Empire District Electric (EDE) 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2009

or

o Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                    to                    .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Kansas	44-0236370
(State of Incorporation)	(I.R.S. Employer Identification No.)
602 S. Joplin Avenue, Joplin, Missouri	64801
(Address of principal executive offices)	(zip code)

Registrant’s telephone number: (417) 625-5100

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  o  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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

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

As of August 1, 2009, 34,492,377 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

		PAGE
	Forward Looking Statements	3
Part I -	Financial Information:
Item 1.	Financial Statements:
	a.     Consolidated Statements of Operations	4
	b.     Consolidated Statements of Comprehensive Income	7
	c.     Consolidated Balance Sheets	8
	d.     Consolidated Statements of Cash Flows	10
	e.     Notes to Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	Executive Summary	34
	Results of Operations	37
	Rate Matters	49
	Competition	51
	Liquidity and Capital Resources	53
	Contractual Obligations	56
	Dividends	56
	Off-Balance Sheet Arrangements	57
	Critical Accounting Policies	57
	Recently Issued Accounting Standards	58
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	60
Part II-	Other Information:
Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds - (none)
Item 3.	Defaults Upon Senior Securities - (none)
Item 4.	Submission of Matters to a Vote of Security Holders	64
Item 5.	Other Information	65
Item 6.	Exhibits	65
	Signatures	66

2

FORWARD LOOKING STATEMENTS

Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like “anticipate”, “believe”, “expect”, “project”, “objective” or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:

·the amount, terms and timing of rate relief we seek and related matters;

·the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs;

·volatility in the credit, equity and other financial markets and the resulting impact on our short term debt costs and our ability to issue debt or equity securities, or otherwise secure funds to meet our capital expenditure, dividend and liquidity needs;

·the results of prudency and similar reviews by regulators of costs we incur;

·weather, business and economic conditions and other factors which may impact sales volumes and customer growth;

·operation of our electric generation facilities and electric and gas transmission and distribution systems, including the performance of our joint owners;

·the costs and other impacts resulting from natural disasters, such as tornados and ice storms;

·the periodic revision of our construction and capital expenditure plans and cost and timing estimates;

·legislation;

·regulation, including environmental regulation (such as NOx, SO2 and CO2 regulation);

·competition, including the regional SPP energy imbalance market;

·electric utility restructuring, including ongoing federal activities and potential state activities;

·the impact of electric deregulation on off-system sales;

·changes in accounting requirements;

·other circumstances affecting anticipated rates, revenues and costs;

·the timing of accretion estimates, and integration costs relating to completed and contemplated acquisitions and the performance of acquired businesses;

·rate regulation, growth rates, discount rate, capital spending rate, terminal value calculations and other factors integral to the calculations utilized to test the impairment of goodwill, in addition to market and economic conditions which could adversely affect the analysis and ultimately negatively impact earnings;

·matters such as the effect of changes in credit ratings on the availability and our cost of funds;

·the performance of our pension assets and other post employment benefit plan assets and the resulting impact on our related funding commitments;

·interruptions or changes in our coal delivery, gas transportation or storage agreements or arrangements;

·the success of efforts to invest in and develop new opportunities;

·costs and effects of legal and administrative proceedings, settlements, investigations and claims; and

·our exposure to the credit risk of our hedging counterparties.

All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us.  Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

We caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual results, performance or achievements to differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements.

3

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended
	June 30
	2009			2008
	(000’s except per share amounts)
Operating revenues:
Electric	$	102,649		$	100,502
Gas	7,919			9,148
Water	434			441
Other	1,228			1,189
	112,230			111,280
Operating revenue deductions:
Fuel and purchased power	41,548			46,942
Cost of natural gas sold and transported	4,211			5,297
Regulated operating expenses	18,076			17,663
Other operating expenses	422			443
Maintenance and repairs	8,925			6,827
Depreciation and amortization	12,739			13,862
Provision for income taxes	4,028			1,972
Other taxes	6,254			5,948
	96,203			98,954
Operating income	16,027			12,326
Other income and (deductions):
Allowance for equity funds used during construction	1,229			1,497
Interest income	61			543
Provision for other income taxes	(19		)	(282		)
Other, net	(43		)	(224		)
	1,228			1,534
Interest charges:
Long-term debt	10,912			8,838
Note payable to securitization trust	1,062			1,062
Short-term debt	206			312
Allowance for borrowed funds used during construction	(2,106		)	(1,514		)
Other	(446		)	345
	9,628			9,043
Net income	$	7,627		$	4,817
Weighted average number of common shares outstanding - basic	34,194			33,775
Weighted average number of common shares outstanding - diluted	34,223			33,807
Total earnings per weighted average share of common stock – basic and diluted	$	0.22		$	0.14
Dividends per share of common stock	$	0.32		$	0.32

See accompanying Notes to Consolidated Financial Statements.

4

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Six Months Ended
	June 30,
	2009			2008
	(000’s except per share amounts)
Operating revenues:
Electric	$	209,011		$	208,806
Gas	36,006			36,424
Water	859			876
Other	2,369			2,119
	248,245			248,225
Operating revenue deductions:
Fuel and purchased power	88,338			103,884
Cost of natural gas sold and transported	23,519			22,998
Regulated operating expenses	35,577			35,561
Other operating expenses	831			826
Maintenance and repairs	16,592			12,393
Depreciation and amortization	25,412			27,483
Provision for income taxes	9,561			5,089
Other taxes	13,733			13,106
	213,563			221,340
Operating income	34,682			26,885
Other income and (deductions):
Allowance for equity funds used during construction	2,636			2,615
Interest income	137			623
Provision for other income taxes	(94		)	(270		)
Other, net	35			(462		)
	2,714			2,506
Interest charges:
Long-term debt	20,547			16,911
Note payable to securitization trust	2,125			2,125
Short-term debt	786			843
Allowance for borrowed funds used during construction	(4,303		)	(2,862		)
Other	(299		)	567
	18,856			17,584
Net income	$	18,540		$	11,807
Weighted average number of common shares outstanding - basic	34,129			33,717
Weighted average number of common shares outstanding - diluted	34,155			33,747
Total earnings per weighted average share of common stock – basic and diluted	$	0.54		$	0.35
Dividends per share of common stock	$	0.64		$	0.64

See accompanying Notes to Consolidated Financial Statements.

5

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Twelve Months Ended
	June 30,
	2009			2008
	(000’s except per share amounts)
Operating revenues:
Electric	$	446,671		$	439,525
Gas	65,020			60,273
Water	1,764			1,851
Other	4,727			3,837
	518,182			505,486
Operating revenue deductions:
Fuel and purchased power	188,511			207,782
Cost of natural gas sold and transported	43,151			37,180
Regulated operating expenses	71,934			71,354
Other operating expenses	1,895			1,601
Maintenance and repairs	32,748			27,439
Gain on sale of assets	—			(1,241		)
Depreciation and amortization	51,491			54,302
Provision for income taxes	23,600			15,074
Other taxes	26,043			25,580
	439,373			439,071
Operating income	78,809			66,415
Other income and (deductions):
Allowance for equity funds used during construction	5,950			3,979
Interest income	572			768
Benefit (provision) for other income taxes	178			(319		)
Other, net	(1,073		)	(946		)
	5,627			3,482
Interest charges:
Long-term debt	39,677			33,027
Note payable to securitization trust	4,250			4,250
Short-term debt	1,796			2,441
Allowance for borrowed funds used during construction	(8,029		)	(5,484		)
Other	287			1,058
	37,981			35,292
Income from continuing operations	46,455			34,605
Income from discontinued operations, net of tax	—			111
Net income	$	46,455		$	34,716
Weighted average number of common shares outstanding – basic	34,025			32,265
Weighted average number of common shares outstanding – diluted	34,067			32,294
Earnings from continuing operations per weighted average share of common stock– basic	$	1.37		$	1.07
Earnings from discontinued operations per weighted average share of common stock – basic	$	—		$	0.01
Total earnings per weighted average share of common stock – basic	$	1.37		$	1.08
Earnings from continuing operations per weighted average share of common stock– diluted	$	1.36		$	1.07
Earnings from discontinued operations per weighted average share of common stock – diluted	$	—		$	0.01
Total earnings per weighted average share of common stock – diluted	$	1.36		$	1.08
Dividends per share of common stock	$	1.28		$	1.28

See accompanying Notes to Consolidated Financial Statements.

6

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended
	June 30,
	2009			2008
	($-000’s)
Net income	$	7,627		$	4,817
Reclassification adjustments for (gain)/loss included in net income or reclassified to regulatory asset or liability	1,739			(1,713		)
Net change in fair market value of derivative contracts for period	1,866			22,806
Income taxes	(1,374		)	(8,036		)
Comprehensive income	$	9,858		$	17,874
	Six Months Ended
	June 30,
	2009			2008
	($-000’s)
Net income	$	18,540		$	11,807
Reclassification adjustments for (gain)/loss included in net income or reclassified to regulatory asset or liability	6,665			(2,573		)
Net change in fair market value of derivative contracts for period	(7,467		)	33,829
Income taxes	306			(11,909		)
Comprehensive income	$	18,044		$	31,154
	Twelve Months Ended
	June 30,
	2009			2008
	($-000’s)
Net income	$	46,455		$	34,716
Reclassification adjustments for (gain)/loss included in net income or reclassified to regulatory asset or liability	5,365			(4,130		)
Net change in fair market value of derivative contracts for period	(58,689		)	30,445
Income taxes	20,316			(10,026		)
Comprehensive income	$	13,447		$	51,005

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30, 2009		December 31, 2008
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	1,591,255	$	1,485,235
Natural gas	57,178		56,282
Water	10,818		10,560
Other	29,280		28,481
Construction work in progress	262,600		289,460
	1,951,131		1,870,018
Accumulated depreciation and amortization	545,334		527,245
	1,405,797		1,342,773
Current assets:
Cash and cash equivalents	3,391		2,754
Accounts receivable – trade, net	35,169		39,487
Accrued unbilled revenues	21,192		25,170
Accounts receivable – other	14,453		19,353
Fuel, materials and supplies	46,125		54,202
Unrealized gain in fair value of derivative contracts	1,924		2,395
Prepaid expenses and other	6,242		5,675
Regulatory assets	2,263		2,033
	130,759		151,069
Noncurrent assets and deferred charges:
Regulatory assets	156,941		162,026
Goodwill	39,492		39,492
Unamortized debt issuance costs	11,093		9,133
Unrealized gain in fair value of derivative contracts	5,282		6,434
Other	3,215		2,919
	216,023		220,004
Total Assets	$	1,752,579	$	1,713,846

(Continued)

See accompanying Notes to Consolidated Financial Statements.

8

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	June 30, 2009			December 31, 2008
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 34,267,124 and 33,981,579 shares issued and outstanding, respectively	$	34,267		$	33,982
Capital in excess of par value	486,955			483,443
Retained earnings	10,260			13,579
Accumulated other comprehensive loss, net of income tax	(2,628		)	(2,132		)
Total common stockholders’ equity	528,854			528,872
Long-term debt (net of current portion):
Note payable to securitization trust	50,000			50,000
Obligations under capital lease	223			174
First mortgage bonds and secured debt	339,045			312,953
Unsecured debt	248,243			248,440
Total long-term debt	637,511			611,567
Total long-term debt and common stockholders’ equity	1,166,365			1,140,439
Current liabilities:
Accounts payable and accrued liabilities	45,131			69,502
Current maturities of long-term debt	70,539			20,160
Short-term debt	72,000			102,000
Customer deposits	9,776			9,577
Interest accrued	6,255			5,921
Unrealized loss in fair value of derivative contracts	7,429			12,276
Taxes accrued	10,581			3,174
	221,711			222,610
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	71,643			66,585
Deferred income taxes	179,741			173,511
Unamortized investment tax credits	2,744			2,917
Pension and other postretirement benefit obligations	85,913			83,151
Unrealized loss in fair value of derivative contracts	3,846			3,302
Other	20,616			21,331
	364,503			350,797
Total Capitalization and Liabilities	$	1,752,579		$	1,713,846

See accompanying Notes to Consolidated Financial Statements.

9

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended
	June 30,
	2009			2008
	($-000’s)
Operating activities:
Net income	$	18,540		$	11,807
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization	29,903			29,471
Pension and other postretirement benefit costs	2,803			4,720
Deferred income taxes and unamortized investment tax credit, net	5,321			556
Allowance for equity funds used during construction	(2,636		)	(2,615		)
Stock compensation expense	1,398			1,543
Non-cash (gain)/loss on derivatives	6,034			(1,705		)
Gain on sale of assets	(504		)	—
Iatan deferred construction accounting costs	(615		)	—
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	6,714			11,751
Fuel, materials and supplies	8,077			442
Prepaid expenses, other current assets and deferred charges	(2,496		)	(1,588		)
Accounts payable and accrued liabilities	(21,462		)	4,134
Customer deposits, interest and taxes accrued	7,940			8,101
Other liabilities and other deferred credits	968			(496		)
Net cash provided by operating activities	59,985			66,121
Investing activities:
Capital expenditures – regulated	(83,613		)	(114,130		)
Capital expenditures and other investments – other	(876		)	(919		)
Proceeds from the sale of property, plant and equipment	544			807
Net cash used in investing activities	(83,945		)	(114,242		)
Financing activities:
Proceeds from first mortgage bonds - electric	75,000			89,950
Proceeds from notes payable	1,431			—
Long-term debt issuance costs	(2,396		)	(3,096		)
Proceeds from issuance of common stock net of issuance costs	2,589			3,366
Net short-term debt repayments	(30,000		)	(21,040		)
Dividends	(21,859		)	(21,586		)
Other	(168		)	(167		)
Net cash provided by financing activities	24,597			47,427
Net increase (decrease) in cash and cash equivalents	637			(694		)
Cash and cash equivalents at beginning of period	2,754			4,043
Cash and cash equivalents at end of period	$	3,391		$	3,349

See accompanying Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - - Summary of Significant Accounting Policies

We operate our businesses as three segments:  electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary which provides natural gas distribution to communities in northwest, north central and west central Missouri. Our other segment is held by our wholly-owned subsidiary, EDE Holdings, Inc. (EDE Holdings) and primarily consists of a 100% interest in Empire District Industries Inc., a subsidiary for our fiber optics business.

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008. Subsequent events were evaluated through August 6, 2009, the date these financial statements were issued.

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2008.

Note 2 - - Recently Issued and Proposed Accounting Standards

We adopted Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” (FAS 157) on January 1, 2008. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements. FASB Staff Position (FSP) 157-1, issued in February 2008, amended FAS 157 to exclude FASB Statement No. 13, “Accounting for Leases” (FAS 13) and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under FAS 13. The adoption of FAS 157 for financial assets and financial liabilities did not have a material impact on our consolidated financial position, results of operations and cash flows. FASB Staff Position (FSP) 157-2 amended FAS 157 to delay the effective date of FAS 157 for all nonfinancial assets and nonfinancial liabilities to fiscal years beginning after November 15, 2008. We adopted this portion of the standard on January 1, 2009. The adoption of FAS 157 for nonfinancial assets and nonfinancial liabilities did not have an effect on our consolidated financial position, results of operations or cash flows. (See Note 5).

In April 2008, the FASB issued SFAS No. 161 “Disclosure About Derivative Instruments and Hedging Activities, an Amendment of FASB Statement No. 133” (FAS 161). FAS 161 enhances the current disclosure framework in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” FAS 161 is effective for periods beginning after November 15, 2008. We adopted this statement on January 1, 2009. The adoption of FAS 161 did not have a material effect on our financial statement disclosures (See Note 4 below).

In May 2009, the FASB issued SFAS No. 165 “Subsequent Events” (FAS 165). This statement is effective for periods ending after June 15, 2009. FAS 165 requires the disclosure of the date through which an entity has evaluated subsequent events, and whether that date represents the date the financial statements were issued or were available to be issued. We adopted this statement upon its issuance by the FASB. The adoption of FAS 165 did not have a material effect on our financial statement disclosures. (See Note 1 above).

In December 2008, the FASB issued FSP SFAS No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FAS 132 (R)-1) which requires additional disclosures

11

related to pension and other postretirement benefit plan assets. FAS 132 (R)-1 will be effective as of December 31, 2009 and requires a separate disclosure of the fair value of each major category of plan assets of a defined benefit pension or postretirement plan. In addition, employers are required to disclose information enabling users to understand investment policies and strategies, assess the inputs and valuation techniques used to develop fair value measurements, and to disclose any significant concentrations of risks within plan assets. We do not expect the adoption of FAS 132(R)-1 to have a material effect on our results of operations, financial position or liquidity because it provides enhanced disclosure requirements only.

                In April 2009 the FASB issued FSP FAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability have Significantly Decreased and Identifying Transactions That Are Not Orderly” which provides additional guidance for estimating fair value in accordance with FAS 157, Fair Value Measurements, when the volume and level of activity for an asset or liability has decreased significantly. This staff position also provides guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 was effective as of June 30, 2009. The adoption of FSP FAS 157-4 did not have any effect on our results of operations, financial position or liquidity.

                In April 2009 the FASB issued FSP FAS 115-2 and FAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments” which changes the other-than-temporary impairment guidance in existing Generally Accepted Accounting Principles for debt securities. FSP FAS 115-2 and FAS 124-2 provide for improved presentation and disclosure of other-than-temporary impairments of debt securities in the financial statements. This staff position was effective as of June 30, 2009. The adoption of FSP FAS 115-2 and FAS 124-2 did not have a material effect on our result of operations, financial position or liquidity.

In April 2009, the FASB issued FSP FAS No. 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which amends FAS No. 107, “Disclosures about Fair Value of Financial Instruments,” and APB Opinion No. 28, “Interim Financial Reporting,” respectively. FSP FAS No. 107-1 and APB 28-1 require disclosures about fair value of financial instruments in interim financial statements, in addition to the annual financial statements as already required by FAS No.107. FSP FAS 107-1 and APB 28-1 is required for interim periods ending after June 15, 2009. As FSP FAS 107-1 and APB 28-1 provide only disclosure requirements, the application of this standard did not have a material impact on our results of operations, financial position or liquidity. (See Note 5).

                In June 2009, the FASB issued SFAS No. 166 “Accounting for Transfers of Financial Assets — an amendment of FASB Statement No. 140” (FAS 166). This statement is effective for annual periods beginning after November 15, 2009. FAS 166 removes qualifying special-purpose entities (QSPE) from generally accepted accounting principles. Additionally, the requirements for derecognizing financial assets have been changed, and additional disclosures about a transferor’s continuing involvement in transferred financial assets will be required. We do not expect the adoption of FAS 166 to have a material effect on our financial statements.

                In June 2009, the FASB issued SFAS No. 167 “Amendments to FASB interpretation No. 46(R)” (FAS 167). This statement is effective for annual periods beginning after November 15, 2009. FAS 167 amends FASB Interpretation No. 46(R) (FIN 46(R)) to require an entity to complete a qualitative analysis when determining who must consolidate a variable interest entity. Additionally, FAS 167 requires additional disclosures, and an ongoing reassessment of who must consolidate a variable interest entity. We are evaluating the impact of the adoption of this standard; however, we do not expect the adoption of this standard to have a material impact on our financial statements.

                In June 2009, the FASB issued SFAS No. 168 “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162” (FAS 168). This statement is effective for periods ending after September 15, 2009. FAS 168 identifies the sources of accounting principles, and establishes the FASB Accounting Standards Codification (Codification) as the only source of authoritative accounting principles recognized by the FASB. This statement is not intended to change generally accepted accounting principles. Accordingly we do not expect the adoption of FAS 168 to have a material effect on our financial statements.

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See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2008 for further information regarding recently issued accounting standards.

Note 3— Regulatory Matters

                On April 19, 2009, we began recording deferred carrying charges associated with environmental upgrades recently completed at our Iatan 1 facility in accordance with our regulatory plan. The effect of these deferred carrying charges is reflected in depreciation and in other interest on the statement of operations. Construction accounting, for purposes of the regulatory plan, is specific to Iatan 1 and Iatan 2 construction and allows us to defer certain charges as regulatory assets, including depreciation and carrying costs, related to operation of the facilities until the facilities are ultimately included in our rate base. The amounts deferred, which began at the in-service date for Iatan 1 and will also be deferred for Iatan 2 at its in-service date, will then be amortized over the life of the plants once they are in our rate base. The regulatory plan covers the 150 megawatt V84.3A2 combustion turbine (Unit 12) that began commercial operation on April 10, 2007 at our Riverton plant, the environmental upgrades at Asbury, which were completed in 2008, environmental upgrades at Iatan 1 and the construction of the Iatan 2 facilities.

                The following table sets forth the components of our regulatory assets and liabilities on our consolidated balance sheet (in thousands).

Regulatory Assets and Liabilities

	June 30, 2009		December 31, 2008
Regulatory Assets:
Unrecovered purchased gas costs — gas segment, current	$	336	$	1,791
Unrecovered electric fuel and purchased power costs — current(1)	1,927		242
Regulatory assets, current	$	2,263	$	2,033
Income taxes	35,671		34,515
Unamortized loss on reacquired debt	12,829		13,490
Unamortized loss on interest rate derivative	2,248		2,405
Asbury five-year maintenance	1,628		1,855
Pension and other postretirement benefits(2)	83,646		84,926
Storm costs(3)	13,538		14,704
Deferred Iatan construction accounting costs(4)	812		—
Asset retirement obligation	3,198		3,118
Unrecovered purchased gas costs — gas segment	—		3,787
Unsettled derivative losses — electric segment	1,080		1,218
Other	2,291		2,008
Regulatory assets, long-term	$	156,941	$	162,026
Total	$	159,204	$	164,059

	June 30, 2009		December 31, 2008
Regulatory Liabilities:
Income taxes	$	11,123	$	11,126
Unamortized gain on interest rate derivative	4,136		4,221
Costs of removal	48,102		43,713
Pension and other postretirement benefits(5)	6,135		7,042
Over recovered electric fuel and purchased power costs(6)	1,569		228
Other	578		255
Total	$	71,643	$	66,585

(1) Reflects under recovered costs for the accumulation period from September 2008 through February 2009 currently being recovered in Missouri rates.

(2) Primarily reflects regulatory assets resulting from the unfunded portion of our pension and OPEB liabilities and regulatory accounting for EDG acquisition costs. Approximately $0.3 million in pension and other postretirement benefit costs have been recognized since January 1, 2009 to reflect the amortization of the regulatory assets that were recorded at the time of the acquisition of the Aquila, Inc. gas properties.

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(3) Primarily reflects the amortization of ice storm costs but also includes deferred wind storm costs of $0.7 million incurred in May 2009. Consistent with recent rate case treatment, we expect to recover wind storm costs over a five year period commencing when rates go into effect.

(4) Includes $0.2 million of deferred depreciation costs and $0.6 million in carrying costs related to construction accounting for Iatan 1, which will be amortized over the life of the plant once it is included in rate base (see Note 1).

(5) Includes the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension costs and the Missouri EDE portion of other postretirement benefit costs. Since January 1, 2009, regulatory liabilities and corresponding expenses have been reduced by approximately $0.2 million as a result of ratemaking treatment.

(6) Primarily consists of Missouri over recovered fuel and purchased power costs for the current accumulation period March 2009 through August 2009.

There have been no changes to the rate base inclusions, expected recoverability or amortizable lives of our regulatory assets and liabilities since December 31, 2008, other than the Iatan construction accounting carrying costs and wind storm costs discussed above.

Note 4— Risk Management and Derivative Financial Instruments

                We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expense and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

                All derivative instruments are recognized at fair value on the balance sheet with gains and losses deferred in other comprehensive income (in stockholders’ equity) for effective instruments related to our electric segment, entered into prior to September 1, 2008. All other instruments are deferred as a regulatory asset or liability, due to our fuel recovery mechanism, effective September 1, 2008 for our electric segment, and for our gas segment.

                For instruments entered into prior to September 1, 2008, we record unrealized gains/(losses) on the ineffective portion of our gas hedging activities in “Fuel and purchased power” under the Operating Revenue Deductions section of our Statement of Operations since all of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities. Risks and uncertainties affecting the determination of fair value include:  market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Operations.

                As of June 30, 2009 and December 31, 2008, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		June 30,		December 31,
ASSET DERIVATIVES		2009		2008
Derivatives designated as hedging instruments under FAS 133	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, electric segment	Current assets	$	763	$	1,214
	Non-current assets and deferred charges	5,282		6,208

Derivatives not designated as hedging instruments under FAS 133 due to regulatory accounting
Natural gas contracts, gas segment	Current assets	1,161		1,177
	Non-current assets and deferred charges	—		226
Natural gas contracts, electric segment	Current assets	—		4
Total derivatives assets		$	7,206	$	8,829

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		June 30,		December 31,
LIABILITY DERIVATIVES		2009		2008
Derivatives designated as hedging instruments under FAS 133	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, electric segment	Current liabilities	$	4,666	$	6,254
	Non-current liabilities and deferred credits	3,846		3,282

Derivatives not designated as hedging instruments under FAS 133 due to regulatory accounting
Natural gas contracts, gas segment	Current liabilities	$	1,374	$	4,474
	Non-current liabilities and deferred credits	—		20
Natural gas contracts, electric segment	Current liabilities	1,389		1,548
Total derivatives liabilities		$	11,275	$	15,578

Electric

                A $(2.6) million net of tax, unrealized loss representing the fair market value of our electric segment derivative contracts treated as cash flow hedges is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of June 30, 2009. The tax effect of $1.6 million on this loss is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning July 1, 2009 and ending on September 30, 2011. At the end of each determination period, or if cash flow hedge treatment is discontinued, any realized gain or loss for that period related to the instrument will be reclassified to fuel expense. As of June 30, 2009, approximately $6.1 million of these unrealized losses are applicable to financial instruments which will settle within the next twelve months.

                Effective September 1, 2008, in conjunction with the implementation of the Missouri fuel adjustment clause in the July 2008 Missouri Public Service Commission (MPSC) rate order, the unrealized losses or gains from new cash flow hedges are recorded in regulatory assets or liabilities. This is in accordance with FAS 71, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism. Unrealized gains and losses from cash flow hedges existing at September 1, 2008 will continue to be recorded through comprehensive income. Once settled, the realized gain or loss will be recorded as fuel expense and be subject to the fuel adjustment clause.

                The following tables set forth the actual pre-tax gains/(losses) and the mark to market effect of unsettled positions from the qualified portion of our hedging activities for the electric segment for each of the periods ended June 30, (in thousands):

Derivatives in FAS 133 Cash Flow Hedging	Statement of Operations Classification of	Amount of Gain / (Loss) Reclassed from OCI into Income (Effective portion)
Relationships - Electric	Gain / (Loss) on	Three Months Ended					Six Months Ended					Twelve Months Ended
Segment	Derivative	2009			2008		2009			2008		2009			2008
Commodity contracts	Fuel and purchased power expense	$	(1,739	)	$	1,713	$	(6,665	)	$	2,573	$	(5,365	)	$	4,130
Total Effective — Electric Segment		$	(1,739	)	$	1,713	$	(6,665	)	$	2,573	$	(5,365	)	$	4,130

Derivatives in FAS 133 Cash Flow Hedging	Statement of	Amount of Gain / (Loss) Recognized in OCI on Derivative(Effective portion)
Relationships -	Comprehensive	Three Months Ended				Six Months Ended					Twelve Months Ended
Electric Segment	Income	2009		2008		2009			2008		2009			2008
Commodity contracts	Net change in fair market value of open derivative contracts	$	1,866	$	22,806	$	(7,467	)	$	33,829	$	(58,689	)	$	30,445
Total Effective — Electric Segment		$	1,866	$	22,806	$	(7,467	)	$	33,829	$	(58,689	)	$	30,445

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                The following table sets forth “mark-to-market” pre-tax gains/(losses) from the ineffective portion of our hedging activities for the electric segment for each of the periods ended June 30, (in thousands):

Derivatives in FAS 133 Cash Flow Hedging	Statement of Operations Classification of	Amount of Gain / (Loss) Recognized in Income on Derivative(Ineffective portion)
Relationships - Electric	Gain / (Loss) on	Three Months Ended				Six Months Ended					Twelve Months Ended
Segment	Derivative	2009		2008		2009		2008			2009			2008
Commodity contracts	Fuel and purchased power expense	$	—	$	1	$	—	$	(267	)	$	(2	)	$	14
Total Ineffective — Electric Segment		$	—	$	1	$	—	$	(267	)	$	(2	)	$	14

                The following tables set forth “mark-to-market” pre-tax gains/(losses) from derivatives not designated as hedging instruments under FAS 133 for the electric segment for each of the periods ended June 30, (in thousands):

Derivatives Not
Designated as Hedging
Instruments Under FAS	Balance Sheet
133 - Due to Regulatory	Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Accounting	Gain / (Loss) on	Three Months Ended					Six Months Ended					Twelve Months Ended
Electric  Segment(1)	Derivative	2009			2008		2009			2008		2009			2008
Commodity contracts	Regulatory (assets)/liabilities	$	(74	)	$	—	$	(543	)	$	—	$	(2,088	)	$	—
Total Electric Segment		$	(74	)	$	—	$	(543	)	$	—	$	(2,088	)	$	—

Derivatives Not Designated as Hedging Instruments Under FAS 133 - Due to Regulatory	Statement of Operations Classification of	Amount of Gain / (Loss) Recognized in Income on Derivative
Accounting	Gain / (Loss) on	Three Months Ended					Six Months Ended					Twelve Months Ended
Electric  Segment(1)	Derivative	2009			2008		2009			2008		2009			2008
Commodity contracts	Fuel and purchased power expense	$	(30	)	$	—	$	(678	)	$	—	$	(1,007	)	$	—
Total Electric Segment		$	(30	)	$	—	$	(678	)	$	—	$	(1,007	)	$	—

(1)  As all gas hedging activities are related to stabilizing fuel costs, if conditions change, such as a planned unit outage, we may need to unwind some of our previous derivatives accounted for under FAS 133.

                We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the fair value accounting of FAS 133 because they are considered to be normal purchases. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchases exception contain a price adjustment feature and will account for these contracts accordingly.

                As of July 24, 2009, 92% of our anticipated volume of natural gas usage for our electric operations for the remainder of 2009 is hedged, either through physical (1.7 million Dths) or financial contracts (2.6 million Dths), at an average price of $6.009 per Dekatherm (Dth). In addition, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for the next four years are hedged at the following average prices per Dth:

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Year	% Hedged		Dth Hedged	Average Price
2010(1)	81	%	7,225,000	$	6.317
2011(1)	60	%	5,115,000	$	5.840
2012	20	%	1,665,000	$	7.123
2013	12	%	1,200,000	$	7.295

(1) 3 million Dth and 2 million Dth of the anticipated volume of natural gas usage for 2010 and 2011, respectively, are hedged through financial derivative contracts.

                We utilize the following procurement guidelines for our electric segment:  current year up to 100% of expected gas usage, first year minimum of 60%, second year minimum of 40%, third year minimum of 20% and fourth year minimum of 10%, subject to a maximum of 80% of the expected gas usage in any one year.

On February 15, 2008, we unwound 992,000 Dth of physical gas contracts originally scheduled for delivery in July and August of 2010 and 2011. This transaction resulted in a gain of approximately $1.3 million after tax which was recorded as a reduction to fuel and purchased power expense in the Statement of Operations for the six and twelve months ended June 30, 2008. We believe it is probable that we will take physical delivery under the remaining physical gas forward contracts.

Gas

                We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of July 24, 2009, we had 1.2 million Dths in storage on the three pipelines that serve our customers. This represents 60% of our storage capacity. We have an additional 1.0 million Dths hedged through financial derivative and physical contracts. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of current year, up to 50% of second year and up to 20% of third year expected gas usage by the beginning of the Actual Cost Adjustment (ACA) year at September 1. A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

                The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments under FAS 133 for the gas segment for each of the periods ended June 30, (in thousands).

Derivatives Not Designated as Hedging Instruments Under	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
FAS 133 Due to Regulatory	Gain / (Loss) on	Three Months Ended					Six Months Ended						Twelve Months Ended
Accounting - Gas Segment	Derivative	2009		2008			2009			2008			2009			2008
Commodity contracts	Regulatory (assets)/liabilities	$	77	$	(395	)	$	(1,761	)	$	(71	)	$	(8,210	)	$	(1,262	)
Total - Gas Segment		$	77	$	(395	)	$	(1,761	)	$	(71	)	$	(8,210	)	$	(1,262	)

Contingent Features

Certain of our derivative instruments contain provisions that require our senior unsecured debt to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position on June 30, 2009 is $3.8 million

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for which we have posted no collateral in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2009, we would have been required to post $1.8 million of collateral with one of our counterparties. On June 30, 2009, we had no collateral posted with this counterparty.

Note 5— Fair Value Measurements

                FAS 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs provided by a third party that are derived principally from or corroborated by observable market data by correlation. Our Level 3 fair value measurements consist of both quoted price inputs and unobservable quoted inputs provided by a third party.

                FAS 157 also requires that the fair value measurement of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.

                The following fair value hierarchy table presents information about our assets measured at fair value using the market value approach on a recurring basis as of June 30, 2009 (in thousands):

				Fair Value Measurements Using
Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	June 30, 2009
Net derivative assets/(liabilities)	$	(4,070	)	$	(7,602	)	$	—	$	3,532
	December 31, 2008
Net derivative assets/(liabilities)	$	(6,749	)	$	(14,117	)	$	1,160	$	6,208

                The following tables present the net fair value on a recurring basis using significant unobservable inputs (Level 3) during the periods ended June 30, 2009 and 2008 (in thousands):

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

($ in 000’s)	Net Derivatives(1)
Beginning Balance, March 31, 2009	$	3,752
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—
Included in comprehensive income	1,012
Purchases, issuances, and settlements	—
Transfers into and (out of) Level 3	(1,232		)
Ending Balance, June 30, 2009	$	3,532
Changes in unrealized gains relating to assets still held at reporting date	$	1,012

(1)Net derivatives at June 30, 2009 included derivative assets of $3.5 million and no derivative liabilities.

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($ in 000’s)	Net Derivatives(1)
Beginning Balance, March 31, 2008	$	12,266
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—
Included in comprehensive income	9,807
Purchases, issuances, and settlements	—
Transfers into and (out of) Level 3	—
Ending Balance, June 30, 2008	$	22,073
Changes in unrealized gains relating to assets still held at reporting date	$	9,807

(1) Net derivatives at June 30, 2008 included derivative assets of $22.1 million and no derivative liabilities.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

($ in 000’s)	Net Derivatives(1)
Beginning Balance, December 31, 2008	$	6,208
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—
Included in comprehensive income	(1,444		)
Purchases, issuances, and settlements	—
Transfers into and (out of) Level 3	(1,232		)
Ending Balance, June 30, 2009	$	3,532
Changes in unrealized gains/(losses) relating to assets still held at reporting date	$	(1,444	)

(1) Net derivatives at June 30, 2009 included derivative assets of $3.5 million and no derivative liabilities.

($ in 000’s)	Net Derivatives(1)
Beginning Balance, December 31, 2007	$	11,961
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—
Included in comprehensive income	10,112
Purchases, issuances, and settlements	—
Transfers into and (out of) Level 3	—
Ending Balance, June 30, 2008	$	22,073
Changes in unrealized gains relating to assets still held at reporting date	$	10,112

(1) Net derivatives at June 30, 2008 included derivative assets of $22.1 million and no derivative liabilities.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

($ in 000’s)	Net Derivatives(1)
Beginning Balance, June 30, 2008	$	22,073
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—
Included in comprehensive income	(17,309		)
Purchases, issuances, and settlements	—
Transfers into and (out of) Level 3	(1,232		)
Ending Balance, June 30, 2009	$	3,532
Changes in unrealized gains/(losses) relating to assets still held at reporting date	$	(17,309	)

(1) Net derivatives at June 30, 2009 included derivative assets of $3.5 million and no derivative liabilities.

($ in 000’s)	Net Derivatives(1)
Beginning Balance, June 30, 2007	$	11,455
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—
Included in comprehensive income	10,618
Purchases, issuances, and settlements	—
Transfers into and (out of) Level 3	—
Ending Balance, June 30, 2008	$	22,073
Changes in unrealized gains relating to assets still held at reporting date	$	10,618

(1) Net derivatives at June 30, 2008 included derivative assets of $22.1 million and no derivative liabilities.

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Long-Term Debt

                The carrying amount of our total debt exclusive of capital leases at June 30, 2009, was $708 million compared to a fair market value of approximately $680 million. These estimates were based on the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of June 30, 2009 or that will be realizable in the future.

Note 6— Financing

                On March 27, 2009, we issued $75 million principal amount of 7% first mortgage bonds due April 1, 2024. The net proceeds (after payment of expenses) of approximately $72.6 million were used to repay short-term debt incurred, in part, to fund our current construction program.

                On February 25, 2009, we entered into an equity distribution agreement with UBS Securities LLC (UBS). Under the terms of the agreement, we may offer and sell shares of our common stock, par value $1.00 per share, having an aggregate offering price of up to $60 million from time to time through UBS, as sales agent. We intend to use the net proceeds from this equity distribution program to repay short-term debt and for general corporate purposes, including to fund our current construction program. During the second quarter of 2009, we issued and sold 6,400 shares pursuant to this equity distribution program, at an average price per share of $16.50, resulting in proceeds to us of approximately $0.1 million (after payment of approximately $4,489 in commissions to the sales agent). Through July 31, 2009, in the aggregate, we have issued and sold 200,519 shares pursuant to the program, resulting in net proceeds to us of approximately $3.2 million.

                Sales of the shares pursuant to the equity distribution agreement will be made at market prices or as otherwise agreed with UBS. Under the terms of the program agreement, we may also sell shares to UBS as principal for UBS’ own account at a price agreed upon at the time of sale.

                On March 11, 2009, we entered into a $50 million unsecured credit agreement. This agreement provides for $50 million of revolving loans to be available to us for working capital, general corporate purposes and to back-up our use of commercial paper and terminates on July 15, 2010. This credit agreement is in addition to, and has substantially identical covenants and terms as (other than pricing), our Amended and Restated Unsecured Credit Agreement dated March 14, 2006 discussed below. There were no borrowings under this agreement at June 30, 2009.

                On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy Station project. This extra $76 million of availability reduces over a four year period in line with the amount of construction expenditures we owe for Plum Point Unit 1 and was $12.5 million as of August 1, 2009. The unallocated credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include our note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of June 30, 2009, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were $51.0 million of outstanding borrowings under this agreement at June 30,

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2009. In addition, $21.0 million of the availability thereunder was used at such date to back up our outstanding commercial paper.

Note 7— Commitments and Contingencies

                We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided accruals for any liabilities, in accordance with the guidelines of Statement of Financial Accounting Standards SFAS 5, “Accounting for Contingencies” (FAS 5). In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse affect upon our financial condition, or results of operations or cash flows.

Coal, Natural Gas and Transportation Contracts

                We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Certain of these are firm physical contracts and others are derivatives that are used to hedge future purchases. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used, the gas would remain in storage or be liquidated at market price. The firm physical gas and transportation commitments are as follows (in millions):

Firm physical gas and transportation contracts
July 1, 2009 through June 30, 2010	$	41.5
July 1, 2010 through June 30, 2012	65.2
July 1, 2012 through June 30, 2014	42.7
July 1, 2014 and beyond	43.9

                We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. Some of these contracts  are subject to fuel and index price adjustments. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. Due to damage incurred in March 2009 to our Asbury rail car unloading facility, we issued Force Majeure notices to our western coal suppliers and to the railroads, suspending western coal shipments. This relieved us of our contractual obligations to receive shipments of coal until the railroad unloading facility was repaired and put back in service on May 13, 2009. The minimum requirements for our coal and coal transportation contracts are as follows (in millions):

Coal and coal transportation contracts
July 1, 2009 through June 30, 2010	$	30.2
July 1, 2010 through June 30, 2012	20.6
July 1, 2012 through June 30, 2013	7.3

Purchased Power

                We currently supplement our on-system generating capacity with purchases of capacity and energy from other utilities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.

                We have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. Commitments under this contract total approximately $14.8 million through May 31, 2010.

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                We also have a long-term (30 year) agreement for the purchase of capacity from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which is being built by Dynegy near Osceola, Arkansas. Construction began in the spring of 2006 and Dynegy reports that substantial completion is scheduled for the summer of 2010. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. Commitments under this contract total approximately $48.0 million through June 30, 2015.

                We have a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas commencing with the commercial operation date, which was December 15, 2008. We also have a 20-year contract with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc. (formerly known as PPM Energy), to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements are considered operating leases under GAAP, payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations discussed below.

New Construction

                On March 14, 2006, we entered into contracts to purchase an undivided interest in 50 megawatts of the Plum Point Energy Station’s new 665-megawatt, coal-fired generating facility which is being built near Osceola, Arkansas. Dynegy reports that substantial completion is scheduled for the summer of 2010. The estimated cost is approximately $88.0 million, excluding allowance for funds used during construction (AFUDC). Our share of the Plum Point costs through June 30, 2009 was $79.3 million.

                On June 13, 2006, we announced we had entered into an agreement with Kansas City Power & Light (KCP&L) to purchase an undivided ownership interest in the coal-fired Iatan 2 generating facility. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. Early in the third quarter of 2009, KCP&L announced its efforts to produce a cost and schedule reforecast primarily to address on-going productivity issues that were negatively impacting the original schedule. KCP&L now reports that the anticipated in-service date for Iatan 2 is late summer of 2010. Based on a late summer in-service date, we expect base rates reflecting our investment to be in effect in early 2011. Our share of the Iatan 2 construction costs is still expected to be in a range of approximately $218 million to $230 million. Our share of the Iatan 2 costs through June 30, 2009 was $161.0 million. As a requirement for the air permit for Iatan 2, and to help meet requirements of the Clean Air Interstate Rule (CAIR), additional emission control equipment was required for Iatan 1. Our share of the Iatan 1 environmental costs was $51.7 million through June 30, 2009. KCP&L reported the equipment had met regulatory in-service criteria as of April 19, 2009 and it is currently in service. All of these construction expenditures exclude AFUDC.

                There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than currently planned, the scope and timing of projects may change, the re-baselined schedule may not be met and other events beyond our control, including the failure of one or more of the generation plant co-owners to pay their share of construction, operations and maintenance costs, may occur that may materially affect the schedule, budget, cost and performance of these projects. To the extent the completion of these projects is delayed, we expect that the timing of receipt of increases in base rates reflecting our investment in such projects will be correspondingly delayed.

Leases

                As discussed above, on June 25, 2007, we entered into a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas. Pursuant to the terms of the agreement, we will purchase all of the output from the approximately

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105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.

                On December 10, 2004, we entered into a 20-year contract with Elk River Windfarm, LLC to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. We have contracted to purchase approximately 550,000 megawatt-hours of energy per year, or approximately 10% of our annual supply under the contract. We do not own any portion of the windfarm. Payments for wind energy from the Elk River Windfarm are contingent upon output of the facility. Annual payments can run from zero to a maximum of approximately $16.9 million based on a 20-year average cost.

                Payments for these agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in operating lease obligations.

                We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for six service center properties for our gas segment. In addition we have a five-year capital lease for telephone equipment.

                Our lease obligations over the next five years have not significantly changed at June 30, 2009, compared to December 31, 2008.

Environmental Matters

                We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as other environmental matters. We believe that our operations are in compliance with present laws and regulations.

Electric Segment

Air. The 1990 Amendments to the Clean Air Act, referred to as the 1990 Amendments, affect the Asbury, Riverton, State Line and Iatan 1 Power Plants and Units 3 and 4 (the FT8 peaking units) at the Empire Energy Center. The 1990 Amendments require affected plants to meet certain emission standards, including maximum emission levels for sulfur dioxide (SO2) and nitrogen oxides (NOx).

SO2 Emissions.  Under the 1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Each existing affected unit has been allocated a specific number of emission allowances, each of which allows the holder to emit one ton of SO2. Utilities covered by the 1990 Amendments must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. The annual reconciliation of allowances, which occurs on a facility wide basis, is held each March 1 for the previous calendar year. Allowances may be traded between plants or utilities or “banked” for future use. A market for the trading of emission allowances exists on the Chicago Board of Trade. The Environmental Protection Agency(EPA) withholds annually a percentage of the emission allowances allocated to each affected unit and sells those emission allowances through a direct auction. We receive compensation from the EPA for the sale of these withheld allowances. During 2008 and 2009, we received less than $0.1 million from the EPA auction.

                Our Asbury, Riverton and Iatan coal plants collectively receive 11,723 allowances per year. They burn a blend of low sulfur Western coal (Powder River Basin) and higher sulfur blend coal and petroleum coke, or burn 100% low sulfur Western coal. In addition, tire-derived fuel (TDF) is used as a supplemental fuel at the Asbury Plant. The Riverton Plant can also burn natural gas as its primary fuel. The State Line Plant, the Energy Center Units 3 and 4 and Riverton Unit 12 are gas-fired facilities and are allocated zero SO2 allowances. In the near term, annual allowance requirements for the State Line Plant, the Energy Center Units 3 and 4 and Riverton Unit 12, which are not expected to exceed 20 allowances per year, will be transferred from our inventoried bank of allowances. In 2008, the combined actual SO2 allowance need for all affected plant facilities exceeded the number of allowances allocated to us by the EPA. As of March 1, 2009, we had

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17,394 banked SO2 allowances as compared to 23,800 at March 1, 2008. We project that our 2009 emissions will again exceed the number of allowances allocated by the EPA by an amount approximately equal to the difference during 2008.

                When our SO2 allowance bank is exhausted, currently estimated to be mid-2011, we will need to purchase additional SO2 allowances or build a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant. Based on current and projected SO2 allowance prices and high-level estimated FGD scrubber construction costs ($81 million in 2010 dollars), we project it will be more economical for us to purchase SO2 allowances than to build a scrubber at the Asbury Plant. Based on SO2 allowance market prices as of May 4, 2009 in conjunction with currently estimated future operating parameters at the Asbury Plant, we estimate it will cost us approximately $0.4 million to purchase SO2 allowances for the remainder of 2011 and a range of approximately $0.45 million to $0.75 million annually for the years 2012 through 2018. We would expect the costs of SO2 allowances to be fully recoverable in our rates.

                Effective March 1, 2005, the MPSC approved a Stipulation and Agreement granting us authority to manage our SO2 allowance inventory in accordance with our SO2 Allowance Management Policy (SAMP). The SAMP allows us to exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. We have not yet exchanged or sold any allowances under the SAMP.

                SO2 emissions will be further regulated as described in the Clean Air Interstate Rule section below.

NOx Emissions. The Asbury, Iatan, State Line, Energy Center and Riverton Plants are each in compliance with the NOx limits applicable to them under the 1990 Amendments as currently operated.

                In March 2008, the EPA lowered the National Ambient Air Quality Standard (NAAQS) for ozone from 84 ppb to 75 ppb. Ozone, also called ground level smog, is formed by the mixing of NOx andVolatile Organic Compounds (VOCs) in the presence of sunlight. It is possible that several counties in southwest Missouri will be classified as being in non-attainment of the ozone NAAQS standard by the EPA in 2010 or later. We anticipate that the EPA will classify the Kansas City area, where Iatan 1 is located, as being in non-attainment in 2010. At this time we do not foresee the need for additional pollution controls due to the reduction in the ozone standard. In addition, our units do not emit appreciable VOCs. We do not anticipate that southeast Kansas, where our Riverton Plant is located, will be classified as non-attainment under the new ozone NAAQS.

                NOx emissions are further regulated as described in the Clean Air Interstate Rule section below.

Clean Air Interstate Rule (CAIR)

                The EPA issued its final CAIR on March 10, 2005. CAIR governed NOx and SO2 emissions from fossil fueled units greater than 25 megawatts in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located and Arkansas where the Plum Point Energy Station is being constructed. Kansas was not included in CAIR and our Riverton Plant was not affected.

                On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAIR Rule and remanded it back to the EPA. However, the court stayed its vacatur on December 23, 2008. As a result, CAIR became effective for NOx on January 1, 2009 and will become effective for SO2 on January 1, 2010.

                The CAIR is not directed to specific generation units, but instead, requires the states (including Missouri and Arkansas) to develop State Implementation Plans (SIPs) to comply with specific NOx and SO2 state-wide annual budgets. Missouri and Arkansas finalized their respective regulations and submitted their SIPs to the EPA, which were approved. We have received our full allotment of allowances as published in the Missouri CAIR Rule. In addition to this allotment, the Missouri Department of Natural Resources (MDNR) has allocated 61 annual NOx allowances for 2009 to our account from the Renewable Energy Pool and we estimate we will be allocated an

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additional 663 annual NOx allowances for 2009 from the Compliance Supplemental Pool in 2010. Under the Arkansas CAIR rule, we will not receive allowances until approximately six years after Plum Point Unit 1 is operational. In the interim, we will transfer allowances from our Missouri units. Based on SIPs for Missouri and Arkansas, we believe we will have excess annual and ozone season NOx allowances. SO2 allowances must be utilized at a 2:1 ratio for our Missouri units as compared to our non-CAIR Kansas units beginning in 2010. As a result, based on current SO2 allowance usage projections, we expect to exhaust our banked allowances by mid-2011 and will need to purchase additional SO2 allowances or build a scrubber at our Asbury Plant.

                In order to meet CAIR requirements for Iatan 1 and to meet air permit requirements for Iatan 2, pollution control equipment has been installed on Iatan 1. Installation was completed in April 2009 and KCP&L reported the equipment met in-service criteria as of April 19, 2009. This equipment includes a Selective Catalytic Reduction (SCR) system, an FGD scrubber and a baghouse, with our share of the capital cost estimated to be between $58 million and $60 million, excluding AFUDC. Of this amount, approximately $3.9 million was incurred in 2006, $12.1 million in 2007 and $27.3 million in 2008 with estimated expenditures of approximately $15.6 million in 2009 (of which $8.4 million has been incurred through June 30, 2009). KCP&L is in the process of closing out the project and expects final costs by the end of the year. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC.

                Also to meet CAIR requirements, we constructed an SCR at Asbury that was completed in November 2007 and placed in service in February 2008 at a total cost of approximately $31.0 million (excluding AFUDC). This project was also included as part of our Experimental Regulatory Plan approved by the MPSC and its cost is now in base rates in Missouri.

Air Permits. Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our plants from the authorities in the state in which the plant is located. These permits, which are valid for five years, regulate the plant site’s total air emissions; including emissions from stacks, individual pieces of equipment, road dust, coal dust and other emissions. We have been issued permits for Asbury, Iatan, Riverton, State Line and the Energy Center Plants. We submitted the required renewal applications for the State Line and Energy Center Title V permits in 2003 and the Asbury Title V permit in 2004 and will operate under the existing permits until the MDNR issues the renewed permits. A Compliance Assurance Monitoring (CAM) plan for particulate matter (PM) will be required by the renewed permit for Asbury. We estimate that the capital costs associated with the PM CAM plan will not exceed $2 million. We submitted the renewal application for the Riverton Title V permit in June 2008. A CAM plan for PM will also be required by the renewed permit for Riverton. No additional capital costs are anticipated. It is expected that the Kansas Department of Health and Environment (KDHE) will issue the renewal permit for Riverton in the third quarter of 2009.

                A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and Iatan Unit No. 2 currently under construction. The Unit No. 1 SCR, scrubber and baghouse are fully operational and the unit is operating in compliance with the permit conditions.

                The Clean Air Act required companies to obtain permits and, if necessary, install control equipment to reduce emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in regulated emissions. The Sierra Club and Concerned Citizens of Platte County have claimed that modifications were made to Iatan 1 prior to the Comprehensive Energy Plan project in violation of Clean Air Act regulations. We own 12% of Iatan 1. As operator, KCP&L entered into a Collaboration Agreement with those parties that provide, among other things, for the release of such claims. In May 2008, a grand jury subpoena requesting documents was received by KCP&L. KCP&L completed documentation delivery in response to the subpoena in March 2009. The outcome of these activities cannot presently be determined, nor can the costs and other liabilities that could potentially result from a negative outcome presently be reasonably estimated.

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Clean Air Mercury Rule (CAMR)

                On March 15, 2005, the EPA issued the CAMR regulations for mercury emissions by power plants under the requirements of the 1990 Amendments to the Clean Air Act. The new mercury emission limits of CAMR Phase 1 were to go into effect January 1, 2010. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia vacated the EPA’s CAMR regulations which was appealed to the U.S. Supreme Court on October 17, 2008. On February 23, 2009, the U.S. Supreme Court denied the appeal.

                The EPA has not issued guidance to the states regarding the vacated regulation nor recommended future actions. Based on CAMR, we installed a mercury analyzer at Asbury during late 2007 and installed two mercury analyzers at Riverton in 2008 in order to verify our mercury emissions and to meet the monitoring compliance date of January 1, 2009 and the Phase 1 mercury emission compliance date of January 1, 2010. We will operate the mercury analyzers at Riverton and Asbury in accordance with the appropriate state environmental regulator’s guidance.

                The CAMR rulemaking was revoked by the EPA after final adjudication. Maximum Achievable Control Technology (MACT) re-emerged under current law but no specific MACT rulemakings have yet been adopted in Missouri or Kansas.

CO2 Emissions

                Our coal and gas plants emit carbon dioxide (CO2), a greenhouse gas (GHG). Although not currently regulated, increasing public concerns and political pressures from local, regional, national and international bodies are likely to result in the passage of new laws mandating limits on GHG emissions such as CO2. The EPA recently proposed a mandatory GHG reporting system to become effective in early 2011 applicable to power generating and certain other facilities that exceed specified emission thresholds. Also, in response to a 2007 decision of the U.S. Supreme Court determining that GHG are air pollutants under the CAA, on April 17, 2009 the EPA proposed a finding that GHG, including CO2, threaten the public health and welfare. If finally adopted, this endangerment finding by the EPA may lead it to promulgate regulations for GHG emissions, including those from power plants. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (also known as H.R. 2454). The bill provides provisions to cap CO2 levels emitted by electric utilities at 3% below 2005 levels beginning in 2012. We are closely monitoring proposed CO2 legislation. Certain states have taken steps to develop similar regulatory systems which may be more stringent than any federal regulations. For example, Kansas is a participating member of the Midwestern Greenhouse Gas Reduction Accord, one purpose of which is to develop a market-based cap and trade mechanism to reduce GHG emissions. The impact on us of any future GHG regulation will depend in large part on the details of the requirements and the timetable for mandatory compliance. Although there can be no guarantee and the ultimate cost of any GHG regulations cannot be determined at this time, we would expect the cost of complying with any such regulations to be fully recoverable in our rates. We also cannot predict with certainty the impact to our financial position, liquidity or results of operations at this time.

Water. We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Water Pollution Control Act Amendments of 1972. The Asbury, Iatan, Riverton, Energy Center and State Line plants are in compliance with applicable regulations and have received discharge permits and subsequent renewals as required.

                The Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the Clean Water Act (CWA) Section 316(b) Phase II. The regulations became final on February 16, 2004 and required the submission of a Sampling Report and Comprehensive Demonstration Study with the permit renewal in 2008. Sampling and summary reports, which were completed during the first quarter of 2008 and submitted to the KDHE, indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. The need for a further Demonstration Study is not expected. On January 25, 2007, the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations. On July 9, 2007, the EPA suspended the regulation and is expected to revise and re-propose the regulation in 2009. In

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addition, on April 14, 2008 certiorari was granted by the United States Supreme Court limited to the review as to whether Section 316(b) of the CWA authorized the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impacts at cooling water intake structures. On April 1, 2009, the U.S. Supreme Court overturned the lower court’s ruling on the cost/benefit issue and remanded the regulation to the EPA. The permit renewal application was prepared and submitted in June 2008 and the final permit was received on January 1, 2009. Under the initial regulations, we did not expect costs associated with compliance to be material. We will reassess costs after the revised rules are complete.

Ash Ponds. We own and maintain coal ash ponds located at our Riverton and Asbury Power Plants. Additionally, we own a 12 percent interest in a coal ash pond at the Iatan Generating Station. In April and May of 2009 we received Information Collection Requests from the EPA regarding our ash ponds. The requests were completed and submitted to the EPA as directed. All of the ash ponds are compliant with state and federal regulations.

Renewable Energy. On November 4, 2008, Missouri voters approved the Clean Energy Initiative (Proposition C). This initiative requires investor-owned utilities in Missouri (such as Empire) to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, at the rate of at least 2% in retail sales by 2011, increasing to at least 15% by 2021. At least 25 other states have adopted renewable portfolio standard (RPS) programs that mandate some form of renewable generation. Some of these RPS programs incorporate a trading system in which utilities are allowed to buy and sell renewable energy certificates (RECs) in order to meet compliance. Additionally, RECs are utilized by many companies in “green” marketing efforts. REC prices are driven by various market forces. We have been selling RECs and plan to continue to sell all or a portion of the RECs associated with our contracts with Elk River Windfarm, LLC and Cloud County Windfarm, LLC. With respect to the energy underlying the RECs that we sell, we may not claim that we are purchasing renewable energyfor any purpose, including for purposes of complying with the new Missouri requirements. Over time, we expect to retain some of the renewable attributes associated with these contracts in order to meet the new Missouri requirements. We realized revenues of $1.8 million from REC sales in 2008 and $0.9 million in 2007. Revenues from REC sales for the twelve months ended June 30, 2009 and 2008 were $1.5 million and $1.4 million, respectively. Revenues from REC sales for the quarter ended June 30, 2009 and 2008 were $0.3 million and $0.4 million, respectively and for the six months ended June 30, 2009 and 2008, REC revenues were $0.7 million and $1.0 million, respectively.

The MPSC initiated a proceeding on March 9, 2009 to develop a rulemaking to implement Proposition C. The proceeding includes workshops and public comment periods to allow for input from industry as well as the public at large. We expect this process to conclude in 2009.

Gas Segment

The acquisition of Missouri Gas involved the property transfer of two former manufactured gas plant (MGP) sites previously owned by Aquila, Inc. and its predecessors. Site #1 in Chillicothe, Missouri is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. Site #2 in Marshall, Missouri has received a letter of no further action from the MDNR. A Change of Use request and work plan was approved by the MDNR allowing us to expand our existing service center at Site #1 in Chillicothe, Missouri. This project, which was completed in October 2007, included the removal of all excavated soil and the addition of a new concrete surface replacing the existing gravel at a cost of approximately $0.1 million. We estimate further remediation costs at these two sites to be no more than approximately $0.2 million, based on our best estimate at this time. The remaining liability balance of $0.2 million is recorded under noncurrent liabilities and deferred credits. In our agreement with the MPSC approving the acquisition of Missouri Gas, it was agreed that we could reflect a liability and offsetting regulatory asset not to exceed $260,000 for the acquired sites. The MPSC agreed that up to $260,000 of costs related to the clean up of these MGP sites would be allowed for future rate recovery. Accordingly, we concluded that rate recovery was probable and at the acquisition date, a regulatory asset of

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$260,000 was recorded as part of the purchase price allocation based on our agreement with the MPSC, and in accordance with SFAS No. 71 – “Accounting for the Effects of Certain Types of Regulation” (FAS 71).

Note 8 – Retirement Benefits

Net periodic benefit pension cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components and is shown for our noncontributory defined benefit pension plan, our supplemental retirement program (SERP) and other postretirement benefits (OPEB) (in thousands):

	Three months ended June 30,
	Pension Benefits						SERP						OPEB
	2009			2008			2009			2008			2009			2008
Service cost	$	1,019		$	863		$	15		$	12		$	509		$	407
Interest cost	2,491			2,245			37			32			1,066			910
Expected return on plan assets	(2,601		)	(2,680		)	—			—			(970		)	(938		)
Amortization of prior service cost (1)	151			186			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	837			404			20			30			356			140
Net periodic benefit cost	$	1,897		$	1,018		$	70		$	72		$	708		$	266
	Six months ended June 30,
	Pension Benefits						SERP						OPEB
	2009			2008			2009			2008			2009			2008
Service cost	$	2,010		$	1,725		$	31		$	24		$	963		$	814
Interest cost	4,929			4,491			74			63			2,051			1,820
Expected return on plan assets	(5,202		)	(5,359		)	—			—			(1,930		)	(1,876		)
Amortization of prior service cost (1)	302			372			(4		)	(4		)	(505		)	(505		)
Amortization of net actuarial loss (1)	1,591			807			51			61			588			279
Net periodic benefit cost	$	3,630		$	2,036		$	152		$	144		$	1,167		$	532
	Twelve months ended June 30,
	Pension Benefits						SERP						OPEB
	2009			2008			2009			2008			2009			2008
Service cost	$	3,853		$	3,468		$	64		$	49		$	1,800		$	1,468
Interest cost	9,486			8,641			147			122			3,848			3,287
Expected return on plan assets	(10,573		)	(10,484		)	—			—			(3,804		)	(3,624		)
Amortization of prior service cost (1)	674			772			(8		)	(10		)	(1,011		)	(1,266		)
Amortization of net actuarial loss (1)	2,477			2,108			123			134			820			831
Net periodic benefit cost	$	5,917		$	4,505		$	326		$	295		$	1,653		$	696

(1) Amounts are amortized from our regulatory asset originally recorded upon adoption of FAS 158.

Based on the performance of our pension plan assets through January 1, 2008 and 2009, we were not required by law to fund any additional minimum amounts with respect to 2008.

The expected minimum funding for 2009 is estimated to be between $1.9 million and $3.0 million. For 2010, it is estimated to be between $9.0 million and $15.0 million. The actual minimum funding requirements will be determined based on the results of the actuarial valuations and, in the case of 2010, the performance of our pension assets during 2009.

Note 9— Stock-Based Awards and Programs

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended June 30 (in thousands):

	Three Months Ended				Six Months Ended				Twelve Months Ended
	2009		2008		2009		2008		2009		2008
Compensation Expense	$	669	$	503	$	1,248	$	1,377	$	1,712	$	2,234
Tax Benefit Recognized	244		181		453		505		607		813

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Activity for our various stock plans for the six months ended June 30, 2009 is summarized below:

Performance-Based Restricted Stock Awards

The assumptions used in the model for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at June 30,
	2009	2008
Risk-free interest rate	0.35% to 1.37%	2.44% to 5.09%
Expected volatility of Empire stock	28.8%	15.2% to 19.9%
Expected volatility of peer group stock	21.8% to 79.6%	14.1% to 34.6%
Expected dividend yield on Empire stock	7.3%	5.4% to 5.8%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
Fair value percentage	105.0% to 130.0%	107.73% to 113.0%
Weighted average fair value per share	$19.29	$24.88

Non-vested restricted stock awards (based on target number) as of June 30, 2009 and 2008 and changes during the six months ended June 30, 2009 and 2008 were as follows:

	2009				2008
	Number		Weighted Average		Number		Weighted Average
	of shares		Grant Date Price		of shares		Grant Date Price
Nonvested at January 1,	52,300		$	22.64	43,400		$	23.02
Granted	13,500		$	18.12	21,000		$	21.92
Awarded	(12,394	)	$	22.23	(6,486	)	$	22.77
Not Awarded	(1,206	)			(5,614	)
Nonvested at June 30,	52,200		$	21.57	52,300		$	22.64

At June 30, 2009, there was $0.5 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period.

Stock Options

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of June 30, 2009 and 2008, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

	Fair Value of Grants Outstanding at June 30,
	2009	2008
Risk-free interest rate	1.25% to 2.97%	3.27% to 4.68%
Dividend yield	7.3%	5.33% to 6.16%
Expected volatility	24.0%	16.13% to 20.0%
Expected life in months	78	60 to 78
Market value	$16.52	$20.25
Weighted average fair value per option	$0.63	$2.21

A summary of option activity under the plan during the six months ended June 30, 2009 and 2008 is presented below:

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	2009			2008
		Weighted Average			Weighted Average
	Options	Exercise Price		Options	Exercise Price
Outstanding at January 1,	205,600	$	22.73	149,200	$	23.04
Granted	27,000	$	18.12	56,400	$	21.92
Exercised	—			—
Outstanding at June 30,	232,600	$	22.19	205,600	$	22.73
Exercisable at June 30,	85,000	$	22.46	43,300	$	22.67

The aggregate intrinsic value at June 30, 2009 and 2008 was zero. The intrinsic value of the unexercised options is the difference between Empire’s closing stock price on the last day of the quarter and the exercise price multiplied by the number of in the money options had all option holders exercised their option on the last day of the quarter. The intrinsic value is zero if such closing price is less than the exercise price.

The range of exercise prices for the options outstanding at June 30, 2009 was $18.12 to $23.81. The weighted-average remaining contractual life of outstanding options at June 30, 2009 and 2008 was 7.1 years and 7.6 years, respectively. As of June 30, 2009, there was $0.3 million of total unrecognized compensation expense related to the non-vested options and related dividend equivalents granted under the plan. That cost will be recognized over a period of 1 to 3 years.

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of June 30, 2009, there were 397,744 shares available for issuance in this plan.

	2009		2008
Subscriptions outstanding at June 30	69,830		49,960
Maximum subscription price	$	14.62	$	18.57
Shares of stock issued (1)	44,265		38,803
Stock issuance price	$	14.10	$	18.61

(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2009 to May 31, 2010.

Assumptions for valuation of these shares are shown in the table below.

	ESPP
	2009			2008
Weighted average fair value of grants	$	3.26		$	3.46
Risk-free interest rate	0.48		%	2.17		%
Dividend yield	7.90		%	6.20		%
Expected volatility	40.00		%	26.00		%
Expected life in months	12			12
Grant Date	6/1/09			6/2/08

Note 10- Regulated Operating Expenses

The following table sets forth the major components comprising “Regulated operating expenses” under “Operating Revenue Deductions” on our consolidated statements of operations (in thousands) for all periods presented ended June 30:

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	Three Months Ended		Three Months Ended		Six Months Ended		Six Months Ended		Twelve Months Ended		Twelve Months Ended
	2009		2008		2009		2008		2009		2008
Electric transmission and distribution expense	$	2,747	$	2,687	$	5,337	$	5,344	$	10,884	$	10,432
Natural gas transmission and distribution expense	548		475		1,074		949		2,119		1,836
Power operation expense (other than fuel)	3,062		2,716		6,126		5,429		12,369		10,861
Customer accounts and assistance expense	2,736		2,439		5,187		4,987		10,366		9,845
Employee pension expense (1)	1,327		1,568		2,687		3,122		5,457		6,285
Employee healthcare plan (1)	1,375		1,944		2,691		3,887		5,941		7,581
General office supplies and expense	2,564		2,400		4,824		4,842		9,312		9,968
Administrative and general expense	2,851		2,529		5,850		5,487		12,090		10,871
Allowance for uncollectible accounts	853		879		1,800		1,450		3,294		3,456
Miscellaneous expense	13		26		1		64		102		219
Total	$	18,076	$	17,663	$	35,577	$	35,561	$	71,934	$	71,354

(1) Includes effects of regulatory treatment for pension and other postretirement benefits but does not include capitalized portion or amount deferred to a regulatory asset.

Note 11— Segment Information

We operate our business as three segments:  electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The other segment consists of our non-regulated businesses, primarily a subsidiary for our fiber optics business.

The tables below present statement of operations information, balance sheet information and capital expenditures of our business segments.

	For the quarter ended June 30, 2009
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Operations Information
Revenues	$	103,083	$	7,919		$	1,376	$	(148	)	$	112,230
Depreciation and amortization	11,888		503			348		—			12,739
Federal and state income taxes	4,293		(467		)	221		—			4,047
Operating income	15,500		155			372		—			16,027
Interest income	61		108			—		(108		)	61
Interest expense	10,841		988			13		(108		)	11,734
Income from AFUDC (debt and equity)	3,335		—			—		—			3,335
Net income	8,018		(750		)	359		—			7,627
Capital Expenditures	$	40,673	$	386		$	246				$	41,305

	For the quarter ended June 30, 2008
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Operations Information
Revenues	$	100,943	$	9,148		$	1,321	$	(132	)	$	111,280
Depreciation and amortization	13,055		481			326		—			13,862
Federal and state income taxes	2,467		(403		)	190		—			2,254
Operating income	11,713		261			352		—			12,326
Interest income	552		149			—		(158		)	543
Interest expense	9,680		991			44		(158		)	10,557
Income from AFUDC (debt and equity)	3,011		—			—		—			3,011
Net income	5,157		(648		)	308		—			4,817
Capital Expenditures	$	48,579	$	453		$	667				$	49,699

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	For the six months ended June 30, 2009
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Operations Information
Revenues	$	209,870	$	36,006	$	2,678	$	(309	)	$	248,245
Depreciation and amortization	23,717		1,003		692		—			25,412
Federal and state income taxes	8,663		576		416		—			9,655
Operating income	31,198		2,769		715		—			34,682
Interest income	136		266		—		(265		)	137
Interest expense	21,400		1,984		40		(265		)	23,159
Income from AFUDC (debt and equity)	6,938		1		—		—			6,939
Net income	16,861		1,003		676		—			18,540
Capital Expenditures	$	80,667	$	855	$	792				$	82,314

	For the six months ended June 30, 2008
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Operations Information
Revenues	$	209,682	$	36,424	$	2,382	$	(263	)	$	248,225
Depreciation and amortization	25,874		961		648		—			27,483
Federal and state income taxes	3,955		1,106		298		—			5,359
Operating income	22,659		3,639		587		—			26,885
Interest income	655		264		—		(296		)	623
Interest expense	18,658		1,981		103		(296		)	20,446
Income from AFUDC (debt and equity)	5,476		1		—		—			5,477
Net income	9,516		1,806		485		—			11,807
Capital Expenditures	$	102,826	$	890	$	1,082				$	104,798

	For the twelve months ended June 30, 2009
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Operations Information
Revenues	$	448,435	$	65,020	$	5,300	$	(573	)	$	518,182
Depreciation and amortization	48,149		1,982		1,360		—			51,491
Federal and state income taxes	22,472		457		493		—			23,422
Operating income	72,965		4,550		1,294		—			78,809
Interest income	642		393		—		(463		)	572
Interest expense	42,369		3,965		139		(463		)	46,010
Income from AFUDC (debt and equity)	13,970		9		—		—			13,979
Net income	44,781		873		801		—			46,455
Capital Expenditures	$	180,202	$	2,105	$	1,665				$	183,972

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	For the twelve months ended June 30, 2008
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Operations Information
Revenues	$	441,376	$	60,273	$	4,344	$	(507	)	$	505,486
Depreciation and amortization	51,147		1,912		1,243		—			54,302
Federal and state income taxes	13,739		1,095		559		—			15,393
Operating income	59,904		5,626		885		—			66,415
Interest income	695		454		—		(381		)	768
Interest expense	37,166		3,974		17		(381		)	40,776
Income from AFUDC (debt and equity)	9,459		4		—		—			9,463
Net Income	31,916		1,849		840		—			34,605
Capital Expenditures	$	203,316	$	2,180	$	4,277				$	209,773

	As of June 30, 2009
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	1,681,351	$	134,607	$	22,186	$	(85,565	)	$	1,752,579

(1) Includes goodwill of $39,492.

	As of December 31, 2008
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	1,621,502	$	138,788	$	22,186	$	(68,630	)	$	1,713,846

(1) Includes goodwill of $39,492.

Note 12— Income Taxes

We adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” on January 1, 2007. We decreased our estimate of unrecognized tax benefits by an immaterial amount during the quarter ended March 31, 2008 as a review of certain amended returns by the Joint Committee on Taxation was completed. The Joint Committee accepted our tax position which led us to recognize certain tax benefits previously unrecognized. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months. The reserve balance related to unrecognized tax benefits as of December 31, 2008 was $2,176,000 and has not materially changed at June 30, 2009.

Our consolidated provision for income taxes increased approximately $2.1 million during the second quarter of 2009 as compared to the same period in 2008 mainly due to increased income. Our consolidated effective federal and state income tax rate for the second quarter of 2009 was 34.7% as compared to 31.9% for the second quarter of 2008.

Our consolidated provision for income taxes increased approximately $4.5 million during the six months ended June 30, 2009 as compared to the same period in 2008. This resulted primarily from increased income. Our consolidated effective federal and state income tax rate for the six months ended June 30, 2009 was 34.2% as compared to 31.2% for the same period in 2008.

Our consolidated provision for income taxes increased approximately $8.5 million during the twelve months ended June 30, 2009 as compared to the twelve months ended June 30, 2008, primarily resulting from higher income. Our effective federal and state income tax rate for the twelve months ended June 30, 2009 was 33.5% as compared to 30.8% for the same period in 2008.

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The rates in all periods are higher when comparing to the corresponding prior period primarily due to lower tax benefits received from cost of plant retirement expenditures. Our cost of retirement expenditures was unusually high during the twelve months ended June 30, 2008 due to the ice storms we experienced. This reduced benefit during this period was partially offset by an increase in the tax effects of equity AFUDC.

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

EXECUTIVE SUMMARY

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE) is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary. It provides natural gas distribution to customers in 44 communities in northwest, north central and west central Missouri. Our other segment consists of our non-regulated businesses, primarily a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business. During the twelve months ended June 30 2009, 86.5% of our gross operating revenues were provided from sales from our electric segment (including 0.3% from the sale of water), 12.6% from our gas segment and 0.9% from our other segment.

Earnings

During the second quarter of 2009, basic and diluted earnings per weighted average share of common stock were $0.22 as compared to $0.14 in the second quarter of 2008. For the six months ended June 30, 2009, basic and diluted earnings per weighted average share of common stock were $0.54 as compared to $0.35 for the six months ended June 30, 2008. For the twelve months ended June 30, 2009, basic earnings per weighted average share of common stock were $1.37 as compared to $1.08 for the twelve months ended June 30, 2008 and diluted earnings per weighted average share of common stock were $1.36 as compared to $1.08 for the twelve months ended June 30, 2008. As reflected in the table below, the primary positive drivers for all periods presented were increased revenues, mainly due to our 2008 Missouri rate case, and decreased fuel and purchased power costs. The primary negative drivers for all periods presented were increased maintenance costs and decreased revenues due to decreased off-system sales.

The following reconciliation of basic earnings per share between the three months, six months and twelve months ended June 30, 2008 versus June 30, 2009 is a non-GAAP presentation. We believe this information is useful in understanding the fluctuation in earnings per share between the prior and current years. The reconciliation presents the after tax impact of significant items and components of the statement of operations on a per share basis before the impact of additional stock issuances which is presented separately. Earnings per share for the three months, six months and twelve months ended June 30, 2008 and 2009 shown in the reconciliation are presented on a GAAP basis and are the same as the amounts included in the statements of operations. This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of operations.

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	Three Months Ended			Six Months Ended			Twelve Months Ended
Earnings Per Share – 2008	$	0.14		$	0.35		$	1.08
Revenues
Electric on-system	$	0.14		$	0.17		$	0.26
Electric off-system and other	(0.10		)	(0.16		)	(0.11		)
Gas	(0.02		)	(0.01		)	0.10
Other	0.00			0.00			0.02
Expenses
Electric fuel and purchased power	0.11			0.31			0.41
Cost of natural gas sold and transported	0.02			(0.01		)	(0.13		)
Regulated – electric segment	(0.01		)	0.01			0.00
Regulated –gas segment	0.00			(0.01		)	(0.01		)
Other segment	0.00			0.00			(0.01		)
Maintenance and repairs	(0.04		)	(0.08		)	(0.11		)
Depreciation and amortization	0.02			0.04			0.06
Other taxes	(0.01		)	(0.01		)	(0.01		)
Interest charges	(0.02		)	(0.06		)	(0.11		)
AFUDC	0.01			0.03			0.10
Gain on sale of assets	—			—			(0.03		)
Change in effective income tax rates	(0.01		)	(0.03		)	(0.06		)
Gain on sale of land	0.00			0.01			0.01
Other income and deductions	(0.01		)	(0.01		)	(0.03		)
Dilutive effect of additional shares issued	0.00			0.00			(0.06		)
Earnings Per Share – 2009	$	0.22		$	0.54		$	1.37

Recent Activities

2009 Storm Damage

A major wind storm caused substantial damage to our electric service territory on May 8, 2009. Approximately 83,000 of our electric customers were without power at the height of the storm.

Incremental costs associated with the restoration effort due to the wind storm were approximately $6.4 million, of which $5.7 million was capitalized as additions to our utility plant and approximately $0.7 million was maintenance expense that was deferred as a regulatory asset as we believe it is probable that these costs will be recoverable in future electric rate cases.

Ozark Beach Plant

Our hydroelectric generating plant (FERC Project No. 2221), located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in southwestern Missouri. As part of the Energy and Water Development Appropriations Act of 2006 (the Appropriations Act), a new minimum flow was established with the intent of increasing minimum flows on recreational streams in Arkansas. To accomplish this, the level of Bull Shoals Lake will be increased an average of 5 feet. The increase at Bull Shoals will decrease the head waters available for generation at Ozark Beach by 5 feet and, thus, reduce our electrical output. We estimate the lost production to be up to 16% of our average annual energy production for this unit. The loss in this facility would require us to replace it with additional generation from our gas-fired and coal-fired units or with purchased power. The Appropriations Act has a provision for the Army Corp of Engineers to provide a one time payment to us for lost energy production. The Appropriations Act requires the Southwest Power Administration (SWPA), in coordination with us and our relevant public service commissions, to determine our economic detriment. The SWPA published its Final Determination Report on January 23, 2009 documenting the procedure they intended to use to calculate the present value of the future lifetime replacement cost of the electrical energy and capacity lost due to the White River Minimum Flows project at Ozark Beach. The actual hydropower compensation values were to be

35

calculated using the method presented in the Final Determination and current values for the specified parameters based on the official implementation date. Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and November 2008 values for the specified parameters, the SWPA’s determination at that time resulted in a present value for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach of $41,319,400. However, on June 8, 2009, the SWPA published a draft addendum in the Federal Register to its January 2009 Final Determination Report documenting proposed changes to the SWPA’s methodology. Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and current values for the specified parameters, the SWPA’s Draft Addendum to its Final Determination results in a present value of $22,340,800 for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach. We and the MPSC have provided comments on the new methodology included in the draft addendum but cannot predict the final outcome. We expect that the Army Corp of Engineers will not implement the new minimum flow plan until at least January 2011, but, at this time, we cannot be sure of the timetable as it is dependent on Congress providing funding for the economic detriment.

SLCC Generator Failure

On July 3, 2009, the generator on State Line Unit 2-1, one of the combustion turbines at SLCC, failed during operation. Unit 2-1 represents about 150 megawatts of the 500 megawatts rated output of SLCC, of which we are entitled to 60%, or 300 megawatts. The remainder of SLCC is undamaged and continues to operate as normal. However, since the SLCC consists of the combination of two combustion turbines, two heat recovery steam generators, a steam turbine and auxiliary equipment, we cannot utilize the entire capability of the steam turbine without the use of Unit 2-1. This reduces SLCC’s generation capability by another 100 megawatts. Determinations as to the cost and timing of the repair have not yet been finalized. However, the damage is in excess of the $1.5 million insurance deductible on the unit. At this point, we expect Unit 2-1 will return to service during the fall of 2009. We do not anticipate the unplanned outage to have a material financial impact.

Regulatory Plan

On May 1, 2009, we began recording deferred carrying charges associated with environmental upgrades recently completed at our Iatan 1 facility in accordance with our regulatory plan. We deferred $0.8 million in the second quarter of 2009. Construction accounting, for purposes of the regulatory plan, allows us to defer certain charges as regulatory assets, including depreciation and carrying costs, related to operation of the facilities until the facilities are ultimately included in our rate base. The amounts deferred, which began at the in-service date for Iatan 1 and will also be deferred for Iatan 2 at its in-service date, will then be amortized over the life of the plants once they are in our rate base. The regulatory plan covers the 150 megawatt V84.3A2 combustion turbine (Unit 12) that began commercial operation on April 10, 2007 at our Riverton plant, the environmental upgrades at Asbury, which were completed in 2008, environmental upgrades at Iatan 1 and the construction of the Iatan 2 facilities. See Note 3 of “Notes to Consolidated Financial Statements (Unaudited)”.

Regulatory Matters

On June 5, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri gas customers in the amount of $2.9 million, or 4.9%. In this filing, we requested recovery of the ongoing cost of operating and maintaining our 1,200-mile gas distribution system and a return on equity of 11.3%. Results from this case would likely take effect in the second quarter of 2010.

All pending applications for rehearing in our 2006 Missouri electric rate case were denied by the MPSC on November 20, 2008. On December 15, 2008, the OPC filed a Petition for Writ of Review with the Cole County Circuit Court regarding the MPSC’s decisions in our 2006 rate case. Praxair and Explorer Pipeline filed a Petition for Writ of Review on December 19, 2008. These

36

actions were consolidated into one proceeding. Briefs have been filed by all parties and oral argument took place on June 2, 2009.

On May 13, 2009, the OPC filed a petition in the Jasper County Circuit Court seeking refunds with regard to utility rates for electric service paid by our customers during the period of January 1, 2007 to December 13, 2007. During this period, we charged the rates set forth in the tariffs which were approved by, and are on file with, the MPSC. We filed a motion to dismiss, or, in the alternative, motion for more definitive statement. Oral argument on our motion is scheduled for August 28, 2009.

For additional information, see “Rate Matters” below.

Financings

On February 25, 2009, we entered into an equity distribution agreement with UBS Securities LLC (UBS). Under the terms of the agreement, we may offer and sell shares of our common stock, par value $1.00 per share, having an aggregate offering price of up to $60 million from time to time through UBS, as sales agent. We intend to use the net proceeds from this equity distribution program to repay short-term debt and for general corporate purposes, including to fund our current construction program. During the second quarter of 2009, we issued and sold 6,400 shares pursuant to this program, at an average price per share of $16.50, resulting in proceeds to us of approximately $0.1 million (after payment of approximately $4,489 in commissions to the sales agent). Through July 31, 2009, in the aggregate, we have issued and sold 200,519 shares pursuant to the program, resulting in net proceeds to us of approximately $3.2 million.

Sales of the shares pursuant to the equity distribution agreement will be made at market prices or as otherwise agreed with UBS. Under the terms of the program agreement, we may also sell shares to UBS as principal for UBS’ own account at a price agreed upon at the time of sale.

On March 27, 2009, we issued $75 million principal amount of 7% first mortgage bonds due April 1, 2024. The net proceeds (after payment of expenses) of approximately $72.6 million, were used to repay short-term debt incurred, in part, to fund our current construction program.

On March 11, 2009, we entered into a $50 million unsecured credit agreement. This agreement provides for $50 million of revolving loans to be available to us for working capital, general corporate purposes and to back-up our use of commercial paper and terminates on July 15, 2010. This credit agreement is in addition to, and has substantially identical covenants and terms as (other than pricing), our Amended and Restated Unsecured Credit Agreement dated March 14, 2006. There were no borrowings under the new agreement at June 30, 2009.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month, six-month and twelve-month periods ended June 30, 2009, compared to the same periods ended June 30, 2008.

The following table represents our results of operations by operating segment for the applicable periods ended June 30 (in millions):

	Quarter Ended						Six Months Ended				Twelve Months Ended
	2009			2008			2009		2008		2009		2008
Income from continuing operations
Electric	$	8.0		$	5.2		$	16.8	$	9.5	$	44.8	$	31.9
Gas	(0.8		)	(0.6		)	1.0		1.8		0.9		1.8
Other	0.4			0.3			0.7		0.5		0.8		0.9
Income from continuing operations	$	7.6		$	4.8		$	18.5	$	11.8	$	46.5	$	34.6
Income from discontinued operations	—			—			—		—		—		0.1
Net income	$	7.6		$	4.8		$	18.5	$	11.8	$	46.5	$	34.7

*Differences could occur due to rounding.

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Electric Segment

Overview

Our electric segment income for the second quarter of 2009 was $8.0 million as compared to $5.2 million for the second quarter of 2008.

Electric operating revenues comprised approximately 91.5% of our total operating revenues during the second quarter of 2009. Of our total electric operating revenues during the second quarter of 2009, approximately 38.5% were from residential customers, 34.3% from commercial customers, 16.4% from industrial customers, 4.2% from wholesale on-system customers, 2.5% from wholesale off-system transactions, 2.7% from other electric revenues, primarily public authorities, and 1.4% from miscellaneous sources. The percentage of revenues provided from our wholesale off-system transactions decreased during the second quarter of 2009 as compared to the second quarter of 2008, primarily due to decreased market demand resulting from milder weather in April and May of 2009 and general economic conditions.

The amounts and percentage changes from the prior periods in kilowatt-hour (“kWh”) sales and operating revenues by major customer class for on-system sales and for off-system sales for the applicable periods ended June 30, were as follows:

	kWh Sales
	(in millions)
	Second	Second			6 Months	6 Months			12 Months	12 Months
	Quarter	Quarter	%		Ended	Ended	%		Ended	Ended	%
Customer Class	2009	2008	Change*		2009	2008	Change*		2009	2008	Change*
Residential	387.2	381.6	1.5	%	938.1	975.1	(3.8	)%	1,915.9	1,981.7	(3.3	)%
Commercial	403.9	392.5	2.9		779.9	771.4	1.1		1,630.5	1,626.1	0.3
Industrial	252.0	269.5	(6.5	)	492.3	531.6	(7.4	)	1,034.0	1,097.0	(5.7	)
Wholesale on-system	82.7	83.7	(1.1	)	163.5	169.1	(3.3	)	339.0	348.8	(2.8	)
Other**	29.8	30.0	(0.9	)	62.0	62.0	(0.1	)	123.7	123.1	0.5
Total on-system sales	1,155.6	1,157.3	(0.1	)	2,435.8	2,509.2	(2.9	)	5,043.1	5,176.7	(2.6	)
Off-system	111.9	169.4	(34.0	)	245.7	309.8	(20.7	)	624.1	572.5	9.0
Total KWh Sales	1,267.5	1,326.7	(4.5	)	2,681.5	2,819.0	(4.9	)	5,667.2	5,749.2	(1.4	)

*Percentage changes are based on actual kWh sales and may not agree to the rounded amounts shown above.

**Other kWh sales include street lighting, other public authorities and interdepartmental usage.

	Electric Segment Operating Revenues
	($ in millions)
	Second		Second				6 Months		6 Months				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%		Ended		Ended		%
Customer Class	2009		2008		Change*		2009		2008		Change*		2009		2008		Change*
Residential	$	39.5	$	36.3	8.6	%	$	88.1	$	85.0	3.6	%	$	182.4	$	178.6	2.1	%
Commercial	35.3		31.7		11.3		64.9		59.6		9.0		138.2		130.3		6.1
Industrial	16.8		16.6		1.3		31.7		31.4		0.8		67.6		67.2		0.6
Wholesale on-system	4.3		4.4		(2.4	)	9.0		9.5		(5.0	)	18.7		19.4		(3.3	)
Other**	2.7		2.6		5.2		5.5		5.2		6.4		11.4		10.7		6.6
Total on-system revenues	$	98.6	$	91.6	7.6		$	199.2	$	190.7	4.5		$	418.3	$	406.2	3.0
Off-system	2.6		7.4		(64.6	)	6.6		14.8		(55.6	)	21.5		27.1		(20.8	)
Total revenues from kWh sales	101.2		99.0		2.2		205.8		205.5		0.1		439.8		433.3		1.5
Miscellaneous revenues***	1.4		1.5		(5.0	)	3.2		3.3		(2.6	)	6.9		6.2		10.5
Total electric operating Revenues	$	102.6	$	100.5	2.1		$	209.0	$	208.8	0.1		$	446.7	$	439.5	1.6
Water revenues	0.5		0.4		(1.3	)	0.9		0.9		(2.0	)	1.7		1.9		(4.7	)
Total Electric Segment
Operating Revenues	$	103.1	$	100.9	2.1		$	209.9	$	209.7	0.1		$	448.4	$	441.4	1.6

*Percentage changes are based on actual revenues and may not agree to the rounded amounts shown above.

**Other operating revenues include street lighting, other public authorities and interdepartmental usage.

***Miscellaneous revenues include transmission service revenue, late payment fees, rent, etc.

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Quarter Ended June 30, 2009 Compared to Quarter Ended June 30, 2008

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers decreased slightly during the second quarter of 2009 as compared to the second quarter of 2008. However, revenues for our on-system customers increased approximately $7.0 million, or 7.6%, primarily due to the August 2008 Missouri rate increase (discussed below). Rate changes contributed an estimated $6.4 million of the increase in revenues during the second quarter of 2009. Weather and other related factors increased revenues by an estimated $0.5 million compared to last year’s second quarter. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65° F) for the second quarter of 2009 were 21.7% more than the same period last year and 16.6% more than the 30-year average, mainly due to unseasonably hot weather in June of 2009. Residential and commercial sales growth contributed an estimated $0.1 million of the increase in revenues. Our electric customer growth for the twelve months ended June 30, 2009 was 0.2%.

Residential and commercial kWh sales and related revenues increased during the second quarter of 2009 due to the favorable June 2009 weather while revenues also increased due to the 2008 Missouri rate increase.

Industrial kWh sales decreased 6.5% mainly due to a slowdown created by economic uncertainty while the associated revenues increased 1.3% due to the effects of the 2008 Missouri rate increase which offset the economic conditions.

On-system wholesale kWh sales decreased during the second quarter of 2009 reflecting the general economic conditions. Revenues associated with these FERC-regulated sales decreased more than kWh sales as a result of the fuel adjustment clause applicable to such sales. This clause permits the distribution to customers of changes in fuel and purchased power costs.

Off-System Electric Transactions

In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power Pool (SPP) energy imbalance services (EIS) market. See “Competition” below. The majority of our off-system sales margins are now included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and generally adjust the fuel and purchased power expense. As a result, the off-system sales margin flows back to the customer. The following table sets forth information regarding these sales and related expenses for the quarters ended June 30:

(in millions)	2009		2008
EIS revenues	$	0.9	$	4.4
Other revenues	1.7		3.0
Total off-system revenues	2.6		7.4
EIS expenses	0.8		2.7
Other expenses	1.6		2.5
Total off-system expenses	2.4		5.2
Net	$	0.2	$	2.2

*Differences could occur due to rounding.

Revenues and related expenses were less during the second quarter of 2009 as compared to the second quarter of 2008 primarily due to decreased market demand and lower gas prices that made it more economical for utilities to generate their own power rather than purchase it. Total purchased power related expenses are included in our discussion of purchased power costs below.

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Miscellaneous Revenues

Our miscellaneous revenues were $1.4 million for the second quarter of 2009 as compared to $1.5 million in the second quarter of 2008. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions

During the second quarter of 2009, total electric segment operating expenses decreased approximately $1.6 million (1.8%) compared with the same period last year.

Total fuel and purchased power expenses decreased approximately $5.4 million (11.5%) during the second quarter of 2009. The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statement of operations for the second quarter of 2009 and 2008.

(in millions)	2009		2008
Actual fuel and purchased power expenditures	$	38.7	$	46.9
Kansas regulatory adjustments*	0.1		—
Missouri fuel adjustment deferral*	2.6		—
Missouri fuel adjustment recovery**	0.1		—
Unrealized loss on derivatives	—		—
Total fuel and purchased power expense per income statement	$	41.5	$	46.9

*A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.

**Currently being recovered from customers from prior deferral period.

The overall fuel and purchased power decrease reflects decreased generation by both our coal-fired and gas-fired units during the second quarter of 2009. The decrease in fuel costs includes theeffect of decreased market demand resulting from milder weather in April and May of 2009 as well as decreased off-system sales of $2.8 million.

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the second quarter of 2009 as compared to the second quarter of 2008. This table incorporates all the changes mentioned above. As shown below, the largest impact on fuel and purchased power costs was decreased generation by our gas-fired units and lower gas prices which decreased both generation and purchased power costs.

(in millions)	2009
Purchased power (cost per mWh)	$	(4.9	)
Purchased power spot purchase volume	1.4
Coal (cost per mWh)	1.2
Coal generation volume	(1.4		)
Natural gas (cost per mWh)	(2.6		)
Natural gas generation volume	(2.2		)
Other (including fuel adjustments)	3.1
TOTAL	$	(5.4	)

Regulated operating expenses increased approximately $0.5 million (3.1%) during the second quarter of 2009 as compared to the same period in 2008 primarily due to increases of $0.4 million in customer accounts expenses (including $0.2 million in uncollectible accounts), $0.3 million in other steam power expense, $0.3 million in general labor costs, $0.2 million in professional services, $0.1 million in transmission expense and $0.1 million in other power operation expense. These increases were partially offset by decreases of $0.6 million in employee health care expense and $0.3 million in employee pension expense.

Maintenance and repairs expense increased approximately $2.1 million (31.7%) in the second quarter of 2009 as compared to 2008 primarily due to increases of $1.2 million in distribution maintenance costs (including $0.9 million of ice storm related amortization), $0.6 million in

40

maintenance and repairs expense at the Asbury plant and $0.3 million in maintenance and repairs expense at the State Line Combined Cycle (SLCC) plant.

Depreciation and amortization expense decreased approximately $1.2 million (8.9%) during the quarter primarily due to reduced regulatory amortization resulting from the 2008 Missouri rate case that went into effect on August 23, 2008. Other taxes increased approximately $0.3 million during the second quarter of 2009 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers decreased during the six months ended June 30, 2009 as compared to the six months ended June 30, 2008 primarily due to milder weather in the first 5 months of 2009 as compared to the same period in 2008. However, revenues for our on-system customers increased approximately $8.5 million, or 4.5%. Rate changes contributed an estimated $13.3 million during the six months ended June 30, 2009 while sales growth contributed an estimated $0.5 million. Weather and other related factors decreased revenues by an estimated $5.3 million compared to the six months ended June 30, 2008.

The decrease in residential kWh sales during the six months ended June 30, 2009 was primarily due to the mild weather in 2009. The related revenues increased during the second quarter of 2009, primarily as a result of the 2008 Missouri rate increase.

Commercial kWh sales and revenues increased during the six months ended June 30, 2009 due to sales growth while the increase in revenues was also due to the 2008 Missouri rate increase.

Industrial kWh sales decreased 7.4% mainly due to a slowdown created by economic uncertainty while the associated revenues increased 0.8% due to the effects of the Missouri rate increase which offset the economic conditions.

On-system wholesale kWh sales decreased during the six months ended June 30, 2009 reflecting the economic conditions and mild weather discussed above while the revenues associated with these FERC-regulated sales decreased more as a result of the fuel adjustment clause applicable to such sales.

Off-System Electric Transactions

In addition to sales to our own customers, we also sell power to other utilities as available, including through the SPP EIS market. See “Competition” below. The majority of our off-system sales margins are now included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and generally adjust the fuel and purchased power expense. The following table sets forth information regarding these sales and related expenses for the six months ended June 30:

(in millions)	2009		2008
EIS revenues	$	2.4	$	7.4
Other revenues	4.2		7.4
Total off-system revenues	6.6		14.8
EIS expenses	2.0		5.0
Other expenses	3.6		5.9
Total off-system expenses	5.6		10.9
Net	$	1.0	$	3.9

*Differences could occur due to rounding.

Revenues and related expenses were less during the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to decreased market demand resulting from

41

mild weather and decreased gas prices. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $3.2 million for the six months ended June 30, 2009 as compared to $3.3 million during the same period in 2008. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions

During the six months ended June 30, 2009, total electric segment operating expenses decreased approximately $8.4 million (4.5%) compared with the same period last year.

Total fuel and purchased power expenses decreased approximately $15.5 million (15.0%) during the six months ended June 30, 2009. The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statement of operations for the six months ended June 30, 2009 and 2008.

(in millions)	2009			2008
Actual fuel and purchased power expenditures	$	88.4		$	104.4
Kansas regulatory adjustments*	0.4			(0.5		)
Missouri fuel adjustment deferral*	(0.5		)	—
Missouri fuel adjustment recovery**	0.1			—
Unrealized loss on derivatives	—			—
Total fuel and purchased power expense per income statement	$	88.4		$	103.9

*A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.

**Currently being recovered from customers from prior deferral period.

The overall fuel and purchased power expenses decrease reflects decreased generation by both our coal-fired and gas-fired units during the six months ended June 30, 2009 as compared to the same period in 2008. The decrease in fuel costs includes the effect of decreased market demand resulting from milder weather in 2009 as well as decreased off-system sales of $5.3 million.

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the six months ended June 30, 2009 as compared to the six months ended June 30, 2008. This table incorporates all the changes mentioned above. As shown below, the largest impact on fuel and purchased power costs was decreased generation by our gas-fired units and lower gas prices which decreased both generation and purchased power costs.

(in millions)	2009
Purchased power (cost per mWh)	$	(8.5	)
Purchased power spot purchase volume	1.4
Coal (cost per mWh)	2.7
Coal generation volume	(1.4		)
Natural gas (cost per mWh)	(4.7		)
Natural gas generation volume	(8.2		)
Natural gas – gain on unwind of positions	2.1
Other (including fuel adjustments)	1.1
TOTAL	$	(15.5	)

Regulated operating expenses for our electric segment decreased approximately $0.3 million (0.9%) during the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to decreases of $1.2 million in employee health care expense, $0.5 million in employee pension expense, $0.2 million in injuries and damages expense and $0.2 million in distribution expense. These decreases were partially offset by increases of $0.7 million in other

42

steam power expense, $0.5 million in professional services, $0.4 million in customer accounts expenses (including $0.2 million in uncollectible accounts) and $0.2 million in transmission expense.

Maintenance and repairs expense increased approximately $4.3 million (35.9%) during the six months ended June 30, 2009 as compared to 2008 primarily due to increases of $2.7 million in distribution maintenance costs (including $1.9 million of ice storm related amortization), $0.8 million in maintenance and repairs expense due to the SLCC maintenance outage in the first quarter of 2009, $0.6 million in maintenance and repairs expense at the Asbury plant, $0.1 million in maintenance and repairs expense at the Iatan plant and $0.1 million in transmission maintenance expense.

Depreciation and amortization expense decreased approximately $2.2 million (8.3%) during the six months ended June 30, 2009 primarily due to reduced regulatory amortization resulting from the 2008 Missouri rate case that went into effect on August 23, 2008. Other taxes increased approximately $0.5 million during the six months ended June 30, 2009 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Twelve Months Ended June 30, 2009 Compared to Twelve Months Ended June 30, 2008

On-System Operating Revenues and Kilowatt-Hour Sales

For the twelve months ended June 30, 2009, kWh sales to our on-system customers decreased 2.6% with the associated revenues increasing approximately $12.1 million (3.0%). Rate changes, primarily the August 2008 Missouri rate increase (discussed below), contributed an estimated $21.5 million to revenues while continued sales growth contributed an estimated $2.3 million. Weather and other related factors decreased revenues an estimated $11.7 million.

The decrease in residential kWh sales during the twelve months ended June 30, 2009 was primarily due to the mild weather in 2009 and the third quarter of 2008. The related revenues increased during the twelve months ended June 30, 2009 primarily as a result of the 2008 Missouri rate increase. Commercial kWh sales increased primarily due to sales growth while the increase in associated revenues was also due to the 2008 Missouri rate increase. Industrial kWh sales decreased mainly due to a slowdown created by economic uncertainty while the associated revenues increased due to the effects of the Missouri rate increase which offset the economic conditions. On-system wholesale kWh sales and revenues decreased reflecting the general economic conditions and mild weather.

Off-System Electric Transactions

In addition to sales to our own customers, we also sell power to other utilities as available, including through the SPP EIS market. See “Competition” below. The majority of our off-system sales margins are now included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and generally adjust the fuel and purchased power expense. The following table sets forth information regarding these sales and related expenses for the twelve months ended June 30:

(in millions)	2009		2008
EIS revenues	$	8.1	$	12.9
Other revenues	13.4		14.2
Total off-system revenues	21.5		27.1
EIS expenses	6.4		9.0
Other expenses	9.8		10.8
Total off-system expenses	16.2		19.8
Net	$	5.3	$	7.3

*Differences could occur due to rounding.

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Revenues and related expenses were less during the twelve months ended June 30, 2009 as compared to the same period in 2008 primarily due to decreased market demand. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $6.9 million for the twelve months ended June 30, 2009 as compared to $6.2 million during the same period in 2008. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions

During the twelve months ended June 30, 2009, total electric segment operating expenses decreased approximately $6.0 million (1.6%) compared with the same period last year.

Total fuel and purchased power expenses decreased approximately $19.3 million (9.3%) during the twelve months ended June 30, 2009. The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statement of operations for the twelve months ended June 30, 2009 and 2008.

(in millions)	2009			2008
Actual fuel and purchased power expenditures	$	188.1		$	208.3
Kansas regulatory adjustments*	0.3			(0.5		)
Missouri fuel adjustment deferral*	(0.3		)	—
Missouri fuel adjustment recovery**	0.1			—
Unrealized loss on derivatives	0.3			—
Total fuel and purchased power expense per income statement	$	188.5		$	207.8

*A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.

**Currently being recovered from customers from prior deferral period.

The overall fuel and purchased power expenses decrease includes theeffect of decreased market demand resulting from mild weather in 2009 and the third quarter of 2008, as well as the effects of an extended outage at the Asbury plant lasting from the fourth quarter of 2007 into the first quarter of 2008 during which time we relied on purchased power and our gas-fired units to replace our coal-fired generation. The decrease in fuel costs includes the effect of decreased off-system sales of $3.6 million.

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the twelve months ended June 30, 2009 as when compared to the twelve months ended June 30, 2008. This table incorporates all the changes mentioned above. As shown below, the largest impact on fuel and purchased power costs was decreased generation by our gas-fired units and lower gas prices which decreased both generation and purchased power costs.

(in millions)	2009
Purchased power (cost per mWh)	$	(5.5	)
Purchased power spot purchase volume	(0.8		)
Coal (cost per mWh)	5.7
Coal generation volume	1.8
Natural gas (cost per mWh)	(11.8		)
Natural gas generation volume	(13.0		)
Natural gas – gain on unwind of positions	2.1
Other (including fuel adjustments)	2.2
TOTAL	$	(19.3	)

Regulated operating expenses for our electric segment increased approximately $0.2 million (0.3%) during the twelve months ended June 30, 2009 as compared to the same period in 2008 primarily due to increases of $1.2 million in other steam power expense, $0.5 million in injuries and

44

damages expense, $0.4 million in transmission expense, $0.3 million in professional services, $0.3 million in other power supply expense, $0.2 million in director and stockholder expense, and $0.2 million in property insurance expense. These increases were partially offset by decreases of $1.7 million in employee health care expense, $0.9 million in employee pension expense, $0.2 million in general labor costs and $0.1 million in uncollectible accounts.

Maintenance and repairs expense increased approximately $5.6 million (21.3%) during the twelve months ended June 30, 2009 as compared to 2008 primarily due to increases of $3.1 million in distribution maintenance costs (including $3.3 million of ice storm related amortization), $0.9 million in maintenance and repairs expense due to the SLCC maintenance outage in the first quarter of 2009, $0.9 million in maintenance and repairs expense at the Iatan plant due to an outage in the fourth quarter of 2008, $0.4 million in maintenance and repairs expense at the Riverton plant mainly due to the extended outage on Unit 8 to repair damage to high pressure blades discovered during Riverton’s scheduled maintenance outage in May 2008, $0.4 million in maintenance and repairs expense at the Asbury plant, and $0.3 million in transmission expense. These increases were partially offset by a $0.4 million decrease in maintenance and repairs expense at the Energy Center plant.

Depreciation and amortization expense decreased approximately $3.0 million (5.9%) during the twelve months ended June 30, 2009 primarily due to reduced regulatory amortization resulting from the 2008 Missouri rate case that went into effect on August 23, 2008. Other taxes increased approximately $0.4 million during the twelve months ended June 30, 2009 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

Gas Operating Revenues and Sales

Total Gas Delivered to Customers

	Three Months Ended				Six months ended				Twelve months ended
			%				%				%
bcf sales	2009	2008	change		2009	2008	change		2009	2008	change
Residential	0.29	0.32	(10.0	)%	1.60	1.85	(13.5	)%	2.70	2.97	(9.0	)%
Commercial	0.15	0.17	(8.3	)	0.72	0.84	(14.0	)	1.28	1.38	(7.3	)
Industrial*	0.02	0.15	(89.5	)	0.17	0.20	(16.0	)	0.52	0.25	108.5
Other**	0.00	0.00	(25.9	)	0.02	0.03	(18.0	)	0.03	0.03	(6.5	)
Total retail sales	0.46	0.64	(28.3	)	2.51	2.92	(13.9	)	4.53	4.63	(2.1	)
Transportation sales	0.92	0.85	9.5		2.08	2.20	(5.5	)	3.94	4.23	(6.9	)
Total gas operating sales	1.38	1.49	(6.9	)	4.59	5.12	(10.3	)	8.47	8.86	(4.4	)

*Percentage change reflects the transfer of a customer from transportation to industrial sales in April 2008 and back to transportation in May 2009.

**Other includes other public authorities and interdepartmental usage.

Operating Revenues and Cost of Gas Sold

	Three Months Ended						Six months ended						Twelve months ended
($ in millions)	2009		2008		% change		2009		2008		% change		2009		2008		% change
Residential	$	4.9	$	5.0	(2.6	)%	$	23.0	$	23.1	(0.6	)%	$	39.5	$	38.3	3.1	%
Commercial	2.1		2.2		(3.0	)	9.5		9.6		(1.2	)	17.3		16.3		5.9
Industrial*	0.2		1.4		(85.0	)	1.6		1.8		(9.9	)	4.9		2.3		118.2
Other**	0.0		0.0		(19.9	)	0.3		0.3		(5.7	)	0.4		0.4		7.3
Total retail revenues	$	7.2	$	8.6	(15.9	)	$	34.4	$	34.8	(1.3	)	$	62.1	$	57.3	8.4
Other revenues	0.0		0.0		(15.8	)	0.1		0.1		0.1		0.2		0.2		0.4
Transportation revenues*	0.7		0.5		28.4		1.5		1.5		1.7		2.7		2.8		(3.0	)
Total gas operating revenues	$	7.9	$	9.1	(13.4	)	$	36.0	$	36.4	(1.1	)	$	65.0	$	60.3	7.9
Cost of gas sold	4.2		5.3		(20.5	)	23.5		23.0		2.3		43.1		37.2		16.1
Gas operating revenues over cost of gas in rates	$	3.7	$	3.8	(3.7	)	$	12.5	$	13.4	(7.0	)	$	21.9	$	23.1	(5.3	)

*Percentage change reflects the transfer of a customer from transportation to industrial sales in April 2008 and back to transportation in May 2009.

**Other includes other public authorities and interdepartmental usage.

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Quarter Ended June 30, 2009 Compared to Quarter Ended June 30, 2008

Operating Revenues and bcf Sales

Gas retail sales decreased 28.3% during the second quarter of 2009 as compared to 2008 primarily due to mild weather, customer contraction of 1.07% and the suspension of operations by a large volume industrial customer. Gas sales are less during the summer months as the heating season runs from November to March of each year. Residential sales decreased 10.0% and commercial sales decreased 8.3% during the second quarter of 2009 as compared to the second quarter of 2008 primarily due to the mild weather and customer contraction. Heating degree days were 8.6% lower in the second quarter of 2009 as compared to the second quarter of 2008. Industrial sales decreased during the second quarter of 2009 as compared to the same period in 2008 due to the suspension of operations by a large volume industrial customer in the first quarter of 2009.

During the second quarter of 2009, gas segment revenues were approximately $7.9 million as compared to $9.1 million in the second quarter of 2008, a decrease of 13.4%. During the second quarter of 2009, our PGA revenue (which represents the cost of gas recovered from our customers) was approximately $4.2 million as compared to $5.3 million in the second quarter of 2008, a decrease of approximately $1.1 million. This decrease was largely driven by the decrease in industrial sales and a decrease in the PGA that went into effect May 15, 2009.

Our PGA clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of June 30, 2009, we had unrecovered purchased gas costs of $0.3 million recorded as a regulatory asset.

Operating Revenue Deductions

Total other operating expenses were approximately $2.6 million during both the second quarter of 2009 and 2008 although uncollectible accounts decreased $0.2 million in the second quarter of 2009 as compared to the same period in 2008. Our gas segment had a net loss of $0.8 million for the second quarter of 2009 as compared to a net loss of $0.6 million for the second quarter of 2008, which is not unexpected due to the seasonality of the gas segment whose heating season runs from November to March of each year.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Operating Revenues and bcf Sales

Gas retail sales decreased 13.9% during the six months ended June 30, 2009 as compared to the same period in 2008 mainly due to mild weather in the first and second quarters of 2009, customer contraction and the suspension of operations by a large volume industrial customer in the first quarter of 2009. Residential and commercial sales decreased during the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to the milder weather and customer contraction. Industrial sales decreased during the six months ended June 30, 2009 as compared to the same period in 2008 mainly due to the suspension of operations by a large volume industrial customer in the first quarter of 2009.

During the six months ended June 30, 2009, gas segment revenues were approximately $36.0 million as compared to $36.4 million in the six months ended June 30, 2008, a decrease of 1.1%. This decrease was largely driven by the decrease in industrial sales, which offset a slight increase in PGA revenues. During the six months ended June 30, 2009, our PGA revenue was approximately $23.5 million as compared to $23.0 million during the six months ended June 30, 2008, an increase of approximately $0.5 million.

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Operating Revenue Deductions

Total other operating expenses were $5.4 million for the six months ended June 30, 2009 as compared to $5.1 million for the six months ended June 30, 2008. This increase was mainly due to an increase of $0.2 million in uncollectible accounts and an increase of $0.1 million in employee health care expense and employee pension expense. Our gas segment had net income of $1.0 million for the six months ended June 30, 2009 as compared to $1.8 million for the six months ended June 30, 2008.

Twelve Months Ended June 30, 2009 Compared to Twelve Months Ended June 30, 2008

Operating Revenues and bcf Sales

Gas retail sales decreased 2.1% during the twelve months ended June 30, 2009 mainly due to a decrease in residential and commercial sales as compared to 2008. Industrial sales increased during the twelve months ended June 30, 2009 as compared to the same period in 2008 due to the transfer of a large volume industrial customer from transportation to sales service and the addition of a new large volume industrial customer in the second quarter of 2008.

During the twelve months ended June 30, 2009, gas segment revenues were approximately $65.0 million as compared to $60.3 million in the twelve months ended June 30, 2008, an increase of 7.9%. This increase was largely driven by the increase in industrial sales and PGA revenue. During the twelve months ended June 30, 2009, our PGA revenue was approximately $43.1 million as compared to $37.2 million during the twelve months ended June 30, 2008, an increase of approximately $5.9 million.

Operating Revenue Deductions

Total other operating expenses were $10.4 million for the twelve months ended June 30, 2009 as compared to $9.9 million for the twelve months ended June 30, 2008. This increase was mainly due to a $0.3 million increase in customer accounts expense and a $0.2 million increase in distribution operation expense. Our gas segment had net income of $0.9 million for the twelve months ended June 30, 2009 as compared to $1.8 million for the twelve months ended June 30, 2008.

Other Segment

Our other segment consists of our non-regulated business, primarily the leasing of fiber optics cable and equipment (which we are also using in our own utility operations). The following table represents the results for our other segment for the applicable periods ended June 30 (in millions):

	Three Months Ended				Six Months Ended				Twelve Months Ended
(in millions)	2009		2008		2009		2008		2009		2008
Revenues	$	1.4	$	1.3	$	2.7	$	2.4	$	5.3	$	4.3
Expenses	1.0		1.0		2.0		1.9		4.5		3.5
Net income*	$	0.4	$	0.3	$	0.7	$	0.5	$	0.8	$	0.9

*Differences could occur due to rounding.

Consolidated Company

Income Taxes

Our consolidated provision for income taxes increased approximately $2.1 million during the second quarter of 2009 as compared to the same period in 2008 mainly due to increased income. Our consolidated effective federal and state income tax rate for the second quarter of 2009 was 34.7% as compared to 31.9% for the second quarter of 2008.

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Our consolidated provision for income taxes increased approximately $4.5 million during the six months ended June 30, 2009 as compared to the same period in 2008. This resulted primarily from increased income. Our consolidated effective federal and state income tax rate for the six months ended June 30, 2009 was 34.2% as compared to 31.2% for the same period in 2008.

Our consolidated provision for income taxes increased approximately $8.5 million during the twelve months ended June 30, 2009 as compared to the twelve months ended June 30, 2008, primarily resulting from higher income. Our effective federal and state income tax rate for the twelve months ended June 30, 2009 was 33.5% as compared to 30.8% for the same period in 2008.

The rate in all periods is higher primarily due to lower tax benefits received from cost of plant retirement expenditures. Our cost of retirement expenditures was unusually high during the twelve months ended June 30, 2008 due to the ice storms we experienced. This reduced benefit during this period was partially offset by an increase in the tax effects of equity AFUDC.

Nonoperating Items

Total allowance for funds used during construction (AFUDC) increased $0.3 million in the second quarter of 2009 as compared to 2008. AFUDC increased $1.5 million during the six months ended June 30, 2009 and increased $4.5 million during the twelve months ended June 30, 2009 as compared to the same periods in the prior year due to higher levels of construction in each period.

Total interest charges on long-term and short-term debt for the periods ended June 30, 2009 are shown below. The increases in long-term debt interest for all three periods reflect the interest on the $90 million principal amount of first mortgage bonds we issued May 16, 2008, and the $75 million principal amount of first mortgage bonds we issued March 27, 2009. The decreases in short-term debt interest for all three periods reflect lower cost of borrowing.

	Interest Charges
	(in millions)
	Second		Second			6 Months		6 Months			12 Months		12 Months
	Quarter		Quarter	%		Ended		Ended	%		Ended		Ended	%
	2009		2008	Change*		2009		2008	Change*		2009		2008	Change*
Long-term debt interest	10.9		8.8	23.5	%	20.5		16.9	21.5	%	39.7		33.0	20.1	%
Short-term debt interest	0.2		0.3	(33.8	)	0.8		0.8	(6.8	)	1.8		2.4	(26.4	)
Note payable to securitization trust interest	1.1		1.1	0.0		2.1		2.1	0.0		4.2		4.2	0.0
Iatan carrying charges	(0.6	)	—	—		(0.6	)	—	—		(0.6	)	—	—
Other interest	0.1		0.3	(50.9	)	0.3		0.6	(44.3	)	0.9		1.1	(14.8	)
Total interest charges	11.7		10.5	11.2		23.1		20.4	13.3		46.0		40.7	12.8

We had no gains or losses from discontinued operations in the twelve months ended June 30, 2009 compared to a gain of $0.1 million for the twelve months ended June 30, 2008.

Other Comprehensive Income

The change in the fair value of the effective portion of our open gas contracts designated as cash flow hedges entered into prior to September 1, 2008 for our electric segment and the gains and losses on these contracts settled during the periods being reported, including the tax effect of these items, are reflected in our Consolidated Statement of Comprehensive Income. The fair value of open electric segment derivative contracts purchased prior to September 1, 2008, the effective date of our fuel adjustment mechanism, increased $1.9 million in the second quarter of 2009, reflecting falling natural gas prices. This net change is recorded as accumulated other comprehensive income in the capitalization section of our balance sheet and does not affect net income or earnings per share. All of these contracts have been designated as cash flow hedges. The unrealized gains and losses accumulated in other comprehensive income are reclassified to fuel and purchased power in the periods in which the hedged transaction is actually realized or no longer qualifies for hedge accounting.

The following table sets forth the pre-tax gains/(losses) of this activity and the related tax effect in Other Comprehensive Income for the presented periods ended June 30:

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	Three Months Ended						Six Months Ended						Twelve Months Ended
(in millions)	2009			2008			2009			2008			2009			2008
Natural gas contracts settled (1)	$	1.7		$	(1.7	)	$	6.7		$	(2.6	)	$	5.4		$	(4.1	)
Change in FMV of open contracts for natural gas	$	1.9		$	22.8		$	(7.5	)	$	33.8		$	(58.7	)	$	30.4
Taxes	$	(1.4	)	$	(8.0	)	$	0.3		$	(11.9	)	$	20.3		$	(10.0	)
Total change in OCI – net of tax	$	2.2		$	13.1		$	(0.5	)	$	19.3		$	(33.0	)	$	16.3

(1) Reflected in fuel expense.

RATE MATTERS

We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.

Electric Segment

The following table sets forth information regarding electric and water rate increases since January 1, 2007:

		Annual		Percent
	Date	Increase		Increase		Date
Jurisdiction	Requested	Granted		Granted		Effective
Missouri - Electric	October 1, 2007	$	22,040,395	6.70	%	August 23, 2008

Missouri

2007 Rate Case

The MPSC issued an order on July 30, 2008 in response to a request filed with the MPSC on October 1, 2007 for an annual increase in base rates for our Missouri electric customers. This order granted an annual increase in revenues for our Missouri electric customers in the amount of $22.0 million, or 6.7%, based on a 10.8% return on equity. The new rates went into effect August 23, 2008.

The order contains two components. The first component provides an addition to base rates of approximately $27.7 million. This increase in base rates was partially offset by a $5.7 million reduction to regulatory amortization, which is the second component to support certain credit metrics of the overall change in revenue authorized by the MPSC. Regulatory amortization provides us additional cash through rates during the current construction cycle. This construction, which is part of our long-range plan to ensure reliability, includes the facilities at the Riverton Power Plant and Iatan 2 Power Plant, as well as environmental improvements at the Asbury Power Plant and at Iatan 1. The regulatory amortization is now approximately $4.5 million annually and is recorded as depreciation expense.

The MPSC also authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. The MPSC established a base cost for the recovery of fuel and purchased power expenses used to supply energy. The clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, the off-system sales margin flows back to the customer. Rates related to the recovery of fuel and purchased power costs will be modified twice a year subject to the review and approval by the MPSC. In accordance with FAS 71, 95% of the difference between the actual cost of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or a regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered or refunded to our customers when the fuel adjustment clause is modified. On April 1, 2009, we filed proposed rate schedules with the MPSC requesting an increase of $1.9 million in revenues for the under recovered

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fuel costs recognized for the six month period ended February 28, 2009. This increase in revenue was approved by the MPSC on May 21, 2009, became effective June 1, 2009 and will be billed through our fuel adjustment clause.

The MPSC order in the rate case approved a Stipulation and Agreement providing for the recovery of deferred expenses of approximately $14.2 million over a five year period for the 2007 ice storms. In addition, the MPSC order required the implementation of a two-way tracking mechanism for recovery of the costs relating to the new MPSC rules on infrastructure inspection and vegetation management. The mechanism authorized by the MPSC creates a regulatory liability in any year we spend less than the target amount, which has been set at $8.6 million for our Missouri jurisdiction, and a regulatory asset if we spend more than the target amount. Any regulatory asset and liability amounts created using the tracking mechanism will then be netted against each other and taken into account in our next rate case. The MPSC also approved Stipulations and Agreements providing for the continuation of the pension and other post-retirement employee benefits tracking mechanism established in our 2006 and 2007 Missouri rate orders.

The MPSC issued its Report and Order on July 30, 2008, effective August 9, 2008. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed applications for rehearing with the MPSC regarding this order. On August 12, 2008, the MPSC issued its Order Granting Expedited Treatment and Approving Compliance Tariff Sheets, effective August 23, 2008, in which the MPSC approved our tariff sheets containing our base rates for service rendered on and after August 23, 2008, and approved our fuel adjustment clause tariff sheets effective September 1, 2008. On September 3, 2008, the MPSC denied all pending applications for rehearing.

On October 2, 2008, the OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the Cole County Circuit Court. These actions were consolidated into one proceeding, and briefs have been filed with the Cole County Circuit Court.

2006 Rate Case

All pending applications for rehearing in our Missouri 2006 rate case were denied by the MPSC on November 20, 2008. On December 15, 2008, the OPC filed a Petition for Writ of Review with the Cole County Circuit Court regarding the MPSC’s decisions in our 2006 rate case. Praxair and Explorer Pipeline filed a Petition for Writ of Review on December 19, 2008. These actions were consolidated into one proceeding. Briefs have been filed by all parties and oral arguments were held on June 2, 2009.

On May 13, 2009, the OPC filed a petition in the Jasper County Circuit Court seeking refunds with regard to utility rates for electric service paid by our customers during the period of January 1, 2007 to December 13, 2007. During this period, we charged the rates set forth in the tariffs which were approved by, and are on file with, the MPSC. We filed a motion to dismiss, or, in the alternative, motion for more definitive statement. Oral arguments are scheduled for August 28, 2009.

Kansas

The Kansas Corporation Commission (KCC) approved a Joint Stipulated Settlement Agreement on December 9, 2005 effective January 4, 2006, in relation to our last Kansas rate case. Pursuant to the Agreement, we sought KCC approval of an explicit natural gas hedging program in a separate docket by March 1, 2006. We requested and received an extension until April 1, 2006 and made this filing on March 30, 2006, which was denied in a February 4, 2008 order by the KCC. As a result, all gains or losses related to the financial instruments used to fix the future price of natural gas will be excluded from the Energy Cost Adjustment clause implemented in the last Kansas rate case and future base electric rates in Kansas.

Gas Segment

On June 5, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri gas customers in the amount of $2.9 million, or 4.9%. In this filing, we requested

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recovery of the ongoing cost of operating and maintaining our 1,200-mile gas distribution system and a return on equity of 11.3%. Results from this case would likely take effect in the second quarter of 2010.

COMPETITION

Electric Segment

SPP-RTO

On February 1, 2007, the Southwest Power Pool (SPP) regional transmission organization (RTO) launched its energy imbalance services market (EIS). In general, the SPP RTO EIS market provides real time energy for most participating members within the SPP regional footprint. Imbalance energy prices are based on market bids and status/availability of dispatchable generation and transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO performs a real time security-constrainedeconomic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native load.

The SPP and its members have been evaluating the costs and benefits on expanding the EIS market into a full day ahead energy market with a co-optimized ancillary services market, which will include the consolidation of all SPP balancing authorities, including ours, into a single SPP balancing authority. On April 28, 2009, the SPP Regional State Committee (SPP RSC), whose members include state commissioners from our four state commissions, and the SPP Board of Directors (SPP BOD) endorsed a cost benefit report that recommended the SPP RTO move forward with the development of a day-ahead market with unit commitment and co-optimized ancillary services market (Day-Ahead Market) and implement the complete Day-Ahead Market as soon as practical, which is anticipated in late 2012 or early 2013. As part of the Day-Ahead Market, the SPP RTO will create, prior to implementation of such market, a single NERC approved balancing authority to take over balancing authority responsibilities for its members, including us, which is expected to provide operational and economic benefits for us and our customers. The implementation of the Day-Ahead Market will replace the existing EIS market, which to date has, and is expected to continue to, provide benefits for our customers.

On August 15, 2008, the SPP filed with the FERC proposed revisions to its open access transmission pro forma tariff (OATT) to establish a process for including a “balanced portfolio” of economic transmission upgrades in the annual SPP Transmission Expansion Plan. The cost of such upgrades will be recovered through a regional rate allocated to SPP members based on their load ratio share within SPP’s market area of the balanced portfolio’s cost. On October 16, 2008, the FERC accepted the balanced portfolio approach, which sets forth the selection process of a group of projects and regional cost allocation rules based on projected benefits and allocated costs over a ten year period. The plan will be balanced if the portfolio is cost beneficial for each zone, including ours, within the SPP. A balanced portfolio could include projects below the 345 kv level (which is the bright line voltage level for projects to be included in the portfolio) to increase benefits to a particular zone to achieve balance of benefits and costs over the ten year study period. On April 28, 2009, the SPP RSC and the SPP BOD approved the first set of balanced portfolio extra high voltage transmission projects to be constructed within the SPP region. The transmission expansion projects, totaling over $700 million, include projects in Missouri, Kansas, Arkansas, Oklahoma, Nebraska and Texas. We anticipate this set of transmission expansion projects will provide long term benefits to our customers yet expect our share of the net allocated costs to be immaterial. Also on April 28, 2009, the SPP RSC and BOD approved a new report that recommends restructuring of the SPP’s regional planning processes, which would establish an integrated planning process for reliability, transmission service and economic transmission projects, based on a new set of planning principles that focus on the construction of a more robust transmission system large enough in both scale and geography to provide flexibility to meet SPP members’ and customers’ future needs. We will actively participate in the development of these new processes as well as cost allocation and recovery issues with members, prospective customers and the state commission representatives to the SPP RSC.

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FERC Market Power Order

On March 3, 2005, the FERC issued an order commencing an investigation to determine if we had market power within our control area based on our failure to meet one of the FERC’s wholesale market share screens. We filed responses to that order in May and June 2005 and in early January 2006. On August 15, 2006, the FERC issued its order accepting Empire’s proposed mitigation to become effective May 16, 2005, subject to a further compliance filing as directed in the order. Relying on a series of orders issued since March 17, 2006 in other proceedings, the FERC rejected our tariff language and directed us to file revisions to our market-based tariff to provide that service under the tariff applies only to sales outside our control area. The FERC directed us to make refunds, with interest, by September 15, 2006, covering over 1,000 hourly energy sales since May 16, 2005 to numerous counterparties external to our system for wholesale sales made at market prices above the cost based prices permitted under the mitigation proposal accepted by the FERC. The refund obligation applied to certain wholesale power sales made “inside” our service area at market based rates, even though consumption of the energy occurred outside our service area.

On September 14, 2006, we filed a Request For Rehearing of the FERC’s August 15, 2006 order regarding the refund and market power mitigation we had proposed. We requested a rehearing and a waiver of the refund requirement in its entirety. On April 25, 2008, the FERC issued an Order that rejected our Request For Rehearing, required a Compliance Filing of our market based rate tariff and ordered refunds with interest. We made our Compliance Filing and issued refunds totaling $340,608, including interest, on May 27, 2008. We also filed an informational refund report with the FERC on June 26, 2008.

As a result of the FERC’s requirement for us to issue the aforementioned refunds and our belief that the FERC erred in its orders, on June 30, 2008 we initiated a Petition For Review of the FERC’s orders on our market based rate refunds in the United States Court of Appeals for the District ofColumbia Circuit (DC Circuit). We requested and received approval for a consolidation of our Petition with a similar petition by Westar Energy. On June 12, 2009, the DC Circuit denied our and Westar’s Petition for FERC to review its Order requiring the refunds to be made, concluding our efforts to recover the refunds paid.

As part of our market based pricing authority, we are required to conduct a market power analysis within our service territory and within the SPP RTO region every three years. We anticipate that our next filing will occur during the third quarter of 2009 and will not show any material changes to our market position and existing market based rate authority.

Other FERC Activity

On June 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking (ANOPR) on potential reforms to improve operations in organized wholesale power markets, such as the SPP RTO in which we participate. On October 16, 2008, the FERC issued its Final Order on Wholesale Competition in Regions with Organized Electric Markets. The Final Order will affect us as it directly affects the SPP RTO. The Final Order addresses four key areas for amending its regulations in Wholesale Competition for RTOs and Independent System Operators (ISOs): (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market monitoring policies; and (4) the responsiveness of RTOs and ISOs to stakeholders and customers. We will be involved in the SPP RTOs discussions on compliance of these new rules.

On May 21, 2009, the FERC issued an order clarifying that, going forward, small public utilities that have been granted waiver of Order No. 889 (Open Access Same Time Information Systems (OASIS) requirement) and the Standards of Conduct for transmission operations, which includes us, are required to submit a notification filing if there has been a material change in facts that may affect the basis on which a public utility’s waiver was premised. The Standards of Conduct generally govern the communications between our day to day transmission operations personnel and our day to day wholesale marketing and sales personnel. We submitted our filing on July 13, 2009 in which we believe continuation of our waiver, issued in 1997 and reaffirmed in 2004, is appropriate and reasonable. Based on the May 21, 2009 order, it is possible that the FERC will

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revoke our waiver which would impact communication between our transmission and wholesale marketing and sales functions and operations within our organization. As part of our filing, we sought a twelve month extension in order to comply with the Standard of Conduct requirements in the event the FERC determined that revoking our waiver was appropriate. The FERC’s decision on this and other Standard of Conduct waiver filings is expected during the third quarter of 2009.

LIQUIDITY AND CAPITAL RESOURCES

We used approximately $84.5 million of cash for capital expenditures during the six months ended June 30, 2009. Our primary source of cash for these expenditures during the six months ended June 30, 2009 was $60.0 million in cash provided by operating activities. As of June 30, 2009, our working capital was negative (current liabilities exceeded current assets), primarily due to the reclassification of $70 million of long-term debt to reflect its current maturity and the continued use of short-term debt to fund our construction program. Our current maturities include $20 million due November 1, 2009 and $50 million due April 1, 2010. We expect to refinance the long-term debt and continue to use short-term debt under our unsecured credit agreements. We also have an equity distribution program in place which is designed to provide additional funds from the issuance of equity from time to time.

Summary of Cash Flows (in millions)

	Six Months Ended June 30,
	2009			2008
Cash provided by (used in):
Operating activities	$	60.0		$	66.1
Investing activities	(84.0		)	(114.2		)
Financing activities	24.6			47.4
Net change in cash and cash equivalents	$	0.6		$	(0.7	)

Operating Activities

Our net cash flows provided by continuing operating activities were $60.0 million during the six months ended June 30, 2009 as compared to $66.1 million for the six months ended June 30, 2008. This $6.1 million decrease was primarily due to changes in the level of accounts payable. In the six month period ended June 30, 2008, we received $17.7 million in collateral from one of our counterparties. This collateral was refunded subsequent to June 30, 2008 and no comparable receipt of cash took place in the six month period ended June 30, 2009. The effect of this change in accounts payable was offset by positive cash effects of $6.7 million in higher net income and increases to net income for non cash expenses, including deferred income taxes and non-cash losses on derivatives settling through our margin accounts.

Capital Requirements and Investing Activities

Our net cash flows provided by investing activities decreased $30.2 million during the six months ended June 30, 2009 to $84.0 million as compared to $114.2 million in the six months ended June 30, 2008 and decreased $10.5 million to $42.4 million in the second quarter of 2009 as compared to $52.9 million in the second quarter of 2008. This change occurred primarily due to a decrease in capital expenditures. The 2008 capital expenditures reflect cash outlays for the December 2007 ice storm. These expenditures were incurred in 2007 but paid in the first quarter of 2008. In addition, expenditures for new generation and distribution and transmission system additions are lower this year than last. Partially offsetting the capital expenditures during the six months ended June 30, 2009 were proceeds from the sale of land totaling $0.5 million.

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A breakdown of the capital expenditures for the quarter and six months ended June 30, 2009 is as follows:

	Capital Expenditures
	Quarter Ended			Six Months Ended
(in millions)	June 30, 2009			June 30, 2009
Distribution and transmission system additions	$	7.0		$	17.2
New Generation – Plum Point Energy Station	4.0			9.0
New Generation – Iatan 2	15.3			31.5
Storms	6.0			6.3
Additions and replacements – electric plant	8.7			17.5
Gas segment additions and replacements	0.4			0.8
Transportation	0.6			0.8
Other (including retirements and salvage -net) (1)	(0.9		)	(1.6		)
Subtotal	41.1			81.5
Non-regulated capital expenditures (primarily fiber optics)	0.2			0.8
Subtotal capital expenditures incurred (2)	41.3			82.3
Adjusted for capital expenditures payable (3)	1.3			2.2
Total cash outlay	$	42.6		$	84.5

(1) Other includes equity AFUDC of $(2.6) million.

(2) Expenditures incurred represent the total cost for work completed for the projects during the quarter. Discussion of capital expenditures throughout this 10-Q is presented on this basis. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

(3) Represents the change in unpaid capital expenditures since the beginning of the year which is not reflected in the Investing Activities section of the Statement of Cash Flows.

Approximately 25% of our cash requirements for capital expenditures during the second quarter of 2009 were satisfied internally from operations (funds provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and debt securities discussed below

We estimate that internally generated funds will provide approximately 43% of the funds required for the remainder of our budgeted 2009 capital expenditures. We intend to utilize a combination of short-term debt, the proceeds of sales of long-term debt and/or common stock (including common stock sold under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, our 401(k) Plan and ESOP and our equity distribution agreement) to finance additional amounts needed beyond those provided by operating activities for such capital expenditures. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements. For further information see Note 6 of “Notes to Consolidated Financial Statements (Unaudited).”

Financing Activities

Our net cash flows provided by financing activities decreased $22.8 million to $24.6 million in 2009 as compared to $47.4 million in 2008 primarily due to lower financing needs as a result of the decrease in capital expenditures discussed above. Our 2009 financing needs were satisfied as set forth below.

On March 27, 2009, we issued $75 million principal amount of 7% first mortgage bonds due April 1, 2024. The net proceeds (after payment of expenses) of approximately $72.6 million were used to repay short-term debt incurred, in part, to fund our current construction program.

On February 25, 2009, we entered into an equity distribution agreement with UBS Securities LLC (UBS). Under the terms of the agreement, we may offer and sell shares of our common stock, par value $1.00 per share, having an aggregate offering price of up to $60 million from time to time through UBS, as sales agent. We intend to use the net proceeds from this equity distribution program to repay short-term debt and for general corporate purposes, including to fund our current construction program. During the second quarter of 2009, we issued and sold 6,400 shares pursuant to this program, at an average price per share of $16.50, resulting in proceeds to us of approximately $0.1 million (after payment of approximately $4,489 in commissions to the sales agent). Through July 31, 2009, in the aggregate, we have issued and sold 200,519 shares pursuant to the program, resulting in net proceeds to us of approximately $3.2 million.

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Sales of the shares pursuant to the equity distribution agreement will be made at market prices or as otherwise agreed with UBS. Under the terms of the program agreement, we may also sell shares to UBS as principal for UBS’ own account at a price agreed upon at the time of sale.

We have a $400 million shelf registration statement with the SEC, which became effective on August 15, 2008, covering our common stock, unsecured debt securities, preference stock, first mortgage bonds and trust preferred securities. As of June 30, 2009, in addition to amounts remaining under the equity distribution program described above, $265 million remains available for issuance under this shelf registration statement. Of the original $400 million, $250 million was available for first mortgage bonds with $175 million remaining available after the issuance of $75 million in first mortgage bonds on March 27, 2009. We plan to use a portion of the proceeds from issuances under this shelf to fund a portion of the capital expenditures for our new generation projects.

On March 11, 2009, we entered into a $50 million unsecured credit agreement. This agreement provides for $50 million of revolving loans to be available to us for working capital, general corporate purposes and to back-up our use of commercial paper and terminates on July 15, 2010. This credit agreement is in addition to, and has substantially identical covenants and terms as (other than pricing), our Amended and Restated Unsecured Credit Agreement dated March 14, 2006 discussed below. There were no borrowings under this agreement at June 30, 2009.

On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy Station project. This extra $76 million of availability reduces over a four year period in line with the amount of construction expenditures we owe for Plum Point Unit 1 and was $12.5 million as of August 1, 2009. The unallocated credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include our note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of June 30, 2009, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were $51.0 million of outstanding borrowings under this agreement at June 30, 2009. In addition, $21.0 million of the availability thereunder was used at such date to back up our outstanding commercial paper.

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage.Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended June 30, 2009 would permit us to issue approximately $291.2 million of new first mortgage bonds based on this test with an assumed interest rate of 7.0%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At June 30, 2009, we had retired bonds and net property additions which would

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enable the issuance of at least $608.8 million principal amount of bonds if the annual interest requirements are met. As of June 30, 2009, we are in compliance with all restrictive covenants of the EDE Mortgage.

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.As of June 30, 2009, this test would not allow us to issue new first mortgage bonds.

Currently, our corporate credit ratings and the ratings for our securities are as follows:

	Fitch	Moody’s	Standard & Poor’s
Corporate Credit Rating	n/r*	Baa2	BBB-
First Mortgage Bonds	BBB+	Baa1	BBB+
First Mortgage Bonds - Pollution Control Series**	AAA	Aaa	AAA
Senior Notes	BBB	Baa2	BBB-
Trust Preferred Securities	BBB-	Baa3	BB
Commercial Paper	F2	P-2	A-3
Outlook	Negative	Negative	Stable

*Not rated

**Insured by a third party insurer.

CONTRACTUAL OBLIGATIONS

Our contractual obligations have not significantly changed at June 30, 2009, compared to December 31, 2008 other than the $75 million principal amount of 7% first mortgage bonds issued on March 27, 2009 and due April 1, 2024 and related interest costs.

DIVIDENDS

Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). As of June 30, 2009 our retained earnings balance was $10.3 million, compared to $7.4 million as of June 30, 2008, after paying out $11.0 million in dividends during the second quarter of 2009. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price. On July 23, 2009, the Board of Directors declared a quarterly dividend of $0.32 per share on common stock payable September 15, 2009 to holders of record as of September 1, 2009.

Our diluted earnings per share were $0.54 for the six months ended June 30, 2009 and were $1.17 and $1.09 for the years ended December 31, 2008 and 2007, respectively. Dividends paid per share were $0.64 for the six months ended June 30, 2009 and $1.28 for each of the years ended December 31, 2008 and 2007.

In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make

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any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. On March 11, 2008, we amended the EDE Mortgage in order to provide us with more flexibility to pay dividends to our shareholders by increasing the basket available to pay dividends by $10.75 million, as described above. As of June 30, 2008, this restriction did not prevent us from issuing dividends.

In addition, under certain circumstances, our Junior Subordinated Debentures, 8-1/2% Series due 2031, reflected as a note payable to securitization trust on our balance sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock. These restrictions apply if: (1) we have knowledge that an event has occurred that would constitute an event of default under the indenture governing these junior subordinated debentures and we have not taken reasonable steps to cure the event, (2) we are in default with respect to payment of any obligations under our guarantee relating to the underlying preferred securities, or (3) we have deferred interest payments on the Junior Subordinated Debentures, 8-1/2% Series due 2031 or given notice of a deferral of interest payments. As of June 30, 2008, there were no such restrictions on our ability to pay dividends.

OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources, other than operating leases entered into in the normal course of business.

CRITICAL ACCOUNTING POLICIES

Goodwill.We recorded goodwill of $39.5 million upon the completion of the 2006 Missouri Gas acquisition. Goodwill represents the excess of the cost of the acquisition over the fair value of the related net assets at the date of acquisition. In accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” (FAS 142) goodwill is required to be tested for impairment on an annual basis or whenever events or circumstances indicate possible impairment. In performing impairment tests, we utilize valuation techniques which estimate the discounted future cash flows of operations. Our procedures include developing a baseline test and performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering those assumptions which are subjective in nature and inherent to a discounted cash flows valuation technique. Other qualitative factors and comparisons to industry peers are also used to further support the assumptions and ultimately the overall evaluation. A significant qualitative factor considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for our gas segment. Some of the more significant quantitative assumptions included in our tests involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. Risks and uncertainties affecting these assumptions include:  management’s identification of impairment indicators, changes in business, industry, laws, technology or economic and market conditions. While management believes the assumptions utilized in our analysis were reasonable, significant adverse developments in the gas segment in future periods or changes in the assumptions could negatively impact goodwill impairment considerations, which could adversely impact earnings. We performed our annual goodwill impairment test as of November 30, 2008 and concluded our goodwill was not impaired. This test estimated the fair market value of our gas segment to be 10-15% higher than its carrying value at that time. We do not believe the fair value of our gas segment declined below the carrying value during the quarter ended June 30, 2009 and as a result an interim test for impairment was not performed.

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See “Item 7 – Managements Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report Form 10-K for the year ended December 31, 2008 for a discussion of our other critical accounting policies. There were no changes in these policies in the quarter ended June 30, 2009.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Note 2 of “Notes to Consolidated Financial Statements (Unaudited)”.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

Our fuel procurement activities involve primary market risk exposures, including commodity price risk and credit risk. Commodity price risk is the potential adverse price impact related to the fuel procurement for our generating units. Credit risk is the potential adverse financial impact resulting from non-performance by a counterparty of its contractual obligations. Additionally, we are exposed to interest rate risk which is the potential adverse financial impact related to changes in interest rates.

Market Risk and Hedging Activities.

Prices in the wholesale power markets often are extremely volatile. This volatility impacts our cost of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would attempt to purchase power from others. Such supplies are not always available. In addition, congestion on the transmission system can limit our ability to make purchases from (or sell into) the wholesale markets.

We engage in physical and financial trading activities with the goals of reducing risk from market fluctuations. In accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions, we attempt to mitigate our commodity market risk. Derivatives are utilized to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Commodity Price Risk.

We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations, including utilizing derivatives.

We satisfied 60.9% of our 2008 generation fuel supply need through coal. Approximately 90% of our 2008 coal supply was Western coal. We have contracts to supply a portion of the fuel for our coal plants through 2013. These contracts satisfy approximately 89% of our anticipated fuel requirements for 2009, 75% for 2010, 58% for 2011, 27% for 2012 and 30% of our 2013 requirements for our Asbury and Riverton coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of July 24, 2009, 92%, or 4.3 million Dths, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2009 is hedged.

Based on our expected natural gas purchases for our electric operations for the next twelve months, if average natural gas prices should increase 10% more than the price at June 30, 2009, our natural gas cost would increase by approximately $0.9 million based on our June 30, 2009 total hedged positions for the next twelve months. However, such an increase would be probable of recovery through fuel adjustment mechanisms.

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We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of July 24, 2009, we have 1.2 million Dths in storage on the three pipelines that serve our customers. This represents 60% of our storage capacity. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of current year, up to 50% of the second year and up to 20% of third year expected gas usage by the beginning of the ACA year at September 1. However, due to purchased natural gas cost recovery mechanisms for our retail customers, fluctuations in the cost of natural gas have little effect on income.

Credit Risk.

In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” regarding agreements containing credit risk contingent features. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit by various trading counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets and margin deposit liabilities at June 30, 2009 and December 31, 2008:

(in millions)	June 30, 2009		December 31, 2008
Margin deposit assets	$	4.9	$	10.7
Margin deposit liabilities	$	—	$	—

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at June 30, 2009, reflecting that our counterparties are exposed to Empire for the net unrealized mark-to-market losses for physical forward and financial natural gas contracts carried at fair value.

(in millions)
Net unrealized mark-to-market losses for physical forward natural gas contracts	$	8.1
Net unrealized mark-to-market losses for financial natural gas contracts	6.1
Net credit exposure	$	14.2

The $6.1 million net unrealized mark-to-market loss for financial natural gas contracts is comprised of $9.9 million of exposure to counterparties of Empire for unrealized losses and $3.8 million of exposure to Empire of unrealized gains from a single counterparty. We are holding no collateral from this counterparty since we are below the $10 million mark-to-market collateral threshold in our agreement with this counterparty. As noted above, we have $4.9 million on deposit with NYMEX covering counterparty exposure to Empire. In addition, if NYMEX gas prices decreased 25% from their July 24, 2009 levels, we would be required to post an additional $1.1 million in collateral. If these prices increased 25%, our collateral requirement would decrease $1.6 million.

We sell electricity and gas and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for purchases of energy-related commodities, including natural gas in our fuel procurement process.

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Interest Rate Risk.

We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit agreement) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates.

If market interest rates average 1% more in 2009 than in 2008, our interest expense would increase, and income before taxes would decrease by less than $0.8 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2008. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

Item 4.  Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2009.

There have been no changes in our internal control over financial reporting that occurred during the second quarter of 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

Platte County Levee Lawsuit

On May 22, 2009, a suit was filed in the Circuit Court of Platte County Missouri by several individuals and Class Representatives alleging damages to land, structures, equipment and devastation of Plaintiff crops due to inappropriate management of the levee system around Iatan. No procedural schedule has been established and we are unable to predict the outcome of the law suit.

Item 1A.  Risk Factors.

The following risk factors update and replace in their entirety the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2008.

Any reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.

Currently, our corporate credit ratings and the ratings for our securities are as follows:

	Fitch	Moody’s	Standard & Poor’s
Corporate Credit Rating	n/r*	Baa2	BBB-
EDE First Mortgage Bonds	BBB+	Baa1	BBB+
EDE First Mortgage Bonds – Pollution Control Series**	AAA	Aaa	AAA
Senior Notes	BBB	Baa2	BBB-
Trust Preferred Securities	BBB-	Baa3	BB
Commercial Paper	F2	P-2	A-3
Outlook	Negative	Negative	Stable

*Not rated.

**Insured by a third party insurer.

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The ratings indicate the agencies’ assessment of our ability to pay interest, distributions and principal on these securities. A rating is not a recommendation to purchase, sell or hold securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost of the securities when they are sold. In addition, a downgrade in our senior unsecured long-term debt rating would result in an increase in our borrowing costs under our bank credit facility. If any of our ratings fall below investment grade (investment grade is defined as Baa3 or above for Moody’s and BBB- or above for Standard & Poor’s and Fitch), our ability to issue short-term debt, commercial paper or other securities or to market those securities would be impaired or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on our business, financial condition and results of operations. In addition, any actual downgrade of our commercial paper rating from Moody’s or Fitch, may make it difficult for us to issue commercial paper. To the extent we are unable to issue commercial paper, we will need to meet our short-term debt needs through borrowings under our revolving credit facilities, which may result in higher costs.

We cannot assure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.

Financial market disruptions may increase financing costs, limit access to the credit markets or cause reductions in investment values in our pension plan assets.

The recent general market declines resulting in part from the sub-prime mortgage issues have generally reduced access to the capital markets and reduced market returns on investments. We estimate our capital expenditures to be $168.9 million in 2009. Although we believe it is unlikely we will have difficulty accessing the markets for the capital needed to complete these projects, our financing costs will likely be higher when compared to previous years. The market’s effect on our pension plan assets resulted in a negative return of 25.1% in 2008. This decline will likely result in increased funding requirements under the Pension Protection Act of 2006.

We are exposed to factors that can increase our fuel and purchased power expenditures, including disruption in deliveries of coal or natural gas, decreased output from our power plants, failure of performance by purchased power counterparties and market risk in our fuel procurement strategy.

Fuel and purchased power costs are our largest expenditures. Increases in the price of coal, natural gas or the cost of purchased power will result in increased electric operating expenditures.

We depend upon regular deliveries of coal as fuel for our Riverton, Asbury and Iatan plants, and as fuel for the facility which supplies us with purchased power under our contract with Westar Energy. Substantially all of this coal comes from mines in the Powder River Basin of Wyoming and is delivered to the plants by train. Production problems in these mines, railroad transportation or congestion problems, such as those that occurred in 2005 and 2006, or unavailability of trains could affect delivery cycle times required to maintain plant inventory levels, causing us to implement coal conservation and supply replacement measures to retain adequate reserve inventories at our facilities. These measures could include some or all of the following:  reducing the output of our coal plants, increasing the utilization of our higher-cost gas-fired generation facilities, purchasing power from other suppliers, adding additional leased trains to our supply system and purchasing locally mined coal which can be delivered without using the railroads. Such measures could result in increased fuel and purchased power expenditures.

With the addition of the Missouri fuel adjustment mechanism effective September 1, 2008, we now have a fuel cost recovery mechanism in all of our jurisdictions, which significantly reduces our net income exposure to the impact of the risks discussed above. However, cash flow could still be impacted by these increased expenditures. We are also subject to prudency reviews which could negatively impact our net income if a regulatory commission would conclude our costs were incurred imprudently.

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We have also established a risk management practice of purchasing contracts for future fuel needs to meet underlying customer needs and manage cost and pricing uncertainty. Within this activity, we may incur losses from these contracts. By using physical and financial instruments, we are exposed to credit risk and market risk. Market risk is the exposure to a change in the value of commodities caused by fluctuations in market variables, such as price. The fair value of derivative financial instruments we hold is adjusted cumulatively on a monthly basis until prescribed determination periods. At the end of each determination period, which is the last day of each calendar month in the period, any realized gain or loss for that period related to the contract will be reclassified to fuel expense and recovered or refunded to the customer through our fuel adjustment mechanisms. Credit risk is the risk that the counterparty might fail to fulfill its obligations under contractual terms.

We are subject to regulation in the jurisdictions in which we operate.

We are subject to comprehensive regulation by federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility commissions in the states where we operate regulate many aspects of our utility operations, including the rates that we can charge customers, siting and construction of facilities, pipeline safety and compliance, customer service and our ability to recover increases in our fuel and purchased power costs.

The FERC has jurisdiction over wholesale rates for electric transmission service and electric energy sold in interstate commerce. Federal, state and local agencies also have jurisdiction over many of our other activities.

Information concerning recent filings requesting increases in rates and related matters is set forth under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Rate Matters.”

We are unable to predict the impact on our operating results from the regulatory activities of any of these agencies. Despite our requests, these regulatory commissions have sole discretion to leave rates unchanged, grant increases or order decreases in the base rates we charge our utility customers. They have similar authority with respect to our recovery of increases in our fuel and purchased power costs. If our costs increase and we are unable to recover increased costs through base rates or fuel adjustment clauses, or if we are unable to fully recover our investments in new facilities, our results of operations could be materially adversely affected. Changes in regulations or the imposition of additional regulations could also have a material adverse effect on our results of operations.

Operations risks may adversely affect our business and financial results.

The operation of our electric generation, and electric and gas transmission and distribution systems involves many risks, including breakdown or failure of expensive and sophisticated equipment, processes and personnel performance; operating limitations that may be imposed by equipment conditions, environmental or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; transmission scheduling constraints; and catastrophic events such as fires, explosions, severe weather or other similar occurrences.

We have implemented training, preventive maintenance and other programs, but there is no assurance that these programs will prevent or minimize future breakdowns, outages or failures of our generation facilities. In those cases, we would need to either produce replacement power from our other facilities or purchase power from other suppliers at potentially volatile and higher cost in order to meet our sales obligations.

These and other operating events may reduce our revenues, increase costs, or both, and may materially affect our results of operations, financial position and cash flows.

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We are exposed to increases in costs and reductions in revenue which we cannot control and which may adversely affect our business, financial condition and results of operations.

The primary drivers of our electric operating revenues in any period are:  (1) rates we can charge our customers, (2) weather, (3) customer growth and (4) general economic conditions. Of the factors driving revenues, weather has the greatest short-term effect on the demand for electricity for our regulated business. Mild weather reduces demand and, as a result, our electric operating revenues. In addition, changes in customer demand due to downturns in the economy could reduce our revenues.

The primary drivers of our electric operating expenses in any period are:  (1) fuel and purchased power expenses, (2) maintenance and repairs expense, including repairs following severe weather and plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. Although we generally recover maintenance and repairs expense and such costs through our rates, there can be no assurance that we will recover all, or any part of, such increased costs in future rate cases.

The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth, (4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our natural gas service territory and a significant amount of our natural gas revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our natural gas operations have historically generated less revenues and income when weather conditions are warmer in the winter.

The primary driver of our gas operating expense in any period is the price of natural gas.

Significant increases in electric and gas operating expenses or reductions in electric and gas operating revenues may occur and result in a material adverse effect on our business, financial condition and results of operations.

We may be unable to recover increases in the cost of natural gas from our natural gas utility customers, or may lose customers as a result of any price increases.

In our natural gas utility business, we are permitted to recover the cost of gas directly from our customers through the use of a purchased gas adjustment provision. Our purchased gas adjustment provision is regularly reviewed by the Missouri Public Service Commission (MPSC). In addition to reviewing our adjustments to customer rates, the MPSC reviews our costs for prudency as well. To the extent the MPSC may determine certain costs were not incurred prudently, it could adversely affect our gas segment earnings and cash flows. In addition, increases in natural gas costs affect total prices to our customers and, therefore, the competitive position of gas relative to electricity and other forms of energy. Increases in natural gas costs may also result in lower usage by customers unable to switch to alternate fuels. Such disallowed costs or customer losses could have a material adverse effect on our business, financial condition and results of operations.

We are subject to environmental laws and the incurrence of environmental liabilities which may adversely affect our business, financial condition and results of operations.

We are subject to extensive federal, state and local regulation with regard to air and other environmental matters. Failure to comply with these laws and regulations could have a material adverse effect on our results of operations and financial position. In addition, new environmental laws and regulations, and new interpretations of existing environmental laws and regulations, have been adopted and may in the future be adopted which may substantially increase our future environmental expenditures for both new facilities and our existing facilities. Compliance with current and future air emission standards (such as those limiting emission levels of sulfur dioxide (SO2) and nitrogen oxide (NOx) and, potentially, carbon dioxide (CO2)) has required, and may in the future require, significant environmental expenditures. Although we generally recover such costs through our rates, there can be no assurance that we will recover all, or any part of, such increased costs in

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future rate cases. The incurrence of additional material environmental costs which are not recovered in our rates may result in a material adverse effect on our business, financial condition and results of operations.

The cost and schedule of construction projects may materially change.

We have entered into contracts to purchase an undivided interest in 50 megawatts (7.5% ownership interest) of the Plum Point Energy Station’s new 665-megawatt, coal-fired generating facility which is being built near Osceola, Arkansas. We have also entered into an agreement with Kansas City Power & Light Company to purchase an undivided ownership interest in the coal-fired Iatan 2 generating facility. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit.

There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than currently planned, the scope and timing of projects may change, the re-baselined schedule may not be met and other events beyond our control, including the failure of one or more of the generation plant co-owners to pay their share of construction, operations and maintenance costs, may occur that may materially affect the schedule, budget, cost and performance of these projects. To the extent the completion of these projects is delayed, we expect that the timing of receipt of increases in base rates reflecting our investment in such projects will be correspondingly delayed.

Item 4.  Submission of Matters to a Vote of Security Holders.

(a)           The Annual Meeting of Stockholders was held on April 23, 2009.

(b)The following persons were re-elected Directors of Empire to serve until the 2012 Annual Meeting of Stockholders:

B. Thomas Mueller (28,855,278 votes for; 527,446 withheld authority).

D. Randy Laney (28,817,587 votes for; 565,137 withheld authority).

The following persons were elected Directors of Empire to serve until the 2012 Annual Meeting of Stockholders:

Bonnie C. Lind (28,792,170 votes for; 590,554 withheld authority).

Paul R. Portney (28,759,326 votes for; 623,398 withheld authority).

The term of office as Director of the following other Directors continued after the meeting:  William L. Gipson, Kenneth R. Allen, Bill D. Helton, Ross C. Hartley, Julio S. Leon, and Allan T. Thoms.

(c)Common stockholders voted to approve ratification of the appointment of PricewaterhouseCoopers LLP as Empire’s independent registered public accounting firm for the fiscal year ending December 31, 2009. Passage of the proposal required the affirmative vote of a majority of the votes cast. The proposal received 28,945,310 votes for and 359,096 votes against.

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Item 5.  Other Information.

For the twelve months ended June 30, 2009, our ratio of earnings to fixed charges was 2.33x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)           Exhibits.

(12) Computation of Ratio of Earnings to Fixed Charges.

(31)(a) Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31)(b) Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32)(a) Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

(32)(b) Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

* This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.

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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.

	THE EMPIRE DISTRICT ELECTRIC COMPANY
	Registrant
	By	/s/ Gregory A. Knapp
		Gregory A. Knapp
		Vice President – Finance and Chief Financial Officer
	By	/s/ Laurie A. Delano
		Laurie A. Delano
		Controller, Assistant Secretary and Assistant Treasurer
August 6, 2009

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