**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 March 31, 2007**                           |
|                                                                        |
| **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 a large accelerated filer, an accelerated filer or a non-accelereated filer (see definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act). 

|   | Large Accelerated filer x | Accelerated filer o | Non-accelerated filer 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 May 4, 2007** |
|----------------------------|--------------------------------|
| Common Stock, $1 par value | 374,683,578                    |

 

 

**PART** **I—FINANCIAL INFORMATION**

 

*ITEM* *1. FINANCIAL STATEMENTS*

 

Information regarding the consolidated financial statements is on pages 5 through 28.

 

*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 28 through 43.

 

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

 

We are subject to market risk as described on pages 66 through 69 of our 2006 Annual Report on Form 10-K.  See discussion on page 44 of this document for changes in market risk since December 31, 2006.

 

*ITEM* *4. CONTROLS AND PROCEDURES*

 

Information regarding disclosure controls and procedures is on page 45.

 

**PART** **II—OTHER INFORMATION**

 

*ITEM* *1. LEGAL PROCEEDINGS*

 

Information regarding legal proceedings is on page 45.

 

*ITEM 1A. RISK FACTORS*

 

Information regarding updated risk factors is on page 45.  See pages 21 through 25 of our 2006 Annual Report on Form 10-K for a complete 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 46.

 

2

**Glossary of Terms and Abbreviations**

 

AFUDC – Allowance for Funds Used During Construction.

Aquila Merchant – Aquila Merchant Services, Inc., our wholly-owned merchant energy subsidiary.

Black Hills – Black Hills Corporation, a South Dakota corporation.

Crossroads plant – the Crossroads Energy Center, a non-regulated, 340 MW electric generation “peaking” facility located in Clarksdale, Mississippi which is contractually controlled by Aquila.

EBITDA – Earnings before interest, taxes, depreciation and amortization.

EITF – Emerging Issues Task Force, an organization that is designed to assist the FASB in improving financial reporting through the identification, discussion and resolution of financial issues within the framework of existing authoritative literature.

ERISA – Employee Retirement Income Security Act of 1974, as amended.

Exchange Act – Securities Exchange Act of 1934, as amended.

FASB – Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States of America.

FERC – Federal Energy Regulatory Commission, a governmental agency of the United States of America that, among other things, regulates interstate transmission and wholesale sales of electricity and gas and related matters.

FIN – FASB Interpretation intended to clarify accounting pronouncements previously issued by the FASB.

Fitch – Fitch Ratings, a leading global rating agency.

GAAP – Generally Accepted Accounting Principles in the United States of America.

Great Plains Energy – Great Plains Energy Incorporated, a Missouri corporation.

GWh – Gigawatt-hour.

IUB – Iowa Utilities Board, a governmental agency of the State of Iowa that, among other things, regulates the tariffs and service quality standards of our regulated utility operations in Iowa.

Kansas Commission – Kansas Corporation Commission, a governmental agency of the State of Kansas that, among other things, regulates the tariffs and service quality standards of our regulated utility operations in Kansas.

KCPL – Kansas City Power & Light Company, an electric utility company with operations in Missouri and Kansas that is wholly owned by Great Plains Energy.

LIBOR – London Inter-Bank Offering Rate.

Merger – the pending merger of Gregory Acquisition Corp., a wholly-owned subsidiary of Great Plains Energy, with and into Aquila.

Missouri Commission – Missouri Public Service Commission, a governmental agency of the State of Missouri that, among other things, regulates the tariffs and service quality standards of our regulated electric utility operations in Missouri.

Moody’s – Moody’s Investors Service, Inc., a leading global rating agency.

MW – Megawatt, which is one thousand kilowatts.

Nebraska Commission – Nebraska Public Service Commission, a governmental agency of the State of Nebraska that, among other things, regulates the tariffs and service quality standards of our regulated utility operations in Nebraska.

NYMEX – New York Mercantile Exchange.

OCI – Other Comprehensive Income (Loss) as defined by GAAP.

 

4

S&P – Standard and Poor’s, a division of The McGraw-Hill Companies, Inc., a leading global rating agency.

SEC – Securities and Exchange Commission, a governmental agency of the United States of America.

SFAS – Statement of Financial Accounting Standards, the accounting and financial reporting rules issued by FASB.

Westar – Westar Energy, Inc., a Kansas utility company.

 

5

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

**Item 1.  Financial Statements**

 

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

**Consolidated Statements of Income—Unaudited**

 

|                                                            | **Three Months Ended** |
|-----------------------------------------------------------------|------------------------|
|                                                            | **March 31,**          |
| *In millions, except per share amounts*                         | **2007**               | **2006** |
| **Sales:**                                                      |                   |   |   |   |
| Electricity—regulated                                      | $                      | 171.6 | $ | 169.3 |
| Natural gas—regulated                                      |                   | 270.7 |   | 253.2 |
| Other—non-regulated                                        |                   | 1.9 |   | 8.5 |
| **Total sales**                                                 |                   | 444.2 |   | 431.0 |
| **Cost of sales:**                                              |                   |   |   |   |
| Electricity—regulated                                      |                   | 115.5 |   | 97.4 |
| Natural gas—regulated                                      |                   | 209.7 |   | 199.5 |
| Other—non-regulated                                        |                   | 2.4 |   | 17.3 |
| **Total cost of sales**                                         |                   | 327.6 |   | 314.2 |
| **Gross profit**                                                |                   | 116.6 |   | 116.8 |
| **Operating expenses:**                                         |                   |   |   |   |
| Operation and maintenance expense                               |                   | 91.0 |   | 71.2 |
| Taxes other than income taxes                                   |                   | 8.9 |   | 8.9 |
| Restructuring charges                                           |                   | 1.6 |   | 2.0 |
| Net loss on sale of assets and other charges                    |                   | – |   | .7 |
| Depreciation and amortization expense                           |                   | 27.2 |   | 27.1 |
| **Total operating expenses**                                    |                   | 128.7 |   | 109.9 |
| **Operating income (loss)**                                     |                   | (12.1) |   | 6.9 |
| Other income (expense), net                                     |                   | 5.8 |   | 1.7 |
| Interest expense                                                |                   | 34.7 |   | 37.0 |
| **Loss from continuing operations before income taxes**         |                   | (41.0) |   | (28.4) |
| **Income tax benefit**                                          |                   | (13.8) |   | (10.8) |
| **Loss from continuing operations**                             |                   | (27.2) |   | (17.6) |
| **Earnings from discontinued operations, net of tax**           |                   | 2.9 |   | 16.5 |
| **Net loss**                                                    | $                      | (24.3) | $ | (1.1) |
|  

**Basic and diluted earnings (loss) per common share:** |                   |   |   |   |
| Continuing operations                                           | $                      | (.07) | $ | (.05) |
| Discontinued operations                                         |                   | .01 |   | .05 |
| Net loss                                                        | $                      | (.06) | $ | – |
|  

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

See accompanying notes to consolidated financial statements.

 

6

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

**Consolidated Balance Sheets**

|                                                | **March 31,** | **December 31,** |
|-----------------------------------------------------|---------------|------------------|
| *In millions*                                       | **2007**      | **2006**         |
|                                                |          | (Unaudited)      |   |   |
| **Assets**                                          |          |             |   |   |
| **Current assets:**                                 |          |             |   |   |
| Cash and cash equivalents                           | $             | 202.9            | $ | 232.8 |
| Funds on deposit                                    |          | 68.7             |   | 107.9 |
| Accounts receivable, net                            |          | 245.7            |   | 257.0 |
| Inventories and supplies                            |          | 96.4             |   | 116.0 |
| Price risk management assets                        |          | 95.1             |   | 71.3 |
| Regulatory assets, current                          |          | .9               |   | 29.0 |
| Other current assets                                |          | 24.7             |   | 33.5 |
| Current assets of discontinued operations           |          | 26.4             |   | 26.5 |
| **Total current assets**                            |          | 760.8            |   | 874.0 |
| Utility plant, net                                  |          | 1,841.9          |   | 1,825.1 |
| Non-utility plant, net                              |          | 129.1            |   | 130.2 |
| Price risk management assets                        |          | 35.7             |   | 43.4 |
| Goodwill, net                                       |          | 111.0            |   | 111.0 |
| Regulatory assets                                   |          | 131.7            |   | 149.0 |
| Deferred charges and other assets                   |          | 54.6             |   | 53.6 |
| Non-current assets of discontinued operations       |          | 298.4            |   | 286.1 |
| **Total Assets**                                    | $             | 3,363.2          | $ | 3,472.4 |
|                                                |          |             |   |   |
| **Liabilities and Shareholders’ Equity**       |          |             |   |   |
| **Current liabilities:**                            |          |             |   |   |
| Current maturities of long-term debt                | $             | 5.1              | $ | 19.7 |
| Accounts payable                                    |          | 141.3            |   | 205.4 |
| Accrued interest                                    |          | 33.4             |   | 49.7 |
| Regulatory liabilities, current                     |          | 19.6             |   | 10.8 |
| Accrued compensation and benefits                   |          | 18.8             |   | 26.8 |
| Pension and post-retirement benefits, current       |          | 3.5              |   | 3.5 |
| Other accrued liabilities                           |          | 103.9            |   | 94.3 |
| Price risk management liabilities                   |          | 71.5             |   | 74.5 |
| Customer funds on deposit                           |          | 16.6             |   | 15.6 |
| Current liabilities of discontinued operations      |          | 4.1              |   | 1.4 |
| **Total current liabilities**                       |          | 417.8            |   | 501.7 |
| **Long-term liabilities:**                          |          |             |   |   |
| Long-term debt, net                                 |          | 1,384.5          |   | 1,385.9 |
| Deferred income taxes and credits                   |          | –           |   | 19.3 |
| Price risk management liabilities                   |          | 21.0             |   | 27.1 |
| Pension and post-retirement benefits                |          | 73.7             |   | 72.5 |
| Regulatory liabilities                              |          | 73.5             |   | 72.4 |
| Deferred credits                                    |          | 51.6             |   | 51.5 |
| Non-current liabilities of discontinued operations  |          | 37.9             |   | 35.9 |
| **Total long-term liabilities**                     |          | 1,642.2          |   | 1,664.6 |
|                                                |          |             |   |   |
| **Common shareholders’ equity**                |          | 1,303.2          |   | 1,306.1 |
|                                                |          |             |   |   |
| **Total Liabilities and Shareholders’ Equity** | $             | 3,363.2          | $ | 3,472.4 |

 

See accompanying notes to consolidated financial statements.

 

7

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

**Consolidated Statements of Comprehensive Income—Unaudited**

 

| * *                                                                                                                                                      |   | **Three Months Ended** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|------------------------|
| * *                                                                                                                                                      |   | **March 31,**          |
| *In millions***                                                                                                                                               |   |                   | **2007** | **2006** |
| **Net loss**                                                                                                                                                  |   |                   |   |   | $ | (24.3) | $ | (1.1) |
| **Other comprehensive income (loss), net of related tax:**                                                                                                    |   |                   |   |   |   |   |   |   |
| Foreign currency adjustments:                                                                                                                                 |   |                   |   |   |   |   |   |   |
| Foreign currency translation adjustments, net of deferred tax expense (benefit) of $(.2) million for the three months ended March 31, 2006                    |   |                   |   |   |   | – |   | (.3) |
| Reclassification of foreign currency (gains) losses to income, net of deferred tax (expense) benefit of $.1 million for the three months ended March 31, 2006 |   |                   |   |   |   | – |   | .2 |
| Total foreign currency adjustments                                                                                                                            |   |                   |   |   |   | – |   | (.1) |
| Pension and post-retirement benefits costs amortized to income:                                                                                               |   |                   |   |   |   |   |   |   |
| Prior service cost, net of deferred tax expense (benefit) of $.2 million for the three months ended March 31, 2007                                            |   |                   |   |   |   | .3 |   | – |
| Net actuarial loss, net of deferred tax expense (benefit) of $.2 million for the three months ended March 31, 2007                                            |   |                   |   |   |   | .2 |   | – |
| Accumulated regulatory loss adjustment, net of deferred tax expense (benefit) of $.5 million for the three months ended March 31, 2007                        |   |                   |   |   |   | .9 |   | – |
| Total pension and post-retirement benefit costs                                                                                                               |   |                   |   |   |   | 1.4 |   | – |
| Other comprehensive income (loss)                                                                                                                             |   |                   |   |   |   | 1.4 |   | (.1) |
| **Total Comprehensive Loss**                                                                                                                                  |   |                   |   |   | $ | (22.9) | $ | (1.2) |

 

See accompanying notes to consolidated financial statements.

 

8

**Aquila, Inc.**

**Consolidated Statements of Common Shareholders' Equity**

 

| *In millions*                                                                                                                                                                                                                                                                                                                        | **March 31,****2007** | **December 31,****2006** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------------|--------------------------|
|                                                                                                                                                                                                                                                                                                                                 | (Unaudited)           |                     |   |
| Common stock: authorized 400 million shares at March 31, 2007 and December 31, 2006, par value $1 per share; 374,790,313 shares issued at March 31, 2007 and 374,611,194 shares issued at December 31, 2006; authorized 20 million shares of Class A common stock, par value $1 per share, none issued | $                     | 374.8                    | $ | 374.6 |
| Premium on capital stock                                                                                                                                                                                                                                                                                                             |                  | 3,509.8                  |   | 3,509.2 |
| Retained deficit:                                                                                                                                                                                                                                                                                                                    |                  |                     |   |   |
| Beginning balance                                                                                                                                                                                                                                                                                                                    |                  | (2,546.7)                |   | (2,570.6) |
| Net income (loss)                                                                                                                                                                                                                                                                                                                    |                  | (24.3)                   |   | 23.9 |
| Cumulative effect of change in accounting                                                                                                                                                                                                                                                                                            |                  | 19.3                     |   | – |
| Ending balance                                                                                                                                                                                                                                                                                                                       |                  | (2,551.7)                |   | (2,546.7) |
| Treasury stock, at cost 117,296 shares at March 31, 2007 (90,063 shares at December 31, 2006)                                                                                                                                                                                                                                        |                  | (.5)                     |   | (.4) |
| Accumulated other comprehensive loss                                                                                                                                                                                                                                                                                                 |                  | (29.2)                   |   | (30.6) |
| **Total Common Shareholders’ Equity**                                                                                                                                                                                                                                                                                           | $                     | 1,303.2                  | $ | 1,306.1 |

 

See accompanying notes to consolidated financial statements.

 

9

**Aquila, Inc.**

**Consolidated Statements of Cash Flows—Unaudited**

 

|                                                                                                                                                | **Three Months Ended** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------|------------------------|
|                                                                                                                                                | **March 31,**          |
| *In millions*                                                                                                                                       | **2007**               | **2006** |
|                                                                                                                                                |                   |   |   |   |
| **Cash Flows From Operating Activities:**                                                                                                           |                   |   |   |   |
| Net loss                                                                                                                                            | $                      | (24.3) | $ | (1.1) |
| Adjustments to reconcile net loss to net cash provided from operating activities:                                                                   |                   |   |   |   |
| Depreciation and amortization expense                                                                                                               |                   | 27.2 |   | 27.7 |
| Restructuring charges                                                                                                                               |                   | 1.6 |   | 2.7 |
| Cash paid for restructuring and other charges                                                                                                       |                   | (.9) |   | – |
| Net (gain) loss on sale of assets and other charges                                                                                                 |                   | (.1) |   | (.8) |
| Net changes in price risk management assets and liabilities                                                                                         |                   | (25.2) |   | 42.6 |
| Deferred income taxes and investment tax credits                                                                                                    |                   | – |   | .6 |
| Changes in certain assets and liabilities, net of effects of divestitures:                                                                          |                   |   |   |   |
| Funds on deposit                                                                                                                                    |                   | 39.3 |   | 130.0 |
| Accounts receivable/payable, net                                                                                                                    |                   | (53.1) |   | (29.3) |
| Inventories and supplies                                                                                                                            |                   | 18.9 |   | 53.9 |
| Other current assets                                                                                                                                |                   | 32.6 |   | 15.2 |
| Deferred charges and other assets                                                                                                                   |                   | 16.1 |   | .2 |
| Accrued interest and other accrued liabilities                                                                                                      |                   | (26.0) |   | (70.1) |
| Customer funds on deposit                                                                                                                           |                   | 1.0 |   | (43.7) |
| Deferred credits                                                                                                                                    |                   | 5.8 |   | (6.1) |
| Other                                                                                                                                               |                   | 1.5 |   | (.4) |
| **Cash provided from operating activities**                                                                                                         |                   | 14.4 |   | 121.4 |
| **Cash Flows From Investing Activities:**                                                                                                           |                   |   |   |   |
| Utilities capital expenditures                                                                                                                      |                   | (52.1) |   | (30.9) |
| Cash proceeds received on sale of assets                                                                                                            |                   | 22.3 |   | 182.8 |
| Other                                                                                                                                               |                   | 5.1 |   | (4.5) |
| **Cash provided from (used for) investing activities**                                                                                              |                   | (24.7) |   | 147.4 |
| **Cash Flows From Financing Activities:**                                                                                                           |                   |   |   |   |
| Retirement of long-term debt                                                                                                                        |                   | (15.9) |   | (1.7) |
| Short-term borrowings (repayments), net                                                                                                             |                   | – |   | (12.0) |
| Cash paid on long-term gas contracts                                                                                                                |                   | (4.3) |   | (4.3) |
| Other                                                                                                                                               |                   | .6 |   | .6 |
| **Cash used for financing activities**                                                                                                              |                   | (19.6) |   | (17.4) |
| **Increase (decrease) in cash and cash equivalents**                                                                                                |                   | (29.9) |   | 251.4 |
| **Cash and cash equivalents at beginning of period**  (includes $4.8 million of cash included in current assets of discontinued operations in 2006) |                   | 232.8 |   | 19.0 |
| **Cash and cash equivalents at end of period**(includes $6.8 million of cash included in current assets of discontinued operations in 2006)         | $                      | 202.9 | $ | 270.4 |

 

See accompanying notes to consolidated financial statements.

 

10

**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 2006 Annual Report on Form 10-K filed with the SEC on March 1, 2007.  You should read our 2006 Form 10-K in conjunction with this report.  The accompanying Consolidated Balance Sheets and Consolidated Statements of Common Shareholders’ Equity as of December 31, 2006, 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 the results of our operations. Certainestimates 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 period amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2007 presentation.  

 

Our consolidated financial statements include all of our operating divisions and majority-owned subsidiaries for which we maintain controlling interests, including Aquila Merchant.

 

**Pending Merger**

 

We have entered into a merger agreement with Great Plains Energy.  We discuss our pending merger in more detail in Note 11.

 

***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 FASB issued SFAS 157, “Fair Value Measurements”, 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. 

 

11

**Accounting for Planned Major Maintenance**

 

In September 2006, the FASB issued FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities”.  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 followed as allowed by regulatory authorities.  FSP AUG AIR-1 was effective for our financial statements as of January 1, 2007, and was applied retrospectively. Before considering the effect of our regulatory “accrue-in-advance” method, we adopted the direct expense method under FSP AUG AIR-1. We believe, however, it is probable that the cost of planned major maintenance will continue to be recovered through customer rates charged by our rate-regulated utility operations in advance of such maintenance being performed consistent with our historical rate recovery ofthese costs.  Therefore, a regulatory liability was recorded.  Upon adoption as of January 1, 2007, our accrued liability for planned major maintenance in our continuing operations of $4.7 million was reclassified as a regulatory liability.  

 

**2.  Restructuring Charges**

 

We recorded the following restructuring charges:

 

|                                |   | **Three Months Ended** |
|-------------------------------------|--------|------------------------|
|                                |   | **March 31,**          |
| *In millions*                       |   |                   | **2007** | **2006** |
| Corporate and Other severance costs |   |                   |   |   | $ | 1.6 | $ | 2.0 |
| Total restructuring charges         |   |                   |   |   | $ | 1.6 | $ | 2.0 |

 

**Severance Costs and Retention Payments**

 

During the first quarter of 2006 our management adopted and communicated to employees a plan to reduce corporate and central services costs, which included the elimination of approximately 220 positions through attrition and employee terminations.  The 83 employees who were involuntarily terminated received severance and other one-time termination benefits.  The total cost of one-time termination benefits for these terminated employees was approximately $5.7 million, which was recognized in 2006 over the remaining service period of terminated employees and will be paid out over time.  We recognized $2.0 million of the $5.7 million for termination benefits in the first quarter of 2006.

 

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.  We recognized $.7 million of the $2.0 million for termination benefits in the first quarter of 2006.

 

Finally, we recorded $1.6 million of one-time termination benefits in first quarter of 2007 related to the departure of our Chief Operating Officer.  These benefits will be paid over a two-year period beginning April 28, 2007.

 

12

**Restructuring Reserve Activity**

 

The following table summarizes activity in accrued restructuring charges for our continuing and discontinued operations for the three months ended March 31, 2007:

 

| *In millions*                                              |   |   |
|------------------------------------------------------------|--------|--------|
| Severance and Retention Costs:                             |   |   |
| Accrued severance costs as of December 31, 2006            | $      | 2.3    |
| Additional expense during the period                       |   | 1.6    |
| Cash payments during the period                            |   | (.9)   |
| Accrued severance and retention costs as of March 31, 2007 | $      | 3.0    |

 

**3.  Discontinued Operations**

 

As part of a strategic repositioning of our company, we have sold or wound-down a number of operations since 2002 to generate cash to be used to reduce debt and eliminate other long-term obligations.  We have sold the assets discussed below, which are considered discontinued operations in accordance with SFAS 144.  

 

After-tax losses 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. 

 

**Electric and Gas Utilities**

 

In September 2005, we entered into agreements to sell our Kansas electric distribution business and our Michigan, Minnesota and Missouri natural gas distribution businesses.  We completed these asset sales in 2006, except for the Kansas electric sale, which was completed on April 1, 2007.  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 depends upon the final allocation of the purchase price based upon the terms of the respective asset purchase agreements.  Ordinary income has been offset by current year net operating losses and/ornet operating loss carryforwards.  Capital gains have been offset by capital loss carryforwards.  To the extent capital loss carryforwards were utilized, the valuation allowance against the tax benefit of the capital loss carryforwards will be reversed.  The tax gains will be adjusted when final determinations are made and as income tax returns are filed in the third quarter 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 of 2006, we received $25.0 million as part of the working capital and other adjustments “true up.”  We settled with the buyer regarding the gas in storage issue and other matters and paid the buyer $1.8 million in March 2007.  The only remaining contingency relates to the final determination of the Michigan Commission in gas cost recovery proceedings.  In connection with this sale we have recorded a pretax gain of approximately $92.2 million after transaction fees and expenses.  The estimated after-tax gain was approximately $99.5 million, including an estimate of $44.0 million for the valuation allowance reversalrelated to the estimated 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 were “trued up” in the fourth quarter of 2006 through a final payment of $.2 million to the buyer.  In connection with this sale we recorded a pretax gain of approximately $30.7 million after transaction fees and expenses.  The estimated after-tax gain was approximately $31.1 million, including an 

 

13

estimate of $11.7 million for the valuation allowance reversal related to the estimated 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.  We paid $16.9 million as part of the working capital and other adjustments “true up.”  In connection with this sale we recorded a pretax gain of approximately $120.5 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 $127.5 million, including an estimate of $56.9 million for the valuation allowance reversal related to the estimated capital gain amount discussed above.   

 

On April 1, 2007, we closed the sale of our Kansas electric operations and transfer of our 8% leased interest in the Jeffrey Energy Center and received gross cash proceeds of $291.8 million, including the base purchase price of $249.7 million plus preliminary working capital and other adjustments of $42.1 million.  The working capital and other adjustments will be “trued up” in the third quarter of 2007 through a final payment to or from the buyers.  In connection with this sale we preliminarily expect to record a pretax gain of approximately $2.0 million in the second quarter of 2007 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 $1.2 million, subject to the determination of the capital gain amount discussed above.

 

The operating results of the utility divisions sold include the direct operating costs associated with those businesses but do not include the allocated operating costs of central services and corporate overhead in accordance with EITF Consensus 87-24, “Allocation of Interest to Discontinued Operations” (EITF 87-24).  We provide corporate 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 not included in the reclassification to earnings fromdiscontinued 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 have eliminated the majority of these costs following the closing of the Michigan, Minnesota and Missouri gas operations.  

 

The discontinued utility operations participated in our qualified pension plan, non-qualified Supplemental Executive Retirement Plan (SERP) and other post-retirement benefit plan.  Under the asset purchase agreements, the buyers assumed upon closing the accrued pension obligations owed to the current and former employees of the operations they acquired.  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 ERISA requirements.  We expect these benefit plan asset transfers to result in plan curtailments.  In connection with the sale of our Michigan, Minnesota and Missouri gas operations we included $13.0 million of net prepaid pension assets and pension and post-retirement benefit obligations, including the effect of plan curtailment and settlement losses,in the determination of the pretax gains on these sales.  The plan curtailment and settlement losses related to the sale of our Kansas electric operations are estimated to be approximately $5.6 million.  The effect of the plan curtailments will depend on the final determination of the asset transfers, which will not be completed until late 2007. 

 

**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.  In 

 

14

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.

 

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 aggregate book tax benefit on the asset sales of approximately $59.8 million (tax calculation on the pre-tax loss of approximately $159.5 million), although there was no immediate cash tax receivable on the asset sales due to our net operating loss carryovers.  On March 31, 2006, we closed the sales of these facilities and received gross proceeds of $175 million.

 

**Everest Connections**

 

In the fourth quarter of 2005, we began a sales 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 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.  Net proceeds were approximately $78 million after payment of transaction costs, but before resolving the pending lawsuit filed by EGTG’s minority partners regarding certain put rights they heldprior to the sale.  In connection with this sale we recorded a 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 Kansas, Michigan, Minnesota and Missouri utility divisions, Illinois peaking facilities and Everest Connections did not assume any of our long-term debt.  The direct debt and related interest of Everest Connections was included in discontinued 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 completed each asset sale the allocation of interest to discontinued operations ceased, thereby increasing interest expense in continuing operations, without impacting totalinterest 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 months ended March 31, 2007 and 2006 in the Consolidated Statements of Income. 

 

15

Operating results from our discontinued operations are as follows:

 

| * *                                                                        |   | **Three Months Ended** |
|---------------------------------------------------------------------------------|--------|------------------------|
| * *                                                                        |   | **March 31,**          |
| *In millions*                                                                   |   |                   | **2007** | **2006** |
| * *                                                                        |   |                   |   |   |   |   |   |   |
| Sales                                                                           |   |                   |   |   | $ | 43.5 | $ | 310.0 |
| Cost of sales                                                                   |   |                   |   |   |   | 23.1 |   | 233.5 |
| Gross profit                                                                    |   |                   |   |   |   | 20.4 |   | 76.5 |
| Operating expenses:                                                             |   |                   |   |   |   |   |   |   |
| Operation and maintenance expense                                               |   |                   |   |   |   | 10.0 |   | 28.7 |
| Taxes other than income taxes                                                   |   |                   |   |   |   | 1.8 |   | 4.1 |
| Restructuring charges                                                           |   |                   |   |   |   | – |   | .7 |
| Net (gain) on sale of assets and other      charges    |   |                   |   |   |   | (.1) |   | (1.5) |
| Depreciation and amortization expense                                           |   |                   |   |   |   | – |   | .6 |
| Total operating expenses                                                        |   |                   |   |   |   | 11.7 |   | 32.6 |
| Operating income                                                                |   |                   |   |   |   | 8.7 |   | 43.9 |
| Other income (expense)                                                          |   |                   |   |   |   | .1 |   | (.3) |
| Interest expense                                                                |   |                   |   |   |   | 4.1 |   | 16.9 |
| Income before income taxes                                                      |   |                   |   |   |   | 4.7 |   | 26.7 |
| Income tax expense                                                              |   |                   |   |   |   | 1.8 |   | 10.2 |
| Earnings from discontinued operations, net      of tax |   |                   |   |   | $ | 2.9 | $ | 16.5 |

 

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 March 31, 2007 and December 31, 2006 Consolidated Balance Sheets as follows:

 

|                                                     | **March 31,** | **December 31,** |
|----------------------------------------------------------|---------------|------------------|
| *In millions***                                          | **2007**      | **2006**         |
| Current assets of discontinued operations:               |          |             |   |   |
| Accounts receivable, net                                 | $             | 16.2             | $ | 13.0 |
| Inventories and supplies                                 |          | 6.3              |   | 5.7 |
| Other current assets                                     |          | 3.9              |   | 7.8 |
| Total current assets of discontinued operations          | $             | 26.4             | $ | 26.5 |
| Non-current assets of discontinued operations:           |          |             |   |   |
| Utility plant, net                                       | $             | 249.0            | $ | 236.6 |
| Regulatory assets                                        |          | 28.3             |   | 28.9 |
| Other non-current assets                                 |          | 21.1             |   | 20.6 |
| Total non-current assets of discontinued operations      | $             | 298.4            | $ | 286.1 |
| Current liabilities of discontinued operations:          |          |             |   |   |
| Other current liabilities                                | $             | 4.1              | $ | 1.4 |
| Total current liabilities of discontinued operations     | $             | 4.1              | $ | 1.4 |
| Non-current liabilities of discontinued operations:      |          |             |   |   |
| Pension and post-retirement benefits                     | $             | 17.7             | $ | 17.7 |
| Deferred credits                                         |          | 20.2             |   | 18.2 |
| Total non-current liabilities of discontinued operations | $             | 37.9             | $ | 35.9 |

 

 

16

**4.  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.  Diluted earnings (loss) per share is calculated by dividing our net loss, after assumed conversion of dilutive securities, by our weighted average shares outstanding, adjusted for the effect of dilutive securities.  However, as a result of the net losses in the three months ended March 31, 2007 and 2006, the potential issuances of common stock for dilutive securities of 460,169 and 505,421, respectively, were considered anti-dilutive in those periods and were therefore not included in thecalculation of diluted earnings (loss) per share.

 

|                                                                                         |   | **Three Months Ended** |
|----------------------------------------------------------------------------------------------|--------|------------------------|
|                                                                                         |   | **March 31,**          |
| *In millions, except per share amounts***                                                    |   |                   | **2007** | **2006** |
|                                                                                         |   |                   |   |   |   |   |   |   |
| Loss from continuing operations                                                              |   |                   |   |   | $ | (27.2) | $ | (17.6) |
| Earnings from discontinued operations                                                        |   |                   |   |   |   | 2.9 |   | 16.5 |
| Loss available for common shares                                                             |   |                   |   |   | $ | (24.3) | $ | (1.1) |
|                                                                                         |   |                   |   |   |   |   |   |   |
| Basic and diluted earnings (loss) per share:                                                 |   |                   |   |   |   |   |   |   |
| Loss from continuing operations                                                              |   |                   |   |   | $ | (.07) | $ | (.05) |
| Earnings from discontinued operations                                                        |   |                   |   |   |   | .01 |   | .05 |
| Net loss                                                                                     |   |                   |   |   | $ | (.06) | $ | – |
| Weighted average number of common shares used in basic and diluted earnings (loss) per share |   |                   |   |   |   | 375.6 |   | 374.7 |

 

**5.  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 two 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 was sold April 1, 2007, 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 discontinued operations.Merchant Services consists of the residual operations of our Aquila Merchant subsidiary.  These operations include 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.  Also, included in Merchant Services is our investment in the Crossroads plant.  The operating results of Merchant Services’ two Illinois power plants, which were sold on March 31, 2006, have been reclassified to discontinued operations.  All other operations are included in 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.

 

17

Our reportable segment reconciliation is shown below:

 

|                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |   | **Three Months Ended** |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|------------------------|
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |   | **March 31,**          |
| *In millions***                                                                                                                                                                                                                                                                                                                                                                                                                                                               |   |                   | **2007** | **2006** |
| Sales: *(a)*                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |   |                   |   |   |   |   |   |   |
| Utilities:                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |   |                   |   |   |   |   |   |   |
| Electric Utilities                                                                                                                                                                                                                                                                                                                                                                                                                                                            |   |                   |   |   | $ | 171.8 | $ | 169.5 |
| Gas Utilities                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |   |                   |   |   |   | 275.8 |   | 263.0 |
| Total Utilities                                                                                                                                                                                                                                                                                                                                                                                                                                                               |   |                   |   |   |   | 447.6 |   | 432.5 |
| Merchant Services                                                                                                                                                                                                                                                                                                                                                                                                                                                             |   |                   |   |   |   | (3.4) |   | (1.5) |
| Corporate and Other                                                                                                                                                                                                                                                                                                                                                                                                                                                           |   |                   |   |   |   | – |   | – |
| Total sales                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |   |                   |   |   | $ | 444.2 | $ | 431.0 |
| *(a)*         *For the three months ended March 31, 2007 and 2006, respectively, the following sales (in millions) have been reclassified to discontinued operations and are not included in the above amounts: Electric Utilities of $41.7 and $38.1; Gas Utilities of $1.8 and $258.9; Merchant Services sales of $– and $.6; and Corporate and Other sales related to Everest Connections of $– and $12.4.*

  |
| Earnings (Loss) Before Interest, Taxes, Depreciation and Amortization (EBITDA): *(a)*                                                                                                                                                                                                                                                                                                                                                                                         |   |                   |   |   |   |   |   |   |
| Utilities:                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |   |                   |   |   |   |   |   |   |
| Electric Utilities                                                                                                                                                                                                                                                                                                                                                                                                                                                            |   |                   |   |   | $ | 6.2 | $ | 23.6 |
| Gas Utilities                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |   |                   |   |   |   | 29.1 |   | 25.1 |
| Total Utilities                                                                                                                                                                                                                                                                                                                                                                                                                                                               |   |                   |   |   |   | 35.3 |   | 48.7 |
| Merchant Services                                                                                                                                                                                                                                                                                                                                                                                                                                                             |   |                   |   |   |   | (4.1) |   | (7.4) |
| Corporate and Other                                                                                                                                                                                                                                                                                                                                                                                                                                                           |   |                   |   |   |   | (10.3) |   | (5.6) |
| Total EBITDA                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |   |                   |   |   |   | 20.9 |   | 35.7 |
| Depreciation and amortization expense                                                                                                                                                                                                                                                                                                                                                                                                                                         |   |                   |   |   |   | 27.2 |   | 27.1 |
| Interest expense                                                                                                                                                                                                                                                                                                                                                                                                                                                              |   |                   |   |   |   | 34.7 |   | 37.0 |
| Loss from continuing operations before income    taxes                                                                                                                                                                                                                                                                                                                                                                                                    |   |                   |   |   | $ | (41.0) | $ | (28.4) |
| *(a)*         *For the three months ended March 31, 2007 and 2006, respectively, the following EBITDA (in millions) have been reclassified to discontinued operations and are not included in the above amounts: Electric Utilities of $7.0 and $7.4; Gas Utilities of $1.8 and $34.8; Merchant Services of $*–*and $(.7); and Corporate and Other related to Everest Connections of $*–*and $2.7.*

             |
| Depreciation and Amortization:                                                                                                                                                                                                                                                                                                                                                                                                                                                |   |                   |   |   |   |   |   |   |
| Utilities:                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |   |                   |   |   |   |   |   |   |
| Electric Utilities                                                                                                                                                                                                                                                                                                                                                                                                                                                            |   |                   |   |   | $ | 18.4 | $ | 17.3 |
| Gas Utilities                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |   |                   |   |   |   | 7.8 |   | 8.8 |
| Total Utilities                                                                                                                                                                                                                                                                                                                                                                                                                                                               |   |                   |   |   |   | 26.2 |   | 26.1 |
| Merchant Services                                                                                                                                                                                                                                                                                                                                                                                                                                                             |   |                   |   |   |   | 1.0 |   | 1.1 |
| Corporate and Other                                                                                                                                                                                                                                                                                                                                                                                                                                                           |   |                   |   |   |   | – |   | (.1) |
| Total depreciation and amortization                                                                                                                                                                                                                                                                                                                                                                                                                                           |   |                   |   |   | $ | 27.2 | $ | 27.1 |
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |

 

 

18

| *In millions***                                                                                                                                                                                                     | **March 31,****2007** | **December 31,****2006** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------------|--------------------------|
| Assets: *(a)*                                                                                                                                                                                                       |                  |                     |   |   |
| Utilities:                                                                                                                                                                                                          |                  |                     |   |   |
| Electric Utilities                                                                                                                                                                                                  | $                     | 2,200.7                  | $ | 2,169.5 |
| Gas Utilities                                                                                                                                                                                                       |                  | 572.8                    |   | 689.5 |
| Total Utilities                                                                                                                                                                                                     |                  | 2,773.5                  |   | 2,859.0 |
| Merchant Services                                                                                                                                                                                                   |                  | 321.1                    |   | 316.2 |
| Corporate and Other                                                                                                                                                                                                 |                  | 268.6                    |   | 297.2 |
| Total assets                                                                                                                                                                                                        | $                     | 3,363.2                  | $ | 3,472.4 |
| *(a)*  *Included in total assets as of March 31, 2007 and December 31, 2006 are total assets of discontinued operations as follows:  Electric Utilities $324.8 million and $312.6 million, respectively.* |

 

**6.  Financings**

 

**Five-Year Unsecured Revolving Credit Facility**

 

In September 2004, we completed a $110 million 364-day unsecured revolving credit facility.  This facility automatically extended to September 2009 when we received extension approval from the FERC and various state public utility commissions (the Five-Year Unsecured Revolving Credit Facility). There were no borrowings outstanding on this facility as of March 31, 2007.  The Five-Year Unsecured Revolving Credit Facility bears interest at the LIBOR plus 5.75%, subject to reduction if our credit rating improves.  Among other restrictions, the Five-Year Unsecured 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 March 31, 2007.

 

The Five-Year Unsecured Revolving Credit Facility contains a $40 million “cross default” provision, as well as 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. 

 

**$180 Million Unsecured 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 March 31, 2007, we had $150.0 million of uncollateralized capacity at an average cost of 3.65% under this agreement, which contains a $40 million “cross default” provision.  As of March 31, 2007, $129.7 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, Iowa, 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 

 

19

expense ratios as those contained in the Five-Year Unsecured Revolving Credit Facility discussed above.  The credit agreement also contains a $40 million “cross default” provision.  No borrowings were outstanding under this facility as of March 31, 2007.

 

**$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 was originally scheduled to terminate on December 20, 2006, that allows us to either issue letters of credit or make cash drawings under the facility. This facility, which initially included a 2.50% advance rate on letters of credit, is expected to be nearly fully utilized through letter of credit issuances.  The credit agreement also contains a $40 million “cross default” provision.  In November 2006, we entered into amendments to extend the maturity date to December 19, 2007 and lower the advance rate to 1.07%.  There were $42.0 million of letters of credit outstanding under this facility as of March 31, 2007.

 

**Iatan 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 the Iatan 2 facility being developed by 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 Public Service electric operations.  There were no borrowings or letters ofcredit outstanding under this facility at March 31, 2007.  Among other restrictions, the Iatan Facility contains the following financial covenants with which we were in compliance as of March 31, 2007: 

 

|   | (1) | 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. |
|--------|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | (2) | We must maintain a trailing 12-month ratio of EBITDA, as defined in the agreement, to interest expense of no less than 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. |
|--------|-----|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | (3) | We must maintain a trailing 12-month ratio of debt outstanding to EBITDA of no more than 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. |
|--------|-----|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | (4) | 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 contains a $40 million “cross default” provision, as well as 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.

 

**Other**

 

|   | We had an additional $.8 million of letters of credit outstanding under various arrangements as |
|--------|-------------------------------------------------------------------------------------------------|

 

20

of March 31, 2007.

 

**7.  Employee Benefits**

 

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

 

| * *                                                           | **Pension Benefits**             | **Other****Post-retirement****Benefits** |
|--------------------------------------------------------------------|----------------------------------|------------------------------------------|
| * *                                                           | **Three Months Ended March 31,** |
| *In millions***                                                    | **2007**                         | **2006**                                 | **2007** | **2006** |
| **Components of Net Periodic Benefit Cost:**                       |                             |                                     |   |   |   |   |   |   |
| Service cost                                                       | $                                | 2.4                                      | $ | 2.6 | $ | .3 | $ | .2 |
| Interest cost                                                      |                             | 5.4                                      |   | 5.8 |   | .8 |   | 1.2 |
| Expected return on plan assets                                     |                             | (6.4)                                    |   | (7.4) |   | (.3) |   | (.2) |
| Amortization of transition amount                                  |                             | –                                   |   | (.2) |   | .3 |   | .4 |
| Amortization of prior service cost                                 |                             | 1.2                                      |   | 1.4 |   | .5 |   | .6 |
| Recognized net actuarial (gain)/loss                               |                             | .8                                       |   | 1.1 |   | (.1) |   | – |
| Net periodic benefit cost before regulatory expense adjustments    |                             | 3.4                                      |   | 3.3 |   | 1.5 |   | 2.2 |
| Regulatory (gain)/loss adjustment                                  |                             | 1.4                                      |   | 1.3 |   | .1 |   | .2 |
| SFAS 71 regulatory adjustment                                      |                             | –                                   |   | .2 |   | – |   | – |
| **Net periodic benefit cost after regulatory expense adjustments** | $                                | 4.8                                      | $ | 4.8 | $ | 1.6 | $ | 2.4 |

 

The unrecognized net periodic benefit costs amortized to income from the regulatory asset and accumulated other comprehensive income accounts are as follows:

 

| * *                                                         | **Pension Benefits**                  | **Other****Post-retirement****Benefits** |
|------------------------------------------------------------------|---------------------------------------|------------------------------------------|
| * *                                                         | **Three Months Ended March 31, 2007** |
| *In millions***                                                  | **Regulatory Asset**                  | **Other Comprehensive Income**           | **Regulatory Asset** | **Other Comprehensive Income** |
| **Components of Net Periodic Benefit Cost Amortized to Income:** |                                  |                                     |   |   |   |   |   |   |
| Transition amount                                                | $                                     | –                                   | $ | – | $ | .3 | $ | – |
| Prior service cost                                               |                                  | .7                                       |   | .5 |   | .5 |   | – |
| Recognized net actuarial (gain)/loss                             |                                  | .5                                       |   | .3 |   | (.1) |   | – |
| Regulatory (gain)/loss adjustment                                |                                  | –                                   |   | 1.4 |   | .1 |   | – |
| **Total pension and post-retirement benefit****costs amortized** | $                                     | 1.2                                      | $ | 2.2 | $ | .8 | $ | – |

 

We previously disclosed in our financial statements for the year ended December 31, 2006, that we expected to contribute $.7 million and $2.9 million to our defined benefit pension plans and other post-retirement benefit plan, respectively, in 2007.  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 3, 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.  To comply with aregulatory condition related to the closing of the sale of our Kansas electric operations, we contributed $3.4 million of the estimated $10 million voluntary contribution to our qualified defined benefit pension plan and $1.1 million to our other post-retirement benefit plan in April 2007.

 

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As disclosed in Note 3, our former Kansas electric operations 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 months ended March 31, 2007 and March 31, 2006, the net periodic pension benefit cost charged to discontinued operations was $.5 million and $1.1 million, respectively.  In addition, for the three months ended March 31, 2007 and March 31, 2006, the net periodic other post-retirement benefits cost charged to discontinued operations was $.3 million and $.7 million, respectively.

 

**8.  Legal******

 

**Price Reporting Litigation**

 

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 appealed to the Ninth Circuit Court of Appeals and in March 2007, the City of Tacoma dismissed its appeal with prejudice, ending the case.

 

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, including a class action which did not name Aquila.  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*.  In February 2007, our motion to dismiss Aquila was granted by the California Court of Appeals, leaving only Aquila Merchant as a defendant.  In March 2007, Aquila Merchant settled the class action case for $6.6 million.  We believe we have strong defenses and will defend the remaining individual 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.  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*.  In March 2007, we settled these cases for a payment of $1.0 million.

 

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 approximately $7.6 million in refunds.  However, various parties 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 sufficientjustification 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 tariff violations occurred during this period could result in Aquila 

 

22

Merchant being required to make substantial refunds and have a material adverse effect on its financial condition, results of operations and cash flows.

 

On October 6, 2006, the Missouri 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.  The court ordered that all of these lawsuits be consolidated into a single case captioned *In re AquilaERISA Litigation*and certified the case as a class action*.*In April 2007, we settled the case for $10.5 million, which will be paid by our insurance carrier.

 

**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 county zoning approval was required to construct the project.  In January 2005, a Circuit Court of Cass County judge granted the County's request for an injunction; however, we were permitted to continue construction while the order was appealed.  We appealed the Circuit Court decision to the Missouri Court of Appeals for the Western District of Missouri and, in June 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.  

In December 2005, the appellate court issued a new opinion affirming the Circuit Court’s opinion, but also opining that it was not too late to obtain the necessary approval.  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, 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.  The Missouri Commission and Aquila have appealed the court’s decision, and the Missouri Court of Appeals for the Western District of Missouri is scheduled to hear oral arguments in May 2007.  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 up to $20 million based on an engineering study.  Significant additional costs would be incurred to 

 

23

store the equipment, secure replacement power and/or build 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 to the extent the 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 majeure 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 the supplier in federal court in Salt Lake City and the trial was held in February 2007.  We are awaiting the court’s ruling.

 

**Merger-Related Shareholder Lawsuits**

 

Two lawsuits were filed against us and our board of directors in the Circuit Court of Jackson County, Missouri, and one lawsuit was filed against us and our directors in the Delaware Chancery Court.  The complaints were filed as purported class actions on behalf of a proposed class of holders of Aquila common stock.  These complaints seek as relief, among other things, an injunction against the consummation of the proposed merger between us and a subsidiary of Great Plains Energy.  We believe we have strong defenses and will defend these cases vigorously.  However, given the nature of the claims and remedies sought, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

 

**9.  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.

 

**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.  Cash received on stock options exercised was $.5 million, the intrinsic value of options exercised was $.7 million and the tax benefit realized was $.1 million for the three months ended March 31, 2007.  Stock options as of March 31, 2007 and changes during the three months ended March 31, 2007 were as follows: 

 

|                              | **Shares** | **Weighted Average Exercise Prices** | **Remaining Contractual****Term in Years** |
|-----------------------------------|------------|--------------------------------------|--------------------------------------------|
| Beginning balance                 | 4,865,866  | $                                    | 15.57                                      | 3.20 |
| Granted                           | -          |                                 | -                                          |   |
| Exercised                         | (158,965)  |                                 | 2.90                                       |   |
| Forfeited                         | (535,754)  |                                 | 19.18                                      |   |
| **Ending balance**                | 4,171,147  | $                                    | 15.62                                      | 3.26 |
| **Exercisable at March 31, 2007** | 4,171,147  | $                                    | 15.62                                      | 3.26 |

 

The aggregate intrinsic value of “in-the-money” outstanding and exercisable options was $2.1 million as of March 31, 2007.

 

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**Time-Based Restricted Stock Awards**

 

In 2005, 183,823 shares of restricted stock were awarded to certain managers and executives, excluding senior management.  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 $.1 million for the three months ended March 31, 2007.  As of March 31, 2007, the total compensation cost not yet realized was $.2 million.  This compensation cost will be recognized over the period through December 31, 2007.  The total fair value of restricted stock released for the three months ended March 31, 2007 was $.3 million.  Non-vested, time-based restricted stock awards as of March 31, 2007 and changes during the three months ended March 31, 2007 were as follows: 

 

|               | **Shares** | **Weighted Average Grant Date****Fair Value** | **Remaining Contractual****Term in Years** |
|--------------------|------------|-----------------------------------------------|--------------------------------------------|
| Beginning balance  | 351,515    | $                                             | 16.79                                      | .97 |
| Awarded            | -          |                                          | -                                          |   |
| Released           | (75,533)   |                                          | 25.59                                      |   |
| Forfeited          | -          |                                          | -                                          |   |
| **Ending balance** | 275,982    | $                                             | 14.38                                      | .85 |

 

The aggregate intrinsic value of outstanding time-based restricted stock was $1.2 million as of March 31, 2007.

 

**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 EBITDA 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 be payable if the threshold is not reached. The fair valueof these stock awards is determined based on the number of shares granted and the quoted price of our stock on date of the award.  The compensation expense related to this award was $.1 million for the three months ended March 31, 2007.  As of March 31, 2007, the estimated total compensation cost not yet recognized was $.4 million.  This compensation cost will be recognized over the period through March 1, 2008.  Non-vested, performance-based restricted stock awards (based on target number) as of March 31, 2007 and changes during the three months ended March 31, 2007 were as follows:

 

|               | **Shares** | **Weighted average Grant Date****Fair Value** | **Remaining Contractual****Term in Years** |
|--------------------|------------|-----------------------------------------------|--------------------------------------------|
| Beginning balance  | 176,000    | $                                             | 4.44                                       | 1.25 |
| Awarded            | -          |                                          | -                                          |   |
| Released           | -          |                                          | -                                          |   |
| Forfeited          | -          |                                          | -                                          |   |
| **Ending balance** | 176,000    | $                                             | 4.44                                       | .88 |

 

The aggregate intrinsic value of outstanding performance-based restricted stock was $ .7 million as of March 31, 2007.

 

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**Director Stock Awards**

 

Non-employee directors receive as part of his or her annual retainer, an annual award of 7,500 shares of common stock of the Company.  Each director may elect to defer receipt of their shares until retirement or until they are no longer a member of our Board of Directors.  Shares are awarded on the last trading day of each calendar quarter.  Compensation expense is based upon the fair market value of the Company’s common stock at the date of issuance

 

|               | **Shares** | **Weighted average Grant Date****Fair Value** |
|--------------------|------------|-----------------------------------------------|
| Beginning balance  | 208,372    | $                                             | 4.45 |
| Awarded            | 13,125     |                                          | 4.18 |
| Released           | (3,750)    |                                          | 4.18 |
| **Ending balance** | 217,747    | $                                             | 4.44 |

 

The aggregate intrinsic value of outstanding director stock awards was $.9 million as of March 31, 2007.

 

**10: Income Taxes**

 

We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” (FIN 48) effective January 1, 2007.  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 practice prior to FIN 48 was to recognize income tax benefits when they were reflected on filed income tax returns and establish a reserve against these tax benefits when their ultimate realization was not deemed to be “probable.”  Our reserve for uncertain tax positions was $377.3 million at December 31, 2006.

 

In connection with the adoption of FIN 48 we analyzed our uncertain tax positions using the new “more likely than not” threshold.  Based on this analysis, the reserve for uncertain tax positions was reduced by $175.4 million.  This resulted in net deferred tax assets of $156.1 million.  The primary deferred tax asset is the tax benefit related to our net operating loss (NOL) carryforwards.  We were required to assess the ultimate realization of the deferred tax assets using a “more likely than not” standard of assessment.  This assessment considered tax planning strategies within our control.  The assessment, however, did not take into consideration the expected taxable gains, both ordinary and capital, from the pending sales of our Colorado electric properties and our Colorado, Kansas, Iowa and Nebraska gas properties.  In addition, the assessment did not take intoconsideration our pending merger with a subsidiary of Great Plains Energy.  Lastly, the assessment also did not take into consideration the expected results from filed rate cases or debt reductions expected to be completed with the proceeds from the sale of our Kansas electric properties.

 

Since the implementation of FIN 48 resulted in a net deferred tax asset position and the primary deferred tax asset relates to NOL carryforwards, we recorded a valuation allowance of $156.1 million against the tax benefit related to the NOL carryforwards equal to the net deferred tax assets.

 

The net effect of the implementation of FIN 48 including the adjustment for related valuation allowance was affected through an increase of $19.3 million to beginning retained earnings in the first quarter of 2007.

 

As discussed above, our practice prior to implementation of FIN 48 was to record tax benefits based on returns as filed and establish a reserve against these tax benefits when they were deemed to be uncertain.  Under FIN 48, however, tax benefits are not recorded when their ultimate realization is deemed to be uncertain.  As such, we adjusted our deferred tax accounts at January 1, 2007 to reduce deferred tax assets that relate to uncertain tax benefits under the FIN 48 “more likely than not” threshold.  The reserve for uncertain tax benefits was reduced by the same amount.

 

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Deferred tax assets impacted by these adjustments were those related to NOL carryforwards, AMT credit carryforwards and general business credit carryforwards.  In addition, some income tax uncertainties relate to the characterization of certain taxable gains as capital instead of ordinary.  Thus, the reduction in deferred tax assets for NOL carryforwards was partially offset by an increase in deferred tax assets for capital loss carryforwards.  However, we maintain a full valuation allowance against the tax benefits from our capital loss carryforwards, so this valuation allowance was likewise increased.  These adjustments did not change the amount of net deferred tax assets.

 

The amount of unrecognized income tax benefits at January 1, 2007 was $222.6 million.  Of this amount, $196.9 million would impact the effective rate, if recognized.  We recognize accrued interest and penalties associated with uncertain tax positions as part of the tax provision.  When interest and penalties are assessed they are recorded as such and the tax provision is adjusted.  As of January 1, 2007, we had $5 million of accrued interest and penalties included in the reserve for uncertain tax positions.  At March 31, 2007, the amount of unrecognized income tax benefits increased to $223.2 million.  Of this amount, $197.3 would impact the effective rate, if recognized.  Accrued interest and penalties associated with uncertain tax positions at March 31, 2007 were $7.3 million.

 

In addition to our consolidated Federal and various state tax returns, we file separate subsidiary tax returns in Canada and certain other states.

 

On March 22, 2007, the Joint Committee on Taxation approved our settlement with the Appeals division of the Internal Revenue Service (IRS) related to the 1996 and 1997 tax years.  The Examination division of the IRS is currently auditing tax years 1998 through 2004.  We expect the audit of the years 1998 through 2002 to be complete within the next twelve months but we cannot predict when the audit of 2003 and 2004 will be complete.

 

It is reasonably possible that the amount of unrecognized tax benefits will change significantly within the next twelve months.  This change will occur if the audit of the years 1998 through 2002 is completed.  An estimate of any changes to the amount of unrecognized tax benefits cannot be made at this time.

 

**11: Pending Merger**

 

On February 6, 2007, we entered into an agreement and plan of merger with Great Plains Energy, Gregory Acquisition Corp., a wholly-owned subsidiary of Great Plains Energy, and Black Hills, which provides for the merger of Gregory Acquisition Corp. into us, with Aquila continuing as the surviving corporation.  If the Merger is completed, we will become a wholly-owned subsidiary of Great Plains Energy, and our shareholders will receive cash and shares of Great Plains Energy common stock in exchange for their shares of Aquila common stock.  At the effective time of the Merger, each share of Aquila common stock will convert into the right to receive 0.0856 of a share of Great Plains Energy common stock and a cash payment of $1.80.  The exchange ratio is fixed and will not be adjusted to reflect stock price changes prior to the completion of the Merger.  Upon consummation of the Merger, ourshareholders are expected to own approximately 27% of the outstanding common stock of Great Plains Energy, and the Great Plains Energy shareholders will own approximately 73% of the outstanding common stock of Great Plains Energy.

 

The parties have made customary representations, warranties and covenants in the merger agreement.  We have agreed, subject to certain exceptions set forth in the merger agreement, to conduct our business in the ordinary course during the period between the execution of the merger agreement and consummation of the Merger, to refrain from engaging in or otherwise limit certain transactions and activities during this interim period, and to use our reasonable best efforts to hold a shareholders meeting as promptly as possible to consider approval of the Merger and the other transactions contemplated by the merger agreement.  We and Great Plains Energy have also agreed, subject to customary exceptions, that (i) each party’s board of directors will recommend that its shareholders approve the transactions and (ii) neither party will solicit proposals relating to alternative businesscombination transactions.  

 

27

 

Consummation of the Merger is subject to a number of conditions, including (i) approval by our shareholders and the shareholders of Great Plains Energy; (ii) approval of the FERC, the Kansas Commission and the Missouri Commission; (iii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (iv) the completion of the asset sale transactions described below; and (v) the absence of a material adverse effect on our businesses that remain after giving effect to the asset sales described below. 

 

The merger agreement contains certain termination rights for both us and Great Plains Energy, including the right to terminate the merger agreement if the Merger has not closed within 12 months following the date of the merger agreement (subject to extension to up to 18 months for receipt of regulatory approvals required to consummate the Merger and the asset sales). We and Great Plains Energy each have the right to terminate the merger agreement to enter into a superior transaction after giving the other party six business’ days notice and an opportunity to revise the terms of the merger agreement.  If the merger agreement is terminated under specified circumstances (including a termination to enter into a superior transaction), we or Great Plains Energy will pay to the other a $45 million termination fee.

 

In connection with the Merger, we also entered into agreements with Black Hills under which we have agreed to sell our Colorado electric utility and our Colorado, Iowa, Kansas and Nebraska gas utilities to Black Hills for $940 million in cash, subject to certain working capital and other purchase price adjustments.  The agreements contain various provisions customary for transactions of this size and type, including representations, warranties and covenants with respect to the Colorado, Iowa, Kansas and Nebraska utility businesses that are subject to usual limitations.  Completion of the sale transactions is subject to various conditions, including: (i) the approval of the FERC, the Colorado Public Utilities Commission, the IUB, the Kansas Commission, and the Nebraska Commission; (ii) the expiration or early termination of any waiting period under the Hart-Scott-Rodino Antitrust Act of1976, as amended; (iii) the absence of a material adverse effect on the utility businesses being sold to Black Hills; and (iv) the ability and readiness of Aquila, Great Plains Energy and Gregory Acquisition Corp. to complete the Merger immediately after the completion of the asset sales.  The employees of these utility operations are expected to be transferred to Black Hills upon completion of the sale.

 

The Merger and the asset sales are contingent upon the closing of the other transaction, meaning that one transaction will not close unless the other transaction closes.  

 

On April 4, 2007, we and Great Plains Energy filed joint applications with the Missouri Commission and the Kansas Commission requesting approval of the Merger.  On the same date, we and Black Hills filed joint applications with the Colorado Public Utilities Commission, IUB, Kansas Commission and Nebraska Commission requesting approval of the asset sales to Black Hills.

 

We have evaluated the accounting classification of the assets to be acquired by Black Hills relative to SFAS 144.  Based on our assessment, the criteria for classification of the assets as "held for sale" and discontinued operations have not been met.  Important factors underlying our analysis include: our management and board of directors have no intention of selling these assets separately from the contingent, two-step Merger transaction, which is not a usual and customary provision for asset sales; the significant conditions to closing, including numerous shareholder and regulatory approvals; and, the fact the asset sale will occur immediately prior to the completion of the Merger.  As a result, we have not reclassified the assets to be acquired by Black Hills as "held for sale" and reported those results as discontinued operations.

 

Regardless of whether the Merger is completed, we will incur significant costs, primarily consisting of investment banking, legal, employee retention, change-in-control, and other severance costs which we will expense as they are incurred.  In 2006, we incurred approximately $2.3 million of costs (primarily investment banking and legal costs) relating to these transactions.  In the three months ended March 31, 2007, we incurred $7.3 million of additional costs, including fees paid to our 

 

28

financial advisors of $6.2 million in connection with the signing and announcement of the merger agreement.  These costs are included in operation and maintenance expense in Corporate and Other.

 

In February 2007, we also executed retention agreements totaling $8.4 million with numerous non-executive employees to mitigate employee attrition prior to the closing of the Merger.  The retention awards will be paid on the earlier of the closing of the Merger or January 31, 2008.  We accrued $1.2 million of expense related to these retention agreements in the three months ended March 31, 2007.  These costs are included in operation and maintenance expense in Corporate and Other.

 

Further information concerning the Merger and asset sales will be included in a merger proxy statement we will file with the SEC and mail to our shareholders.  This proxy statement will also constitute a prospectus for the Great Plains Energy common stock to be issued to our shareholders in the Merger and be included in a registration statement on Form S-4 to be filed with the SEC by Great Plains Energy.

 

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

 

**See Forward-Looking Information beginning on page 42.**

 

**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 efficiently execute our multi-state regulated utility growth strategy.  The key elements of our remaining repositioning initiatives are to significantly reduce our debt levels and interest expense.

 

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 expect to use the proceeds from our Kansas electric asset sale to retire debt and reduce interest expense or fund capital expenditures. 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 improvement to our credit profile and cash flow.

 

29

**Current Credit Ratings**

 

As of March 31, 2007, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows: 

 

| **Agency** | **Rating** | **Commentary**                            |
|------------|------------|-------------------------------------------|
| Moody's    | B2         | Ratings Under Review for Possible Upgrade |
| S&P    | B          | Credit Watch Positive                     |
| Fitch      | B+         | Rating Watch Positive                     |

 

**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****March 31, 2007** |
|-----------------------------------------------------------------------------------------------------------------------------------------|----------------------|-------------------------|--------------------------------------------------------------------|
|                                                                                                                                    |                 | *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                                                              |   | 129.7 |
| $50 Million Unsecured    Revolving Credit and     Letter of Credit     Facility  | December 19, 2007    |                    | 50.0                                                               |   | 42.0 |

 

| * * | *(1)* | *Borrowings under these facilities must be repaid within 364 days unless we obtain regulatory approval to incur long-term indebtedness under these facilities.* |
|----------|-------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

**Cash Flows**

 

***Cash Flows Provided From Operating Activities***

 

Our positive three-month 2007 operating cash flows were driven primarily by seasonal declines in working capital requirements for our utility operations.

 

30

 

Our positive three-month 2006 operating cash flows were driven primarily 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 $91.3 million of funds on deposit and a $35.1 million decrease in other current assets.  Additionally, we received $38.7 million of funds on deposit returns due to the replacement of cash deposits and cash-collateralized letters of credit with unsecured letters of credit supporting our former Elwood tolling contracts, and utilized $53.9 million of gas inventory held in storage.  Offsetting the increases was the return of $43.7 million of counterparty collateral resulting from lower natural gas prices since December 2005, a $25.4 million payment to Calpine in connection with the netting of amounts owed under various contracts at the time ofCalpine’s bankruptcy filing, and a $15.8 million decrease in accrued interest due to the timing of interest payments.   

 

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 to cover these interest costs as well as to fund our capital investment plan. We are attempting to do this by improving the efficiency of our remaining businesses, increasing sales through utility rates, retiring debt and completing the wind-down of our Merchant Services business. 

 

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

 

The decrease in cash provided from investing activities was primarily the result of lower cash proceeds received on the sale of assets. In addition, utility capital expenditures increased compared to 2006 primarily due to the construction of the Iatan 2 facility.  

 

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

 

Cash flows used for financing activities in the three months ended March 31, 2007 and 2006 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.

 

**Collateral Positions**

 

|   | As of March 31, 2007, we had posted cash collateral for the following: |
|--------|------------------------------------------------------------------------|

 

| *In millions***                      |   |   |
|--------------------------------------|--------|--------|
| Trading positions                    | $      | 32.1   |
| Utility cash collateral requirements |   | 35.8   |
| Other                                |   | .8     |
| Total Funds on Deposit               | $      | 68.7   |

 

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 EBITDA. We use EBITDA as a performance measure as it captures the 

 

31

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 3 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 former 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 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.”

 

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** |
|------------------------------------------------------------------------|--------|------------------------|
|                                                                   |   | **March 31,**          |
| *In millions*                                                          |   |                   | **2007** | **2006** |
| Earnings (Loss) Before Interest, Taxes, Depreciation and Amortization: |   |                   |   |   |   |   |   |   |
| Utilities:                                                             |   |                   |   |   |   |   |   |   |
| Electric Utilities                                                     |   |                   |   |   | $ | 6.2 | $ | 23.6 |
| Gas Utilities                                                          |   |                   |   |   |   | 29.1 |   | 25.1 |
| Total Utilities                                                        |   |                   |   |   |   | 35.3 |   | 48.7 |
| Merchant Services                                                      |   |                   |   |   |   | (4.1) |   | (7.4) |
| Corporate and Other                                                    |   |                   |   |   |   | (10.3) |   | (5.6) |
| Total EBITDA                                                           |   |                   |   |   |   | 20.9 |   | 35.7 |
| Depreciation and amortization                                          |   |                   |   |   |   | 27.2 |   | 27.1 |
| Interest expense                                                       |   |                   |   |   |   | 34.7 |   | 37.0 |
| Income tax benefit                                                     |   |                   |   |   |   | (13.8) |   | (10.8) |
| Loss from continuing operations                                        |   |                   |   |   |   | (27.2) |   | (17.6) |
| Earnings from discontinued    operations, net of tax    |   |                   |   |   |   | 2.9 |   | 16.5 |
| Net loss                                                               |   |                   |   |   | $ | (24.3) | $ | (1.1) |

 

**Key Factors Impacting Results of Continuing Operations**

 

For the three months ended March 31, 2007, total EBITDA decreased $14.8 million compared to 2006. Key factors affecting 2007 results were as follows: 

 

|   | **•** | Total Utilities EBITDA decreased $13.4 million primarily due to increased fuel and |
|--------|------------|------------------------------------------------------------------------------------|

 

32

purchased power costs in our Electric Utilities resulting from reduced availability of certain power plants due to unplanned or extended outages and curtailed delivery under a purchased power contract, unfavorable settlements of hedge transactions and increased operation and maintenance expenses.  These EBITDA decreases were offset in part by increased EBITDA in our Gas Utilities due to favorable weather and other volumes and increased interim rates in Nebraska.

 

|   | **•** | Merchant Services loss before interest, taxes, depreciation and amortization decreased $3.3 million in 2007 compared to 2006 primarily due to the elimination of $9.6 million of margin losses incurred in 2006 related to our former Elwood tolling agreements as a result of the assignment of obligations associated with these agreements in June 2006, offset in part by $4.4 million of reversals of allowances for bad debts in 2006 that did not recur in 2007. |
|--------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Corporate and other loss before interest, taxes, depreciation and amortization increased $4.7 million in 2007 compared to 2006, primarily due to increased legal and financial advisors fees related to the pending merger and asset sale. |
|--------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

**Electric Utilities**

 

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

 

|                                                                   |   | **Three Months Ended** |
|------------------------------------------------------------------------|--------|------------------------|
|                                                                   |   | **March 31,**          |
| *Dollars in millions***                                                |   |                   | **2007** | **2006** |
| Sales:                                                                 |   |                   |   |   |   |   |   |   |
| Electricity—regulated                                             |   |                   |   |   | $ | 171.6 | $ | 169.3 |
| Other—non-regulated                                               |   |                   |   |   |   | .2 |   | .2 |
| Total sales                                                            |   |                   |   |   |   | 171.8 |   | 169.5 |
| Cost of sales:                                                         |   |                   |   |   |   |   |   |   |
| Electricity—regulated                                             |   |                   |   |   |   | 115.5 |   | 97.4 |
| Other—non-regulated                                               |   |                   |   |   |   | – |   | .1 |
| Total cost of sales                                                    |   |                   |   |   |   | 115.5 |   | 97.5 |
| Gross profit                                                           |   |                   |   |   |   | 56.3 |   | 72.0 |
| Operation and maintenance expense                                      |   |                   |   |   |   | 48.2 |   | 42.9 |
| Taxes other than income taxes                                          |   |                   |   |   |   | 5.8 |   | 5.4 |
| Other income (expense)                                                 |   |                   |   |   |   | 3.9 |   | (.1) |
| EBITDA                                                                 |   |                   |   |   | $ | 6.2 | $ | 23.6 |
| Reconciliation of EBITDA to Loss Before   Income Taxes: |   |                   |   |   |   |   |   |   |
| EBITDA                                                                 |   |                   |   |   | $ | 6.2 | $ | 23.6 |
| Depreciation and amortization expense                                  |   |                   |   |   |   | 18.4 |   | 17.3 |
| Interest expense                                                       |   |                   |   |   |   | 14.1 |   | 13.2 |
| Loss before income taxes                                               |   |                   |   |   | $ | (26.3) | $ | (6.9) |
| Electric sales and transportation   volumes (GWh)  |   |                   |   |   |   | 2,673.0 |   | 2,661.0 |
| Electric customers at end of period                                    |   |                   |   |   |   | 400,414 |   | 394,418 |

 

***Quarter-to-Quarter***

 

*Sales, Cost of Sales and Gross Profit*

 

33

Sales and cost of sales for the Electric Utilities business increased $2.3 million and $18.0 million, respectively. However, gross profit decreased by $15.7 million in 2007 compared to 2006.  These changes were primarily due to the following factors:  

 

|   | **•** | Sales and gross profit increased by $5.0 million due to a rate increase in Missouri effective March 2006. |
|--------|------------|-----------------------------------------------------------------------------------------------------------|

 

|   | **•** | Favorable weather-related retail volume and other variances increased gross profit by $4.3 million in 2007. |
|--------|------------|-------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Cost of sales increased by $21.9 million due to several factors.  First, several of our wholly-owned and jointly-owned coal-fired, baseload plants experienced outages (both unplanned outages and extended planned outages) in the quarter that required us to purchase replacement power in the spot market, which increased costs by $3.0 million.  In addition, a baseload purchased power contract was curtailed under a force majeure due to transmission constraints, thereby requiring additional power to be purchased in the spot market resulting in increased costs of sales of $3.4 million.  Also contributing to the increased costs was higher generation cost of $3.3 million caused by higher coal and delivery costs as well as a greater percentage of generation from gas fired units.  A combination of the above events, as well as other regional market conditions, generallyresulted in higher purchased power prices in the spot market during the quarter, which added $12.2 million to our cost of sales. |
|--------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Unfavorable derivative settlements related to fuel hedges for our Missouri operations of $5.5 million also contributed to the increase in cost of sales in 2007. |
|--------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Sales and cost of sales decreased $8.5 million and $9.5 million, respectively, from lower sales for resale.  Gross profit increased, however, by $1.0 million from 2006 to 2007. |
|--------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense increased $5.3 million in 2007 compared to 2006.  A primary factor contributing to this increase was a $2.4 million increase in labor and benefit costs.  Also included in the quarter-to-quarter expense increase was a $3.5 million increase in outside services and materials related to maintenance during the plant outages.

 

*Other Income (Expense)*

 

Other income increased $4.0 million primarily due to the receipt in 2007 of $3.2 million in breakup fees related to the unsuccessful attempt to purchase the Aries power plant for which we had been named the stalking horse bidder in an auction process run on behalf of creditors of Calpine Corporation.

 

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

 

As mentioned above, it was necessary for us to purchase additional power in the spot market due to reduced delivery under a purchase power contract whose supplier was experiencing severe transmission constraints resulting from winter storm damage.  It is anticipated that repairs to these 

 

34

transmission lines will not be completed until the end of May 2007 and could result in $2.0 million of estimated increased costs for purchased power in the second quarter of 2007.

 

We have entered into a program for our electric utility operations in Missouri to mitigate our exposure to natural gas price volatility in the market.  The mark-to-market liability position of the portfolio of $.9 million relates to contracts that will settle against actual purchases of natural gas and purchased power in 2007 through 2009.  In connection with the March 2006 settlement of our 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 $.9 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 set forth rules regarding the implementation and definition of costs to be recovered in the fuel adjustment mechanism for our Missouri electric operations.  The rules became final on January 30, 2007.  Based upon the Stipulation and Agreement in the pending rate case ER-2007-0004 in Missouri the value of our NYMEX financial contracts will be a part of the defined costs to be recovered through any fuel adjustment structure approved by the Missouri Commission in this pending rate case.  

 

**Gas Utilities**

 

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

 

|                                                                     |   | **Three Months Ended** |
|--------------------------------------------------------------------------|--------|------------------------|
|                                                                     |   | **March 31,**          |
| *Dollars in millions***                                                  |   |                   | **2007** | **2006** |
| Sales:                                                                   |   |                   |   |   |   |   |   |   |
| Natural gas—regulated                                               |   |                   |   |   | $ | 270.7 | $ | 253.2 |
| Other—non-regulated                                                 |   |                   |   |   |   | 5.1 |   | 9.8 |
| Total sales                                                              |   |                   |   |   |   | 275.8 |   | 263.0 |
| Cost of sales:                                                           |   |                   |   |   |   |   |   |   |
| Natural gas—regulated                                               |   |                   |   |   |   | 209.7 |   | 199.5 |
| Other—non-regulated                                                 |   |                   |   |   |   | 2.4 |   | 7.5 |
| Total cost of sales                                                      |   |                   |   |   |   | 212.1 |   | 207.0 |
| Gross profit                                                             |   |                   |   |   |   | 63.7 |   | 56.0 |
| Operation and maintenance expense                                        |   |                   |   |   |   | 31.1 |   | 27.7 |
| Taxes other than income taxes                                            |   |                   |   |   |   | 3.2 |   | 3.0 |
| Other income (expense)                                                   |   |                   |   |   |   | (.3) |   | (.2) |
| EBITDA                                                                   |   |                   |   |   | $ | 29.1 | $ | 25.1 |
| Reconciliation of EBITDA to Income   Before Income Taxes: |   |                   |   |   |   |   |   |   |
| EBITDA                                                                   |   |                   |   |   | $ | 29.1 | $ | 25.1 |
| Depreciation and amortization expense                                    |   |                   |   |   |   | 7.8 |   | 8.8 |
| Interest expense                                                         |   |                   |   |   |   | 3.1 |   | 3.8 |
| Income before income taxes                                               |   |                   |   |   | $ | 18.2 | $ | 12.5 |
|                                                                     |   |                   |   |   |   |   |   |   |
| Gas sales and transportation volumes (Bcf)                          |   |                   |   |   |   | 39.5 |   | 33.4 |
| Gas customers at end of period                                           |   |                   |   |   |   | 520,340 |   | 514,651 |

 

***Quarter-to-Quarter***

 

*Sales, Cost of Sales and Gross Profit*

 

Sales and cost of sales for the Gas Utilities business increased $12.8 million and $5.1 million, respectively, for a gross profit increase of $7.7 million in 2007 compared to 2006.  These changes 

 

35

were primarily due to the following factors:  

 

|   | **•** | Sales and gross profit increased by $1.8 million due primarily to an interim rate increase, subject to refund, in Nebraska effective in February 2007. |
|--------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Favorable weather and volume variances, net of weather hedges, increased sales, cost of sales and gross profit by $52.8 million, $48.4 million and $4.4 million, respectively. |
|--------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Increased sales and cost of sales were partially offset by approximately $40.1 million due to a 15.5% decrease in natural gas prices in the first quarter of 2007 compared to 2006.  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. |
|--------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

*Operation and Maintenance Expense*

 

Operation and maintenance increased $3.4 million in 2007 compared to 2006.  The increase was due to higher outside services, labor and other operating costs.

 

***Regulatory Matters***

 

|   | The following is a summary of our recent rate case activity through April 30, 2007: |
|--------|-------------------------------------------------------------------------------------|

 

| *In millions*  | **Type of****Service** | **Date****Requested** | **Date****Effective** | **Amount****Requested** | **Amount****Approved** |
|----------------|------------------------|-----------------------|-----------------------|-------------------------|------------------------|
| Iowa *(1)*     | Gas                    | 5/2005                | 3/2006                | $                       | 4.1                    | $ | 2.9 |
| Missouri *(2)* | Electric               | 5/2005                | 3/2006                |                    | 78.6                   |   | 44.8 |
| Missouri *(2)* | Steam                  | 5/2005                | 3/2006                |                    | 5.0                    |   | 4.5 |
| Missouri *(3)* | Electric               | 7/2006                | Pending               |                    | 118.9                  |   | Pending |
| Kansas *(4)*   | Gas                    | 11/2006               | Pending               |                    | 7.2                    |   | Pending |
| Nebraska *(5)* | Gas                    | 11/2006               | Pending               |                    | 16.3                   |   | Pending |

 

|   | (1) | Under Iowa regulations, we instituted interim rates, subject to refund, totaling approximately $1.7 million in May 2005.  On March 1, 2006, the 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. Final rates became effective March 17, 2006. |
|--------|-----|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | (2) | 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. |
|--------|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | (3) | In July 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 purchased 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. |
|--------|-----|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

36

Our original filing reflected flow-through power capacity costs equivalent to the estimated revenue requirement for the purchase of the Aries plant, for which we had been named the stalking horse bidder in an auction process run on behalf of creditors of Calpine Corporation.  However, the bidding reached a point at which it did not make economic sense for Aquila to continue in the process.  Consequently, we secured lower cost short-term purchased power contracts in lieu of the capacity the Aries plant would have otherwise provided.

 

In January 2007, the Missouri Commission staff recommended a return on equity in the range of 9% to 10.25% which, together with other recommendations of the staff, would yield a rate increase in the range of $45.9 million to $56.4 million.  The staff’s case included the effects of not acquiring Aries, as discussed above.  The staff recommended implementing an interim energy charge instead of a fuel adjustment clause.

 

On April 4, 2007, Aquila, the Missouri Commission staff and various intervenors entered into a stipulation and agreement that settled several issues raised in the pending Missouri rate cases.  Among other things, the stipulation and agreement (i) established a $918.5 million rate base for the Missouri Public Service operations and a $186.8 million rate base for the St. Joseph Light & Power operations; (ii) established the present revenue requirements of each operation, and the additional revenue requirements to result from the pending rate cases; (iii) authorized the inclusion in base rates of $156.4 million and $38.2 million of fuel and purchased power costs for the Missouri Public Service and St. Joseph Light & Power operations, respectively; and (iv) authorized us to continue to use the depreciation rates currently established for our Missouri operations.  On April 12, 2007, theMissouri Commission approved the stipulation and agreement.  The settlement would result in rate increases of approximately $53.3 million pending the resolution of three issues on which hearings were held.  The remaining issues to be settled include the appropriate return on equity, for which the Missouri Commission staff has recommended a return on equity of 9.625%, which is the mid-point of staff's recommended range of 9% to 10.25%; the authorization of our requested fuel adjustment recovery mechanism; and, the treatment of an accounting authority order.  Hearings were completed on April 12, 2007, and we expect a final order from the Missouri Commission by mid-May, with new rates effective May 30, 2007.

 

|   | (4) | In November 2006, we filed for a $7.2 million rate increase for our Kansas gas utility operations.  Also included in this filing was a request to redesign the rate structure to shift most fixed-cost of service recovery from the usage-based delivery charge to a customer and demand charge. The Kansas Commission staff has proposed a $4.2 million increase based upon a 9.8% return on equity, and another intervenor (CURB) proposed a $3.5 million increase based upon a 9.35% return on equity.  On April 20, 2007, Aquila, the Kansas Commission staff, and various intervenors entered into a stipulation and agreement that resulted in a "black box" settlement of $5.1 million, with a residential customer charge of $16 per month that will recover approximately 65% of the margin in the customer charge.  Our proposed demand-based rate design was not adopted.  We expect the KansasCommission to approve the settlement and new rates in May 2007, with implementation beginning June 1, 2007. |
|--------|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | (5) | In November 2006, we filed for a $16.3 million rate increase for our Nebraska gas utility operations.  Interim rates were implemented on February 15, 2007, and the Nebraska Commission has up to 240 days to make a decision regarding our rate request.  The state's public advocate has recommended a $1.8 million rate increase based upon a 10% return on equity.  If the interim rates are higher than the final rates approved by the Nebraska Commission, the difference plus interest will be refunded or credited to customers. |
|--------|-----|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

37

**Merchant Services**

 

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

 

|                                                                           |   | **Three Months Ended** |
|--------------------------------------------------------------------------------|--------|------------------------|
|                                                                           |   | **March 31,**          |
| *Inmillions*                                                                   |   |                   | **2007** | **2006** |
| Sales                                                                          |   |                   |   |   | $ | (3.4) | $ | (1.5) |
| Cost of sales                                                                  |   |                   |   |   |   | **–** |   | 9.7 |
| Gross loss                                                                     |   |                   |   |   |   | (3.4) |   | (11.2) |
| Operating expenses:                                                            |   |                   |   |   |   |   |   |   |
| Operation and maintenance expense, net                                         |   |                   |   |   |   | .8 |   | (3.1) |
| Taxes other than income taxes                                                  |   |                   |   |   |   | **–** |   | .4 |
| Net loss on sale of assets and other charges                                   |   |                   |   |   |   | – |   | .7 |
| Total operating expenses (income), net                                         |   |                   |   |   |   | .8 |   | (2.0) |
| Other income                                                                   |   |                   |   |   |   | .1 |   | 1.8 |
| Earnings (loss) before interest, taxes, depreciation and amortization          |   |                   |   |   | $ | (4.1) | $ | (7.4) |
| Reconciliation of EBITDA to Loss      Before Income Taxes: |   |                   |   |   |   |   |   |   |
| EBITDA                                                                         |   |                   |   |   | $ | (4.1) | $ | (7.4) |
| Depreciation and amortization expense                                          |   |                   |   |   |   | 1.0 |   | 1.1 |
| Interest expense                                                               |   |                   |   |   |   | 2.6 |   | 6.2 |
| Loss before income taxes                                                       |   |                   |   |   | $ | (7.7) | $ | (14.7) |
|                                                                           |   |                   |   |   |   |   |   |   |

 

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 March 31, 2007 was $3.4 million, primarily due to the following factors:

 

|   | **•** | We incurred margin losses of $2.2 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 $1.2 million gross loss related to the settlement of various contracts and trade positions in the first quarter of 2007 due to the continued wind-down of our merchant operations. |
|--------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

Gross loss for our Merchant Services operations for the three months ended March 31, 2006 was $11.2 million, primarily due to the following factors:

 

|   | **•** | We made fixed capacity payments evenly throughout the year that entitled us to generate power at the Elwood plant.  In the first quarter of 2006, we recorded net margin losses associated with these agreements of $9.6 million.  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. |
|--------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | We also incurred margin losses of $2.1 million resulting from the difference between revenue recognized on our two remaining long-term gas contracts compared to the net cost of gas delivered under these contracts. |
|--------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

38

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense increased $3.9 million in 2007 from 2006 primarily due to the first quarter of 2006 reversal of $4.4 million of allowances for bad debts provided in prior years as our receivable balance declined with the roll-off of the legacy trading portfolio.

 

***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. It is generally expected that the fuel and start-up costs of operating our Crossroads plant will exceed the revenues that would be generated from the power sold.  We therefore believe that during the next few years we have limited ability to generate power at the Crossroads facility for a profit.  We have assessed the realizability of our investment in this plant and do not believe an impairment has occurred.  We will continue to have operating and maintenance costs associated with this plant, whether it is being utilized to generate power or is idle. Additionally, we continue to wind down and terminate our remainingtrading 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 which expire by early 2008.  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 the Crossroads 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 next few years. This situation has prevented 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-simulationscenario analysis and then equally weighted each price environment. Based on this analysis and the level of probability we would sell this asset, the undiscounted, probability-weighted cash flows for the plant exceeded its current book value. Therefore, under SFAS 144 no 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 December 31, 2006, we reviewed market conditions and the assumptions used in the 2005 assessment and determined that no significant adverse changes had occurred.  Therefore, a full assessment was not required.  As of March 31, 2007, the carrying value of this plant was $117.9 million.

 

39

**Corporate and Other**

 

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

 

|                                                                                          |   | **Three Months Ended** |
|-----------------------------------------------------------------------------------------------|--------|------------------------|
|                                                                                          |   | **March 31,**          |
| *In millions***                                                                               |   |                   | **2007** | **2006** |
| Operating expenses:                                                                           |   |                   |   |   |   |   |   |   |
| Operation and maintenance expense                                                             |   |                   |   |   | $ | 10.9 | $ | 3.7 |
| Taxes other than income taxes                                                                 |   |                   |   |   |   | (.1) |   | .1 |
| Restructuring charges                                                                         |   |                   |   |   |   | 1.6 |   | 2.0 |
| Total operating expenses                                                                      |   |                   |   |   |   | 12.4 |   | 5.8 |
| Other income                                                                                  |   |                   |   |   |   | 2.1 |   | .2 |
| Earnings (loss) before interest, taxes,     depreciation and amortization |   |                   |   |   | $ | (10.3) | $ | (5.6) |
| Reconciliation of EBITDA to Loss      Before Income Taxes:                |   |                   |   |   |   |   |   |   |
| EBITDA                                                                                        |   |                   |   |   | $ | (10.3) | $ | (5.6) |
| Depreciation and amortization expense                                                         |   |                   |   |   |   | – |   | (.1) |
| Interest expense                                                                              |   |                   |   |   |   | 14.9 |   | 13.8 |
| Loss before income taxes                                                                      |   |                   |   |   | $ | (25.2) | $ | (19.3) |
|                                                                                          |   |                   |   |   |   |   |   |   |

 

***Quarter-to-Quarter***

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense increased $7.2 million primarily due to advisor fees and legal costs related to the pending merger.

 

*Other Income*

 

Other income increased $1.9 million in 2007 compared to 2006 primarily due to increased interest income on available cash balances.

 

**Interest Expense and Income Tax Benefit**

 

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

 

|                                 |   | **Three Months Ended** |
|--------------------------------------|--------|------------------------|
|                                 |   | **March 31,**          |
| *In millions***                      |   |                   | **2007** | **2006** |
|                                 |   |                   |   |   |   |   |   |   |
| Interest expense                     |   |                   |   |   | $ | 34.7 | $ | 37.0 |
|  

Income tax expense (benefit) |   |                   |   |   | $ | (13.8) | $ | (10.8) |

 

***Quarter-to-Quarter***

 

*Interest Expense*

 

Interest expense decreased $2.3 million in 2007 compared to 2006 primarily due to $14.3 million of interest savings on debt retired in 2006 offset in part by $12.8 million of decreased allocations of interest to discontinued operations due to the completion of the sale of certain assets.  This increase 

 

40

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 were used to reduce obligations other than debt, such as our former Elwood tolling agreement, this interest expense will remain in continuing obligations.  

 

*Income Tax Benefit*

 

Income tax benefit increased $3.0 million in 2007 compared to 2006.  The effective tax rate in 2007 was 33.5% compared to 38.0% in 2006 as a result of the tax effect of non-deductible merger transaction fees offset in part by a $2.9 million decrease in our valuation allowance for net operating losses.

 

**Discontinued Operations**

 

As further discussed in Note 3 to the Consolidated Financial Statements, we have reported the results of operations of our former 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.  

 

| * *                                                         |   | **Three Months Ended** |
|------------------------------------------------------------------|--------|------------------------|
| * *                                                         |   | **March 31,**          |
| *Dollars in millions*                                            |   |                   | **2007** | **2006** |
| Sales                                                            |   |                   |   |   | $ | 43.5 | $ | 310.0 |
| Cost of sales                                                    |   |                   |   |   |   | 23.1 |   | 233.5 |
| Gross profit                                                     |   |                   |   |   |   | 20.4 |   | 76.5 |
| Operating expenses:                                              |   |                   |   |   |   |   |   |   |
| Operation and maintenance expense                                |   |                   |   |   |   | 10.0 |   | 28.7 |
| Taxes other than income taxes                                    |   |                   |   |   |   | 1.8 |   | 4.1 |
| Restructuring charges                                            |   |                   |   |   |   | – |   | .7 |
| Net (gain) on sale of assets and other charges                   |   |                   |   |   |   | (.1) |   | (1.5) |
| Total operating expenses                                         |   |                   |   |   |   | 11.7 |   | 32.0 |
| Other income (expense)                                           |   |                   |   |   |   | .1 |   | (.3) |
| EBITDA                                                           |   |                   |   |   |   | 8.8 |   | 44.2 |
| Depreciation and amortization expense                            |   |                   |   |   |   | – |   | .6 |
| Interest expense                                                 |   |                   |   |   |   | 4.1 |   | 16.9 |
| Income before income taxes                                       |   |                   |   |   |   | 4.7 |   | 26.7 |
| Income tax expense                                               |   |                   |   |   |   | 1.8 |   | 10.2 |
| Earnings from discontinued operations, net of tax                |   |                   |   |   | $ | 2.9 | $ | 16.5 |
|                                                             |   |                   |   |   |   |   |   |   |
| Electric sales and transportation   volumes (GWh) |   |                   |   |   |   | 549.6 |   | 501.0 |
| Electric customers at end of period                              |   |                   |   |   |   | 69,193 |   | 69,001 |
| Gas sales and transportation   volumes (Bcf)      |   |                   |   |   |   | – |   | 37.3 |
| Gas customers at end of period                                   |   |                   |   |   |   | – |   | 416,587 |

 

 

41

***Quarter-to-Quarter***

 

*Sales, Cost of Sales and Gross Profit*

 

Electric Utilities

 

Sales and cost of sales for our Kansas electric utility increased $3.6 million and $4.0 million, respectively, resulting in a gross profit decrease of $.4 million in 2007 compared to 2006.  The decrease in gross profit is primarily due to lower sale for resale margins. 

 

Gas Utilities

 

Sales and cost of sales for our Michigan, Minnesota, and Missouri gas utilities decreased $257.1 million and $209.6 million, respectively, resulting in a gross profit decrease of $47.5 million due to the closing of the sales of these operations in 2006.  

 

Corporate and Other

 

Sales, cost of sales and gross profit decreased $12.4 million, $4.0 million, and $8.4 million, respectively, in 2007 compared to 2006 due to the sale of our Everest Connections subsidiary in June 2006.

 

*Operation and Maintenance Expense*

 

Operation and maintenance expense decreased $18.7 million in 2007 compared to 2006 primarily as a result of the sale of our former Michigan, Missouri, and Minnesota gas operations and our Everest Connections subsidiary in 2006.

 

*Interest Expense*

 

Interest expense decreased $12.8 million in 2007 compared to 2006 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*

 

Income tax expense decreased $8.4 million in 2007 compared to 2006.  The effective income tax rate for 2007 was 38.3% compared to 38.2% for 2006.

 

**Significant Balance Sheet Movements**

 

Total assets decreased by $109.2 million since December 31, 2006. This decrease is primarily due to the following:

 

|   | **•** | Cash decreased $29.9 million. See our Consolidated Statement of Cash Flows for analysis of this decrease. |
|--------|------------|-----------------------------------------------------------------------------------------------------------|

 

|   | **•** | Funds on deposit decreased $39.2 million, primarily due to the return of margin deposits associated with the seasonal decrease in gas purchases by our regulated utilities. |
|--------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Price risk management assets increased $16.1 million, primarily due to the expiration of unfavorable gas forward contracts and options in the quarter at the end of the winter heating season and increases in forward gas prices on remaining positions. |
|--------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Utility plant, net increased $16.8 million, primarily due to additional capital expenditures, including the construction of Iatan 2. |
|--------|------------|--------------------------------------------------------------------------------------------------------------------------------------|

 

42

 

|   | **•** | Regulatory assets, current decreased $28.1 million due to lower purchased gas cost adjustment clause assets at the end of the winter heating season. |
|--------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------|

 

Total liabilities decreased by $106.3 million and common shareholders’ equity decreased by $2.9 million since December 31, 2006. These changes are primarily attributable to the following:

 

|   | **•** | Accounts payable decreased by $64.1 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 delivered due to our exit from wholesale energy trading. |
|--------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Price risk management liabilities decreased $9.1 million, primarily due to the expiration of unfavorable gas forward contracts and options in the quarter at the end of the winter heating season offset in part by increases in forward gas prices on remaining positions. |
|--------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Accrued interest decreased $16.3 million primarily due to the timing of periodic interest payments. |
|--------|------------|-----------------------------------------------------------------------------------------------------|

 

|   | **•** | Long-term debt including current maturities of long-term debt, decreased $16.0 million primarily due to the scheduled retirement of senior notes and other debt. |
|--------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Deferred income taxes and credits decreased $19.3 million due to the implementation of FIN 48 as discussed in Note 10 to the Consolidated Financial Statements. |
|--------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Common shareholders equity decreased $2.9 million primarily due to the net loss for the three months ended March 31, 2007 offset by the $19.3 million cumulative effect of adopting FIN 48 on January 1, 2007. |
|--------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

**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 merge with a subsidiary of Great Plains Energy and, if completed, we will become a wholly-owned subsidiary of Great Plains Energy and our shareholders will receive a combination of 0.0856 shares of Great Plains Energy common stock and $1.80 in cash upon the effectiveness of the Merger.  Some important factors that could cause actual results to differ materially from those anticipated include: |
|--------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | § | We or Great Plains Energy may not receive in a timely manner the shareholder, regulatory and third-party approvals required to complete the Merger.  Even if we and Great Plains Energy obtain the regulatory and third-party approvals required to complete the Merger, the approvals may contain unacceptable terms or conditions that would permit us or Great Plains Energy to terminate the Merger. |
|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | § | We may not complete the sale of our Colorado electric utility assets and Colorado, Iowa, Kansas and Nebraska gas utility assets to Black Hills, which must occur prior to the completion of the Merger. |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | § | The occurrence of certain events outside of our control may permit Great Plains Energy to terminate the Merger, to the extent the events result in a material adverse effect on our Missouri electric operations. |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

43

|   | **•** | 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. |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | § | Significant increases in forecasted capital expenditures may result in the retirement of less debt than would otherwise be possible and, therefore, we may not be able to reduce our interest expense in a manner that improves our credit sufficiently. |
|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | 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: |
|--------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | § | Although we have requested the implementation of a fuel adjustment clause in our current rate case, 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 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. |
|--------|--------|-----------------------------------------------------------------------------------------------------------------|

 

44

**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 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 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 usecomparable 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 2007 are summarized below:

 

| *In millions***                        | **Utilities** | **Merchant Services** | **Total** |
|----------------------------------------|---------------|-----------------------|-----------|
|                                   |          |                  |      |   |   |   |
| Fair value at December 31, 2006        | $             | (19.1)                | $         | 32.2 | $ | 13.1 |
| Change in fair value during the period |          | 13.6                  |      | (1.3) |   | 12.3 |
| Contracts realized or cash settled     |          | 16.3                  |      | (3.4) |   | 12.9 |
| Fair value at March 31, 2007           | $             | 10.8                  | $         | 27.5 | $ | 38.3 |

 

The fair value of contracts maturing in the remainder of 2007, each of the next three years and thereafter are shown below:

 

| *In millions***  | **Utilities** | **Merchant Services** | **Total** |
|------------------|---------------|-----------------------|-----------|
|             |          |                  |      |   |   |   |
| 2007             | $             | 2.6                   | $         | 14.0 | $ | 16.6 |
| 2008             |          | 5.5                   |      | 5.3 |   | 10.8 |
| 2009             |          | 2.7                   |      | 1.0 |   | 3.7 |
| 2010             |          | –                |      | 1.1 |   | 1.1 |
| Thereafter       |          | –                |      | 6.1 |   | 6.1 |
| Total fair value | $             | 10.8                  | $         | 27.5 | $ | 38.3 |

 

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.

 

45

**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 period covered by this report that has materiallyaffected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

**Part** **II – Other Information**

 

**Item 1.  Legal Proceedings**

 

Information on our legal proceedings is set forth in Note 8 to the Consolidated Financial Statements, which is incorporated herein by reference.

 

**Item 1A.  Risk Factors**

 

***Our strategic repositioning plan depends on our ability to retire a sufficient amount of debt and other long-term liabilities with the net proceeds from the sale of our Kansas electric operations.***

 

In April 2007, we sold our Kansas electric utility operations for a base purchase price of $249.7 million.  We anticipate using the net sale proceeds to retire debt and other obligations, and to fund capital expenditures, including rate-base investments required to satisfy our long-term power generation and transmission needs and comply with environmental rules and regulation.  If we are not able to retire a principal amount of debt sufficient to reduce our interest expense to a level that can be satisfied by the cash flow generated by our remaining utility operations, we will continue to have a cash flow shortfall.  We may also need to explore alternatives with respect to financing the significant capital expenditures anticipated in connection with environmental upgrades and compliance, as well as capital expenditures generally required to continue to provide safe and reliable service toour remaining utility customers. 

 

46

**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**                                                                                                                                                                                                                                                                                  |
|-----------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2.1*            | Agreement and Plan of Merger among the Company, Great Plains Energy Incorporated, Gregory Acquisition Corp. and Black Hills Corporation, dated as of February 6, 2007 (Exhibit 2.1 to the Company’s Current Report on Form 8-K filed February 7, 2007).                                     |
| 10.1*           | Agreement, by and between Aquila, Inc. and Keith G. Stamm, dated March 16, 2007 (Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 21, 2007).                                                                                                                         |
| 10.2*           | Asset Purchase Agreement by and among the Company, Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.1 to the Company’s Current Report on Form 8-K filed February 7, 2007).                                       |
| 10.3*           | Partnership Interests Purchase Agreement by and among the Company, Aquila Colorado, LLC, Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.2 to the Company’s Current Report on Form 8-K filed February 7, 2007). |
| 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.                                                                                                                                                                                                                                     |

 

**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

*Senior Vice President and Chief Accounting Officer* |   |
|--------|-------------------------------------------------------------------------------------------------|--------|
|   | Signing on behalf of the registrant and as principal financial officer                          |   |
|   |                                                                                            |   |
| Date:  | May 7, 2007                                                                                     |   |
|   |                                                                                            |   |

 

 

 

47