Exhibit 99.2

Aquila, Inc.

Consolidated Statements of Income—Unaudited

	Three Months Ended
	March 31,
In millions	2008			2007
Sales:
Electricity—regulated	$	148.4		$	127.9
Other		(1.1	)		(3.4	)
Total sales		147.3			124.5
Cost of sales:
Electricity—regulated		77.0			86.1
Other		–			–
Total cost of sales		77.0			86.1
Gross profit		70.3			38.4
Operating expenses:
Operation and maintenance expense		56.9			59.9
Taxes other than income taxes		4.3			5.8
Restructuring charges		–			1.6
Depreciation and amortization expense		18.4			17.1
Total operating expenses		79.6			84.4
Operating loss		(9.3	)		(46.0	)
Other income (expense), net		3.5			6.2
Interest expense		24.2			26.5
Loss from continuing operations before income taxes		(30.0	)		(66.3	)
Income tax expense (benefit)		(17.5	)		(23.8	)
Loss from continuing operations		(12.5	)		(42.5	)
Earnings from discontinued operations, net of tax		21.0			18.2
Net income (loss)	$	8.5		$	(24.3	)

See accompanying notes to consolidated financial statements.

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Aquila, Inc.

Consolidated Balance Sheets—Unaudited

	March 31,		December 31,
In millions	2008		2007
Assets
Current assets:
Cash and cash equivalents	$	28.2	$	34.4
Funds on deposit		33.9		41.3
Accounts receivable, net		121.7		136.8
Inventories and supplies		67.3		62.3
Price risk management assets		44.4		32.0
Regulatory assets, current		24.9		25.5
Other current assets		8.2		9.7
Current Assets of discontinued operations		166.8		213.6
Total current assets		495.4		555.6
Utility plant, net		1,551.1		1,484.3
Non-utility plant, net		127.0		119.5
Price risk management assets		16.4		13.1
Goodwill, net		111.0		111.0
Pension asset		26.3		26.0
Regulatory assets		81.7		84.6
Deferred charges and other assets		39.1		39.3
Non-current assets of discontinued operations		575.1		583.1
Total Assets	$	3,023.1	$	3,016.5
Liabilities and Shareholders’ Equity
Current liabilities:
Current maturities of long-term debt	$	2.4	$	2.4
Short-term debt		100.0		25.0
Accounts payable		63.6		85.5
Accrued interest		30.9		45.8
Accrued compensation and benefits		9.9		21.7
Pension and post-retirement benefits, current		1.6		1.6
Other accrued liabilities		65.7		46.8
Price risk management liabilities		30.6		28.7
Customer funds on deposit		10.7		14.0
Current liabilities of discontinued operations		90.7		150.0
Total current liabilities		406.1		421.5
Long-term liabilities:
Long-term debt, net		1,034.1		1,035.4
Deferred income taxes and credits		–		–
Price risk management liabilities		.6		.5
Pension and post-retirement benefits		25.7		25.4
Regulatory liabilities		87.4		75.4
Deferred credits		41.5		41.7
Non-current liabilities of discontinued operations		61.8		60.9
Total long-term liabilities		1,251.1		1,239.3
Common shareholders’ equity		1,365.9		1,355.7
Total Liabilities and Shareholders’ Equity	$	3,023.1	$	3,016.5

See accompanying notes to consolidated financial statements.

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Aquila, Inc.

Consolidated Statements of Comprehensive Income—Unaudited

	Three Months Ended
	March 31,
In millions	2008			2007
Net income (loss)	$	8.5		$	(24.3	)
Other comprehensive income (loss), net of related tax:
Foreign currency adjustments:
Reclassification of foreign currency (gains) losses to income, net of deferred tax (expense) benefit of $– million for the three months ended March 31, 2008		(.1	)		–
Total foreign currency adjustments		(.1	)		–
Pension and post-retirement benefits costs amortized to income:
Prior service cost, net of deferred tax expense (benefit) of $– million after valuation allowance and $.2 million for the three months ended March 31, 2008 and 2007, respectively		.6			.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 $– million after valuation allowance and $.5 million for the three months ended March 31, 2008 and 2007, respectively		1.0			.9
Total pension and post-retirement benefit costs		1.6			1.4
Other comprehensive income		1.5			1.4
Total Comprehensive Income (Loss)	$	10.0		$	(22.9	)

See accompanying notes to consolidated financial statements.

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Aquila, Inc.

Consolidated Statements of Cash Flows—Unaudited

	Three Months Ended
	March 31,
In millions	2008			2007
Cash Flows From Operating Activities:
Net income (loss)	$	8.5		$	(24.3	)
Adjustments to reconcile net income (loss) to net cash provided from   operating activities:
Depreciation and amortization expense		29.1			27.2
Net changes in price risk management assets and liabilities		(17.9	)		(25.2	)
Changes in certain assets and liabilities, net of effects of divestitures:
Funds on deposit		7.4			39.3
Accounts receivable/payable, net		(44.8	)		(48.7	)
Inventories and supplies		23.9			18.9
Other current assets		24.3			32.6
Deferred charges and other assets		9.2			16.1
Accrued interest and other accrued liabilities		(31.3	)		(26.0	)
Customer funds on deposit		(3.1	)		1.0
Deferred credits		11.7			5.8
Other		1.3			2.1
Cash provided from operating activities		18.3			18.8
Cash Flows From Investing Activities:
Utilities capital expenditures		(94.6	)		(56.0	)
Cash proceeds received on sale of assets		–			22.3
Other		(2.4	)		4.6
Cash used for investing activities		(97.0	)		(29.1	)
Cash Flows From Financing Activities:
Retirement of long-term debt		(1.3	)		(15.9	)
Short-term debt borrowings, net		75.0			–
Cash paid on long-term gas contracts		(1.4	)		(4.3	)
Other		.2			.6
Cash provided from (used for) financing activities		72.5			(19.6	)
Decrease in cash and cash equivalents		(6.2	)		(29.9	)
Cash and cash equivalents at beginning of period		34.4			232.8
Cash and cash equivalents at end of period	$	28.2		$	202.9

See accompanying notes to consolidated financial statements.

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AQUILA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1: Merger and Asset Sale

On February 6, 2007, Aquila, Inc. (Aquila) 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 provided for the merger of Gregory Acquisition Corp. into us, with Aquila continuing as the surviving corporation.  As of July 14, 2008, all required approvals had been received.  Upon completion of the Merger, we became a wholly-owned subsidiary of Great Plains Energy, and our shareholders received cash and shares of Great Plains Energy common stock in exchange for their shares of Aquila common stock.  As of July 14, 2008, each share of Aquila common stock converted 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 was fixed and was not adjusted to reflect stock price changes prior to the completion of the Merger.  Upon consummation of the Merger, our shareholders owned approximately 27% of the outstanding common stock of Great Plains Energy, and the Great Plains Energy shareholders owned approximately 73% of the outstanding common stock of Great Plains Energy.

On July 14, 2008, subsequent to the merger a dividend of approximately $675 million was declared and paid to Great Plains Energy.

In connection with the Merger, we also entered into agreements with Black Hills under which we sold 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, in a transaction that also closed on July 14, 2008.  The agreements contained 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.  The employees of these utility operations were transferred to Black Hills upon completion of the sale.

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

We 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 was met upon closing of the transactions.  As a result, we have reclassified the assets to be acquired by Black Hills as “held for sale” and reported those results as discontinued operations herein.

We incurred significant costs in connection with the merger and related asset sale, primarily consisting of investment banking, legal, employee retention, and other severance costs which we expensed as they were 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.  In connection with the closing of the transactions we paid an additional $14.2 million of fees in 2008 including $11.9 million to investment advisors.  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.  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.

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Note 2.  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.

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

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.  The adoption of SFAS 157 did not have a material impact on our financial condition or results of operations.  See Note 11 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.

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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.

Note 3.  Restructuring Charges

We recorded the following restructuring charges:

	Three Months Ended
	March 31,
In millions	2008		2007
Corporate and Other severance costs	$	–	$	1.6
Total restructuring charges	$	–	$	1.6

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.

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Restructuring Reserve Activity

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

In millions
Severance Costs:
Accrued severance costs as of December 31, 2007	$	1.1
Additional expense during the period		–
Cash payments during the period		(.1	)
Accrued severance costs as of March 31, 2008	$	1.0

In connection with the closing of the merger with Great Plains Energy and sale of certain operations to Black Hills, approximately 200 employees were severed or agreed to transitional employment agreements.  As a result, approximately $23.8 million of severance-related costs were paid or accrued.  In accordance with the sale agreements, Black Hills will reimburse approximately $8.6 million of these costs.

Note 4.  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.

On July 14, 2008, we closed the sale of our Colorado electric operations and Colorado, Iowa, Kansas and Nebraska gas operations to Black Hills and received gross cash proceeds of $908.8 million, subject to true-up within 120 days after close.  We expect the sale to result in a pretax and after-tax gain of approximately $315.0 million.  This amount will be adjusted for final working capital and capital expenditure adjustments determined through July 14, 2008.

The operating results of the utility divisions sold or held for sale include the direct operating costs associated with those businesses but do not include 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,

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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.  With the exception of certain central services operations acquired by Black Hills, these allocated costs were not included in the reclassification to earnings from discontinued operations because these support services were necessary to maintain ongoing operations until the sales were completed.  The allocated operating expenses related to the utility divisions held for sale that were not assumed by Black Hills were as follows:

	Three Months Ended March 31,
In millions	2008		2007
Allocated expenses retained in continuing operations	$	9.8	$	9.8

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, 2008 and 2007 in the Consolidated Statements of Income as follows.

	Three Months Ended March 31,
In millions	2008			2007
Sales	$	335.8		$	363.1
Cost of sales		248.5			264.6
Gross profit		87.3			98.5
Operating expenses:
Operation and maintenance expense		30.5			41.1
Taxes other than income taxes		3.0			4.9
Net (gain) on sale of assets and other charges		–			(.1	)
Depreciation and amortization expense		10.7			10.1
Total operating expenses		44.2			56.0
Operating income		43.1			42.5
Other income		(.4	)		(.2	)
Interest expense		7.8			12.3
Income before income taxes		34.9			30.0
Income tax expense		13.9			11.8
Earnings from discontinued operations, net of tax	$	21.0		$	18.2

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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, 2008 and December 31, 2007 Consolidated Balance Sheets as follows:

	March 31,		December 31,
In millions	2008		2007
Current assets of discontinued operations:
Accounts receivable, net	$	122.1	$	119.3
Inventories and supplies		11.4		40.3
Regulatory assets, current		18.8		33.0
Other current assets		14.5		21.0
Total current assets of discontinued operations	$	166.8	$	213.6
Non-current assets of discontinued operations:
Utility plant, net	$	537.2	$	537.6
Regulatory assets		36.4		40.5
Other non-current assets		1.5		5.0
Total non-current assets of discontinued operations	$	575.1	$	583.1
Current liabilities of discontinued operations:
Accounts Payable	$	65.0	$	105.2
Regulatory liabilities, current		8.0		19.4
Other current liabilities		17.7		25.4
Total current liabilities of discontinued operations	$	90.7	$	150.0
Non-current liabilities of discontinued operations:
Pension and post-retirement benefits	$	44.9	$	43.9
Regulatory liabilities		5.1		5.0
Deferred credits		11.8		12.0
Total non-current liabilities of discontinued operations	$	61.8	$	60.9

Note 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.  In addition, the operating results of our Colorado electric and Colorado, Iowa, Kansas and Nebraska gas operations (sold to Black Hills on July 14, 2008) 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.

Our reportable segment reconciliation is shown below:

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	Three Months Ended
	March 31,
In millions	2008			2007
Sales: (a)
Electric Utilities	$	148.4		$	127.9
Merchant Services		(1.1	)		(3.4	)
Corporate and Other		–			–
Total sales	$	147.3		$	124.5
(a)For the three months ended March 31, 2008 and 2007, respectively, the following sales (in millions) were reclassified to discontinued operations and are not included in the above amounts: Electric Utilities of $51.0 and $85.5; and Gas Utilities of $284.8 and $277.6.
EBITDA: (a)
Utilities:
Electric Utilities	$	22.1		$	(1.2	)
Gas Utilities		(7.4	)		(7.0	)
Total Utilities		14.7			(8.2	)
Merchant Services		(1.8	)		(4.1	)
Corporate and Other		(.3	)		(10.4	)
Total EBITDA		12.6			(22.7	)
Depreciation and amortization expense		18.4			17.1
Interest expense		24.2			26.5
Loss from continuing operations before income taxes	$	(30.0	)	$	(66.3	)
(a)           For the three months ended March 31, 2008 and 2007, respectively, the following EBITDA (in millions) were reclassified to discontinued operations and are not included in the above amounts: Electric Utilities of $10.8 and $14.5; and Gas Utilities of $42.6 and $37.9.

Depreciation and Amortization: (a)
Utilities:
Electric Utilities	$	16.1		$	15.7
Gas Utilities		.1			.4
Total Utilities		16.2			16.1
Merchant Services		2.3			1.0
Corporate and Other		(.1	)		–
Total depreciation and amortization	$	18.4		$	17.1
(a)           For the three months ended March 31, 2008 and 2007, respectively, the following EBITDA (in millions) were reclassified to discontinued operations and are not included in the above amounts: Electric Utilities of $2.7 and $2.7; and Gas Utilities of $8.0 and $7.4.

In millions	March 31, 2008		December 31, 2007
Assets:
Utilities:
Electric Utilities	$	1,993.2	$	1,858.6
Gas Utilities		35.8		51.0
Total Utilities		2,029.0		1,909.6
Merchant Services		202.4		205.0
Corporate and Other		49.8		105.2
Total Continuing Operations		2,281.2		2,219.8
Discontinued Operations:
Electric Utilities		202.4		201.0
Gas Utilities		539.5		595.7
Total Discontinued Operations		741.9		796.7
Total assets	$	3,023.1	$	3,016.5

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Note 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.

Effective July 14, 2008, this facility was terminated.

$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%.

      We have entered into an amendment of the facility to permit the obligation to be transferred to Great Plains Energy upon the closing of the merger and to release the accounts receivable generated by our Colorado electric and Colorado, Iowa, Kansas and Nebraska gas operations.  In addition, the maximum borrowing limit was reduced from $150 million to $65 million.

$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

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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.

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:

(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 1.4 to 1.0 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 6.0 to 1.0 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 another arrangement as of March 31, 2008.

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Note 7.  Employee Benefits

The following table shows the components of net periodic benefit costs for total continuing and discontinued operations:

	Pension Benefits						Other Post-retirement Benefits
	Three Months Ended March 31,
In millions	2008			2007			2008			2007
Components of Net Periodic Benefit Cost:
Service cost	$	2.0		$	2.4		$	.3		$	.3
Interest cost		5.2			5.4			.8			.8
Expected return on plan assets		(6.3	)		(6.4	)		(.3	)		(.3	)
Amortization of transition amount		–			–			.2			.3
Amortization of prior service cost		1.1			1.2			.5			.5
Recognized net actuarial (gain)/loss		–			.8			–			(.1	)
Net periodic benefit cost before regulatory expense adjustments		2.0			3.4			1.5			1.5
Regulatory (gain)/loss adjustment		1.0			1.4			(.1	)		.1
SFAS 71 regulatory adjustment		.7			–			–			–
Net periodic benefit cost after regulatory expense adjustments		3.7			4.8			1.4			1.6
Effect of curtailments and settlements included in gain on sale of assets		–			–			–			–
Total periodic benefit costs	$	3.7		$	4.8		$	1.4		$	1.6

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

	Pension Benefits				Other Post-retirement Benefits
	Three Months Ended March 31, 2008
In millions	Regulatory Asset		Other Comprehensive Income		Regulatory Asset			Other Comprehensive Income
Components of Net Periodic Benefit Cost Amortized to Income:
Transition amount	$	–	$	–	$	.2		$	–
Prior service cost		.5		.6		.5			–
Regulatory (gain)/loss adjustment		–		1.0		(.1	)		–
Total pension and post-retirement benefit costs amortized	$	.5	$	1.6	$	.6		$	–

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 made an additional

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voluntary contribution of approximately $7.7 million to our defined benefit plan in July 2008 to maintain the funded status of our pension plan.

As disclosed in Note 3, certain former utility 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, 2008 and 2007, respectively, the net periodic pension benefit cost charged to discontinued operations was $1.2 million and $2.0 million.  In addition, for the three months ended March 31, 2008 and 2007, respectively, the net periodic other post-retirement benefits cost charged to discontinued operations was $.8 million and $1.0 million.

Note 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

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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 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 filed and Cass County is processing a land use application for the facilities.  This application is set for a hearing before the County’s Planning Board on July 22, 2008.  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.  In addition, on June 12, 2008, we entered into a final settlement agreement with the members of StopAquila.org, an unincorporated association of approximately 100 individuals who opposed the facilities.  This settlement agreement finally resolves our dispute with StopAquila.  In addition, we have entered into agreements in principal to settle six of seven pending private lawsuits filed by Cass County residents alleging that the facilities constitute a public and private nuisance.  We recorded reserves of $10.7 million for fines, legal fees, infrastructure investments and the potential resolution of various related claims in 2008, including $7.1 million in the first quarter of 2008.  The actual amount required to resolve the related claims may be different than the amounts recorded.  On June 16, 2008, Missouri Lt. Governor Peter Kinder (serving as acting Governor in Governor Blunt’s absence from the state) signed into law SB720, a bill that grants to the Missouri Commission the authority to retroactively approve the development and construction of our South Harper facilities.  The law will become effective August 28, 2008.

Note 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.

Effective on July 14, 2008, the Omnibus Incentive Compensation Plan was terminated and all outstanding, vested awards were converted to Great Plains Energy awards.

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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:

	Shares			Weighted Average Exercise Prices		Remaining Contractual Term in Years
Beginning balance		3,740,720		$	16.00		2.51
Granted		-			-
Exercised		(8,750	)		1.60
Forfeited		(358,037	)		22.89
Ending balance		3,373,933		$	15.30		2.50
Exercisable at March 31, 2008		3,373,933		$	15.30		2.50

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 total continuing and discontinued operations 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:

	Shares			Weighted Average Grant Date Fair Value		Remaining Contractual Term in Years
Beginning balance		258,982		$	15.17		1.18
Awarded		–			–
Released		(152,982	)		23.06
Forfeited		–			–
Ending balance		106,000		$	3.80		2.33

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

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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 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 total continuing and discontinued operations 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:

	Shares			Weighted Average Grant Date Fair Value		Remaining Contractual Term in Years
Beginning balance		288,000		$	4.16		.53
Awarded		144,000			4.16
Released		(246,000	)		4.44
Forfeited		–			–
Ending balance		186,000		$	3.80		.75

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:

	Shares			Weighted Average Grant Date Fair Value
Beginning balance		245,872		$	4.38
Awarded		13,125			3.21
Released		(40,499	)		4.76
Ending balance		218,498		$	4.24

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

Note 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

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to the IRS examination of our 2003-2004 tax years which is currently underway.  We do not have an estimate of any changes at this time.

Rollforward of Unrecognized Tax Benefits from Uncertain Tax Positions
In millions	Unrecognized Tax Benefits			Accrued Interest
Balance at December 31, 2007	$	205.2		$	9.5
Additions related to 2008 tax positions		–			–
Additions related to tax positions prior years		–			–
Reductions related to tax positions prior years		–			–
Settlements		(115.3	)		(9.5	)
Balance at March 31, 2008	$	89.9		$	–

Note 11.  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.

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

In millions	Utilities		Merchant Services		Total
Level 1	$	22.0	$	–	$	22.0
Level 2		–		2.1		2.1
Level 3		–		5.5		5.5
Total Fair Value	$	22.0	$	7.6	$	29.6

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:

In millions	Utilities		Merchant Services		Total
Balance at January 1, 2008	$	–	$	4.8	$	4.8
Gains or (losses) in earnings		–		.4		.4
Purchases, sales, issuances and settlements, net		–		.3		.3
Transfers in and/or out of Level 3		–		–		–
Balance at March 31, 2008	$	–	$	5.5	$	5.5

The total of unrealized gains or (losses) for the three months ended March 31, 2008, included in net sales for Merchant Services was $.4 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.

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