** **

**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

** **

**FORM 10-Q**

** **
| **x**                                                                                               | **QUARTERLY REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**  |
|-----------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------|
|                                                                                                |
| **For  the quarterly period ended Sept. 30, 2006**                                                  |
| ** **                                                                                          |
| **or**                                                                                              |
|                                                                                                |
| **o**                                                                                               | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
|                                                                                                |
| **For  the transition period from            to** |

 

**Commission File Number: 001-3280**

 

**Public Service Company ofColorado**

(Exact name ofregistrant as specified in its charter)

 

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

 

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

 

Indicate by check mark whether the registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days. Yes  x   No o

 

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer (asdefined in Rule 12b-2 of the Exchange Act). o Largeaccelerated filer o Acceleratedfiler x Non-accelerated filer

 

Indicate by check mark whether the registrant is ashell company (as defined in Rule 12b-2 of the Exchange Act). Yes  o   No  x

 

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

 

| **Class**                      | ** ** | **Outstanding at Oct  30, 2006** |
|--------------------------------|------------|-------------------------------------------------|
| Common Stock, $0.01 par  value |       | 100 shares                                      |

 

Public Service Company of Colorado meets the conditionsset forth in General Instruction H (1)(a) and (b) of Form 10-Q and is thereforefiling this Form 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                                                                       |   |
| Item 2.   | Management’s  Discussion and Analysis of Financial Condition and Results of Operations |   |
| Item 4    | Controls and  Procedures                                                                    |   |
|      | **PART II - OTHER  INFORMATION**                                                            |   |
| Item 1.   | Legal Proceedings                                                                           |   |
| Item  1A. | Risk  Factors                                                                               |   |
| Item  6.  | Exhibits                                                                                    |   |

 

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

 

2

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**PART I. FINANCIAL INFORMATION**

** **

**Item 1. Consolidated Financial Statements**

** **

**PUBLIC SERVICE CO.OF COLORADO AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)(Thousands of dollars)**

** **
| ** **                                                                                                  | ** ** | **Three Months Ended Sept. 30,** | ** ** | **Nine Months Ended Sept. 30,** | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                                                  | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Operating  revenues**                                                                                     |       |                                                 |       |                                                |       |   |   |   |   |
| Electric utility                                                                                            |       | $                                                    | 644,445    |                                                | $          | 654,199 |   | $ | 1,916,376 |   | $ | 1,807,470 |   |
| Natural gas  utility                                                                                        |       | 142,422                                              |       | 122,427                                             |       | 885,340 |   | 774,277 |   |
| Steam and other                                                                                             |       | 6,857                                                |       | 6,097                                               |       | 26,264 |   | 23,461 |   |
| Total operating  revenues                                                                                   |       | 793,724                                              |       | 782,723                                             |       | 2,827,980 |   | 2,605,208 |   |
|                                                                                                        |       |                                                 |       |                                                |       |   |   |   |   |
| **Operating  expenses**                                                                                     |       |                                                 |       |                                                |       |   |   |   |   |
| Electric fuel  and purchased power                                                                          |       | 391,011                                              |       | 394,583                                             |       | 1,157,636 |   | 1,062,300 |   |
| Cost of natural  gas sold and transported                                                                   |       | 78,062                                               |       | 70,032                                              |       | 654,607 |   | 566,881 |   |
| Cost of sales —  steam and other                                                                       |       | 3,203                                                |       | 2,889                                               |       | 14,405 |   | 13,275 |   |
| Other operating  and maintenance expenses                                                                   |       | 140,486                                              |       | 133,189                                             |       | 418,791 |   | 395,495 |   |
| Depreciation and  amortization                                                                              |       | 61,375                                               |       | 60,195                                              |       | 179,895 |   | 179,114 |   |
| Taxes (other  than income taxes)                                                                            |       | 20,083                                               |       | 22,562                                              |       | 64,707 |   | 67,226 |   |
| Total operating  expenses                                                                                   |       | 694,220                                              |       | 683,450                                             |       | 2,490,041 |   | 2,284,291 |   |
|                                                                                                        |       |                                                 |       |                                                |       |   |   |   |   |
| **Operating  income**                                                                                       |       | 99,504                                               |       | 99,273                                              |       | 337,939 |   | 320,917 |   |
|                                                                                                        |       |                                                 |       |                                                |       |   |   |   |   |
| Interest and  other income (expense) - net (see Note 7)                                                     |       | (4,043                                               | )          | (2,207                                              | )          | (10,513 | ) | (8,181 | ) |
| Allowance for  funds used during construction - equity                                                      |       | 1,052                                                |       | 13                                                  |       | 1,315 |   | 1,243 |   |
|                                                                                                        |       |                                                 |       |                                                |       |   |   |   |   |
| **Interest  charges and financing costs**                                                                   |       |                                                 |       |                                                |       |   |   |   |   |
| Interest charges  — includes other financing costs of $1,509, $1,663, $4,547 and $5,109,  respectively |       | 32,951                                               |       | 34,691                                              |       | 101,993 |   | 109,380 |   |
| Allowance for  funds used during construction — debt                                                   |       | (3,840                                               | )          | (993                                                | )          | (9,305 | ) | (3,388 | ) |
| Total interest  charges and financing costs                                                                 |       | 29,111                                               |       | 33,698                                              |       | 92,688 |   | 105,992 |   |
|                                                                                                        |       |                                                 |       |                                                |       |   |   |   |   |
| Income before  income taxes                                                                                 |       | 67,402                                               |       | 63,381                                              |       | 236,053 |   | 207,987 |   |
| Income taxes                                                                                                |       | 20,044                                               |       | 17,703                                              |       | 59,656 |   | 49,514 |   |
| **Net  income**                                                                                             |       | $                                                    | 47,358     |                                                | $          | 45,678 |   | $ | 176,397 |   | $ | 158,473 |   |

 

**See Notes to Consolidated Financial Statements**

 

3

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**PUBLIC SERVICE CO.OF COLORADO AND SUBSIDIARIES**CONSOLIDATEDSTATEMENTS OF CASH FLOWS (UNAUDITED)(Thousands of dollars)

** **
| ** **                                                                         | ** ** | **Nine Months Ended Sept. 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2006**                                            | ** ** | **2005** | ** ** |
| **Operating  activities**                                                          |       |                                                |       |   |   |
| Net income                                                                         |       | $                                                   | 176,397    |   | $ | 158,473 |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                                                |       |   |   |
| Depreciation and  amortization                                                     |       | 190,859                                             |       | 189,512 |   |
| Deferred income  taxes                                                             |       | 70,736                                              |       | 83,321 |   |
| Amortization of  investment tax credits                                            |       | (2,962                                              | )          | (2,978 | ) |
| Allowance for  equity funds used during construction                               |       | (1,315                                              | )          | (1,243 | ) |
| Unrealized  (gain) loss on derivative instruments                                  |       | (2,566                                              | )          | 3,200 |   |
| Change in  accounts receivable                                                     |       | 144,710                                             |       | (2,990 | ) |
| Change in  accrued unbilled revenue                                                |       | 65,883                                              |       | (61,041 | ) |
| Change in  inventories                                                             |       | 19,685                                              |       | (30,796 | ) |
| Change in  recoverable purchased natural gas and electric energy costs             |       | 212,713                                             |       | 76,809 |   |
| Change in  prepayments and other current assets                                    |       | (50,527                                             | )          | 80,648 |   |
| Change in  accounts payable                                                        |       | (261,725                                            | )          | 51,325 |   |
| Change in other  current liabilities                                               |       | 10,991                                              |       | (16,811 | ) |
| Change in other  noncurrent assets                                                 |       | (39,767                                             | )          | 6,805 |   |
| Change in other  noncurrent liabilities                                            |       | (6,668                                              | )          | 3,287 |   |
| Net cash  provided by operating activities                                         |       | 526,444                                             |       | 537,521 |   |
|                                                                               |       |                                                |       |   |   |
| **Investing  activities**                                                          |       |                                                |       |   |   |
| Capital/construction  expenditures                                                 |       | (399,924                                            | )          | (283,052 | ) |
| Allowance for  equity funds used during construction                               |       | 1,315                                               |       | 1,243 |   |
| Other  investments                                                                 |       | (1,472                                              | )          | (2,864 | ) |
| Net cash used in  investing activities                                             |       | (400,081                                            | )          | (284,673 | ) |
|                                                                               |       |                                                |       |   |   |
| **Financing  activities**                                                          |       |                                                |       |   |   |
| Short-term  borrowings — net                                                  |       | (98,604                                             | )          | (196,889 | ) |
| Borrowings under  utility money pool arrangement                                   |       | 934,800                                             |       | 3⁄4 |   |
| Repayments under  utility money pool arrangement                                   |       | (902,400                                            | )          | 3⁄4 |   |
| Proceeds from  issuance of long-term debt                                          |       | 3⁄4                                              |       | 129,500 |   |
| Repayment of  long-term debt, including reacquisition premiums                     |       | (125,997                                            | )          | (240,528 | ) |
| Capital  contribution from parent                                                  |       | 193,185                                             |       | 199,880 |   |
| Dividends paid  to parent                                                          |       | (129,655                                            | )          | (62,564 | ) |
| Net cash used in  financing activities                                             |       | (128,671                                            | )          | (170,601 | ) |
|                                                                               |       |                                                |       |   |   |
| Net increase  (decrease) in cash and cash equivalents                              |       | (2,308                                              | )          | 82,247 |   |
| Cash and cash  equivalents at beginning of year                                    |       | 3,662                                               |       | 726 |   |
| Cash and cash  equivalents at end of quarter                                       |       | $                                                   | 1,354      |   | $ | 82,973 |   |
|                                                                               |       |                                                |       |   |   |
| Supplemental  disclosure of cash flow information:                                 |       |                                                |       |   |   |
| Cash paid for  interest (net of amounts capitalized)                               |       | $                                                   | 86,441     |   | $ | 92,296 |   |
| Cash paid for  income taxes (net of refunds received)                              |       | $                                                   | 30,395     |   | $ | 38,587 |   |
|                                                                               |       |                                                |       |   |   |
| Supplemental  disclosure of non-cash investing transactions:                       |       |                                                |       |   |   |
| Property, plant  and equipment additions in accounts payable                       |       | $                                                   | 7,774      |   | $ | 22,685 |   |

 

See Notes to ConsolidatedFinancial Statements

 

4

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**PUBLIC SERVICE CO.OF COLORADO AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS (UNAUDITED)(Thousands of dollars)**

 
| ** **                                                                                     | ** ** | **Sept. 30, 2006** | ** ** | **Dec. 31, 2005** | ** ** |
|------------------------------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| **ASSETS**                                                                                     | ** ** | ** **                   | ** ** | ** **                  | ** ** |
| Current assets:                                                                                |       |                         |       |                        |       |
| Cash and cash  equivalents                                                                     |       | $                            | 1,354      |                        | $          | 3,662 |   |
| Accounts  receivable — net of allowance for bad debts: $13,205 and $19,381,  respectively |       | 346,452                      |       | 451,944                     |       |
| Accounts  receivable from affiliates                                                           |       | 8,528                        |       | 47,746                      |       |
| Accrued unbilled  revenues                                                                     |       | 168,731                      |       | 234,614                     |       |
| Recoverable  purchased natural gas and electric energy costs                                   |       | 17,681                       |       | 230,393                     |       |
| Materials and  supplies inventories — at average cost                                     |       | 44,222                       |       | 42,602                      |       |
| Fuel inventory —  at average cost                                                         |       | 32,712                       |       | 19,582                      |       |
| Natural gas  inventory — at average cost                                                  |       | 177,838                      |       | 212,274                     |       |
| Derivative  instruments valuation                                                              |       | 97,559                       |       | 78,064                      |       |
| Prepayments and  other                                                                         |       | 79,776                       |       | 35,218                      |       |
| Total current  assets                                                                          |       | 974,853                      |       | 1,356,099                   |       |
| Property, plant  and equipment, at cost:                                                       |       |                         |       |                        |       |
| Electric utility  plant                                                                        |       | 6,401,297                    |       | 6,275,046                   |       |
| Natural gas  utility plant                                                                     |       | 1,816,572                    |       | 1,793,240                   |       |
| Construction  work in progress                                                                 |       | 382,917                      |       | 209,721                     |       |
| Other                                                                                          |       | 720,127                      |       | 745,894                     |       |
| Total property,  plant and equipment                                                           |       | 9,320,913                    |       | 9,023,901                   |       |
| Less accumulated  depreciation                                                                 |       | (2,907,608                   | )          | (2,854,757                  | )          |
| Net property,  plant and equipment                                                             |       | 6,413,305                    |       | 6,169,144                   |       |
| Other assets:                                                                                  |       |                         |       |                        |       |
| Other  investments                                                                             |       | 29,764                       |       | 29,465                      |       |
| Regulatory  assets                                                                             |       | 242,588                      |       | 231,801                     |       |
| Derivative  instruments valuation                                                              |       | 166,115                      |       | 164,251                     |       |
| Other                                                                                          |       | 28,556                       |       | 35,191                      |       |
| Total other  assets                                                                            |       | 467,023                      |       | 460,708                     |       |
| Total assets                                                                                   |       | $                            | 7,855,181  |                        | $          | 7,985,951 |   |
| **LIABILITIES  AND EQUITY**                                                                    | ** ** | ** **                   | ** ** | ** **                  | ** ** |
| Current  liabilities:                                                                          |       |                         |       |                        |       |
| Current portion  of long-term debt                                                             |       | $                            | 101,368    |                        | $          | 126,334 |   |
| Short-term debt                                                                                |       | 237,000                      |       | 335,604                     |       |
| Borrowings on  utility money pool, weighted average yield of 5.38% at Sept. 30, 2006           |       | 32,400                       |       | —                      |       |
| Accounts payable                                                                               |       | 320,654                      |       | 578,722                     |       |
| Accounts payable  to affiliates                                                                |       | 25,233                       |       | 26,388                      |       |
| Taxes accrued                                                                                  |       | 64,205                       |       | 81,638                      |       |
| Dividends  payable to parent                                                                   |       | 65,970                       |       | —                      |       |
| Derivative  instruments valuation                                                              |       | 86,626                       |       | 66,463                      |       |
| Accrued interest                                                                               |       | 44,139                       |       | 36,498                      |       |
| Other                                                                                          |       | 76,877                       |       | 71,206                      |       |
| Total current  liabilities                                                                     |       | 1,054,472                    |       | 1,322,853                   |       |
| Deferred credits  and other liabilities:                                                       |       |                         |       |                        |       |
| Deferred income  taxes                                                                         |       | 932,708                      |       | 811,961                     |       |
| Deferred  investment tax credits                                                               |       | 60,022                       |       | 62,984                      |       |
| Regulatory  liabilities                                                                        |       | 456,197                      |       | 492,335                     |       |
| Customer  advances for construction                                                            |       | 276,956                      |       | 288,397                     |       |
| Derivative instruments  valuation                                                              |       | 164,053                      |       | 170,849                     |       |
| Minimum pension  liability                                                                     |       | 86,099                       |       | 86,099                      |       |
| Benefit  obligations and other                                                                 |       | 124,393                      |       | 122,511                     |       |
| Total deferred  credits and other liabilities                                                  |       | 2,100,428                    |       | 2,035,136                   |       |
| Commitments and  contingencies (see Note 4)                                                    |       |                         |       |                        |       |
| Capitalization:                                                                                |       |                         |       |                        |       |
| Long-term debt                                                                                 |       | 1,845,463                    |       | 1,945,973                   |       |
| Common stock —  authorized 100 shares of $0.01 par value; outstanding 100 shares          |       | —                       |       | —                      |       |
| Additional paid  in capital                                                                    |       | 2,377,116                    |       | 2,183,932                   |       |
| Retained  earnings                                                                             |       | 584,936                      |       | 604,163                     |       |
| Accumulated  other comprehensive loss                                                          |       | (107,234                     | )          | (106,106                    | )          |
| Total common  stockholder’s equity                                                        |       | 2,854,818                    |       | 2,681,989                   |       |
| Total  liabilities and equity                                                                  |       | $                            | 7,855,181  |                        | $          | 7,985,951 |   |

 

See Notes to Consolidated Financial Statements

 

5

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**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS**

** **

In the opinion of management, the accompanyingunaudited consolidated financial statements contain all adjustments necessaryto present fairly the financial position of PSCo and its subsidiaries as ofSept. 30, 2006, and Dec. 31, 2005; the results of its operations for the threeand nine months ended Sept. 30, 2006 and 2005; and its cash flows for the ninemonths ended Sept. 30, 2006 and 2005. Due to the seasonality of electric andnatural gas sales of PSCo, quarterly results are not necessarily an appropriatebase from which to project annual results.

 

Except to the extent updated or described below, thefootnotes set forth in the consolidated financial statements in PSCo’s AnnualReport on Form 10-K for the year ended Dec. 31, 2005 appropriately represent,in all material respects, the current status of the footnotes and areincorporated herein by reference.

 

**1.     Significant Accounting Policies**

 

***FASB Interpretation No. 48 (FIN 48)****—*****InJuly 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” FIN 48 prescribes a comprehensive financial statement model of how acompany should recognize, measure, present and disclose uncertain tax positionsthat the company has taken or expects to take in its income tax returns. FIN 48requires that only income tax benefits that meet the “more likely than not”recognition threshold be recognized or continue to be recognized on itseffective date. Initial derecognition amounts would be reported as a cumulativeeffect of a change in accounting principle.

 

FIN 48 is effective forfiscal years beginning after Dec. 15, 2006. PSCo is assessing the impact ofthe new guidance on all of its open tax positions.

 

***Statement of Financial AccountingStandards No. 157 — “***Fair Value Measurements” (SFASNo. 157) — In September 2006, the FASB issued SFAS No. 157, which enhancesexisting guidance for measuring assets and liabilities using fair value. SFASNo. 157 provides a single definition of fair value, together with a frameworkfor measuring it, and requires additional disclosure about the use of fairvalue to measure assets and liabilities. SFAS No. 157 also emphasizes that fairvalue is a market-based measurement, not an entity-specific measurement, andsets out a fair value hierarchy with the highest priority being quoted pricesin active markets. Under SFAS No. 157, fair value measurements are disclosed bylevel within that hierarchy. SFAS No. 157 is effective for financial statementsissued for fiscal years beginning after Nov. 15, 2007. PSCo is evaluating theimpact of SFAS No. 157 on its financial condition and results of operations.

 

***Statementof Financial Accounting Standards No. 158 — “***Employers’Accounting for Defined Benefit Pension and Other Postretirement Plans—anamendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158) — InSeptember 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the fundedstatus of each pension and other postretirement benefit plan as a liability orasset on their balance sheets with all unrecognized amounts to be recorded inother comprehensive income. Although PSCo continues to evaluate the impact ofthe new pronouncement, preliminary estimates indicate that assets could beincreased by approximately $393 million, the loss in other comprehensive incomecould be decreased by approximately $120 million and liabilities could beincreased by approximately $273 million. PSCo is evaluating regulatoryaccounting treatment, which would allow recognition of this item as aregulatory asset rather than as a charge to other comprehensive income. Theseestimates reflect the expected deferral of these amounts as regulatory assetsor liabilities. The actual impact of the adoption of SFAS No. 158 could differsignificantly from this estimate due to plan asset performance for the year andthe discount rate in effect at the end of the year when the plans’ liabilitiesare measured. The implementation of SFAS No.158 will have no impact on netincome. SFAS No. 158 is effective as of the end of the fiscal yearending after Dec. 15, 2006.

 

**2.     Regulation**

 

***FERC Transmission Rate Case****—*****OnSept. 2, 2004, Xcel Energy filed on behalf of PSCo and Southwestern PublicService Company (SPS), an affiliate of PSCo, an application to increasewholesale transmission service and ancillary service rates within the XcelEnergy joint open access transmission tariff. PSCo and SPS requested anincrease in annual transmission service and ancillary services revenues of $6.1million. On Feb. 6, 2006, theparties in the proceeding submitted an uncontested offer of settlement thatcontains a $1.6 million rate increase, a formula transmission service rate, a10.5 percent rate of return on common equity, and the phased inclusion of PSCo’s345 kilovolt tie line costs in wholesale transmission service rates. On April5, 2006, the Federal Energy Regulatory Commission (FERC) issued an order approving the uncontested settlement. PSCoplaced the final rates in effect on June 1, 2005 and issued refunds ofapproximately $3.7 million.

 

***Electric Commodity Adjustment (ECA)****—* The ECA, effective Jan. 1, 2004, is anincentive adjustment mechanism that compares actual fuel and purchased energyexpense in a calendar year to a benchmark formula. The ECA also provides for an$11.25 million cap on any cost sharing over or under an allowed ECA formularate. The formula rate is revised annually and collected or refunded in thefollowing year, if necessary. The current ECA mechanism will expire Jan. 1,2007.  Based on PSCo's analysis of themost recent forecast, a $10.3 million accrual was recorded in the third quarterof 2006.

 

6

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***Electric Rate Case —*** In April 2006, PSCo filed with the ColoradoPublic Utilities Commission (CPUC) to increase electricity rates by $208million annually, beginning Jan. 1, 2007.  The request was based on twocomponents, including an increase in base rate revenues of $178 million and anestimated $30 million increase in purchased capacity cost adjustment (PCCA)revenue.  The base rate request was based on a return on equity of 11percent, an equity ratio of 59.9 percent and an electric rate base of $3.4billion.  No interim rate increase was implemented.  The PCCA requestwas based on 2007 projected costs and a revenue credit to customers for onewholesale contract.

 

On Aug. 18, 2006, PSCo received testimony from 10 intervenorgroups, including the staff of the CPUC and the Office of Consumer Counsel(OCC). The intervenor testimony addressed a multitude of cost-of-service issuesand recommended various reductions to PSCo’s requested increase.  Theintervenors’ recommended increases, as subsequently corrected, ranged from $35million to $91.4 million, exclusive of PCCA revenue.  The CPUC staffrecommended an overall base rate increase of $83 million.  In addition,the staff generally agreed with PSCo’s proposal for a PCCA mechanism throughDec. 31, 2009.  The staff’s filed case incorporated a 9.5 percent returnon equity, adopted PSCo’s recommended capital structure and reduceddepreciation expense by $19.6 million annually.

 

The OCC recommended, as subsequently corrected, an overallbase rate increase of $35 million, which incorporated an 8.5 percent return onequity, adopted PSCo’s capital structure and reduced depreciation expense by$40.5 million annually.

 

On Sept. 29, 2006, PSCo filed answer testimony in which itadvocated for a $206.6 million increase, composed of an approximate $172 millionincrease in base rate revenues, an estimated $30 million in PCCA revenue and anestimated $4.6 million in ECA revenue to recover certain WindSource programcosts.  PSCo continued to support an 11.0 percent return on equity, a 60percent equity ratio and year-end rate base treatment of Comanche constructionwork in progress costs.  The primary changes from the original filing wereto propose the recovery of certain WindSource program revenues through the ECAmechanism rather than through base rates, and an update of pension and otherbenefits expense.

 

On Oct. 20, 2006, PSCo entered into a comprehensivesettlement agreement with several of the parties to the case, including theCPUC staff, the OCC, the Colorado Energy Consumers, The Kroger Co., Climax MolybdenumCompany, CF&I Steel,L.P., and the Commercial Group.  Ifapproved by the CPUC, the settlement would authorize an overall rate increase,effective Jan. 1, 2007. The settlement provides for an increase in base ratesof $107 million, including an increase to depreciation expense of approximately$13.8 million and use of year-end 2006 rate base treatment for Comancheconstruction work in progress costs; an estimated $39.4 million in PCCA revenueand an estimated $4.6 million in ECA revenue to recover certain WindSourceprogram costs.  As a part of the total revenue increase of $151 million,the settlement also included the following terms:

 

•      A10.50 percent return on equity and a 60 percent equity ratio;

•      APCCA rider for all purchased capacity costs, with no revenue credit;

•      Recoveryof certain WindSource-related costs through the ECA and the remainder throughWindSource rates; and

•      Implementationof a residential late payment fee of 1.00 percent.

 

The settlement also provides for recovery of fuel andpurchased energy costs through the ECA.  The ECA mechanism would:

 

•      Changequarterly;

•      Allowfor interest on any deferred balance;

•      Asnoted above, provide for recovery of WindSource-related costs fromnon-participating customers updated annually to reflect the system costs absentWindSource resources;

•      Providefor an incentive if targets for baseload energy production, or purchased energybenefits exceed certain thresholds.  If the thresholds are exceeded,sharing under the ECA incentive would be 80 percent to customers and 20 percentto PSCo and

•      Sharingwith customers of trading margins from system resources (generation-basedtrading) and non-system resources (proprietary trading) that are over and abovethe first approximately $1 million in margins achieved for each type oftrading.  The sharing percentage for generation-based trading is 80percent to customers and 20 percent to PSCo; the sharing percentage for theproprietary trading is 20 percent to customers and 80 percent to PSCo.

 

In a filing made with the CPUC on Oct. 20, 2006, theparties requested that the CPUC delay hearings currently scheduled to begin onOct. 23, 2006 and hold hearings on the settlement beginning on Nov. 2, 2006.

 

***2003 Resource Plan —***On June 2, 2006,PSCo filed a motion with the CPUC requesting permission to withdraw an earlierapplication it made, which requested CPUC approval to shorten the ten-yearresource acquisition period of its 2003 resource plan by one year resulting ina nine year acquisition period (2004-2012). PSCo’s original application alsosought to reject all bids offering power supplies starting in 2013 that itreceived in response to its Feb. 24, 2005 all-source solicitation. On June7, 2006, the CPUC approved PSCo’s motion and directed PSCo to complete theevaluation of bids and negotiation of contracts offering new power suppliesstarting in year 2013 by Dec. 15, 2006. It also directed PSCo management toapprove the selected contracts by Jan. 15, 2007.

 

7

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***Renewable PortfolioStandards****—*****In November 2004, anamendment to the Colorado statutes was passed by referendum requiringimplementation of a renewable energy portfolio standard (RES) for electricservice. The law requires PSCo to generate, or cause to be generated, a certainlevel of electricity from eligible renewable resources. During 2006, the CPUCdetermined that compliance with the RES should be measured through theacquisition of renewable energy credits either with or without the accompanyingrenewable energy; that the utility purchaser owns the renewable energy creditsassociated with existing contracts where the power purchase agreement is silenton the issue; that Colorado utilities should be required to file implementationplans and the methods utilities should use for determining the budget availablefor renewable resources. In April 2006, the CPUC issued rules that establishthe process utilities are to follow in implementing the RES. PSCo filed itsfirst annual compliance plan under these rules on Aug. 31, 2006. The plan demonstrates that PSCo will meet theRES beginning in 2007 as required.

 

On Dec. 1, 2005,PSCo filed with the CPUC to implement a new rate rider that would apply to eachcustomer’s total electric bill, providing approximately $22 million in annualrevenue (1.0 percent of total retail revenue). The revenues collected under therider will be used to acquire sufficient solar generation resources to meet therequirements of the Colorado renewable energy portfolio standard. On Feb. 14,2006, PSCo and the other parties to the case filed a stipulation agreeing toreduce the rider to 0.60 percent. The CPUC approved the stipulation on February22, 2006. The rider became effective March 1, 2006. PSCo’s compliance plan willaddress whether modification to the level of this rider is necessary to meetthe requirements of the renewable energy portfolio standard.

 

On Aug. 31, 2006, PSCofiled with the CPUC an application for approval of its 2007 plan for compliancewith the CPUC’s RES rules. As a part of its plan, PSCo requested approval tocontinue its existing 0.60 percent RES adjustment rider. Through its existingresources and contracts entered into in 2006, PSCo anticipates havingsufficient non-solar renewable energy resources to meet the standard through atleast 2016. In June 2006, PSCo issued a request for proposal to provide solarrenewable energy credits and expects to enter into contracts to meet itsobligation for on-site solar resources. On Sept. 1, 2006, PSCo executed a twenty-year solar power purchaseagreement, which will provide about 16,000 megawatt hours per year andaccompanying solar renewable energy credits beginning in 2008.

 

***PSCo Quality of Service Plan****—*****PSCowas required to make a filing regarding the future of its quality of serviceplan (QSP), which expires at the end of 2006. In the initial filing, PSCoproposed a service quality monitoring and reporting plan. After reviewing theresponses of the CPUC staff and other intervenors, PSCo negotiated a new QSPthat will extend through calendar year 2010. The plan establishes performancemeasures and provides for associated bill credits for failure to achieveregional electric distribution system reliability, electric service continuityand restoration thresholds, customer complaints and telephone response times.If the performance thresholds are not met, the annual bill credit exposures areapproximately $7 million for regional reliability and $1 million each for thecontinuity, reliability, customer complaints and telephone response timethresholds. Each of PSCo’s nine operating regions has its own calculatedreliability metric and the bill credits would be apportioned among the regions.PSCo would have to fail the operating threshold two years in a row beforepaying reliability bill credits. The bill credit levels would not escalate. Ifthe credits are required to be paid, the stated amounts would be grossed up fortaxes. The proposed plan is pending CPUC approval.

 

PSCo entered into aseparate stipulation with the local government intervenors and the City ofBoulder regarding certain issues they raised in the QSP proceeding. PSCo agreedto incorporate provisions in its electric tariff regarding conducting regularstreet light outage surveys and establishing benchmarks for standard outagerates and streetlight and traffic signal restoration. The electric tariff willprovide for a charge to conduct the street light surveys. The tariff also willprovide for payment of credits if PSCo does not restore street lights within adefined period. The CPUC conducted hearings regarding the QSP settlements anddeliberated on the new QSP on Sept. 27, 2006. In deliberations, the CPUCapproved the as-settled QSP with some modifications. The CPUC requires PSCo tofile a replacement QSP by 2010 and to modify some reporting requirements. TheCPUC has not issued a final order.

 

***Controlled Outage Investigation****—*****OnJuly 7, 2006, the CPUC discussed a CPUC staff report regarding itsinvestigation of the controlled outages of Feb. 18, 2006, which affected anestimated 323,000 customers in Colorado for approximately 30 minutes. Theinvestigation reviewed natural gas supply issues, the causes of unplannedoutages on several PSCo-owned and independent power generation facilities,transmission availability, customer interruption procedures, emergencypreparedness and internal and external communications. The CPUC report madeover 90 recommendations and directed PSCo to respond within two weeks with itsplans to implement certain procedures to address curtailment situations if theyarise this summer. The CPUC’s recommendations are directed at ensuring thatthere is an appropriate level of situational awareness between the operationalstatus of the interdependent gas and electric supply systems so that adequatepipeline delivery pressures are available during critical peak periods. PSCoresponded to the report of the CPUC and is in the process of implementing therecommendations. The final order has not been issued by the CPUC.

 

8

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**3.     Tax Matters — Corporate-Owned LifeInsurance**

 

***Interest ExpenseDeductibility —***As previously disclosed, inApril 2004, Xcel Energy filed a lawsuit against the U.S. government in theU.S. District Court for the District of Minnesota to establish its right todeduct the policy loan interest expense that had accrued during tax years 1993and 1994 on policy loans related to its corporate-owned life insurance (COLI)policies that insured certain lives of employees of PSCo. These policies areowned and managed by PSR Investments, Inc. (PSRI), a wholly ownedsubsidiary of PSCo.

 

After Xcel Energy filedthis suit, the Internal Revenue Service (IRS) sent its two statutory notices ofdeficiency of tax, penalty and interest for taxable years 1995 through 1999. XcelEnergy has filed U.S. Tax Court petitions challenging those notices. XcelEnergy anticipates the dispute relating to its claimed interest expensedeductions for tax years 1993 and later will be resolved in the refund suitthat is pending in the Minnesota federal district court and the Tax Courtpetitions will be held in abeyance pending the outcome of the refund litigation.In the third quarter of 2006, Xcel Energy also received a statutory notice ofdeficiency from the IRS for tax years 2000 through 2002 and timely filed a TaxCourt petition challenging the denial of the COLI interest expense deductionsfor those years.

 

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

 

On May 5, 2006, XcelEnergy filed a second motion for summary judgment. Oral arguments werepresented on Aug. 8, 2006. A decision on this motion is pending. On Aug. 18,2006, the U.S. government filed a second motion for summary judgment. Oralarguments were presented on Oct. 12, 2006, with the Court taking the matterunder advisement. The district court has ordered the parties to be ready fortrial by Jan. 2, 2007 in the event the motions are denied.

 

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

 

Should the IRS ultimatelyprevail on this issue, tax and interest payable through Dec. 31, 2006, wouldreduce earnings by an estimated $419 million. In 2004, Xcel Energy receivedformal notification that the IRS will seek penalties. If penalties (plusassociated interest) also are included, the total exposure through Dec. 31,2006, is approximately $497 million. PSCo annual earnings for 2006 would bereduced by approximately $44 million, after tax, if COLI interest expensedeductions were no longer available.

 

**4.     Commitments and Contingent Liabilities**

 

**Environmental Contingencies**

 

PSCo has been, or is, currently involved with thecleanup of contamination from certain hazardous substances at several sites. Inmany situations, PSCo is pursuing or intends to pursue insurance claims andbelieves it will recover some portion of these costs through such claims.Additionally, where applicable, PSCo is pursuing, or intends to pursue,recovery from other potentially responsible parties and through the rateregulatory process. New and changing federal and state environmental mandatescan also create added financial liabilities for PSCo, which are normallyrecovered through the rate regulatory process. To the extent any costs are notrecovered through the options listed above, PSCo would be required to recognizean expense for such unrecoverable amounts in its Consolidated FinancialStatements.

 

***Regional Haze Rules ***— The U.S.Environmental Protection Agency (EPA) requires states to develop implementationplans to comply with regional haze rules that require emission controls, knownas best available retrofit technology (BART), by December 2007. States arerequired to identify the facilities that will have to reduce emissions underBART and then set BART emissions limits for those facilities. Colorado is thefirst state in Xcel Energy’s region to earnestly begin its BARTrule development as the first step toward the December 2007 deadline.PSCo is actively involved in the stakeholder process in Colorado. On May 30,2006, the Colorado Air Quality Control Commission promulgated BART regulationsrequiring certain major stationary sources to evaluate and install, operate andmaintain BART technology or an approved BART alternative to make reasonableprogress toward meeting the national visibility goal. On Aug. 1, 2006, PSCosubmitted its BART alternatives analysis to the Colorado Air Pollution ControlDivision. As set forth in its analysis, PSCo estimates that implementation ofthe BART alternatives will cost approximately $165 million in capital costs,which includes approximately $62 million in environmental upgrades for theexisting Comanche Station project. PSCo expects the cost of any requiredcapital investment will be recoverable from customers. Emissions controls areexpected to be installed between 2010 and 2012 and must be operational by 2013.

 

9

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***Clean Air MercuryRule***— In March 2005, the EPA issued the Clean AirMercury Rule (CAMR), which regulates mercury emissions from power plants forthe first time. PSCo continues to evaluate the strategy for complying with CAMR.Compliance may be achieved by either adding mercury controls or purchasingallowances or a combination of both. On June 6, 2006, the Colorado Departmentof Public Health and Environment issued a draft rule for implementing CAMR inColorado. The proposed rule provides for fewer mercury allowances than thefederal program, which may result in additional implementation costs. The stateof Colorado is required to submit a plan to the EPA by Oct. 31, 2006 to limitmercury emissions from coal-fired electric utility steam generating unitsconsistent with federal standards of performance. A stakeholder process isongoing, with a hearing before the Colorado Air Quality Control Commissioncurrently scheduled for Nov. 16-17, 2006. The capital cost is estimated to be $4.9million for the mercury control equipment.

 

**Legal Contingencies**

 

Lawsuits and claims arise in the normal course ofbusiness. Management, after consultation with legal counsel, has recorded anestimate of the probable cost of settlement or other disposition of them. Theultimate outcome of these matters cannot presently be determined. Accordingly,the ultimate resolution of these matters could have a material adverse effecton PSCo’s financial position and results of operations.

 

***Comer vs. Xcel Energy Inc. et al.***— OnApril 25, 2006, Xcel Energy received notice of a purported class action lawsuitfiled in U.S. District Court for the Southern District of Mississippi. AlthoughPSCo is not named as a party to this litigation, if the litigation ultimatelyresults in an unfavorable outcome for Xcel Energy, it could have a materialadverse effect on PSCo. The lawsuit names more than 45 oil, chemical andutility companies, including Xcel Energy, as defendants and alleges thatdefendants’ carbon dioxide emissions “were a proximate and direct cause of theincrease in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim,several legal theories, including negligence, and public and private nuisanceand seek damages related to the loss resulting from the hurricane. Xcel Energybelieves this lawsuit is without merit and intends to vigorously defend itselfagainst these claims. On July 19, 2006, Xcel Energy filed a motion to dismissthe lawsuit in its entirety.

 

***Comanche 3 Permit Litigation***- On Aug. 4, 2005, Citizens for Clean Air and Water inPueblo and Southern Colorado and Clean Energy Action filed a complaint againstthe Colorado Air Pollution Control Division alleging that the Divisionimproperly granted permits to PSCo under Colorado’s Prevention of SignificantDeterioration program for the construction and operation of Comanche 3. PSCointervened in the case. On June 20, 2006, the court ruled in PSCo’s favor andheld that the Comanche 3 permits had been properly granted and plaintiffs’claims to the contrary were without merit. Plaintiffs have appealed thisdecision.

 

***Carbon DioxideEmissions Lawsuit***— On July 21, 2004, the attorneysgeneral of eight states and New York City, as well as several environmentalgroups, filed lawsuits in U.S. District Court for the Southern District of NewYork against five utilities, including Xcel Energy, to force reductions incarbon dioxide (CO2)emissions. Although PSCo is not named as a party to this litigation, therequested relief that Xcel Energy cap and reduce its CO2 emissions could have a materialadverse effect on PSCo. The other utilities include American Electric PowerCo., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuelis combusted, such as in automobiles, industrial operations and coal- orgas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as definedunder state and federal common law because it has contributed to global warming.The lawsuits do not demand monetary damages. Instead, the lawsuits ask thecourt to order each utility to cap and reduce its CO2 emissions. InOctober 2004, Xcel Energy and four other utility companies filed a motionto dismiss the lawsuit, contending, among other reasons, that the lawsuit is anattempt to usurp the policy-setting role of the U.S. Congress and the president.On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss onconstitutional grounds. Plaintiffs filed an appeal to the Second Circuit Courtof Appeals. Oral arguments were presented on June 7, 2006 and a decision on theappeal is pending.

 

**Other Contingencies**

 

The circumstances in Notes 11 and 12 to theconsolidated financial statements in PSCo’s Annual Report on Form 10-K for theyear ended Dec. 31, 2005 and Notes 3 and 4 to the consolidated financialstatemtents in this Quarterly Report on Form 10-Q, appropriately represent, inall material respects, the current status of respective commitments andcontingent liabilities and are incorporated herein by reference. The followingare unresolved contingencies that are material to PSCo’s financial position:

 

•  TaxMatters—See Note 3 to the consolidated financial statements for discussion ofexposures regarding the tax deductibility of corporate-owned life insuranceloan interest.

 

10

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**5.     Short-Term Borrowings and FinancingActivities**

 

At Sept. 30, 2006, PSCo had $237.0 million inshort-term debt outstanding at a weighted average yield of 5.42 percent.

 

**6.     Derivative Valuation and Financial Impacts**

 

PSCouses a number of different derivative instruments in connection with itsutility operations, short-term wholesale and commodity trading activities,including forward contracts, futures, swaps and options. These derivativesinstruments are utilized in connection with various commodity prices, certainenergy related products, including emission allowances and renewable energycredits, and interest rates. All derivative instruments not qualifying for thenormal purchases and normal sales exception, as defined by SFAS No. 133— “Accountingfor Derivative Instruments and Hedging Activities,” as amended (SFASNo. 133), are recorded at fair value. The presentation of these derivativeinstruments is dependent on the designation of a qualifying hedgingrelationship. The adjustment to fair value of derivative instruments notdesignated in a qualifying hedging relationship is reflected in currentearnings or as a regulatory balance. This classification is dependent on theapplicability of specific regulation. This includes certain instruments used tomitigate market risk for PSCo and all instruments related to the commoditytrading operations. The designation of a cash flow hedge permits theclassification of fair value to be recorded within Other Comprehensive Income,to the extent effective. The designation of a fair value hedge permits aderivative instrument’s gains or losses to offset the related results of thehedged item in the Consolidated Statements of Income.

 

PSCo records the fairvalue of its derivative instruments in its Consolidated Balance Sheets asseparate line items identified as Derivative Instruments Valuation in bothcurrent and noncurrent assets and liabilities.

 

Thefair value of all interest rate swaps is determined through counterpartyvaluations, internal valuations and broker quotes. There have been no materialchanges in the techniques or models used in the valuation of interest rateswaps during the periods presented.

 

Qualifyinghedging relationships are designated as either a hedge of a forecastedtransaction or future cash flow (cash flow hedge), or a hedge of a recognizedasset, liability or firm commitment (fair value hedge). The types of qualifyinghedging transactions in which PSCo is currently engaged in are discussed below.

 

**Cash Flow Hedges**

 

PSCo enters into derivative instruments to managevariability of future cash flows from changes in commodity prices and interestrates. These derivative instruments are designated as cash flow hedges foraccounting purposes, and the changes in the fair value of these instruments arerecorded as a component of Other Comprehensive Income or deferred as aregulatory asset or liability.

 

At Sept. 30, 2006, PSCo had variouscommodity-related contracts designated as cash flow hedges extending throughDecember 2009. The fair value of these cash flow hedges is recorded ineither Other Comprehensive Income or deferred as a regulatory asset orliability. This classification is based on the regulatory recovery mechanismsin place.  Amounts deferred in these accounts are recorded in earnings asthe hedged purchase or sales transaction is settled. This could include thepurchase or sale of energy or energy-related products, the use of natural gasto generate electric energy or gas purchased for resale. As of Sept. 30, 2006, PSCo had noamounts in Accumulated Other Comprehensive Loss related to commodity cash flowhedge contracts that are expected to be recognized in earnings during the next12 months as the hedged transactions settle.

 

PSCo enters into****variousinstruments that effectively fix interest payments on certain floating ratedebt obligations or effectively fix the yield or price on a specified benchmarkinterest rate for a specific period. These derivative instruments aredesignated as cash flow hedges for accounting purposes and the change in fairvalue of these instruments is recorded as a component of Other ComprehensiveIncome. As of Sept. 30, 2006, PSCo had net gains of $1.5 million in AccumulatedOther Comprehensive Income related to interest rate cash flow hedge contractsthat are expected to be recognized in earnings during the next 12 months.

 

Gains or losses on hedging transactions for the salesof energy or energy-related products are primarily recorded as a component ofrevenue, hedging transactions for fuel used in energy generation are recordedas a component of fuel costs, hedging transactions for gas purchased for resaleare recorded as a component of gas costs and interest rate hedging transactionsare recorded as a component of interest expense. PSCo is allowed to recover in electricor gas rates the costs of certain financial instruments purchased to reducecommodity cost volatility. There was an immaterial amount of ineffectiveness inthe third quarter of 2006.

 

11

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The impact of qualifying cash flow hedges on PSCo’sAccumulated Other Comprehensive Income, included as a component of stockholder’sequity, is detailed in the following table:

 
| ** **                                                                          | ** ** | **Nine Months Ended** | ** ** |
|-------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| **(Millions of Dollars)**                                                 | ** ** | **Sept. 30, 2006**    | ** ** | **Sept. 30, 2005** | ** ** |
| Accumulated  other comprehensive income related to cash flow hedges at Dec. 31      |       | $                               | 14.2       |   | $ | 15.7 |   |
| After-tax net  unrealized gains related to derivatives accounted for as hedges      |       | —                          |       | 8.4 |   |
| After-tax net  realized gains on derivative transactions reclassified into earnings |       | (1.1                            | )          | (9.5 | ) |
| Accumulated  other comprehensive income related to cash flow hedges at Sept. 30     |       | $                               | 13.1       |   | $ | 14.6 |   |

 

###### **Fair Value Hedges**

######  

The effective portion of the change in the fair valueof a derivative instrument qualifying as a fair value hedge is offset againstthe change in the fair value of the underlying asset, liability or firmcommitment being hedged. That is, fair value hedge accounting allows the gainsor losses of the derivative instrument to offset, in the same period, the gainsand losses of the hedged item.

 

**Derivatives Not Qualifying for HedgeAccounting**

 

PSCo has commodity trading operations that enter intoderivative instruments. These derivative instruments are accounted for on amark-to-market basis in the Consolidated Statements of Income. The results ofthese transactions are recorded on a net basis within Operating Revenue on theConsolidated Statements of Income.

 

PSCo also enters into certain commodity-basedderivative transactions, not included in trading operations, which do notqualify for hedge accounting treatment. These derivative instruments areaccounted for on a mark-to-market basis in accordance with SFAS No. 133.

 

**Normal Purchases or Normal SalesContracts**

 

PSCo enters intocontracts for the purchase and sale of various commodities for use in itsbusiness operations. SFAS No. 133 requires a company to evaluate thesecontracts to determine whether the contracts are derivatives. Certain contractsthat literally meet the definition of a derivative may be exempted from SFASNo. 133 as normal purchases or normal sales. Normal purchases and normal salesare contracts that provide for the purchase or sale of something other than afinancial or derivative instrument that will be delivered in quantitiesexpected to be used or sold over a reasonable period in the normal course ofbusiness. In addition, normal purchases and normal sales contracts must have aprice based on an underlying that is clearly and closely related to the assetbeing purchased or sold. An underlying is a specified interest rate, securityprice, commodity price, foreign exchange rate, index of prices or rates, orother variable, including the occurrence or nonoccurrence of a specified event,such as a scheduled payment under a contract.

 

PSCo evaluates allof its contracts when such contracts are entered to determine if they arederivatives and, if so, if they qualify to meet the normal designationrequirements under SFAS No. 133. None of the contracts entered into within thecommodity trading operations qualify for a normal designation.

 

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

 

Normal purchases and normal sales contracts areaccounted for as executory contracts as required under other generally acceptedaccounting principles.

 

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**7.     Detail of Interest and Other Income(Expense) — Net**

** **

Interest and other income, net of nonoperatingexpenses, for the three and nine months ended Sept. 30 consisted of thefollowing:

 
| ** **                                                                                         | ** ** | **Three months ended Sept. 30,** | ** ** | **Nine months ended Sept. 30,** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| **(Thousands of dollars)**                                                               | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                                                         | ** ** | ** **                                           | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest income                                                                                    |       | $                                                    | 391        |                                                | $          | 1,007 |   | $ | 2,518 |   | $ | 2,384 |   |
| Other  nonoperating income                                                                         |       | 594                                                  |       | 628                                                 |       | 3,075 |   | 2,872 |   |
| Interest expense  on corporate-owned life insurance and other employee-related insurance  policies |       | (3,605                                               | )          | (3,540                                              | )          | (13,902 | ) | (13,076 | ) |
| Other  nonoperating expenses                                                                       |       | (1,423                                               | )          | (302                                                | )          | (2,204 | ) | (361 | ) |
| Total interest  and other income (expense) – net                                              |       | $                                                    | (4,043     | )                                                   | $          | (2,207 | ) | $ | (10,513 | ) | $ | (8,181 | ) |

 

**8.     Segment Information**

 

PSCo has two reportable segments, Regulated ElectricUtility and Regulated Natural Gas Utility. Commodity trading operations are nota reportable segment and are included in the Regulated Electric Utilitysegment.

 
| **(Thousands of dollars)**                           | ** ** | **Regulated  Electric Utility** | ** ** | **Regulated  Natural  Gas Utility** | ** ** | **All Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|----------------------------------------------------------------|------------|--------------------------------------|------------|------------------------------------------|------------|--------------------|------------|-------------------------------|------------|-------------------------|------------|
| **Three months ended Sept. 30, 2006** |       |                                 |       |                                     |       |               |       |                          |       |                    |       |
| Revenues from:                                                 |       |                                 |       |                                     |       |               |       |                          |       |                    |       |
| External  customers                                            |       | $                                    | 644,445    |                                     | $          | 142,422            |       | $                             | 6,857      |                    | $          | — |   | $ | 793,724 |   |
| Internal  customers                                            |       | 35                                   |       | 5                                        |       | —             |       | (40                           | )          | —                  |       |
| Total revenue                                                  |       | $                                    | 644,480    |                                     | $          | 142,427            |       | $                             | 6,857      |                    | $          | (40 | ) | $ | 793,724 |   |
| Segment net  income (loss)                                     |       | $                                    | 39,622     |                                     | $          | 5,653              |       | $                             | 2,083      |                    | $          | — |   | $ | 47,358 |   |
|                                                           |       |                                 |       |                                     |       |               |       |                          |       |                    |       |
| **Three  months ended Sept. 30, 2005**                         |       |                                 |       |                                     |       |               |       |                          |       |                    |       |
| Revenues from:                                                 |       |                                 |       |                                     |       |               |       |                          |       |                    |       |
| External customers                                             |       | $                                    | 654,199    |                                     | $          | 122,427            |       | $                             | 6,097      |                    | $          | — |   | $ | 782,723 |   |
| Internal  customers                                            |       | 65                                   |       | 170                                      |       | —             |       | (235                          | )          | —                  |       |
| Total revenue                                                  |       | $                                    | 654,264    |                                     | $          | 122,597            |       | $                             | 6,097      |                    | $          | (235 | ) | $ | 782,723 |   |
| Segment net  income (loss)                                     |       | $                                    | 42,337     |                                     | $          | (1,295             | )          | $                             | 4,636      |                    | $          | — |   | $ | 45,678 |   |

 
| **(Thousands of dollars)**  | ** ** | **Regulated  Electric Utility** | ** ** | **Regulated  Natural Gas  Utility** | ** ** | **All Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|---------------------------------------|------------|--------------------------------------|------------|-------------------------------------|------------|--------------------|------------|-------------------------------|------------|-------------------------|------------|
| **Nine  months ended Sept. 30, 2006** | ** ** | ** **                           | ** ** | ** **                          | ** ** | ** **         | ** ** | ** **                    | ** ** | ** **              | ** ** |
| Revenues from:                        |       |                                 |       |                                |       |               |       |                          |       |                    |       |
| External  customers                   |       | $                                    | 1,916,376  |                                | $          | 885,340            |       | $                             | 26,264     |                    | $          | — |   | $ | 2,827,980 |   |
| Internal  customers                   |       | 155                                  |       | 61                                  |       | —             |       | (216                          | )          | —                  |       |
| Total revenue                         |       | $                                    | 1,916,531  |                                | $          | 885,401            |       | $                             | 26,264     |                    | $          | (216 | ) | $ | 2,827,980 |   |
| Segment net  income                   |       | $                                    | 125,854    |                                | $          | 39,761             |       | $                             | 10,782     |                    | $          | — |   | $ | 176,397 |   |
|                                  |       |                                 |       |                                |       |               |       |                          |       |                    |       |
| **Nine  months ended Sept. 30, 2005** | ** ** | ** **                           | ** ** | ** **                          | ** ** | ** **         | ** ** | ** **                    | ** ** | ** **              | ** ** |
| Revenues from:                        |       |                                 |       |                                |       |               |       |                          |       |                    |       |
| External  customers                   |       | $                                    | 1,807,470  |                                | $          | 774,277            |       | $                             | 23,461     |                    | $          | — |   | $ | 2,605,208 |   |
| Internal  customers                   |       | 179                                  |       | 216                                 |       | —             |       | (395                          | )          | —                  |       |
| Total revenue                         |       | $                                    | 1,807,649  |                                | $          | 774,493            |       | $                             | 23,461     |                    | $          | (395 | ) | $ | 2,605,208 |   |
| Segment net  income                   |       | $                                    | 116,144    |                                | $          | 27,026             |       | $                             | 15,303     |                    | $          | — |   | $ | 158,473 |   |

 

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**9.     ComprehensiveIncome**

 

The components of total comprehensive income are shownbelow:

 
| ** **                                                                                        | ** ** | **Three months ended  Sept. 30,** | ** ** | **Nine months ended  Sept. 30,** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|--------------------------------------------------|------------|-------------------------------------------------|------------|
| **(Millions of dollars)**                                                               | ** ** | **2006**                                         | ** ** | **2005**                                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                                                        | ** ** | ** **                                       | ** ** | ** **                                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income                                                                                        |       | $                                                | 47.4       |                                            | $          | 45.7 |   | $ | 176.4 |   | $ | 158.5 |   |
| Other  comprehensive income (loss):                                                               |       |                                             |       |                                            |       |   |   |   |   |
| After-tax net  unrealized gains related to derivatives accounted for as hedges (see Note 6)       |       | —                                           |       | 4.5                                             |       | — |   | 8.3 |   |
| After-tax net  realized gains on derivative transactions reclassified into earnings (see  Note 6) |       | (0.4                                             | )          | (4.8                                            | )          | (1.1 | ) | (9.5 | ) |
| Other  comprehensive loss                                                                         |       | (0.4                                             | )          | (0.3                                            | )          | (1.1 | ) | (1.2 | ) |
| Comprehensive  income                                                                             |       | $                                                | 47.0       |                                            | $          | 45.4 |   | $ | 175.3 |   | $ | 157.3 |   |

 

Theaccumulated other comprehensive loss in stockholder’s equity at Sept. 30, 2006and Dec. 31, 2005, relates to valuation adjustments on PSCo’s derivativefinancial instruments and hedging activities, the mark-to-market component ofPSCo’s marketable securities and unrealized losses related to its minimumpension liability.

 

**10.  Benefit Plans and Other PostretirementBenefits**

 

Pension and other postretirement benefit disclosuresbelow generally represent Xcel Energy consolidated information unlessspecifically identified as being attributable to PSCo.

 

**Components of Net Periodic BenefitCost**

 
| ** **                                                    | ** ** | **Three months ended Sept. 30,** | ** ** |
|---------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                    | ** ** | **2006**                                             | ** ** | **2005** | ** ** | **2006** | ** ** | **2005** | ** ** |
| **(Thousands of dollars)**                          | ** ** | **Pension Benefits**                            | ** ** | **Postretirement Health  Care Benefits** | ** ** |
| **Xcel  Energy Inc.**                                         | ** ** | ** **                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Service cost                                                  |       | $                                                    | 15,406     |   | $ | 15,115 |   | $ | 1,659 |   | $ | 1,671 |   |
| Interest cost                                                 |       | 38,854                                               |       | 40,246 |   | 13,234 |   | 13,765 |   |
| Expected return  on plan assets                               |       | (67,017                                              | )          | (70,290 | ) | (6,690 | ) | (6,425 | ) |
| Amortization of  transition obligation                        |       | —                                               |       | — |   | 3,611 |   | 3,645 |   |
| Amortization of  prior service cost (credit)                  |       | 7,424                                                |       | 7,509 |   | (544 | ) | (545 | ) |
| Amortization of  net loss                                     |       | 4,339                                                |       | 1,705 |   | 6,200 |   | 6,562 |   |
| Net periodic  benefit cost (credit)                           |       | (994                                                 | )          | (5,715 | ) | 17,470 |   | 18,673 |   |
| Credits not  recognized due to the effects of regulation      |       | 3,159                                                |       | 4,842 |   | — |   | — |   |
| Additional cost  recognized due to the effects of regulation  |       | —                                               |       | — |   | 972 |   | 972 |   |
| Net benefit cost  (credit) recognized for financial reporting |       | $                                                    | 2,165      |   | $ | (873 | ) | $ | 18,442 |   | $ | 19,645 |   |
|                                                          |       |                                                 |       |   |   |   |   |   |   |
| **PSCo**                                                      | ** ** | ** **                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net periodic  benefit cost                                    |       | $                                                    | 4,667      |   | $ | 11,431 |   | $ | 9,994 |   | $ | 10,960 |   |
| Additional cost  recognized due to the effects of regulation  |       | —                                               |       | — |   | 973 |   | 972 |   |
| Net benefit cost  recognized for financial reporting          |       | $                                                    | 4,667      |   | $ | 11,431 |   | $ | 10,967 |   | $ | 11,932 |   |

 

14

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| ** **                                                    | ** ** | **Nine months ended Sept. 30,** | ** ** |
|---------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                    | ** ** | **2006**                                            | ** ** | **2005** | ** ** | **2006** | ** ** | **2005** | ** ** |
| **(Thousands of dollars)**                          | ** ** | **Pension Benefits**                           | ** ** | **Postretirement Health  Care Benefits** | ** ** |
| **Xcel  Energy Inc.**                                         | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Service cost                                                  |       | $                                                   | 46,220     |   | $ | 45,345 |   | $ | 4,975 |   | $ | 5,013 |   |
| Interest cost                                                 |       | 116,560                                             |       | 120,738 |   | 39,704 |   | 41,295 |   |
| Expected return  on plan assets                               |       | (201,049                                            | )          | (210,048 | ) | (20,068 | ) | (19,275 | ) |
| Amortization of  transition obligation                        |       | —                                              |       | — |   | 10,833 |   | 10,934 |   |
| Amortization of  prior service cost (credit)                  |       | 22,272                                              |       | 22,527 |   | (1,634 | ) | (1,634 | ) |
| Amortization of  net loss                                     |       | 13,015                                              |       | 5,115 |   | 18,598 |   | 19,685 |   |
| Net periodic  benefit cost (credit)                           |       | (2,982                                              | )          | (16,323 | ) | 52,408 |   | 56,018 |   |
| Credits not  recognized due to the effects of regulation      |       | 9,477                                               |       | 14,526 |   | — |   | — |   |
| Additional cost  recognized due to the effects of regulation  |       | —                                              |       | — |   | 2,918 |   | 2,918 |   |
| Net benefit cost  (credit) recognized for financial reporting |       | $                                                   | 6,495      |   | $ | (1,797 | ) | $ | 55,326 |   | $ | 58,936 |   |
|                                                          |       |                                                |       |   |   |   |   |   |   |
| **PSCo**                                                      | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net periodic  benefit cost                                    |       | $                                                   | 14,000     |   | $ | (4,036 | ) | $ | 29,982 |   | $ | 32,881 |   |
| Additional cost  recognized due to the effects of regulation  |       | —                                              |       | — |   | 2,918 |   | 2,918 |   |
| Net benefit cost  (credit) recognized for financial reporting |       | $                                                   | 14,000     |   | $ | (4,036 | ) | $ | 32,900 |   | $ | 35,799 |   |

 

**Item2.**                MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

** **

Discussion of financial condition and liquidity forPSCo is omitted per conditions set forth in general instructions H (1) (a) and (b)of Form 10-Q for wholly owned subsidiaries. It is replaced with management’snarrative analysis of the results of operations set forth in generalinstructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduceddisclosure format).

 

**Forward-LookingInformation**

 

The following discussion and analysis by managementfocuses on those factors that had a material effect on the financial conditionand results of operations of PSCo during the periods presented, or are expectedto have a material impact in the future. It should be read in conjunction withthe accompanying unaudited consolidated financial statements and notes.

 

Except for the historical statements contained in thisreport, the matters discussed in the following discussion and analysis are forward-lookingstatements that are subject to certain risks, uncertainties and assumptions.Such forward-looking statements are intended to be identified in this documentby the words “anticipate,” “estimate,” “expect,” “objective,” “outlook,” “projected,”“possible,” “potential” and similar expressions. Actual results may varymaterially. Factors that could cause actual results to differ materiallyinclude, but are not limited to:

 

•    Economicconditions, including inflation rates, monetary fluctuations and their impacton capital expenditures;

•    Therisk of a significant slowdown in growth or decline in the U.S. economy, therisk of delay in growth recovery in the U.S. economy or the risk of increasedcost for insurance premiums, security and other items as a consequence of pastor future terrorist attacks;

•    Trade,monetary, fiscal, taxation and environmental policies of governments, agenciesand similar organizations in geographic areas where PSCo has a financialinterest;

•    Customerbusiness conditions, including demand for their products or services and supplyof labor and materials used in creating their products and services;

•    Financialor regulatory accounting principles or policies imposed by the FinancialAccounting Standards Board, the Securities and Exchange Commission (SEC), theFederal Energy Regulatory Commission and similar entities with regulatoryoversight;

•    Availabilityor cost of capital such as changes in: interest rates; market perceptions ofthe utility industry, PSCo, Xcel Energy or any of its subsidiaries; or securityratings;

•    Factorsaffecting utility and nonutility operations such as unusual weather conditions;catastrophic weather-related damage; unscheduled generation outages,maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel ornatural gas supply costs or availability due to higher demand, shortages,transportation problems or other developments; nuclear or environmentalincidents; or electric transmission or gas pipeline constraints;

•    Employeeworkforce factors, including loss or retirement of key executives, collectivebargaining agreements with union employees, or work stoppages;

 

15

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•    Increasedcompetition in the utility industry or additional competition in the marketsserved by PSCo;

•    State,federal and foreign legislative and regulatory initiatives that affect cost andinvestment recovery, have an impact on rate structures and affect the speed anddegree to which competition enters the electric and natural gas markets;industry restructuring initiatives; transmission system operation and/oradministration initiatives; recovery of investments made under traditionalregulation; nature of competitors entering the industry; retail wheeling; a newpricing structure; and former customers entering the generation market;

•    Rate-settingpolicies or procedures of regulatory entities, including environmentalexternalities, which are values established by regulators assigningenvironmental costs to each method of electricity generation when evaluatinggeneration resource options;

•    Socialattitudes regarding the utility and power industries;

•    Costand other effects of legal and administrative proceedings, settlements,investigations and claims;

•    Technologicaldevelopments that result in competitive disadvantages and create the potentialfor impairment of existing assets;

•    Risksassociated with implementations of new technologies;

•    Otherbusiness or investment considerations that may be disclosed from time to timein PSCo’s SEC filings or in other publicly disseminated written documents; and

•    Theother risk factors listed from time to time by PSCo in reports filed with theSEC, including Risk Factors in Item 1A of PSCo’s Annual Report on Form 10-K forthe year ended Dec. 31, 2005 and Exhibit 99.01 to this report onForm 10-Q for the quarter ended Sept. 30, 2006.

 

**Market Risks**

 

PSCo is exposed to market risks, including changes incommodity prices and interest rates, as disclosed in Item 7A — Quantitative andQualitative Disclosures About Market Risk in its Annual Report on Form 10-K forthe year ended Dec. 31, 2005. Commodity price and interest rate risks for PSCoare mitigated due to cost-based rate regulation. At Sept. 30, 2006, there wereno material changes to the financial market risks that affect the quantitativeand qualitative disclosures presented as of Dec. 31, 2005.

 

**RESULTS OF OPERATIONS**

 

PSCo’s net income was approximately $176.4 millionfor the first nine months of 2006, compared with approximately $158.5 millionfor the first nine months of 2005.

 

**Electric Utility, Short-termWholesale and Commodity Trading Margins**

 

Electric fuel and purchased power expenses tend tovary with changing retail and wholesale sales requirements and unit costchanges in fuel and purchased power. Due to fuel and purchased energycost-recovery mechanisms for customers, most fluctuations in these costs do notsignificantly affect electric utility margin.

 

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

 

Margins from commodity trading activity conducted atPSCo are partially redistributed to Northern States Power Company, a Minnesotacorporation, and SPS, both wholly owned subsidiaries of Xcel Energy, pursuantto the joint operating agreement (JOA) approved by the FERC. Margins receivedpursuant to the JOA are reflected as part of Base Electric Utility Revenue.Trading revenues are reported net of trading costs in the ConsolidatedStatements of Income. Commodity trading costs include fuel, purchased power,transmission, broker fees and other related costs. Short-term wholesale andcommodity trading margins reflect the estimated impact of regulatory sharing ofmargins, if applicable.

 

16

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

 
| **(Millions of dollars)**                     | ** ** | **Base  Electric  Utility** | ** ** | **Short-term  Wholesale** | ** ** | **Commodity  Trading** | ** ** | **Consolidated  Total** | ** ** |
|---------------------------------------------------------|------------|-----------------------------|------------|---------------------------|------------|------------------------|------------|-------------------------|------------|
| ** **                                              | ** ** | ** **                  | ** ** | ** **                | ** ** | ** **             | ** ** | ** **              | ** ** |
| **Nine  months ended Sept. 30, 2006**                   | ** ** | ** **                  | ** ** | ** **                | ** ** | ** **             | ** ** | ** **              | ** ** |
| Electric utility  revenue (excluding commodity trading) |       | $                           | 1,884      |                      | $          | 29                     |       | $                       | —     |   | $ | 1,913 |   |
| Electric fuel  and purchased power                      |       | (1,132                      | )          | (26                       | )          | —                 |       | (1,158                  | )          |
| Commodity  trading revenue                              |       | —                      |       | —                    |       | 404                    |       | 404                     |       |
| Commodity  trading costs                                |       | —                      |       | —                    |       | (400                   | )          | (400                    | )          |
| Gross margin  before operating expenses                 |       | $                           | 752        |                      | $          | 3                      |       | $                       | 4          |   | $ | 759 |   |
| Margin as a  percentage of revenue                      |       | 39.9                        | %          | 10.3                      | %          | 1.0                    | %          | 32.8                    | %          |
|                                                    |       |                        |       |                      |       |                   |       |                    |       |
| **Nine  months ended Sept. 30, 2005**                   | ** ** | ** **                  | ** ** | ** **                | ** ** | ** **             | ** ** | ** **              | ** ** |
| Electric utility  revenue (excluding commodity trading) |       | $                           | 1,800      |                      | $          | 11                     |       | $                       | —     |   | $ | 1,811 |   |
| Electric fuel  and purchased power                      |       | (1,051                      | )          | (11                       | )          | —                 |       | (1,062                  | )          |
| Commodity  trading revenue                              |       | —                      |       | —                    |       | 387                    |       | 387                     |       |
| Commodity  trading costs                                |       | —                      |       | —                    |       | (391                   | )          | (391                    | )          |
| Gross margin  before operating expenses                 |       | $                           | 749        |                      | $          | —                 |       | $                       | (4         | ) | $ | 745 |   |
| Margin as a  percentage of revenue                      |       | 41.6                        | %          | —                    | %          | (1.0                   | )%         | 33.9                    | %          |

 

The following summarizes the components of thechanges in base electric revenue and base electric margin for the nine monthsended Sept. 30:

 

# ***Base ElectricRevenue***

 
| **(Millions of dollars)**      | ** ** | **2006 vs. 2005** | ** ** |
|------------------------------------------|------------|-----------------------------|------------|
| ** **                               | ** ** | ** **                  | ** ** |
| Fuel cost  recovery                      |       | $                           | 67         |   |
| Quality of  service plan                 |       | 14                          |       |
| Sales growth  (excluding weather impact) |       | 7                           |       |
| Non-fuel rider  revenue                  |       | 3                           |       |
| Estimated impact  of weather             |       | 2                           |       |
| Sales mix                                |       | (8                          | )          |
| Other                                    |       | (1                          | )          |
| Total base  electric revenue increase    |       | $                           | 84         |   |

 

***Base ElectricMargin***

 
| **(Millions of dollars)**      | ** ** | **2006 vs. 2005** | ** ** |
|------------------------------------------|------------|-----------------------------|------------|
| ** **                               | ** ** | ** **                  | ** ** |
| Quality of  service plan                 |       | $                           | 14         |   |
| Sales growth  (excluding weather impact) |       | 7                           |       |
| Non-fuel rider  revenue                  |       | 3                           |       |
| Estimated impact  of weather             |       | 2                           |       |
| Sales mix                                |       | (8                          | )          |
| ECA incentive                            |       | (18                         | )          |
| Other                                    |       | 3                           |       |
| Total base  electric margin increase     |       | $                           | 3          |   |

 

17

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**Natural Gas Utility Margins**

 

The following table details the change in naturalgas revenue and margin. The cost of natural gas tends to vary with changingsales requirements and unit cost of natural gas purchases. PSCo has a Gas CostAdjustment (GCA) mechanism for natural gas sales, which recognizes the majorityof the effects 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 of natural gas have little effect on natural gasmargin.

 
| ** **                                | ** ** | **Nine Months ended Sept. 30,** | ** ** |
|-------------------------------------------|------------|-----------------------------------------------------|------------|
| **(Millions of dollars)**       | ** ** | **2006**                                            | ** ** | **2005** | ** ** |
| ** **                                | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| Natural gas utility  revenue              |       | $                                                   | 885        |   | $ | 774 |   |
| Cost of natural  gas sold and transported |       | (655                                                | )          | (567 | ) |
| Natural gas  utility margin               |       | $                                                   | 230        |   | $ | 207 |   |

 

The following summarizes the components of the changesin natural gas revenue and margin for the nine months ended Sept. 30:

 

***Natural Gas Revenue***

 
| **(Millions of dollars)**               | ** ** | **2006 vs. 2005** | ** ** |
|---------------------------------------------------|------------|-----------------------------|------------|
| ** **                                        | ** ** | ** **                  | ** ** |
| Purchased gas  adjustment clause recovery         |       | $                           | 94         |   |
| Base rate  increase                               |       | 13                          |       |
| Sales growth  (excluding weather impact)          |       | 2                           |       |
| Estimated impact  of weather on firm sales volume |       | (1                          | )          |
| Transport and  other                              |       | 3                           |       |
| Total natural  gas revenue increase               |       | $                           | 111        |   |

 

***Natural Gas Margin***

 
| **(Millions of dollars)**               | ** ** | **2006 vs. 2005** | ** ** |
|---------------------------------------------------|------------|-----------------------------|------------|
| ** **                                        | ** ** | ** **                  | ** ** |
| Base rate  increase                               |       | $                           | 13         |   |
| Transportation                                    |       | 7                           |       |
| Sales growth  (excluding weather impact)          |       | 2                           |       |
| Estimated impact  of weather on firm sales volume |       | (1                          | )          |
| Other                                             |       | 2                           |       |
| Total natural  gas margin increase                |       | $                           | 23         |   |

 

**Non-Fuel Operating Expense and OtherItems**

 

The following summarizes the components of thechanges in other utility operating and maintenance expense for the nine monthsended Sept. 30:

 
| **(Millions of dollars)**               | ** ** | **2006 vs. 2005** | ** ** |
|---------------------------------------------------|------------|-----------------------------|------------|
| ** **                                        | ** ** | ** **                  | ** ** |
| Higher employee  benefit costs                    |       | $                           | 12         |   |
| Higher plant  costs                               |       | 4                           |       |
| Higher  application and development costs         |       | 3                           |       |
| Higher  transportation costs                      |       | 1                           |       |
| Other                                             |       | 3                           |       |
| Total operating  and maintenance expense increase |       | $                           | 23         |   |

 

Income tax expense increased by approximately $10.1million for the first nine months of 2006 compared with the first nine monthsof 2005. The effective tax rate was 25.3 percent for the first nine months of2006, compared with 23.8 percent for the same period in 2005. The increase intax expense and the effective tax rate was primarily due to an increase inpretax income.

 

18

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**Item 4. CONTROLS AND PROCEDURES**

** **

**Disclosure Controls and Procedures**

 

PSCo maintains a set of disclosure controls andprocedures designed to ensure that information required to be disclosed inreports that it files or submits under the Securities Exchange Act of 1934 isrecorded, processed, summarized and reported within the time periods specifiedin Securities and Exchange Commission rules and forms. In addition, thedisclosure controls and procedures ensure that information required to bedisclosed is accumulated and communicated to management, including the chief executiveofficer (CEO) and chief financial officer (CFO), allowing timely decisionsregarding required disclosure. As of the end of the period covered by thisreport, based on an evaluation carried out under the supervision and with theparticipation of PSCo’s management, including the CEO and CFO, of theeffectiveness of our disclosure controls and procedures, the CEO and CFO haveconcluded that PSCo’s disclosure controls and procedures are effective.

 

**InternalControl Over Financial Reporting**

 

No change in PSCo’s internal control over financialreporting has occurred during the most recent fiscal quarter that hasmaterially affected, or is reasonably likely to materially affect, its internalcontrol over financial reporting.

 

**Part II. OTHER INFORMATION**

** **

**Item 1. LEGAL PROCEEDINGS**

** **

In the normal course of business, various lawsuitsand claims have arisen against PSCo. Management, after consultation with legalcounsel, has recorded an estimate of the probable cost of settlement or otherdisposition for such matters. See Notes 2, 3 and 4 to the ConsolidatedFinancial Statements in this Form 10-Q for further discussion of legalproceedings, including Regulatory Matters and Commitments and ContingentLiabilities, which are hereby incorporated by reference. Reference also is madeto Item 3 and Note 12 of PSCo’s Annual Report on Form 10-K for the year endedDec. 31, 2005 for a description of certain legal proceedings presently pending.Except as set forth above and below, there are no new significant cases toreport against PSCo, and there have been no notable changes in the previouslyreported proceedings.

 

**Item 1A. RISK FACTORS**

 

PSCo’srisk factors are documented in Item 1A of Part I of its 2005 Annual Report onForm 10-K, which is incorporated herein by reference. There have been nomaterial changes to the risk factors.

 

**Item 6. EXHIBITS**

** **

The following Exhibits are filed with this report:

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

 

19

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**SIGNATURES**

 

Pursuant to the requirements of the SecuritiesExchange Act of 1934, the registrant has duly caused this report to be signedon its behalf by the undersigned thereunto duly authorized on Oct. 30, 2006.

 

Public Service Co. ofColorado

(Registrant)

 

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

 

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