ILA Aquila

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________

 

FORM   10-Q

 

 

_______________________

 

AQUILA,   INC.

(Exact name of registrant as specified in its charter)

 

 

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, a non-accelerated filer or a smaller reporting company (see definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act).

 

 

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.

 

 

 

PART   I—FINANCIAL INFORMATION

 

ITEM   1. FINANCIAL STATEMENTS

 

Information regarding the consolidated financial statements is on pages 5 through 27.

 

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 27 through 40.

 

ITEM   3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

We are subject to market risk as described on pages 54 through 56 of our 2007 Annual Report on Form 10-K. See discussion on page 40 of this document for changes in market risk since December 31, 2007.

 

ITEM   4. CONTROLS AND PROCEDURES

 

Information regarding disclosure controls and procedures is on page 41.

 

PART   II—OTHER INFORMATION

 

ITEM   1. LEGAL PROCEEDINGS

 

Information regarding legal proceedings is on page 41.

 

ITEM 1A. RISK FACTORS

 

See pages 18 through 21 of our 2007 Annual Report on Form 10-K for a discussion of risk factors.

 

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

 

Not applicable.

 

ITEM   3. DEFAULTS UPON SENIOR SECURITIES

 

Not applicable.

 

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

 

Not applicable.

 

ITEM   5. OTHER INFORMATION

 

Not applicable.

 

ITEM   6. EXHIBITS

 

Exhibits are on page 42.

 

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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 304 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.

Fuel Adjustment Clause – a regulatory mechanism in Missouri that allows us to recover 95% of fuel costs in excess of those included in base rates.

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.

 

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NYMEX – New York Mercantile Exchange.

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

SAIFI – System Average Interruption Frequency Index.

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.

 

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Part   I. Financial Information

Item 1. Financial Statements

 

Aquila,   Inc.

Consolidated Statements of Income—Unaudited

 

See accompanying notes to consolidated financial statements.

 

5

Aquila,   Inc.

Consolidated Balance Sheets—Unaudited

 

See accompanying notes to consolidated financial statements.

 

6

Aquila,   Inc.

Consolidated Statements of Comprehensive Income—Unaudited

 

 

See accompanying notes to consolidated financial statements.

 

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Aquila, Inc.

Consolidated Statements of Common Shareholders' Equity—Unaudited

 

 

See accompanying notes to consolidated financial statements.

 

8

Aquila, Inc.

Consolidated Statements of Cash Flows—Unaudited

 

 

See accompanying notes to consolidated financial statements.

 

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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 2007 Annual Report on Form 10-K filed with the SEC on February 29, 2008. You should read our 2007 Form 10-K in conjunction with this report. The accompanying Consolidated Balance Sheets and Consolidated Statements of Common Shareholders’ Equity as of December 31, 2007, 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. Certain estimates and assumptions have been made in preparing the consolidated financial statements that affect reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of sales and expenses during the reporting periods shown. Actual results could differ from these estimates.

 

Certain prior period amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2008 presentation. During the fourth quarter of 2007 we identified immaterial changes in certain payable balances that had not been correctly presented in our prior period cash flow statements. Changes in payable balances representing capital expenditures had previously been classified with cash flows from operating activities and should have been classified with capital expenditures as part of investing activities. Accordingly, the Consolidated Statements of Cash Flows for all periods presented have been reclassified to conform to the current presentation. As a result of these reclassifications, cash provided by operating activities increased by $4.4 million from $14.4 million to $18.8 million for the three months ended March 31, 2007. This same adjustment also increased cash used for investing activities to $29.1 million from $24.7 million in 2007. The reclassifications did not impact operating income or net income, working capital, any earnings per share measures or net change in cash and cash equivalents as previously reported.

 

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.

 

 

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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. The adoption of SFAS 157 did not have a material impact on our financial condition or results of operations. See Note 12 for additional disclosures required by SFAS 157.

 

Offsetting of Amounts Related to Certain Contracts

 

In April 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation No. 39.” FSP FIN 39-1 replaces certain terms in FIN No. 39 with “derivative instruments” (as defined in SFAS No. 133) and permits the offsetting of fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007. The adoption of this FSP did not have a material impact on our financial condition or results of operations.

 

Noncontrolling Interests

 

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (SFAS 160). SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We do not expect SFAS 160 to have a material impact on our financial position or results of operations.

 

Business Combinations

 

In December 2007, the FASB issued SFAS No. 141R “Business Combinations” (SFAS 141R). SFAS 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. SFAS 141R also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for business combinations with acquisition dates in fiscal years beginning after December 15, 2008. As we have no business acquisitions pending, we do not expect SFAS 141R to have a material impact on our financial position or results of operations.

 

Disclosures about Derivative Instruments and Hedging Activities

 

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment to FASB Statement No. 133” (SFAS 161), effective for fiscal years beginning after November 15, 2008.  SFAS 161 requires an entity to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.  We are currently evaluating the disclosures required by SFAS 161.

 

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2. Restructuring Charges

 

We recorded the following restructuring charges:

 

 

Severance Costs

 

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 are being paid over a two-year period which began April 28, 2007.

 

Restructuring Reserve Activity

 

The following table summarizes activity in accrued restructuring charges for the three months ended March 31, 2008:

 

 

3. Discontinued Operations

 

As part of our ongoing effort to reduce debt and 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 tax gain on the sale of the Kansas electric properties will be adjusted when the final determination as to the amount of capital gain on the sale is made and as the 2007 income tax return is filed in 2008.

 

In March 2007, we paid $1.8 million to the buyer of the Michigan properties to settle a gas-in-storage issue and other matters.

 

On April 1, 2007, we closed the sale of our Kansas electric operations and received gross cash proceeds of $292.2 million, including the base purchase price of $249.7 million plus preliminary working capital and other adjustments of $42.5 million. In connection with this sale we recorded a pretax gain of approximately $1.8 million in 2007 after transaction fees and expenses, including an adjustment for the final determination of pension assets transferred to the buyer. The estimated after-tax gain was approximately $1.1 million, subject to the determination of the capital gain amount discussed above.

 

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Interest Allocation to Discontinued Operations

 

The buyers of the assets in discontinued operations did not assume any of our long-term debt. 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. As we completed each asset sale the allocation of interest to discontinued operations ceased, thereby increasing interest expense in continuing operations, without impacting total interest expense, until the sales proceeds were 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 in the Consolidated Statements of Income as follows.

 

 

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 income (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 income (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 loss from continuing operations in the three months ended March 31, 2007, the potential issuances of common stock for dilutive securities of 460,169 were considered anti-dilutive in that period and were therefore not included in the calculation of diluted earnings (loss) per share.

 

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5. Reportable Segment Reconciliation

 

We manage our business in three business segments: Electric Utilities, Gas Utilities and Merchant Services. Our Electric and Gas Utilities 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 includes the residual operations of Aquila Merchant Services, Inc. These operations primarily include remaining contracts from its former wholesale energy trading operations and our investment in the Crossroads plant, which is an investment of Aquila, Inc. and is not an asset of Aquila Merchant Services, Inc. All other operations are included in Corporate and Other, including the costs not allocated to our operating businesses.

 

Each segment is managed based on operating results, expressed as EBITDA. Generally, decisions on finance and taxes are made at the Corporate level.

 

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Our reportable segment reconciliation is shown below:

 

 

 

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6. Financings

 

Five-Year Unsecured Revolving Credit Facility

 

In September 2004, we completed a $110 million unsecured revolving credit facility that matures in September 2009 (the Five-Year Unsecured Revolving Credit Facility). There were no borrowings outstanding on this facility as of March 31, 2008. The Five-Year Unsecured Revolving Credit Facility bears interest at the Eurodollar Rate plus 5.50%, 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, 2008.

 

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, 2008, 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, 2008, $149.7 million of this capacity had been utilized for letters of credit issued to commodity suppliers, lessors and insurance companies for financial assurance purposes.

 

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 1.25% or prime plus .375% depending on the term of the advance, subject to reduction if our credit ratings improve. Borrowings must be repaid within 364 days unless we obtain the necessary regulatory approvals to incur long-term indebtedness under the facility. Among other restrictions, we are required under the AR Facility to maintain the same debt-to-total capital and EBITDA-to-interest expense ratios as those contained in the Five-Year Unsecured Revolving Credit Facility discussed above. The credit agreement also contains a $40 million “cross default” provision. We had borrowed $100.0 million under this facility as of March 31, 2008 at a rate of 5.12%.

 

$50 Million Revolving Credit and Letter of Credit Facility

 

In January 2006, we closed on a $50 million short-term letter of credit facility with a commercial lender that allows us to issue letters of credit under the facility. The credit agreement contains a $40 million “cross default” provision. The advance rate under this facility is 1.10%. There were $49.8 million of letters of credit outstanding under this facility as of March 31, 2008. These letters of credit have been issued to commodity suppliers, lessors and insurance companies for financial assurance purposes.

 

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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 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 the Eurodollar Rate plus 1.375%, subject to reduction if our credit rating improves. Obligations under the credit agreement are secured by the assets of our Missouri Public Service electric operations. There were no borrowings outstanding under this facility at March 31, 2008. Among other restrictions, the Iatan Facility contains the following financial covenants with which we were in compliance as of March 31, 2008:

 

 

 

 

 

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 another arrangement as of March 31, 2008.

 

 

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7. Employee Benefits

 

 

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

 

 

We previously disclosed in our financial statements for the year ended December 31, 2007, that we expected to contribute in 2008 $.8 million and $5.1 million to our defined benefit pension plans and other post-retirement benefit plan, respectively. 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.

 

To comply with a regulatory condition related to the closing of the sale of our Kansas electric operations, we contributed $3.4 million to our qualified defined benefit pension plan and $1.1 million to our other post-retirement benefit plan in April 2007. 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 $7.7 million to our defined benefit plan to maintain the funded status of our pension plan.

 

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

 

8. Legal

 

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our consolidated financial statements are adequate in light of the probable and estimable contingencies.  However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our consolidated financial statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31, 2008, cannot be reasonably determined.

 

Price Reporting Litigation

 

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 sufficient justification for refusing to exercise its remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the period prior to October 2, 2000, and imposing a remedy for any such violations. The court remanded the matter to FERC to determine whether tariff violations occurred and, if so, the appropriate remedy. In March 2008, the FERC issued an order declining to order refunds for the period prior to October 2, 2000. We expect that order to be appealed by other companies impacted by this decision. The ultimate outcome of this matter cannot be predicted.

 

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. Our motion to have the case dismissed is pending. 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.

 

South Harper Peaking Facility

 

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

 

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Western District of Missouri and, in June 2005, the appellate court affirmed the circuit court ruling. 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 in January 2006. In January 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 appealed, and on March 4, 2008, the Missouri Court of Appeals for the Western District of Missouri affirmed the district court’s decision. In March, the Missouri Commission and Aquila each requested that the Court of Appeals either rehear the case or transfer the case to the Missouri Supreme Court. On April 25, 2008, we entered into an agreement with Cass County pursuant to which we will file and Cass County will process a land use application for the facilities. The parties have also requested that the Court of Appeals stay a ruling on the rehearing and transfer request pending Cass County’s review of the land use application. We have recorded reserves of $7.1 million for fines, legal fees, infrastructure investments and the potential resolution of various related claims. The actual amount required to resolve the related claims may be different than the amounts recorded. We are also supporting legislation that would, in limited circumstances, authorize the Missouri Commission to approve utility facilities after they are constructed.

 

If we are not successful in resolving the pending disputes and are ultimately ordered to remove the plant and substation, we estimate the cost to dismantle these facilities to be up to $20 million.  We estimate the incremental cost of relocating and reconstructing the plant and substation on a site that is being developed to meet future generation needs to be approximately $75 million based on recent engineering studies.  Additional costs may be incurred to store the equipment before relocating it, and to secure replacement power until the plant and substation can be reconstructed.  We cannot reasonably estimate with certainty the total amount of these and other 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 ultimate costs incurred exceed the amount allowed for recovery in rates.

 

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 first from treasury shares, if available, and then from newly issued shares.

 

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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, the intrinsic value of options exercised and the tax benefit realized were immaterial for the three months ended March 31, 2008. Stock options as of March 31, 2008 and changes during the three months ended March 31, 2008 were as follows:

 

 

The aggregate intrinsic value of “in-the-money” outstanding and exercisable options was $.7 million as of March 31, 2008.

 

Time-Based Restricted Stock Awards

 

On July 31, 2007, 106,000 shares of restricted stock were awarded to members of our senior management. This award will vest in three years, and no restrictions on the sale of shares will apply thereafter. The time restriction on this award will lapse upon a change in control of the Company. The fair value of these stock awards is determined based on the number of shares granted and the quoted price of our stock on the date of the award. The compensation expense related to this award was $.1 million for the three months ended March 31, 2008. As of March 31, 2008, the total compensation cost not yet recognized was $.3 million. This compensation cost will be recognized over the remaining restriction period through July 31, 2010. The total fair value of restricted stock released for the three months ended March 31, 2008 was $.2 million. Non-vested, time-based restricted stock awards as of March 31, 2008 and changes during the three months ended March 31, 2008 were as follows:

 

 

The aggregate intrinsic value of outstanding time-based restricted stock was $.3 million as of March 31, 2008.

 

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 were met. Additional performance-based restricted stock awards were granted to senior management in the third quarter of 2007 and will vest on December 31, 2008. The performance measure for both awards was the ratio of 2007 adjusted EBITDA to 2007 average net utility plant investment. The threshold level of performance was a ratio of 10.0%, target at a ratio of 11.5%, and

 

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maximum at a ratio of 13.0%. Shares would be earned at the end of the performance period as follows: 50% of the target number of shares if the threshold was reached, 100% if the target level of performance was reached and 150% if the ratio was at or above the maximum, with the number of shares interpolated between these levels. No shares would be payable if the threshold was not reached. The awards to senior management were also subject to reduction or forfeiture if the Company failed to achieve one or more of four operating metrics.

 

On February 26, 2008, our directors verified that the Company’s non-GAAP 2007 Adjusted EBITDA was $265.0 million and the Company’s 2007 average net utility plant investment was $1.9 billion, yielding a 13.8% ratio and a 150% payout. To compute the Company’s 2007 Adjusted EBITDA, the Company’s actual 2007 EBITDA from continuing operations of $239.0 million was increased by excluding $26.0 million of merger-related costs and severance costs incurred last year. Our directors also verified that each of the four operating metrics applicable to the restricted shares granted to senior management had been achieved, resulting in 100% of these restricted shares being earned by senior management. As a result, an additional 144,000 restricted shares were issued under both awards of performance-based restricted shares.

 

The fair value of these stock awards was determined based on the number of shares granted and the average of the high and low quoted price of our stock on the date of the award. An estimated annual turnover rate of 8% was assumed to determine the compensation expense related to the 2006 award. No estimated turnover was assumed to determine the compensation expense in the 2007 award to members of senior management. The compensation expense related to these awards was $.4 million for the three months ended March 31, 2008. As of March 31, 2008, the estimated total compensation cost not yet recognized was $.4 million. This compensation cost will be recognized over the period through December 31, 2008. The total fair value of restricted stock released for the three months ended March 31, 2008 was $.3 million. Non-vested, performance-based restricted stock awards as of March 31, 2008 and changes during the three months ended March 31, 2008 were as follows:

 

        

 

The aggregate intrinsic value of outstanding performance-based restricted stock was $.6 million as of March 31, 2008.

 

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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 determined as the average of the high and low quoted price on that date. Director stock awards as of March 31, 2008 and changes during the three months ended March 31, 2008 were as follows:

 

 

The aggregate intrinsic value of outstanding director stock awards was $.7 million as of March 31, 2008.

 

10: Income Taxes

 

Income tax benefit in the first quarter of 2008 was $3.6 million. The effective tax rate was (74.0)%. The effective tax rate differed from the combined statutory rate primarily as a result of the recognition of $24.4 million of previously unrecognized tax benefits due to the settlement of an IRS examination discussed below. These tax benefits were partially offset by $15.6 million of valuation allowance provided against net deferred tax assets.

 

On October 9, 2007, we agreed to adjustments contained in IRS audit reports related to our 1998 to 2002 taxable years. In addition, the agreement stipulates consistent treatment during our 2003 and 2004 taxable years for certain issues related to our former businesses in Australia and Canada. On February 29, 2008, we received notice from the IRS indicating that the Joint Committee on Taxation had completed their review of the audits without objection. The audits resulted in the following adjustments: (i) we will receive tax refunds of $19.7 million, $4.9 million of which will be received after the 2003-2004 audit is complete; (ii) our federal net operating loss carryforwards decreased by $251.9 million; (iii) our capital loss carryforwards decreased by $53 million; (iv) our AMT credit decreased by $7.5 million; (v) our general business credit carryforward decreased by $5.7 million; and (vi) we will pay interest to the IRS of $6.2 million, $3.3 million of which is currently on deposit with the IRS. The impact of these adjustments, both positive and negative, was included in unrecognized tax benefits as of January 1, 2008.

 

The total amount of unrecognized income tax benefits at January 1, 2008 was $205.2 million, $169.2 million of which would have impacted the effective rate if recognized. We recognize accrued interest and penalties associated with uncertain tax positions as part of the tax provision. As of January 1, 2008, we had reserved $9.5 million of accrued interest, net of a $3.7 million tax benefit, associated with tax positions included in unrecognized tax benefits. At March 31, 2008, the amount of unrecognized income tax benefits decreased to $89.9 million. Of this amount, $88.3 million would impact the effective rate if recognized. We have no accrued interest and penalties associated with uncertain tax positions at March 31, 2008.

 

The $115.3 million decrease in unrecognized income tax benefits in the first quarter is due to our determination that tax positions related to the years 1998-2002 were effectively settled upon receipt of Joint Committee approval. It is possible that the amount of unrecognized tax benefits will change significantly within the next twelve months. This change could occur due to the IRS examination of

 

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our 2003-2004 tax years which is currently underway. We do not have an estimate of any changes 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, our shareholders 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, and to refrain from engaging in or otherwise limit certain transactions and activities during this interim period. Consummation of the Merger is subject to a number of conditions, including (i) approval of the Missouri Commission; (ii) the completion of the asset sale transactions described below; and (iii) 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 by February 6, 2008 (subject to extension until August 6, 2008 for receipt of regulatory approvals required to consummate the Merger and the asset sales). On January 31, 2008, Aquila, Great Plains Energy and Black Hills extended the initial termination date to May 1, 2008. On April 29, 2008, Aquila, Great Plains Energy and Black Hills further extended the termination date to August 6, 2008.

 

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 the absence of a material adverse effect on the utility businesses being sold to Black Hills and 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.

 

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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.

 

In April 2007, we and Great Plains Energy filed joint applications with the Missouri Commission and the Kansas Commission requesting approval of the Merger, and 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. In May 2007, the parties filed a joint application with the FERC requesting approval of the Merger and the sale of our Colorado electric assets to Black Hills, which we amended in June 2007. In July 2007, the parties filed the antitrust notifications required under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) to complete the Merger and the asset sales to Black Hills.

 

On August 27, 2007, the Federal Trade Commission granted early termination of the statutory waiting period under the HSR Act for both the Merger and the asset sales to Black Hills. On August 31, 2007, the sale of our Iowa gas utility operation to Black Hills was approved by the IUB. On October 9, 2007, the merger agreement was adopted by Aquila’s shareholders. On October 10, 2007, the issuance of common stock by Great Plains Energy in connection with the Merger was approved by Great Plains Energy’s shareholders. On October 16, 2007, the Nebraska Commission approved the sale of our Nebraska gas operations to Black Hills. On October 19, 2007, the FERC approved the Merger and the sale of our Colorado electric operations to Black Hills.

 

On February 14, 2008, the Colorado Commission approved the sale of our Colorado electric and gas operations to Black Hills. On March 7, 2008, the Kansas Commission approved (i) an agreement filed with the Commission on January 31, 2008, under which Black Hills and the other interested parties settled all of the issues relating to the sale of our Kansas gas operations to Black Hills, and (ii) an agreement filed with the Commission on February 27, 2008, under which Great Plains Energy and the other interested parties settled all of the issues relating to the Merger.

 

Regulatory hearings in Missouri began on December 3, 2007, and the hearings were suspended on December 6, 2007, when Great Plains Energy announced its intention to submit a revised regulatory plan in connection with the Merger. On February 20, 2008, we and Great Plains Energy proposed a procedural schedule that would resume hearings in late April. On February 25, 2008, Great Plains Energy filed additional testimony with the Missouri Commission regarding its revised regulatory plan. Hearings resumed on April 21, 2008, and were concluded on May 1, 2008. We expect the Missouri Commission to issue an order approving the Merger or denying its approval in June or July 2008.

 

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; and, the fact the asset sale will only occur upon 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, and other severance costs which we will expense as they are incurred. We incurred approximately $.3 million and $7.3 million of costs (primarily investment banking and legal costs) relating to these transactions in the three months ended March 31, 2008 and 2007, respectively. These costs are included in operation and maintenance expense in Corporate and Other.

 

Beginning in February 2007, we executed retention agreements totaling $8.8 million with numerous non-executive employees to mitigate employee attrition prior to the closing of the Merger.

 

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Substantially all of the retention awards were paid on January 31, 2008. We accrued $.9 million and $1.2 million of expense related to these retention agreements in the three months ended March 31, 2008 and 2007, respectively. These costs are included in operation and maintenance expense in Corporate and Other.

 

12. Fair Value Measurements

 

Effective January 1, 2008, we adopted SFAS 157, which provides a framework for measuring fair value under GAAP.  SFAS 157 requires that the impact of this change in accounting for fair valued assets and liabilities be recorded as an adjustment to beginning retained earnings in the period of adoption.  We did not have any adjustments to beginning retained earnings in the period of adoption.

 

SFAS 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.  SFAS 157 also establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The standard describes three levels of inputs that may be used to measure fair value:

 

Level   1

 

Level 1 inputs are defined as quoted prices in active markets for identical assets or liabilities.  Our Level 1 assets and liabilities include forward natural gas contracts and options that are traded on NYMEX.

 

Level   2

 

Level 2 inputs are observable inputs other than Level 1 prices such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.  Our Level 2 assets and liabilities include physical natural gas delivery contracts, forward contracts and swaps with quoted prices primarily from direct broker quotes that are traded less frequently than exchange-traded instruments.

 

Level 3

 

Level 3 inputs are unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.  Our Level 3 assets and liabilities include long-term physical natural gas delivery contracts for which observable prices are not available throughout the term. We determine the fair value of these contracts by modeling or extrapolating observable prices over the full term of the contracts.

 

Following is a summary of our net price risk management assets and liabilities by category as of March 31, 2008:

 

 

 

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      Following is a reconciliation of fair value measurements using significant unobservable inputs (Level 3) from initial adoption on January 1, 2008 through March 31, 2008:

 

 

The total of unrealized gains or (losses) for the three months ended March 31, 2008, included in net sales for Merchant Services was $.3 million.

 

FSP SFAS 157-2 allows for a deferral from the SFAS 157 disclosures for non-financial assets or liabilities until fiscal years beginning after November 15, 2008.  We did not have any non-financial assets or liabilities accounted for on a fair value basis in the period ending March 31, 2008.

 

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

 

See Forward-Looking Information beginning on page 39.

 

Pending Merger

 

We have entered into a merger agreement with Great Plains Energy, which is discussed in Note 11 to the Consolidated Financial Statements.

 

Operating Strategy

 

We are focused on improving operational results of our integrated electric and gas utility operations and strengthening our credit profile in order to efficiently execute our utility growth strategy. 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.

 

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.

 

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Current Credit Ratings

 

As of March 31, 2008, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

 

 

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 working capital needs for our utility operations could increase up to $200 million over base requirements. 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.

 

 

 

Cash Flows

 

Cash Flows Provided From Operating Activities

 

Our positive three-month 2007 and 2008 operating cash flows were driven primarily by seasonal declines in working capital requirements for our utility operations.

 

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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 and completing the wind-down of our Merchant Services business.

 

Cash Flows Used For Investing Activities

 

The increase in cash used for investing activities was primarily the result of higher utility capital expenditures largely due to the construction of the Iatan 2 facility and environmental upgrades. In addition, we did not receive any cash proceeds from the sale of assets in the current period.

 

Cash Flows Provided From Financing Activities

 

The increase in cash provided from financing activities was primarily due to short-term borrowings and lower retirements of long-term debt obligations.

 

Collateral Positions

 

 

 

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.

 

Iatan 1 and 2 Projects

 

KCPL recently concluded a cost and schedule update for the Iatan 1 environmental upgrade and Iatan 2 construction projects.  KCPL provided updated estimates of the total capital expenditures, excluding AFUDC, associated with these two projects. The prior and most recent total cost estimates provided by KCPL follow:

 

 

We are an 18% owner of both Iatan projects. Based on the updated estimates provided by KCPL, we anticipate that our share, including AFUDC, of (i) the 2008–2009 capital expenditures required to complete the Iatan 1 environmental upgrades will increase from $46.4 million to $84.0 million and (ii) the 2008–2010 Iatan 2 construction costs will increase from $272.8 million to $313.8 million.  These increases from the budgeted capital expenditure amounts reported in our Annual Report on Form 10-K include the timing of costs planned for 2007 and the increased estimates provided by

 

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KCPL. KCPL also announced that the completion date of the Iatan 1 environmental upgrades will be delayed almost two months. 

 

Colorado Purchased Capacity

 

In 2007, we purchased 83% of our Colorado energy from a single provider under a long-term purchased power contract. This contract, under which we are entitled to purchase up to 300 MW of capacity, expires at the end of 2011 and will need to be replaced with other purchased capacity or the construction of additional generating capacity.

 

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 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 our former Kansas electric utility operations and our former Michigan, Minnesota and Missouri gas utility operations in discontinued operations in the Consolidated Statements of Income. 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.

 

 

 

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Key Factors Impacting Results of Continuing Operations

 

For the three months ended March 31, 2008, total EBITDA increased $45.1 million compared to 2007. Key factors affecting 2008 results were as follows:

 

 

 

 

Electric Utilities

 

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

 

 

 

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Quarter-to-Quarter

 

Sales, Cost of Sales and Gross Profit

 

Sales for the Electric Utilities business increased $27.7 million while cost of sales decreased $4.5 million, for a gross profit increase of $32.2 million in 2008 compared to 2007. These changes were primarily due to the following factors:

 

 

 

 

 

 

Operation and Maintenance Expense

 

Operation and maintenance expense increased $4.6 million in 2008 compared to 2007. The primary factor contributing to this increase was a $7.1 million provision related to the South Harper litigation, offset in part by a decrease in labor and benefit costs of $1.2 million and bad debt expense of $.5 million.

 

Other Income (Expense)

 

Other income decreased $.5 million due to the receipt in 2007 of 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. This decrease was offset in part by an increase in AFUDC related to the construction of Iatan 2 of $2.8 million.

 

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. We are making significant investments in our Missouri electric operations which will require us to file multiple rate cases between now and 2010. We expect the resulting rate increases will cause earnings generated by our Missouri electric operations to continue to improve.

 

 

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Gas Utilities

 

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

 

 

Quarter-to-Quarter

 

Sales, Cost of Sales and Gross Profit

 

Sales and cost of sales for the Gas Utilities business increased $9.1 million and $2.3 million, respectively, for a gross profit increase of $6.8 million in 2008 compared to 2007. These changes were primarily due to the following factors:

 

 

 

 

 

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Regulatory Matters

 

 

 

 

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; and (ii) 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. On April 12, 2007, the Missouri Commission approved the stipulation and agreement. We received a final order from the Missouri Commission, effective May 31, 2007. The final order increased base rates $58.8 million, or 11.9%, based on a return on equity of 10.25% and authorized a fuel adjustment recovery mechanism with a 95% sharing of costs with our customers. On March 1, 2008 we implemented the first rate changes to be approved under the Fuel Adjustment Clause. The new rates reflect an increase of $1.50 per MWh for St. Joseph Light & Power and $2.00 per MWh for Missouri Public Service to recover increased fuel costs from the rates included in base rates.

 

 

 

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Merchant Services

 

 

 

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, 2008 was $1.4 million, primarily due to the following factors:

 

 

 

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:

 

 

 

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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. We have assessed the realizability of our investment in the Crossroads 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. As of March 31, 2008, the carrying value of this plant was $118.4 million. As we continue to explore options to deliver the capacity and energy associated with the Crossroads plant to our Missouri utility operations, we acquired an option to purchase the Crossroads plant for a nominal purchase price. If cost effective for our Missouri customers, we intend to secure transmission rights necessary to deliver the Crossroads capacity and energy to our Missouri operations and add the Crossroads plant to our Missouri rate base. Additionally, we continue to wind down and terminate our remaining trading positions with various counterparties. However, it will take a number of years to complete the wind-down. 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.

 

Corporate and Other

 

 

 

Quarter-to-Quarter

 

Operation and Maintenance Expense

 

Operation and maintenance expense decreased $8.3 million due to lower advisor fees and other costs related to the pending merger.

 

Taxes Other Than Income Taxes

 

Taxes other than income taxes decreased $2.5 million primarily due to a provision for a non-recurring refund from an employment tax audit.

 

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Interest Expense and Income Tax Expense (Benefit)

 

 

 

Quarter-to-Quarter

 

Interest Expense

 

Interest expense decreased $2.7 million in 2008 compared to 2007 primarily due to $6.9 million of interest savings on debt retired in 2007. This decrease was partially offset by $4.1 million of decreased allocations of interest to discontinued operations due to the completion of the sale of our Kansas electric operations in 2007.

 

Income Tax Expense (Benefit)

 

Income tax benefit decreased $10.2 million in 2008 compared to 2007. An income tax benefit was recorded in 2008 for (74.0)% versus an income tax benefit of 33.5% in 2007. The effective tax rate for 2008 differed from the combined statutory rate primarily as a result of the recognition of $24.4 million in previously unrecognized tax benefits due to the settlement of an IRS examination of our 1998 – 2002 tax years, offset in part by $15.6 million of valuation allowance provided on net deferred tax assets.

 

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 and minor adjustments on the gas utilities sold in 2006 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.

 

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Quarter-to-Quarter

 

The decrease in EBITDA and earnings from discontinued operations is the result of the sale of our Kansas electric operations on April 2, 2007 and the settlement in March 2007 of a purchase price adjustment with the buyer of the Michigan gas properties.

 

Significant Balance Sheet Movements

 

Total assets increased by $5.8 million since December 31, 2007. This increase is primarily due to the following:

 

 

 

 

 

 

 

Total liabilities decreased by $4.4 million and common shareholders’ equity increased by $10.2 million since December 31, 2007. These changes are primarily attributable to the following:

 

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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:

 

 

 

 

 

 

 

 

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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 under SFAS 157, effective January 1, 2008. 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 use comparable transactions to obtain current values of our contracts. In addition, the market prices or fair values used in determining the value of the portfolio are our best estimates utilizing information such as historical volatility, time value, counterparty credit and the potential impact on market prices of liquidating our positions in an orderly manner over a reasonable period of time under current market conditions. When market prices are not readily available or determinable, certain contracts are recorded at fair value using an alternative approach such as model pricing.

 

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The changes in fair value of our derivative contracts for 2008 are summarized below:

 

 

The fair value of contracts maturing in the remainder of 2008, each of the next three years and thereafter are shown below:

 

 

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

 

Item 4. Controls and Procedures

 

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

 

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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.

 

 

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.

 

 

 

 

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