**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**_______________________**

 

**FORM** **10-Q**

 

| **(Mark One)**                                                              |                                                                  |
|-----------------------------------------------------------------------------|-----------------------------------------------------------------------|
| **x**                                                                       | **QUARTERLY REPORT PURSUANT TO SECTION** **13 OR 15(d) OF THE**  |
|                                                                        | **SECURITIES EXCHANGE ACT OF 1934**                                   |
|                                                                        |
| **For the quarterly period ended September 30, 2006**                       |
|                                                                        |
| **OR**                                                                      |
|                                                                        |
| **o**                                                                       | **TRANSITION REPORT PURSUANT TO SECTION** **13 OR 15(d) OF THE** |
|                                                                        | **SECURITIES EXCHANGE ACT OF 1934**                                   |
|                                                                        |
| **For the transition period from** **__________ to** **________** |
|                                                                        |
| **Commission file number: 1-03562**                                         |

 

**_______________________**

 

**AQUILA,** **INC.**

(Exact name of registrant as specified in its charter)

 

| **Delaware**                             | **44-0541877**                    |
|------------------------------------------|-----------------------------------|
| (State or other jurisdiction of          | (IRS Employer Identification No.) |
| incorporation or organization)           |                              |
|                                     |                              |
| **20 West Ninth Street, Kansas City,**   | **64105**                         |
| **Missouri**                             | (Zip Code)                        |
| (Address of principal executive offices) |                              |

 

Registrant’s telephone number, including area code **816-421-6600**

**_______________________**

 

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

 

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

 

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

 

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

 

| **Class**                  | **Outstanding at October 27, 2006** |
|----------------------------|-------------------------------------|
| Common Stock, $1 par value | 374,472,263                         |

 

 

 

**PART** **I—FINANCIAL INFORMATION**

 

*ITEM* *1. FINANCIAL STATEMENTS*

 

Information regarding the consolidated financial statements is on pages 3 through 29.

 

*ITEM* *2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*

 

Management’s discussion and analysis of financial condition and results of operations is on pages 29 through 53.

 

*ITEM* *3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK*

 

We are subject to market risk as described on pages 71 through 74 of our 2005 Annual Report on Form 10-K.  See discussion on pages 53 and 54 of this document for changes in market risk since December 31, 2005.

 

*ITEM* *4. CONTROLS AND PROCEDURES*

 

Information regarding disclosure controls and procedures is on page 54.

 

**PART** **II—OTHER INFORMATION**

 

*ITEM* *1. LEGAL PROCEEDINGS*

 

Information regarding legal proceedings is on page 55.

 

*ITEM 1A. RISK FACTORS*

 

See pages 22 through 26 of our 2005 Annual Report on Form 10-K for a discussion of risk factors.

 

*ITEM* *2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS*

 

Not applicable.

 

*ITEM* *3. DEFAULTS UPON SENIOR SECURITIES*

 

Not applicable.

 

*ITEM* *4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS*

 

Not applicable.

 

*ITEM* *5. OTHER INFORMATION*

 

Not applicable.

 

*ITEM* *6. EXHIBITS*

 

Exhibits are on page 55.

**Part** **I.  Financial Information**

**Item 1.  Financial Statements**

 

**Aquila,** **Inc.**

**Consolidated Statements of Income—Unaudited**

 

|                                                            | **Three Months Ended** |
|-----------------------------------------------------------------|------------------------|
|                                                            | **September 30,**      |
| *In millions, except per share amounts*                         | **2006**               | **2005** |
| **Sales:**                                                      |                   |   |   |   |
| Electricity—regulated                                      | $                      | 242.8 | $ | 215.3 |
| Natural gas—regulated                                      |                   | 71.4 |   | 74.1 |
| Other—non-regulated                                        |                   | 2.4 |   | 11.4 |
| **Total sales**                                                 |                   | 316.6 |   | 300.8 |
| **Cost of sales:**                                              |                   |   |   |   |
| Electricity—regulated                                      |                   | 135.0 |   | 89.9 |
| Natural gas—regulated                                      |                   | 43.9 |   | 46.7 |
| Other—non-regulated                                        |                   | 2.9 |   | 14.6 |
| **Total cost of sales**                                         |                   | 181.8 |   | 151.2 |
| **Gross profit**                                                |                   | 134.8 |   | 149.6 |
| **Operating expenses:**                                         |                   |   |   |   |
| Operation and maintenance expense                               |                   | 87.8 |   | 79.3 |
| Taxes other than income taxes                                   |                   | 8.5 |   | 7.0 |
| Restructuring charges                                           |                   | .6 |   | – |
| Net loss on sale of assets and other charges                    |                   | 5.5 |   | 82.3 |
| Depreciation and amortization expense                           |                   | 27.0 |   | 26.0 |
| **Total operating expenses**                                    |                   | 129.4 |   | 194.6 |
| **Operating income (loss)**                                     |                   | 5.4 |   | (45.0) |
| Other income (expense), net                                     |                   | 6.5 |   | 2.6 |
| Interest expense                                                |                   | 42.7 |   | 35.6 |
| **Loss from continuing operations before income taxes**         |                   | (30.8) |   | (78.0) |
| **Income tax expense (benefit)**                                |                   | (10.2) |   | 2.0 |
| **Loss from continuing operations**                             |                   | (20.6) |   | (80.0) |
| **Earnings from discontinued operations, net of tax**           |                   | 136.3 |   | 4.3 |
| **Net income (loss)**                                           | $                      | 115.7 | $ | (75.7) |
|  

**Basic and diluted earnings (loss) per common share:** |                   |   |   |   |
| Continuing operations                                           | $                      | (.05) | $ | (.21) |
| Discontinued operations                                         |                   | .36 |   | .01 |
| Net income (loss)                                               | $                      | .31 | $ | (.20) |
|  

**Dividends per common share**                          | $                      | – | $ | – |

See accompanying notes to consolidated financial statements.

 

3

**Aquila,** **Inc.**

**Consolidated Statements of Income—Unaudited**

 

|                                                            | **Nine Months Ended** |
|-----------------------------------------------------------------|-----------------------|
|                                                            | **September 30,**     |
| *In millions, except per share amounts*                         | **2006**              | **2005** |
| **Sales:**                                                      |                  |   |   |   |
| Electricity—regulated                                      | $                     | 601.0 | $ | 517.3 |
| Natural gas—regulated                                      |                  | 413.3 |   | 386.1 |
| Other—non-regulated                                        |                  | 16.3 |   | 13.0 |
| **Total sales**                                                 |                  | 1,030.6 |   | 916.4 |
| **Cost of sales:**                                              |                  |   |   |   |
| Electricity—regulated                                      |                  | 327.7 |   | 246.6 |
| Natural gas—regulated                                      |                  | 300.2 |   | 276.0 |
| Other—non-regulated                                        |                  | 33.3 |   | 40.8 |
| **Total cost of sales**                                         |                  | 661.2 |   | 563.4 |
| **Gross profit**                                                |                  | 369.4 |   | 353.0 |
| **Operating expenses:**                                         |                  |   |   |   |
| Operation and maintenance expense                               |                  | 240.8 |   | 230.6 |
| Taxes other than income taxes                                   |                  | 22.6 |   | 15.8 |
| Restructuring charges                                           |                  | 5.5 |   | 6.6 |
| Net loss on sale of assets and other charges                    |                  | 246.9 |   | 56.7 |
| Depreciation and amortization expense                           |                  | 78.5 |   | 78.4 |
| **Total operating expenses**                                    |                  | 594.3 |   | 388.1 |
| **Operating loss**                                              |                  | (224.9) |   | (35.1) |
| Other income (expense), net                                     |                  | 14.4 |   | 13.7 |
| Interest expense                                                |                  | 124.4 |   | 115.5 |
| **Loss from continuing operations before income taxes**         |                  | (334.9) |   | (136.9) |
| **Income tax benefit**                                          |                  | (43.9) |   | (20.1) |
| **Loss from continuing operations**                             |                  | (291.0) |   | (116.8) |
| **Earnings from discontinued operations, net of tax**           |                  | 250.6 |   | 14.6 |
| **Net loss**                                                    | $                     | (40.4) | $ | (102.2) |
|  

**Basic and diluted earnings (loss) per common share:** |                  |   |   |   |
| Continuing operations                                           | $                     | (.78) | $ | (.29) |
| Discontinued operations                                         |                  | .67 |   | .04 |
| Net loss                                                        | $                     | (.11) | $ | (.25) |
|  

**Dividends per common share**                          | $                     | – | $ | – |

See accompanying notes to consolidated financial statements.

 

4

 

**Aquila,** **Inc.**

**Consolidated Balance Sheets**

 

|                                                | **September 30,** | **December 31,** |
|-----------------------------------------------------|-------------------|------------------|
| *In millions*                                       | **2006**          | **2005**         |
|                                                |              | (Unaudited)      |   |   |
| **Assets**                                          |              |             |   |   |
| **Current assets:**                                 |              |             |   |   |
| Cash and cash equivalents                           | $                 | 216.5            | $ | 14.2 |
| Short-term investments                              |              | 42.5             |   | – |
| Restricted cash                                     |              | 9.2              |   | 10.9 |
| Funds on deposit                                    |              | 116.6            |   | 264.9 |
| Accounts receivable, net                            |              | 195.2            |   | 399.7 |
| Inventories and supplies                            |              | 126.1            |   | 107.3 |
| Price risk management assets                        |              | 94.8             |   | 200.0 |
| Other current assets                                |              | 48.1             |   | 78.1 |
| Current assets of discontinued operations           |              | 25.8             |   | 269.0 |
| **Total current assets**                            |              | 874.8            |   | 1,344.1 |
|                                                |              |             |   |   |
| Utility plant, net                                  |              | 1,773.4          |   | 1,741.9 |
| Non-utility plant, net                              |              | 129.3            |   | 135.4 |
| Price risk management assets                        |              | 60.5             |   | 177.7 |
| Goodwill, net                                       |              | 111.0            |   | 111.0 |
| Prepaid pension                                     |              | 58.4             |   | 68.3 |
| Deferred charges and other assets                   |              | 163.6            |   | 154.4 |
| Non-current assets of discontinued operations       |              | 269.5            |   | 897.9 |
| **Total Assets**                                    | $                 | 3,440.5          | $ | 4,630.7 |
|                                                |              |             |   |   |
| **Liabilities and Shareholders’ Equity**       |              |             |   |   |
| **Current liabilities:**                            |              |             |   |   |
| Current maturities of long-term debt                | $                 | 18.4             | $ | 88.3 |
| Short-term debt                                     |              | –           |   | 12.0 |
| Accounts payable                                    |              | 115.0            |   | 356.2 |
| Accrued interest                                    |              | 38.7             |   | 64.6 |
| Other accrued liabilities                           |              | 160.0            |   | 184.4 |
| Price risk management liabilities                   |              | 89.4             |   | 164.9 |
| Customer funds on deposit                           |              | 14.0             |   | 74.0 |
| Current liabilities of discontinued operations      |              | 1.2              |   | 30.5 |
| **Total current liabilities**                       |              | 436.7            |   | 974.9 |
| **Long-term liabilities:**                          |              |             |   |   |
| Long-term debt, net                                 |              | 1,389.0          |   | 1,891.2 |
| Deferred income taxes and credits                   |              | 103.9            |   | 71.5 |
| Price risk management liabilities                   |              | 50.4             |   | 138.9 |
| Deferred credits                                    |              | 165.9            |   | 180.7 |
| Non-current liabilities of discontinued operations  |              | 22.5             |   | 63.6 |
| **Total long-term liabilities**                     |              | 1,731.7          |   | 2,345.9 |
|                                                |              |             |   |   |
| **Common shareholders’ equity**                |              | 1,272.1          |   | 1,309.9 |
| **Total Liabilities and Shareholders’ Equity** | $                 | 3,440.5          | $ | 4,630.7 |

 

See accompanying notes to consolidated financial statements.

 

5

**Aquila,** **Inc.**

**Consolidated Statements of Comprehensive Income—Unaudited**

 

| * *                                                                                                                                                                                                                                           | **Three Months Ended** | **Nine Months Ended** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------------------|-----------------------|
| * *                                                                                                                                                                                                                                           | **September 30,**      | **September 30,**     |
| *In millions***                                                                                                                                                                                                                                    | **2006**               | **2005**              | **2006** | **2005** |
| **Net income (loss)**                                                                                                                                                                                                                              | $                      | 115.7                 | $ | (75.7) | $ | (40.4) | $ | (102.2) |
| **Other comprehensive income (loss), net of related tax:**                                                                                                                                                                                         |                   |                  |   |   |   |   |   |   |
| Foreign currency adjustments:                                                                                                                                                                                                                      |                   |                  |   |   |   |   |   |   |
| Foreign currency translation adjustments, net of deferred tax expense (benefit) of $.1 million and $.5 million for the three months ended September 30, 2006 and 2005, respectively and $(.3) million for the nine months ended September 30, 2006 |                   | .2                    |   | .8 |   | (.4) |   | – |
| Reclassification of foreign currency (gains) losses to income, net of deferred tax (expense) benefit of $– million and $.3 million for the three and nine months ended September 30, 2006, respectively                                       |                   | (.1)                  |   | – |   | .5 |   | – |
| Total foreign currency adjustments                                                                                                                                                                                                                 |                   | .1                    |   | .8 |   | .1 |   | – |
| Other comprehensive income                                                                                                                                                                                                                         |                   | .1                    |   | .8 |   | .1 |   | – |
| **Total Comprehensive Income (Loss)**                                                                                                                                                                                                              | $                      | 115.8                 | $ | (74.9) | $ | (40.3) | $ | (102.2) |

 

See accompanying notes to consolidated financial statements.

 

6

**Aquila, Inc.**

**Consolidated Statements of Common Shareholders' Equity**

 

| *In millions*                                                                                                                                                                                                                                                                                                                                | **September 30,****2006** | **December 31,****2005** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------|--------------------------|
|                                                                                                                                                                                                                                                                                                                                         | (Unaudited)               |                     |   |
| Common stock: authorized 400 million shares at September 30, 2006 and December 31, 2005, par value $1 per share; 374,542,735 shares issued at September 30, 2006 and 373,603,277 shares issued at December 31, 2005; authorized 20 million shares of Class A common stock, par value $1 per share, none issued | $                         | 374.5                    | $ | 373.6 |
| Premium on capital stock                                                                                                                                                                                                                                                                                                                     |                      | 3,508.9                  |   | 3,507.0 |
| Retained deficit                                                                                                                                                                                                                                                                                                                             |                      | (2,611.0)                |   | (2,570.6) |
| Treasury stock, at cost 84,029 shares at September 30, 2006 (7 shares at December 31, 2005)                                                                                                                                                                                                                                                  |                      | (.3)                     |   | – |
| Accumulated other comprehensive loss                                                                                                                                                                                                                                                                                                         |                      | –                   |   | (.1) |
| **Total Common Shareholders’ Equity**                                                                                                                                                                                                                                                                                                   | $                         | 1,272.1                  | $ | 1,309.9 |

 

See accompanying notes to consolidated financial statements.

 

7

**Aquila, Inc.**

**Consolidated Statements of Cash Flows—Unaudited**

 

|                                                                                                                                                                                    | **Nine Months Ended** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------------|
|                                                                                                                                                                                    | **September 30,**     |
| *In millions*                                                                                                                                                                           | **2006**              | **2005** |
|                                                                                                                                                                                    |                  |   |   |   |
| **Cash Flows From Operating Activities:**                                                                                                                                               |                  |   |   |   |
| Net loss                                                                                                                                                                                | $                     | (40.4) | $ | (102.2) |
| Adjustments to reconcile net loss to net cash provided from operating activities:                                                                                                       |                  |   |   |   |
| Depreciation and amortization expense                                                                                                                                                   |                  | 79.5 |   | 116.9 |
| Restructuring charges                                                                                                                                                                   |                  | 7.5 |   | 6.6 |
| Cash paid for restructuring and other charges                                                                                                                                           |                  | (222.2) |   | (1.8) |
| Net (gain) loss on sale of assets and other charges                                                                                                                                     |                  | (24.0) |   | 56.7 |
| Foreign currency losses                                                                                                                                                                 |                  | .5 |   | – |
| Net changes in price risk management assets and liabilities                                                                                                                             |                  | 67.3 |   | (143.5) |
| Deferred income taxes and investment tax credits                                                                                                                                        |                  | 33.0 |   | (9.2) |
| Dividends and fees from investments                                                                                                                                                     |                  | – |   | .5 |
| Changes in certain assets and liabilities, net of effects of divestitures:                                                                                                              |                  |   |   |   |
| Restricted cash                                                                                                                                                                         |                  | 1.7 |   | 5.4 |
| Funds on deposit                                                                                                                                                                        |                  | 148.3 |   | 108.7 |
| Accounts receivable/payable, net                                                                                                                                                        |                  | 29.4 |   | 35.7 |
| Inventories and supplies                                                                                                                                                                |                  | 18.0 |   | (71.1) |
| Prepaid pension and other current assets                                                                                                                                                |                  | 41.3 |   | 26.1 |
| Deferred charges and other assets                                                                                                                                                       |                  | (15.3) |   | (5.2) |
| Accrued interest and other accrued liabilities                                                                                                                                          |                  | (69.7) |   | 52.5 |
| Customer funds on deposit                                                                                                                                                               |                  | (60.1) |   | 130.4 |
| Deferred credits                                                                                                                                                                        |                  | (4.7) |   | 5.3 |
| Other                                                                                                                                                                                   |                  | (1.0) |   | (.5) |
| **Cash provided from (used for) operating activities**                                                                                                                                  |                  | (10.9) |   | 211.3 |
| **Cash Flows From Investing Activities:**                                                                                                                                               |                  |   |   |   |
| Utilities capital expenditures                                                                                                                                                          |                  | (115.0) |   | (175.9) |
| Cash proceeds received on sale of assets                                                                                                                                                |                  | 1,003.0 |   | 13.8 |
| Purchases of short-term investments                                                                                                                                                     |                  | (42.5) |   | (45.3) |
| Other                                                                                                                                                                                   |                  | (14.8) |   | (13.1) |
| **Cash provided from (used for) investing activities**                                                                                                                                  |                  | 830.7 |   | (220.5) |
| **Cash Flows From Financing Activities:**                                                                                                                                               |                  |   |   |   |
| Premium on the retirement of long-term debt                                                                                                                                             |                  | (28.2) |   | – |
| Issuance of long-term debt                                                                                                                                                              |                  | – |   | 2.0 |
| Retirement of long-term debt                                                                                                                                                            |                  | (572.8) |   | (23.4) |
| Short-term borrowings (repayments), net                                                                                                                                                 |                  | (12.0) |   | – |
| Cash paid on long-term gas contracts                                                                                                                                                    |                  | (11.7) |   | (11.0) |
| Other                                                                                                                                                                                   |                  | 2.4 |   | .8 |
| **Cash used for financing activities**                                                                                                                                                  |                  | (622.3) |   | (31.6) |
| Increase (decrease) in cash and cash equivalents                                                                                                                                        |                  | 197.5 |   | (40.8) |
| Cash and cash equivalents at beginning of period  (includes $4.8 million and $6.6 million of cash included in current assets of discontinued operations in 2006 and 2005, respectively) |                  | 19.0 |   | 225.1 |
| **Cash and cash equivalents at end of period (includes $6.3 million of cash included in current assets of discontinued operations in 2005)**                                            | $                     | 216.5 | $ | 184.3 |

 

See accompanying notes to consolidated financial statements.

 

8

**AQUILA,** **INC.**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**(Unaudited)**

 

**1.  Summary of Significant Accounting Policies**

 

**Basis of Presentation**

 

The accompanying unaudited consolidated financial statements have been prepared in accordance with the accounting policies described in the consolidated financial statements and related notes included in our 2005 Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC) on March 7, 2006.  You should read our 2005 Form 10-K in conjunction with this report.  The accompanying Consolidated Balance Sheets and Consolidated Statements of Common Shareholders’ Equity as of December 31, 2005, were derived from our audited financial statements, but do not include all disclosures required by accounting principles generally accepted in the United States.  In our opinion, the accompanying consolidated financial statements reflect all adjustments (which include only normal recurring adjustments) necessary for a fair representation of our financial position and theresults of our operations. Certain estimates and assumptions have been made in preparing the consolidated financial statements that affect reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of sales and expenses during the reporting periods shown.  Actual results could differ from these estimates.

 

Certain prior year amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2006 presentation.  In particular, as discussed in Note 4, the results of operations from certain utilities and other businesses that we have sold or agreed to sell have been reclassified as discontinued operations in the accompanying balance sheets and statements of income for all periods presented. 

 

Our consolidated financial statements include all of our operating divisions and majority-owned subsidiaries for which we maintain controlling interests, including Aquila Merchant Services, Inc. (Aquila Merchant).  Aquila Merchant is our wholly-owned subsidiary that conducts our remaining Merchant Services business, which is in the process of being wound down.

 

***Seasonal Variations of Business***

 

Our electric and gas utility businesses are weather-sensitive. We have both summer- and winter-peaking network assets to reduce dependence on a single peak season. The table below shows normal utility peak seasons. 

 

| **Operations**     | **Peak**               |
|--------------------|------------------------|
| Gas Utilities      | November through March |
| Electric Utilities | July and August        |

 

**New Accounting Standards**

 

**Fair Value Measurements**

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS 157), which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This statement is effective for our financial statements as of January 1, 2008. We are currently evaluating the impact SFAS 157 may have on our financial condition or results of operations. 

 

9

**Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans**

 

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS 158). SFAS 158 requires an employer to recognize the over-funded or under-funded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income.  Under SFAS 158, we will be required to recognize the funded status of our defined benefit and other postretirement plans and to provide the required disclosures commencing as of December 31, 2006. SFAS 158 also requires companies to use a measurement date that is the same as its fiscal year-end.  For our financial statements as ofDecember 31, 2008, we will have to change our September 30 measurement date for our plans’ assets and obligations to comply with this requirement.  In addition, we may be required to record a deferred tax benefit associated with the temporary differences between liabilities recognized for tax and book purposes under SFAS 158. 

 

Based upon our September 30, 2005 valuation information, we would have reduced Accumulated other comprehensive income (net of tax) by approximately $74 million. Our estimate has been adjusted to reflect the sale of our Michigan, Minnesota, and Missouri natural gas businesses as well as the proposed sale of our Kansas electric distribution business which is expected to close during the first quarter of 2007.  The actual impact of adopting SFAS 158 will be dependent upon the current fair value of plan assets and the amount of projected benefit obligation, measured as of the adoption date.  Additionally, adjustments for the final transfer of pension assets related to the sales states as well as the sale of the Kansas electric distribution business will be required.  Further, if we determine that it is probable that the additional liabilities will be recoverable through customer rates chargedby our rate-regulated utility operations, a regulatory asset may be recorded.  We are currently evaluating the impact that SFAS 158 will have on our consolidated financial position and our credit or debt ratios or financing covenants.  

 

**Considering the Effects of Prior Year Misstatements**

 

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB 108), which addresses how the effects of prior year misstatements should be considered when quantifying misstatements in current year financial statements. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to beginning retained earnings as of January 1, 2006 for errors that were not previously deemed material, but would be material under the guidance in SAB 108. We do not expect the implementation of SAB 108 to have a material impact on our financial condition and results of operations.

 

**Accounting for Uncertainty in Income Taxes**

 

In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), effective for fiscal years beginning after December 15, 2006.  This interpretation sets a “more likely than not” threshold that must be met before a tax benefit can be recognized in our financial statements.  Our current practice is to recognize tax benefits when their ultimate realization is deemed to be “probable”.  We will adopt FIN 48 in the first quarter of 2007.  Based upon our preliminary analysis we expect our reserve for contingent tax liabilities to be significantly reduced upon adoption of this interpretation.  This reduction will be effected through an increase to beginning retained earnings.   

 

After implementation of FIN 48 we expect to be in a net deferred tax asset position.  The primary deferred tax asset will be the tax benefit related to our net operating loss carryforwards.  As a result, 

 

10

we will be required to assess whether a valuation allowance is necessary.  If a valuation allowance is necessary it will be recognized through an increase to tax expense in the first quarter of 2007.

 

**Accounting for Planned Major Maintenance**

 

In September 2006, the FASB issued FASB Staff Position (FSP) AUG AIR-1 “Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1).  FSP AUG AIR-1 amends the guidance on the accounting for planned major maintenance activities; specifically, it precludes the use of the previously acceptable “accrue in advance” method, which we currently follow as allowed by regulatory authorities.  FSP AUG AIR-1 is effective for our financial statements as of January 1, 2007, and is to be applied retrospectively.  If we determine that it is probable that the cost of planned major maintenance will continue to be recoverable through customer rates charged by our rate-regulated utility operations in advance of such maintenance being performed, a regulatory liability may be recorded.  As of September 30, 2006, our accrued liability for planned major maintenance was $5.3 million.  Weare currently evaluating the impact FSP AUG AIR-1 may have on our financial condition and results of operations.

 

**2.  Restructuring Charges**

 

We recorded the following restructuring charges:

 

|                                | **Three Months Ended** | **Nine Months Ended** |
|-------------------------------------|------------------------|-----------------------|
|                                | **September 30,**      | **September 30,**     |
| *In millions*                       | **2006**               | **2005**              | **2006** | **2005** |
| Merchant Services:                  |                   |                  |   |   |   |   |   |   |
| Lease agreements                    | $                      | –                | $ | – | $ | – | $ | 6.6 |
| Total Merchant Services             |                   | –                |   | – |   | – |   | 6.6 |
| Corporate and Other severance costs |                   | .6                    |   | – |   | 5.5 |   | – |
| Total restructuring charges         | $                      | .6                    | $ | – | $ | 5.5 | $ | 6.6 |

 

**Severance Costs and Retention Payments**

 

In connection with the sale of our Kansas electric and Michigan, Minnesota and Missouri gas utility operations, during the first quarter of 2006 our management adopted and communicated to employees a plan to reduce executive management and central services costs, which includes the elimination of approximately 220 positions through attrition and employee terminations.  Employees who are involuntarily terminated will receive severance and other one-time termination benefits.  This process is expected to be substantially completed in the first quarter of 2007, subject to the completion of the sale of our Kansas electric operations.  The estimated total cost of one-time termination benefits is approximately $5.7 million, which is being recognized over the remaining service period of terminated employees and will be paid out over time.  Approximately $.6 million and $5.5 million of such costswere accrued for the three and nine months ended September 30, 2006, respectively.

 

In addition, upon closing of the sale of Everest Connections in June 2006, its employees received retention payments of approximately $2.0 million, which were recognized over the period through the closing of the sale.  These charges were included in discontinued operations.  

 

11

 

**Lease Agreements**

 

In the first quarter of 2005, we terminated the majority of the remaining leases associated with our former Merchant Services headquarters.  In connection with this termination we made a lump-sum payment of $13.0 million which exceeded our restructuring reserve obligation as of the termination date.  This resulted in an additional lease restructuring charge of $6.6 million in the first quarter of 2005.

 

**Restructuring Reserve Activity**

 

The following table summarizes activity in accrued restructuring charges for our continuing and discontinued operations for the nine months ended September 30, 2006:

 

| *In millions*                                                  |   |   |
|----------------------------------------------------------------|--------|--------|
| Severance and Retention Costs:                                 |   |   |
| Accrued severance costs as of December 31, 2005                | $      | .1     |
| Additional expense during the period                           |   | 7.5    |
| Cash payments during the period                                |   | (4.2)  |
| Accrued severance and retention costs as of September 30, 2006 | $      | 3.4    |

 

**3.  Net (Gain) Loss on Sale of Assets and Other Charges**

 

We have sold the assets and terminated the contracts in the table below and recorded the following pretax net losses (gains) on sale of assets and other charges:

 

|                                                 | **Three Months Ended** | **Nine Months Ended** |
|------------------------------------------------------|------------------------|-----------------------|
|                                                 | **September 30,**      | **September 30,**     |
| *In millions*                                        | **2006**               | **2005**              | **2006** | **2005** |
| Merchant Services:                                   |                   |                  |   |   |   |   |   |   |
| Elwood tolling contract                              | $                      | –                | $ | – | $ | 218.0 | $ | – |
| Batesville tolling contract                          |                   | –                |   | – |   | – |   | (16.3) |
| ICE sale                                             |                   | –                |   | – |   | – |   | (9.3) |
| Other                                                |                   | –                |   | – |   | .7 |   | – |
| Total Merchant Services                              |                   | –                |   | – |   | 218.7 |   | (25.6) |
| Corporate and Other:                                 |                   |                  |   |   |   |   |   |   |
| Early retirement of debt                             |                   | 5.5                   |   | – |   | 28.2 |   | – |
| Early conversion of the PIES                         |                   | –                |   | 82.3 |   | – |   | 82.3 |
| Total Corporate and Other                            |                   | 5.5                   |   | 82.3 |   | 28.2 |   | 82.3 |
| Total net loss on sale of assets and other 

charges | $                      | 5.5                   | $ | 82.3 | $ | 246.9 | $ | 56.7 |

 

After-tax losses and gains discussed below are reported after giving consideration to the effect of capital loss carryback and carryforward limitations.  As a result, the net tax effect may differ substantially from our expected statutory tax rates.  

 

**Elwood Tolling Contract**

 

In June 2006, we paid $218 million to a third party to assume our rights and obligations under the Elwood tolling contract. This transaction resulted in a pretax and after-tax loss of $218 million, and terminated approximately $405 million of our fixed capacity payments through August 2017.  For income tax purposes, we expect to treat the $218 million payment as an ordinary loss on our 2006 income tax return.  However, because we have not concluded that it is probable that the IRS will agree with this treatment, we have increased our reserve for contingent tax liabilities by $81.8 million, thereby fully offsetting the tax benefit of the loss.  We are currently evaluating the impact of FIN 48 on our financial statements, but based on our preliminary analysis we expect to recognize 

12

this tax benefit through a reduction of our reserve for contingent tax liabilities when we adopt FIN 48 in the first quarter of 2007.

 

**Batesville Tolling Contract**

 

In February 2005, we terminated our power sales contract and assigned our rights and obligations under the tolling contract in exchange for approximately $16.3 million.  This transaction resulted in a pretax gain of approximately $16.3 million, or $10.2 million after tax.  

 

**ICE Sale**

 

In February 2005, we sold our 4.5% interest in Intercontinental Exchange, Inc. (ICE) to other shareholders for approximately $13.8 million.  ICE owns a web-based commodity exchange platform. This transaction resulted in a pretax and after-tax gain of approximately $9.3 million.  The gain was realized as a capital gain for income tax purposes resulting in the reversal of previously provided valuation allowances on capital loss carryforwards. 

 

**Early Retirement of Debt**

 

As discussed in more detail in Note 7, we completed a cash tender offer that resulted in the early retirement of approximately $350 million of outstanding senior notes in June 2006.  We recorded a pretax early retirement loss of $22.7 million, or $14.0 million after tax, in connection with this transaction.  We also incurred fees of $5.5 million, or $3.3 million after tax, primarily on the prepayment of the remaining $210 million outstanding on our five-year term loan, as discussed in Note 7.

 

**Early Conversion of the Premium Income Equity Securities (PIES)**

 

We completed an exchange offer that resulted in the early conversion of approximately 98.9% of the PIES in July 2005.  We recorded a pretax and after-tax early conversion loss of approximately $82.3 million in connection with this transaction. We did not record a tax benefit from this transaction as the premium paid to complete the conversion is not deductible for tax purposes.

 

**4.  Discontinued Operations**

 

We have sold, or are in the process of selling, the assets discussed below, which are considered discontinued operations in accordance with SFAS 144.  

 

**Electric and Gas Utilities**

 

On September 21, 2005, we entered into asset purchase agreements to sell our Kansas electric distribution business and our Michigan, Minnesota and Missouri natural gas distribution businesses.  The buyer and base price for each of these transactions are shown in the following table:

 

| **Utility** | **Buyer** | **Base Price****(in millions)** |  
Kansas Electric

Mid-Kansas Electric Company/Westar Energy, Inc.

$

249.7

Michigan Gas

WPS Resources Corporation

 

269.5

Minnesota Gas

WPS Resources Corporation

 

288.0

Missouri Gas

The Empire District Electric Company

 

85.0

 

The sale of our Michigan, Minnesota and Missouri gas utility assets resulted in, and the sale of our Kansas electric utility division is expected to result in, pretax and after tax gains.  The Michigan, Minnesota and Missouri sales also resulted in, and the Kansas electric sale is expected to result in, gains for tax purposes.  The classification of the tax gains between ordinary income and capital gain will depend upon the final allocation of the purchase price based upon the terms of the respective 

 

13

asset purchase agreements.  Ordinary income will be offset by current year net operating losses and/or net operating loss carryforwards.  Capital gains will be offset by capital loss carryforwards.  To the extent capital loss carryforwards are utilized, the valuation allowance against the tax benefit of the capital loss carryforwards will be reversed.  The tax gains and the character thereof will be further adjusted when income tax returns are filed including the sales in the fall of 2007.

 

On April 1, 2006, we closed the sale of our Michigan gas operations and received gross cash proceeds of $314.9 million, including the base purchase price of $269.5 million plus preliminary working capital and other adjustments of $45.4 million.  During the third quarter, we received $25.0 million as part of the working capital and other adjustments “true up”.  We are currently working to resolve the remaining adjustments, the largest of which relates to the value of gas in storage.  These items are expected to be resolved during the first quarter of 2007.  In connection with this sale we have recorded a pretax gain of approximately $94.2 million after transaction fees and expenses, subject to the final determination of pension assets transferred to the buyer as discussed below and the value of gas in storage.  The estimated after-tax gain was approximately $101.0 million,including a preliminary estimate of $44.3 million for the valuation allowance reversal related to the capital gain amount discussed above.

 

On June 1, 2006, we closed the sale of our Missouri gas operations and received gross cash proceeds of $102.1 million, including the base purchase price of $85.0 million plus preliminary working capital and other adjustments of $17.1 million.  The working capital and other adjustments will be “trued up” in the fourth quarter of 2006 through a final payment to or from the buyer.  In connection with this sale we recorded a pretax gain of approximately $30.0 million after transaction fees and expenses, subject to the final determination of pension assets transferred to the buyer as discussed below.  The estimated after-tax gain was approximately $30.7 million, including a preliminary estimate of $11.7 million for the valuation allowance reversal related to the capital gain amount discussed above.  

 

On July 1, 2006, we closed the sale of our Minnesota gas operations and received gross cash proceeds of $333.3 million, including the base purchase price of $288.0 million plus preliminary working capital and other adjustments of $45.3 million.  During the third quarter, we paid $15.4 million as part of the working capital and other adjustments “true up”.  The buyer is currently completing its review of the “true up” and we expect to resolve any remaining adjustments during the fourth quarter of 2006.  In connection with this sale we recorded a pretax gain of approximately $122.0 million after transaction fees and expenses, subject to the final determination of pension assets transferred to the buyer as discussed below.  The estimated after-tax gain will be approximately $71.5 million, subject to the determination of the capital gain amount discussed above.   

 

In August 2006, we and the buyer amended the asset purchase agreement relating to the sale of our Kansas electric utility assets.  Under the amendment, the base purchase price payable by the buyer will be reduced by an amount equal to (i) the book value of our 8% interest in the Jeffrey Energy Center associated with our Kansas electric utility assets (the JEC Interest), plus (ii) $2 million.  The parties also agreed not to terminate the asset purchase agreement before October 2, 2006 (subsequently extended by the parties to April 16, 2007) if the only closing conditions that remain unsatisfied relate to the receipt of regulatory approvals. The sale of our Kansas electric utility assets depends on several conditions being satisfied, including: (i) the non-occurrence of a material adverse event, as described in the asset purchase agreement; (ii) the approval of the Kansas CorporationCommission and the Federal Energy Regulatory Commission (FERC); and (iii) the other closing conditions set forth in the asset purchase agreement.  The Kansas electric employees are expected to be transferred to the buyer upon completion of the sale, upon the terms and conditions contained in the asset purchase agreement.

 

In August 2006, we and Westar Energy, Inc. (Westar) entered into a transfer agreement whereby we will transfer the JEC Interest to Westar, rather than to the buyer as originally contemplated by the asset purchase agreement described above.  Westar will acquire the JEC Interest from us for a 

 

14

purchase price equal to the book value of the JEC Interest, minus $3.5 million.  The closing of this transaction is subject to, among other things, (i) receipt of certain regulatory approvals including the approval of the FERC, the Federal Trade Commission, and the Kansas Corporation Commission; (ii) the closing of the sale of our Kansas electric utility assets to the buyer; (iii) the effectiveness of a participation power agreement related to the JEC interest between Westar and the buyer, which has been executed by those parties; and  (iv) the consent of certain financial parties with ownership or other interests in the JEC Interest.

 

The discontinued utility operations participate in our qualified pension plan, non-qualified Supplemental Executive Retirement Plan and other post-retirement benefit plan.  Under the asset purchase agreements, the buyers assumed or will assume upon closing the accrued pension obligations owed to the current and former employees of the operations they acquired or are acquiring.  After closing, benefit plan assets were or will be transferred to comparable plans established by the buyers in accordance with the terms of the asset purchase agreements and the applicable requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA).  We expect these benefit plan asset transfers to result in plan curtailments.  The effect of the plan curtailments will depend on the final determination of the asset transfers, which may not be completed until 2007.

 

The operating results of the utility divisions sold or held for sale include the direct operating costs associated with those businesses but do not include allocated operating costs of central services and corporate overhead in accordance with Emerging Issues Task Force Consensus 87-24 (EITF 87-24), “Allocation of Interest to Discontinued Operations.”  We provide executive management and centralized support services to all of our utility divisions, including customer care, billing, collections, information technology, accounting, tax and treasury services, regulatory services, gas supply services, human resources, safety and other services.  The operating costs related to these functions are allocated to the utility divisions based on various cost drivers.  Effective January 1, 2006, we ceased allocating costs to our held-for-sale utilities.  These allocated costs were notincluded in the reclassification to earnings from discontinued operations because these support services were necessary to maintain ongoing operations until the sales are final and cannot be eliminated immediately upon closing of the asset sales.  We plan to eliminate the majority of these costs when these support services are no longer required.  The allocated operating costs related to the utility divisions held for sale were $9.9 million and $30.4 million in the three and nine months ended September 30, 2005, respectively.

 

**Merchant Peaking Power Plants**

 

In December 2005, two of our subsidiaries agreed to sell to AmerenUE the Goose Creek Energy Facility and Raccoon Creek Energy Facility.  The Goose Creek Energy Facility is a 510 MW natural gas-fired, simple-cycle peaking power plant in Piatt County, Illinois, and the Raccoon Creek Energy Facility is a 340 MW natural gas-fired, simple-cycle peaking power plant in Clay County, Illinois.  On March 31, 2006, we closed the sales of these facilities and received gross proceeds of $175 million.

 

In connection with the sale of these facilities, we determined that they should be classified as “held for sale” and included in discontinued operations, rather than “held and used” as they had previously been classified.  As a result, we reassessed the realizability of the carrying value of our investments in these facilities and concluded that they were impaired.  We based this conclusion on the anticipated net sale proceeds of the sale transactions described above.  In the fourth quarter of 2005, based on the expected net sale proceeds and transaction-related costs, we recorded a pretax non-cash impairment charge of approximately $93.6 million and $65.9 million for the Goose Creek Energy Facility and the Raccoon Creek Energy Facility, respectively, or an after-tax loss of approximately $58.5 million and $41.2 million, respectively.  We expect to receive an aggregatebook tax benefit on the asset sales of approximately $59.8 million (tax calculation on the pretax loss of approximately $159.5 million), although there will be no immediate cash tax receivable on the asset sales due to our net operating loss carryovers.  

 

15

**Everest Connections**

 

In the fourth quarter of 2005, we began a sale process for our Everest Connections communications business.  Based on the level of bidder participation and the bid valuations, we determined that the business should be classified as “held for sale” and included it in discontinued operations.  In connection with this reclassification, we reassessed the realizability of the carrying value of our investment in Everest.  

 

In March 2006, our subsidiary, Everest Global Technologies Group, LLC (EGTG), agreed to sell to Everest Connections Holdings, Inc., an acquisition subsidiary of Seaport Capital Partners III, L.P., certain EGTG subsidiaries conducting its communications business for a base purchase price of $85.7 million.  On June 30, 2006, EGTG closed the sale and received net cash proceeds of $80.2 million after the repayment of $6.8 million of direct debt of Everest Connections and including working capital and other adjustments of approximately $1.3 million.  The working capital and other adjustments were “trued up” in the third quarter of 2006 through a final payment of $.2 million to the buyer.  We expect net proceeds available to be approximately $76 million, after payment of transaction costs and certain amounts owed to EGTG minority partners.  In connection with this sale we have recordeda pretax gain of approximately $25.5 million after transaction fees and expenses.  The estimated after-tax gain was approximately $15.7 million.

 

**Interest Allocation to Discontinued Operations**

 

The buyers of our former Michigan, Minnesota and Missouri gas utility divisions, Illinois peaking facilities and communications business did not assume, and the buyer of our held-for-sale Kansas electric utility division will not assume, any of our long-term debt.  Other than $6.8 million of direct debt of Everest Connections, none of our long-term debt was required to be repaid with the proceeds of these asset sales, although the lenders of our $220 million five-year term loan (see Note 7) had the opportunity to elect prepayment without premium from the proceeds of utility asset sales.  These lenders did not elect prepayment with regard to the proceeds of the Michigan or Minnesota gas utility sales, but one lender elected to receive prepayment of $10 million from the proceeds of the Missouri gas utility sale.  The direct debt and related interest of Everest Connections was included indiscontinued operations. We allocated a portion of consolidated interest expense to discontinued operations based on the ratio of net assets of discontinued operations to consolidated net assets plus consolidated debt in accordance with EITF 87-24.  The amount of interest expense allocated to discontinued operations may not be representative of the actual interest reductions we may achieve from future debt retirements using the proceeds of the asset sales.  As we complete each asset sale the allocation of interest to discontinued operations ceases, thereby increasing interest expense in continuing operations, without impacting total interest expense, until the sales proceeds are used to reduce debt.

 

**Summary**

 

We have reported the results of operations from these assets in discontinued operations for the three and nine months ended September 30, 2006 and 2005 in the Consolidated Statements of Income. 

16

 

Operating results from our discontinued operations are as follows:

 

* *

**Three Months Ended**

**Nine Months Ended**

* *

**September 30,**

**September 30,**

*In millions*

**2006**

**2005**

**2006**

**2005**

* *

 

 

 

 

 

 

 

 

Sales

$

61.8

$

142.9

$

479.3

$

585.9

Cost of sales

 

30.5

 

79.2

 

322.6

 

385.4

Gross profit

 

31.3

 

63.7

 

156.7

 

200.5

Operating expenses:

 

 

 

 

 

 

 

 

Operation and maintenance expense

 

11.0

 

25.9

 

61.0

 

79.3

Taxes other than income taxes

 

1.4

 

1.6

 

9.8

 

4.4

Restructuring charges

 

–

 

–

 

2.0

 

–

Net (gain) on sale of assets and other      charges

 

(122.2)

 

–

 

(270.8)

 

–

Depreciation and amortization expense

 

–

 

12.7

 

.9

 

38.4

Total operating expenses (income)

 

(109.8)

 

40.2

 

(197.1)

 

122.1

Operating income

 

141.1

 

23.5

 

353.8

 

78.4

Other income (expense)

 

(.4)

 

.4

 

.1

 

.2

Interest expense 

 

4.5

 

16.4

 

30.7

 

53.6

Income before income taxes

 

136.2

 

7.5

 

323.2

 

25.0

Income tax expense (benefit)

 

(.1)

 

3.2

 

72.6

 

10.4

Earnings from discontinued operations, net      of tax

$

136.3

$

4.3

$

250.6

$

14.6

 

The related assets and liabilities included in the sale of these businesses, as detailed below, have been reclassified as current and non-current assets and liabilities of discontinued operations on the September 30, 2006 and December 31, 2005 Consolidated Balance Sheets as follows:

 

 

**September 30,**

**December 31,**

*In millions***

**2006**

**2005**

Current assets of discontinued operations:

 

 

 

 

Cash and cash equivalents

$

–

$

4.8

Accounts receivable, net

 

18.8

 

160.5

Inventories and supplies

 

5.4

 

81.0

Other current assets

 

1.6

 

22.7

Total current assets of discontinued operations

$

25.8

$

269.0

Non-current assets of discontinued operations:

 

 

 

 

Utility plant, net

$

231.3

$

610.6

Non-utility plant, net

 

–

 

220.8

Prepaid pension

 

10.8

 

26.6

Other non-current assets

 

27.4

 

39.9

Total non-current assets of discontinued operations

$

269.5

$

897.9

Current liabilities of discontinued operations:

 

 

 

 

Current maturities of long-term debt

$

–

$

1.3

Other current liabilities

 

1.2

 

29.2

Total current liabilities of discontinued operations

$

1.2

$

30.5

Non-current liabilities of discontinued operations:

 

 

 

 

Long-term debt, net

$

–

$

6.2

Deferred credits

 

22.5

 

57.4

Total non-current liabilities of discontinued operations

$

22.5

$

63.6

 

 

17

 

**5.  Earnings (Loss) per Common Share**

 

The table below shows how we calculated basic and diluted earnings (loss) per share.  Basic earnings (loss) per share and basic weighted average shares are the starting point in calculating the dilutive measures.  To calculate basic earnings (loss) per share, divide our loss available for common shares for the period by our weighted average shares outstanding, without adjusting for dilutive items.  Weighted average shares used in basic earnings (loss) per share included 110.9 million shares issuable on the conversion of the mandatorily convertible PIES from August 24, 2004, the date of issuance of the PIES.  On July 7, 2005, approximately 98.9% of the PIES units were converted to 131.4 million shares of common stock pursuant to an exchange offer.  Diluted earnings (loss) per share is calculated by dividing our net loss, after assumed conversion of dilutive securities, by our weightedaverage shares outstanding, adjusted for the effect of dilutive securities.  However, as a result of the net loss in the nine months ended September 30, 2006 and three and nine months ended September 30, 2005, the potential issuances of common stock for dilutive securities were considered anti-dilutive in those periods and were therefore not included in the calculation of diluted earnings (loss) per share.

 

 

**Three Months Ended**

**Nine Months Ended**

 

**September 30,**

**September 30,**

*In millions, except per share amounts***

**2006**

**2005**

**2006**

**2005**

 

 

 

 

 

 

 

 

 

Loss from continuing operations

$

(20.6)

$

(80.0)

$

(291.0)

$

(116.8)

Earnings from discontinued operations

 

136.3

 

4.3

 

250.6

 

14.6

Net earnings (loss) as reported

 

115.7

 

(75.7)

 

(40.4)

 

(102.2)

Interest and debt amortization costs associated with the PIES

 

–

 

.1

 

.1

 

12.5

Earnings (loss) available for common shares

$

115.7

$

(75.6)

$

(40.3)

$

(89.7)

 

 

 

 

 

 

 

 

 

Basic and diluted earnings (loss) per share:

 

 

 

 

 

 

 

 

Loss from continuing operations

$

(.05)

$

(.21)

$

(.78)

$

(.29)

Earnings from discontinued operations

 

.36

 

.01

 

.67

 

.04

Net earnings (loss)

$

.31

$

(.20)

$

(.11)

$

(.25)

Weighted average number of common shares used in basic earnings (loss) per share

 

375.2

 

372.9

 

375.0

 

359.5

Effect of dilutive stock options, convertible debentures and restricted stock units

 

.6

 

–

 

–

 

–

Weighted average number of common shares used in diluted earnings (loss) per share

 

375.8

 

372.9

 

375.0

 

359.5

 

**6.  Reportable Segment Reconciliation**

 

We manage our business in three business segments:  Electric Utilities, Gas Utilities and Merchant Services.  Our Electric and Gas Utilities currently consist of our regulated electric utility operations in three states and our natural gas utility operations in four states.  We manage our electric and gas utility divisions by state.  However, as each of our electric utility divisions and each of our gas utility divisions have similar economic characteristics, we aggregate our electric utility divisions into the Electric Utilities reporting segment and our gas utility divisions into the Gas Utilities reporting segment.  The operating results of our Kansas electric division, which is in the process of being sold, and our Michigan, Missouri and Minnesota gas divisions, which were sold on April 1, 2006, June 1, 2006 and July 1, 2006, respectively, have been reclassified to discontinuedoperations.  Merchant Services consists of the residual operations of our Aquila Merchant subsidiary.  These operations include its investment in the Crossroads peaking power plant, its former commitments under merchant capacity tolling obligations, and its commitments under long-term gas contracts and the remaining contracts from its wholesale energy trading operations.  The operating results of Merchant Services’ two Illinois merchant power plants, which were sold on March 31, 2006, have been reclassified to discontinued operations.  All other operations are included in 

 

18

Corporate and Other, including the costs not allocated to our operating businesses.  The operating results of Everest Connections, which was sold on June 30, 2006, have been reclassified to discontinued operations.

 

Each segment is managed based on operating results, expressed as earnings before interest, taxes, depreciation and amortization. Generally, decisions on finance, dividends and taxes are made at the Corporate level.  The current and non-current assets of our discontinued operations are included in the segments referenced above.

 

19

Our reportable segment reconciliation is shown below:

 

 

**Three Months Ended**

**Nine Months Ended**

 

**September 30,**

**September 30,**

*In millions***

**2006**

**2005**

**2006**

**2005**

Sales: *(a)*

 

 

 

 

 

 

 

 

Utilities:

 

 

 

 

 

 

 

 

Electric Utilities

$

243.0

$

215.4

$

601.5

$

517.7

Gas Utilities

 

78.0

 

81.5

 

436.3

 

401.7

Total Utilities

 

321.0

 

296.9

 

1,037.8

 

919.4

Merchant Services

 

(4.4)

 

3.9

 

(7.3)

 

(3.0)

Corporate and Other

 

–

 

–

 

.1

 

–

Total sales

$

316.6

$

300.8

$

1,030.6

$

916.4

*(a)*         *For the three months ended September 30, 2006 and 2005, and nine months ended September 30, 2006 and 2005, respectively, the following sales (in millions) have been reclassified to discontinued operations and are not included in the above amounts: Electric Utilities of $61.8, $67.2, $147.8 and $143.9; Gas Utilities of $–, $56.7, $304.2 and $393.0; Merchant Services sales of $–, $7.2, $2.2 and $14.9; and Corporate and Other sales related to Everest Connections of $–, $11.8, $25.1 and $34.1.*

 

Earnings (Loss) Before Interest, Taxes, Depreciation and Amortization (EBITDA): *(a)*

 

 

 

 

 

 

 

 

Utilities:

 

 

 

 

 

 

 

 

Electric Utilities

$

58.0

$

82.4

$

120.5

$

139.8

Gas Utilities

 

1.6

 

(2.1)

 

29.3

 

19.9

Total Utilities

 

59.6

 

80.3

 

149.8

 

159.7

Merchant Services

 

(17.0)

 

(9.5)

 

(249.0)

 

(9.8)

Corporate and Other

 

(3.7)

 

(87.2)

 

(32.8)

 

(92.9)

Total EBITDA

 

38.9

 

(16.4)

 

(132.0)

 

57.0

Depreciation and amortization expense

 

27.0

 

26.0

 

78.5

 

78.4

Interest expense

 

42.7

 

35.6

 

124.4

 

115.5

Loss from continuing operations before income taxes

$

(30.8)

$

(78.0)

$

(334.9)

$

(136.9)

*(a)*         *For the three months ended September 30, 2006 and 2005, and nine months ended September 30, 2006 and 2005, respectively, the following EBITDA (in millions) have been reclassified to discontinued operations and are not included in the above amounts: Electric Utilities of $20.4, $22.2, $39.4 and $38.5; Gas Utilities of $121.4, $10.7, $286.0 and $68.4; Merchant Services of $*–*, $.5, $(.8) and $2.1; and Corporate and Other related to Everest Connections of $(1.1), $3.2, $30.2 and $8.0.*

 

Depreciation and Amortization: *(a)*

 

 

 

 

 

 

 

 

Utilities:

 

 

 

 

 

 

 

 

Electric Utilities

$

18.4

$

15.7

$

52.1

$

46.3

Gas Utilities

 

7.7

 

8.5

 

24.6

 

26.7

Total Utilities

 

26.1

 

24.2

 

76.7

 

73.0

Merchant Services

 

1.0

 

1.7

 

3.1

 

5.3

Corporate and Other

 

(.1)

 

.1

 

(1.3)

 

.1

Total depreciation and amortization

$

27.0

$

26.0

$

78.5

$

78.4

*(a)*         *For the three months and nine months ended September 30, 2005, respectively, the following depreciation and amortization (in millions) have been reclassified to discontinued operations and are not included in the above amounts: Electric Utilities of $3.3 and $9.7; Gas Utilities of $4.9 and $15.6; Merchant Services of $2.6 and $7.6; and Corporate and Other related to Everest Connections of $1.9 and $5.5.*

 

 

 

20

 

 

*In millions***

**September 30,****2006**

**December 31,****2005**

Assets: *(a)*

 

 

 

 

Utilities:

 

 

 

 

Electric Utilities

$

2,160.0

$

2,065.7

Gas Utilities

 

610.3

 

1,430.0

Total Utilities

 

2,770.3

 

3,495.7

Merchant Services

 

332.4

 

918.6

Corporate and Other

 

337.8

 

216.4

Total assets

$

3,440.5

$

4,630.7

*(a)*  *Included in total assets as of September 30, 2006 and December 31, 2005 are total assets of discontinued operations as follows:  Electric Utilities $295.3 million and $273.6 million, respectively; Gas Utilities $*–*million and $657.3 million, respectively; Merchant Services $*–*million and $175.0 million, respectively; and Corporate and Other related to Everest Connections of $*– *million and $61.0 million, respectively.*

**7.  Financings**

 

**$180 Million Revolving Credit and Letter of Credit Facility**

 

On April 13, 2005, we entered into a five-year credit agreement with a commercial lender.  Subject to the satisfaction of certain conditions, the facility provides for up to $180 million of cash advances and letters of credit for working capital purposes.  Cash advances must be repaid within 364 days unless we obtain the necessary regulatory approvals to incur long-term indebtedness under the facility.  As of September 30, 2006, we had $150.0 million of uncollateralized capacity at an average cost of 3.65% under this agreement.  As of September 30, 2006, $116.7 million of the available capacity had been utilized for letters of credit under this facility.

 

**Four-Year Secured Revolving Credit Facility**

 

On April 22, 2005, we executed a four-year $150 million secured revolving credit facility (the AR Facility).  Proceeds from this facility may be used for working capital and other general corporate purposes.  Borrowings under this facility are secured by the accounts receivable generated by our regulated utility operations in Colorado, Kansas, Missouri and Nebraska.  Borrowings under the AR Facility bear interest at LIBOR plus 1.375%, subject to reduction if our credit ratings improve.  Borrowings must be repaid within 364 days unless we obtain the necessary regulatory approvals to incur long-term indebtedness under the facility.  Among other restrictions, we are required under the AR Facility to maintain the same debt-to-total capital and EBITDA-to-interest expense ratios as those contained in the Five-Year Facilities discussed below.  There were no borrowings under this facility as ofSeptember 30, 2006.

 

The accounts receivable generated by our Michigan and Missouri gas businesses were released upon the closing of the sales of these businesses.  As we close the sale of our Kansas electric business, the accounts receivable generated by this utility will be released from the AR Facility and the maximum borrowing limit may be reduced.

 

**$50 Million Revolving Credit and Letter of Credit Facility**

 

On January 13,2006, we closed on a $50 million short-term letter of credit facility with a commercial lender, which terminates on December 20, 2006, and allows us to either issue letters of credit or make cash drawings under the facility.  This facility, which bears a 2.50% advance rate on letters of credit, is expected to be nearly fully utilized through letter of credit issuances.  There were $47.6 million of letters of credit outstanding under this facility as of September 30, 2006.

 

21

**Five-Year Unsecured Term Loan and Revolving Credit Facility**

 

In September 2004, we completed a $220 million 364-day unsecured term loan and a $110 million 364-day unsecured revolving credit facility.  The facilities automatically extended to September 2009 when we received extension approval from the FERC and various state public utility commissions (the Five-Year Facilities). We borrowed the full amount of the term loan and received $211.3 million of net proceeds after upfront fees and expenses on the two facilities.  In June 2006, the holder of $10 million of term loan notes elected to receive an optional prepayment from the proceeds of the sale of our Missouri gas utility operations.  In September 2006, we elected to prepay the remaining $210 million outstanding and paid a 2.5% prepayment fee.  There were no borrowings outstanding on the Revolving Credit Facility as of September 30, 2006.  The Revolving Credit Facility bears interest at the LIBORplus 5.75%, subject to reduction if our credit rating improves.  Among other restrictions, the Revolving Credit Facility contains financial covenants similar to, but less restrictive than, those contained in the Iatan Facility described below.  We were in compliance with these covenants as of September 30, 2006.

 

The Revolving Credit Facility also contains covenants that restrict certain activities including, among others, limitations on additional indebtedness, restrictions on acquisitions, sale transactions and investments. In addition, we are prohibited from paying dividends and from making certain other payments if our senior unsecured debt is not rated at least Ba2 by Moody's and BB by Standard & Poor’s (S&P), or if such a payment would cause a default under the facility. 

 

**Iatan 2 Construction Financing**

 

On August 31, 2005, we entered into a $300 million credit agreement with a commercial lender and a syndicate of other lenders (the Iatan Facility). The credit agreement allows us to obtain loans and issue letters of credit (limited to $175 million of letters of credit) in support of our participation in the construction of an approximately 850 MW coal-fired power plant being developed by Kansas City Power & Light Company (KCPL) near Weston, Missouri (Iatan 2), and our obligation to fund pollution controls being installed at an adjacent facility. Extensions of credit under the facility will be due and payable on August 31, 2010. Loans bear interest at LIBOR plus a margin determined by our credit ratings.  A fee based on our credit ratings will be paid on the amount of letters of credit outstanding. Obligations under the credit agreement are secured by the assets of our Missouri PublicService electric operations.  There were no borrowings under this facility at September 30, 2006.  There were $138.7 million of letters of credit outstanding under this facility as of September 30, 2006.  In October 2006, based on our improved financial condition, we obtained consents from our Iatan 2 partners to release these letters of credit.  The letters of credit outstanding as of September 30, 2006 have since been cancelled.  Among other restrictions, the Iatan Facility contains the following financial covenants with which we were in compliance as of September 30, 2006: 

 

 

**•**

We are required to maintain a ratio of total debt to total capital (expressed as a percentage) of not more than 75% through September 30, 2008; 70% from October 1, 2008 through September 30, 2009; and 65% thereafter. 

 

 

**•**

We must maintain a trailing 12-month ratio of EBITDA, as defined in the agreement, to interest expense of no less than 1.2 to 1.0 through September 30, 2006; 1.3 to 1.0 from October 1, 2006 through September 30, 2007; 1.4 to 1.0 from October 1, 2007 through September 30, 2008; 1.6 to 1.0 from October 1, 2008 through September 30, 2009; and 1.8 to 1.0 thereafter. 

 

 

**•**

We must maintain a trailing 12-month ratio of debt outstanding to EBITDA of no more than 7.75 to 1.0 through September 30, 2006; 7.5 to 1.0 from October 1, 2006 through September 30, 2007; 6.0 to 1.0 from October 1, 2007 through September 30, 2008; 5.5 to 1.0 from October 1, 2008 through September 30, 2009; and 5.0 to 1.0 thereafter. 

 

22

 

**•**

We must maintain a ratio of mortgaged property to extensions of credit (borrowings plus outstanding letters of credit) of no less than 2.0 to 1.0 as of the last day of each fiscal quarter.

 

The Iatan Facility also contains covenants that restrict certain activities including, among others, limitations on additional indebtedness, restrictions on acquisitions, sale transactions and investments. In addition, we are prohibited from paying dividends and from making certain other payments if our senior unsecured debt is not rated at least Ba2 by Moody's and BB by S&P, or if such a payment would cause a default under the facility.

 

**Early Retirement of Senior Notes**

 

In May 2006, we announced a cash tender offer for the early retirement of certain of our outstanding senior notes.  Under the offer, the total consideration paid in exchange for the notes was based either on a fixed spread over the yield to maturity of a U.S. Treasury reference security or on a fixed price basis. Noteholders that accepted the tender received the accrued interest from the last interest payment date, and those that properly tendered their notes before the early tender time date were also entitled to receive an additional early tender premium of two percent of the debt tendered.  

 

In June 2006, we completed the cash tender offer, which resulted in the early retirement of $350 million of aggregate debt principal. We recorded a pretax early retirement loss of $22.7 million, or $14.0 million after tax, in connection with the transaction.  The table below provides the detail on the notes retired:

 

**Title of Security**

 

**Principal Amount Retired (in millions)**

6.7% Notes due 10/15/2006

 

$

84.5

8.2% Notes due 1/15/2007

 

 

22.3

7.625% Notes due 11/15/2009

 

 

130.5

9.95% Notes due 2/01/2011

 

 

112.7

Total

 

$

350.0

 

**Other**

 

We had an additional $.8 million of letters of credit outstanding under various arrangements as of September 30, 2006.

 

 

23

**8.  Employee Benefits**

 

 

The following table shows the components of net periodic benefit costs:

 

* *

**Pension Benefits**

**Other****Post-retirement****Benefits**

* *

**Three Months Ended September 30,**

*In millions***

**2006**

**2005**

**2006**

**2005**

**Components of Net Periodic Benefit Cost:**

 

 

 

 

 

 

 

 

Service cost

$

2.2

$

2.3

$

.2

$

–

Interest cost

 

4.9

 

5.7

 

.9

 

1.0

Expected return on plan assets

 

(6.3)

 

(7.0)

 

(.1)

 

(.2)

Amortization of transition amount

 

(.2)

 

(.2)

 

.3

 

.3

Amortization of prior service cost

 

1.2

 

1.2

 

.5

 

.2

Recognized net actuarial loss

 

.8

 

.9

 

–

 

.2

Net periodic benefit cost before regulatory expense adjustments

 

2.6

 

2.9

 

1.8

 

1.5

Regulatory gain/loss adjustment

 

1.1

 

.8

 

.2

 

.2

SFAS 71 regulatory adjustment

 

.2

 

1.0

 

–

 

–

**Net periodic benefit cost after regulatory expense adjustments**

$

3.9

$

4.7

$

2.0

$

1.7

 

* *

**Pension Benefits**

**Other****Post-retirement****Benefits**

* *

**Nine Months Ended September 30,**

*In millions***

**2006**

**2005**

**2006**

**2005**

**Components of Net Periodic Benefit Cost:**

 

 

 

 

 

 

 

 

Service cost

$

7.2

$

6.6

$

.6

$

.4

Interest cost

 

16.0

 

16.3

 

3.1

 

3.7

Expected return on plan assets

 

(20.5)

 

(20.5)

 

(.5)

 

(.7)

Amortization of transition amount

 

(.6)

 

(.6)

 

1.0

 

1.1

Amortization of prior service cost

 

3.9

 

2.8

 

1.8

 

1.5

Recognized net actuarial loss

 

2.8

 

3.2

 

–

 

.4

Net periodic benefit cost before regulatory expense adjustments

 

8.8

 

7.8

 

6.0

 

6.4

Regulatory gain/loss adjustment

 

3.7

 

2.5

 

.6

 

.7

SFAS 71 regulatory adjustment

 

.5

 

3.0

 

–

 

–

**Net periodic benefit cost after regulatory expense adjustments**

$

13.0

$

13.3

$

6.6

$

7.1

 

We previously disclosed in our financial statements for the year ended December 31, 2005, that we expected to contribute $.8 million and $9.4 million to our defined benefit pension plans and other post-retirement benefit plan, respectively, in 2006.  Our qualified pension plan is funded in compliance with income tax regulations and federal funding requirements.  We expect to fund no less than the IRS minimum funding amount and no more than the IRS maximum tax deductible amount.  As a result of the transfer of pension plan assets and pension benefits obligations in accordance with ERISA requirements to the buyers of our utility assets as discussed in Note 4, we expect to make an additional voluntary contribution of approximately $10 million to our defined benefit plan upon completion of the final plan asset transfers to sustain the funded status of our pension plan.

 

As disclosed in Note 4, the Kansas electric utility operations being held for sale and our former Michigan, Minnesota and Missouri gas operations have been reclassified as discontinued operations.  The components of net periodic benefit cost presented in the tables above disclose information for the plans in total.  For the three and nine months ended September 30, 2006, the net periodic pension 

 

24

benefit cost charged to discontinued operations was $.3 million and $2.0 million, respectively.  In addition, for the three and nine months ended September 30, 2006, the net periodic other post-retirement benefits cost charged to discontinued operations was $.3 million and $1.6 million, respectively.

 

**9.  Legal******

 

**Price Reporting Litigation**

 

On August 18, 2003, Cornerstone Propane Partners filed suit in the Southern District of New York against 35 companies, including Aquila, alleging that the companies manipulated natural gas prices and futures prices on NYMEX through misreporting of natural gas trade data in the physical market.  The suit does not specify alleged damages and was filed on behalf of all parties who bought and sold natural gas futures and options on NYMEX from 2000 to 2002.  The suit has been certified as a class-action lawsuit.  Fact discovery closed on December 23, 2005.  In the third quarter of 2006, we agreed to pay $6.59 million to settle this case.  This settlement is subject to approval of the court.

 

On June 7, 2004, the City of Tacoma, Washington, filed suit against 56 companies, including Aquila Merchant, for allegedly conspiring to manipulate the California power market in 2000 and 2001 in violation of the Sherman Act.  This case was dismissed in February 2005.  The City of Tacoma has appealed to the Ninth Circuit Court of Appeals.  

 

On July 8, 2004, the County of Santa Clara and the City and County of San Francisco each filed suit against seven energy trading companies and their subsidiaries and affiliates, including Aquila and Aquila Merchant, in the Superior Court of California for San Diego County alleging manipulation of the California natural gas market in 1999 through 2002.  Since that date, 14 other complaints making nearly identical allegations have been filed against Aquila and Aquila Merchant in California state courts.  These lawsuits allege violations of the Cartwright Act and in some cases California’s Unfair Competition Law, and also assert an unjust enrichment claim.  The lawsuits have been coordinated before a single Motion Coordination Judge in the Superior Court of California for the County of San Diego, in the proceeding entitled *In re Natural Gas Antitrust Cases I, II,III & IV*.  We believe we have strong defenses and will defend these cases vigorously.  Given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

 

Aquila Merchant is also a defendant in two federal actions that were filed on November 30, 2004 and June 21, 2005 in the United States District Court for the Eastern District of California.  These cases were transferred by the Judicial Panel on Multidistrict Litigation to the United States District Court for the District of Nevada on January 21, 2005 and August 15, 2005, respectively.  The action originally filed on November 30, 2004 was subsequently consolidated with two other actions.  All of these lawsuits are now part of the proceeding known as *In re Western States Wholesale Natural Gas Antitrust Litigation*, MDL Docket No. 1566, and make allegations similar to those made in the *In re Natural Gas Antitrust Cases I, II, III & IV*.  The plaintiffs in the November 2004 action allege violationsof the Sherman Act, the Cartwright Act, California’s Unfair Competition Law, unjust enrichment, and constructive trust, whereas the plaintiffs in the June 2005 action allege only violations of the Sherman Act.  The action originally filed on November 30, 2004 has been dismissed, and the plaintiffs have appealed the dismissal to the Ninth Circuit Court of Appeals.  We believe we have strong defenses and will defend these cases vigorously.  Given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

 

In response to complaints of manipulation of the California energy market, in 2002 the FERC issued an order requiring net sellers of power in the California markets from October 2, 2000 through June 20, 2001 at prices above a FERC determined competitive market clearing price to make refunds to net purchasers of power in the California market during that time period.  Because Aquila Merchant was a net purchaser of power during the refund period it has received 

 

25

approximately $7.6 million in refunds.  However, various parties have appealed the FERC order to the United States Court of Appeals for the Ninth Circuit seeking review of a number of issues, including changing the refund period to include periods prior to October 2, 2000.  On August 2, 2006, the U.S. Court of Appeals for the Ninth Circuit issued an order finding, among other things, that FERC did not provide a sufficient justification for refusing to exercise its remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the period prior to October 2, 2000, and imposing a remedy for any such violations.  The court remanded the matter to FERC to determine whether tariff violations occurred and, if so, the appropriate remedy. A finding by FERC that Aquila Merchant must remedy tariff violations that occurred during this period could resultin Aquila Merchant being required to make substantial refunds and have a material adverse effect on its financial condition, results of operations and cash flows. 

 

In December 2005, Aquila Merchant provided a liability of $9.0 million for the above claims.  Based on our continuing evaluation of the above claims, including the settlement of the Cornerstone case discussed above, we determined that the ultimate resolution of such claims could result in an obligation of between $15.6 million and $35 million, excluding the recent Cornerstone settlement.  In the third quarter of 2006, we recorded an additional provision of $9.3 million to increase the liability recorded to the lower end of the range, after reflecting a receivable of $3.9 million from our insurance carrier.  The timing and amount of the ultimate resolution of these claims remains uncertain and could exceed that range by a material amount.

 

On October 5, 2006, the Missouri Public Service Commission filed suit in the Circuit Court of Jackson County, Missouri against 18 companies, including Aquila and Aquila Merchant, alleging that the companies manipulated natural gas prices through the misreporting of natural gas trade data and, therefore, violated Missouri antitrust laws.  The suit does not specify alleged damages and was filed on behalf of all local distribution gas companies in Missouri who bought and sold natural gas from June 2000 to October 2002.  We believe we have strong defenses and will defend this case vigorously.  We cannot predict whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

 

**ERISA Litigation**

 

On September 24, 2004, a lawsuit was filed in the U.S. District Court for the Western District of Missouri against us and certain members of our Board of Directors and management, alleging they violated the ERISA and are responsible for losses that participants in our 401(k) plan experienced as a result of the decline in the value of their Aquila common stock held in the 401(k) plan.  A number of similar lawsuits alleging that the defendants breached their fiduciary duties to the plan participants in violation of ERISA by concealing information and/or misleading employees who held our common stock through our 401(k) plan were subsequently filed against us.  The suits also seek damages for the plan's losses resulting from the alleged breaches of fiduciary duties.  On January 26, 2005, the court ordered that all of these lawsuits be consolidated into a single case captioned *In re Aquila ERISA Litigation.*The plaintiffs filed an amended consolidated complaint in March 2005, which largely repeats each of the allegations in the first complaint. This case has been certified as a class action and set for trial in August 2007.  We believe we have strong defenses and will defend this case vigorously.  We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.  

 

**South Harper Peaking Facility**

 

We have constructed a 315 MW natural gas "peaking" power plant and related substation in an unincorporated area of Cass County, Missouri.  Cass County and local residents filed suit claiming that 

 

26

county zoning approval was required to construct the project.  In January 2005, a trial court judge granted the County's request for an injunction; however, we were permitted to continue construction while the order was appealed.  We appealed the trial court decision to the Missouri Court of Appeals for the Western District of Missouri and, on June 21, 2005, the appellate court affirmed the circuit court ruling.  In July 2005, we requested that the Court of Appeals either rehear the case or transfer the case to the Missouri Supreme Court and, in October 2005, the Court of Appeals granted our request for rehearing.  

On December 20, 2005, the appellate court issued a new opinion affirming the trial court’s opinion, but also opining that it was not too late to obtain the necessary approval for the project.  In light of this, we filed an application for approval with the Missouri Commission on January 24, 2006.  On January 27, 2006, the trial court granted our request to stay the permanent injunction until May 31, 2006, and ordered us to post a $20 million bond to secure the cost of removing the project.  Effective May 31, 2006, the Missouri Commission issued an order specifically authorizing our construction and operation of the power plant and substation.  On June 2, 2006, the trial court dissolved the $20 million bond, further stayed its injunction, and authorized us to operate the plant and substation while Cass County appealed the Missouri Commission’s order.

In June 2006, Cass County filed an appeal with the Circuit Court of Cass County, challenging the lawfulness and reasonableness of the Missouri Commission’s order.  On October 20, 2006, the Circuit Court ruled that the Missouri Commission’s order was unlawful and unreasonable.  We will appeal the court’s decision.  If we exhaust all of our legal options and are ordered to remove the plant and substation, we estimate the cost to dismantle the plant and substation to be approximately $20 million based on an engineering study.  Significant additional costs would be incurred to store the equipment, secure replacement power and/or reconstruct the plant and substation on other sites.  We cannot estimate with certainty the total amount of these incremental costs that could be incurred, or the potential impairment of the carrying value of our investment in the plant we could suffer ifthe cost exceeds the amount allowed for recovery in rates. 

 

**Coal Supply Litigation**

 

In the spring of 2006, one of our coal suppliers, C. W. Mining Company, terminated a long term, fixed price coal supply agreement allegedly because of a force majure event.  We have incurred significant costs procuring replacement coal and dispute that the supplier was entitled to terminate the contract.  We filed a lawsuit against it in federal court in Salt Lake City and trial has been scheduled for February 2007.

 

**10.  Share-Based Compensation**

 

In 2002, the Board and our shareholders approved the Omnibus Incentive Compensation Plan.  This plan authorizes the issuance of 9,000,000 shares of Aquila common stock as stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, stock awards, cash-based awards and annual incentive awards to all eligible employees and directors of the company.  All equity-based awards are issued under this plan.  Generally, shares issued for stock option exercises and other share awards are made from treasury shares, if available, and newly issued shares.

 

**Share-Based Payments**

 

In December 2004, the FASB issued Statement of SFAS No. 123R (SFAS 123R), “Share-Based Payments,” that requires all companies to expense the value of employee stock options.  SFAS 123R became effective for us as of January 1, 2006, and was applied to all outstanding unvested share-based awards on that date, consisting of 74,700 unvested stock options.  We have elected to use the modified prospective method to adopt SFAS 123R. The impact of the adoption of SFAS 123R was immaterial.  As of September 30, 2006, we had 5.2 million of fully vested stock options outstanding.

 

27

We issue stock options to employees from time to time and had accounted for these options under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25) through December 31, 2005.  All stock options issued are granted at the common stock’s market price on the date of the grant.  Therefore prior to 2006 we recorded no compensation expense related to stock options. 

 

Because we accounted for options under APB 25 in 2005, we disclosed a pro forma net loss and basic and diluted earnings (loss) per share as if we reflected the estimated fair value of options determined using the Black-Scholes option pricing model as compensation expense in accordance with SFAS No. 123, “Accounting for Stock-Based Compensation.”  Our pro forma net loss and basic and diluted loss per share were as follows: 

 

* *

**Three Months Ended**

**Nine Months Ended**

*In millions, except per share amounts***

**September 30, 2005**

**September 30, 2005**

Net loss:

 

 

 

 

As reported

$

(75.7)

$

(102.2)

Premium Income Equity Securities (PIES) adjustment (Note 5)

 

.1

 

12.5

Loss available for common shares

 

(75.6)

 

(89.7)

Total stock-based employee compensation expense determined under fair value method, net of related tax benefits

 

–

 

(1.9)

Pro forma loss available for common shares

$

(75.6)

$

(91.6)

Basic and diluted loss per share:

 

 

 

 

As reported

$

(.20)

$

(.25)

Pro forma

 

(.20)

 

(.25)

 

**Stock Options**

 

Stock options under this plan and preceding plans have been granted at market prices generally with one to three year vesting terms and have been exercisable for seven to 10 years from the date of grant.  In December 2004, we granted fully vested stock options for approximately 1.9 million shares to all employees other than senior executive officers of the company.  These options are exercisable for seven years from the date of grant.  Cash received on stock options exercised was $3.0 million, the intrinsic value of options exercised was $1.2 million and the tax benefit realized was $.4 million for the nine months ended September 30, 2006.  Stock options as of September 30, 2006 and changes during the nine months ended September 30, 2006 were as follows: 

 

 

**Shares**

**Weighted average exercise prices**

**Remaining Contractual Term in Years**

Beginning balance

6,545,607

$14.92

 

Granted

-

-

 

Exercised

(715,668)

4.26

 

Forfeited

(615,526)

23.66

 

**Ending balance**

5,214,413

$15.58

3.5

**Exercisable at September 30, 2006**

5,214,413

$15.58

3.5

 

The aggregate intrinsic value of “in-the-money” outstanding and exercisable options was $2.8 million as of September 30, 2006.

 

**Time-Based Restricted Stock Awards**

 

In 2005, 183,823 shares of restricted stock were awarded to certain managers and executives, excluding senior management, as an incentive to retain their services through this transition time.  

 

28

These awards will vest two years after the award date.  The fair value of these stock awards is determined based on the number of shares granted and the quoted price of our stock.  The compensation expense related to these awards was $.4 million for the nine months ended September 30, 2006.  As of September 30, 2006, the total compensation cost not yet realized was $.3 million.  This compensation cost will be recognized over the period through December 31, 2007.  The total fair value of restricted stock released for the nine months ended September 30, 2006 was $1.0 million.  Non-vested, time-based restricted stock awards as of September 30, 2006 and changes during the nine months ended September 30, 2006 were as follows: 

 

 

**Shares**

**Weighted average grant date fair value**

**Remaining Contractual Term in Years**

Beginning balance

632,210

$17.81

 

Granted

-

-

 

Released

(260,872)

20.25

 

Forfeited

-

-

 

**Ending balance**

371,338

$16.09

1.2

 

**Performance-Based Restricted Stock Awards**

 

Performance-based restricted stock awards were granted in the third quarter of 2006 to qualified individuals, excluding senior management, consisting of the right to receive a number of shares of common stock at the end of the restriction period, March 1, 2008, assuming performance criteria are met.  The performance measure for the award is the ratio of 2007 annual earnings before interest, taxes, depreciation and amortization to net utility plant investment.  The threshold level of performance was a ratio of 10.0%, target at a ratio of 11.5%, and maximum at a ratio of 13.0%.  Shares would be earned at the end of the performance period as follows: 100% of the target number of shares if the target level of performance is reached, 50% if the threshold is reached, and 150% if the ratio is at or above the maximum, with the number of shares interpolated between these levels.  No shares would bepayable if the threshold is not reached. The fair value of these stock awards is determined based on the number of shares granted and the quoted price of our stock on date of the award.  As of September 30, 2006, the estimated total compensation cost not yet recognized was $.7 million.  This compensation cost will be recognized over the period through December 31, 2007.  Non-vested, performance-based restricted stock awards (based on target number) as of September 30, 2006 and changes during the nine months ended September 30, 2006 were as follows:

 

 

**Shares**

**Weighted average grant date fair value**

**Remaining Contractual Term in Years**

Beginning balance

-

$-

 

Granted

176,000

4.44

 

Distributed

-

-

 

Forfeited

-

-

 

**Ending balance**

176,000

$4.44

1.4

 

**Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations**

 

**See Forward-Looking Information beginning on page 52.**

 

**Strategy**

 

Our remaining repositioning initiatives continue to be focused on improving operational results of our integrated electric and gas utility operations and strengthening our credit profile in order to 

 

29

efficiently execute our multi-state regulated utility growth strategy.  The key elements of our remaining repositioning initiatives are to:

 

 

**•**

Complete our pending sale of our Kansas electric utility assets.

 

**•**

Significantly reduce our debt levels and interest expense.

 

**•**

Eliminate the majority of allocated operating costs related to utility divisions that have been sold or are in the process of being sold, when the services are no longer required.

 

**•**

Actively work with regulators and legislators to address capital investment and fuel recovery issues in Missouri.

 

Successful completion of the repositioning initiatives is essential to position the company to execute on the following key elements of our strategy.

 

 

**•**

Maintain synergies of an integrated, multi-state utility.

 

**•**

Continue to improve operational efficiency and lower earnings variability.

 

**•**

Provide competitive earnings growth by, among other things, gaining access to the capital markets on improved terms, allowing the company to more cost-effectively fund investments in its rate base to meet customer needs.

 

We will continue to focus on building and maintaining the generation, transmission and distribution infrastructure necessary to provide our utility customers with safe and reliable service, while increasing the returns on invested capital in jurisdictions that lag behind those of our peers.  We will also focus on improving our returns through future rate activities and process improvements.

 

**Strengthen Credit Profile**

 

With a stronger credit profile we will have the opportunity to more cost effectively invest in power generation, transmission and distribution capacity, as well as undertake environmental upgrades over the next decade.  We believe these normal course investments will not only improve the reliability and quality of our utility service, but also provide a platform for additional growth in our earnings and enhanced shareholder value.

 

We completed a cash tender offer for $350 million of senior notes and exited the Elwood tolling contract for $218 million in June 2006 using the proceeds from the sale of the Illinois peaking power plants and our Michigan and Missouri gas operations.  In September 2006, we elected to prepay the remaining $210 million outstanding on our five-year term loan.  We also expect to use the proceeds from our Kansas electric asset sale to retire debt and reduce interest expense. We have not made a final determination of which debt will be retired.  The particular debt instruments to be retired will depend upon market conditions, the market price of the particular debt instrument, the call provisions, the remaining life of the instrument, our near term capital needs and the timing of the receipt of the sales proceeds.  We intend to apply the sales proceeds in a manner which maximizes the improvementto our credit profile and cash flow.

 

**Current Credit Ratings**

 

In September 2006, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were upgraded to the following ratings: 

 

**Agency**

**Rating**

**Commentary**

Moody's

B2

Stable

S&P

B

Positive Outlook

Fitch

B

Stable

 

 

These ratings upgrades resulted in lower fees and interest on our Iatan Facility.

 

 

30

**LIQUIDITY AND CAPITAL RESOURCES**

 

**Working Capital Requirements**

 

The most significant activity impacting working capital is the purchase of natural gas for our gas utility customers.  We could experience significant working capital requirements during peak months of the winter heating season due to higher natural gas consumption, during potential periods of high natural gas prices and due to our current requirement to prepay certain gas commodity suppliers and pipeline transportation companies.  Under a stressed weather and commodity price environment, such as the spike in commodity prices in late 2005 following an active hurricane season, we estimate our peak working capital needs to be up to $200 million.  We anticipate using the combination of revolving credit and letter of credit facilities listed below and cash on hand to meet our peak winter working capital requirements.

 

**Credit Facility**

**Expiration**

**Maximum****Capacity**

**Borrowings or Letters of****Credit Issued at****September 30, 2006**

 

 

*In millions***

Four-Year Secured    Revolving Credit     Facility

April 22, 2009 *(1)*

$

150.0

$

–

Five-Year Unsecured   Revolving Credit     Facility

September 19, 2009

 

110.0

 

–

$180 Million Unsecured    Revolving Credit and     Letter of Credit     Facility

April 13, 2010 *(1)*

 

180.0

 

116.7

$50 Million Unsecured    Revolving Credit and     Letter of Credit     Facility

December 20, 2006

 

50.0

 

47.6

 

* *

*(1)*

*Borrowings under these facilities must be repaid within 364 days unless we obtain regulatory approval to incur long-term indebtedness under these facilities.*

 

**Potential Aries Acquisition**

 

MEP Pleasant Hill, LLC (MEP) and its parent, Calpine Corporation (“Calpine”), filed for bankruptcy in December 2005.  As part of its plan of reorganization, Calpine announced its intention to sell by the end of 2006 certain power plants owned by it or its subsidiaries.  The Aries Energy Center, a 580 MW gas-fired combined-cycle electric generating facility located in Pleasant Hill, Missouri, is one such plant.  

 

In September 2006, we and MEP entered into an asset purchase agreement pursuant to which we agreed to acquire the Aries Energy Center and certain other rights and obligations relating to the Aries Energy Center for a cash purchase price of $158.5 million. By signing the agreement, we provided the opening bid and will serve as the “stalking horse” bidder in a sales process for the Aries Energy Center supervised by the Bankruptcy Court for the Southern District of New York.  As part of this process, the acquisition is subject to higher or better bids and bankruptcy court approval.  We were required to deposit into escrow $7.9 million when the asset purchase agreement was executed, and we will deposit into escrow an equal cash amount on the date the bankruptcy court enters an order approving the sale.  The escrowed funds will be applied toward the payment of the cash purchase priceat closing or, if applicable, returned to us.****

 

31

The asset purchase agreement contains various representations, warranties and covenants customary for transactions of comparable size and nature.  Completion of the transaction depends on the satisfaction of several closing conditions, including (i) the receipt of an order by the bankruptcy court approving the transaction; (ii) the expiration or early termination of any waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (iii) the approval of the FERC; (iv) the non-occurrence of a material adverse effect, as defined in the asset purchase agreement, with respect to the Aries Energy Center; and (v) the other closing conditions set forth in the asset purchase agreement.  We may terminate the agreement if the transaction does not close on or before December 28, 2006.  In addition, MEP will pay us a break-up fee equal to 2% of the cash purchase price if,subject to certain requirements, MEP sells the Aries Energy Center to a party other than us. 

 

**Environmental Capital Expenditures**

 

The EPA finalized several Clean Air Act regulations such as Clean Air Interstate Rule (CAIR), Best Available Retrofit Technology (BART) and the Clean Air Mercury Rule (CAMR) regulations in 2005 that would affect our coal-fired power plants by requiring reductions in emissions of sulfur dioxide, nitrogen oxide and mercury.  We have completed engineering studies in 2006 which evaluated costs and likely controls for compliance with CAIR, BART and CAMR.  For our Missouri electric operations, we estimate that probable capital expenditures through 2009 will be approximately $138 million and reasonably possible expenditures could be $176 million to comply with the regulations.  If our Kansas electric utility is not sold, our total estimated probable capital expenditures would be approximately $161 million and reasonably possible expenditures could be $199 million.  We believe these costs wouldlikely be allowed for recovery in future rate cases.

 

**Cash Flows**

 

***Cash Flows Provided From (Used For) Operating Activities***

 

Our $10.9 million of negative operating cash flows for the nine months ended September 30, 2006, were largely due to our 2006 operating net loss which was primarily driven by the $218 million loss on our exit from the Elwood toll in the second quarter of 2006. The return of $60.1 million of counterparty collateral resulting from lower natural gas prices since December 2005, and a $25.4 million payment to Calpine in connection with the netting of amounts owed under various contracts at the time of Calpine’s bankruptcy filing also contributed to our negative cash flows.  The decreases were offset by seasonal declines in working capital requirements for our utility operations and the continued wind-down of our merchant trading portfolio which triggered the return of $109.6 million of funds on deposit and a $41.3 million decrease in other current assets.  Additionally, we received $38.7million of funds on deposit returns due to the replacement of cash deposits and cash-collateralized letters of credit with unsecured letters of credit supporting the Elwood tolling contracts, and utilized $18.0 million of gas and other inventory held in storage.  

 

Our $211.3 million of positive operating cash flows for the nine months ended September 30, 2005, were driven primarily by seasonal declines in working capital requirements for our utility operations and an increase in natural gas prices.  The seasonal decline in working capital requirements was the primary cause of the return of $108.7 million of funds on deposit and a $26.1 million decrease in prepayments.  The increase in natural gas prices required our merchant and utilities counterparties to post an additional $130.4 million of collateral with us. Offsetting these increases were the use of $71.1 million of cash to increase our natural gas storage for the winter heating season, a 2005 income tax payment of $30.9 million related to the sale of our Canadian utilities business in 2004, and the $28.0 million settlement with Enron in connection with the netting of amounts owed under variouscontracts at the time of Enron’s bankruptcy filing in 2001.

 

The 14.875% interest rate we pay on $500 million of our long-term debt has substantially increased our interest costs and will continue to negatively impact our operating cash flows.  It will be important for us to substantially improve our operating cash flows. We are attempting to do this 

 

32

by improving the efficiency of our remaining businesses, increasing sales through utility rates, retiring debt and completing the Kansas electric utility asset sale and the continued wind-down of our Merchant Services business. 

 

***Cash Flows Provided From (Used For) Investing Activities***

 

The increase in cash provided from (used for) investing activities was primarily the result of the receipt of cash proceeds on the sale of our Michigan, Missouri and Minnesota gas utilities, our investment in Everest Connections and our merchant peaking power plants. In addition, utility capital expenditures decreased compared to prior year primarily due to the construction of our South Harper peaking facility in 2005.

 

***Cash Flows Used For Financing Activities***

 

Cash flows used for financing activities in the nine months ended September 30, 2006 and 2005 consist primarily of cash we paid to retire our short and long-term debt obligations and our payments under our remaining long-term gas contracts that expire by early 2008.  The increase in cash used for financing activities is primarily related to the completion of a $350 million debt tender offer in June 2006 and the prepayment of our $220 million five-year term loan.  

 

**Collateral Positions**

 

As of September 30, 2006, we had posted collateral for the following in the form of cash or cash collateralized letters of credit:  

 

*In millions***

 

 

Trading positions

$

40.2

Utility cash collateral requirements

 

73.5

Other

 

2.9

Total Funds on Deposit

$

116.6

 

Collateral requirements for our remaining trading positions will fluctuate based on the movement in commodity prices and our credit rating. Changes in collateral requirements will vary depending on the magnitude of the price movement and the current position of our trading portfolio. As these trading positions settle in the future, the collateral will be returned. 

 

We are required to post collateral with certain commodity and pipeline transportation vendors. This amount will fluctuate depending on gas prices and projected volumetric deliveries. The ultimate return of this collateral is dependent on the strengthening of our credit profile. 

 

**FINANCIAL REVIEW**

 

This review of performance is organized by business segment, reflecting the way we managed our business during the periods covered by this report. Each business group leader is responsible for operating results down to earnings before interest, taxes, depreciation and amortization (EBITDA). We use EBITDA as a performance measure as it captures the income and expenses within the management control of our segment business leaders. Because financing for the various business segments is generally completed at the parent company level, EBITDA provides our management and third parties an indication of how well individual business segments are performing. Therefore, each segment discussion focuses on the factors affecting EBITDA, while financing and income taxes are separately discussed at the corporate level. 

 

As further discussed in Note 4 to the Consolidated Financial Statements, we have reported the results of operations of the following assets in discontinued operations in the Consolidated Statements of Income: (i) our Kansas electric utility operations and our former Michigan, Minnesota and Missouri gas utility operations, (ii) our former peaking power plants in Illinois, and (iii) our 

 

33

former communications business, Everest Connections.  Therefore, the operating results of these assets are discussed separately from the reporting segments to which they relate under the caption “Discontinued Operations.”

 

As described in Note 4 to the Consolidated Financial Statements, only direct operating costs associated with the utility divisions currently held for sale have been reclassified to discontinued operations.  The costs related to executive management and centralized services that were allocated to these divisions in 2005 remain in continuing operations.  Effective January 1, 2006, we ceased allocating costs to our held-for-sale utilities.  We plan to eliminate the majority of these costs when these support services are no longer required.  

 

The use of EBITDA as a performance measure is not meant to be considered an alternative to net income or cash flows from operating activities, which are determined in accordance with GAAP. In addition, our use of EBITDA may not be comparable to similarly titled measures used by other entities. 

 

 

**Three Months Ended**

**Nine Months Ended**

 

**September 30,**

**September 30,**

*In millions*

**2006**

**2005**

**2006**

**2005**

Earnings (Loss) Before Interest, Taxes, Depreciation and Amortization:

 

 

 

 

 

 

 

 

Utilities:

 

 

 

 

 

 

 

 

Electric Utilities

$

58.0

$

82.4

$

120.5

$

139.8

Gas Utilities

 

1.6

 

(2.1)

 

29.3

 

19.9

Total Utilities

 

59.6

 

80.3

 

149.8

 

159.7

Merchant Services 

 

(17.0)

 

(9.5)

 

(249.0)

 

(9.8)

Corporate and Other

 

(3.7)

 

(87.2)

 

(32.8)

 

(92.9)

Total EBITDA

 

38.9

 

(16.4)

 

(132.0)

 

57.0

Depreciation and amortization

 

27.0

 

26.0

 

78.5

 

78.4

Interest expense

 

42.7

 

35.6

 

124.4

 

115.5

Income tax expense (benefit) 

 

(10.2)

 

2.0

 

(43.9)

 

(20.1)

Loss from continuing operations

 

(20.6)

 

(80.0)

 

(291.0)

 

(116.8)

Earnings from discontinued    operations, net of tax

 

136.3

 

4.3

 

250.6

 

14.6

Net income (loss)

$

115.7

$

(75.7)

$

(40.4)

$

(102.2)

 

**Key Factors Impacting Results of Continuing Operations**

 

For the nine months ended September 30, 2006, total EBITDA decreased $189.0 million compared to 2005. Key factors affecting 2006 results were as follows: 

 

 

**•**

Total Utilities EBITDA decreased $9.9 million primarily due to the inclusion in 2005 of $27.3 million of mark-to-market gains on certain NYMEX natural gas contracts that are not included in 2006, offset in part by increased margins from recent rate increases, lower fuel and purchased power costs and customer growth.

 

 

**•**

The continued wind-down of our energy trading businesses in 2005 and 2006, including a $218.0 million loss on the exit of the Elwood tolling contract in June 2006 compared to $25.6 million of gains related to the 2005 sale of our investment in ICE and the 2005 assignment of our Batesville tolling agreement and associated forward sale contract, represented the primary causes of the $239.2 million increase in losses before interest and taxes, depreciation and amortization from Merchant Services.  

 

 

**•**

Corporate and other loss before interest, taxes, depreciation and amortization decreased $60.1 million in 2006 compared to 2005, primarily due to the $82.3 million loss in 2005 on the early conversion of the PIES, offset in part by $28.2 million of losses on early 

 

34

retirement of debt in 2006 and the accrual of $5.5 million of severance restructuring costs in connection with the planned elimination of costs after the sale of certain utility operations.

 

**Electric Utilities**

 

The table below summarizes the operations of our Missouri and Colorado Electric Utilities, which represent substantially all of our continuing electric operations:

 

 

**Three Months Ended**

**Nine Months Ended**

 

**September 30,**

**September 30,**

*Dollars in millions***

**2006**

**2005**

**2006**

**2005**

Sales:

 

 

 

 

 

 

 

 

Electricity—regulated

$

242.8

$

215.3

$

601.0

$

517.3

Other—non-regulated

 

.2

 

.1

 

.5

 

.4

Total sales

 

243.0

 

215.4

 

601.5

 

517.7

Cost of sales:

 

 

 

 

 

 

 

 

Electricity—regulated

 

135.0

 

89.9

 

327.7

 

246.6

Other—non-regulated

 

(.4)

 

.1

 

.3

 

.2

Total cost of sales

 

134.6

 

90.0

 

328.0

 

246.8

Gross profit

 

108.4

 

125.4

 

273.5

 

270.9

Operation and maintenance expense

 

44.6

 

40.7

 

134.4

 

123.2

Taxes other than income taxes

 

5.8

 

4.3

 

18.1

 

14.4

Other income (expense)

 

–

 

2.0

 

(.5)

 

6.5

EBITDA

$

58.0

$

82.4

$

120.5

$

139.8

 

 

 

 

 

 

 

 

 

Depreciation and amortization expense

$

18.4

$

15.7

$

52.1

$

46.3

Electric sales and transportation   volumes (GWh)

 

3,053.5

 

3,105.2

 

8,398.7

 

8,325.4

Electric customers at end of period

 

 

 

 

 

397,721

 

391,126

 

***Quarter-to-Quarter***

 

*Sales, Cost of Sales and Gross Profit*

 

Sales and cost of sales for the Electric Utilities business increased $27.6 million and $44.6 million, respectively. However, gross profit decreased by $17.0 million in 2006 compared to 2005.  These changes were primarily due to the following factors:  

 

 

**•**

Sales and gross profit increased by $10.2 million due to a rate increase in Missouri effective March 2006, plus $1.7 million of additional margin from an increase in customers. 

 

 

**•**

Cost of sales increased in the third quarter of 2006 compared to 2005 because we recognized approximately $20.7 million of mark-to-market gains on certain NYMEX natural gas contracts as a result of increases in forward gas prices in the third quarter of 2005.  In 2006, the mark-to-market value of these contracts was recorded as a regulatory asset or liability in accordance with our recent Missouri rate case settlement.  These contracts were primarily purchased to offset the risk of increasing natural gas prices to our Missouri electric operations.

 

 

**•**

Cost of sales increased and gross profit decreased by $3.8 million due to unfavorable derivative settlements net of lower fuel and purchased power costs.

 

 

**•**

Sales and cost of sales increased $13.1 million and $18.6 million, respectively, from 

 

35

higher sales for resale.  Gross profit decreased, however, by $5.5 million from $8.3 million in 2005 to $2.8 million in 2006.

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense increased $3.9 million in 2006 compared to 2005.  A primary factor contributing to this increase was a change in the allocation of executive management and central services costs effective January 1, 2006 to no longer allocate these costs to our held-for-sale utilities.  This change resulted in an increased allocation of these costs to our Electric Utilities of approximately $2.3 million and a corresponding decreased allocation to our Gas Utilities for the quarter.  Also included in the quarter-to-quarter expense increase were a $1.2 million increase in labor and benefit costs and a $.4 million increase in insurance costs.

 

*Depreciation and Amortization Expense*

 

Depreciation and amortization expense increased $2.7 million due to the additional depreciation of our South Harper peaking facility, which was placed in service in the third quarter of 2005, and additional depreciation related to centralized assets such as our billing system and call centers.  The change in the allocation of central services costs mentioned above resulted in an increased allocation of centralized asset depreciation to our Electric Utilities and a corresponding decreased allocation to our Gas Utilities.

 

***Year-to-Date***

 

*Sales, Cost of Sales and Gross Profit*

 

Sales and cost of sales for the Electric Utilities business increased $83.8 million and $81.2 million, respectively, for a gross profit increase of $2.6 million in 2006 compared to 2005.  These changes were primarily due to the following factors:  

 

 

**•**

Sales and gross profit increased by $22.2 million due to rate increases and rate redesign in Missouri effective March 2006 and in Colorado effective March 2005, plus $7.6 million of additional margin from an increase in customers and customer billings and $4.0 million due to increased transmission revenues, the sale of green energy credits, and transition services revenues. 

 

 

**•**

Cost of sales increased in 2006 compared to 2005 because we recognized approximately $27.3 million of mark-to-market gains on certain NYMEX natural gas contracts as a result of increases in forward gas prices in 2005.  In 2006, the mark-to-market value of these contracts was recorded as a regulatory asset or liability in accordance with our recent Missouri rate case settlement.  These contracts were primarily purchased to offset the risk of increasing natural gas prices to our Missouri electric operations.

 

 

**•**

Cost of sales decreased and gross profit increased by $12.7 million due to demand charges for purchased capacity from the Aries plant in 2005 but not in 2006.  Also, unfavorable derivative settlements and higher fuel, purchased power, demand charges and transmission costs increased cost of sales and decreased gross profit by $10.8 million.

 

 

**•**

Sales and cost of sales increased $41.7 million and $48.3 million, respectively, from higher sales for resale.  Gross profit decreased, however, by $6.6 million from $16.3 million in 2005 to $9.7 million in 2006.

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense increased $11.2 million in 2006 compared to 2005.  A primary factor contributing to this increase was a change in the allocation of executive management 

 

36

and central services costs effective January 1, 2006 to no longer allocate these costs to our held-for-sale utilities.  This change resulted in an increased allocation of these costs to our Electric Utilities of approximately $7.5 million and a corresponding decreased allocation to our Gas Utilities.  Also included in the year-to-date expense increase were a $3.9 million increase in labor and benefit costs and a $1.3 million increase in insurance costs, which were partially offset by a $1.4 million decrease in outside services costs primarily related to the 2005 ice storm.

 

*Other Income (Expense)*

 

Other income (expense) decreased $7.0 million primarily due to decreased Allowance for Funds Used During Construction (AFUDC) associated with the construction of our South Harper peaking facility in 2005.  AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during the construction period.  AFUDC is capitalized as a part of the cost of utility plant and is credited to other income.

 

*Depreciation and Amortization Expense*

 

Depreciation and amortization expense increased $5.8 million due to $3.7 million in additional depreciation of our South Harper peaking facility which was placed in service in the third quarter of 2005 and $2.1 million in additional depreciation related to centralized assets such as our billing system and call centers.  The change in the allocation of central services costs mentioned above resulted in an increased allocation of centralized asset depreciation to our Electric Utilities and a corresponding decreased allocation to our Gas Utilities.

 

***Current Developments***

 

**Iatan 2**

 

Our power supply plan indicates the need for additional base-load capacity in Missouri after 2009.  KCPL is developing Iatan 2, an 850 MW coal-fired electric generating facility.  The additional generating capacity is planned for commercial operation in 2010.  Effective June 12, 2006, we entered into the Iatan Unit 2 and Common Facilities Ownership Agreement (the Ownership Agreement) with KCPL, The Empire District Electric Company, Kansas Electric Power Cooperative, Inc., and Missouri Joint Municipal Electric Utility Commission.  The Ownership Agreement provides for the construction, ownership and operation of Iatan 2 adjacent to the existing Iatan electric generation station located in Platte County, Missouri.  We will own an 18% undivided interest in Iatan 2, which will be constructed and operated by KCPL.  We will reimburse KCPL for our pro rata share of the construction, operating andmaintenance costs of, and will be entitled to the energy from our pro rata share of, Iatan 2 generating capacity.

 

**Potential Aries Acquisition**

 

In September 2006, we and a subsidiary of Calpine entered into an asset purchase agreement regarding our potential acquisition of the Aries Energy Center, a 580 MW gas-fired, combined-cycle electric generating facility located in Pleasant Hill, Missouri.  We expect this transaction to close in the fourth quarter of 2006, subject to (i) the bankruptcy court approving our “stalking horse” bid and not accepting a higher or better bid from another bidder through a court-supervised auction process, and (ii) the completion of the closing conditions described in the asset purchase agreement. 

 

***Earnings Trend***

 

Our Missouri electric assets comprise a majority of our utility assets, and the earnings generated by our Missouri electric operations account for a majority of our total utility earnings and revenue.  We expect this trend to continue, and for our financial condition to become increasingly dependent on the revenue and earnings generated by our Missouri electric operations, as we complete the sale of our Kansas electric business and the wind-down of our remaining Merchant Services operations.  As 

 

37

we increase rates and eliminate costs formerly allocated to our other operations, we expect the earnings generated by our Missouri electric operations to improve.

 

The February 2006 settlement of our electric rate case in Missouri is expected to increase annual sales by approximately $26.3 million, net of the former interim energy charge.  To the extent that our costs of natural gas used for fuel and purchased power or other operating expenses increase or decrease from the level of costs recovered in the current rate case settlement, the impact of the change will affect our operating results.  The $4.5 million settlement of our Missouri steam case includes an 80% sharing of fuel cost changes from the base fuel rate.

 

As discussed in Note 4 to the Consolidated Financial Statements, certain allocated executive management and centralized services costs associated with our electric and gas utility divisions sold or held for sale cannot be immediately eliminated when the asset sales close.  We intend to eliminate these costs to the greatest extent possible.  To the extent we are unsuccessful in eliminating these costs, our earnings could be adversely affected.

 

We have entered into a program for our Missouri electric utility operations to mitigate our exposure to natural gas price volatility in the market.  The mark-to-market liability position of the portfolio of $17.8 million relates to contracts that will settle against actual purchases of natural gas and purchased power in 2006 through 2008.  In connection with the recently settled Missouri electric rate case, we agreed that these contracts would be recognized into cost of sales when they settle.  A net regulatory asset has been recorded under SFAS No 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS 71) in the amount of $17.8 million to reflect the change in the timing of recognition authorized by the Missouri Commission. 

 

As a result of the fuel adjustment clause legislation signed into law in July 2005, the Missouri Commission will set forth rules regarding the implementation and definition of costs to be recovered in a fuel adjustment mechanism for our Missouri electric operations.  On July 17, 2006, rules proposed by the Missouri Commission that pertain to electric utility fuel and purchased power adjustment mechanisms were published for comments.  On September 19, 2006, the Commission approved rules and sent them to a joint committee of the legislature.  On October 23, 2006, the joint committee sent the rules to the Secretary of State for final public notification.  The rules become final 60 days after public notice is made.  We expect the value of our NYMEX financial contracts to be a part of the defined costs to be recovered through the fuel adjustment clause.  If so, the settlement of the contracts,as well as the cost of the physical fuel and purchased power from the marketplace, will flow through to the customer.  

 

38

**Gas Utilities**

 

The table below summarizes the operations of our Colorado, Iowa, Kansas and Nebraska Gas Utilities, which represent substantially all of our continuing gas operations:

 

 

**Three Months Ended**

**Nine Months Ended**

 

**September 30,**

**September 30,**

*Dollars in millions***

**2006**

**2005**

**2006**

**2005**

Sales:

 

 

 

 

 

 

 

 

Natural gas—regulated

$

71.4

$

74.1

$

413.3

$

386.1

Other—non-regulated

 

6.6

 

7.4

 

23.0

 

15.6

Total sales

 

78.0

 

81.5

 

436.3

 

401.7

Cost of sales:

 

 

 

 

 

 

 

 

Natural gas—regulated

 

43.9

 

46.7

 

300.2

 

276.0

Other—non-regulated

 

2.7

 

4.6

 

14.6

 

8.5

Total cost of sales

 

46.6

 

51.3

 

314.8

 

284.5

Gross profit

 

31.4

 

30.2

 

121.5

 

117.2

Operation and maintenance expense

 

27.4

 

29.5

 

83.3

 

89.2

Taxes other than income taxes

 

2.7

 

2.6

 

8.8

 

8.1

Other income (expense)

 

.3

 

(.2)

 

(.1)

 

–

EBITDA

$

1.6

$

(2.1)

$

29.3

$

19.9

 

 

 

 

 

 

 

 

 

Depreciation and amortization expense

$

7.7

$

8.5

$

24.6

$

26.7

 

 

 

 

 

 

 

 

 

Gas sales and transportation volumes (Bcf)

 

16.4

 

16.0

 

68.1

 

67.3

Gas customers at end of period

 

 

 

 

 

505,544

 

496,629

 

***Quarter-to-Quarter***

 

*Sales, Cost of Sales and Gross Profit*

 

Sales and cost of sales for the Gas Utilities business decreased $3.5 million and $4.7 million, respectively, for a gross profit increase of $1.2 million in 2006 compared to 2005.  These changes were primarily due to the following factors:  

 

 

**•**

Sales and cost of sales decreased approximately $6.4 million due to a 12.4% decrease in natural gas prices in the third quarter of 2006 compared to 2005.  However, because gas purchase costs for our gas utility operations are passed through to our customers, the change in gas prices did not have a corresponding impact on gross profit.

 

 

**•**

Sales and gross profit increased by $.6 million due to a rate increase in Iowa effective in May 2005 on an interim basis and finalized in March 2006.

 

 

**•**

Sales and gross profit decreased by $1.4 million due to a Kansas weather normalization adjustment recorded in the third quarter of 2005.  Slightly offsetting that decrease was higher weather-related and other customer usage that increased sales, cost of sales and gross profit by $3.4 million, $3.1 million and $.3 million, respectively.

 

 

**•**

Non-regulated gross profit increased by $1.1 million primarily due to the sale of excess pipeline capacity.

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense decreased $2.1 million in 2006 compared to 2005.  The primary cause of the decrease was a change in the allocation of executive management and central services costs effective January 1, 2006 to no longer allocate these costs to our held-for-sale utilities.  

 

39

This change resulted in an increased allocation of these costs to our Electric Utilities of approximately $2.3 million and a corresponding decreased allocation to our Gas Utilities.  

 

***Year-to-Date***

 

*Sales, Cost of Sales and Gross Profit*

 

Sales and cost of sales for the Gas Utilities business increased $34.6 million and $30.3 million, respectively, for a gross profit increase of $4.3 million in 2006 compared to 2005.  These changes were primarily due to the following factors:  

 

 

**•**

Sales and cost of sales increased approximately $47.7 million due to a 19.4% increase in natural gas prices on the average in 2006 compared to 2005.  However, because gas purchase costs for our gas utility operations are passed through to our customers, the change in gas prices did not have a corresponding impact on gross profit.

 

 

**•**

Sales and gross profit increased by $3.3 million due to an interim rate increase in Iowa effective in May 2005 on an interim basis and finalized in March 2006, and a rate increase in Kansas effective in June 2005, plus $.9 million of additional margin from an increase in customers.

 

 

**•**

Unusually mild winter weather decreased gas volumes sold and reduced sales, cost of sales and gross profit by $30.9 million, $27.6 million and $3.3 million, respectively, in the first nine months of 2006.

 

 

**•**

Sales and gross profit increased $1.7 million due to revenue from transition services provided to the purchaser of our Michigan and Missouri gas utility assets.

 

 

**•**

Non-regulated sales, cost of sales and gross profit increased $7.4 million, $6.1 million and $1.3 million, respectively, primarily due to the resale of excess natural gas resulting from weather-related sales volume decreases and the sale of excess pipeline capacity in Nebraska.

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense decreased $5.9 million in 2006 compared to 2005.  The primary cause of the decrease was a change in the allocation of executive management and central services costs effective January 1, 2006 to no longer allocate these costs to our held-for-sale utilities. This change resulted in an increased allocation of these costs to our Electric Utilities of approximately $7.5 million and a corresponding decreased allocation to our Gas Utilities. Partially offsetting this decrease was a $1.9 million increase in employee benefit costs.

 

***Regulatory Matters***

 

 

The following is a summary of our recent rate case activity through October 31, 2006:

 

*In millions*

**Type of****Service**

**Date****Requested**

**Date****Effective**

**Amount****Requested**

**Amount****Approved**

Kansas *(1)*

Electric

6/2004

4/2005

$

16.4

$

8.0

Kansas *(2)*

Gas

11/2004

6/2005

 

6.2

 

2.7

Iowa *(3)*

Gas

5/2005

3/2006

 

4.1

 

2.9

Missouri *(4)*

Electric

5/2005

3/2006

 

78.6

 

44.8

Missouri *(4)*

Steam

5/2005

3/2006

 

5.0

 

4.5

Missouri *(5)*

Electric

7/2006

Pending

 

118.9

 

Pending

 

 

(1)

In connection with the settlement, our Energy Cost Adjustment (ECA) provision was modified to allow the pass through of SO2 emission allowance costs to customers.

 

40

 

 

(2)

The Kansas gas settlement also included $244,000 per year for three years for a pipe replacement program. 

 

 

(3)

Under Iowa regulations, we instituted interim rates, subject to refund, totaling approximately $1.7 million in May 2005.  On March 1, 2006, the Iowa Utilities Board (IUB) issued an order approving a $2.9 million rate increase, including recovery of rate case costs.  The order denied a settlement provision that would have established a recovery mechanism for investments in distribution system integrity. However, at our request, the IUB agreed to rehear the distribution system integrity issue.  In an order dated September 12, 2006, the IUB affirmed its earlier decision denying a recovery mechanism for investments in distribution system integrity. Final rates became effective March 17, 2006.

 

 

(4)

The Missouri electric settlement terminated the interim energy charge established in our 2003 rate case filing and required a $1.0 million refund to our St. Joseph Light & Power customers as part of the termination.  The settlement also established the value of our South Harper peaking facility at approximately $140 million, resulting in an additional $4.4 million impairment of the plant’s turbines.  The settlement was approved by the Missouri Commission on February 23, 2006, and the new rates became effective March 1, 2006.  In addition, in February 2006, we settled the Missouri steam rate case for a $4.5 million rate increase.  This settlement includes a provision for sharing 80% of fuel cost variability from the established base fuel rates.  It was approved by the Missouri Commission in February 2006, and the new rates became effective March 6,2006.

 

 

(5)

On July 3, 2006, we filed for a $94.5 million rate increase, or 22.0%, in our Missouri Public Service territory and a $24.4 million increase, or 22.1%, in our St. Joseph Light & Power territory.  These increases were requested to recover increases in the cost of fuel and purchase power capacity and increased operating costs.  The amount of the request is based, among other things, on a return on equity of 11.5% and an adjusted equity ratio of 47.5%.  In addition, we requested the implementation of a fuel adjustment clause.

 

The Missouri Commission staff’s case is due to be filed January 18, 2007.  Rebuttal testimony is scheduled to be filed on February 20, 2007, and evidentiary hearings are scheduled to begin April 2, 2007.  We expect the Commission to rule on our request in May 2007, with approved rate changes taking effect on June 1, 2007.

 

41

**Merchant Services**

 

 

The table below summarizes the operations of our Merchant Services businesses:

 

 

**Three Months Ended**

**Nine Months Ended**

 

**September 30,**

**September 30,**

*Inmillions*

**2006**

**2005**

**2006**

**2005**

Sales

$

(4.4)

$

3.9

$

(7.3)

$

(3.0)

Cost of sales

 

.6

 

9.9

 

18.4

 

32.1

Gross loss

 

(5.0)

 

(6.0)

 

(25.7)

 

(35.1)

Operating expenses:

 

 

 

 

 

 

 

 

Operation and maintenance expense, net

 

11.1

 

3.5

 

10.8

 

3.8

Taxes other than income taxes

 

(.1)

 

**–**

 

(4.6)

 

(7.0)

Restructuring charges

 

**–**

 

**–**

 

**–**

 

6.6

Net (gain) loss on sale of assets and other charges

 

–

 

**–**

 

218.7

 

(25.6)

Total operating expenses (income), net

 

11.0

 

3.5

 

224.9

 

(22.2)

Other income (expense)

 

(1.0)

 

**–**

 

1.6

 

3.1

Earnings (loss) before interest, taxes, depreciation and amortization 

$

(17.0)

$

(9.5)

$

(249.0)

$

(9.8)

 

 

 

 

 

 

 

 

 

Depreciation and amortization expense

$

1.0

$

1.7

$

3.1

$

5.3

 

We show our gains and losses from energy trading contracts on a net basis. To the extent losses exceeded gains, sales are shown as a negative number. 

 

***Quarter-to-Quarter***

 

*Sales, Cost of Sales and Gross Loss*

 

Gross loss for our Merchant Services operations for the three months ended September 30, 2006 was $5.0 million, primarily due to the following factors:

 

 

**•**

We incurred margin losses of $1.9 million resulting from the difference between revenue recognized on our two remaining long-term gas delivery contracts compared to the net cost of gas delivered under these contracts.  These contracts expire by early 2008.

 

 

**•**

We also incurred a $3.1 million gross loss related to the settlement of various contracts and trade positions and other settlements in the third quarter of 2006 due to the continued wind-down of our merchant operations.

 

Gross loss for our Merchant Services operations for the three months ended September 30, 2005 was $6.0 million, primarily due to the following factors:

 

 

**•**

As part of the continued wind-down of our wholesale energy trading operations, we assigned the final year of our obligation under a stream flow contract and recorded additional margin of $2.4 million in the third quarter of 2005, the final quarter of our obligation.  

 

 

**•**

In the third quarter of 2005, we recorded a net margin loss of $7.8 million associated with our Elwood tolling agreement.  We made fixed capacity payments evenly throughout the year that entitled us to generate power at the Elwood plant.  The cost to purchase natural gas to fuel this power plant generally exceeded the value of the power that could be generated.  Accordingly, we did not generate material revenues.  

 

 

**•**

Approximately $3.0 million of gross profit was a non-cash gain related to the discounting of our trading portfolio.  We discount the future cash flows of our price risk management assets 

 

42

based on our counterparties’ credit standing, versus the future cash flows of our price risk management liabilities that are discounted at our credit standing.  

 

 

**•**

We incurred margin losses of $1.8 million resulting from the difference between revenue recognized on our two remaining long-term gas delivery contracts and the net cost of gas delivered under these contracts.  

 

 

**•**

We also incurred a $1.7 million gross loss related to the settlement of various contracts and trade positions and other settlements in the third quarter of 2005 due to the continued wind-down of our Merchant operations.

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense increased $7.6 million from 2005 primarily due to the provision of a $9.3 million net reserve related to price reporting litigation offset in part by lower salary and other expenses.

 

***Year-to-Date***

 

*Sales, Cost of Sales and Gross Loss*

 

Gross loss for our Merchant Services operations for the nine months ended September 30, 2006 was $25.7 million, primarily due to the following factors:

 

 

**•**

In the first nine months of 2006, we recorded net margin losses associated with our Elwood tolling agreements of $17.8 million.  We did not generate material revenues on this capacity.  

 

 

**•**

We incurred margin losses of $5.7 million resulting from the difference between revenue recognized on our two remaining long-term gas delivery contracts and the net cost of gas delivered under these contracts.

 

 

**•**

We also incurred a $2.2 million gross loss related to the settlement of various contracts and trade positions and other settlements due to the continued wind-down of our merchant operations.

 

Gross loss for our Merchant Services operations for the nine months ended September 30, 2005 was $35.1 million, primarily due to the following factors:

 

 

**•**

In the first nine months of 2005, we recorded a net margin loss of $24.0 million associated with our Elwood tolling agreement. We did not generate material revenues on this capacity.  

 

 

**•**

Included in our gross loss for the nine months ended September 30, 2005 were mark-to-market losses of approximately $7.4 million, related to our stream flow transaction.  

 

 

**•**

We recorded a margin loss of $4.5 million on the 2005 write-off of certain balances retained in our previous sale of gas pipeline investments.

 

 

**•**

We also incurred margin losses of $5.2 million resulting from the difference between revenue recognized on our two remaining long-term gas delivery contracts and the net cost of gas delivered under these contracts.

 

 

**•**

Partially offsetting the gross loss for 2005 was the termination of certain commodity and interest rate hedges.  The termination of the hedges and the release of our contingent obligation to the buyer of our former merchant loan portfolio resulted in the reversal of related reserves of $7.1 million associated with these contracts.

 

43

 

**•**

We recorded $3.3 million of gross profit associated with the non-cash gains related to the discounting of our trading portfolio.  We discount the future cash flows of our price risk management assets based on our counterparties’ credit standing, versus the future cash flows of our price risk management liabilities that are discounted at our credit standing. 

 

 

**•**

We also incurred a $4.3 million gross loss related to the settlement of various contracts and trade positions and other settlements due to the continued wind-down of our Merchant operations.

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense increased $7.0 million from 2005 primarily due to the provision of a $9.3 million net reserve related to price reporting litigation offset in part by lower salary and other expenses.

 

*Taxes Other Than Income Taxes*

 

Refunds of taxes other than income taxes decreased $2.4 million from 2005 primarily due to the difference between the $7.1 million refund of value added taxes we received in 2005 and the $5.7 million refund of Canadian goods and services taxes we received in 2006.

 

*Restructuring Charges*

 

Restructuring charges decreased $6.6 million in the first nine months of 2006, primarily due to the 2005 termination of the majority****of the remaining leases associated with our former Merchant Services headquarters that did not recur in 2006.

 

*Net (Gain) Loss on Sale of Assets and Other Charges*

 

In the first nine months of 2006, we recorded a pretax loss of $218.0 million on the assignment of our rights and obligations under the Elwood tolling agreement.  In 2005, we had pretax gains of $16.3 million on the assignment of our rights and obligations under the Batesville tolling agreement and related forward sale contract and $9.3 million on the sale of our stock investment in ICE.

 

***Earnings Trend and Impact of Changing Business Environment***

 

The merchant energy sector has been negatively impacted by the increase in generation capacity that became operational in 2002 and 2003. This increase in supply has placed downward pressure on power prices and subsequently the value of unsold merchant generation capacity. Although weather and market conditions enabled us to generate $2.3 million of gross profit in 2005, it is generally expected that the fuel and start-up costs of operating our Crossroads peaking power plant will exceed the revenues that would be generated from the power sold.  We therefore believe that during the foreseeable future we will have limited assurance of our ability to generate power at the Crossroads facility for a gross profit. We will continue to have operating and maintenance costs associated with this plant, whether it is being utilized to generate power or is idle. We continue to look for viable solutionsto the utilization of our unsold merchant generation capacity.  Additionally, we continue to wind down and terminate our remaining trading positions with various counterparties.  However, it will take a number of years to complete the wind-down, and we continue to deliver gas under our remaining long-term gas contracts.  Because most of our remaining trading positions are hedged, we should experience limited fluctuation in earnings or losses other than the impacts from counterparty credit, the discounting or accretion of interest, and the termination or liquidation of additional trading contracts. As a result of the above factors, we do not expect Merchant Services to be profitable in the next two to three years.

 

We evaluated the carrying value of our Crossroads merchant peaking power plant as of December 31, 2005.  We performed this evaluation due to reduced spark spreads and an oversupply of generation that we expect will continue for the foreseeable future.  This situation has prevented 

 

44

the plant from producing significant margins and, in turn, has created losses for us.  It is forecasted that these losses will continue for the next few years.  We separately tested the cash flows for the plant based on estimated margin contributions and forecasted operating expenses over its remaining plant life.  The peaking plant was placed into service in 2002 and we depreciate the facility over 35 years.  In evaluating future estimated margin contributions, we used external price curves based on four different future price environments.  In each environment, we calculated an average margin contribution based on a multi-simulation scenario analysis and then equally weighted each price environment.  Based on this analysis and the level of probability we would sell the asset, the undiscounted probability weighted cash flows for the plant exceeded its current book value.  Therefore, under SFAS 144no impairment was required as of December 31, 2005.  We have evaluated this asset as held and used.  If at some future date we determine this asset is held for sale, based on current market values, we would likely record a material impairment charge.  As of September 30, 2006, the carrying value of this plant was $119.8 million.  

 

**Corporate and Other**

 

 

The table below summarizes the operating results of Corporate and Other:

 

 

**Three Months Ended**

**Nine Months Ended**

 

**September 30,**

**September 30,**

*In millions***

**2006**

**2005**

**2006**

**2005**

Sales

$

**–**

$

**–**

$

.1

$

**–**

Cost of sales

 

**–**

 

**–**

 

**–**

 

**–**

Gross profit 

 

**–**

 

**–**

 

.1

 

**–**

Operating expenses:

 

 

 

 

 

 

 

 

Operation and maintenance expense

 

4.7

 

5.6

 

12.3

 

14.4

Taxes other than income taxes

 

.1

 

.1

 

.3

 

.3

Restructuring charges

 

.6

 

**–**

 

5.5

 

**–**

Net loss on sale of assets and other charges

 

5.5

 

82.3

 

28.2

 

82.3

Total operating expenses

 

10.9

 

88.0

 

46.3

 

97.0

Other income

 

7.2

 

.8

 

13.4

 

4.1

Earnings (loss) before interest, taxes,     depreciation and amortization

$

(3.7)

$

(87.2)

$

(32.8)

$

(92.9)

 

 

 

 

 

 

 

 

 

Depreciation and amortization expense

$

(.1)

$

.1

$

(1.3)

$

.1

 

***Quarter-to-Quarter***

 

*Net Loss on Sale of Assets and Other Charges*

 

In the third quarter of 2006, we recorded a pretax loss of $5.5 million primarily upon the prepayment of our five-year term loan.  In the third quarter of 2005, we recorded a loss of $82.3 million related to the early conversion of the PIES.

 

*Other Income*

 

Other income increased $6.4 million in 2006 compared to 2005 primarily due to increased interest income on available cash balances and lower letter of credit fees under our $180 million Revolving Credit and Letter of Credit Facility.

 

45

***Year-to-Date***

 

*Restructuring Charges*

 

In connection with the sale of our Kansas electric and Michigan, Minnesota and Missouri gas operations, management has adopted and communicated to employees a plan to reduce executive management and central services costs, which includes the elimination of approximately 80 employee positions through involuntary terminations.  Approximately $5.5 million of the estimated total of $5.7 million of one-time termination benefits were accrued in the first nine months of 2006.

 

*Net Loss on Sale of Assets and Other Charges*

 

In the first nine months of 2006, we recorded a pretax loss of $28.2 million upon the completion of a cash tender offer that resulted in the early retirement of approximately $350 million of outstanding senior notes and the prepayment of our five-year term loan.  In the third quarter of 2005, we recorded a loss of $82.3 million related to the early conversion of the PIES.

 

*Other Income*

 

Other income increased $9.3 million in 2006 compared to 2005 primarily due to increased interest income on available cash balances partially offset by additional letter of credit fees under our $180 million Revolving Credit and Letter of Credit Facility.

 

**Interest Expense and Income Tax Benefit**

 

 

The table below summarizes our consolidated interest expense and income tax benefit:

 

 

**Three Months Ended**

**Nine Months Ended**

 

**September 30,**

**September 30,**

*In millions***

**2006**

**2005**

**2006**

**2005**

 

 

 

 

 

 

 

 

 

Interest expense

$

42.7

$

35.6

$

124.4

$

115.5

 

Income tax expense (benefit)

$

(10.2)

$

2.0

$

(43.9)

$

(20.1)

 

***Quarter-to-Quarter***

 

*Interest Expense*

 

Interest expense increased $7.1 million in 2006 compared to 2005 primarily due to $11.8 million of decreased allocations of interest to discontinued operations due to the completion of the sale of certain assets.  This increase in expense for continuing operations reflects the delay between the receipt of cash proceeds and the use of that cash to reduce debt.  In addition, to the extent that cash proceeds are used to reduce obligations other than debt, such as our former Elwood tolling agreement, this interest expense will remain in continuing obligations.  The increase also includes the write-off of $3.5 million of deferred debt costs related to the prepayment of our five-year term loan in September 2006.  These increases were offset in part by $7.4 million of lower interest costs resulting from the retirement of $350 million of senior notes in a debt tender in June 2006.

 

*Income Tax Benefit*

 

Income tax benefit increased $12.2 million in 2006 compared to 2005.  The effective tax rate in 2006 was 33.1% compared to (2.6)% in 2005 as a result of the $31.6 million tax provision effect of the treatment of the 2005 loss on early conversion of the PIES as non-deductible for income tax purposes.

 

46

***Year-to-Date***

 

*Interest Expense*

 

Interest expense increased $8.9 million in 2006 compared to 2005 primarily due to $22.9 million of decreased allocations of interest to discontinued operations due to the completion of the sale of certain assets, the write-off of $3.5 million of deferred debt costs related to the prepayment of our five-year term loan in September 2006, $2.6 million of increased interest on floating rate debt and $1.2 million of increased interest and fees on our revolving lines of credit.  These increases were offset in part by the early conversion of the PIES in July 2005 which decreased interest expense by $10.6 million, $6.3 million of lower interest costs resulting from the retirement of $350 million of senior notes in a debt tender in June 2006 and a $1.6 million decrease from other debt retirements in 2005.

 

*Income Tax Benefit*

 

Income tax benefit increased $23.8 million in 2006 compared to 2005.  The effective tax rate in 2006 was 13.1% compared to 14.7% in 2005 as a result of the $81.8 million reserve for contingent tax liabilities provided in the second quarter of 2006 in connection with the $218 million loss on the assignment of our obligations under the Elwood tolling agreement and the 2005 reversal of $3.7 million of income tax valuation allowances previously provided on capital losses due to the recognition of a capital gain on the sale of our ICE shares in March 2005, offset in part by non-deductible interest and the loss on early conversion of the PIES in 2005.

 

**Discontinued Operations**

 

As further discussed in Note 4 to the Consolidated Financial Statements, we have reported the results of operations of our Kansas electric utility, our former Michigan, Minnesota and Missouri gas utilities, our former Raccoon Creek and Goose Creek merchant peaking plants and our former Everest Connections business, in discontinued operations in the Consolidated Statements of Income for all periods presented.  The operating results of these operations are summarized in the table below.  

 

 

47

 

* *

**Three Months Ended**

**Nine Months Ended**

* *

**September 30,**

**September 30,**

*Dollars in millions*

**2006**

**2005**

**2006**

**2005**

Sales

$

61.8

$

142.9

$

479.3

$

585.9

Cost of sales

 

30.5

 

79.2

 

322.6

 

385.4

Gross profit

 

31.3

 

63.7

 

156.7

 

200.5

Operating expenses:

 

 

 

 

 

 

 

 

Operation and maintenance expense

 

11.0

 

25.9

 

61.0

 

79.3

Taxes other than income taxes

 

1.4

 

1.6

 

9.8

 

4.4

Restructuring charges

 

–

 

–

 

2.0

 

–

Net (gain) on sale of assets and other charges

 

(122.2)

 

–

 

(270.8)

 

–

Total operating expenses (income)

 

(109.8)

 

27.5

 

(198.0)

 

83.7

Other income (expense)

 

(.4)

 

.4

 

.1

 

.2

EBITDA

 

140.7

 

36.6

 

354.8

 

117.0

Depreciation and amortization expense

 

–

 

12.7

 

.9

 

38.4

Interest expense 

 

4.5

 

16.4

 

30.7

 

53.6

Income before income taxes

 

136.2

 

7.5

 

323.2

 

25.0

Income tax expense (benefit) 

 

(.1)

 

3.2

 

72.6

 

10.4

Earnings from discontinued operations, net of tax

$

136.3

$

4.3

$

250.6

$

14.6

 

 

 

 

 

 

 

 

 

Electric sales and transportation   volumes (GWh)

 

669.7

 

675.6

 

1,755.3

 

1,765.5

Electric customers at end of period

 

 

 

 

 

69,077

 

68,764

Gas sales and transportation   volumes (Bcf)

 

–

 

18.6

 

52.6

 

89.0

Gas customers at end of period

 

 

 

 

 

–

 

404,251

 

***Quarter-to-Quarter***

 

*Sales, Cost of Sales and Gross Profit*

 

Electric Utilities

 

Sales and cost of sales for our Kansas electric utility decreased $5.4 million and $5.7 million, respectively, resulting in a gross profit increase of $.3 million in 2006 compared to 2005.  Growth in the number of customers served was the primary driver of the increase in the quarter.  The unfavorable impact of weather was offset by lower fuel and purchased power costs.  

 

Gas Utilities

 

Sales and cost of sales for our Michigan, Minnesota, and Missouri gas utilities decreased $56.7 million and $34.0 million, respectively, resulting in a gross profit decrease of $22.7 million.  No margins were realized from these sold businesses during the third quarter of 2006.

 

Corporate and Other

 

Sales, cost of sales and gross profit decreased $11.8 million, $3.6 million, and $8.2 million, respectively, in 2006 compared to 2005 due to the sale of our Everest Connections subsidiary in June 2006.

 

48

*Operation and Maintenance Expense*

 

Operation and maintenance expense decreased $14.9 million in 2006 compared to 2005 primarily as a result of the sale of our former Michigan, Missouri, and Minnesota gas operations and our Everest Connections subsidiary.

 

*Net (Gain) Loss on Sale of Assets and Other Charges*

 

In the third quarter of 2006, we closed on the sale of our Minnesota gas operations and recognized a gain of $122.0 million.

 

*Depreciation and Amortization Expense*

 

Depreciation and amortization expense decreased $12.7 million in 2006 compared to 2005.  Depreciation from our Kansas electric utility business was eliminated in the third quarter of 2006, due to its classification as held for sale in accordance with SFAS 144.  SFAS 144 requires that depreciation expense no longer be recorded for those assets classified for accounting purposes as held for sale.  No depreciation was incurred in the third quarter of 2006 for the sold gas utilities, peaking plants or Everest Connections.

 

*Interest Expense*

 

Interest expense decreased $11.9 million in 2006 compared to 2005 as the allocations to our Michigan, Missouri and Minnesota gas operations, our two Illinois merchant peaking facilities and our Everest Connections subsidiary ended when they were sold.

 

*Income Tax Expense (Benefit)*

 

Income tax benefit increased $3.3 million in 2006 compared to 2005.  The effective income tax rate for 2006 was (.1)% compared to 42.7% for 2005 primarily due to the reversal of $56.0 million of valuation allowances on capital losses resulting from estimated capital gains realized on the sale of our Michigan and Missouri gas operations.

 

***Year-to-Date***

 

*Sales, Cost of Sales and Gross Profit*

 

Electric Utilities

 

Sales for our Kansas electric utility increased $3.9 million, while cost of sales decreased $2.5 million, resulting in a $6.4 million increase in gross profit in 2006 compared to 2005.  Sales and gross profit increased by $2.2 million due to a rate increase in Kansas effective in April 2005, by $.3 million due to warmer weather and other changes in customer usage, and by $1.2 million due to increased transmission and other revenues.  Lower demand charges and transmission costs combined with the positive impact of emission allowance cost recovery in the ECA resulted in a net $2.2 million increase in gross profit.  Growth in the number of customers served caused gross profit to increase by $.5 million in 2006.

 

Gas Utilities

 

Sales and cost of sales for our Michigan, Minnesota, and Missouri gas utilities decreased $88.8 million and $48.4 million, respectively, resulting in a gross profit decrease of $40.4 million.  The sale of our Michigan, Missouri and Minnesota gas operations decreased sales, cost of sales and gross profit by $88.0 million, $57.2 million and $30.8 million, respectively.  Sales and cost of sales increased approximately $50.8 million due to a 32.8% increase in gas costs which were passed through to our customers with no impact on gross profit.  Unseasonably mild winter weather 

 

49

decreased gas volumes sold and reduced sales, cost of sales and gross profit, primarily in Michigan and Minnesota, by $52.0 million, $44.2 million and $7.8 million, respectively, in the first half of 2006.

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense decreased $18.3 million in 2006 compared to 2005 primarily as a result of the sale of our Michigan and Missouri gas operations and our Everest Connections subsidiary in the second quarter of 2006 and the sale of our Minnesota gas operations at the beginning of the third quarter of 2006.

 

*Taxes Other Than Income Taxes*

 

Taxes other than income taxes increased $5.4 million in 2006 compared to 2005, primarily due to a Minnesota property tax settlement in 2005 regarding protested property valuations in prior tax years.

 

*Net (Gain) Loss on Sale of Assets and Other Charges*

 

In the first nine months of 2006, we closed on the sale of our Michigan gas operations, our Missouri gas operations, our Minnesota gas operations and Everest Connections and recognized gains of $94.2 million, $30.0 million, $122.0 million and $25.5 million, respectively.

 

*Depreciation and Amortization Expense*

 

Depreciation and amortization expense decreased $37.5 million in 2006 compared to 2005 as a result of the elimination of depreciation from our Kansas electric and Michigan, Minnesota and Missouri gas utility businesses, Goose Creek and Raccoon Creek peaking plants and Everest Connections in the first half of 2006, due to their classification as held for sale in accordance with SFAS 144.  Depreciation from Kansas electric utility operations continued to be eliminated in the third quarter of 2006 in accordance with SFAS 144, and no depreciation was incurred on the sold businesses in the third quarter of 2006.

 

*Interest Expense*

 

Interest expense decreased $22.9 million in 2006 compared to 2005 as the allocations to our Michigan gas operations, our Missouri gas operations, our Minnesota gas operations, our two Illinois merchant peaking facilities and our Everest Connections subsidiary ended when they were sold.  In addition, allocations to the Illinois merchant peaking facilities decreased in the first quarter of 2006 due to the decrease in the proportion of these assets to total net assets resulting from the impairment charges recognized in the fourth quarter of 2005.

 

*Income Tax Expense (Benefit)*

 

Income tax expense increased $62.2 million in 2006 compared to 2005 due in part to the increased income before income taxes resulting from the gains on the sales discussed above. The effective income tax rate for 2006 was 22.5% compared to 41.6% for 2005 primarily due to the reversal of $56.0 million of valuation allowances on capital losses resulting from estimated capital gains realized on the sale of our Michigan and Missouri gas operations, partially offset by effect of the write-off of non-deductible acquisition premiums in the pretax gain on the sale of our Michigan gas operations.

 

**Significant Balance Sheet Movements**

 

Total assets decreased by $1,190.2 million since December 31, 2005. This decrease is primarily due to the following:

 

50

 

**•**

Cash increased $202.3 million. See our Consolidated Statement of Cash Flows for analysis of this increase.

 

 

**•**

Short-term investments increased $42.5 million as we moved funds in excess of immediate liquidity needs into investments with terms longer than three months.

 

 

**•**

Funds on deposit decreased $148.3 million, primarily due to the return of margin deposits associated with the seasonal decrease in gas purchases by our regulated utilities and the replacement of cash-collateralized letters of credit with unsecured letters of credit.

 

 

**•**

Accounts receivable decreased $204.5 million, primarily reflecting seasonal declines in regulated gas customer deliveries, the effects of lower natural gas prices, and lower volumes of gas and electricity delivered due to the continued wind-down of our wholesale energy trading business.

 

 

**•**

Price risk management assets decreased $222.4 million, primarily due to a decrease in natural gas prices since December 31, 2005 and the expiration of gas forward contracts and options at the end of the winter heating season.

 

 

**•**

Other current assets decreased $30.0 million due to lower prepaid gas purchases and purchased gas cost adjustment clause regulatory assets at the end of the winter heating season.

 

 

**•**

Current assets of discontinued operations decreased $243.2 million, primarily due to the sale of our Michigan, Missouri and Minnesota natural gas distribution businesses.

 

 

**•**

Non-current assets of discontinued operations decreased $628.4 million primarily due to the sale of our Michigan, Missouri and Minnesota natural gas distribution businesses and our Goose Creek and Raccoon Creek Energy facilities.

 

Total liabilities decreased by $1,152.4 million and common shareholders’ equity decreased by $37.8 million since December 31, 2005. These changes are primarily attributable to the following:

 

 

**•**

Accounts payable decreased by $241.2 million, primarily reflecting the seasonal decrease in gas purchases by our regulated utilities, the effects of lower natural gas prices, and lower volumes of gas and electricity delivered due to our exit from wholesale energy trading.

 

 

**•**

Price risk management liabilities decreased $164.0 million, primarily due to a decrease in natural gas prices since December 31, 2005 and the expiration of gas forward contracts and options at the end of the winter heating season.

 

 

**•**

Accrued interest decreased $25.9 million primarily due to the early retirement of debt discussed in Note 7 to the Consolidated Financial Statements.

 

 

**•**

Other accrued liabilities decreased $24.4 million primarily due to the deferral of mark-to-market gains on derivative contracts for natural gas to be passed on to our utility customers at December 31, 2005 which were settled by September 30, 2006.

 

 

**•**

Customer funds on deposit decreased $60.0 million, primarily due to the return of postings required from our merchant and utilities counterparties at December 31, 2005 due to the impact of lower natural gas prices on our positions with these counterparties and the expiration of gas forward contracts and options at the end of the winter heating season.

 

 

**•**

Long-term debt including current maturities of long-term debt, decreased $572.1 million primarily due to the early retirement of debt discussed in Note 7 to the Consolidated Financial Statements.

 

51

 

 

**•**

Deferred income taxes and credits increased $32.4 million primarily due to the reserve for contingent taxes provided in connection with our exit from the Elwood tolling contract and the reversal of temporary differences associated with the sale of assets, offset in part by net operating loss tax benefits generated in the period.

 

 

**•**

Current and non-current liabilities of discontinued operations decreased $70.4 million, primarily due to the sale of our Michigan, Missouri and Minnesota natural gas distribution businesses.

 

 

**•**

Common shareholders equity decreased $37.8 million primarily due to the net loss for the nine months ended September 30, 2006.

 

**Forward-Looking Information**

 

This report contains forward-looking information.  Forward-looking information involves risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated.  The forward-looking statements contained in this report include:

 

 

**•**

We expect to use the net proceeds from asset sales to retire debt and other liabilities and fund our anticipated capital expenditures, in a manner that maximizes the improvement of our credit profile.  Some important factors that could cause actual results to differ materially from those anticipated include: 

 

 

§

We may not be able to retire a sufficient principal amount of debt and other liabilities in a manner that maximizes our net sale proceeds or improves our credit sufficiently.  

 

 

§

We may not close the sale of our Kansas electric utility division, or we may receive less net sale proceeds than anticipated due to purchase price adjustments or changes required to satisfy the conditions of regulatory orders pertaining to the asset sale.

 

 

**•**

We plan to eliminate the majority of the allocated costs related to utility divisions that have been sold or are in the process of being sold, when the support services are no longer required.  Some important factors that could cause actual results to differ materially from those anticipated include: 

 

 

§

We may not be able to eliminate a majority, or even a material amount, of the overhead costs allocated to utility divisions that we have sold and our held-for-sale utility divisions.

 

 

§

Even if we are otherwise able to eliminate a majority of these allocated costs, we may subsequently conclude that some portion of these costs should not be eliminated in order to continue to provide safe and reliable utility service to our remaining utility divisions.

 

 

**•**

We believe our anticipated capital costs of environmental compliance and other infrastructure investments will be allowed for recovery in rates.  Some important factors that could cause actual results to differ materially from those anticipated include:

 

 

§

Regulatory commission may refuse to allow us to recover in rates part or all of our capital costs related to environmental and other infrastructure investments.

 

52

 

§

Changes in applicable law or regulation may prohibit us from recovering in rates part or all of our capital costs related to environmental and other infrastructure investments.

 

 

**•**

We expect our financial condition to be increasingly dependent upon the revenues and earnings generated by our Missouri electric operations, and for these earnings to increase in the future.  Some important factors that could cause actual results to differ materially from those anticipated include:

 

 

§

We are currently unable to pass through fuel costs and environmental capital expenditures to our Missouri electric customers.  If we are not permitted in the future to pass these costs through to our Missouri electric customers, the earnings of our Missouri electric operations (and, therefore, our overall financial condition) may not improve.

 

 

§

If the Missouri Public Service Commission does not approve our requested rate increases or rate increases requested in the future, the earnings of our Missouri electric operations (and, therefore, our overall financial condition) may not improve.

 

 

**•**

We anticipate that our current revolving credit capacity and available cash will be sufficient to fund our working capital requirements.  Some important factors that could cause actual results to differ materially from those anticipated include:

 

 

§

Our access to revolving credit capacity depends on maintaining compliance with loan covenants.  If we violate these covenants, we may lose revolving credit capacity and not have sufficient cash available for our winter needs and working capital requirements.

 

 

§

Unanticipated increases in the price of natural gas that we purchase for our utility customers could exhaust our liquidity in the winter months.

 

 

§

Counterparties may default on their obligations to supply commodities or return collateral to us or to meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.

 

 

**•**

We believe that we have strong defenses to litigation pending against us.  Some important factors that could cause actual results to differ materially from those anticipated include:

 

 

§

Judges and juries can be difficult to predict and may, in fact, rule against us. 

 

 

§

Our positions may be weakened by adverse developments in the law or the discovery of facts that hurt our cases.

 

**Item 3.  Quantitative and Qualitative Disclosures About Market Risk**

 

**Price Risk Management**

 

We engage in price risk management activities for both trading and non-trading activities. Transactions carried out in connection with trading activities that are derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) are accounted for under the mark-to-market method of accounting. Under SFAS 133, our energy commodity trading contracts, including physical transactions (mainly gas and power) and financial instruments, are recorded at fair value. As part of the valuation of our portfolio, we value the credit risks associated with the financial condition of counterparties and the time value of money. We primarily use quoted 

 

53

market prices from published sources or comparable transactions in liquid markets to value our contracts. If actively quoted market prices are not available, we contact brokers and other external sources or use comparable transactions to obtain current values of our contracts. In addition, the market prices or fair values used in determining the value of the portfolio are our best estimates utilizing information such as historical volatility, time value, counterparty credit and the potential impact on market prices of liquidating our positions in an orderly manner over a reasonable period of time under current market conditions. When market prices are not readily available or determinable, certain contracts are recorded at fair value using an alternative approach such as model pricing. 

 

The changes in fair value of our Utilities and Merchant Services derivative contracts for 2006 are summarized below:

 

*In millions***

**Utilities**

**Merchant Services**

**Total**

 

 

 

 

 

 

 

Fair value at December 31, 2005

$

42.3

$

31.6

$

73.9

Change in fair value during the period

 

(58.3)

 

(1.6)

 

(59.9)

Contracts realized or cash settled 

 

(.9)

 

2.4

 

1.5

Fair value at September 30, 2006

$

(16.9)

$

32.4

$

15.5

 

The fair value of contracts maturing in the remainder of 2006, each of the next three years and thereafter are shown below:

 

*In millions***

**Utilities**

**Merchant Services**

**Total**

 

 

 

 

 

 

 

2006

$

(8.7)

$

.7

$

(8.0)

2007

 

(8.7)

 

18.8

 

10.1

2008

 

.8

 

5.1

 

5.9

2009

 

(.3)

 

.9

 

.6

Thereafter

 

–

 

6.9

 

6.9

Total fair value

$

(16.9)

$

32.4

$

15.5

 

In addition to the natural gas derivative instruments purchased to mitigate our exposure to changes in natural gas and purchased power prices in our Missouri electric operations, the totals above include natural gas derivative instruments purchased to reduce our natural gas customers’ underlying exposure to fluctuations in gas prices where programs have been approved by state regulatory commissions.  These instruments are collectible under the provisions of the purchased gas adjustment provisions of those states.  The changes in fair value of these contracts are recorded in current assets or liabilities for under- or over-recovered purchase gas adjustments until passed through to customers in rates.

 

**Item 4. Controls and Procedures**

 

Our Chief Executive Officer (CEO) and Chief Accounting Officer (CAO) (our principal financial and accounting officer) are responsible for establishing and maintaining the company’s disclosure controls and procedures.  These controls and procedures were designed to ensure that material information relating to the company and its subsidiaries are communicated to the CEO and the CAO.  We evaluated these disclosure controls and procedures as of the end of the period covered by this report under the supervision of our CEO and CAO.  Based on this evaluation, our CEO and CAO concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic reports filed with the SEC.  There has been no change in our internal controls over financial reporting during the quarters covered by this report that has materiallyaffected, or is reasonably likely to materially affect, our internal control over financial reporting, except as discussed in the following paragraph.

 

54

 

Effective January 1, 2006, the company implemented an upgraded version of its enterprise resource planning suite of software applications, including its financial accounting and management systems.  This implementation impacted controls important to our financial reporting process and was effected to better align our account code structure for regulated reporting purposes and to reduce the number and complexity of custom modifications which existed in our previous version.  

 

55

**Part** **II – Other Information**

 

**Item 1.  Legal Proceedings**

 

Information on our legal proceedings is set forth in Note 9 to the Consolidated Financial Statements, which is incorporated herein by reference.

 

**Item 6. Exhibits**

 

**(a)  List of Exhibits**

 

Exhibits filed herewith are designated by an asterisk (*).  All exhibits not so designated are incorporated by reference to a prior filing, as indicated below.

 

**Exhibit No.**

**Description**

10.1

Severance Compensation Agreement, by and between Aquila, Inc. and Leo E. Morton, dated October 6, 2006 (Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 10, 2006).

10.2

Severance Compensation Agreement, by and between Aquila, Inc. and Jon R. Empson, dated October 6, 2006 (Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on October 10, 2006).

10.3*

Severance Compensation Agreement, by and between Aquila, Inc. and Keith G. Stamm, dated July 8, 2005 (replaces and supersedes Exhibit 10(a)(20) to the Company’s 2005 Annual Report on Form 10-K filed on March 7, 2006).

10.4*

Severance Compensation Agreement, by and between Aquila, Inc. and Beth A. Armstrong, dated August 22, 2006 (replaces and supersedes Exhibit 99.2 to the Company’s Current Report on Form 8-K filed on June 29, 2006).

10.5

Asset Purchase Agreement Amendment No. 1, by and between Aquila, Inc. and Mid-Kansas Electric Company, dated August 11, 2006 (Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 17, 2006).

10.6

Jeffrey Energy Center Transfer Agreement, by and between Aquila, Inc., Westar Energy, Inc., and Kansas Gas and Electric Company, dated August 11, 2006 (Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 17, 2006).

10.7

Asset Purchase Agreement, by and between Aquila, Inc. and MEP Pleasant Hill, LLC, dated September 22, 2006 (Exhibit 10.1 on the Company’s Current Report on Form 8-K filed on September 25, 2006).

10.8

Asset Purchase Agreement Amendment No. 2, by and between Aquila, Inc. and Mid-Kansas Electric Company, dated October 20, 2006 (Exhibit 10.1 on the Company’s Current Report on Form 8-K filed on October 25, 2006).

31.1*

Certification of Chief Executive Officer under Section 302.

31.2*

Certification of Chief Accounting Officer under Section 302.

32.1*

Certification of Chief Executive Officer under Section 906.

32.2*

Certification of Chief Accounting Officer under Section 906.

 

 

56

**Signatures**

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Aquila, Inc.

 

By:

/s/  Beth A. Armstrong

Beth A. Armstrong

*Chief Accounting Officer*

 

 

Signing on behalf of the registrant and as principal financial and accounting officer

 

 

 

 

Date:

November 2, 2006

 

 

 

 

 

 

 

57

 

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