****              Income Taxes**

 

***Accounting for Uncertainty in IncomeTaxes — an interpretation of FASB Statement No. 109 ***(FIN 48)************— PSCois a member of the Xcel Energy affiliated group that files consolidated incometax returns.  In the first quarter of2008, the Internal Revenue Service (IRS) completed an examination of XcelEnergy’s federal income tax returns for 2004 and 2005 (and research credits for2003). The IRS did not propose any material adjustments for those tax years.Tax year 2004 is the earliest open year and the statute of limitationsapplicable to Xcel Energy’s 2004 federal income tax return remains open until Dec. 31,2009. Xcel Energy expects the IRS to commence their examination of tax years2006 and 2007 in the third quarter of 2008.

 

As of June 30,2008, PSCo’s earliest open tax year in which an audit can be initiated by statetaxing authorities under applicable statutes of limitations is 2003. Therecurrently are no state income tax audits in progress.

 

The amount ofunrecognized tax benefits was $8.8 million and $10.3 million on Dec. 31,2007 and June 30, 2008, respectively. These unrecognized tax benefit amounts were reduced by the tax benefitsassociated with net operating loss (NOL) and tax credit carryovers of $3.8million and $4.7 million as of Dec. 31, 2007 and June 30, 2008,respectively.

 

Theunrecognized tax benefit balance included $2.8 million and $2.9 million of taxpositions on Dec. 31, 2007 and June 30, 2008, respectively, which ifrecognized would affect the annual effective tax rate.  In addition, the unrecognized tax benefitbalance included $6.0 million and $7.4 million of tax positions on Dec. 31,2007 and June 30, 2008, respectively, for which the ultimate deductibilityis highly certain but for which there is uncertainty about the timing of suchdeductibility.  A change in the period ofdeductibility would not affect the effective tax rate but would accelerate thepayment of cash to the taxing authority to an earlier period.

 

The increasein the unrecognized tax benefit balance of $0.7 million from April 1, 2008to June 30, 2008, was due to the addition of similar uncertain taxpositions related to ongoing activity. PSCo’s amount of unrecognized tax benefits could significantly change inthe next 12 months when the IRS and state audits resume and as statutes oflimitations expire.  At this time, as itrelates to upcoming audits, it is not reasonably possible to estimate anoverall range of possible change. However, as it relates to the expiration ofstatutes of limitations, it is reasonably possible that the amount ofunrecognized tax benefits could decrease up to $2.0 million.

 

The liabilityfor interest related to unrecognized tax benefits is partially offset by theinterest benefit associated with NOL and tax credit carryovers.  The amount of interest expense related tounrecognized tax benefits reported within interest charges in the secondquarter of 2008 was $0.2 million.  Theliability for interest related to unrecognized tax benefits was $3.8 million onDec. 31, 2007 and $4.1 million on June 30, 2008.

 

No amountswere accrued for penalties in the second quarter of 2008.  The liability for penalties related tounrecognized tax benefits was $1.0 million on Dec. 31, 2007 and June 30,2008.

 

***Other Income Tax Matters*****—** The effective tax rate was33.5 percent for the first six months of 2008, compared with 44.0 percent forthe same period in 2007.  The highereffective tax rate for the first six months of 2007 was primarily due to thecorporate-owned life insurance (COLI) settlement, partially offset by anincrease in the forecasted annual effective tax rate for 2008, which waslargely a result of PSR Investments, Inc. (PSRI) terminating the COLIprogram in 2007. Without these charges and benefits, the effective tax rate forthe first six months of 2008 and 2007 would have been 33.5 percent and 38.0percent, respectively.

 

***COLI —***OnJune 19, 2007, a settlement in principle was reached between Xcel Energyand representatives of the United States Government regarding PSCo’s right todeduct interest expense on policy loans related to its COLI program that 

 

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insured lives of certainPSCo employees. These COLI policies were owned and managed by PSRI, a whollyowned subsidiary of PSCo.

 

In September 2007, XcelEnergy and the United States finalized a settlement, which terminated the taxlitigation pending between the parties. As a result of the settlement, thelawsuit filed by Xcel Energy in the United States District Court has been dismissedand the Tax Court proceedings are in the process of being dismissed.  Xcel Energy paid 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.

 

**5.****              Rate Matters**

 

Except to the extent noted below, the circumstances set forth in Note12 to the consolidated financial statements included in PSCo’s Annual Report onForm 10-K for the year ended Dec. 31, 2007 appropriately represent,in all material respects, the current status of other rate matters, and areincorporated herein by reference. The following include unresolved proceedingsthat are material to PSCo’s financial position.

 

***Pending and RecentlyConcluded Regulatory Proceedings — Colorado Public Utilities Commission(CPUC)***

 

**Electric,Purchased Gas and Resource Adjustment Clauses**

** **

***Transmission CostAdjustment Rider —***In September 2007, PSCofiled with the CPUC a request to implement a transmission cost adjustment rider(TCA), which would recover approximately $18.2 million in 2008. Thisfiling was pursuant to recently enacted legislation, which entitled publicutilities to recover, through a separate rate adjustment clause, the costs thatthey prudently incur in planning, developing and completing the construction orexpansion of transmission.

 

In December 2007, the CPUC approved PSCo’s application toimplement the TCA. The CPUC limited the scope of the costs that could berecovered through the rider during 2008 to only those costs associated withtransmission investment made after the new legislation authorizing the riderbecame effective on March 26, 2007. The CPUC also will require PSCo tobase its revenue requirement calculation on a thirteen-month average nettransmission plant balance. As a result of the CPUC’s decision, PSCoimplemented a rider on Jan. 1, 2008, expected to recover approximately$4.5 million in 2008.

 

***Enhanced Demand SideManagement (DSM) Program —***In October 2007,PSCo filed an application with the CPUC for approval to implement an expandedDSM program and to revise its DSM cost adjustment mechanism to include currentcost recovery and incentives designed to reward PSCo for successfullyimplementing cost-effective DSM programs and measures. In July 2008, theCPUC issued an order approving PSCo’s proposal to expand the DSM programand recover 100 percent of its forecasted expenses associated with the DSMprogram during the year in which the rider is in effect, beginning in2009.  An incentive mechanism was also approved to reward PSCo formeeting and exceeding program goals.

 

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

*** ***

***Pacific NorthwestFERC Refund Proceeding —***In July 2001, theFERC ordered a preliminary hearing to determine whether there may have beenunjust and unreasonable charges for spot market bilateral sales in the PacificNorthwest for the period Dec. 25, 2000 through June 20, 2001. PSCosupplied energy to the Pacific Northwest markets during this period and hasbeen an active participant in the hearings. In September 2001, thepresiding administrative law judge (ALJ) concluded that prices in the PacificNorthwest during the referenced period were the result of a number of factors,including the shortage of supply, excess demand, drought and increased naturalgas prices. Under these circumstances, the ALJ concluded that the prices in thePacific Northwest markets were not unreasonable or unjust and no refunds shouldbe ordered. Subsequent to the ruling, the FERC has allowed the parties torequest additional evidence regarding the use of certain strategies and howthey may have impacted the markets in the Pacific Northwest markets. For thereferenced period, parties have claimed that the total amount of transactionswith PSCo subject to refund are $34 million. In June 2003, the FERCissued an order terminating the proceeding without ordering furtherproceedings. Certain purchasers filed appeals of the FERC’s orders in thisproceeding with the U. S. Court of Appeals for the Ninth Circuit.

 

In an orderissued in August 2007, the Ninth Circuit remanded the proceeding back tothe FERC. The court of appeals preliminarily determined that it hadjurisdiction to review the FERC’s decision not to order refunds and remandedthe case back to the FERC, directing that the FERC consider evidence that hadbeen presented regarding intentional market manipulation in the Californiamarkets and its potential ties to transactions in the Pacific Northwest. Thecourt of appeals also indicated that the FERC should consider other rulingsaddressing overcharges in the California organized markets.  The FERC has yet to act on this order onremand.

 

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***PSCo Wholesale Rate Case —***In February 2008,PSCo requested a $12.5 million, or 5.88 percent, increase in wholesale rates,based on 11.5 percent requested return on equity (ROE).  The $12.5 million total increase was composedof  $8.8 million of traditional baserate recovery and $3.7 million of construction work in progress recovery forthe Comanche 3 and Fort St. Vrain projects.  The increase is applicable to all wholesale firm service customers withthe exception of Intermountain Rural Electric Cooperative, which would be undera rate moratorium until January 2009.

 

In March 2008,PSCo reached an agreement with Rural Electric Association (REA) customers HolyCross, Yampa Valley and Grand Valley, which resolved all issues based on a “blackbox” settlement with an implied ROE of 10.4 percent.  Parties filed the settlement with the FERC onApril 17, 2008, with rates effective May 1, 2008.  PSCo has reached an agreement with the citiesof Burlington, Center and Aquila under the same substantive terms andconditions as the REA settlement.  Thissettlement was filed with the FERC on April 25, 2008.  The settlements provide for:

 

·              Atraditional annual rate base rate increase of $6.6 million with allowance for funds used during constructioncontinuing for Comanche and Fort St. Vrain.

·              Implementationof new rates several months earlier than is typical in a disputed filing.

·              Theability to implement rates in PSCo’s next general rate case that will involveComanche 3 costs upon a nominal suspension.

 

The FERC approved the settlement agreementson June 19, 2008.

 

**6.****              Commitments andContingent Liabilities**

 

Except asnoted below, the circumstances set forth in Notes 12 and 13 to the consolidatedfinancial statements in PSCo’s Annual Report on Form 10-K for the yearended Dec. 31, 2007 and Note 5 to the consolidated financial statements inthis Quarterly Report on Form 10-Q appropriately represent, in allmaterial respects, the current status of respective commitments and contingentliabilities and are incorporated herein by reference. The following areunresolved contingencies that are material to PSCo’s financial position.

 

***Operating Leases* —****During the second quarter of 2008,two purchase power agreements were commenced that are being accounted for asoperating leases in accordance with EITF No. 01-8, *Determining Whether an Arrangement Contains a Lease,*andSFAS No. 13, *Accounting for Leases*.These agreements require capacity payments of $12.1 million, $18.2 million,$18.2 million, $18.2 million, $18.2 million and $330.3 million for 2008, 2009,2010, 2011, 2012 and thereafter, respectively.

 

**EnvironmentalContingencies**

 

PSCo has been,or is currently, involved with the cleanup of contamination from certainhazardous substances at several sites. In many situations, PSCo believes itwill 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 (PRP)and through the rate regulatory process. New and changing federal and state environmental mandates can alsocreate added financial liabilities for PSCo, which are normally recoveredthrough the rate regulatory process.  Tothe extent any costs are not recovered through the options listed above, PSCowould be required to recognize an expense.

 

***Site Remediation****—*PSCo must pay all or a portion of thecost to remediate sites where past activities of PSCo or other parties havecaused environmental contamination. Environmental contingencies could arise from various situationsincluding sites of former manufactured gas plants (MGPs) operated by PSCo, itspredecessors, or other entities; and third party sites, such as landfills, towhich PSCo is alleged to be a PRP that sent hazardous materials andwastes.  At June 30, 2008, theliability for the cost of remediating these sites was estimated to be $1.7million, of which $0.7 million was considered to be a current liability.

 

###### ***Manufactured Gas Plant Site***

######  

***Fort CollinsManufactured Gas Plant Site****** —***Prior to1926, the Poudre Valley Gas Co. operated an MGP in Fort Collins, Colo., not farfrom the Cache la Poudre River.  In 1926,after acquiring the assets of the Poudre Valley Gas Co., PSCo shut down the MGPand has subsequently sold most of the property. In 2002, an oily substance similar to MGP byproducts was discovered inthe Cache la Poudre River.  In November 2004,PSCo entered into an agreement with the Environmental Protection Agency (EPA),the city of Fort Collins and Schrader Oil Co. (Schrader) under which PSCoperformed remediation and monitoring work. PSCo has substantially completed work at the site, with the exception ofongoing maintenance and monitoring.

 

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InNovember 2006, PSCo filed a natural gas rate case with the CPUC requestingrecovery of additional clean-up costs at the Fort Collins MGP site spentthrough September 2006, plus unrecovered amounts previously authorizedfrom the last rate case, which amounted to $10.8 million to be amortized overfour years.  In June 2007, PSCoentered into a settlement agreement that included recovery of the full $10.8million, but with a five-year amortization period.  The CPUC approved the agreement on June 18,2007.  The total amount to be recoveredfrom customers is $13.1 million.  Estimatedfuture project costs, based upon an assumed 30-year system operating life,including EPA oversight costs, are approximately $3.9 million.

 

In April 2005, PSCo brought a contribution action against Schraderand related parties alleging Schrader released hazardous substances into theenvironment and these releases caused MGP byproducts to migrate to the Cache laPoudre River, thereby substantially increasing the scope and cost ofremediation.  PSCo requested damages,including a portion of the costs PSCo incurred to investigate and removecontaminated sediments from the Cache la Poudre River.  In December 2005, the court deniedSchrader’s request to dismiss the PSCo suit. Schrader thereafter filed a response to the PSCo complaint and acounterclaim against PSCo for its response costs under the ComprehensiveEnvironmental Response Compensation and Liability Act (CERCLA) and under theResource Conservation and Recovery Act (RCRA). Schrader alleged as part of its counterclaim an “imminent andsubstantial endangerment” of its property as defined by RCRA.  PSCo filed a motion for partial summaryjudgment to dismiss Schrader’s RCRA claim. In October 2007, the court granted PSCo’s motion for partialsummary judgment and dismissed Schrader’s RCRA claim.  Schrader also filed a motion for summaryjudgment seeking to dismiss PSCo’s CERCLA claim, which was denied by the courtin April 2008.  The case iscurrently scheduled for a January 2009 trial. Any costs recovered fromSchrader are expected to operate as a credit to ratepayers.

 

# ***Third Party and Other Environmental SiteRemediation***

# *** ***

***Asbestos Removal*—**Someof PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that containit are demolished or renovated.  PSCo hasrecorded an estimate for final removal of the asbestos as an asset retirementobligation.  See additional discussion ofasset retirement obligations in Note 13 of the PSCo Annual Report on Form 10-Kfor the year ended Dec. 31, 2007. It may be necessary to remove some asbestos to perform maintenance ormake improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and isrecorded as incurred as operating expenses for maintenance projects, capitalexpenditures for construction projects or removal costs for demolitionprojects.

 

***Other Environmental Requirements***

 

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

 

The EPA requires states to developimplementation plans to comply with BART by December 2007.  States are required to identify thefacilities that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) andparticulate matter emissions under BART and then set BART emissions limits forthose facilities.  In May 2006, theColorado Air Quality Control Commission (AQCC) promulgated BART regulationsrequiring certain major stationary sources to evaluate and install, operate andmaintain BART or an approved BART alternative to make reasonable progresstoward meeting the national visibility goal. PSCo estimates that implementation of the BART alternatives will costapproximately $201 million in capital costs, which includes approximately $59million 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 berecoverable from customers.  Emissionscontrols are expected to be installed between 2011 and 2014.  On June 4, 2007, the Colorado AirPollution Control Division (CAPCD) approved PSCo’s BART analysis and obtainedpublic comment on its BART determination and PSCo’s BART permits. The AQCCapproved the CAPCD’s BART determination for PSCo during a public hearing in December 2007.CAPCD’s BART determinations and corresponding provisions of the regional hazestate implementation plan will be submitted to the EPA for approval in 2008. Inaddition, in early 2008, the CAPCD initiated a stakeholder process to establishreasonable progress goals for Colorado’s Class I areas. To meet thesegoals, more controls may be required from certain sources, which may or may notinclude those sources previously controlled under BART. The reasonable progressstakeholder process has been placed on hold by the CAPCD due to limitedresources and will resume in early 2009.

 

***Clean Air Mercury Rule ***—In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR),which regulated mercury emissions from power plants.  In February 2008, the D.C. Circuit Courtof Appeals vacated CAMR, which impacts federal CAMR requirements, but notnecessarily state-only mercury legislation and rules.  Colorado’s mercury rule requires mercuryemission controls capable of achieving 80 percent capture be installed at thePawnee Generating Station by 2012 and all other Colorado units by 2014.  PSCo is in the process of installing mercurymonitors on six Colorado units at an estimated 

 

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aggregate costof approximately $2.3 million.  PSCo isevaluating the mercury emission controls required to meet the state rule andis currently unable to provide a capital cost estimate.

 

***Federal Clean Water Act***—The Federal Clean Water Act requires the EPA to regulate cooling water intakestructures to assure that these structures reflect the “best technologyavailable” (BTA) for minimizing adverse environmental impacts.  In July 2004, the EPA published phase IIof the rule, which applies to existing cooling water intakes at steam-electricpower plants. Several lawsuits were filed against the EPA in the United StatesCourt of Appeals for the Second Circuit challenging the phase IIrulemaking.  In January 2007, thecourt issued its decision and remanded virtually every aspect of the rule tothe EPA for reconsideration.  In June 2007,the EPA suspended the deadlines and referred any implementation to each state’sbest professional judgment until the EPA is able to fully respond to thecourt-ordered remand.  As a result, therule’s compliance requirements and associated deadlines are currentlyunknown.  It is not possible to providean accurate estimate of the overall cost of this rulemaking at this time due tothe many uncertainties involved.  In April 2008,the U.S. Supreme Court granted limited review of the Second Circuit’s opinionto determine whether the EPA has the authority to consider costs and benefitsin assessing BTA.  A decision is notexpected until 2009.

 

***Notice of Violation***— In July 2002, PSCo received a Notice of Violation (NOV) from the EPAalleging violations of the New Source Review (NSR) requirements of the CleanAir Act (CAA) at the Comanche and Pawnee plants in Colorado.  The NOV specifically alleges that variousmaintenance, repair and replacement projects undertaken at the plants in themid- to late-1990s should have required a permit under the NSR process.  PSCo believes it has acted in full compliancewith the CAA and NSR process.  Itbelieves that the projects identified in the NOV fit within the routinemaintenance, repair and replacement exemption contained within the NSRregulations or are otherwise not subject to the NSR requirements.  PSCo disagrees with the assertions containedin the NOV and intends to vigorously defend its position.

 

***Cherokee StationAlleged Clean Air Act Violations*** — In January 2008,Xcel Energy, the parent company of PSCo, received a notice letter from RockyMountain Clean Air Action stating that the group intends to sue Xcel Energy foralleged CAA violations at Cherokee Station. The group claims that Cherokee Station’s opacity emissions have exceededallowable limits over the past five years and that its opacity monitorsexceeded downtime limits.  Xcel Energydisputes these claims and believes they are without merit.  The CAA requires notice be given 60 daysprior to filing a lawsuit.  If the groupdoes in fact file its threatened lawsuit, Xcel Energy will vigorously defenditself against these claims.

 

**Legal Contingencies**

** **

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

 

**CabinCreek Hydro Generating Station Accident**

 

In October 2007,employees of RPI Coatings Inc. (RPI), a contractor retained by PSCo, wereapplying an epoxy coating to the inside of a penstock at PSCo’s Cabin CreekHydro Generating Station near Georgetown, Colo. This work was being performedas part of a corrosion prevention effort. A fire occurred inside the penstock, which is a 4,000-foot long, 12-footwide pipe used to deliver water from a reservoir to the hydro facility. Four ofthe nine RPI employees working inside the penstock were positioned below thefire and were able to exit the pipe. The remaining five RPI employees wereunable to exit the penstock. Rescue crews located the five employees a fewhours later and confirmed their deaths. The accident was investigated by severalstate and federal agencies, including the federal Occupational Safety andHealth Administration (OSHA), U.S. Chemical Safety Board and the ColoradoBureau of Investigations. In March 2008, OSHA proposed penalties totaling$189,900 for twenty-two serious violations and three willful violations arisingout of the accident. In April 2008, Xcel Energy notified OSHA of itsdecision to contest all of the proposed citations. On May 28, 2008 theSecretary of Labor filed its complaint, and Xcel Energy subsequently filed itsanswer on June 17, 2008.

 

**Environmental Litigation**

** **

***Comanche 3Permit Litigation******—***In August 2005,Citizens for Clean Air and Water in Pueblo and Southern Colorado and CleanEnergy Action filed a complaint in Colorado state court against the CAPCDalleging that the division improperly granted permits to PSCo under Colorado’sPrevention of Significant Deterioration program for the construction andoperation of Comanche 3.  PSCo intervenedin the case.  In June 2006, thecourt ruled in PSCo’s favor and held that the Comanche 3 permits had beenproperly granted and plaintiffs’ claims to the contrary were withoutmerit.  Plaintiffs appealed thedecision.  In February 2008, theColorado Court of Appeals affirmed the state court’s ruling.  Plaintiffs filed a petition with the ColoradoSupreme Court seeking discretionary review of the appellate courtdecision.  On June 30, 2008 theColorado Supreme Court denied the petition.

 

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***Carbon DioxideEmissions Lawsuit******—***In July 2004,the attorneys general of eight states and New York City, as well as severalenvironmental groups, filed lawsuits in U.S. District Court in the SouthernDistrict of New York against five utilities, including Xcel Energy, the parentcompany of PSCo, to force reductions in carbon dioxide (CO2) emissions.  The other utilities include American ElectricPower Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  The lawsuits allege that CO2 emitted by eachcompany is a public nuisance as defined under state and federal common lawbecause it has contributed to global warming. The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to ordereach utility to cap and reduce its CO2 emissions.  In October 2004, Xcel Energy and theother defendants filed a motion to dismiss the lawsuit.  On Sept. 19, 2005, the court granted themotion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals.  In June 2007, the Second Circuit Courtof Appeals issued an order requesting the parties to file a letter briefregarding the impact of the United States Supreme Court’s decision in Massachusettsv. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues raised by the partieson appeal.  Among other things, in itsdecision in Massachusetts v. EPA, the United States Supreme Court held that CO2emissions are a “pollutant” subject to regulation by the EPA under theCAA.  In response to the request of theSecond Circuit Court of Appeals, in June 2007, the defendant utilitiesfiled a letter brief stating the position that the United States Supreme Court’sdecision supports the arguments raised by the utilities on appeal.  The Court of Appeals has taken the matterunder advisement ***and isexpected to issue an opinion in due course.***

 

***Comer vs.Xcel Energy Inc. et al.******—***In April 2006, Xcel Energy received notice of a purported class actionlawsuit filed in U.S. District Court in the Southern District ofMississippi.  The lawsuit names more than45 oil, chemical and utility companies, including Xcel Energy, the parentcompany of PSCo,****as defendants and alleges thatdefendants’ CO2 emissions “were a proximate and direct cause of the increase inthe destructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories,including negligence and public and private nuisance and seek damages relatedto the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends tovigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entiretyagainst all defendants on constitutional grounds.  In September 2007, plaintiffs filed anotice of appeal to the Fifth Circuit Court of Appeals. *** ***Oral arguments will bepresented to the Court of Appeals on Aug. 6, 2008. It is uncertain whenthe Court will reach a decision.

** **

***Native Village of Kivalina vs.Xcel Energy Inc. et al.******—*** In February 2008, the City and Native Village ofKivalina, Alaska, filed a lawsuit in U.S. District Court for the NorthernDistrict of California against Xcel Energy, the parent company of PSCo, and 23other oil, gas and coal companies.  Thesuit was brought on behalf of approximately 400 native Alaskans, the InupiatEskimo, who claim that Defendants’ emission of CO2 and othergreenhouse gases (GHG) contribute to global warming, which is harming theirvillage.  Plaintiffs claim that as aconsequence, the entire village must be relocated at a cost of between $95million and $400 million.  Plaintiffsassert a nuisance claim under federal and state common law, as well as a claimasserting “concert of action” in which defendants are alleged to have engagedin tortious acts in concert with each other. Xcel Energy was not named in the civil conspiracy claim.  Xcel Energy believes the claims asserted inthis lawsuit are without merit and joined with other utility defendants infiling a motion to dismiss on June 30, 2008.

 

**Employment, Tort and Commercial Litigation**

** **

***Qwest vs. XcelEnergy Inc.******—*** In June 2004, an employee of PSCo wasseriously injured when a pole owned by Qwest malfunctioned.  In September 2005, the employeecommenced an action against Qwest in Denver state court.  In April 2006, Qwest filed a third partycomplaint against PSCo based on terms in a joint pole use agreement betweenQwest and PSCo. Pursuant to this agreement, Qwest asserted PSCo had anaffirmative duty to properly train and instruct its employees on pole safety,including testing the pole for soundness before climbing.  In May 2006, PSCo filed a counterclaimagainst Qwest asserting Qwest had a duty to PSCo and an obligation under thecontract to maintain its poles in a safe and serviceable condition.  In May 2007, the matter was tried andthe jury found Qwest solely liable for the accident and this determinationresulted in an award of damages in the amount of approximately $90million.  On June 16, 2008, Qwestfiled its appellate brief.  After thematter is fully briefed by the parties, oral arguments will be scheduled.

 

***Mallon v. XcelEnergy Inc.******—***In July 2007, Theodore Mallonand TransFinancial Corporation filed a declaratory judgment action against XcelEnergy in U.S. District Court in Colorado (Mallon Federal Action).  In this lawsuit, plaintiffs seek adetermination that Xcel Energy is not entitled to assert claims againstplaintiffs related to the 1984 and 1985 sale of COLI to PSCo, a predecessor ofXcel Energy.  In August 2007, XcelEnergy, PSCo and PSRI commenced a lawsuit in Colorado state court againstMallon and TransFinancial Corporation (Mallon State Action).  In the Mallon State Action, Xcel Energy, PSCoand PSRI seek damages against Mallon and TransFinancial for, among otherthings, breach of contract and breach of fiduciary duties associated with thesale of the COLI policies.  In August 2007,Xcel Energy also filed a motion to stay or, in the alternative, to dismiss theMallon Federal Action.  In September, amotion to stay the Mallon State Court action was subsequently filed by Mallonand TransFinancial.  In November 2007,the U.S. District Court in Colorado dismissed the complaint in the Mallon Federal Action and Mallon andTransFinancial subsequently withdrew their motion to stay the Mallon StateCourt Action. In May 2008, Xcel Energy, PSCo and PSRI filed a secondamended complaint that, among other things, adds Provident Life &Accident Insurance Company (Provident) as a defendant and asserts claims forbreach of 

 

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contract, unjust enrichment and fraudulent concealment against theinsurance company. On June 23, 2008 Provident filed a motion to dismissthe complaint. Xcel Energy, PSCo and PSRI filed a brief in opposition to themotion on July 28, 2008. It is uncertain when the court will rule onthis motion.

 

**7.****              Short-TermBorrowings and Financing Activities**

 

***CommercialPaper —***At June 30, 2008 and Dec. 31,2007, PSCo had commercial paper outstanding of approximately $317.6 million and$271.0 million, respectively.  Theweighted average interest rates at June 30, 2008 and Dec. 31, 2007were 3.08 percent and 5.64 percent, respectively.

 

***Money Pool****** —***XcelEnergy has established a utility money pool arrangement that allows forshort-term loans between the utility subsidiaries and from the holding companyto the utility subsidiaries at market-based interest rates. The utility moneypool arrangement does not allow loans from the utility subsidiaries to theholding company.  PSCo has approval toborrow up to $250 million under the arrangement.  At June 30, 2008 and Dec. 31, 2007,PSCo had money pool borrowings of $21.0 million and money pool loansoutstanding of $100.6 million, respectively. The weighted average interest rates at June 30, 2008 and Dec. 31,2007, were 3.06 percent and 5.64 percent, respectively.

 

**8.****              DerivativeInstruments**

 

PSCo usesderivative instruments in connection with its utility commodity price, interestrate, short-term wholesale and commodity trading activities, including forwardcontracts, futures, swaps and options. Qualifying hedging relationships are designated as a hedge of aforecasted transaction or future cash flow (cash flow hedge).  The types of qualifying hedging transactionsthat PSCo is currently engaged in are discussed below.

 

**CashFlow Hedges**

 

***Commodity Cash Flow Hedges***— PSCo enters into derivative instruments to manage variability of future cashflows from changes in commodity prices. These derivative instruments are designated as cash flow hedges foraccounting purposes.  At June 30,2008, PSCo had various commodity-related contracts designated as cash flowhedges extending through December 2009.  The fair value of these cashflow hedges is recorded in other comprehensive income or deferred as aregulatory asset or liability.  Thisclassification is based on the regulatory recovery mechanisms in place.  This could include the purchase or sale ofenergy or energy-related products, the use of natural gas to generate electricenergy or gas purchased for resale.

 

At June 30, 2008, PSCo had $0.7 million in accumulated othercomprehensive income that is expected to be recognized in earnings during thenext 12 months as the hedged transactions settle.

 

***Interest Rate CashFlow Hedges*** — PSCo enters into interest rate lockagreements, including treasury-rate locks and forward starting swaps thateffectively fix the yield or price on a specified treasury security for aspecific period.  These derivativeinstruments are designated as cash flow hedges for accounting purposes.

 

At June 30, 2008, PSCo had net gains of approximately $1.5 millionin accumulated other comprehensive income that is expected to be recognized inearnings during the next 12 months.

 

Thefollowing table shows the major components of the derivative instrumentsvaluation in the consolidated balance sheets at June 30 and Dec. 31:

*** ***
| ** **                                                   | ** ** | **June 30, 2008**                                | ** ** | **Dec. 31, 2007**                                | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------------|------------|------------------------------------------------------------|------------|
| **(Thousands of Dollars)**                         | ** ** | **Derivative  Instruments  Valuation –  Assets** | ** ** | **Derivative  Instruments  Valuation -  Liabilities** | ** ** | **Derivative  Instruments  Valuation -  Assets** | ** ** | **Derivative  Instruments  Valuation -  Liabilities** | ** ** |
| Long term purchased power agreements                         |       | $                                                          | 146,631    |                                                       | $          | 72,511 |   | $ | 155,928 |   | $ | 96,654 |   |
| Electricity and natural gas trading and  hedging instruments |       | 34,810                                                     |       | 11,339                                                     |       | 19,117 |   | 9,057 |   |
| Total                                                        |       | $                                                          | 181,441    |                                                       | $          | 83,850 |   | $ | 175,045 |   | $ | 105,711 |   |

 

In 2003, as a result of FASBStatement 133 Implementation Issue No. C20, PSCo began recording severallong-term purchased power agreements at fair value due to accountingrequirements related to underlying price adjustments. As these purchases arerecovered through normal regulatory recovery mechanisms in the respective jurisdictions,the changes in fair

 

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value for these contracts were offset by regulatory assets andliabilities. During the first quarter of 2006, PSCo qualified these contractsunder the normal purchase exception. Based on this qualification, the contractsare no longer adjusted to fair value and the previous carrying value of thesecontracts will be amortized over the remaining contract lives along with theoffsetting regulatory assets and liabilities.

 

The impact ofqualifying cash flow hedges on PSCo’s accumulated other comprehensive income,included as a component of common stockholder’s equity, is detailed in thefollowing table:

 
| ** **                                                                          | ** ** | **Six months ended June 30,** | ** ** |
|-------------------------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| **(Thousands of Dollars)**                                                | ** ** | **2008**                                          | ** ** | **2007** | ** ** |
| Accumulated other comprehensive income  related to cash flow hedges at Jan. 1  |       | $                                                 | 12,447     |   | $ | 12,614 |   |
| After-tax net unrealized gains related to  derivatives accounted for as hedges      |       | 176                                               |       | 1,407 |   |
| After-tax net realized gains on derivative  transactions reclassified into earnings |       | (766                                              | )          | (747 | ) |
| Accumulated other comprehensive income  related to cash flow hedges at June 30 |       | $                                                 | 11,857     |   | $ | 13,274 |   |

 

**9.****              Fair ValueMeasurements**

 

**Effective Jan. 1, 2008, PSCo adoptedSFAS No. 157 for recurring fair value measurements.  SFAS No. 157 provides a singledefinition of fair value and requires enhanced disclosures about assets andliabilities measured at fair value. SFAS No. 157 establishes a hierarchalframework for disclosing the observability of the inputs utilized in measuringassets and liabilities at fair value. The three levels defined by the SFAS No. 157hierarchy and examples of each level are as follows:**

** **

Level1 – Quoted prices are available in active markets for identical assets orliabilities as of the reported date. The types of assets and liabilitiesincluded in Level 1 are highly liquid and actively traded instruments withquoted prices, such as commodity derivative contracts listed on the New YorkMercantile Exchange.

 

Level2 – Pricing inputs are other than quoted prices in active markets, but areeither directly or indirectly observable as of the reported date.  The types of assets and liabilities includedin Level 2 are typically either comparable to actively traded contracts, suchas energy forwards with pricing interpolated from recent trades at a similarlocation, or priced with models using highly observable inputs, such ascommodity options priced using observable forward prices and volatilities.

 

Level3 – Significant inputs to pricing have little or no observability as of thereporting date.  The types of assets andliabilities included in Level 3 are those with inputs requiring significantmanagement judgment or estimation, such as the long-term commodity price forecastsused to determine the fair value of long-term energy forwards.

 

The following table presents, for each of these hierarchy levels, PSCo’sassets and liabilities that are measured at fair value on a recurring basis asof June 30, 2008:

 
| **(Thousands of Dollars)** | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Counterparty  Netting (a)** | ** ** | **Net Balance** | ** ** |
|--------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|------------------------------------|------------|----------------------|------------|
| Commodity derivative assets          |       | $                | 653        |             | $          | 27,227           |       | $                                  | 7,326      |                 | $          | (396 | ) | $ | 34,810 |   |
| Commodity derivative liabilities     |       | —           |       | 7,835            |       | 4,818            |       | (1,314                             | )          | 11,339               |       |
|                                      |            |                  |            |                  |            |                  |            |                                    |            |                      |            |  |  |  |  |  |

 

----

(a) FASB Interpretation No. 39*Offsetting of Amounts Relating to CertainContracts*, as amended by FASB Staff Position FIN 39-1 *Amendment of FASB Interpretation No. 39*,permits the netting of receivables and payables for derivatives and relatedcollateral amounts when a legally enforceable master netting agreement existsbetween PSCo and a counterparty. A master netting agreement is an agreementbetween two parties who have multiple contracts with each other that providesfor the net settlement of all contracts in the event of default on or termination of any one contract.

 

**The following tables present the changes inLevel 3 recurring fair value measurements for the three and six months ended June 30,2008:**

** **
| **(Thousands of Dollars)**       | ** ** | **Commodity  Derivatives,  Net** | ** ** |
|--------------------------------------------|------------|----------------------------------|------------|
| Balance, April 1, 2008                |       | $                                | 2,549      |   |
| Purchases, issuances, and settlements, net |       | (1,347                           | )          |
| Gains recognized in earnings               |       | 1,306                            |       |
| Balance, June 30, 2008                |       | $                                | 2,508      |   |

 

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| **(Thousands of Dollars)**       | ** ** | **Commodity  Derivatives,  Net** | ** ** |
|--------------------------------------------|------------|----------------------------------|------------|
| Balance, Jan. 1, 2008                 |       | $                                | 4,121      |   |
| Purchases, issuances, and settlements, net |       | (2,643                           | )          |
| Gains recognized in earnings               |       | 1,030                            |       |
| Balance, June 30, 2008                |       | $                                | 2,508      |   |

 

Gains on Level 3 commodity derivatives recognized inearnings for the three and six months ended June 30, 2008, include $1.2million and $1.0 million, respectively, of net unrealized gains relating tocommodity derivatives held at June 30, 2008.  Realized and unrealized gains and losses oncommodity trading activities are included in electric utility revenues.

 

**10.     Detailof Interest and Other Income (Expense), Net**

 

Interest and other income (expense), net, for the three and six monthsended June 30 consisted of the following:

 
| ** **                                      | ** ** | **Three months ended June 30,** | ** ** | **Six months ended June 30,** | ** ** |
|-------------------------------------------------|------------|-----------------------------------------------------|------------|---------------------------------------------------|------------|
| **(Thousands of dollars)**            | ** ** | **2008**                                            | ** ** | **2007**                                          | ** ** | **2008** | ** ** | **2007** | ** ** |
| ** **                                      | ** ** | ** **                                          | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest income                                 |       | $                                                   | 1,327      |                                              | $          | 1,524 |   | $ | 3,554 |   | $ | 3,111 |   |
| Other nonoperating income                       |       | 1,202                                               |       | 494                                               |       | 1,779 |   | 995 |   |
| Insurance policy income (expense)               |       | 1,562                                               |       | (5,376                                            | )          | 1,978 |   | (9,588 | ) |
| Total interest and other income (expense),  net |       | $                                                   | 4,091      |                                              | $          | (3,358 | ) | $ | 7,311 |   | $ | (5,482 | ) |

 

**11.****               Segment Information**

 

PSCo has two reportablesegments, regulated electric utility and regulated natural gas utility.Commodity trading operations are not a reportable segment and commodity tradingresults are included in the regulated electric utility segment.

 
| **(Thousands of Dollars)**      | ** ** | **Regulated  Electric  Utility** | ** ** | **Regulated  Natural  Gas Utility** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|-------------------------------------------|------------|----------------------------------|------------|------------------------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| **Three months ended June 30, 2008** | ** ** | ** **                       | ** ** | ** **                               | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| Revenues from:                            |       |                             |       |                                     |       |           |       |                          |       |                    |       |
| External customers                        |       | $                                | 738,357    |                                     | $          | 249,302        |       | $                             | 7,648      |                    | $          | — |   | $ | 995,307 |   |
| Internal customers                        |       | 52                               |       | 35                                       |       | —         |       | (87                           | )          | —                  |       |
| Total revenues                            |       | $                                | 738,409    |                                     | $          | 249,337        |       | $                             | 7,648      |                    | $          | (87 | ) | $ | 995,307 |   |
| Segment net income                        |       | $                                | 50,139     |                                     | $          | 12,225         |       | $                             | 3,975      |                    | $          | — |   | $ | 66,339 |   |
|                                      |       |                             |       |                                     |       |           |       |                          |       |                    |       |
| **Three months ended June 30, 2007** | ** ** | ** **                       | ** ** | ** **                               | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| Revenues from:                            |       |                             |       |                                     |       |           |       |                          |       |                    |       |
| External customers                        |       | $                                | 638,142    |                                     | $          | 190,157        |       | $                             | 7,299      |                    | $          | — |   | $ | 835,598 |   |
| Internal customers                        |       | 71                               |       | 3                                        |       | —         |       | (74                           | )          | —                  |       |
| Total revenues                            |       | $                                | 638,213    |                                     | $          | 190,160        |       | $                             | 7,299      |                    | $          | (74 | ) | $ | 835,598 |   |
| Segment net income (loss)                 |       | $                                | 59,025     |                                     | $          | 8,809          |       | $                             | (53,696    | )                       | $          | — |   | $ | 14,138 |   |

 
| **(Thousands of Dollars)**    | ** ** | **Regulated  Electric  Utility** | ** ** | **Regulated  Natural  Gas Utility** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|-----------------------------------------|------------|----------------------------------|------------|------------------------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| **Six months ended June 30, 2008** | ** ** | ** **                       | ** ** | ** **                               | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| Revenues from:                          |       |                             |       |                                     |       |           |       |                          |       |                    |       |
| External customers                      |       | $                                | 1,392,853  |                                     | $          | 812,254        |       | $                             | 18,678     |                    | $          | — |   | $ | 2,223,785 |   |
| Internal customers                      |       | 130                              |       | 68                                       |       | —         |       | (198                          | )          | —                  |       |
| Total revenues                          |       | $                                | 1,392,983  |                                     | $          | 812,322        |       | $                             | 18,678     |                    | $          | (198 | ) | $ | 2,223,785 |   |
| Segment net income                      |       | $                                | 102,069    |                                     | $          | 50,978         |       | $                             | 7,596      |                    | $          | — |   | $ | 160,643 |   |

 

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| **(Thousands of Dollars)**    | ** ** | **Regulated  Electric  Utility** | ** ** | **Regulated  Natural  Gas Utility** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|-----------------------------------------|------------|----------------------------------|------------|------------------------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| **Six months ended June 30, 2007** | ** ** | ** **                       | ** ** | ** **                               | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| Revenues from:                          |       |                             |       |                                     |       |           |       |                          |       |                    |       |
| External customers                      |       | $                                | 1,274,642  |                                     | $          | 706,551        |       | $                             | 18,096     |                    | $          | — |   | $ | 1,999,289 |   |
| Internal customers                      |       | 157                              |       | 53                                       |       | —         |       | (210                          | )          | —                  |       |
| Total revenues                          |       | $                                | 1,274,799  |                                     | $          | 706,604        |       | $                             | 18,096     |                    | $          | (210 | ) | $ | 1,999,289 |   |
| Segment net income (loss)               |       | $                                | 106,427    |                                     | $          | 40,557         |       | $                             | (47,097    | )                       | $          | — |   | $ | 99,887 |   |

 

**12.****               ComprehensiveIncome**

 

The componentsof total comprehensive income are shown below:

 
| ** **                                                                          | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|-------------------------------------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| **(Millions of dollars)**                                                 | ** ** | **2008**                                        | ** ** | **2007**                                      | ** ** | **2008** | ** ** | **2007** | ** ** |
| Net income                                                                          |       | $                                               | 66,339     |                                          | $          | 14,138 |   | $ | 160,643 |   | $ | 99,887 |   |
| Other comprehensive income:                                                         |       |                                            |       |                                          |       |   |   |   |   |
| After-tax net unrealized gains related to  derivatives accounted for as hedges      |       | 202                                             |       | 942                                           |       | 176 |   | 1,407 |   |
| After-tax net realized gains on derivative  transactions reclassified into earnings |       | (382                                            | )          | (376                                          | )          | (766 | ) | (747 | ) |
| Other comprehensive (loss) income                                                   |       | (180                                            | )          | 566                                           |       | (590 | ) | 660 |   |
| Comprehensive income                                                                |       | $                                               | 66,159     |                                          | $          | 14,704 |   | $ | 160,053 |   | $ | 100,547 |   |

 

**13.****               Benefit Plans andOther Postretirement Benefits**

 

Pension and otherpostretirement benefit disclosures below generally represent Xcel Energyconsolidated information unless specifically identified as being attributableto PSCo.

 

**Componentsof Net Periodic Benefit Cost (Credit)**

 
| ** **                                                   | ** ** | **Three months ended June 30,** | ** ** |
|--------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                   | ** ** | **2008 (1)**                                   | ** ** | **2007 (1)** | ** ** | **2008** | ** ** | **2007** | ** ** |
| **(Thousands of Dollars)**                         | ** ** | **Pension Benefits**                           | ** ** | **Postretirement Health  Care Benefits** | ** ** |
| **Xcel Energy Inc.**                                         | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Service cost                                                 |       | $                                                   | 14,929     |   | $ | 14,555 |   | $ | 1,211 |   | $ | 1,205 |   |
| Interest cost                                                |       | 44,677                                              |       | 43,028 |   | 12,894 |   | 11,635 |   |
| Expected return on plan assets                               |       | (68,697                                             | )          | (66,525 | ) | (8,425 | ) | (7,582 | ) |
| Amortization of transition obligation                        |       | —                                              |       | — |   | 3,644 |   | 3,677 |   |
| Amortization of prior service cost (credit)                  |       | 5,166                                               |       | 6,487 |   | (544 | ) | (545 | ) |
| Amortization of net loss                                     |       | 3,511                                               |       | 4,555 |   | 3,031 |   | 2,106 |   |
| Net periodic benefit cost (credit)                           |       | (414                                                | )          | 2,100 |   | 11,811 |   | 10,496 |   |
| Credits not recognized due to the effects  of regulation     |       | 1,925                                               |       | 2,894 |   | — |   | — |   |
| Additional cost recognized due to the  effects of regulation |       | —                                              |       | — |   | 973 |   | 973 |   |
| Net benefit cost recognized for financial  reporting         |       | $                                                   | 1,511      |   | $ | 4,994 |   | $ | 12,784 |   | $ | 11,469 |   |
|                                                         |       |                                                |       |   |   |   |   |   |   |
| **PSCo**                                                     | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net periodic benefit cost                                    |       | $                                                   | 3,274      |   | $ | 5,229 |   | $ | 6,498 |   | $ | 5,533 |   |
| Additional cost recognized due to the  effects of regulation |       | —                                              |       | — |   | 973 |   | 973 |   |
| Net benefit cost recognized for financial  reporting         |       | $                                                   | 3,274      |   | $ | 5,229 |   | $ | 7,471 |   | $ | 6,506 |   |

 

----

(1)  Includes qualified and non-qualified pension net periodicbenefit cost.

 

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| ** **                                                   | ** ** | **Six months ended June 30,** | ** ** |
|--------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                   | ** ** | **2008 (1)**                                 | ** ** | **2007 (1)** | ** ** | **2008** | ** ** | **2007** | ** ** |
| **(Thousands of Dollars)**                         | ** ** | **Pension Benefits**                         | ** ** | **Postretirement Health  Care Benefits** | ** ** |
| **Xcel Energy Inc.**                                         | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Service cost                                                 |       | $                                                 | 31,702     |   | $ | 31,040 |   | $ | 2,675 |   | $ | 2,906 |   |
| Interest cost                                                |       | 85,260                                            |       | 82,626 |   | 25,440 |   | 25,238 |   |
| Expected return on plan assets                               |       | (137,169                                          | )          | (132,416 | ) | (15,925 | ) | (15,200 | ) |
| Amortization of transition obligation                        |       | —                                            |       | — |   | 7,288 |   | 7,288 |   |
| Amortization of prior service cost (credit)                  |       | 10,332                                            |       | 12,974 |   | (1,088 | ) | (1,090 | ) |
| Amortization of net loss                                     |       | 6,370                                             |       | 8,422 |   | 5,749 |   | 7,100 |   |
| Net periodic benefit cost (credit)                           |       | (3,505                                            | )          | 2,646 |   | 24,139 |   | 26,242 |   |
| Credits not recognized due to the effects  of regulation     |       | 4,517                                             |       | 5,574 |   | — |   | — |   |
| Additional cost recognized due to the  effects of regulation |       | —                                            |       | — |   | 1,946 |   | 1,946 |   |
| Net benefit cost recognized for financial  reporting         |       | $                                                 | 1,012      |   | $ | 8,220 |   | $ | 26,085 |   | $ | 28,188 |   |
|                                                         |       |                                              |       |   |   |   |   |   |   |
| **PSCo**                                                     | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net periodic benefit cost                                    |       | $                                                 | 5,939      |   | $ | 9,560 |   | $ | 13,495 |   | $ | 14,331 |   |
| Additional cost recognized due to the  effects of regulation |       | —                                            |       | — |   | 1,946 |   | 1,946 |   |
| Net benefit cost recognized for financial  reporting         |       | $                                                 | 5,939      |   | $ | 9,560 |   | $ | 15,441 |   | $ | 16,277 |   |

 

----

(1)  Includes qualified and non-qualified pension net periodicbenefit cost.

 

**Item 2. MANAGEMENT’S DISCUSSION AND ANALYSISOF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

** **

Discussion of financialcondition and liquidity for PSCo is omitted per conditions set forth in generalinstructions H (1) (a) and (b) of Form 10-Q for whollyowned subsidiaries. It is replaced with management’s narrative analysis and theresults of operations set forth in general instructions H (2) (a) of Form 10-Qfor wholly owned subsidiaries (reduced disclosure format).

 

**Forward-LookingInformation**

 

The followingdiscussion and analysis by management focuses on those factors that had amaterial effect on the financial condition and results of operations of PSCoduring the periods presented, or are expected to have a material impact in thefuture.  It should be read in conjunctionwith the accompanying unaudited consolidated financial statements and notes.

 

Except for the historical statements contained in this report, thematters discussed in the following discussion and analysis are forward-lookingstatements that are subject to certain risks, uncertainties andassumptions.  Such forward-lookingstatements 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.  Forward-looking statements speak only as ofthe date they are made, and we do not undertake any obligation to update themto reflect changes that occur after that date. Factors that could cause actual results to differ materially include,but are not limited to: general economic conditions, including the availabilityof credit and its impact on capital expenditures and the ability of Xcel Energyand its subsidiaries to obtain financing on favorable terms; businessconditions in the energy industry; actions of credit rating agencies;competitive factors, including the extent and timing of the entry of additionalcompetition in the markets served by PSCo; unusual weather; effects ofgeopolitical events, including war and acts of terrorism; state, federal andforeign legislative and regulatory initiatives that affect cost and investmentrecovery, have an impact on rates or have an impact on asset operation orownership or impose environmental compliance conditions; structures that affectthe speed and degree to which competition enters the electric and natural gasmarkets; costs and other effects of legal and administrative proceedings,settlements, investigations and claims; actions of accounting regulatorybodies; the items described under Factors Affecting Results of ContinuingOperations; and the other risk factors listed from time to time by PSCo inreports filed with the SEC, including “Risk Factors” in Item 1A of PSCo’s Form 10-Kfor the year ended Dec. 31, 2007 and Exhibit 99.01 to this report on Form 10-Qfor the quarter ended June 30, 2008.

 

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**MarketRisks**

 

PSCo is exposed to marketrisks, including changes in commodity prices and interest rates, as disclosedin Item 7A — Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K forthe year ended Dec. 31, 2007. Commodity price and interest rate risks for PSCo are mitigated due tocost-based rate regulation.  At June 30,2008, there were no material changes to the financial market risks that affectthe quantitative and qualitative disclosures presented as of Dec. 31,2007.

 

**RESULTSOF OPERATIONS**

 

PSCo’s net income wasapproximately $160.6 million for the first six months of 2008, compared with approximately$99.9 million for the first six months of 2007.

 

**ElectricUtility, Short-term Wholesale and Commodity Trading Margins**

 

Electric fueland purchased power expenses tend to vary with changing retail and wholesalesales requirements and unit cost changes in fuel and purchased power.  Due to fuel and purchased energycost-recovery mechanisms for customers, most fluctuations in these costs do notmaterially affect electric utility margin.

 

PSCo has twodistinct forms of wholesale sales: short-term wholesale and commoditytrading.  Short-term wholesale refers toenergy-related purchase and sales activity and the use of certain financialinstruments associated with the fuel required for, and energy produced from,PSCo’s generation assets or the energy and capacity purchased to serve nativeload.  Commodity trading is notassociated with PSCo’s generation assets or the energy and capacity purchasedto serve native load.  Short-termwholesale and commodity trading activities are considered part of the electricutility segment.

 

Margins fromcommodity trading activity conducted at PSCo are partially redistributed to Northern States Power Co., a Minnesotacorporation (NSP-Minnesota) and SouthwesternPublic Service Co., a New Mexico corporation (SPS), both wholly ownedsubsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC.  Margins received pursuant to the JOA arereflected as part of base electric utility revenues.  Short-term wholesale and commodity tradingmargins reflect the impact of regulatory sharing, if applicable.  Trading revenues are reported net of relatedcosts (i.e., on a margin basis) in the Consolidated Statements of Income.  Commodity trading expenses include purchasedpower, transmission, broker fees and other related costs.  Short-term wholesale and commodity tradingmargins reflect the estimated impact of regulatory sharing of margins, ifapplicable.

 

The followingtable details base electric utility, short-term wholesale and commodity tradingrevenues and margin:

 
| **(Millions of Dollars)**                      | ** ** | **Base  Electric  Utility** | ** ** | **Short-term  Wholesale** | ** ** | **Commodity  Trading** | ** ** | **Consolidated  Total** | ** ** |
|----------------------------------------------------------|------------|-----------------------------|------------|---------------------------|------------|------------------------|------------|-------------------------|------------|
| **Six months ended June 30, 2008**                  | ** ** | ** **                  | ** ** | ** **                | ** ** | ** **             | ** ** | ** **              | ** ** |
| Electric utility revenues (excluding  commodity trading) |       | $                           | 1,351      |                      | $          | 42                     |       | $                       | —     |   | $ | 1,393 |   |
| Electric fuel and purchased power                        |       | (789                        | )          | (39                       | )          | —                 |       | (828                    | )          |
| Commodity trading revenues                               |       | —                      |       | —                    |       | 36                     |       | 36                      |       |
| Commodity trading expenses                               |       | —                      |       | —                    |       | (36                    | )          | (36                     | )          |
| Gross margin before operating expenses                   |       | $                           | 562        |                      | $          | 3                      |       | $                       | —     |   | $ | 565 |   |
| Margin as a percentage of revenues                       |       | 41.6                        | %          | 7.1                       | %          | —                 | %          | 39.5                    | %          |
|                                                     |       |                        |       |                      |       |                   |       |                    |       |
| **Six months ended June 30, 2007**                  | ** ** | ** **                  | ** ** | ** **                | ** ** | ** **             | ** ** | ** **              | ** ** |
| Electric utility revenues (excluding  commodity trading) |       | $                           | 1,254      |                      | $          | 22                     |       | $                       | —     |   | $ | 1,276 |   |
| Electric fuel and purchased power                        |       | (700                        | )          | (18                       | )          | —                 |       | (718                    | )          |
| Commodity trading revenues                               |       | —                      |       | —                    |       | 82                     |       | 82                      |       |
| Commodity trading expenses                               |       | —                      |       | —                    |       | (83                    | )          | (83                     | )          |
| Gross margin before operating expenses                   |       | $                           | 554        |                      | $          | 4                      |       | $                       | (1         | ) | $ | 557 |   |
| Margin as a percentage of revenues                       |       | 44.2                        | %          | 18.2                      | %          | (1.2                   | )%         | 41.0                    | %          |

 

The following summarizes thecomponents of the changes in base electric revenues and base electric marginfor the six months ended June 30:

 

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# ***Base Electric Revenues***

 
| **(Millions of Dollars)**                       | ** ** | **2008 vs. 2007** | ** ** |
|-----------------------------------------------------------|------------|-----------------------------|------------|
| Fuel and purchased power cost recovery                    |       | $                           | 87         |   |
| Conservation and non-fuel riders                          |       | 14                          |       |
| Retail sales growth (excluding weather  impact)           |       | 7                           |       |
| Increased revenues due to leap year  (weather-normalized) |       | 3                           |       |
| Firm wholesale                                            |       | (10                         | )          |
| Estimated impact of weather                               |       | (3                          | )          |
| Other, including sales mix                                |       | (1                          | )          |
| Total increase in base electric revenues                  |       | $                           | 97         |   |

 

# ***Base Electric Margin***

 
| **(Millions of Dollars)**                     | ** ** | **2008 vs. 2007** | ** ** |
|---------------------------------------------------------|------------|-----------------------------|------------|
| Conservation and non-fuel riders                        |       | $                           | 8          |   |
| Retail sales growth (excluding weather  impact)         |       | 7                           |       |
| Purchased capacity costs                                |       | 6                           |       |
| Increased margin due to leap year  (weather-normalized) |       | 3                           |       |
| Firm wholesale                                          |       | (7                          | )          |
| Transmission costs                                      |       | (3                          | )          |
| Estimated impact of weather                             |       | (3                          | )          |
| Other, including sales mix                              |       | (3                          | )          |
| Total increase in base electric margin                  |       | $                           | 8          |   |

 

**The decrease in firm wholesale revenues is largely due to theloss of Cheyenne Light, Fuel, & Power as a customer.**

 

**The favorable change in purchased capacity costs from the prior year isdue to more of these costs being recovered from retail customers as a result ofa higher percentage of the sales coming from retail vs. wholesale customers.**

 

##### **Natural Gas Utility Margins**

##### ** **

The following table detailsthe change in natural gas revenues and margin. The cost of natural gas tends to vary with changing sales requirementsand unit cost of natural gas purchases. PSCo has a gas cost adjustment (GCA) mechanism for natural gas sales,which recognizes the majority of the effects of changes in the cost of naturalgas purchased for resale and adjusts revenues to reflect such changes in costsupon request by PSCo.  Therefore,fluctuations in the cost of natural gas have little effect on natural gasmargin.

 
| ** **                               | ** ** | **Six Months ended June 30,** | ** ** |
|------------------------------------------|------------|---------------------------------------------------|------------|
| **(Millions of Dollars)**      | ** ** | **2008**                                          | ** ** | **2007** | ** ** |
| Natural gas utility revenues             |       | $                                                 | 812        |   | $ | 707 |   |
| Cost of natural gas sold and transported |       | (611                                              | )          | (527 | ) |
| Natural gas utility margin               |       | $                                                 | 201        |   | $ | 180 |   |

 

The following summarizes thecomponents of the changes in natural gas revenues and margin for the six monthsended June 30:

 

***Natural Gas Revenues***

 
| **(Millions of Dollars)**                       | ** ** | **2008 vs. 2007** | ** ** |
|-----------------------------------------------------------|------------|-----------------------------|------------|
| Purchased natural gas adjustment clause  recovery         |       | $                           | 85         |   |
| Base rate changes                                         |       | 18                          |       |
| Service and facility fee revenues                         |       | 2                           |       |
| Increased revenues due to leap year  (weather-normalized) |       | 1                           |       |
| Estimated impact of weather on firm sales  volume         |       | (1                          | )          |
| Total increase in natural gas revenues                    |       | $                           | 105        |   |

 

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***Natural Gas Margin***

 
| **(Millions of Dollars)**                     | ** ** | **2008 vs. 2007** | ** ** |
|---------------------------------------------------------|------------|-----------------------------|------------|
| Base rate changes                                       |       | $                           | 18         |   |
| Service and facility fee revenues                       |       | 2                           |       |
| Increased margin due to leap year  (weather-normalized) |       | 1                           |       |
| Estimated impact of weather on firm sales  volume       |       | (1                          | )          |
| Other, including late payment fees                      |       | 1                           |       |
| Total increase in natural gas margin                    |       | $                           | 21         |   |

 

**Non-FuelOperating Expense and Other Costs**

 

***Other Operating and Maintenance Expenses —***Otheroperating and maintenance expenses forthe first six months of 2008 increased by approximately $15 million, or 5.3percent, compared to the first six months of 2007.  The following summarizes the components ofthe changes for the six months ended June 30:

 
| **(Millions of Dollars)**                         | ** ** | **2008 vs. 2007** | ** ** |
|-------------------------------------------------------------|------------|-----------------------------|------------|
| Higher plant generation costs                               |       | $                           | 10         |   |
| Higher labor costs                                          |       | 3                           |       |
| Higher contract labor costs                                 |       | 2                           |       |
| Lower employee benefit costs                                |       | (4                          | )          |
| Other, including consulting costs                           |       | 4                           |       |
| Total increase in other operating and  maintenance expenses |       | $                           | 15         |   |

 

***Conservation and Demand Side Management (DSM)***– Conservation and DSM expense increased approximately $10.6 million for thefirst six months of 2008, compared with the first six months of 2007.  The higher expense is attributable to theongoing expansion of such programs as designed, in part, to meet certain regulatorycommitments in our various jurisdictions.

 

***Interest and otherincome (expense), net***—******Interest and otherincome (expense), net, increased by approximately $12.8 million for the firstsix months of 2008 compared with the first six months of 2007, primarily due tolower interest expense, net of interest income largely as a result of PSRIterminating the COLI program in 2007.

 

***Allowance for funds used during construction,equity and debt (AFDC)*****— AFDC is a non-cash amount capitalized as a part of constructioncosts representing the cost of financing the construction.  Generally, these costs are recovered fromcustomers, in future rates, as the related property is depreciated.  AFDC increased by $14.2 million for the firstsix months of 2008, compared with the first six months of 2007.  This increase was primarily due to the ongoing construction of Comanche 3, which waspartially offset by the current recovery from customers of the financing costsrelated to this construction through base rates, resulting in a lowerrecognition of AFDC.

 

***Interest charges andfinancing costs***—******Interest charges and financing costsincreased by approximately $6.2 million, or 9.3 percent, for the first sixmonths of 2008 compared with the first six months of 2007, primarily due toincreased long-term borrowings.

 

***Income taxes***—Income tax expense increased by $2.3 million for the first six months of 2008,compared with the first six months of 2007. The increase in income tax expense was primarily due to an increase inpretax income in 2008 (excluding COLI), partially offset by $15.3 million oftax expense related to the COLI settlement in 2007.  The effective tax rate was 33.5 percent forthe first six months of 2008, compared with 44.0 percent for the same period in2007.  The higher effective tax rate forthe first six months of 2007 was primarily due to the COLI settlement,partially offset by an increase in the forecasted annual effective tax rate for2008, which was largely a result of PSRI terminating the COLI program in 2007.Without these charges and benefits, the effective tax rate for the first sixmonths of 2008 and 2007 would have been 33.5 percent and 38.0 percent,respectively.

 

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***Regulation***

** **

**Summary of Recent Regulatory Developments**

 

The FERC has jurisdiction over rates for electric transmission servicein interstate commerce and electricity sold at wholesale, hydro facility licensing,natural gas transportation, accounting practices and certain other activitiesof Xcel Energy’s utility subsidiaries. State and local agencies havejurisdiction over many of PSCo’s utility activities, including regulation ofretail rates and environmental matters. See additional discussion in thesummary of recent federal regulatory developments and public utility regulationsections of the PSCo Annual Report on Form 10-K for the year ended Dec. 31,2007.  In addition to the matters discussed below, see Note 5 to theconsolidated financial statements for a discussion of other regulatory matters.

 

***FERC Tie Line Investigation —***InOctober 2007, the FERC Office of Enforcement, Division of Investigations(DOI), commenced a non-public investigation of use of network transmissionservice across the Lamar Tie Line, a transmission facility that connects PSCoand SPS, an affiliate of PSCo.  XcelEnergy is fully cooperating with the DOI investigation.  In July 2008, the DOI issued apreliminary report alleging Xcel Energy violated FERC policies and rules andapproved tariffs.  The report representsthe preliminary conclusions of the DOI and is subject to additionalprocedures.  The report does notconstitute a finding by the FERC, which may, among other things, accept, modifyor reject any or all of the preliminary conclusions set forth in thereport.  Xcel Energy disagrees with thepreliminary report and will vigorously contest the allegations; Xcel Energy isnot able to predict the outcome of the investigation or what, if any, actionsthe FERC may take.  As previouslydiscussed under “Item 1A – Risk Factors” in Xcel Energy’s 2007 Annual Report onForm 10-K, the Energy Policy Act of 2005 has increased the FERC’s civilpenalty authority for violation of FERC statutes, rules and orders.  Given the preliminary nature of this matter,Xcel Energy is unable to determine if the resolution of this matter will have amaterial adverse impact on operations, cash flows or financial condition.

 

***Electric Reliability Standards Matters*—**In June 2008, PSCo was subject to anaudit of its compliance with NERC and regional reliability standards by WesternElectricity Coordinating Council (WECC), the North American ElectricReliability Council (NERC) regional entity for the PSCo system.  The WECC has not yet issued its final auditreport.  In response to informationidentified in during the audit, Xcel Energy conducted a comprehensive review ofthe maintenance records for all relay devices on the PSCo transmissionsystem.  That review found PSCo did nothave documentation demonstrating that all relay devices on the PSCo system hadbeen maintained on the schedule in Xcel Energy’s adopted maintenance plan.  In June 2008, PSCo filed a self-reportregarding the maintenance plan violations with the WECC.  Xcel Energy is uncertain if any future WECCaudit findings or the self-report will result in financial penalties beingimposed on PSCo.

 

**OtherRegulatory Matters**

 

***Renewable EnergyStandard (RES)*—** The 2007 Coloradolegislature adopted an increased RES that requires PSCo to generate or cause tobe generated electricity from renewable resources equaling:

 

·              At least 10 percent of its retailsales by 2010,

·              15 percent of retail sales by 2015and

·              20 percentof retail sales by 2020.

·              4percent must be generated from solar renewable resources with half the solarresources being located at customers facilities.

 

The new law limits the net incremental retail rateimpact from these renewable resource acquisitions as compared to non-renewableresources to 2 percent. The new legislation encourages the CPUC toconsider earlier and timely cost recovery for utility investment in renewableresources, including the use of a forward rider mechanism.

 

***Colorado ClimateAction Plan *—** In November 2007, GovernorRitter of Colorado published a Colorado Climate Action Plan, which calls for areduction in GHG emissions of 20 percent by 2020 with additionalreductions by 2050.

 

***PSCo RegulatoryPolicy Initiative*****—** At its March 2008 open meetings, the CPUC bothdiscussed and voted to open an investigatory docket that will review thecurrent regulatory structure to determine if current utility incentives arealigned with state public policy objectives and to determine if the existingstructure is internally consistent in achieving these objectives.  TheCPUC expects to explore alternative forms of ratemaking for utilities and tobetter understand the state of the art on different mechanisms across thenation. An official order has not yet been issued.

 

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***PSCo Resource Plan ***—PSCo estimates it will purchase approximately 40 to 50 percent of itstotal electric system energy needs for 2008 and generate the remainder withPSCo-owned resources. Additional capacity has been secured under contract makingadditional energy available for purchase, if required. PSCo currently has undercontract or through owned generation, the resources necessary to meet itsanticipated 2008 load obligation. In November 2007, PSCo filed theColorado Resource Plan (CRP), which details the type and amount of resourcesthat will be added to the system for an eight year Resource Acquisition Period(RAP) through 2015.  Hearings concluded on July 11, 2008 and awritten order on PSCo’s proposal is expected by September 19,2008.   Based on the latest plan, PSCo would:

 

·                  Increaserenewable portfolio to 850 megawatts (MW) by 2015.  PSCo would then have a total of approximately1,900 MW of wind power resources.

·                  Acquireapproximately 25 MW from a central solar facility, with possible option ofacquiring up to 600 MW of solar thermal resources withstorage as technology develops.

·                  Pursuean additional 63.5 MW of on-site, customer-owned solar installations.

·                  Increasecustomer efficiency and conservation programs with plans to meet the CPUCgoals of annual energy sales reductions toapproximately 3,669 gigawatt hours (GWh), which would yield ademand savings in the range of 886 MW to 994 MW by 2020.

·                  Retiretwo older coal-burning plants (Arapahoe and Cameo) and repower at the Arapahoesite with a 480 MW summer rated combined cycle plant.

 

**Item4. CONTROLS AND PROCEDURES**

** **

**Disclosure Controls and Procedures**

 

PSCo maintainsa set of disclosure controls and procedures designed to ensure that informationrequired to be disclosed in reports that it files or submits under theSecurities Exchange Act of 1934 (Exchange Act) is recorded, processed,summarized and reported within the time periods specified in SEC rules andforms. Disclosure controls and procedures include, without limitation, controlsand procedures designed to ensure that information required to be disclosed byus in reports under the Exchange Act is accumulated and communicated tomanagement, including the chief executive officer (CEO) and chief financialofficer (CFO), allowing timely decisions regarding required disclosure. As ofthe end of the period covered by this report, based on an evaluation carriedout under the supervision and with the participation of PSCo’s management,including the CEO and the CFO, of the effectiveness of our disclosure controlsand procedures, the CEO and CFO have concluded that PSCo’s disclosure controlsand procedures are effective.

 

**Internal Control Over FinancialReporting**

** **

No change inPSCo’s internal control over financial reporting has occurred during the mostrecent fiscal quarter that has materially affected, or is reasonably likely tomaterially affect, PSCo’s internal control over financial reporting.

 

##### **Part II. OTHER INFORMATION**

##### ** **

**Item 1. LEGAL PROCEEDINGS**

 

In the normal course ofbusiness, various lawsuits and claims have arisen against PSCo.  After consultation with legal counsel, PSCohas recorded an estimate of the probable cost of settlement or otherdisposition for such matters.  See Notes5 and 6 of the consolidated financial statements in this Quarterly Report on Form 10-Qfor further discussion of legal proceedings, including Regulatory Matters andCommitments and Contingent Liabilities, which are hereby incorporated byreference.  Reference also is made toItem 3 and Notes 12 and 13 of PSCo’s Annual Report on Form 10-K for theyear ended Dec. 31, 2007 for a description of certain legal proceedingspresently pending.

 

**Item 1A. RISK FACTORS**

 

PSCo’s risk factors are documented in Item 1A of Part I of its2007 Annual Report on Form 10-K, which is incorporated herein byreference.  There have been no materialchanges to the risk factors.

 

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**Item 6. EXHIBITS**

 

The followingExhibits are filed with this report:

 
| 31.01 |   | Principal  Executive Officer’s and Principal Financial Officer’s certifications pursuant  to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of  the Sarbanes-Oxley Act of 2002. |
|-------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 32.01 |   | Certification  pursuant to 18 U.S.C. Section 1350, as adopted pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                             |
| 99.01 |   | Statement  pursuant to Private Securities Litigation Reform Act of 1995.                                                                                                                                        |

 

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**SIGNATURES**

 

Pursuant to the requirementsof the Securities Exchange Act of 1934, the registrant has duly caused thisreport to be signed on its behalf by the undersigned thereunto duly authorizedon Aug. 1, 2008.

 

PublicService Co. of Colorado

(Registrant)

 
|   |   /s/ TERESA S. MADDEN                                          |
|--------|---------------------------------------------------------------------------|
|   |     Teresa S. Madden                                  |
|   |     Vice President and  Controller                    |
|   |                                                                      |
|   | /s/ BENJAMIN G.S. FOWKE III                                               |
|   |      Benjamin G.S.  Fowke III                    |
|   |      Vice  President and Chief Financial Officer |

 

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