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**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C.  20549**

 

**FORM 10-Q**

 

**(MarkOne)**

 

**x****QUARTERLY REPORT PURSUANT TO SECTION 13 OR15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

 

**For the quarterly period ended June 30, 2010**

 

**or**

 

**o**** ****TRANSITION REPORT PURSUANTTO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

 

**Commission File Number: 001-3280**

 

**Public Service Company of Colorado**

(Exact name of registrant as specified in its charter)

 

| **Colorado**                                                   | ** ** | **84-0296600**                       |
|----------------------------------------------------------------|------------|--------------------------------------|
| (State or other jurisdiction of incorporation or organization) |       | (I.R.S. Employer Identification No.) |

 

| **1800 Larimer, Suite 1100  Denver, Colorado** | ** ** | **80202**  |
|-----------------------------------------------------|------------|------------|
| (Address of principal executive offices)            |       | (Zip Code) |

 

**(303) 571-7511**

(Registrant’s telephone number, including area code)

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days. x Yes o No

 

Indicate by check markwhether the registrant has submitted electronically and posted on its corporateWeb site, if any, every Interactive Data File required to be submitted andposted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter)during the preceding 12 months (or for such shorter period that the registrantwas required to submit and post such files). o Yes o No

 

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or a smaller reporting company.  See the definitions of “large acceleratedfiler”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2of the Exchange Act.

 

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

 

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

 

Indicate the number ofshares outstanding of each of the issuer’s classes of common stock, as of thelatest practicable date.

 

| **Class**                     | ** ** | **Outstanding at August 2, 2010** |
|-------------------------------|------------|-------------------------------------------------------|
| 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 thisForm 10-Q with the reduced disclosure format specified in GeneralInstruction H (2) to such Form 10-Q.

 

 

 

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**TABLE OF CONTENTS**

** **
| **PART I -  FINANCIAL INFORMATION**     | ** **                                                                                  |
|----------------------------------------------|---------------------------------------------------------------------------------------------|
|                                         |                                                                                        |   |
| Item l.                                      | Financial Statements (Unaudited)                                                            | 3 |
| Item 2.                                      | Management’s  Discussion and Analysis of Financial Condition and Results of Operations | 26 |
| Item 4.                                      | Controls and  Procedures                                                                    | 31 |
|                                         |                                                                                        |   |
| **PART II  - OTHER INFORMATION**        | ** **                                                                                  |
|                                         |                                                                                        |   |
| Item 1.                                      | Legal Proceedings                                                                           | 32 |
| Item 1A.                                     | Risk Factors                                                                                | 32 |
| Item 6.                                      | Exhibits                                                                                    | 33 |
|                                         |                                                                                        |   |
| **SIGNATURES**                               | 34                                                                                          |
|                                         |                                                                                        |   |
| Certifications Pursuant  to Section 302 | 1                                                                                           |
| Certifications Pursuant  to Section 906 | 1                                                                                           |
| Statement Pursuant to  Private Litigation    | 1                                                                                           |

 

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

 

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**PART I— FINANCIAL INFORMATION**

 

**Item 1**—**FINANCIAL STATEMENTS**

 

**PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)**

*(amounts in thousands of dollars)*

 
| ** **                                                                                                 | ** ** | **Three Months Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|-------------------------------|------------|
| ** **                                                                                                 | ** ** | **2010**                        | ** ** | **2009**                      | ** ** | **2010** | ** ** | **2009** | ** ** |
| **Operating revenues**                                                                                     |       |                            |       |                          |       |   |   |   |   |
| Electric                                                                                                   |       | $                               | 773,621    |                          | $          | 588,467 |   | $ | 1,497,255 |   | $ | 1,185,810 |   |
| Natural gas                                                                                                |       | 165,894                         |       | 173,494                       |       | 632,177 |   | 568,615 |   |
| Steam and other                                                                                            |       | 7,781                           |       | 7,132                         |       | 20,561 |   | 17,146 |   |
| Total operating revenues                                                                                   |       | 947,296                         |       | 769,093                       |       | 2,149,993 |   | 1,771,571 |   |
|                                                                                                       |       |                            |       |                          |       |   |   |   |   |
| **Operating expenses**                                                                                     |       |                            |       |                          |       |   |   |   |   |
| Electric fuel and purchased power                                                                          |       | 408,113                         |       | 300,799                       |       | 781,964 |   | 608,068 |   |
| Cost of natural gas sold and transported                                                                   |       | 82,121                          |       | 92,366                        |       | 422,830 |   | 374,802 |   |
| Cost of sales — steam and other                                                                       |       | 2,931                           |       | 2,542                         |       | 9,004 |   | 6,550 |   |
| Other operating and maintenance expenses                                                                   |       | 169,025                         |       | 148,600                       |       | 324,718 |   | 303,490 |   |
| Demand side management program expenses                                                                    |       | 33,550                          |       | 23,510                        |       | 67,261 |   | 49,666 |   |
| Depreciation and amortization                                                                              |       | 69,217                          |       | 62,915                        |       | 136,183 |   | 125,462 |   |
| Taxes (other than income taxes)                                                                            |       | 25,662                          |       | 22,211                        |       | 50,278 |   | 45,400 |   |
| Total operating expenses                                                                                   |       | 790,619                         |       | 652,943                       |       | 1,792,238 |   | 1,513,438 |   |
|                                                                                                       |       |                            |       |                          |       |   |   |   |   |
| **Operating income**                                                                                       |       | 156,677                         |       | 116,150                       |       | 357,755 |   | 258,133 |   |
|                                                                                                       |       |                            |       |                          |       |   |   |   |   |
| Other income, net                                                                                          |       | 1,326                           |       | 2,112                         |       | 1,882 |   | 2,981 |   |
| Allowance for funds used during construction —  equity                                                |       | 3,279                           |       | 9,689                         |       | 6,257 |   | 19,824 |   |
|                                                                                                       |       |                            |       |                          |       |   |   |   |   |
| **Interest charges and financing  costs**                                                                  |       |                            |       |                          |       |   |   |   |   |
| Interest charges — includes other financing costs  of $1,409, $1,433, $2,806 and $2,819, respectively |       | 41,626                          |       | 41,781                        |       | 87,439 |   | 82,133 |   |
| Allowance for funds used during construction —  debt                                                  |       | (1,426                          | )          | (4,367                        | )          | (3,091 | ) | (9,329 | ) |
| Total interest charges and financing costs                                                                 |       | 40,200                          |       | 37,414                        |       | 84,348 |   | 72,804 |   |
|                                                                                                       |       |                            |       |                          |       |   |   |   |   |
| **Income before income taxes**                                                                             |       | 121,082                         |       | 90,537                        |       | 281,546 |   | 208,134 |   |
| Income taxes                                                                                               |       | 43,397                          |       | 29,990                        |       | 119,611 |   | 69,299 |   |
| **Net income**                                                                                             |       | $                               | 77,685     |                          | $          | 60,547 |   | $ | 161,935 |   | $ | 138,835 |   |

 

See Notes to Consolidated Financial Statements

 

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**PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES**

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

*(amounts in thousands of dollars)*

 
| ** **                                                                     | ** ** | **Six Months Ended June 30,** | ** ** |
|--------------------------------------------------------------------------------|------------|-------------------------------|------------|
| ** **                                                                     | ** ** | **2010**                      | ** ** | **2009** | ** ** |
| **Operating activities**                                                       | ** ** | ** **                    |       |   |   |
| Net income                                                                     |       | $                             | 161,935    |   | $ | 138,835 |   |
| Adjustments to reconcile net income to cash  provided by operating activities: |       |                          |       |   |   |
| Depreciation and amortization                                                  |       | 138,590                       |       | 127,787 |   |
| Demand side management program expenses                                        |       | 14,562                        |       | 13,063 |   |
| Deferred income taxes                                                          |       | 42,245                        |       | 113,503 |   |
| Amortization of investment tax credits                                         |       | (1,168                        | )          | (1,248 | ) |
| Allowance for equity funds used during  construction                           |       | (6,257                        | )          | (19,824 | ) |
| Net realized and unrealized hedging and derivative  transactions               |       | (9,697                        | )          | 42,588 |   |
| Changes in operating assets and liabilities:                                   |       |                          |       |   |   |
| Accounts receivable                                                            |       | 46,213                        |       | 78,280 |   |
| Accrued unbilled revenues                                                      |       | 98,842                        |       | 191,712 |   |
| Recoverable purchased natural gas and electric  energy costs                   |       | 11,512                        |       | (41,861 | ) |
| Inventories                                                                    |       | 56,489                        |       | 60,601 |   |
| Prepayments and other                                                          |       | 47,588                        |       | 3,814 |   |
| Accounts payable                                                               |       | (137,259                      | )          | (179,394 | ) |
| Deferred electric energy costs                                                 |       | (26,524                       | )          | (95,856 | ) |
| Net regulatory assets and liabilities                                          |       | 31,583                        |       | 8,290 |   |
| Other current liabilities                                                      |       | (6,901                        | )          | (26,608 | ) |
| Change in other noncurrent assets                                              |       | (1,650                        | )          | 6,325 |   |
| Change in other noncurrent liabilities                                         |       | (16,224                       | )          | (103,387 | ) |
| Net cash provided by operating activities                                      |       | 443,879                       |       | 316,620 |   |
|                                                                           |       |                          |       |   |   |
| **Investing activities**                                                       |       |                          |       |   |   |
| Utility capital/construction expenditures                                      |       | (222,564                      | )          | (306,216 | ) |
| Allowance for equity funds used during  construction                           |       | 6,257                         |       | 19,824 |   |
| Investments in utility money pool                                              |       | (347,200                      | )          | (60,200 | ) |
| Repayments from utility money pool                                             |       | 268,200                       |       | 22,200 |   |
| Net cash used in investing activities                                          |       | (295,307                      | )          | (324,392 | ) |
|                                                                           |       |                          |       |   |   |
| **Financing activities**                                                       |       |                          |       |   |   |
| Repayment of short-term borrowings, net                                        |       | (95,000                       | )          | (40,000 | ) |
| Proceeds from issuance of long-term debt                                       |       | —                        |       | 394,844 |   |
| Repayment of long-term debt, including  reacquisition premiums                 |       | —                        |       | (756 | ) |
| Borrowings under utility money pool arrangement                                |       | 184,900                       |       | 530,000 |   |
| Repayments under utility money pool arrangement                                |       | (268,900                      | )          | (571,000 | ) |
| Capital contributions from parent                                              |       | 137,791                       |       | 40,417 |   |
| Dividends paid to parent                                                       |       | (132,477                      | )          | (134,233 | ) |
| Net cash (used in) provided by financing  activities                           |       | (173,686                      | )          | 219,272 |   |
|                                                                           |       |                          |       |   |   |
| Net (decrease) increase in cash and cash  equivalents                          |       | (25,114                       | )          | 211,500 |   |
| Cash and cash equivalents at beginning of period                               |       | 33,429                        |       | 11,198 |   |
| Cash and cash equivalents at end of period                                     |       | $                             | 8,315      |   | $ | 222,698 |   |
|                                                                           |       |                          |       |   |   |
| Supplemental disclosure of cash flow information:                              |       |                          |       |   |   |
| Cash paid for interest, net of amounts capitalized                             |       | $                             | (78,547    | ) | $ | (66,949 | ) |
| Cash (paid) received for income taxes, net                                     |       | (11,318                       | )          | 5,284 |   |
| Supplemental disclosure of non-cash investing and  financing transactions:     |       |                          |       |   |   |
| Property, plant and equipment additions in  accounts payable                   |       | $                             | 15,272     |   | $ | 17,327 |   |

 

See Notes to Consolidated Financial Statements

 

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**PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES**

**CONSOLIDATED BALANCE SHEETS (UNAUDITED)**

*(amountsin thousands of dollars)*

 
| ** **                                                                            | ** ** | **June 30, 2010** | ** ** | **Dec. 31, 2009** | ** ** |
|---------------------------------------------------------------------------------------|------------|-------------------|------------|-------------------|------------|
| **Assets**                                                                            |       |              |       |              |       |
| Current assets                                                                        |       |              |       |              |       |
| Cash and cash equivalents                                                             |       | $                 | 8,315      |              | $          | 33,429 |   |
| Accounts receivable, net                                                              |       | 284,219           |       | 330,279           |       |
| Accounts receivable from affiliates                                                   |       | 38,533            |       | 33,396            |       |
| Investments in utility money pool arrangement                                         |       | 79,000            |       | —            |       |
| Accrued unbilled revenues                                                             |       | 215,111           |       | 313,953           |       |
| Recoverable purchased natural gas and electric  energy costs                          |       | 13,645            |       | 25,157            |       |
| Inventories                                                                           |       | 197,158           |       | 253,648           |       |
| Deferred income taxes                                                                 |       | 79,003            |       | 81,980            |       |
| Derivative instruments valuation                                                      |       | 15,745            |       | 28,704            |       |
| Prepayments and other                                                                 |       | 11,380            |       | 58,968            |       |
| Total current assets                                                                  |       | 942,109           |       | 1,159,514         |       |
|                                                                                  |       |              |       |              |       |
| Property, plant and equipment, net                                                    |       | 8,224,278         |       | 8,104,841         |       |
|                                                                                  |       |              |       |              |       |
| Other assets                                                                          |       |              |       |              |       |
| Regulatory assets                                                                     |       | 821,953           |       | 827,311           |       |
| Derivative instruments valuation                                                      |       | 82,246            |       | 104,664           |       |
| Other                                                                                 |       | 52,189            |       | 47,175            |       |
| Total other assets                                                                    |       | 956,388           |       | 979,150           |       |
| Total assets                                                                          |       | $                 | 10,122,775 |              | $          | 10,243,505 |   |
|                                                                                  |       |              |       |              |       |
| **Liabilities and Equity**                                                            |       |              |       |              |       |
| Current liabilities                                                                   |       |              |       |              |       |
| Current portion of long-term debt                                                     |       | $                 | 5,453      |              | $          | 3,964 |   |
| Short-term debt                                                                       |       | —            |       | 95,000            |       |
| Borrowings under utility money pool arrangement                                       |       | —            |       | 84,000            |       |
| Accounts payable                                                                      |       | 302,600           |       | 422,276           |       |
| Accounts payable to affiliates                                                        |       | 25,115            |       | 40,758            |       |
| Deferred electric energy costs                                                        |       | 38,028            |       | 64,552            |       |
| Taxes accrued                                                                         |       | 66,779            |       | 80,303            |       |
| Dividends payable to parent                                                           |       | 66,729            |       | 65,822            |       |
| Derivative instruments valuation                                                      |       | 24,255            |       | 18,285            |       |
| Accrued interest.                                                                     |       | 47,296            |       | 47,300            |       |
| Other                                                                                 |       | 102,475           |       | 67,692            |       |
| Total current liabilities                                                             |       | 678,730           |       | 989,952           |       |
|                                                                                  |       |              |       |              |       |
| Deferred credits and other liabilities                                                |       |              |       |              |       |
| Deferred income taxes                                                                 |       | 1,488,168         |       | 1,447,143         |       |
| Deferred investment tax credits                                                       |       | 48,863            |       | 50,031            |       |
| Regulatory liabilities                                                                |       | 496,396           |       | 510,491           |       |
| Pension and employee benefit obligations                                              |       | 246,618           |       | 257,881           |       |
| Customer advances                                                                     |       | 256,796           |       | 271,171           |       |
| Derivative instruments valuation                                                      |       | 44,437            |       | 49,587            |       |
| Asset retirement obligations                                                          |       | 67,242            |       | 65,160            |       |
| Other                                                                                 |       | 56,854            |       | 31,287            |       |
| Total deferred credits and other liabilities                                          |       | 2,705,374         |       | 2,682,751         |       |
|                                                                                  |       |              |       |              |       |
| Commitments and contingent liabilities                                                |       |              |       |              |       |
| Capitalization                                                                        |       |              |       |              |       |
| Long-term debt                                                                        |       | 2,826,911         |       | 2,824,988         |       |
| Common stock — authorized 100 shares of $0.01 par  value; outstanding 100 shares |       | —            |       | —            |       |
| Additional paid-in capital                                                            |       | 3,133,261         |       | 2,995,470         |       |
| Retained earnings                                                                     |       | 770,795           |       | 742,243           |       |
| Accumulated other comprehensive income                                                |       | 7,704             |       | 8,101             |       |
| Total common stockholder’s equity                                                |       | 3,911,760         |       | 3,745,814         |       |
| Total liabilities and equity                                                          |       | $                 | 10,122,775 |              | $          | 10,243,505 |   |

 

See Notes to Consolidated Financial Statements

 

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**PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES**

**Notes to Consolidated Financial Statements (UNAUDITED)**

 

Inthe opinion of management, the accompanying unaudited consolidated financialstatements contain all adjustments necessary to present fairly, in accordancewith accounting principles generally accepted in the United States of America(GAAP), the financial position of PSCo and its subsidiaries as of June 30,2010 and Dec. 31, 2009; the results of its operations for the three andsix months ended June 30, 2010 and 2009; and its cash flows for the sixmonths ended June 30, 2010 and 2009. All adjustments are of a normal, recurring nature, except as otherwisedisclosed.  Management has also evaluatedthe impact of events occurring after June 30, 2010 up to the date ofissuance of these consolidated financial statements.  These statements contain all necessaryadjustments and disclosures resulting from that evaluation.  The Dec. 31, 2009 balance sheetinformation has been derived from the audited 2009 financial statements.  These notes to the consolidated financialstatements have been prepared pursuant to the rules and regulations of theSEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financialstatements prepared in accordance with GAAP have been condensed or omittedpursuant to such rules and regulations. For further information, refer to the consolidated financial statementsand notes thereto, included in the PSCo Annual Report on Form 10-K for theyear ended Dec. 31, 2009, filed with the SEC on March 1, 2010.  Due to the seasonality of PSCo’s electric andnatural gas sales, interim results are not necessarily an appropriate base fromwhich to project annual results.

 

**1.****             ****Summary ofSignificant Accounting Policies**

 

Exceptto the extent updated or described below, the significant accounting policiesset forth in Note 1 to the consolidated financial statements in PSCo’s AnnualReport on Form 10-K for the year ended Dec. 31, 2009, appropriatelyrepresent, in all material respects, the current status of accounting policiesand are incorporated herein by reference.

 

***Reclassifications —*** Demand side managementprogram expenses for the six months ended June 30, 2009 were reclassifiedas a separate item from depreciation and amortization expenses within theconsolidated statements of cash flows. The reclassification did not have an impact on net cash provided byoperating activities.

 

**2.****             ****AccountingPronouncements**

 

***Recently Adopted***

 

***Consolidation of Variable Interest Entities***— In June 2009, the Financial Accounting Standards Board (FASB)issued new guidance on consolidation of variable interest entities.  The guidance affects various elements ofconsolidation, including the determination of whether an entity is a variableinterest entity and whether an enterprise is a variable interest entity’sprimary beneficiary.  These updates tothe FASB Accounting Standards Codification (ASC or Codification) are effectivefor interim and annual periods beginning after Nov. 15, 2009.  PSCo implemented the guidance on Jan. 1,2010, and the implementation did not have a material impact on its consolidatedfinancial statements.  For furtherinformation and required disclosures regarding variable interest entities, seeNote 6 to the consolidated financial statements.

 

***Fair Value Measurement Disclosures*** — In January 2010, theFASB issued *Fair Value Measurements andDisclosures (Topic 820) — Improving Disclosures about Fair ValueMeasurements (Accounting Standards Update (ASU) No. 2010-06)*,which updates the Codification to require new disclosures for assets andliabilities measured at fair value.  Therequirements include expanded disclosure of valuation methodologies for fairvalue measurements, transfers between levels of the fair value hierarchy, andgross rather than net presentation of certain changes in Level 3 fairvalue measurements.  The updates to theCodification contained in ASU No. 2010-06 were effective for interim andannual periods beginning after Dec. 15, 2009, except for requirementsrelated to gross presentation of certain changes in Level 3 fair valuemeasurements, which are effective for interim and annual periods beginningafter Dec. 15, 2010.  PSCoimplemented the portions of the guidance required on Jan. 1, 2010, and theimplementation did not have a material impact on its consolidated financialstatements.  For further information andrequired disclosures, see Note 8 to the consolidated financial statements.

 

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**3.****             ****SelectedBalance Sheet Data**

 
| **(Thousands of Dollars)**              | ** ** | **June 30, 2010** | ** ** | **Dec. 31, 2009** | ** ** |
|-----------------------------------------|------------|-------------------|------------|-------------------|------------|
| **Accounts receivable, net**            |       |              |       |              |       |
| Accounts receivable                     |       | $                 | 307,598    |              | $          | 354,428 |   |
| Less allowance for bad debts            |       | (23,379           | )          | (24,149           | )          |
|                                    |       | $                 | 284,219    |              | $          | 330,279 |   |
| **Inventories**                         |       |              |       |              |       |
| Materials and supplies                  |       | $                 | 46,461     |              | $          | 45,809 |   |
| Fuel                                    |       | 84,789            |       | 96,964            |       |
| Natural gas                             |       | 65,908            |       | 110,875           |       |
|                                    |       | $                 | 197,158    |              | $          | 253,648 |   |
| **Property, plant and equipment,  net** |       |              |       |              |       |
| Electric plant                          |       | $                 | 8,570,102  |              | $          | 7,635,325 |   |
| Natural gas plant                       |       | 2,183,640         |       | 2,133,116         |       |
| Common and other property               |       | 766,657           |       | 731,511           |       |
| Construction work in progress           |       | 250,896           |       | 1,038,013         |       |
| Total property, plant and equipment     |       | 11,771,295        |       | 11,537,965        |       |
| Less accumulated depreciation           |       | (3,547,017        | )          | (3,433,124        | )          |
|                                    |       | $                 | 8,224,278  |              | $          | 8,104,841 |   |

 

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

 

***Corporate Owned Life Insurance (******COLI)***— In 2007, Xcel Energyand the U. S. government settled an ongoing dispute regarding PSCo’sright to deduct interest expense on policy loans related to its COLI programthat insured lives of certain PSCo employees. These COLI policies were owned and managed by P.S.R. Investments, Inc.(PSRI), a wholly owned subsidiary of PSCo. Xcel Energy paid the U. S. government a total of$64.4 million in settlement of the U. S. government’s claims fortax, penalty, and interest for tax years 1993 through 2007.  Xcel Energy surrendered the policies toits insurer on Oct. 31, 2007, without recognizing a taxable gain.  As a result of the settlement, the lawsuitfiled by Xcel Energy in the United States District Court has beendismissed and the Tax Court proceedings are in the process of being dismissed.

 

Aspart of the Tax Court proceedings, during the first quarter of 2010, XcelEnergy and the Internal Revenue Service (IRS) reached an agreement in principleafter a comprehensive financial reconciliation of Xcel Energy, dating back totax year 1993.  Upon completion of thisreview, PSRI recorded a net non-recurring tax and interest charge ofapproximately $10 million (including $7.7 million tax expense and $2.3 millioninterest expense, net of tax). Xcel Energy anticipates that the Tax Court proceedings will bedismissed in 2010.

 

***Medicare Part D Subsidy Reimbursements****—* In March 2010, thePatient Protection and Affordable Care Act was signed into law.  The lawincludes provisions to generate tax revenue to help offset the cost of the newlegislation.  One of these provisions reduces the deductibility of retireehealth care costs to the extent of federal subsidies received by plan sponsorsthat provide retiree prescription drug benefits equivalent to MedicarePart D coverage, beginning in 2013.  Based on this provision, PSCo issubject to additional taxes and is required to reverse previously recorded taxbenefits in the period of enactment.

 

Asa result, PSCo expensed approximately $9.9 million of previously recognized taxbenefits relating to Medicare Part D subsidies during the first quarter of2010.  PSCo does not expect the $9.9 million of additional tax expense torecur in future periods.  However, the 2010 effective tax rate (ETR) willincrease due to additional tax expense of approximately $2.0 million associatedwith current year retiree health care accruals.

 

***Federal Audit*****—**PSCo is a member of the Xcel Energy affiliatedgroup that files a consolidated federal income tax return.  During the first quarter of 2010, the IRScompleted an examination of Xcel Energy’s federal income tax returns oftax years 2006 and 2007.  The IRS did notpropose any material adjustments for those tax years.  The statute of limitations applicable to Xcel Energy’s2006 federal income tax return expires on Aug. 28, 2010.  The IRS audit of tax years 2008 and 2009 isexpected to begin during the fourth quarter of 2010.

 

***State Audits*****—**PSCo is a member of the Xcel Energy affiliatedgroup that files consolidated state income tax returns.  As of June 30, 2010, PSCo’s earliestopen tax year that is subject to examination by state taxing authorities underapplicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

 

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***Unrecognized Tax Benefits*****—**The unrecognized tax benefit balance includespermanent tax positions, which if recognized would affect the annual ETR.  In addition, the unrecognized tax benefitbalance includes temporary tax positions 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 ETR but would accelerate the payment of cashto the taxing authority to an earlier period.

 

Areconciliation of the amount of unrecognized tax benefit is as follows:

 
| **(Millions of Dollars)**                          | ** ** | **June 30, 2010** | ** ** | **Dec. 31, 2009** | ** ** |
|----------------------------------------------------|------------|-------------------|------------|-------------------|------------|
| Unrecognized tax benefit - Permanent tax positions |       | $                 | 1.1        |              | $          | 1.0 |   |
| Unrecognized tax benefit - Temporary tax positions |       | 6.4               |       | 6.2               |       |
| Unrecognized tax benefit balance                   |       | $                 | 7.5        |              | $          | 7.2 |   |

 

Theunrecognized tax benefit balance was reduced by the tax benefits associatedwith net operating loss (NOL) and tax credit carry forwards.  The amounts of tax benefits associated withNOL and tax credit carryforwards were as follows:

 
| **(Millions of Dollars)**                                      | ** ** | **June 30, 2010** | ** ** | **Dec. 31, 2009** | ** ** |
|----------------------------------------------------------------|------------|-------------------|------------|-------------------|------------|
| Tax benefits associated with NOL and tax credit  carryforwards |       | $                 | (3.9       | )                 | $          | (4.0 | ) |
|                                                                |            |                   |            |                   |            |  |  |

 

Theincrease in the unrecognized tax benefit balance of $0.5 million from March 31,2010 to June 30, 2010 and $0.3 million from Dec. 31, 2009 to June 30,2010 was due to recently provided guidance pertaining to plant-relateduncertain tax positions, offset by the addition of uncertain tax positionsrelated to ongoing activity.  PSCo’samount of unrecognized tax benefits could significantly change in the next12 months when the IRS and state audits resume.  At this time, due to the uncertain nature ofthe audit process, it is not reasonably possible to estimate an overall rangeof possible change.

 

**5.****             ****RateMatters**

 

Exceptto the extent noted below, the circumstances set forth in Note 14 to theconsolidated financial statements included in PSCo’s Annual Report onForm 10-K for the year ended Dec. 31, 2009 appropriately represent,in all material respects, the current status of other rate matters, and areincorporated herein by reference.

 

***Pending and Recently ConcludedRegulatory Proceedings — Colorado Public Utilities Commission (CPUC)***

 

**Base Rate**

 

***PSCo 2010 Electric Rate Case***— InDecember 2009, the CPUC approved a rate increase of approximately$128.3 million; however, due to the delay in Comanche Unit 3 comingonline, the CPUC approved PSCo’s proposal to phase in the approved electricrate increase to reflect the actual cost of service.  Under the plan, the following increases willbe implemented:

 

·                  A rate increase of$67 million was implemented on Jan. 1, 2010.  The adjustments to the rate increase, becauseof the delay of the in-service date of Comanche Unit 3, include reducedoperations and maintenance expense (O&M), property taxes, the impact of adelay in changes to jurisdictional allocators and depreciation expenses;

·                  Base rates increased torecover $121 million annually, on May 14, 2010 when ComancheUnit 3 went into service; and

·                  Finally, base rates willincrease to recover $128.3 million annually on Jan. 1, 2011 toreflect 2011 property taxes.

 

Severalparties, including PSCo and the Office of Consumer Counsel (OCC), filed motionsfor reconsideration.  On April 19,2010, the CPUC granted PSCo’s request to not include long-term debt interest inthe working capital calculation, which increases the revenue deficiency,recovered under the order by approximately $2.2 million, and denied all otherrequests for reconsideration.

 

ComancheUnit 3 went into service in May 2010, and the CPUC allowed both the stepchange for Comanche Unit 3 in-service and the increase to reflect the debtinterest on working capital.

 

Asecond phase of the rate case addressed changes to rate design.  The new rates approved by the CPUC went intoeffect on June 1, 2010.  In this phase of the proceeding, the CPUCapproved tiered summer rates for residential customers and seasonallydifferentiated rates for other customer classes.  The CPUC also approved a low-income pilotprogram similar to the previously approved gas low-income pilot program.

 

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***Transmission Cost Adjustment (TCA)Rider***— In April 2010, PSCo filed a TCA rider, toadjust to the amounts recovered in the rider based on the outcome of the 2010rate case.  The filing reduced rates by$2.3 million, effective June 1, 2010. The new TCA rider reflects actual 13-month average transmission plant inservice and year-end transmission construction work in progress (CWIP) accountbalances for 2009, as compared to the amount of transmission costs included inPSCo’s last rate case.

 

***Unreasonable Rates for Natural GasFormal Complaint***— In July 2009, the trial advocacy staffof the CPUC proposed a complaint against PSCo for unreasonable rates fornatural gas service associated with earnings in excess of PSCo’s authorizedreturn that occurred in 2008.  InJanuary 2010, the CPUC opened a proceeding and assigned this matter to anALJ.

 

TheALJ recommended approval of an unopposed settlement of the case on June 14,2010 and vacated the schedule in the docket. The settlement, provided that no adjustments to current rates would bemade, PSCo would file a gas rate case before the end of 2010.  In that case, PSCo would propose to removerecovery on gas in storage from base rates to an adjustment clause.

 

***Renewable Energy Credit (REC) SharingSettlement***— In August 2009, PSCo filed an applicationseeking approval of treatment of margins associated with certain sales ofColorado RECs bundled with energy into California.  In January 2010, PSCo, the OCC, the CPUCstaff, the Colorado governor’s energy office and Western Resource Advocatesentered into a unanimous settlement in this case.  The settlement establishes a pilot programand defines certain margin splits during this pilot period.  The settlement provides margins would beshared based on the following:

 
| **Margin**                 | ** ** | **Customers** | ** ** | **PSCo** | ** ** | **Carbon  Offsets** | ** ** |
|----------------------------|------------|---------------|------------|----------|------------|---------------------|------------|
| Less that $10 million      |       | 50            | %          | 40       | %          | 10                  | %          |
| $10 million to $30 million |       | 55            |       | 35       |       | 10                  |       |
| Greater than $30 million   |       | 60            |       | 30       |       | 10                  |       |

 

Amountsdesignated as carbon offsets are recorded as a regulatory liability untilcarbon offset-related expenditures are incurred.  Carbon offsets are capped at $10 million,with the remaining 10 percent going to customers after the cap is reached.  The unanimous settlement also clarified thatmargins associated with RECs bundled with Colorado energy would be shared20 percent to PSCo and 80 percent to customers and margins associatedwith sales of stand-alone renewable energy credits without energy would becredited 100 percent to customers. The CPUC approved the settlement in a written order in May 2010.

 

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

 

***Wholesale Rate Case***— In 2009, PSCofiled a request with the FERC to increase electric rates to its firm wholesalecustomers by $30.7 million based on a 12.5 percent ROE, a58 percent equity ratio and a rate base of $315 million.  In June and July 2010, PSCo filed blackboxsettlements with all of its wholesale customers except for Intermountain RuralElectric Association at the FERC.  Underthe terms of that settlement, PSCo would increase rates on an annual basis by$17.0 million for these customers, effective July 7, 2010.  In addition, on Jan. 1, 2011, anadditional step rate increase of $1.0 million will be implemented for propertytaxes associated with Comanche Unit 3. The terms of the settlement provide for lower depreciation expense thanrequested and for certain capacity costs to be recovered through the fuelclause until those contracts expire. Adecision by the FERC on the settlements is expected by the end of 2010.

 

**6.****             ****Commitmentsand Contingent Liabilities**

 

Except to the extent notedbelow and in Note 5 to the consolidated financial statements in this QuarterlyReport on Form 10-Q the circumstances set forth in Notes 14 and 15 to theconsolidated financial statements included in PSCo’s Annual Report onForm 10-K for the year ended Dec. 31, 2009, appropriately represent,in all material respects, the current status of commitments and contingentliabilities, and are incorporated herein by reference.  The following include commitments,contingencies and unresolved contingencies that are material to PSCo’sfinancial position.

 

**Commitments**

 

***Variable Interest Entities*****— Effective Jan. 1,2010, PSCo adopted new guidance on consolidation of variable interest entitiescontained in *ASC 810**Consolidation*.  The guidance requires enterprises to considerthe activities that most significantly impact an entity’s financialperformance, and power to direct those activities, when determining whether anentity is a variable interest entity and whether an enterprise is a variableinterest entity’s primary beneficiary.

 

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*PurchasedPower Agreements*— PSCo has entered into agreements with otherutilities and energy suppliers for purchased power to meet system load andenergy requirements, replace generation from company-owned units undermaintenance or during outages, and meet operating reserve obligations.

 

PSCohas various pay-for-performance contracts with expiration dates through theyear 2034.  In general, these contractsprovide for energy payments based on actual power taken under the contracts aswell as capacity payments.  Capacitypayments are typically contingent on the independent power producing entitymeeting certain contract obligations, including plant availability requirements.  Certain contractual payments are adjustedbased on market indices; however, the effects of price adjustments aremitigated through purchased energy cost recovery mechanisms.

 

PSCois not subject to risk of loss from the operations of these entities, and nosignificant financial support has been, or is in the future required to beprovided other than contractual payments for energy and capacity set forth inpurchased power agreements.

 

Certainnatural gas fueled purchased power agreements that either reimburse theindependent power producing entities for fuel costs, or contain tollingarrangements under which PSCo procures the fuel required to produce the energyit purchases, have been determined to be variable interest entities.

 

PSCohas evaluated each of these variable interest entities for possibleconsolidation, including review of qualitative factors such as the length andterms of the contract, control over operations and maintenance, historical andestimated future fuel and electricity prices, and financing activities.  PSCo has concluded that these entities arenot required to be consolidated in its consolidated financial statementsbecause it does not have the power to direct the activities that most significantlyimpact the entities’ economic performance. As of June 30, 2010 and Dec. 31, 2009, PSCo had approximately2,921 megawatts (MW) of capacity under long term purchased power agreementswith entities that have been determined to be variable interest entities.

 

**EnvironmentalContingencies**

 

PSCo has been, or iscurrently, involved with the cleanup of contamination from certain hazardoussubstances at several sites.  In manysituations, PSCo believes it will recover some portion of these costs throughinsurance claims.  Additionally, whereapplicable, PSCo is pursuing, or intends to pursue, recovery from otherpotentially responsible parties (PRPs) and through the rate regulatoryprocess.  New and changing federal andstate environmental mandates can also create added financial liabilities forPSCo, which are normally recovered through the rate regulatory process.  To the extent any costs are not recoveredthrough the options listed above, PSCo would be required to recognize anexpense.

 

***Site Remediation****—*PSCo must payall or a portion of the cost to remediate sites where past activities of PSCoor other parties have caused environmental contamination.  Environmental contingencies could arise fromvarious situations, including sites of former manufactured gas plants operatedby PSCo, its predecessors, or other entities; and third-party sites, such aslandfills, for which PSCo is alleged to be a PRP that sent hazardous materialsand wastes.  At June 30, 2010, theliability for the cost of remediating these sites was estimated to be $0.8million, of which $0.3 million was considered to be a current liability.

 

***Third Party and OtherEnvironmental Site Remediation***

 

***Asbestos Removal*****—**Some of PSCo’sfacilities contain asbestos.  Mostasbestos will remain undisturbed until the facilities that contain it aredemolished or renovated.  PSCo hasrecorded an estimate for final removal of the asbestos as an asset retirementobligation.  See additional discussion ofasset retirement obligations in Note 15 of the PSCo Annual Report onForm 10-K for the year ended Dec. 31, 2009.  It may be necessary to remove some asbestosto perform maintenance or make improvements to other equipment.  The cost of removing asbestos as part of otherwork is immaterial and is recorded as incurred as operating expenses for maintenanceprojects, capital expenditures for construction projects or removal costs fordemolition projects.

 

***Other Environmental Requirements***

 

***Colorado Clean Air-Clean Jobs Act***— The Colorado CleanAir-Clean Jobs Act (the Act) was signed into law on April 19, 2010.  The Act establishes a timeline and regulatoryframework for rate-regulated utilities in Colorado to develop a plan topotentially retrofit, retire or replace 900 MW or more of aging coal-firedelectric generating capacity.  The planmust result in a reduction of 70 to 80 percent in nitrogen oxide (NOx)emissions from affected coal-fired power plants by 2018 or sooner to meetcurrent and reasonably foreseeable Clean Air Act (CAA) emission reductionmandates.

 

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Underthe emission reduction plan, PSCo may retrofit its existing coal-fired plantswith emission controls or retire and replace the plants with natural gas-firedgeneration or other low emitting resources. The Act specifically requires PSCo to study the early retirement of upto 900 MW of existing coal-fired capacity, but does not require any retirementunless, among other things, the retirement can be accomplished at a reasonablecost while protecting system reliability. PSCo must submit its plan to the CPUC by Aug. 15, 2010 and the CPUCmust act on the plan by Dec. 15, 2010.

 

Pursuantto the Act, PSCo is entitled to fully recover the costs that it prudentlyincurs in executing an approved emission reduction plan and is allowed a returnon CWIP on plan investments.  Inaddition, if early action is taken to retire or convert units to natural gas,and PSCo shows that the costs of the plan would contribute to any earningsdeficiency, additional relief, including a more comprehensive rider to recoverother plant costs such as depreciation and O&M expense, or a multi-yearrate plan are allowed.  The Act alsomakes interim rates permissible in Colorado, starting Jan. 1, 2012.  Additional information regarding the ColoradoClean Air-Clean Jobs Act is presented in the Management’s Discussion ofAnalysis of Financial Condition and Results of Operations, Factors AffectingResults of Continuing Operations, Public Utility Regulation section.

 

***Environmental Protection Agency (EPA)Greenhouse Gas (GHG) Rulemaking***— On Dec. 7, 2009, inresponse to the U. S. Supreme Court’s decision in *Massachusettsv. EPA*, 549 U. S. 497 (2007), the EPA issued its “endangerment”finding that GHG emissions endanger public health and welfare and thatemissions from motor vehicles contribute to the GHGs in the atmosphere.  This endangerment finding created a mandatoryduty for the EPA to regulate GHGs from light duty vehicles.  The EPA finalized GHG efficiency standardsfor light duty vehicles in spring of 2010 and has promulgated permittingrequirements for GHGs for large new and modified stationary sources, such aspower plants.  These regulations willbecome applicable in 2011.

 

***Clean Air MercuryRule (CAMR) —***In March 2005, the EPAissued the CAMR, which regulated mercury emissions from power plants.  In February 2008, the U. S. Court ofAppeals for the District of Columbia vacated CAMR, which impacted federal CAMRrequirements, but not necessarily state-only mercury legislation andrules.  The EPA has agreed to finalizeMaximum Achievable Control Technology (MACT) emission standards for allhazardous air pollutants from electric utility steam generating units byNovember 2011 to replace CAMR.  PSCoanticipates that the EPA will require affected facilities to demonstratecompliance within 18 to 36 months thereafter.

 

***Colorado Mercury Regulation***— Colorado’smercury regulations require mercury emission controls capable of achieving80 percent capture to be installed at the Pawnee Generating Station by2012 and other specified units by 2014. The expected cost estimate for the Pawnee Generating Station is$2.3 million for capital costs with an annual estimate of$1.4 million for sorbent expense. PSCo is evaluating the emission controls required to meet the staterule for the remaining units and is currently unable to provide a totalcapital cost estimate.

 

***Regional Haze Rules —***InJune 2005, the EPA finalized amendments to the July 1999 regionalhaze rules.****** These amendments apply to the provisions ofthe regional haze rule that require emission controls, known as bestavailable retrofit technology (BART), for industrial facilities emitting airpollutants that reduce visibility by causing or contributing to regionalhaze.  Xcel Energy generating facilitiesin several states will be subject to BART requirements.

 

Statesare required to identify the facilities that will have to reduce sulfurdioxide, NOx and particulate matter emissions under BART and then set BARTemissions limits for those facilities. In May 2006, the Colorado Air Quality Control Commissionpromulgated BART regulations requiring certain major stationary sources toevaluate, install, operate and maintain BART to make reasonable progress towardmeeting the national visibility goal.

 

PSCoexpects the cost of any required capital investment will be recoverable fromcustomers.  Emissions controls areexpected to be installed between 2012 and 2015. Colorado’s BART state implementation plan (SIP) has been submitted tothe EPA for approval.  The Colorado AirPollution Control Division (CAPCD) is currently analyzing what types ofadditional NOx controls may be necessary to meet reasonable progress goals forColorado’s Class I areas, the new ozone standard, and Rocky MountainNational Park nitrogen deposition reduction goals.  The CAPCD has indicated that it expects tosubmit a Regional Haze/Reasonable Further Progress SIP to the EPA in early2011.  PSCo anticipates that for thoseplants included in the Clean Air-Clean Jobs Act’s emission reduction plan, theplan will satisfy regional haze requirements.

 

InMarch 2010, two environmental groups petitioned the U. S. Department ofInterior (DOI) to certify that 12 coal-fired boilers and one coal-fired cementkiln in Colorado are contributing to visibility problems in Rocky MountainNational Park.  Four PSCo plants arenamed in the petition:  Cherokee, Hayden,Pawnee and Valmont.  The groups allegethat the Colorado BART rule is inadequate to satisfy the CAA mandate ofensuring reasonable further progress towards restoring natural visibilityconditions in the park.  It is not knownwhen the DOI will rule on the petition.

 

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***Federal Clean Water Act***— The federalClean Water Act (CWA) 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 publishedphase II of the rule, which applies to existing cooling water intakes atsteam-electric power plants.  Severallawsuits were filed against the EPA challenging the phase IIrulemaking.  In April 2009, the U.S. Supreme Court issued a decision in *EntergyCorp. v. Riverkeeper, Inc.*, concluding that the EPA canconsider a cost benefit analysis when establishing BTA.  The decision overturned only one aspect ofthe Court of Appeals’ earlier opinion, and gives the EPA the discretion toconsider costs and benefits when it reconsiders its phase II rules.  Until the EPA fully responds, the rule’scompliance requirements and associated deadlines will remain unknown.  As such, it is not possible to provide anaccurate estimate of the overall cost of this rulemaking at this time.

 

***Proposed Coal Ash Regulation***—  In June 2010, the EPA published aproposed rule seeking comment on whether to regulate coal combustionbyproducts (often referred to as coal ash) as a special waste (subject tomany of the requirements for hazardous waste) or as a solid(nonhazardous) waste.  Coal ash is currently exempt from hazardouswaste regulation.  The EPA’s proposalwould result in more comprehensive and expensive requirements related tomanagement and disposal of coal ash. There is a 90-day comment deadline to submit comments on the rule, butrequests for extension of time to submit comments have been submitted to theEPA.  The EPA is also seekingcomment on what regulations are appropriate for the beneficial reuse ofcoal ash.  The timing, scope and potential cost of any final rule thatmight be implemented are not determinable at this time.

 

***PSCo Notice of Violation (NOV)***— In July 2002,PSCo received an NOV from the EPA alleging violations of the New Source Review(NSR) requirements of the CAA at the Comanche Station and Pawnee Station inColorado.  The NOV specifically allegesthat various maintenance, repair and replacement projects undertaken at theplants in the mid to late 1990s should have required a permit under the NSRprocess.  PSCo believes it has acted infull compliance with the CAA and NSR process. PSCo believes that the projects identified in the NOV fit within theroutine maintenance, 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.

 

**LegalContingencies**

 

Lawsuitsand claims arise in the normal course of business.  Management, after consultation with legalcounsel, has recorded an estimate of the probable cost of settlement or otherdisposition of them.  The ultimateoutcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of thesematters could have a material adverse effect on PSCo’s financial position andresults of operations.

 

**Environmental Litigation**

 

***Carbon Dioxide (CO******2******) Emissions Lawsuit —***In 2004, theattorneys 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 CO2 emissions. The other utilities include American Electric Power Co., Southern Co.,Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a publicnuisance.  The lawsuits do not demand monetarydamages.  Instead, the lawsuits ask thecourt to order each utility to cap and reduce its CO2 emissions. On Sept. 19, 2005, the court granted a motion to dismiss onconstitutional grounds.  On appeal in September 2009,the U. S. Court of Appeals for the Second Circuit reversed the lower courtdecision.  Defendants anticipate filing apetition for review with the U. S. Supreme Court.

 

***Comer vs. Xcel Energy Inc. etal. —***In 2006, Xcel Energy, the parent company of PSCo,received notice of a purported class action lawsuit filed in U. S. DistrictCourt in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies,including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate anddirect cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege negligence and public andprivate nuisance and seek damages related to the loss resulting from thehurricane.  Xcel Energy believes thislawsuit is without merit and intends to vigorously defend itself against theseclaims.  In August 2007, the courtdismissed the lawsuit in its entirety against all defendants on constitutionalgrounds.  Plaintiffs filed a notice ofappeal to the U. S. Court of Appeals for the Fifth Circuit.  In October 2009, the U. S. Court ofAppeals for the Fifth Circuit reversed the district court decision, in part,concluding that the plaintiffs pleaded sufficient facts to overcome theconstitutional challenges that formed the basis for dismissal by the districtcourt.  A subsequent petition bydefendants, including Xcel Energy, for en banc review was granted.  On May 28, 2010, the U. S. Court ofAppeals for the Fifth Circuit ruled that it lacked an en banc quorum of nineactive members to hear the case.  Itdismissed the appeal, which resulted in the reinstatement of the district court’sopinion dismissing the case.

 

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***Native Village of Kivalina vs. XcelEnergy Inc. et al. —***In 2008, the City and NativeVillage of Kivalina, Alaska, filed a lawsuit in U. S. District Court for theNorthern District of California against Xcel Energy, the parent company ofPSCo, and 23 other utilities, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission ofCO2 and other GHGs contribute to global warming,which is harming their village.  XcelEnergy believes the claims asserted in this lawsuit are without merit andjoined with other utility defendants in filing a motion to dismiss onJune 30, 2008.  In October 2009,the U. S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed anotice of appeal to the U. S. Court of Appeals for the Ninth Circuit.  It is unknown when the Ninth Circuit willrender a final opinion.

 

***Comanche Unit 3 CAA Lawsuit***— In July 2009,WildEarth Guardians (WEG) filed a lawsuit in the U. S. District Court inColorado against PSCo alleging that PSCo violated the CAA by constructingComanche Unit 3 without a final MACT determination from the ColoradoDepartment of Public Health and Environment, Air Pollution Control Division(APCD).  PSCo disputes these claims andfiled a motion to dismiss the suit. Comanche Unit 3 was constructed with state-of-the-art emissioncontrols and pursuant to a valid air permit issued by the APCD.  In January 2010, WEG sought to enjoinPSCo from constructing, modifying, or operating Comanche Unit 3 prior toreceiving a final MACT determination. The court denied WEG’s request for a temporary restraining order onJan. 26, 2010.  In March 2010,the court partially granted and partially denied PSCo’s motion to dismiss.  The court requested additional briefing oncertain issues related to the MACT determination.  Briefing has now been completed, and thecourt is expected to issue a final ruling in due course.

 

***Cherokee Opacity Lawsuit***— In August 2009, WEGfiled a lawsuit alleging that PSCo had violated the CAA through alleged opacitymonitor downtime, as well as by allegedly exceeding opacity limits on 49occasions over a five-year period at Cherokee Station.  In September 2009, PSCo filed a motionto dismiss the lawsuit and argued that opacity monitor downtime is permitted bylaw.  Cherokee’s opacity monitors wereoperating 98.4 percent of the time during the period in question.  When the monitors were not operating, it wasfor allowed activities, such as calibration, quality control or repair.  On April 16, 2010, the court denied PSCo’smotion to dismiss, holding that whether the opacity monitor downtime ispermitted is a question of fact that cannot be resolved in a motion todismiss.  PSCo will continue tovigorously defend the lawsuit.

 

**Employment,Tort and Commercial Litigation**

 

***Qwest vs. Xcel Energy Inc.***— In 2004, anemployee of PSCo was seriously injured when a pole owned by Qwestmalfunctioned.  In September 2005,the employee commenced an action against Qwest in Colorado state court inDenver.  In April 2006, Qwest fileda third party complaint against PSCo based on terms in a joint pole useagreement between Qwest and PSCo.  InMay 2007, the matter was tried and the jury found Qwest solely liable forthe accident and this determination resulted in an award of damages in theamount of approximately $90 million. In April 2009, the Colorado Court of Appeals affirmed the juryverdict insofar as it relates to claims asserted by Qwest against PSCo.  Qwest filed a petition for rehearing with theColorado Supreme Court in June 2009. In February 2010, the Colorado Supreme Court agreed to review theCourt of Appeals’ decision as to the punitive damages issue but will not reviewthe Court of Appeals’ decision as it relates to PSCo.  It is unknown when the Colorado Supreme Courtwill render a decision.

 

***Mallon vs. XcelEnergy Inc. —***In August 2007, XcelEnergy, PSCo and PSRI (Plaintiffs) commenced a lawsuit in Colorado state courtagainst Theodore Mallon and TransFinancial Corporation seeking damages for,among other things, breach of contract and breach of fiduciary dutiesassociated with the sale of COLI policies. In May 2008, Plaintiffs filed an amended complaint that, amongother things, adds Provident Life & Accident Insurance Company(Provident) as a defendant and asserts claims for breach of contract, unjustenrichment and fraudulent concealment against the insurance company.  In November 2009, Plaintiffs reached asettlement with Mallon and TransFinancial Corporation, where Mallon agreed topay Plaintiffs a specified amount of money and the parties agreed to mutuallyrelease each other from all claims.

 

OnJuly 6, 2010, Plaintiffs entered into a settlement agreement withProvident.  Under the terms of thesettlement, Provident and Reassure America Life Insurance Company paidPlaintiffs $25 million.  Xcel Energy willrecord this settlement of $25 million in the third quarter of 2010.  See additional information set forth in Note15 to the consolidated financial statements in this Quarterly Report onForm 10-Q.

 

***Cabin Creek Hydro Generating StationAccident***— In October 2007, employees of RPI CoatingsInc. (RPI), a contractor retained by PSCo, were applying an epoxy coating tothe inside of a penstock at PSCo’s Cabin Creek Hydro Generating Station nearGeorgetown, Colo.  A fire occurred insidea pipe used to deliver water from a reservoir to the hydro facility.  Five RPI employees were unable to exit thepipe and rescue crews confirmed their deaths. The accident was investigated by several state and federal agencies,including the federal Occupational Safety and Health Administration (OSHA) andthe U. S. Chemical Safety Board and the Colorado Bureau of Investigations.

 

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InMarch 2008, OSHA proposed penalties totaling $189,900 for 22 seriousviolations and three willful violations arising out of the accident.  In April 2008, Xcel Energy notified OSHAof its decision to contest all of the proposed citations.  On May 28, 2008, the Secretary of Laborfiled its complaint, and Xcel Energy subsequently filed its answer onJune 17, 2008.  The Court orderedthis proceeding stayed until March 3, 2009 and has subsequently extended thestay until the criminal proceedings have concluded.

 

Alawsuit was filed in Colorado state court in Denver on behalf of four of thedeceased workers and four of the injured workers (Foster, et. al. v. PSCo, et.al.).  PSCo and Xcel Energy were named asdefendants in that case, along with RPI Coatings and related companies and thetwo other contractors who also performed work in connection with the reliningproject at Cabin Creek.  A second lawsuit(Ledbetter et. al vs. PSCo et. al) was also filed in Colorado state court inDenver on behalf of three employees allegedly injured in the accident.  A third lawsuit was filed on behalf of one ofthe deceased RPI workers in the California state court (Aguirre v. RPI, et. al.),naming PSCo, RPI, and the two other contractors as defendants.  The court subsequently dismissed the Aguirrelawsuit.  Settlements were subsequentlyreached in all three lawsuits.  Theseconfidential settlements did not have a material effect on the financialstatements of Xcel Energy or its subsidiaries.

 

OnAug. 28, 2009, the U. S. Government announced that Xcel Energy and PSCohave been charged with five misdemeanor counts in federal court in Colorado forviolation of an OSHA regulation related to the accident at Cabin Creek inOctober 2007.  RPI Coatings, thecontractor performing the work at the plant, and two individuals employed byRPI have also been indicted.  OnSept. 22, 2009, both Xcel Energy and PSCo entered a not guilty plea, andboth will vigorously defend against these charges.  In December 2009, Xcel Energy and PSCofiled two separate motions to dismiss. On March 29, 2010, the court issued an order denying bothmotions.  No trial date has yet been set.

 

***Stone & Webster, Inc.vs. PSCo***— In July 2009, Stone &Webster, Inc. (Shaw) filed a complaint against PSCo in State DistrictCourt in Denver, Colo. for damages allegedly arising out of its constructionwork on the Comanche Unit 3 coal fired plant.  Shaw, a contractor retained to performcertain engineering, procurement and construction work on Comanche Unit 3,alleges, among other things, that PSCo mismanaged the construction of ComancheUnit 3.  Shaw further claims thatthis alleged mismanagement caused delays and damages in excess of$55 million.  The complaint alsoalleges that Xcel Energy and related entities guaranteed Shaw $10 millionin future profits under the terms of a 2003 settlement agreement.  Shaw alleges that it will not receive the$10 million to which it is entitled. Accordingly, Shaw seeks an amount up to $10 million relating to the2003 settlement agreement.  PSCo deniesthese allegations and believes the claims are without merit.  PSCo filed an answer and counterclaim inAugust 2009, denying the allegations in the complaint and alleging thatShaw has failed to discharge its contractual obligations and has caused delays,and that PSCo is entitled to liquidated damages and excess costs incurred.  In June 2010, PSCo exercised itscontractual right to draw on Shaw’s letter of credit in the total amount ofapproximately $29.6 million.  Trial isscheduled for Oct. 18, 2010.

 

***Connie DeWeese vs. PSCo***— InNovember 2008, there was an explosion in Pueblo, Colo., which destroyed atavern and a neighboring store.  Theexplosion killed one person and injured seven people.  The Pueblo Fire Department and the FederalBureau of Alcohol, Tobacco and Firearms have determined a natural gas leak froma pipeline under the street led to the explosion.  In February 2010, a wrongfuldeath/personal injury lawsuit was filed in Colorado District Court in Pueblo,Colorado against PSCo and the City of Pueblo by several parties that wereallegedly injured, as a result of this explosion.  The plaintiffs are also alleging economic andnoneconomic damages.  The lawsuit allegesthat the accident occurred as a result of PSCo’s negligence.  A related lawsuit was filed in March 2010by Seneca Insurance Company, which insured Branch Inn, LLC and Branch InnEnterprises, LLC.  The Plaintiffs arealleging destruction of the building and disruption of the business.  Both lawsuits allege that the accidentoccurred as a result of PSCo’s negligence. PSCo denies liability for this accident. The cases have been consolidated. In June 2010, the court granted, in part, PSCo’s motion to dismisscertain of plaintiffs’ claims related to, among other things, strictliability.  In July 2010, a thirdrelated lawsuit was filed by Truck Insurance Exchange against PSCo and the Cityof Pueblo to recover damages allegedly paid by the plaintiff insurance companyto its insured as a result of the explosion. PSCo will file a response denying liability in due course.

 

**7.****    ****Short-Term Borrowings and OtherFinancing Instruments**

 

***Commercial Paper —***The following table presents commercial paperoutstanding for PSCo:

 
| **(Millions of Dollars)**                     | ** ** | **June 30, 2010** | ** ** | **Dec. 31, 2009** | ** ** |
|-----------------------------------------------|------------|-------------------|------------|-------------------|------------|
| Commercial paper outstanding                  |       | $                 | —     |              | $          | 95 |   |
| Weighted average interest rate                |       | N/A               | %          | 0.35              | %          |
| Total commercial paper available for issuance |       | $                 | 675        |              | $          | 675 |   |

 

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***Money Pool —***Xcel Energy and its utility subsidiaries haveestablished a money pool arrangement that allows for short-term investments inand borrowings from the utility subsidiaries between each other.  The holding company may make investments inthe utility subsidiaries at market-based interest rates; however, the moneypool arrangement does not allow the utility subsidiaries to make investments inthe holding company.

 

The following table presentsthe money pool investments (borrowings) for PSCo:

 
| **(Millions of Dollars)**           | ** ** | **June 30, 2010** | ** ** | **Dec. 31, 2009** | ** ** |
|-------------------------------------|------------|-------------------|------------|-------------------|------------|
| Money pool investments (borrowings) |       | $                 | 79         |              | $          | (84 | ) |
| Weighted average interest rate      |       | 0.40              | %          | 0.36              | %          |
| Money pool borrowing limit          |       | $                 | 250        |              | $          | 250 |   |

 

**8.****    ****DerivativeInstruments and Fair Value Measurements**

 

PSCoenters into derivative instruments, including forward contracts, futures, swapsand options, for trading purposes and to reduce risk in connection with changesin interest rates, utility commodity prices and vehicle fuel prices.

 

***Short-Term Wholesale and Commodity TradingRisk —***PSCo conducts various short-term wholesale andcommodity trading activities, including the purchase and sale of electriccapacity, energy and energy-related instruments.  PSCo’s risk management policy allowsmanagement to conduct the marketing activities within guidelines andlimitations as approved by its risk management committee, which is made up ofmanagement personnel not directly involved in the activities governed by thepolicy.

 

***Interest Rate Derivatives —***PSCo entersinto various instruments that effectively fix the interest payments on certainfloating rate debt obligations or effectively fix the yield or price on aspecified benchmark interest rate for a specific period.  These derivative instruments are generallydesignated as cash flow hedges for accounting purposes.

 

AtJune 30, 2010, accumulated other comprehensive income (OCI) related tointerest rate derivatives included $1.5 million of net gains expected to bereclassified into earnings during the next 12 months as the related hedgedinterest rate transactions impact earnings.

 

***Commodity Derivatives —***PSCo entersinto derivative instruments to manage variability of future cash flows fromchanges in commodity prices in its electric and natural gas operations, as wellas for trading purposes.  This couldinclude the purchase or sale of energy or energy-related products, natural gasto generate electric energy, gas for resale, and vehicle fuel.

 

AtJune 30, 2010, PSCo had various vehicle fuel related contracts designatedas cash flow hedges extending through December 2012.  PSCo also enters into derivative instrumentsthat mitigate commodity price risk on behalf of electric and natural gascustomers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-tradingcommodity derivative instruments are recorded in OCI or deferred as aregulatory asset or liability.  Theclassification as a regulatory asset or liability is based on commissionapproved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to theineffectiveness of cash flow hedges for the six months ended June 30,2010.

 

AtJune 30, 2010, accumulated OCI related to commodity derivative cash flowhedges included $0.7 million of net losses expected to be reclassified intoearnings during the next 12 months as the hedged transactions occur.

 

Additionally, PSCo entersinto commodity derivative instruments for trading purposes not directly relatedto commodity price risks associated with serving its electric and natural gascustomers.  Changes in the fair value ofthese commodity derivatives are recorded in income subject to applicablecustomer margin-sharing mechanisms.

 

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Thefollowing table details the gross notional amounts of commodity forwards atJune 30, 2010 and Dec. 31, 2009:

 
| **(Amounts in Thousands)****(a)**   | ** ** | **June 30, 2010** | ** ** | **Dec. 31, 2009** | ** ** |
|-------------------------------------|------------|-------------------|------------|-------------------|------------|
| Megawatt hours (MWh) of electricity |       | 5,222             |       | 3,559             |       |
| MMBtu of natural gas                |       | 44,994            |       | 45,352            |       |
| Gallons of vehicle fuel             |       | 870               |       | 1,559             |       |

 

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(a) Amounts are not reflective of net positions in theunderlying commodities.

 

***Financial Impact of Qualifying Cash FlowHedges —***The impact of qualifying interest rate and vehiclefuel cash flow hedges on PSCo’s accumulated OCI, included as a component ofcommon stockholder’s equity, is detailed in the following table:

 
| ** **                                                                              | ** ** | **Three Months  Ended June 30,** | ** ** |
|-----------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| **(Thousands of Dollars)**                                                              | ** ** | **2010**                         | ** ** | **2009** | ** ** |
| Accumulated other  comprehensive income related to cash flow hedges at April 1          |       | $                                | 7,993      |   | $ | 7,763 |   |
| After-tax net unrealized  (losses) gains related to derivatives accounted for as hedges |       | (123                             | )          | 586 |   |
| After-tax net realized  gains on derivative transactions reclassified into earnings     |       | (166                             | )          | (328 | ) |
| Accumulated other  comprehensive income related to cash flow hedges at June 30          |       | $                                | 7,704      |   | $ | 8,021 |   |

 
| ** **                                                                              | ** ** | **Six Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------------------------------|------------|-------------------------------|------------|
| **(Thousands of Dollars)**                                                              | ** ** | **2010**                      | ** ** | **2009** | ** ** |
| Accumulated other comprehensive income related to  cash flow hedges at Jan. 1           |       | $                             | 8,101      |   | $ | 7,628 |   |
| After-tax net unrealized (losses) gains related to  derivatives accounted for as hedges |       | (108                          | )          | 599 |   |
| After-tax net realized gains on derivative transactions  reclassified into earnings     |       | (289                          | )          | (206 | ) |
| Accumulated other comprehensive income related to  cash flow hedges at June 30          |       | $                             | 7,704      |   | $ | 8,021 |   |

 

PSCo had no derivativeinstruments designated as fair value hedges during the three and six monthsended June 30, 2010 and June 30, 2009.  Therefore, no gains or losses from fair valuehedges or related hedged transactions were recognized for these periods.

 

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Thefollowing tables detail the impact of derivative activity during the three andsix months ended June 30, 2010 and June 30, 2009, respectively, onOCI, regulatory assets and liabilities, and income:

 
| ** **                                     | ** ** | **Three  Months Ended June 30, 2010**                | ** ** |
|------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                     | ** ** | **Fair  Value Changes Recognized  During the Period in:** | ** ** | **Pre-Tax  Amounts Reclassified into  Income During the Period from:** | ** ** | **Pre-Tax  Gains (Losses)** | ** ** |
| **(Thousands of Dollars)**           | ** ** | **Other  Comprehensive  Income (Losses)**                 | ** ** | **Regulatory  Assets and  Liabilities** | ** ** | **Other  Comprehensive  Income** | ** ** | **Regulatory  Assets and  Liabilities** | ** ** | **Recognized  During the Period  in Income** | ** ** |
| **Derivatives designated as cash flow hedges** | ** ** | ** **                                                | ** ** | ** ** |   |   | ** ** | ** ** |   |   |   |
| Interest  rate                                 |       | $                                                         | —     |   | $ | — |   | $ | (582 | )(a) | $ | — |   | $ | — |   |
| Vehicle  fuel and other commodity              |       | (198                                                      | )          | — |   | 315 | (c) | — |   | — |   |
| Total                                          |       | $                                                         | (198       | ) | $ | — |   | $ | (267 | ) | $ | — |   | $ | — |   |
|                                           |       |                                                      |       |   |   |   |   |   |   |   |   |
| **Other derivative instruments**               |       |                                                      |       |   |   |   |   |   |   |   |   |
| Trading  commodity                             |       | $                                                         | —     |   | $ | — |   | $ | — |   | $ | — |   | $ | (273 | )(b) |
| Natural  gas commodity                         |       | —                                                    |       | (3,723 | ) | — |   | 752 | (d) | — |   |
| Other                                          |       | —                                                    |       | — |   | — |   | — |   | 84 | (b) |
| Total                                          |       | $                                                         | —     |   | $ | (3,723 | ) | $ | — |   | $ | 752 |   | $ | (189 | ) |

 
| ** **                                     | ** ** | **Six  Months Ended June 30, 2010**                       | ** ** |
|------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                     | ** ** | **Fair  Value Changes Recognized  During the Period in:** | ** ** | **Pre-Tax  Amounts Reclassified into  Income During the Period from:** | ** ** | **Pre-Tax  Gains (Losses)** | ** ** |
| **(Thousands  of Dollars)**                    | ** ** | **Other  Comprehensive  Income (Losses)**                 | ** ** | **Regulatory  Assets and  Liabilities** | ** ** | **Other  Comprehensive  Income** | ** ** | **Regulatory  Assets and  Liabilities** | ** ** | **Recognized  During the Period  in Income** | ** ** |
| **Derivatives designated as cash flow hedges** |       |                                                      |       |   | ** ** | ** ** | ** ** | ** ** |   |   |   |
| Interest  rate                                 |       | $                                                         | —     |   | $ | — |   | $ | (1,158 | )(a) | $ | — |   | $ | — |   |
| Vehicle  fuel and other commodity              |       | (174                                                      | )          | — |   | 692 | (c) | — |   | — |   |
| Total                                          |       | $                                                         | (174       | ) | $ | — |   | $ | (466 | ) | $ | — |   | $ | — |   |
|                                           |       |                                                      |       |   |   |   |   |   |   |   |   |
| **Other derivative instruments**               |       |                                                      |       |   |   |   |   |   |   |   |   |
| Trading  commodity                             |       | $                                                         | —     |   | $ | — |   | $ | — |   | $ | — |   | $ | (522 | )(b) |
| Natural  gas commodity                         |       | —                                                    |       | (31,287 | ) | — |   | 4,389 | (d) | — |   |
| Other                                          |       | —                                                    |       | — |   | — |   | — |   | 134 | (b) |
| Total                                          |       | $                                                         | —     |   | $ | (31,287 | ) | $ | — |   | $ | 4,389 |   | $ | (388 | ) |

 

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| ** **                                     | ** ** | **Three Months Ended June 30, 2009**                          | ** ** |
|------------------------------------------------|------------|----------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Fair Value Changes Recognized  During the Period in:** | ** ** | **Pre-Tax Amounts Reclassified into Income  During the Period from:** | ** ** | **Pre-Tax Gains (Losses)** | ** ** |
| **(Thousands of Dollars)**           | ** ** | **Other  Comprehensive  Income (Losses)**                                         | ** ** | **Regulatory  Assets and  Liabilities** | ** ** | **Other  Comprehensive  Income** | ** ** | **Regulatory  Assets and  Liabilities** | ** ** | **Recognized  During the Period  in Income** | ** ** |
| **Derivatives designated as cash flow hedges** | ** ** | ** **                                                                             | ** ** | ** ** |   |   | ** ** | ** ** |   |   |   |
| Interest  rate                                 |       | $                                                                                      | (632       | ) | $ | — |   | $ | (593 | )(a) | $ | — |   | $ | — |   |
| Natural  gas commodity                         |       | —                                                                                 |       | (417 | ) | — |   | 409 | (d) | — |   |
| Vehicle  fuel and other commodity              |       | 944                                                                                    |       | — |   | 695 | (c) | — |   | — |   |
| Total                                          |       | $                                                                                      | 312        |   | $ | (417 | ) | $ | 102 |   | $ | 409 |   | $ | — |   |
|                                           |       |                                                                                   |       |   |   |   |   |   |   |   |   |
| **Other derivative instruments**               |       |                                                                                   |       |   |   |   |   |   |   |   |   |
| Trading  commodity                             |       | $                                                                                      | —     |   | $ | — |   | $ | — |   | $ | — |   | $ | 1,134 | (b) |
| Natural  gas commodity                         |       | —                                                                                 |       | 6,444 |   | — |   | — |   | — |   |
| Total                                          |       | $                                                                                      | —     |   | $ | 6,444 |   | $ | — |   | $ | — |   | $ | 1,134 |   |

 
| ** **                                     | ** ** | **Six Months Ended June 30, 2009**                            | ** ** |
|------------------------------------------------|------------|----------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Fair Value Changes Recognized  During the Period in:** | ** ** | **Pre-Tax Amounts Reclassified into Income  During the Period from:** | ** ** | **Pre-Tax Gains (Losses)** | ** ** |
| **(Thousands of Dollars)**           | ** ** | **Other  Comprehensive  Income (Losses)**                                         | ** ** | **Regulatory  Assets and  Liabilities** | ** ** | **Other  Comprehensive  Income** | ** ** | **Regulatory  Assets and  Liabilities** | ** ** | **Recognized  During the Period  in Income** | ** ** |
| **Derivatives designated as cash flow hedges** | ** ** | ** **                                                                             |       |   |   |   | ** ** | ** ** |   |   |   |
| Interest  rate                                 |       | $                                                                                      | (632       | ) | $ | — |   | $ | (1,185 | )(a) | $ | — |   | $ | — |   |
| Natural  gas commodity                         |       | —                                                                                 |       | (16,098 | ) | — |   | 66,109 | (d) | (22,243 | )(d) |
| Vehicle  fuel and other commodity              |       | 964                                                                                    |       | — |   | 1,486 | (c) | — |   | — |   |
| Total                                          |       | $                                                                                      | 332        |   | $ | (16,098 | ) | $ | 301 |   | $ | 66,109 |   | $ | (22,243 | ) |
|                                           |       |                                                                                   |       |   |   |   |   |   |   |   |   |
| **Other derivative instruments**               |       |                                                                                   |       |   |   |   |   |   |   |   |   |
| Trading  commodity                             |       | $                                                                                      | —     |   | $ | — |   | $ | — |   | $ | — |   | $ | 2,543 | (b) |
| Natural  gas commodity                         |       | —                                                                                 |       | (8,202 | ) | — |   | 15 | (d) | — |   |
| Total                                          |       | $                                                                                      | —     |   | $ | (8,202 | ) | $ | — |   | $ | 15 |   | $ | 2,543 |   |

 

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(a)       Recorded to interest charges

(b)      Recorded to electric operating revenues. Portions ofthese gains and losses are shared with electric customers throughmargin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)       Recorded to other O&M expenses.

(d)      Recorded to cost of natural gas sold and transported;these derivative settlement gains and losses are shared with natural gascustomers through purchased natural gas cost-recovery mechanisms, andreclassified out of income as regulatory assets and liabilities, asappropriate.

 

***Credit Related Contingent Features******—***Contract provisionsof the derivative instruments that PSCo enters into may require the posting ofcollateral or settlement of the contracts for various reasons, including ifPSCo is unable to maintain its credit ratings. If the credit ratings of PSCo were downgraded below investment grade,contracts underlying $3.4 million and $0.6 million of derivative instruments ina net liability position at June 30, 2010 and Dec. 31, 2009,respectively, would have required PSCo to post collateral or settle applicablecontracts, which would have resulted in payments to counterparties of $3.4million and $3.4 million, respectively. At June 30, 2010 and Dec. 31, 2009, there was no collateralposted on these specific contracts.

 

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PSCo’sderivative instruments are also subject to contract provisions that containadequate assurance clauses.  Theseprovisions allow counterparties to seek performance assurance, including cashcollateral, in the event that a given utility subsidiary’s ability to fulfillits contractual obligations is reasonably expected to be impaired.  PSCo had no collateral posted related toadequate assurance clauses in derivative contracts as of June 30, 2010 andDec. 31, 2009.

 

***Fair Value Measurements***

 

*ASC 820 Fair Value Measurements and Disclosures* provides a single definition of fair value and requires enhanceddisclosures about assets and liabilities measured at fair value.  A hierarchal framework for disclosing theobservability of the inputs utilized in measuring assets and liabilities atfair value is established by this guidance. The three levels in the hierarchy are as follows:

 

Level 1 — Quoted prices areavailable in active markets for identical assets or liabilities as of thereported date. The types of assets and liabilities included in Level 1 arehighly liquid and actively traded instruments with quoted prices.

 

Level 2 — Pricing inputs areother than quoted prices in active markets, but are either directly orindirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typicallyeither comparable to actively traded securities or contracts or priced withdiscounted cash flow or option pricing models using highly observable inputs.

 

Level 3 — Significant inputsto pricing have little or no observability as of the reported date.  The types of assets and liabilities includedin Level 3 are those valued with models requiring significant managementjudgment or estimation.

 

***Recurring Fair Value Measurements***

 

The following table presentsfor each of the hierarchy levels, PSCo’s assets and liabilities that aremeasured at fair value on a recurring basis at June 30, 2010:

 
| ** **                                  | ** ** | **June 30, 2010** | ** ** |
|---------------------------------------------|------------|------------------------|------------|
| ** **                                  | ** ** | **Fair Value**         | ** ** | **Fair Value** | ** ** | **Counterparty** | ** ** | ** ** | ** ** |
| **(Thousands of Dollars)**        | ** ** | **Level 1**       | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** | **Netting****(b)** | ** ** | **Total** | ** ** |
| **Current derivative assets**               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Derivatives designated as cash flow hedges: |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Vehicle fuel and other commodity            |       | $                      | —     |   | $ | 10 |   | $ | — |   | $ | 10 |   | $ | (10 | ) | $ | — |   |
| Other derivative instruments:               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Trading commodity                           |       | 1,768                  |       | 12,331 |   | 298 |   | 14,397 |   | (12,396 | ) | 2,001 |   |
| Natural gas commodity                       |       | —                 |       | 117 |   | — |   | 117 |   | (117 | ) | — |   |
| Total current derivative assets             |       | $                      | 1,768      |   | $ | 12,458 |   | $ | 298 |   | $ | 14,524 |   | $ | (12,523 | ) | 2,001 |   |
| Purchased power agreements (a)              |       |                   |       |   |   |   |   |   |   |   |   | 13,744 |   |
| Current derivative instruments valuation    |       |                   |       |   |   |   |   |   |   |   |   | $ | 15,745 |   |
| **Noncurrent derivative assets**            |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Derivatives designated as cash flow hedges: |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Vehicle fuel and other commodity            |       | $                      | —     |   | $ | 37 |   | $ | — |   | $ | 37 |   | $ | — |   | $ | 37 |   |
| Other derivative instruments:               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Trading commodity                           |       | —                 |       | 3,592 |   | 541 |   | 4,133 |   | (912 | ) | 3,221 |   |
| Total noncurrent derivative assets          |       | $                      | —     |   | $ | 3,629 |   | $ | 541 |   | $ | 4,170 |   | $ | (912 | ) | 3,258 |   |
| Purchased power agreements (a)              |       |                   |       |   |   |   |   |   |   |   |   | 78,988 |   |
| Noncurrent derivative instruments valuation |       |                   |       |   |   |   |   |   |   |   |   | $ | 82,246 |   |

 

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| ** **                                  | ** ** | **June 30, 2010** | ** ** |
|---------------------------------------------|------------|------------------------|------------|
| ** **                                  | ** ** | **Fair Value**         | ** ** | **Fair Value** | ** ** | **Counterparty** | ** ** | ** ** | ** ** |
| **(Thousands of Dollars)**        | ** ** | **Level 1**       | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** | **Netting****(b)** | ** ** | **Total** | ** ** |
| **Current derivative liabilities**          |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Derivatives designated as cash flow hedges: |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Vehicle fuel and other commodity            |       | $                      | —     |   | $ | 756 |   | $ | — |   | $ | 756 |   | $ | (10 | ) | $ | 746 |   |
| Other derivative instruments:               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Trading commodity                           |       | 1,263                  |       | 13,041 |   | 119 |   | 14,423 |   | (13,069 | ) | 1,354 |   |
| Natural gas commodity                       |       | —                 |       | 24,107 |   | — |   | 24,107 |   | (7,692 | ) | 16,415 |   |
| Total current derivative liabilities        |       | $                      | 1,263      |   | $ | 37,904 |   | $ | 119 |   | $ | 39,286 |   | $ | (20,771 | ) | 18,515 |   |
| Purchased power agreements (a)              |       |                   |       |   |   |   |   |   |   |   |   | 5,740 |   |
| Current derivative instruments valuation    |       |                   |       |   |   |   |   |   |   |   |   | $ | 24,255 |   |
| **Noncurrent derivative liabilities**       |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Other derivative instruments:               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Trading commodity                           |       | $                      | —     |   | $ | 2,614 |   | $ | 121 |   | $ | 2,735 |   | $ | (913 | ) | $ | 1,822 |   |
| Natural gas commodity                       |       | —                 |       | 72 |   | — |   | 72 |   | — |   | 72 |   |
| Total noncurrent derivative liabilities     |       | $                      | —     |   | $ | 2,686 |   | $ | 121 |   | $ | 2,807 |   | $ | (913 | ) | 1,894 |   |
| Purchased power agreements (a)              |       |                   |       |   |   |   |   |   |   |   |   | 42,543 |   |
| Noncurrent derivative instruments valuation |       |                   |       |   |   |   |   |   |   |   |   | $ | 44,437 |   |

 

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**(a)  **In 2003, as a result of implementing newguidance on the normal purchase exception for derivative accounting containedin ASC 815 Derivatives and Hedging, PSCo began recording several long-termpurchased power agreements at fair value due to accounting requirements relatedto underlying price adjustments. As these purchases are recovered throughnormal regulatory recovery mechanisms in the respective jurisdictions, thechanges in fair value for these contracts were offset by regulatory assets andliabilities. During 2006, PSCo qualified these contracts under the normalpurchase exception. Based on this qualification, the contracts are no longeradjusted to fair value and the previous carrying value of these contracts willbe amortized over the remaining contract lives along with the offsettingregulatory assets and liabilities.

**(b)  ***ASC 815 Derivatives andHedging* permitsthe netting of receivables and payables for derivatives and related collateralamounts when a legally enforceable master netting agreement exists between PSCoand a counterparty. A master netting agreement is an agreement between twoparties who have multiple contracts with each other that provides for the netsettlement of all contracts in the event of default on or termination of anyone contract.

 

PSCorecognizes transfers between levels as of the beginning of each period.  No transfers occurred between levels duringthe three and six months ended June 30, 2010.

 

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Thefollowing table presents for each of the hierarchy levels, PSCo’s assets andliabilities that are measured at fair value on a recurring basis at Dec. 31,2009:

 
| ** **                                  | ** ** | **Dec. 31, 2009** | ** ** |
|---------------------------------------------|------------|------------------------|------------|
| ** **                                  | ** ** | **Fair Value**         | ** ** | **Fair Value** | ** ** | **Counterparty** | ** ** | ** ** | ** ** |
| **(Thousands of Dollars)**        | ** ** | **Level 1**       | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** | **Netting****(b)** | ** ** | **Total** | ** ** |
| **Current derivative assets**               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Other derivative instruments:               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Trading commodity                           |       | $                      | —     |   | $ | 2,380 |   | $ | 986 |   | $ | 3,366 |   | $ | (2,120 | ) | $ | 1,246 |   |
| Natural gas commodity                       |       | —                 |       | 8,752 |   | — |   | 8,752 |   | 111 |   | 8,863 |   |
| Total current derivative assets             |       | $                      | —     |   | $ | 11,132 |   | $ | 986 |   | $ | 12,118 |   | $ | (2,009 | ) | 10,109 |   |
| Purchased power agreements (a)              |       |                   |       |   |   |   |   |   |   |   |   | 18,595 |   |
| Current derivative instruments valuation    |       |                   |       |   |   |   |   |   |   |   |   | $ | 28,704 |   |
| **Noncurrent derivative assets**            |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Derivatives designated as cash flow hedges: |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Vehicle fuel and other commodity            |       | $                      | —     |   | $ | 69 |   | $ | — |   | $ | 69 |   | $ | — |   | $ | 69 |   |
| Other derivative instruments:               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Trading commodity                           |       | —                 |       | 1,514 |   | 1,535 |   | 3,049 |   | 677 |   | 3,726 |   |
| Natural gas commodity                       |       | —                 |       | 476 |   | — |   | 476 |   | 248 |   | 724 |   |
| Total noncurrent derivative assets          |       | $                      | —     |   | $ | 2,059 |   | $ | 1,535 |   | $ | 3,594 |   | $ | 925 |   | 4,519 |   |
| Purchased power agreements (a)              |       |                   |       |   |   |   |   |   |   |   |   | 100,145 |   |
| Noncurrent derivative instruments valuation |       |                   |       |   |   |   |   |   |   |   |   | $ | 104,664 |   |
| ** **                                  | ** ** | ** **             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Current derivative liabilities**          |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Derivatives designated as cash flow hedges: |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Vehicle fuel and other commodity            |       | $                      | —     |   | $ | 1,338 |   | $ | — |   | $ | 1,338 |   | $ | — |   | $ | 1,338 |   |
| Other derivative instruments:               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Trading commodity                           |       | —                 |       | 3,555 |   | 834 |   | 4,389 |   | (2,589 | ) | 1,800 |   |
| Natural gas commodity                       |       | —                 |       | 6,090 |   | — |   | 6,090 |   | 111 |   | 6,201 |   |
| Total current derivative liabilities        |       | $                      | —     |   | $ | 10,983 |   | $ | 834 |   | $ | 11,817 |   | $ | (2,478 | ) | 9,339 |   |
| Purchased power agreements (a)              |       |                   |       |   |   |   |   |   |   |   |   | 8,946 |   |
| Current derivative instruments valuation    |       |                   |       |   |   |   |   |   |   |   |   | $ | 18,285 |   |
| **Noncurrent derivative liabilities**       |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Other derivative instruments:               |       |                   |       |   |   |   |   |   |   |   |   |   |   |
| Trading commodity                           |       | $                      | —     |   | $ | 489 |   | $ | 883 |   | $ | 1,372 |   | $ | 676 |   | $ | 2,048 |   |
| Natural gas commodity                       |       | —                 |       | 302 |   | — |   | 302 |   | 248 |   | 550 |   |
| Total noncurrent derivative liabilities     |       | $                      | —     |   | $ | 791 |   | $ | 883 |   | $ | 1,674 |   | $ | 924 |   | 2,598 |   |
| Purchased power agreements (a)              |       |                   |       |   |   |   |   |   |   |   |   | 46,989 |   |
| Noncurrent derivative instruments valuation |       |                   |       |   |   |   |   |   |   |   |   | $ | 49,587 |   |

 

----

**(a)  **In 2003, as a result of implementing newguidance on the normal purchase exception for derivative accounting containedin ASC 815 Derivatives and Hedging, PSCo began recording several long-termpurchased power agreements at fair value due to accounting requirements relatedto underlying price adjustments. As these purchases are recovered throughnormal regulatory recovery mechanisms in the respective jurisdictions, the changesin fair value for these contracts were offset by regulatory assets andliabilities. During 2006, PSCo qualified these contracts under the normalpurchase exception. Based on this qualification, the contracts are no longeradjusted to fair value and the previous carrying value of these contracts willbe amortized over the remaining contract lives along with the offsettingregulatory assets and liabilities.

**(b)  ***ASC815 Derivatives and Hedging* permits the netting ofreceivables and payables for derivatives and related collateral amounts when alegally enforceable master netting agreement exists between PSCo and acounterparty. A master netting agreement is an agreement between two partieswho have multiple contracts with each other that provides for the netsettlement of all contracts in the event of default on or termination of anyone contract.

 

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Themethods utilized to measure the fair value of commodity derivatives include theuse of forward prices and volatilities to value commodity forwards and options.  Levels are assigned to these fair valuemeasurements based on the significance of the use of subjective forward priceand volatility forecasts for commodities and locations with limitedobservability, or the significance of contractual settlements that extend toperiods beyond those readily observable on active exchanges or quoted bybrokers.

 

PSCocontinuously monitors the creditworthiness of the counterparties to itscommodity derivative contracts and assesses each counterparty’s ability toperform on the transactions set forth in the contracts.  Given this assessment, as well as anassessment of the impact of PSCo’s own credit risk when determining the fairvalue of commodity derivative liabilities, the impact of considering creditrisk was immaterial to the fair value of commodity derivative assets andliabilities presented in the consolidated balance sheets.

 

Thefollowing tables present the changes in Level 3 recurring fair valuemeasurements for the three and six months ended June 30, 2010 and 2009:

 
| ** **                                             | ** ** | **Three Months Ended June 30,** | ** ** |
|--------------------------------------------------------|------------|-----------------------------------------------------|------------|
| **(Thousands of Dollars)**                   | ** ** | **2010**                                            | ** ** | **2009** | ** ** |
| Balance at April 1                                |       | $                                                   | 331        |   | $ | 2,148 |   |
| Purchases and settlements, net                         |       | (113                                                | )          | (819 | ) |
| Transfers into Level 3                                 |       | —                                              |       | 588 |   |
| Gains recognized in earnings                           |       | 381                                                 |       | 291 |   |
| Gains recognized as regulatory assets and  liabilities |       | —                                              |       | 465 |   |
| Balance at June 30                                |       | $                                                   | 599        |   | $ | 2,673 |   |

 
| ** **                                             | ** ** | **Six Months Ended June 30,** | ** ** |
|--------------------------------------------------------|------------|---------------------------------------------------|------------|
| **(Thousands of Dollars)**                   | ** ** | **2010**                                          | ** ** | **2009** | ** ** |
| Balance at Jan. 1                                 |       | $                                                 | 804        |   | $ | (26 | ) |
| Purchases and settlements, net                         |       | (263                                              | )          | (1,172 | ) |
| Transfers into Level 3                                 |       | —                                            |       | 588 |   |
| Gains recognized in earnings                           |       | 58                                                |       | 2,755 |   |
| Gains recognized as regulatory assets and  liabilities |       | —                                            |       | 528 |   |
| Balance at June 30                                |       | $                                                 | 599        |   | $ | 2,673 |   |

 

Gains on Level 3 commodityderivatives recognized in earnings for the three months ended June 30,2010, include $0.3 million of net unrealized gains relating to commodityderivatives held at June 30, 2010. Gains on Level 3 commodity derivatives recognized in earnings for thethree and six months ended June 30, 2009, include $0.3 million and $2.8million of net unrealized gains relating to commodity derivatives held atJune 30, 2009. Gains on Level 3 commodity derivatives recognized inearnings for the six months ended June 30, 2010 included an immaterialamount of unrealized gains relating to commodity derivatives held atJune 30, 2010.  Realized andunrealized gains and losses on commodity trading activities are included inelectric revenues.  Realized andunrealized gains and losses on short-term wholesale activities reflect theimpact of regulatory recovery and are deferred as regulatory assets andliabilities.

 

**9.****             ****FinancialInstruments**

 

Theestimated fair values of PSCo’s recorded financial instruments are as follows:

 
| ** **                                | ** ** | **June 30, 2010** | ** ** | **Dec. 31, 2009** | ** ** |
|-------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                | ** ** | **Carrying**                | ** ** | ** **                  | ** ** | **Carrying** | ** ** | ** ** | ** ** |
| **(Thousands of Dollars)**      | ** ** | **Amount**                  | ** ** | **Fair Value**         | ** ** | **Amount** | ** ** | **Fair Value** | ** ** |
| Other investments                         |       | $                           | 8          |                        | $          | 8 |   | $ | 8 |   | $ | 8 |   |
| Long-term debt, including current portion |       | 2,832,364                   |       | 3,206,425                   |       | 2,828,952 |   | 3,050,249 |   |
|                                           |            |                             |            |                             |            |  |  |  |  |  |  |  |  |

 

Thefair value of cash and cash equivalents, notes and accounts receivable andnotes and accounts payable are not materially different from their carryingamounts.  The fair value of PSCo’s otherinvestments is estimated based on quoted market prices for those or similarinvestments.  The fair value of PSCo’slong-term debt is estimated based on the quoted market prices for the same orsimilar issues, or the current rates for debt of the same remaining maturitiesand credit quality.

 

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Thefair value estimates presented are based on information available to managementas of June 30, 2010 and Dec. 31, 2009.  These fair value estimates have not beencomprehensively revalued for purposes of these consolidated financialstatements since that date and current estimates of fair values may differsignificantly.

 

***Letters of Credit*****—**PSCo uses letters ofcredit, generally with terms of one year, to provide financial guarantees forcertain operating obligations.  At June 30,2010 and Dec. 31, 2009, there were $4.5 million and $4.6 million ofletters of credit outstanding, respectively. The contract amounts of these letters of credit approximate their fairvalue and are subject to fees determined in the marketplace.

 

**10.     Other Income, Net**

 

Other income (expense), net,consisted of the following:

 
| ** **                           | ** ** | **Three Months Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|--------------------------------------|------------|--------------------------------------|------------|------------------------------------|------------|
| **(Thousands of Dollars)** | ** ** | **2010**                             | ** ** | **2009**                           | ** ** | **2010** | ** ** | **2009** | ** ** |
| Interest income                      |       | $                                    | 741        |                               | $          | 600 |   | $ | 1,119 |   | $ | 1,067 |   |
| Other nonoperating income            |       | 428                                  |       | 2,099                              |       | 859 |   | 2,454 |   |
| Insurance policy (expense) income    |       | 157                                  |       | (587                               | )          | (96 | ) | (463 | ) |
| Other nonoperating expense           |       | —                               |       | —                             |       | — |   | (77 | ) |
| Other income, net                    |       | $                                    | 1,326      |                               | $          | 2,112 |   | $ | 1,882 |   | $ | 2,981 |   |

 

**11.     Segment Information**

 

PSCohas two reportable segments: regulated electric and regulated natural gas.  Commodity trading operations are not areportable segment and are included in the regulated electric segment.  All other revenues primarily include steamrevenue, appliance repair services and nonutility real estate activities.

 
| ** **                                                    | ** ** | **Regulated** | ** ** | **Regulated**        | ** ** | **All**    | ** ** | **Reconciling**  | ** ** | **Consolidated** | ** ** |
|---------------------------------------------------------------|------------|---------------|------------|----------------------|------------|------------|------------|------------------|------------|------------------|------------|
| **(Thousands of Dollars)**                          | ** ** | **Electric**  | ** ** | **Natural Gas** | ** ** | **Other**  | ** ** | **Eliminations** | ** ** | **Total**        | ** ** |
| **Three Months Ended June 30,  2010**                    |       |          |       |                 |       |       |       |             |       |             |       |
| Operating revenues from external customers                    |       | $             | 773,621    |                 | $          | 165,894    |       | $                | 7,781      |             | $          | — |   | $ | 947,296 |   |
| Intersegment revenues                                         |       | 55            |       | 32                   |       | —     |       | (87              | )          | —           |       |
| Total revenues                                                |       | $             | 773,676    |                 | $          | 165,926    |       | $                | 7,781      |             | $          | (87 | ) | $ | 947,296 |   |
| Net income                                                    |       | $             | 65,369     |                 | $          | 10,539     |       | $                | 1,777      |             | $          | — |   | $ | 77,685 |   |
|                                                          |       |          |       |                 |       |       |       |             |       |             |       |
| **Three Months Ended June 30, 2009** | ** ** | ** **    | ** ** | ** **           | ** ** | ** ** | ** ** | ** **       | ** ** | ** **       | ** ** |
| Operating revenues from external customers                    |       | $             | 588,467    |                 | $          | 173,494    |       | $                | 7,132      |             | $          | — |   | $ | 769,093 |   |
| Intersegment revenues                                         |       | 53            |       | 16                   |       | —     |       | (69              | )          | —           |       |
| Total revenues                                                |       | $             | 588,520    |                 | $          | 173,510    |       | $                | 7,132      |             | $          | (69 | ) | $ | 769,093 |   |
| Net income                                                    |       | $             | 44,749     |                 | $          | 11,616     |       | $                | 4,182      |             | $          | — |   | $ | 60,547 |   |

 
| ** **                                 | ** ** | **Regulated** | ** ** | **Regulated**        | ** ** | **All**   | ** ** | **Reconciling**  | ** ** | **Consolidated** | ** ** |
|--------------------------------------------|------------|---------------|------------|----------------------|------------|-----------|------------|------------------|------------|------------------|------------|
| **(Thousands of Dollars)**       | ** ** | **Electric**  | ** ** | **Natural Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total**        | ** ** |
| **Six Months Ended June 30,  2010**   |       |          |       |                 |       |      |       |             |       |             |       |
| Operating revenues from external customers |       | $             | 1,497,255  |                 | $          | 632,177   |       | $                | 20,561     |             | $          | — |   | $ | 2,149,993 |   |
| Intersegment revenues                      |       | 132           |       | 104                  |       | —    |       | (236             | )          | —           |       |
| Total revenues                             |       | $             | 1,497,387  |                 | $          | 632,281   |       | $                | 20,561     |             | $          | (236 | ) | $ | 2,149,993 |   |
| Net income (loss)                          |       | $             | 122,723    |                 | $          | 45,213    |       | $                | (6,001     | )                | $          | — |   | $ | 161,935 |   |
|                                       |       |          |       |                 |       |      |       |             |       |             |       |
| **Six Months Ended June 30,  2009**   |       |          |       |                 |       |      |       |             |       |             |       |
| Operating revenues from external customers |       | $             | 1,185,810  |                 | $          | 568,615   |       | $                | 17,146     |             | $          | — |   | $ | 1,771,571 |   |
| Intersegment revenues                      |       | 146           |       | 47                   |       | —    |       | (193             | )          | —           |       |
| Total revenues                             |       | $             | 1,185,956  |                 | $          | 568,662   |       | $                | 17,146     |             | $          | (193 | ) | $ | 1,771,571 |   |
| Net income                                 |       | $             | 87,060     |                 | $          | 42,855    |       | $                | 8,920      |             | $          | — |   | $ | 138,835 |   |

 

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**12.     Comprehensive Income**

 

The components of totalcomprehensive income are shown below:

 
| ** **                                                                              | ** ** | **Three Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------------------------------|------------|--------------------------------------|------------|
| **(Thousands of Dollars)**                                                    | ** ** | **2010**                             | ** ** | **2009** | ** ** |
| Net income                                                                              |       | $                                    | 77,685     |   | $ | 60,547 |   |
| Other comprehensive (loss) income:                                                      |       |                                 |       |   |   |
| After-tax net unrealized (losses) gains related to  derivatives accounted for as hedges |       | (123                                 | )          | 586 |   |
| After-tax net realized gains on derivative  transactions reclassified into earnings     |       | (166                                 | )          | (328 | ) |
| Other comprehensive (loss) income                                                       |       | (289                                 | )          | 258 |   |
| Comprehensive income                                                                    |       | $                                    | 77,396     |   | $ | 60,805 |   |

 
| ** **                                                                              | ** ** | **Six Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------------------------------|------------|------------------------------------|------------|
| **(Thousands of Dollars)**                                                    | ** ** | **2010**                           | ** ** | **2009** | ** ** |
| Net income                                                                              |       | $                                  | 161,935    |   | $ | 138,835 |   |
| Other comprehensive (loss) income:                                                      |       |                               |       |   |   |
| After-tax net unrealized (losses) gains related to  derivatives accounted for as hedges |       | (108                               | )          | 599 |   |
| After-tax net realized gains on derivative transactions  reclassified into earnings     |       | (289                               | )          | (206 | ) |
| Other comprehensive (loss) income                                                       |       | (397                               | )          | 393 |   |
| Comprehensive income                                                                    |       | $                                  | 161,538    |   | $ | 139,228 |   |

 

**13.    Benefit Plans and OtherPostretirement Benefits**

 

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

 

**Components of Net Periodic Benefit Cost**

 
| ** **                                                                                 | ** ** | **Three Months Ended June 30,** | ** ** |
|--------------------------------------------------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                                                                 | ** ** | **2010**                             | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| ** **                                                                                 | ** ** | ** **                           | ** ** | ** ** | ** ** | **Postretirement Health** | ** ** |
| **(Thousands of Dollars)**                                                       | ** ** | **Pension Benefits**                 | ** ** | **Care Benefits** | ** ** |
| Service cost                                                                               |       | $                                    | 18,956     |   | $ | 16,744 |   | $ | 965 |   | $ | 1,057 |   |
| Interest cost                                                                              |       | 41,853                               |       | 43,046 |   | 10,861 |   | 13,050 |   |
| Expected return on plan assets                                                             |       | (58,035                              | )          | (64,909 | ) | (7,131 | ) | (5,993 | ) |
| Amortization of transition obligation                                                      |       | —                               |       | — |   | 3,611 |   | 3,726 |   |
| Amortization of prior service cost (credit)                                                |       | 5,164                                |       | 6,154 |   | (1,233 | ) | (711 | ) |
| Amortization of net loss                                                                   |       | 13,134                               |       | 3,299 |   | 3,113 |   | 4,779 |   |
| Net periodic pension cost                                                                  |       | 21,072                               |       | 4,334 |   | 10,186 |   | 15,908 |   |
| Costs not recognized and additional cost  recognized due to the effects of regulation |       | (6,314                               | )          | (959 | ) | 973 |   | 973 |   |
| Net benefit cost recognized for financial  reporting                                       |       | $                                    | 14,758     |   | $ | 3,375 |   | $ | 11,159 |   | $ | 16,881 |   |
|                                                                                       |       |                                 |       |   |   |   |   |   |   |
| **PSCo:**                                                                                  |       |                                 |       |   |   |   |   |   |   |
| Net periodic benefit cost                                                                  |       | $                                    | 4,329      |   | $ | 3,163 |   | $ | 5,640 |   | $ | 10,565 |   |
| Additional cost recognized due to the effects of  regulation                               |       | —                               |       | — |   | 973 |   | 973 |   |
| Net benefit cost recognized for financial  reporting                                       |       | $                                    | 4,329      |   | $ | 3,163 |   | $ | 6,613 |   | $ | 11,538 |   |

 

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| ** **                                                                                 | ** ** | **Six Months Ended June 30,** | ** ** |
|--------------------------------------------------------------------------------------------|------------|------------------------------------|------------|
| ** **                                                                                 | ** ** | **2010**                           | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| ** **                                                                                 | ** ** |                                    | ** ** | ** ** | ** ** | **Postretirement Health** | ** ** |
| **(Thousands of Dollars)**                                                       | ** ** | **Pension Benefits**               | ** ** | **Care Benefits** | ** ** |
| Service cost                                                                               |       | $                                  | 36,574     |   | $ | 32,730 |   | $ | 2,003 |   | $ | 2,333 |   |
| Interest cost                                                                              |       | 82,505                             |       | 84,895 |   | 21,390 |   | 25,206 |   |
| Expected return on plan assets                                                             |       | (116,159                           | )          | (128,269 | ) | (14,265 | ) | (11,388 | ) |
| Amortization of transition obligation                                                      |       | —                             |       | — |   | 7,222 |   | 7,222 |   |
| Amortization of prior service cost (credit)                                                |       | 10,328                             |       | 12,309 |   | (2,466 | ) | (1,363 | ) |
| Amortization of net loss                                                                   |       | 24,158                             |       | 6,228 |   | 5,822 |   | 9,665 |   |
| Net periodic pension cost                                                                  |       | 37,406                             |       | 7,893 |   | 19,706 |   | 31,675 |   |
| Costs not recognized and additional cost  recognized due to the effects of regulation |       | (13,640                            | )          | (1,446 | ) | 1,946 |   | 1,946 |   |
| Net benefit cost recognized for financial  reporting                                       |       | $                                  | 23,766     |   | $ | 6,447 |   | $ | 21,652 |   | $ | 33,621 |   |
|                                                                                       |       |                               |       |   |   |   |   |   |   |
| **PSCo:**                                                                                  |       |                               |       |   |   |   |   |   |   |
| Net periodic benefit cost                                                                  |       | $                                  | 7,652      |   | $ | 6,924 |   | $ | 11,153 |   | $ | 20,139 |   |
| Additional cost recognized due to the effects of  regulation                               |       | —                             |       | — |   | 1,946 |   | 1,946 |   |
| Net benefit cost recognized for financial  reporting                                       |       | $                                  | 7,652      |   | $ | 6,924 |   | $ | 13,099 |   | $ | 22,085 |   |

 

**14.   PSCo Agreement toAcquire Assets from Calpine Development Holdings, Inc.**

 

In April 2010, PSCoreached an agreement with Riverside Energy Center, LLC and Calpine DevelopmentHoldings, Inc. to purchase the Rocky Mountain Energy Center and BlueSpruce Energy Center natural gas generation assets for $739 million.  The acquisition is expected to close in December 2010.

 

The Rocky Mountain EnergyCenter is a 621 MW combined cycle natural gas-fired power plant that begancommercial operations in 2004.  The BlueSpruce Energy Center is a 310 MW simple cycle natural gas-fired power plantthat began commercial operations in 2003. Both power plants currently provide energy and capacity to PSCo underpower purchase agreements, which were set to expire in 2013 and 2014.

 

The acquisition developedfrom the PSCo 2007 resource plan in which the assets were offered as part ofthe CPUC competitive bidding process. The offer was the least cost option for thermal resources to be acquiredunder the plan.

 

Theacquisition is subject to federal and state regulatory approvals includingapproval of the proposed recovery of costs. In June 2010, the Federal Trade Commission provided notice of theearly termination of the waiting period under Hart-Scott-Rodino.  In July 2010, FERC issued an orderapproving the acquisition.  The partiesmust obtain approval of the Federal Communications Commission for transfer ofradio licenses associated with the plants, which is the remaining federalregulatory approval.  The proceduralschedule for state regulatory approval by the CPUC is as follows:

 

·                  Intervenor answer testimony due Aug. 9,2010;

·                  Rebuttal and cross-answer testimony dueSept. 3, 2010;

·                  Hearings are Sept. 20 through Sept. 22, 2010;

·                  Deliberations due Oct. 18, 2010;

·                  Initial CPUC decision by Oct. 29, 2010;and

·                  Final decision expected on or before Dec. 1,2010.

 

**15.   Subsequent Event**—**Settlement with Provident Life & AccidentInsurance Company**

 

InJuly 2010, Xcel Energy, PSCo and PSRI (Xcel Energy) entered into a fulland final settlement agreement with Provident related to all claims asserted byXcel Energy against Provident in a lawsuit associated with Xcel Energy’sdiscontinued COLI program.  Under theterms of the settlement, Xcel Energy was paid $25 million by Provident andReassure America Life Insurance Company. Xcel Energy will record this settlement of $25 million in the thirdquarter of 2010.

 

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**Item 2 —MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS**

 

Discussionof financial condition and liquidity for PSCo is omitted per conditions setforth in general instructions H (1) (a) and (b) ofForm 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results ofoperations set forth in general instructions H (2) (a) ofForm 10-Q for wholly owned subsidiaries (reduced disclosure format).

 

**Financial Review**

 

The following discussion andanalysis by management focuses on those factors that had a material effect onPSCo’s financial condition, results of operations and cash flows during theperiods presented, or are expected to have a material impact in thefuture.  It should be read in conjunctionwith the accompanying unaudited consolidated financial statements and relatednotes to the consolidated financial statements. Due to the seasonality of PSCo’s electric and natural gas sales, suchinterim results are not necessarily an appropriate base from which to project annualresults.

 

**Forward-Looking Statements**

 

Exceptfor the historical statements contained in this report, the matters discussedin the following discussion and analysis are forward-looking statements thatare subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intendedto 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 of the date they are made, andwe do not undertake any obligation to update them to reflect changes that occurafter that date.  Factors that couldcause actual results to differ materially include, but are not limited to:general economic conditions, including the availability of credit and itsimpact on capital expenditures and the ability of PSCo and its subsidiaries toobtain financing on favorable terms; business conditions in the energyindustry; actions of credit rating agencies; competitive factors, including theextent and timing of the entry of additional competition in the markets servedby PSCo and its subsidiaries; unusual weather; effects of geopolitical events,including war and acts of terrorism; state, federal and foreign legislative andregulatory initiatives that affect cost and investment recovery, have an impacton rates or have an impact on asset operation or ownership or imposeenvironmental compliance conditions; structures that affect the speed anddegree to which competition enters the electric and natural gas markets; costsand other effects of legal and administrative proceedings, settlements,investigations and claims; environmental laws and regulations; actions ofaccounting regulatory bodies; the items described under Factors AffectingResults of Continuing Operations; and the other risk factors listed from timeto time by PSCo in reports filed with the SEC, including “Risk Factors” in Item1A of PSCo’s Form 10-K for the year ended Dec. 31, 2009, and Item 1Aand Exhibit 99.01 to this Quarterly Report on Form 10-Q for thequarter ended June 30, 2010.

 

**MarketRisks**

 

PSCois exposed to market risks, including changes in commodity prices and interestrates, as disclosed in Item 7A, Quantitative and Qualitative Disclosures AboutMarket Risk, in its Annual Report on Form 10-K for the year endedDec. 31, 2009.  Commodity price andinterest rate risks for PSCo are mitigated in most jurisdictions due tocost-based rate regulation.

 

Distressin the financial markets may impact the fair value of the debt and equitysecurities in pension and postretirement health care plan trusts, as well asPSCo’s ability to earn a return on short-term investments of excess cash.  As of June 30, 2010, there have been nomaterial changes to market risks from that set forth in PSCo’s Annual Report onForm 10-K for the year ended Dec. 31, 2009.

 

**Results ofOperations**

 

PSCo’s net income wasapproximately $161.9 million for the first six months of 2010, compared withapproximately $138.8 million for the first six months of 2009. The increase isprimarily due to new electric rates that went into effect in July 2009 andduring 2010 and electric sales growth. The increase was partially offset by higher operating and maintenanceexpenses and depreciation.

 

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**Electric Revenues and Margin**

 

Electricfuel and purchased power expenses tend to vary with changing retail andwholesale sales requirements and unit cost changes in fuel and purchasedpower.  Due to fuel and purchased energycost-recovery mechanisms for customers, fluctuations in these costs do notmaterially affect electric margin.** **The following tables detail theelectric revenues and margin:

 
| ** **                        | ** ** | **Six Months Ended June 30,** | ** ** |
|-----------------------------------|------------|------------------------------------|------------|
| **(Millions of Dollars)**         | ** ** | **2010**                           | ** ** | **2009** | ** ** |
| Electric revenues                 |       | $                                  | 1,497      |   | $ | 1,186 |   |
| Electric fuel and purchased power |       | (782                               | )          | (608 | ) |
| Electric margin                   |       | $                                  | 715        |   | $ | 578 |   |

 

The following summarizes the components of thechanges in electric revenues and margin for the six months ended June 30:

 

***Electric Revenues***

 
| **(Millions of Dollars)**                       | ** ** | **2010 vs. 2009** | ** ** |
|-----------------------------------------------------------|------------|-----------------------------|------------|
| Fuel and purchased power cost recovery                    |       | $                           | 153        |   |
| Retail rate increase                                      |       | 100                         |       |
| Trading                                                   |       | 22                          |       |
| DSM revenue and incentive (partially offset by  expenses) |       | 14                          |       |
| Estimated impact of weather                               |       | 8                           |       |
| Retail sales increase (excluding weather impact)          |       | 6                           |       |
| Other, net                                                |       | 8                           |       |
| Total increase in electric revenues                       |       | $                           | 311        |   |

 

***Electric Margin***

** **
| **(Millions of Dollars)**                                 | ** ** | **2010 vs. 2009** | ** ** |
|-----------------------------------------------------------|------------|-------------------|------------|
| Retail rate increase                                      |       | $                 | 100        |   |
| DSM revenue and incentive (partially offset by  expenses) |       | 14                |       |
| Estimated impact of weather                               |       | 8                 |       |
| Retail sales increase (excluding weather impact)          |       | 6                 |       |
| Firm wholesale                                            |       | 6                 |       |
| Trading                                                   |       | 1                 |       |
| Other, net                                                |       | 2                 |       |
| Total increase in electric margin                         |       | $                 | 137        |   |

 

**Natural Gas Revenues and Margin**

 

Thecost of natural gas tends to vary with changing sales requirements and unitcost of natural gas purchases.  PSCo hasa GCA mechanism for natural gas sales, which recognizes the majority of theeffects of changes in the cost of natural gas purchased for resale and adjustsrevenues to reflect such changes in costs upon request by PSCo.  Therefore, fluctuations in the cost ofnatural gas have little effect on natural gas margin.  The following tables detail the natural gasrevenues and margin:

 

Thefollowing summarizes the components of the changes in natural gas revenues andmargin for the six months ended June 30:

 
| ** **                               | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------|------------|------------------------------------|------------|
| **(Millions of Dollars)**                | ** ** | **2010**                           | ** ** | **2009** | ** ** |
| Natural gas revenues                     |       | $                                  | 632        |   | $ | 569 |   |
| Cost of natural gas sold and transported |       | (423                               | )          | (375 | ) |
| Natural gas margin                       |       | $                                  | 209        |   | $ | 194 |   |

 

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***Natural Gas Revenues***

 
| **(Millions of Dollars)**                                 | ** ** | **2010 vs. 2009** | ** ** |
|-----------------------------------------------------------|------------|-------------------|------------|
| Purchased natural gas cost recovery                       |       | $                 | 48         |   |
| Estimated impact of weather                               |       | 9                 |       |
| DSM revenue and incentive (partially offset by  expenses) |       | 2                 |       |
| Other, net                                                |       | 4                 |       |
| Total increase in natural gas revenues                    |       | $                 | 63         |   |

 

***Natural Gas Margin***

 
| **(Millions of Dollars)**                                 | ** ** | **2010 vs. 2009** | ** ** |
|-----------------------------------------------------------|------------|-------------------|------------|
| Estimated impact of weather                               |       | $                 | 9          |   |
| DSM revenue and incentive (partially offset by  expenses) |       | 2                 |       |
| Other, net                                                |       | 4                 |       |
| Total increase in natural gas margin                      |       | $                 | 15         |   |

 

**Non-FuelOperating Expense and Other Items**

 

***Other Operatingand Maintenance Expenses****—*Other operating and maintenance expenses increased by approximately$21.2 million, or 7.0 percent, for the first six months of 2010, compared withthe first six months of 2009.  The followingsummarizes the components of the changes for the six months ended June 30:

 
| **(Millions of Dollars)**                                   | ** ** | **2010 vs. 2009** | ** ** |
|-------------------------------------------------------------|------------|-------------------|------------|
| Higher plant generation costs                               |       | $                 | 9          |   |
| Higher labor costs                                          |       | 3                 |       |
| Higher contract labor costs                                 |       | 3                 |       |
| Higher information technology costs                         |       | 3                 |       |
| Lower employee benefit costs                                |       | (3                | )          |
| Other, net                                                  |       | 6                 |       |
| Total increase in other operating and maintenance  expenses |       | $                 | 21         |   |

** **

·                     Higher plantgeneration costs are primarily attributable to a higher level of scheduledmaintenance and overhaul work.

 

***Demand Side Management (DSM) Program Expenses****—*****DSM program expensesincreased by approximately $17.6 million, or 35.4 percent, for the first sixmonths of 2010, compared with the first six months of 2009.  The higher expense is attributable to theongoing expansion of such programs as designed, in part, to meet certainregulatory commitments in Colorado.

 

***Depreciation and Amortization****—*Depreciation and amortization increased byapproximately $10.7 million, or 8.5 percent, for the first six months of 2010,compared with the first six months of 2009. The increase is primarily due to planned system expansion.

 

***Taxes (Other Than Income Taxes)***— Taxes (other than income taxes) increased by approximately $4.9million, or 10.7 percent, for the first six months of 2010, compared with thefirst six months of 2009.  The increaseis primarily due to an increase in property taxes.

 

***Allowance for Funds Used DuringConstruction, Equity and Debt (AFUDC)*****— AFUDCdecreased by approximately $19.8 million for the first six months of 2010,compared with the first six months of 2009. The decrease was partially due to recovery of Comanche Unit 3 financingcosts through base rates and lower AFUDC rates.

 

***Interest Charges***—******Interest chargesincreased by approximately $5.3 million, or 6.5 percent, for the first sixmonths of 2010, compared with the first six months of 2009, primarily due toincreased long-term borrowings.

 

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***Income Taxes —***Income taxexpense increased by $50.3 million for the first six months of 2010, comparedwith the first six months of 2009.  The increase in income tax expense wasprimarily due to an increase in pretax income, a write-off of tax benefitspreviously recorded for Medicare Part D subsidies, and an adjustment atPSRI related to the COLI Tax Court proceedings.  For further information,see Note 4 to the consolidated financial statements.  The effective taxrate was 42.5 percent for the first six months of 2010, compared with 33.3percent for the same period in 2009.  The higher effective tax rate forthe first six months of 2010 was primarily due to a higher forecasted annualeffective tax rate and the write-off of tax benefit for Medicare Part Dsubsidies and the adjustment at PSRI in 2010.  Without these two charges,the effective tax rate for the first six months of 2010 would have been 36.2percent.  The higher forecasted annualeffective tax rate for 2010 as compared to 2009 was primarily due to reducedplant-related deductions and the elimination of tax benefits for Medicare Part Dsubsidies in 2010, partially offset by increased state unitary tax benefit in2010.

 

**Factors Affecting Results of Continuing Operations**

 

**PublicUtility Regulation**

 

***PSCo Resource Plan***— InOctober 2009, the CPUC approved the acquisitions of the resourcesidentified in the bid evaluation report filed with the CPUC in August 2009.  With minor modification, the CPUC adoptedPSCo’s preferred plan, which includes an incremental 900 MW of additionalintermittent renewable energy resources (wind and photovoltaic (PV) solar) andapproximately 280 MW of “new technology” renewable energy sources.  The CPUC approved the negotiation ofpurchased power contracts from a pool of PV solar bidders, rather thandesignating specific bidders.  The CPUCapproved the selection of about 900 MW of traditional gas-fired resources.  The CPUC preferred that PSCo file its nextresource plan in the normal course of business in the fall of 2011 rather thanmaking an interim filing in 2010.  TheColorado OCC has appealed the CPUC’s approval of the resource plan to DenverDistrict Court, arguing that the CPUC erred in approving a portfolio where PSCoobtained an ownership interest in gas-fired generation and that this portfoliowill not result in just and reasonable rates.

 

InMay 2010, PSCo filed for approval to purchase approximately 900 MW ofgas-fired generation from subsidiaries of Calpine Corporation consistent withthe CPUC approved portfolio.  PSCo hasthe ability to terminate the transaction if conditions on regulatory approvalare unacceptable.  The purchase issubject to federal and state regulatory approvals including approval of theproposed recovery of costs.  In June 2010,the Federal Trade Commission provided notice of the early termination of thewaiting period for premerger review.  In July 2010,the FERC issued an order approving the acquisition.  The parties must obtain approval of theFederal Communications Commission for transfer of radio licenses associatedwith the plants, which is the remaining federal regulatory approval.  The application includes prompt recovery ofrevenue requirements associated with the transaction.  The matter has been referred to an ALJ andthe ALJ has set a schedule to resolve the matter by the target closing date of Dec. 1,2010.  Intervenor testimony is due Aug. 9,2010.

 

InJune 2010, PSCo filed an amendment to the approved resource plan to reducethe amount of solar resources (combination of PV solar and new technologyrenewable energy resources) acquired to an amount that could be accommodatedusing existing transmission facilities. This change was necessitated by delays in the certificate of publicconvenience and necessity process to develop a significant new transmissionproject that would allow access to the Colorado’s best solar resource.  The request to reduce solar acquisitions upto 185 MW will ensure that PSCo will not be subject to significant curtailmentpayments due to use of non-firm transmission. The matter is pending before the CPUC.

 

***San Luis Valley-Calumet-ComancheUnit 3 Transmission Project*****—** PSCo and Tri-StateGeneration and Transmission Association filed a joint application with the CPUCfor a certificate of need and public convenience in May 2009.  The project consists of four components ofboth 230 KV and 345 KV line and substation construction.  The line is intended to assist in bringing solarpower in the San Luis Valley to load.  Asnoted in the aforementioned PSCo Resource Plan, the line was originallyexpected to be placed in-service in 2013;however, that appears unlikely now due to delays in the siting andpermitting of the line.  Severallandowners are opposing this transmission line, including two largeranches.  Hearings before an ALJ wereconducted in February 2010, and additionalhearings were held on July 26 and 30, 2010.

 

***RES***— In March 2010,Colorado enacted a law that increases the RES to 30 percent of energy sales tobe supplied by renewable energy for PSCo and removes the solar standard andreplaces it with a distributed generation standard.  Within the distributed generation standard, atleast one-half of the distributed generation must be retail distributedgeneration, i.e., generation that is on customer premises behind the customermeter.  The law requires that PSCogenerate or cause to be generated electricity from renewable resourcesequaling:

 

·                  At least 12 percent of its retail sales forthe years 2011 through 2014;

·                  At least 20 percent of its retail sales forthe years 2015 through 2019; and

·                  At least 30 percent of its retail sales forthe years 2020 and thereafter.

 

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Inaddition, distributed generation must equal:

 

·                  At least 1percent of retail sales in the years 2011 and 2012 and 1.25 percent of retailsales in the years 2013 and 2014;

·                  At least 1.75percent of retail sales in the years 2015 and 2016 and 2 percent of retailsales in the years 2017, 2018 and 2019; and

·                  At least 3percent of retail sales in the years 2020 and thereafter.

 

TheCPUC has discretion to review the reasonableness of the increase in thedistributed generation percentage in 2014. The CPUC commenced a rulemaking in April 2010 to incorporatechanges from the 2010 RES into CPUC rules. PSCo believes that its forecasted plan acquisitions of renewableresources only need minor modification to comply with the new standard.

 

InJune 2010, Colorado enacted “Solar Garden” legislation that allows PSCocustomers to purchase shares of a larger solar facility instead of puttingsolar panels on their rooftops.  In June 2010,the CPUC indicated that it would initiate a separate rulemaking to accommodatethis new law.  The rulemaking is expectedto commence prior to October 2010. In PSCo’s 2011 RES compliance plan, PSCo is expected to include itsinitial Solar Garden product offering.

 

***Colorado Clean Air-Clean Jobs Act***— The ColoradoClean Air-Clean Jobs Act (the Act) was signed into law in April 2010.  TheAct requires PSCo to file a comprehensive plan with the CPUC by Aug. 15,2010 to reduce annual emissions of NOx by at least 70 to 80 percent from 2008levels from the coal-fired generation identified in the plan.  The plan must consider emission controls,plant refueling, or plant retirement of at least 900 MW of coal-firedgenerating units in Colorado by Jan. 1, 2018.  The legislation requires PSCo to preparecomparative evaluations of different scenarios, including a scenario whereemission controls are installed on the coal plants and a scenario where coalplants are repowered or replaced by natural gas by Jan. 1, 2015.  The legislation further encourages PSCo tosubmit long-term gas contracts to the CPUC for approval.  If approved, PSCo would be entitled torecover the costs it incurs under these long-term gas contracts, notwithstandingany change in the market price of natural gas during the term of the contract.

 

Pursuantto the Act, PSCo is entitled to fully recover the costs that it prudentlyincurs in executing an approved emission reduction plan and is allowed a returnon CWIP on plan investments.  Inaddition, if early action is taken to retire or convert units to natural gas,and PSCo shows that the costs of the plan would contribute to any earningsdeficiency, additional relief, including a more comprehensive rider to recover otherplant costs such as depreciation and O&M expense, or a multi-year rate planare allowed.  The Act permits the CPUC to consider interim rate increases after Jan. 1,2012 while the rate filing is pending.

 

In June, CPUC ordered PSCo to file certain informationso that it could process the August filing in a timely manner.  PSCo has filed a significant amount ofinformation with the CPUC and in July 2010 provided a list of thedifferent scenarios it has proposed to model for its plan filing.  Also in July 2010, the CPUC rejected amotion by Colorado Independent Energy Association, representing certainindependent power producers that would require PSCo to consider purchasingreplacement capacity under the plan from these entities.  See additional informationset forth in Note 6 to the consolidated financial statements in this QuarterlyReport on Form 10-Q.

 

***SmartGridCity******TM******Certificate of Public Convenienceand Necessity (CPCN)***— As part of the recent PSCo electric ratecase, the CPUC included recovery of the revenue requirements associated withthe capital and O&M costs incurred by PSCo to develop and operateSmartGridCityTM subject torefund and ordered PSCo to file for a CPCN for that project.  PSCo filed that application on March 10,2010 along with direct testimony.  Answertestimony was received from parties on July 19, 2010.  The CPUC staff, the OCC, and the Governor’sEnergy Office (GEO) support the issuance of the CPCN and cost recovery of theamounts included in the rate case.  Twoparties, Leslie Glustrom and Arapahope Community Team (ACT) oppose issuance ofthe CPCN.  PSCo is currently recoveringthe revenue requirements on $42 million of capital costs and $4 million inannual O&M costs. The OCC and Glustrom recommended partial recovery ofcapital costs while ACT recommended no recovery. PSCo’s rebuttal testimony isdue in early August 2010. Separately, PSCo has received approval to conduct both a pricing and anin-home device pilot program to evaluate the customer response to price signalsenabled by the smart technology.

 

**Summary of Recent Federal Regulatory Developments**

 

TheFERC has jurisdiction over rates for electric transmission service ininterstate commerce and electricity sold at wholesale, hydro facilitylicensing, natural gas transportation, accounting practices, and certain otheractivities of Xcel Energy’s utility subsidiaries, including enforcement ofNorth American Electric Reliability Corporation (NERC) mandatory electricreliability standards.  State and localagencies have jurisdiction over many of PSCo’s utility activities, includingregulation of retail rates and environmental matters.  See additional discussion in the summary ofrecent federal regulatory developments and public utility regulation sectionsof the PSCo Annual Report on Form 10-K for the year ended Dec. 31,2009.  In addition to the mattersdiscussed below, see Note 5 to the consolidated financial statements for adiscussion of other regulatory matters.

 

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***ElectricReliability Standards Compliance***

 

ComplianceAudits

 

In 2008, PSCo wassubject to an audit of its compliance with the NERC and regional reliabilitystandards by the Western Electricity Coordinating Council (WECC), the NERCregional entity for the PSCo system.  OnOct. 31, 2008, the WECC auditors issued their final audit report on PSCo’scompliance with electric reliability standards. The report found a possible violation of one reliability standardrelated to relay maintenance.

 

In2008, PSCo filed self-reports with the WECC relating to failure to completecertain generation station battery tests, relay maintenance intervals andrecord keeping associated with certain critical infrastructure protectionstandards.  In 2009, PSCo reachedagreement with the WECC that would resolve the open 2008 audit finding and the2008 self reports by payment of a non-material penalty.  In February 2010, PSCo executed adefinitive settlement agreement.  Thissettlement agreement is pending approval by the NERC and will also need to beapproved by the FERC.

 

InMarch 2010, the WECC conducted a compliance spot check to evaluatecompliance with the NERC Critical Energy Infrastructure (CIP) standards, whichwere effective July 1, 2008.  Thedraft non-public report issued in July 2010 found that the Xcel Energyutility subsidiaries may not be in compliance with several of the CIPstandards.  Xcel Energy, the parentcompany of PSCo, provided comments on the draft reporting, disagreeing withmany of the conclusions and is awaiting issuance of the final auditreport.  The CIP spot check reportfindings related to PSCo will then proceed to the MRO enforcement process.  In July 2010, the WECC issued a Noticeof Alleged Violation (NOAV) finding alleged violations of two CIP standardsfrom the spot check, plus two unrelated self-reported violations, and proposinga non-material penalty.  The PSCoresponse to the NOAV will be submitted in August 2010.  To what extent the WECC or NERC may seek toimpose penalties for other potential CIP standards violations is unknown atthis time.

 

**Item 4****—****CONTROLS AND PROCEDURES**

 

**Disclosure Controls and Procedures**

 

PSComaintains a set of disclosure controls and procedures designed to ensure thatinformation required to be disclosed in the reports that it files or submitsunder the Securities Exchange Act of 1934 is recorded, processed, summarized,and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls andprocedures ensure that information required to be disclosed is accumulated andcommunicated to management, including the chief executive officer (CEO) andchief financial officer (CFO), allowing timely decisions regarding requireddisclosure.  As of June 30, 2010,based on an evaluation carried out under the supervision and with theparticipation of PSCo’s management, including the CEO and CFO, of theeffectiveness of its disclosure controls and the procedures, the CEO and CFOhave concluded that PSCo’s disclosure controls and procedures were effective.

 

**Internal Control Over Financial Reporting**

 

No change in PSCo’s internalcontrol over financial reporting has occurred during the most recent fiscalquarter that has materially affected, or is reasonably likely to materiallyaffect, PSCo’s internal control over financial reporting.

 

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**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.

 

**AdditionalInformation**

 

See Notes 5 and 6 of thefinancial statements in this Quarterly Report on Form 10-Q for furtherdiscussion of legal proceedings, including Regulatory Matters and Commitmentsand Contingent Liabilities, which are hereby incorporated by reference.  Reference also is made to Item 3 and Notes 14and 15 of PSCo’s consolidated financial statements in its Annual Report onForm 10-K for the year ended Dec. 31, 2009 for a description ofcertain legal proceedings presently pending.

 

**Item 1A — Risk Factors**

 

Except to the extent updated or described below,PSCo’s risk factors are documented in Item 1A of Part I of its AnnualReport on Form 10-K for the year ended Dec. 31, 2009, which isincorporated herein by reference.

 

***We may be subject to legislative andregulatory responses to climate change, with which compliance could bedifficult and costly.***

 

Legislative and regulatory responses related toclimate change and new interpretations of existing laws through climate changelitigation create financial risk. Increased public awareness and concern may result in more regionaland/or federal requirements to reduce or mitigate the effects of GHGs. Numerousstates have announced or adopted programs to stabilize and reduce GHG, andfederal legislation has been introduced in both houses of Congress.  Our electric generating facilities are likelyto be subject to regulation under climate change laws introduced at either thestate or federal level within the next few years.

 

The EPA has taken steps to regulate GHGs under theCAA.  On Dec. 7, 2009, the EPAissued a finding that GHG emissions endanger public health and welfare, andthat motor vehicle emissions contribute to the GHGs in the atmosphere.  This endangerment finding creates a mandatoryduty for the EPA to regulate GHGs from light duty motor vehicles.  The EPA finalized GHG efficiency standardsfor light duty vehicles in spring 2010 and has promulgated permittingrequirements for GHGs for large new and modified stationary sources, such aspower plants.  These regulations willbecome applicable in 2011.  We are alsocurrently a party to climate change lawsuits and may be subject to additionalclimate change lawsuits, including lawsuits similar to those described in Note 6,Commitments and Contingent Liabilities, in the notes to the consolidatedfinancial statements.  While we believesuch lawsuits are without merit, an adverse outcome in any of these cases couldrequire substantial capital expenditures that cannot be determined at this timeand could possibly require payment of substantial penalties or damages.  Defense costs associated with such litigationcan also be significant.  Such paymentsor expenditures could affect results of operations, cash flows, and financialcondition if such costs are not recovered through regulated rates.

 

Many of the federal and state climate changelegislative proposals, such as the American Clean Energy andSecurity Act and the proposedKerry-Lieberman legislation, use a cap and trade policy structure, in which GHGemissions from a broad cross-section of the economy would be subject to anoverall cap.  Under the proposals, thecap becomes more stringent with the passage of time.  The proposals establish mechanisms for GHGsources, such as power plants, to obtain “allowances” or permits to emit GHGsduring the course of a year.  The sourcesmay use the allowances to cover their own emissions or sell them to othersources that do not hold enough emission allowances for their own operations.  Proponents of the cap and trade policybelieve it will result in the most cost effective, flexible emissionreductions.  There are manyuncertainties, however, regarding when and in what form climate changelegislation will be enacted.  The impactof legislation and regulations, including a cap and trade structure, on us andour customers will depend on a number of factors, including whether GHG sourcesin multiple sectors of the economy are regulated, the overall GHG emissions caplevel, the degree to which GHG offsets are allowed, the allocation of emissionallowances to specific sources and the indirect impact of carbon regulation onnatural gas and coal prices.  While we donot have operations outside of the United States, any international treaties oraccords could have an impact to the extent they lead to future federal or stateregulations.  Another important factor isour ability to recover the costs incurred to comply with any regulatoryrequirements that are ultimately imposed. We may not recover all costs related to complying with regulatoryrequirements imposed on us.  If ourregulators do not allow us to recover all or a part of the cost of capitalinvestment or the O&M costs incurred to comply with the mandates, it couldhave a material adverse effect on our results of operations.

 

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**Item 6**—**Exhibits**

 

----

*  Indicates incorporation by reference

†  Certainportions of this agreement have been omitted pursuant to a request forconfidential treatment and have been filed separately with the SEC.

 
| 2.01* † |   | Purchase and Sale  Agreement by and between Riverside Energy Center, LLC and Calpine Development  Holdings, Inc., as Sellers, and PSCo, as Purchaser, dated as of  April 2, 2010 (excluding certain schedules and exhibits referred to in  the agreement, as amended, which the Registrant agrees to furnish  supplementally to the SEC upon request). (Exhibit 2.01 to Form 10-Q  of Xcel Energy (file no. 001-03034) for the quarter ended June 30,  2010). |
|--------------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.01*        |   | Amended and Restated  Articles of Incorporation dated July 15, 1998 (Form 10-K,  Dec. 31, 1998, Exhibit 3(a)(1)).                                                                                                                                                                                                                                                                                                                                                  |
| 3.02*        |   | By-laws dated  Nov. 20, 1997 (For 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).                                                                                                                                                                                                                                                                                                                                                                                                |
| 10.01*       |   | Xcel  Energy Executive Annual Incentive Award Plan (as amended and restated  effective Feb. 17, 2010) (incorporated by reference to Appendix A to  Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no.  001-03034) dated April 6, 2010).                                                                                                                                                                                                                  |
| 10.02*       |   | Xcel  Energy 2005 Long-Term Incentive Plan (as amended and restated effective  Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A,  Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated  April 6, 2010).                                                                                                                                                                                                                          |
| 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 authorized.

 
| ** **           | **Public  Service Company of Colorado**     |
|----------------------|---------------------------------------------|
|                 | (Registrant)                                |
|                 |                                        |
| August 2,  2010 | /s/  TERESA S. MADDEN                       |
|                 | Teresa  S. Madden                           |
|                 | Vice  President and Controller              |
|                 |                                        |
|                 | /s/  DAVID M. SPARBY                        |
|                 | David  M. Sparby                            |
|                 | Vice  President and Chief Financial Officer |

 

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