Consolidated Balance Sheets Unaudited (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2011	Dec. 31, 2010
GREAT PLAINS ENERGY INCORPORATED
Current Assets
Cash and cash equivalents	$ 6.6	$ 10.8
Funds on deposit	4.3	5.2
Receivables, net	191.9	241.7
Accounts receivable pledged as collateral	95.0	95.0
Fuel inventories, at average cost	92.8	85.1
Materials and supplies, at average cost	135.2	132.8
Deferred refueling outage costs	19.5	9.6
Refundable income taxes	0.2	2.1
Deferred income taxes	11.6	14.3
Derivative instruments	1.5	1.1
Prepaid expenses and other assets	15.2	13.9
Total	573.8	611.6
Utility Plant, at Original Cost
Electric	10,621.4	10,536.9
Less-accumulated depreciation	4,096.5	4,031.3
Net utility plant in service	6,524.9	6,505.6
Construction work in progress	286.5	307.5
Nuclear fuel, net of amortization	74.2	79.2
Total	6,885.6	6,892.3
Investments and Other Assets
Nuclear decommissioning trust fund	135.1	129.2
Regulatory assets	937.4	924.0
Goodwill	169.0	169.0
Derivative instruments	9.5	7.8
Other	92.1	84.3
Total	1,343.1	1,314.3
Total	8,802.5	8,818.2
Current Liabilities
Notes payable	219.0	9.5
Collateralized note payable	95.0	95.0
Commercial paper	288.8	263.5
Current maturities of long-term debt	473.6	485.7
Accounts payable	173.4	276.3
Accrued taxes	52.7	26.6
Accrued interest	72.2	75.4
Accrued compensation and benefits	36.5	46.8
Pension and post-retirement liability	4.1	4.1
Derivative instruments	20.3	20.8
Other	42.5	35.6
Total	1,478.1	1,339.3
Deferred Credits and Other Liabilities
Deferred income taxes	510.4	518.3
Deferred tax credits	133.3	133.4
Asset retirement obligations	146.4	143.3
Pension and post-retirement liability	424.5	427.5
Regulatory liabilities	267.3	258.2
Other	130.9	129.4
Total	1,612.8	1,610.1
Common shareholders' equity
Common Stock	2,324.0	2,324.4
Retained earnings	599.6	626.5
Treasury stock	(5.5)	(8.9)
Accumulated other comprehensive gain (loss)	(54.0)	(56.1)
Total	2,864.1	2,885.9
Noncontrolling interest	1.1	1.2
Cumulative preferred stock
3.80%	10.0	10.0
4.50%	10.0	10.0
4.20%	7.0	7.0
4.35%	12.0	12.0
Total	39.0	39.0
Long-term debt	2,807.4	2,942.7
Total	5,711.6	5,868.8
Commitments and Contingencies
Total	8,802.5	8,818.2
KANSAS CITY POWER AND LIGHT COMPANY
Current Assets
Cash and cash equivalents	1.5	3.6
Funds on deposit	0.4	0.4
Receivables, net	122.9	169.4
Accounts receivable pledged as collateral	95.0	95.0
Fuel inventories, at average cost	58.1	44.9
Materials and supplies, at average cost	96.5	94.4
Deferred refueling outage costs	19.5	9.6
Refundable income taxes	7.6	9.0
Deferred income taxes	2.6	5.6
Prepaid expenses and other assets	12.2	10.0
Total	416.3	441.9
Utility Plant, at Original Cost
Electric	7,599.6	7,540.9
Less-accumulated depreciation	3,152.2	3,104.4
Net utility plant in service	4,447.4	4,436.5
Construction work in progress	215.4	227.6
Nuclear fuel, net of amortization	74.2	79.2
Total	4,737.0	4,743.3
Investments and Other Assets
Nuclear decommissioning trust fund	135.1	129.2
Regulatory assets	683.6	679.6
Other	41.5	32.3
Total	860.2	841.1
Total	6,013.5	6,026.3
Current Liabilities
Collateralized note payable	95.0	95.0
Commercial paper	288.8	263.5
Current maturities of long-term debt	275.5	150.3
Accounts payable	148.3	201.7
Accrued taxes	40.9	21.3
Accrued interest	38.5	26.2
Accrued compensation and benefits	36.5	46.8
Pension and post-retirement liability	2.6	2.6
Other	16.8	7.8
Total	942.9	815.2
Deferred Credits and Other Liabilities
Deferred income taxes	687.2	692.0
Deferred tax credits	129.4	129.4
Asset retirement obligations	131.8	129.7
Pension and post-retirement liability	404.4	407.3
Regulatory liabilities	147.5	141.3
Other	80.4	76.7
Total	1,580.7	1,576.4
Common shareholders' equity
Common Stock	1,563.1	1,563.1
Retained earnings	457.3	478.3
Accumulated other comprehensive gain (loss)	(35.1)	(36.4)
Total	1,985.3	2,005.0
Cumulative preferred stock
Long-term debt	1,504.6	1,629.7
Total	3,489.9	3,634.7
Commitments and Contingencies
Total	$ 6,013.5	$ 6,026.3

Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2011	Dec. 31, 2010
GREAT PLAINS ENERGY INCORPORATED
Utility Plant, at Original Cost
Nuclear fuel accumulated amortization	$ 136.9	$ 131.1
Capitalization
Common Stock, Shares, Authorized	250,000,000	250,000,000
Common Stock, Shares, Issued	136,192,220	136,113,954
Treasury Stock, Shares	254,440	400,889
Cumulative preferred stock par value	$ 100	$ 100
3.80% - shares issued	100,000	100,000
4.50% - shares issued	100,000	100,000
4.20% - shares issued	70,000	70,000
4.35% - shares issued	120,000	120,000
KANSAS CITY POWER AND LIGHT COMPANY
Utility Plant, at Original Cost
Nuclear fuel accumulated amortization	$ 136.9	$ 131.1
Capitalization
Common Stock, Shares, Authorized	1,000	1,000
Common Stock, Shares, Issued	1	1

Consolidated Statements of Income Unaudited (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2011	Mar. 31, 2010
GREAT PLAINS ENERGY INCORPORATED
Operating Revenues
Electric revenues	$ 492.9	$ 506.9
Operating Expenses
Fuel	104.9	101.8
Purchased power	54.9	65.5
Transmission of electricity by others	7.5	5.6
Utility operating and maintenance expenses	157.5	151.2
Voluntary separation program	9.7	0
Depreciation and amortization	72.4	82.2
General taxes	42.0	38.1
Other	2.8	0.5
Total	451.7	444.9
Operating income (loss)	41.2	62.0
Non-operating income	3.6	16.1
Non-operating expenses	(2.2)	(1.6)
Interest charges	(44.9)	(46.5)
Income (loss) before income tax (expense) benefit and loss from equity investments	(2.3)	30.0
Income tax (expense) benefit	4.6	(9.7)
Net income	2.3	20.3
Less: Net income attributable to noncontrolling interest	0.1	0
Net income (loss) attributable to Great Plains Energy	2.4	20.3
Preferred stock dividend requirements	0.4	0.4
Earnings available for common shareholders	2.0	19.9
Average number of basic common shares outstanding	135.4	134.9
Average number of diluted common shares outstanding	138.2	136.6
Basic and diluted earnings (loss) per common share
Basic earnings per common share	$ 0.02	$ 0.15
Diluted earnings per common share	$ 0.01	$ 0.15
Cash dividends per common share	$ 0.2075	$ 0.2075
KANSAS CITY POWER AND LIGHT COMPANY
Operating Revenues
Electric revenues	330.8	335.6
Operating Expenses
Fuel	68.2	61.5
Purchased power	21.4	27.3
Transmission of electricity by others	4.3	2.9
Utility operating and maintenance expenses	114.9	108.7
Voluntary separation program	6.8	0
Depreciation and amortization	53.4	63.5
General taxes	33.9	31.2
Other	1.4	0
Total	304.3	295.1
Operating income (loss)	26.5	40.5
Non-operating income	0.5	8.8
Non-operating expenses	(1.0)	(0.8)
Interest charges	(23.1)	(21.7)
Income (loss) before income tax (expense) benefit and loss from equity investments	2.9	26.8
Income tax (expense) benefit	1.1	(7.6)
Net income	$ 4.0	$ 19.2

Consolidated Statements of Cash Flows Unaudited (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2011	Mar. 31, 2010
GREAT PLAINS ENERGY INCORPORATED
Cash Flows from Operating Activities
Net income (loss)	$ 2.3	$ 20.3
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	72.4	82.2
Amortization of:
Nuclear fuel	5.8	6.1
Other	(0.3)	(1.9)
Deferred income taxes, net	(7.4)	4.7
Investment tax credit amortization	(0.1)	(0.5)
Other operating activities	(35.7)	(119.7)
Net cash from operating activities	37.0	(8.8)
Cash Flows from Investing Activities
Utility capital expenditures	(99.9)	(176.9)
Allowance for borrowed funds used during construction	(1.3)	(9.7)
Purchases of nuclear decommissioning trust investments	(3.8)	(65.8)
Proceeds from nuclear decommissioning trust investments	2.9	64.9
Other investing activities	(6.1)	(2.6)
Net cash from investing activities	(108.2)	(190.1)
Cash Flows from Financing Activities
Issuance of common stock	1.5	1.6
Repayment of long-term debt	(138.4)	(1.1)
Net change in short-term borrowings	234.8	74.9
Net change in collateralized short-term borrowings	0	95.0
Dividends paid	(28.6)	(28.5)
Other financing activities	(2.3)	(2.6)
Net cash from financing activities	67.0	139.3
Net Change in Cash and Cash Equivalents	(4.2)	(59.6)
Cash and Cash Equivalents at Beginning of Year	10.8	65.9
Cash and Cash Equivalents at End of Period	6.6	6.3
KANSAS CITY POWER AND LIGHT COMPANY
Cash Flows from Operating Activities
Net income (loss)	4.0	19.2
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	53.4	63.5
Amortization of:
Nuclear fuel	5.8	6.1
Other	6.8	5.6
Deferred income taxes, net	(3.5)	(16.1)
Investment tax credit amortization	0	(0.4)
Other operating activities	(20.7)	(57.1)
Net cash from operating activities	45.8	20.8
Cash Flows from Investing Activities
Utility capital expenditures	(75.5)	(131.2)
Allowance for borrowed funds used during construction	(0.8)	(7.8)
Purchases of nuclear decommissioning trust investments	(3.8)	(65.8)
Proceeds from nuclear decommissioning trust investments	2.9	64.9
Net money pool lending	12.1	6.0
Other investing activities	(3.9)	(2.1)
Net cash from investing activities	(69.0)	(136.0)
Cash Flows from Financing Activities
Net change in short-term borrowings	25.3	17.4
Net change in collateralized short-term borrowings	0	95.0
Net money pool borrowings	20.8	7.7
Dividends paid	(25.0)	(20.0)
Net cash from financing activities	21.1	100.1
Net Change in Cash and Cash Equivalents	(2.1)	(15.1)
Cash and Cash Equivalents at Beginning of Year	3.6	17.4
Cash and Cash Equivalents at End of Period	$ 1.5	$ 2.3

Consolidated Statements of Common Shareholders' Equity Unaudited (USD $) In Millions, except Share data, unless otherwise specified	GREAT PLAINS ENERGY INCORPORATED	KANSAS CITY POWER AND LIGHT COMPANY	Common Stock GREAT PLAINS ENERGY INCORPORATED	Common Stock KANSAS CITY POWER AND LIGHT COMPANY	Retained Earnings GREAT PLAINS ENERGY INCORPORATED	Retained Earnings KANSAS CITY POWER AND LIGHT COMPANY	Treasury Stock GREAT PLAINS ENERGY INCORPORATED	Accumulated Other Comprehensive Income (Loss) GREAT PLAINS ENERGY INCORPORATED	Accumulated Other Comprehensive Income (Loss) KANSAS CITY POWER AND LIGHT COMPANY	Noncontrolling Interest GREAT PLAINS ENERGY INCORPORATED	Total Great Plains Energy Common Shareholders' Equity [Member] GREAT PLAINS ENERGY INCORPORATED
Beginning balance (in shares) at Dec. 31, 2009			135,636,538	1			(213,423)
Beginning balance at Dec. 31, 2009			$ 2,313.7	$ 1,563.1	$ 529.2	$ 410.1	$ (5.5)	$ (44.9)	$ (41.5)	$ 1.2
Issuance of common stock			1.7
Issuance of common stock (in shares)			92,634
Issuance of restricted common stock			1.8
Issuance of restricted common stock (in shares)			98,211
Unearned Compensation
Issuance of restricted common stock			(1.8)
Forfeiture of restricted common stock			0.2
Compensation expense recognized			0.7
Net income (loss) attributable to Great Plains Energy	20.3				20.3	19.2
Loss on reissuance of treasury stock					0
Dividends:
Common stock					(28.1)	(20.0)
Preferred stock - at required rates					(0.4)
Performance shares					(0.1)
Treasury shares acquired							(1.6)
Treasury shares acquired (in shares)							(93,483)
Treasury shares reissued							0
Treasury shares reissued (in shares)							917
Derivative hedging activity, net of tax	(3.3)	1.1						(3.3)	1.1
Net income attributable to noncontrolling interest										0
Ending balance (in shares) at Mar. 31, 2010			135,827,383	1			(305,989)
Ending balance at Mar. 31, 2010		1,932.0	2,316.3	1,563.1	520.9	409.3	(7.1)	(48.2)	(40.4)	1.2	2,781.9
Beginning balance (in shares) at Dec. 31, 2010			136,113,954	1			(400,889)
Beginning balance at Dec. 31, 2010			2,324.4	1,563.1	626.5	478.3	(8.9)	(56.1)	(36.4)	1.2
Issuance of common stock			1.5
Issuance of common stock (in shares)			78,266
Issuance of restricted common stock			0
Issuance of restricted common stock (in shares)			0
Unearned Compensation
Issuance of restricted common stock			(2.6)
Forfeiture of restricted common stock			0.1
Compensation expense recognized			0.6
Net income (loss) attributable to Great Plains Energy	2.4				2.4	4.0
Loss on reissuance of treasury stock					(0.5)
Dividends:
Common stock					(28.2)	(25.0)
Preferred stock - at required rates					(0.4)
Performance shares					(0.2)
Treasury shares acquired							(1.1)
Treasury shares acquired (in shares)							(58,225)
Treasury shares reissued							4.5
Treasury shares reissued (in shares)							204,674
Derivative hedging activity, net of tax	2.1	1.3						2.1	1.3
Net income attributable to noncontrolling interest										(0.1)
Common Stockholders' Equity attributable to Parent	2,864.1	1,985.3
Ending balance (in shares) at Mar. 31, 2011			136,192,220	1			(254,440)
Ending balance at Mar. 31, 2011			$ 2,324.0	$ 1,563.1	$ 599.6	$ 457.3	$ (5.5)	$ (54.0)	$ (35.1)	$ 1.1

Consolidated Statements of Comprehensive Income Unaudited (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2011	Mar. 31, 2010
GREAT PLAINS ENERGY INCORPORATED
Net income (loss)	$ 2.3	$ 20.3
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	0.5	(7.8)
Income tax (expense) benefit	(0.1)	3.1
Net gain (loss) on derivative hedging instruments	0.4	(4.7)
Reclassification to expenses, net of tax	1.7	1.4
Derivative hedging activity, net of tax	2.1	(3.3)
Comprehensive income (loss)	4.4	17.0
Less: comprehensive income attributable to noncontrolling interest	0.1	0
Comprehensive income (loss) attributable to Great Plains Energy	4.5	17.0
KANSAS CITY POWER AND LIGHT COMPANY
Net income (loss)	4.0	19.2
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	0	(0.4)
Income tax (expense) benefit	0	0.2
Net gain (loss) on derivative hedging instruments	0	(0.2)
Reclassification to expenses, net of tax	1.3	1.3
Derivative hedging activity, net of tax	1.3	1.1
Comprehensive income (loss)	$ 5.3	$ 20.3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Summary of Significant Accounting Policies

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

Great Plains Energy, a Missouri corporation incorporated in 2001, is a public utility holding company and does not own or operate any significant assets other than the stock of its subsidiaries. Great Plains Energy’s wholly owned direct subsidiaries with operations or active subsidiaries are as follows:

·	KCP&L is an integrated, regulated electric utility that provides electricity to customers primarily in the states of Missouri and Kansas. KCP&L has one active wholly owned subsidiary, Kansas City Power & Light Receivables Company (Receivables Company).

KCP&L Greater Missouri Operations Company (GMO) is an integrated, regulated electric utility that primarily provides electricity to customers in the state of Missouri. GMO also provides regulated steam service to certain customers in the St. Joseph, Missouri area. GMO wholly owns MPS Merchant Services, Inc. (MPS Merchant), which has certain long-term natural gas contracts remaining from its former non-regulated trading operations.

Each of Great Plains Energy’s and KCP&L’s consolidated financial statements includes the accounts of their subsidiaries. All intercompany transactions have been eliminated.

Great Plains Energy’s sole reportable business segment is electric utility. See Note 16 for additional information.

Basic and Diluted Earnings per Common Share Calculation

To determine basic EPS, preferred stock dividend requirements and net loss attributable to noncontrolling interest are deducted from net income before dividing by the average number of common shares outstanding. The effect of dilutive securities, calculated using the treasury stock method, assumes the issuance of common shares applicable to performance shares, restricted stock, stock options and Equity Units.

The following table reconciles Great Plains Energy’s basic and diluted EPS.


Three Months Ended March 31	2011			2010
Income	(millions, except per share amounts)
Net income	$	2.3		$	20.3
Less: net loss attributable to noncontrolling interest		(0.1	)		-
Less: preferred stock dividend requirements		0.4			0.4
Earnings available for common shareholders	$	2.0		$	19.9
Common Shares Outstanding
Average number of common shares outstanding		135.4			134.9
Add: effect of dilutive securities		2.8			1.7
Diluted average number of common shares outstanding		138.2			136.6

Basic EPS	$	0.02		$	0.15
Diluted EPS	$	0.01		$	0.15

The computation of diluted EPS for the three months ended March 31, 2011, excludes anti-dilutive shares consisting of 213,522 performance shares, 39,722 restricted stock shares and 159,665 stock options.

The computation of diluted EPS for the three months ended March 31, 2010, excludes anti-dilutive shares consisting of 8,430 performance shares, 251,526 restricted stock shares and 218,846 stock options.

Dividends Declared

In May 2011, Great Plains Energy’s Board of Directors (Board) declared a quarterly dividend of $0.2075 per share on Great Plains Energy’s common stock. The common dividend is payable June 20, 2011, to shareholders of record as of May 27, 2011. The Board also declared regular dividends on Great Plains Energy’s preferred stock, payable September 1, 2011, to shareholders of record as of August 11, 2011.

In May 2011, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $25 million payable on June 17, 2011.

SUPPLEMENTAL CASH FLOW INFORMATION

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Supplemental Cash Flow Information

2.	SUPPLEMENTAL CASH FLOW INFORMATION

Great Plains Energy Other Operating Activities
Three Months Ended March 31	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	44.7		$	42.1
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		(7.7	)		(0.4	)
Materials and supplies		(2.4	)		(6.5	)
Accounts payable		(79.8	)		(67.7	)
Accrued taxes		28.2			27.2
Accrued interest		(3.2	)		(1.5	)
Deferred refueling outage costs		(9.9	)		2.9
Fuel adjustment clauses		(2.0	)		(1.1	)
Pension and post-retirement benefit obligations		5.2			13.6
Allowance for equity funds used during construction		(0.4	)		(10.1	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		2.0			-
Other		(10.4	)		(23.2	)
Total other operating activities	$	(35.7	)	$	(119.7	)
Cash paid during the period:
Interest	$	71.4		$	58.0
Income taxes	$	-		$	-
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	21.2		$	52.9

KCP&L Other Operating Activities
Three Months Ended March 31	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	29.8		$	40.3
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		(13.2	)		(1.8	)
Materials and supplies		(2.1	)		(4.2	)
Accounts payable		(56.3	)		(52.6	)
Accrued taxes		21.0			39.6
Accrued interest		12.3			12.1
Deferred refueling outage costs		(9.9	)		2.9
Pension and post-retirement benefit obligations		9.1			16.3
Allowance for equity funds used during construction		-			(8.1	)
Kansas Energy Cost Adjustment		(4.9	)		(0.5	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		1.3			-
Other		(7.8	)		(6.1	)
Total other operating activities	$	(20.7	)	$	(57.1	)
Cash paid during the period:
Interest	$	18.3		$	10.8
Income taxes	$	-		$	1.9
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	18.5		$	51.1

Significant Non-Cash Items

On January 1, 2010, Great Plains Energy and KCP&L adopted new accounting guidance for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivables pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s and KCP&L’s balance sheets. As a result, cash flows from operating activities were reduced by $95.0 million and cash flows from financing activities were raised by $95.0 million with no impact to the net change in cash for the three months ended March 31, 2010.

RECEIVABLES

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Receivables

3.	RECEIVABLES

Great Plains Energy’s and KCP&L’s receivables are detailed in the following table.


	March 31			December 31
	2011			2010
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	54.2		$	62.0
Customer accounts receivable - unbilled		65.9			82.3
Allowance for doubtful accounts		(1.9	)		(2.7	)
Other receivables		73.7			100.1
Total	$	191.9		$	241.7
KCP&L
Customer accounts receivable - billed	$	2.9		$	6.5
Customer accounts receivable - unbilled		38.6			50.1
Allowance for doubtful accounts		(0.9	)		(1.5	)
Intercompany receivables		19.4			43.2
Other receivables		62.9			71.1
Total	$	122.9		$	169.4

Great Plains Energy’s and KCP&L’s other receivables at March 31, 2011, and December 31, 2010, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables.

Sale of Accounts Receivable – KCP&L

KCP&L sells all of its retail electric accounts receivable to its wholly owned subsidiary, Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor. Receivables Company’s sale of the undivided percentage ownership interest in accounts receivable to Victory Receivables Corporation is accounted for as a secured borrowing with $95.0 million of accounts receivables pledged as collateral and a corresponding short-term collateralized note payable recognized on Great Plains Energy’s and KCP&L’s balance sheets at March 31, 2011, and December 31, 2010.

KCP&L sells its receivables at a fixed price based upon the expected cost of funds and charge-offs. These costs comprise KCP&L’s loss on the sale of accounts receivable. KCP&L services the receivables and receives an annual servicing fee of 1.5% of the outstanding principal amount of the receivables sold to Receivables Company. KCP&L does not recognize a servicing asset or liability because management determined the collection agent fee earned by KCP&L approximates market value. The agreement expires in October 2011.

Information regarding KCP&L’s sale of accounts receivable to Receivables Company is reflected in the following tables.


				Receivables			Consolidated
Three Months Ended March 31, 2011	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(291.9	)	$	291.9		$	-
Gain (loss) on sale of accounts receivable (a)		(3.7	)		3.9			0.2
Servicing fees		0.6			(0.6	)		-
Fees to outside investor		-			(0.3	)		(0.3	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(308.3	)		308.3			-
Cash paid to KCP&L for receivables purchased		304.4			(304.4	)		-
Servicing fees		0.6			(0.6	)		-
Interest on intercompany note		0.1			(0.1	)		-


					Receivables			Consolidated
Three Months Ended March 31, 2010		KCP&L			Company			KCP&L
		(millions)
Receivables (sold) purchased		$	(294.3	)	$	294.3		$	-
Gain (loss) on sale of accounts receivable (a)			(3.7	)		3.9			0.2
Servicing fees			0.5			(0.5	)		-
Fees to outside investor			-			(0.3	)		(0.3	)

Cash flows during the period
Cash from customers transferred to Receivables Company			(308.1	)		308.1			-
Cash paid to KCP&L for receivables purchased			304.2			(304.2	)		-
Servicing fees			0.5			(0.5	)		-
Interest on intercompany note			0.1			(0.1	)		-

(a)	Any net gain (loss) is the result of the timing difference inherent in collecting receivables and
	over the life of the agreement will net to zero.

NUCLEAR PLANT

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Nuclear Plant

4.	NUCLEAR PLANT

KCP&L owns 47% of Wolf Creek Generating Station (Wolf Creek), its only nuclear generating unit. Wolf Creek is located in Coffey County, Kansas, just northeast of Burlington, Kansas. Wolf Creek’s operating license expires in 2045. Wolf Creek is regulated by the Nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety-related requirements.

In March 2011, the NRC established a task force to conduct a 90-day review and a longer-term review of U.S. nuclear power plant safety in the aftermath of a March 11, 2011, earthquake and tsunami that eventually resulted in station blackout and a level 7 event on the International Nuclear and Radiological Event Scale (the highest level event on the scale) at Japan’s Fukushima Daiichi nuclear power plant. Initially, the task force will identify potential near-term actions that affect U.S. power reactors, including their spent fuel pools. The task force expects to develop recommendations for the NRC on whether it should require immediate enhancements at U.S. reactors and any changes to NRC regulations, inspection procedures, and licensing processes. Wolf Creek is currently in a status that calls for heightened NRC oversight; however, management expects Wolf Creek to return to the lowest level of NRC oversight before the end of 2011. The timing and effects of any NRC action cannot be determined at this time.

Spent Nuclear Fuel and High-Level Radioactive Waste

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kWh of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel. These disposal costs are charged to fuel expense. In March 2010, the DOE filed a motion to withdraw its application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada, which would bring the licensing process to an end. An NRC board denied the DOE’s motion to withdraw its application in June 2010, and the DOE appealed that decision to the full NRC in July 2010. The NRC has not yet decided that appeal. The question of the DOE’s legal authority to withdraw its license application also is pending in multiple lawsuits filed with a federal appellate court. Oral argument to the court occurred in March 2011 and the parties await a decision. Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025, and believes it will be able to expand on-site storage as needed past 2025. Management cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity. See Note 11 for a related legal proceeding.

Low-Level Radioactive Waste

Wolf Creek disposes of most of its low-level radioactive waste (Class A waste) at an existing third-party repository in Utah. Management expects that the site located in Utah will remain available to Wolf Creek for disposal of its Class A waste. Wolf Creek has contracted with a waste processor that will process, take title and store in another state most of the remainder of Wolf Creek’s low level radioactive waste (Classes B and C waste, which is higher in radioactivity but much lower in volume). Should on-site waste storage be needed in the future, Wolf Creek has current storage capacity on site for about four years’ generation of Classes B and C waste and believes it will be able to expand that storage capacity as needed if it becomes necessary to do so.

Nuclear Decommissioning Trust Fund

The following table summarizes the change in Great Plains Energy’s and KCP&L’s nuclear decommissioning trust fund.


	March 31		December 31
	2011		2010
Decommissioning Trust	(millions)
Beginning balance January 1	$	129.2	$	112.5
Contributions		0.9		3.7
Earned income, net of fees		0.7		2.0
Net realized gains		0.1		6.7
Net unrealized gains		4.2		4.3
Ending balance	$	135.1	$	129.2

The nuclear decommissioning trust is reported at fair value on the balance sheets and is invested in assets as detailed in the following table.


	March 31									December 31
	2011									2010
			Gross		Gross							Gross		Gross
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	73.6	$	17.7	$	(1.2	)	$	90.1	$	73.4	$	13.1	$	(1.0	)	$	85.5
Debt securities		38.9		2.4		(0.1	)		41.2		38.1		2.6		(0.1	)		40.6
Other		3.8		-		-			3.8		3.1		-		-			3.1
Total	$	116.3	$	20.1	$	(1.3	)	$	135.1	$	114.6	$	15.7	$	(1.1	)	$	129.2

The weighted average maturity of debt securities held by the trust at March 31, 2011, was approximately 7.4 years. The costs of securities sold are determined on the basis of specific identification. The following table summarizes the realized gains and losses from the sale of securities by the nuclear decommissioning trust fund.


Three Months Ended March 31	2011		2010
	(millions)
Realized gains	$	0.1	$	6.8
Realized losses		-		(0.4	)

REGULATORY MATTERS

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Regulatory Matters

5.	REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

In November 2010, The State Corporation Commission of the State of Kansas (KCC) issued an order, effective December 1, 2010, for KCP&L, authorizing an increase in annual revenues of $21.8 million, a return on equity of 10.0%, an equity ratio of approximately 49.7% and a Kansas jurisdictional rate base of $1.781 billion. The annual revenue increase was subsequently adjusted by KCC in a January 2011 reconsideration order to $22.0 million. In February 2011, KCC issued an order granting KCP&L and another party to the case their respective petitions for reconsideration regarding rate case expenses and therefore, approximately $1.4 million of the annual revenue increase is considered as interim subject to refund or true-up pending the outcome of the reconsideration proceedings regarding rate case expenses. The rates authorized by KCC are effective unless and until modified by KCC or stayed by a court.

KCP&L Missouri Rate Case Proceedings

On June 4, 2010, KCP&L filed a request with the Missouri Public Service Commission (MPSC) to increase its Missouri retail electric annual revenues by $92.1 million. The request was ultimately adjusted during the rate case proceedings by KCP&L to $66.5 million as the net result of lower fuel and purchased power costs and other updates to the case. KCP&L’s initial and updated requests reflected, among other things, a proposed annual offset to its revenue requirement for the Missouri jurisdictional portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset); the final update included a proposed wholesale margin offset of approximately $29.4 million. On April 12, 2011, the MPSC issued its order and on April 14, 2011, the MPSC Staff filed a report which quantified the authorized revenue increase as approximately $34.8 million on an annual basis, which reflects a wholesale margin offset of approximately $45.9 million and authorizes a return on equity of 10.0%, an equity ratio of approximately 46.3% and a Missouri jurisdictional rate base of approximately $2.0 billion. If the actual Missouri jurisdiction wholesale margin amount exceeds the $45.9 million level reflected in the MPSC order, the difference will be recorded as a regulatory liability and will be returned, with interest, to KCP&L Missouri customers in a future rate case. The MPSC order provides the opportunity for KCP&L to retain a larger amount of non-firm wholesale electric sales margin than KCP&L proposed; however, there are no assurances that KCP&L will achieve the $45.9 million wholesale margin offset amount and there are no means for KCP&L to recover any shortfall through its retail rates.

Accounting rules state that when it becomes probable that part of the cost of a recently completed plant will be disallowed for rate-making purposes and a reasonable estimate of the amount of the disallowance can be made, the estimated amount of the probable disallowance shall be deducted from the reported cost of the plant and recognized as a loss. As a result of disallowances in the MPSC order, KCP&L recognized Missouri jurisdictional losses of $1.3 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project. Management determined it is probable that the MPSC would disallow these costs as well in GMO’s pending rate cases (discussed below). Therefore, GMO’s portion of these costs was recognized as a loss in addition to the KCP&L Missouri jurisdictional portion resulting in a $2.0 million pre-tax loss representing KCP&L’s and GMO’s combined share for these Iatan construction costs incurred through March 31, 2011.

KCP&L also recorded a $3.3 million loss for other disallowed costs in the MPSC order. Management determined it is probable that the MPSC would disallow these costs as well in GMO’s pending rate cases. Therefore, GMO’s portion of these costs was recognized as a loss in addition to the KCP&L Missouri jurisdictional portion resulting in a combined $4.9 million pre-tax loss.

The rates established by the MPSC order will take effect on May 4, 2011. Parties to the case may file applications for rehearing with the MPSC by that date, and may also file court appeals. However, the rates authorized by the MPSC order will be effective unless and until modified by the MPSC or stayed by a court.

In a related order, the MPSC required KCP&L and GMO to apply to the Internal Revenue Service to reallocate approximately $26.5 million of Iatan No. 2 qualifying advance coal project tax credits from KCP&L to GMO, which they have done and are awaiting a decision.

GMO Missouri Rate Case Proceedings

On June 4, 2010, GMO filed requests with the MPSC to increase its Missouri retail electric annual revenues by $75.8 million for its Missouri Public Service division, and $22.1 million for its St. Joseph Light & Power division. GMO subsequently adjusted its requests during the rate case proceedings to $65.9 million and $23.2 million, respectively, as the net result of updates to the cases.

On February 22, 2011, the MPSC Staff filed updated testimony recommending revenue increase ranges of approximately $29,000 to $9.2 million for GMO’s Missouri Public Service division and approximately $14.9 million to $18.4 million for GMO’s St. Joseph Light & Power division. The revenue recommendations reflect the MPSC staff’s proposed construction cost disallowances for Iatan No. 2 and the Iatan No. 1 environmental project, among other differences from GMO’s requests.

Additionally, with respect to GMO’s Missouri Public Service division, one of the differences between the MPSC staff’s revenue recommendation and GMO’s request is the rate base amount for GMO’s Crossroads Energy Center (Crossroads). GMO’s request included a rate base amount of approximately $104 million for Crossroads. In the event of a disallowance of Crossroads costs, Great Plains Energy would compare the sum of the undiscounted expected future cash flows from Crossroads to its carrying value. If the sum of the undiscounted expected future cash flows from Crossroads is less than the carrying value, Great Plains Energy would recognize an impairment loss on its income statement with a corresponding write-down of utility plant on its balance sheet. The amount of the impairment loss recognized would be the excess of the carrying value of Crossroads over its fair value.

The outcome of the GMO case will likely be different from either of the positions of GMO or MPSC staff, though the decision of the MPSC cannot be projected. An order in these cases is expected in May 2011, with rates to take effect on June 4, 2011.

SPP and NERC Inquiries

The Southwest Power Pool, Inc. (SPP) conducted a compliance inquiry regarding a transmission system outage that occurred in the St. Joseph, Missouri area in the summer of 2009. The North American Electric Reliability Corporation (NERC) is also investigating the circumstances surrounding this transmission system outage. The outcome of the outage inquiry cannot be predicted at this time.

MPSC Regulatory Approval of the GMO Acquisition

Appeals of the MPSC order approving the GMO acquisition were filed with the Cole County, Missouri, Circuit Court, which affirmed the order in June 2009. That decision was appealed and the Missouri Court of Appeals, Western District, upheld the MPSC order in August 2010. The case was transferred to the Missouri Supreme Court in December 2010. Oral argument took place in March 2011. The parties await a decision.

Regulatory Assets and Liabilities

Great Plains Energy’s and KCP&L’s regulatory assets and liabilities are detailed in the following tables.


							Great
March 31, 2011	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	118.0		$	25.3		$	143.3
Loss on reacquired debt		4.9	(a)		0.7	(a)		5.6
Cost of removal		9.0			-			9.0
Asset retirement obligations		28.4			13.0			41.4
Pension settlements		7.9	(b)		-			7.9
Pension and post-retirement costs		366.2	(c)		111.9	(c)		478.1
Deferred customer programs		44.7	(d)		16.9			61.6
Rate case expenses		12.7	(e)		4.6	(e)		17.3
Skill set realignment costs		4.4	(f)		-			4.4
Fuel adjustment clauses		13.1	(e)		34.4	(e)		47.5
Acquisition transition costs		28.8	(g)		22.5	(g)		51.3
St. Joseph Light & Power acquisition		-			2.4	(h)		2.4
Storm damage		-			2.8	(i)		2.8
Derivative instruments		-			1.5	(j)		1.5
Iatan No. 1 and Common facilities depreciation and carrying costs		16.3			5.4	(k)		21.7
Iatan No. 2 construction accounting costs		26.0			11.6	(k)		37.6
Other		3.2	(l)		0.8	(l)		4.0
Total	$	683.6		$	253.8		$	937.4
Regulatory Liabilities
Emission allowances	$	85.5		$	0.5		$	86.0
Asset retirement obligations		49.4			-			49.4
Pension		-			38.0			38.0
Cost of removal		-			62.0	(m)		62.0
Other		12.6			19.3			31.9
Total	$	147.5		$	119.8		$	267.3

(a)	Amortized over the life of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.

(b)	$4.3 million not included in rate base and amortized through 2012.

(c)	Represents the funded status of the pension plans more than offset by related liabilities. Also represents financial and regulatory accounting method differences not included in rate base that will be eliminated over the life of the pension plans.

(d)	$12.0 million not included in rate base and amortized over various periods.

(e)	Not included in rate base and amortized over various periods.

(f)	$2.7 million not included in rate base and amortized through 2017.

(g)	Not included in rate base and amortized through 2016.

(h)	Not included in rate base and amortized through 2015.

(i)	Not included in rate base and amortized through 2012.

(j)	Represents the fair value of derivative instruments for commodity contracts. Settlements of the contracts are recognized in fuel expense and included in GMO’s fuel adjustment clause (FAC).

(k)	Not included in rate base and under consideration in the pending Missouri rate cases.

(l)	Certain insignificant items are not included in rate base and amortized over various periods.

(m)	Estimated cumulative net provision for future removal costs.


					Great
December 31, 2010	KCP&L		GMO		Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	117.2	$	25.3	$	142.5
Loss on reacquired debt		5.0		0.7		5.7
Cost of removal		8.5		-		8.5
Asset retirement obligations		27.5		12.8		40.3
Pension settlements		9.0		-		9.0
Pension and post-retirement costs		377.1		106.7		483.8
Deferred customer programs		44.7		15.6		60.3
Rate case expenses		12.3		3.3		15.6
Skill set realignment costs		4.8		-		4.8
Fuel adjustment clauses		8.4		37.1		45.5
Acquisition transition costs		29.3		22.5		51.8
St. Joseph Light & Power acquisition		-		2.6		2.6
Storm damage		-		3.2		3.2
Derivative instruments		-		3.1		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		15.1		4.3		19.4
Iatan No. 2 construction accounting costs		17.2		6.5		23.7
Other		3.5		0.7		4.2
Total	$	679.6	$	244.4	$	924.0
Regulatory Liabilities
Emission allowances	$	85.9	$	0.5	$	86.4
Asset retirement obligations		44.9		-		44.9
Pension		-		37.1		37.1
Cost of removal		-		62.8		62.8
Other		10.5		16.5		27.0
Total	$	141.3	$	116.9	$	258.2

PENSION PLANS AND OTHER EMPLOYEE BENEFITS

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Pension Plans and Other Employee Benefits

6.	PENSION PLANS, OTHER EMPLOYEE BENEFITS AND VOLUNTARY SEPARATION PROGRAM

Great Plains Energy maintains defined benefit pension plans for substantially all active and inactive employees, including officers, of KCP&L, GMO, and Wolf Creek Nuclear Operating Corporation (WCNOC) and incurs significant costs in providing the plans. Pension benefits under these plans reflect the employees’ compensation, years of service and age at retirement. In addition to providing pension benefits, Great Plains Energy provides certain post-retirement health care and life insurance benefits for substantially all retired employees of KCP&L, GMO, and WCNOC.

KCP&L and GMO record pension expense in accordance with rate orders from the MPSC and KCC that allow the difference between pension costs under Generally Accepted Accounting Principles (GAAP) and pension costs for ratemaking to be recognized as a regulatory asset or liability. The pension differences between the financial and regulatory accounting methods is due to timing and will be eliminated over the life of the pension plans.

The following table provides Great Plains Energy’s components of net periodic benefit costs prior to the effects of capitalization and sharing with joint-owners of power plants.


	Pension Benefits						Other Benefits
Three Months Ended March 31	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	7.8		$	7.6		$	0.8		$	0.9
Interest cost		12.5			12.3			2.0			2.2
Expected return on plan assets		(9.6	)		(9.1	)		(0.4	)		(0.5	)
Prior service cost		1.1			1.2			1.8			1.8
Recognized net actuarial loss (gain)		9.7			9.3			(0.1	)		-
Transition obligation		-			-			0.3			0.3
Net periodic benefit costs before
regulatory adjustment		21.5			21.3			4.4			4.7
Regulatory adjustment		(6.4	)		(8.4	)		0.2			-
Net periodic benefit costs	$	15.1		$	12.9		$	4.6		$	4.7

For the three months ended March 31, 2011, Great Plains Energy contributed $14.7 million to the pension plans and expects to contribute an additional $86.3 million in 2011 to satisfy the Employee Retirement Income Security Act of 1974, as amended (ERISA) funding requirements and the MPSC and KCC rate orders, the majority of which is expected to be paid by KCP&L.

Voluntary Separation Program

In March 2011, Great Plains Energy and KCP&L announced an organizational realignment process and a voluntary separation program to assist in the management of overall costs within the level reflected in the Companies’ retail electric rates and to enhance organizational efficiency. Savings from the realignment process and voluntary separation program, including approximately $15 million in labor costs on an annual basis, are expected to partially offset projected cost increases. Under the voluntary separation program, any non-union employee of the Companies could voluntarily elect to separate from the Companies and receive a severance payment equal to two weeks of salary for every year of employment, with a minimum severance payment equal to fourteen weeks of salary. Approximately 140 employees made such elections and the majority separated from the Companies on April 30, 2011. Great Plains Energy and KCP&L recorded $9.7 million and $6.8 million, respectively, for the three months ended March 31, 2011, related to this voluntary separation program reflecting severance and related payroll taxes provided by the Companies to employees who elected to voluntarily separate from the Companies. Great Plains Energy and KCP&L expect to incur total costs of approximately $14.2 million and $9.9 million, respectively, in connection with this voluntary separation program during 2011.

The Companies are currently assessing if a material pension settlement charge may result from the voluntary separation program as a result of accelerated pension distributions. If a pension settlement charge is incurred, the Companies expect to defer the charge and recover it over future periods pursuant to existing and past regulatory agreements. The amount of accelerated pension distributions resulting from the voluntary separation program may also result in increased pension funding requirements in 2011 under ERISA.

- Definition

Description containing the entire pension and other postretirement benefits disclosure as a single block of text.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 158

-Paragraph 7, 21, 22

Reference 2: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5, 6, 7, 8

Reference 3: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 8

-Subparagraph m

Reference 4: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 106

-Paragraph 518

Reference 5: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 87

-Paragraph 264

Reference 6: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph b

Reference 7: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph a

Reference 8: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph h

Reference 9: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph q

Reference 10: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name FASB Staff Position (FSP)

-Number FAS106-2

-Paragraph 20, 21, 22

Reference 11: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 03-2

-Paragraph 8

Reference 12: http://www.xbrl.org/2003/role/presentationRef

-Publisher AICPA

-Name Accounting Principles Board Opinion (APB)

-Number 30

-Paragraph 26

Reference 13: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Implementation Guide (Q and A)

-Number FAS88

-Paragraph 63

+ Details

EQUITY COMPENSATION

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Equity Compensation

7.	EQUITY COMPENSATION

Great Plains Energy’s Long-Term Incentive Plan is an equity compensation plan approved by Great Plains Energy’s shareholders. The Long-Term Incentive Plan permits the grant of restricted stock, stock options, limited stock appreciation rights, director shares, director deferred share units and performance shares to directors, officers and other employees of Great Plains Energy and KCP&L. Forfeiture rates are based on historical forfeitures and future expectations and are reevaluated annually.

The following table summarizes Great Plains Energy’s and KCP&L’s equity compensation expense and associated income tax benefits.


Three Months Ended March 31	2011		2010
Great Plains Energy	(millions)
Compensation expense	$	1.6	$	0.3
Income tax benefits		0.6		0.1
KCP&L
Compensation expense		1.1		0.2
Income tax benefits		0.4		-

Performance Shares

Performance share activity for the three months ended March 31, 2011, is summarized in the following table.


	Performance			Grant Date
	Shares			Fair Value*
Beginning balance		431,784		$	18.01
Granted		134,032			22.31
Earned		(68,258	)		11.04
Forfeited		(10,975	)		19.65
Ending balance		486,583			20.14
* weighted-average

At March 31, 2011, the remaining weighted-average contractual term was 1.7 years. The weighted-average grant-date fair value of shares granted was $22.31 and $23.38 for the three months ended March 31, 2011 and 2010, respectively. At March 31, 2011, there was $4.9 million of total unrecognized compensation expense, net of forfeiture rates, related to performance shares granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term. The total fair value of performance shares earned and paid for the three months ended March 31, 2011 and 2010, was $0.8 million and insignificant, respectively.

Restricted Stock

Restricted stock activity for the three months ended March 31, 2011, is summarized in the following table.


	Nonvested			Grant Date
	Restricted Stock			Fair Value*
Beginning balance		406,657		$	16.23
Granted and issued		135,532			19.14
Vested		(110,347	)		17.89
Forfeited		(6,927	)		15.39
Ending balance		424,915			16.84
* weighted-average

At March 31, 2011, the remaining weighted-average contractual term was 1.9 years. The weighted-average grant-date fair value of shares granted for the three months ended March 31, 2011 and 2010, was $19.14 and $17.71, respectively. At March 31, 2011, there was $4.7 million of total unrecognized compensation expense, net of forfeiture rates, related to nonvested restricted stock granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term. The total fair value of shares vested for the three months ended March 31, 2011 and 2010, was $2.0 million and $4.9 million, respectively.

SHORT TERM BORROWINGS AND SHORT TERM BANK LINES OF CREDIT

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Short-Term Borrowings and Short-Term Bank Lines of Credit

8.	SHORT-TERM BORROWINGS AND SHORT-TERM BANK LINES OF CREDIT

Great Plains Energy’s $200 Million Revolving Credit Facility

Great Plains Energy’s $200 million revolving credit facility with a group of banks expires in August 2013. The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time. A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At March 31, 2011, Great Plains Energy was in compliance with this covenant. At March 31, 2011, Great Plains Energy had $14.0 million of outstanding cash borrowings with a weighted-average interest rate of 3.06% and had issued letters of credit totaling $15.7 million under the credit facility. At December 31, 2010, Great Plains Energy had $9.5 million of outstanding cash borrowings with a weighted-average interest rate of 3.06% and had issued letters of credit totaling $15.8 million under the credit facility.

KCP&L’s $600 Million Revolving Credit Facility and Commercial Paper

KCP&L’s $600 million revolving credit facility with a group of banks to provide support for its issuance of commercial paper and other general corporate purposes expires in August 2013. Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities. A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At March 31, 2011, KCP&L was in compliance with this covenant. At March 31, 2011, KCP&L had $288.8 million of commercial paper outstanding, at a weighted-average interest rate of 0.40%, $20.9 million of letters of credit outstanding and no outstanding cash borrowings under the facility. At December 31, 2010, KCP&L had $263.5 million of commercial paper outstanding, at a weighted-average interest rate of 0.41%, $24.4 million of letters of credit outstanding and no outstanding cash borrowings under the facility.

GMO’s $450 Million Revolving Credit Facility

GMO’s $450 million revolving credit facility with a group of banks expires in August 2013. Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities. A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At March 31, 2011, GMO was in compliance with this covenant. At March 31, 2011, GMO had $205.0 million of outstanding cash borrowings with a weighed-average interest rate of 3.06% and had issued letters of credit totaling $13.2 million under the credit facility. At December 31, 2010, GMO had no outstanding cash borrowings and had issued letters of credit totaling $13.2 million under the credit facility.

LONG TERM DEBT

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Long-Term Debt

9.	LONG-TERM DEBT

Great Plains Energy’s and KCP&L’s long-term debt is detailed in the following table.


		March 31			December 31
	Year Due	2011			2010
KCP&L		(millions)
General Mortgage Bonds
4.90%* EIRR bonds	2012-2035	$	158.8		$	158.8
7.15% Series 2009A (8.59% rate**)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
5.125% EIRR Series 2007A-1	2035		63.3			63.3
2.625% EIRR Series 2007A-2	2035		10.0			10.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
6.50% Series	2011		150.0			150.0
5.85% Series (5.72% rate**)	2017		250.0			250.0
6.375% Series (7.49% rate**)	2018		350.0			350.0
6.05% Series (5.78% rate**)	2035		250.0			250.0
EIRR Bonds
4.90% Series 2008	2038		23.4			23.4
Other	2011-2018		3.3			3.3
Current maturities			(275.5	)		(150.3	)
Unamortized discount			(1.9	)		(2.0	)
Total KCP&L			1,504.6			1,629.7

Other Great Plains Energy
GMO First Mortgage Bonds
9.44% Series	2012-2021		11.2			12.4
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.262%*** Wamego Series 1996	2026		7.3			7.3
0.548%*** State Environmental 1993	2028		5.0			5.0
GMO Senior Notes
7.95% Series			-			137.3
7.75% Series	2011		197.0			197.0
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			40.9			49.9
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate**)	2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate**)	2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes	2042		287.5			287.5
Current maturities			(198.1	)		(335.4	)
Unamortized discount			(0.5	)		(0.5	)
Total Great Plains Energy excluding current maturities		$	2,807.4		$	2,942.7
* Weighted-average interest rates at March 31, 2011
** Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
*** Variable rate

Fair Value of Long-Term Debt

Fair value of long-term debt is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices were not available. At March 31, 2011, and December 31, 2010, the book value of Great Plains Energy’s long-term debt, including current maturities, was $3.3 billion and $3.4 billion, respectively. At March 31, 2011, and December 31, 2010, the fair value of Great Plains Energy’s long-term debt, including current maturities, was $3.5 billion and $3.7 billion, respectively. At March 31, 2011, and December 31, 2010, the book value of KCP&L’s long-term debt, including current maturities, was $1.8 billion. At March 31, 2011, and December 31, 2010, the fair value of KCP&L’s long-term debt, including current maturities, was $1.9 billion.

KCP&L General Mortgage Bonds and EIRR Bonds

In April 2011, KCP&L purchased in lieu of redemption its $63.3 million EIRR Series 2007A-1, $10.0 million EIRR Series 2007A-2 and $39.5 million EIRR Series 1993B bonds. KCP&L opted to purchase rather than remarket the bonds given the poor conditions in the tax-exempt market. The bonds were reported as current maturities of long-term debt on Great Plains Energy’s and KCP&L’s balance sheets at March 31, 2011. KCP&L issued commercial paper to fund the purchase of the bonds. As of April 2011, the bonds were still outstanding, but will not be reported as a liability on the balance sheet since they are being held by KCP&L. KCP&L has the ability to remarket these bonds to third parties whenever it determines market conditions are sufficiently attractive to do so.

GMO Senior Notes

In February 2011, GMO repaid its $137.3 million 7.95% Senior Notes that matured in February 2011 with borrowings from its short-term revolving credit facility.

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Commitments and Contingencies

10.	COMMITMENTS AND CONTINGENCIES

Environmental Matters

Great Plains Energy and KCP&L are subject to extensive regulation by federal, state and local authorities with regard to environmental matters primarily through their utility operations. In addition to imposing extensive and continuing compliance obligations, laws, regulations and permits authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is expected to be material to Great Plains Energy and KCP&L. Failure to comply with environmental requirements or to timely recover environmental costs through rates could have a material adverse effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

The following discussion groups environmental and certain associated matters into the broad categories of air and climate change, water, solid waste and remediation.

Air and Climate Change

The Clean Air Act and associated regulations enacted by the Environmental Protection Agency (EPA) form a comprehensive program to preserve air quality. States are required to establish regulations and programs to address all requirements of the Clean Air Act and have the flexibility to enact more stringent requirements. All of Great Plains Energy’s and KCP&L’s generating facilities, and certain of their other facilities, are subject to the Clean Air Act.

Great Plains Energy’s and KCP&L’s current estimate of capital expenditures (exclusive of AFUDC and property taxes) to comply with the currently effective Clean Air Interstate Rule (CAIR), the best available retrofit technology (BART) rule and the industrial boiler rule (discussed below) is approximately $1 billion.

As discussed below, CAIR has been remanded to the EPA, but remains in effect until the EPA issues final rules consistent with the court’s order or until the court takes further action. In July 2010, the EPA proposed the Transport Rule to replace CAIR. In March 2011, the EPA proposed maximum achievable control technology (MACT) standards for mercury and other hazardous air pollutant emissions. While the Companies cannot reasonably predict at this time the impacts of final rules, if the rules were finalized as currently proposed, the Companies expect that any required capital expenditures to comply with the Transport Rule, BART, the industrial boiler rule and MACT standards for mercury and other hazardous air pollutant emissions would be within the approximate $1 billion estimate of capital expenditures (exclusive of AFUDC and property taxes) to comply with the currently effective CAIR, BART and industrial boiler rule. However, due to uncertainties regarding the proposed rules (discussed below), it is not possible to predict what the final rules may be, when the rules may be issued, or the costs associated with such final rules. The actual cost of compliance with any future rules, and with BART, may be significantly different from the cost estimate provided.

The potential capital costs of the Collaboration Agreement provisions (discussed below) relating to NOx, SO2 and particulate emission limits at the LaCygne generating station are within the disclosed overall capital cost estimate of approximately $1 billion (discussed above). However, the estimated capital costs do not reflect potential costs relating to requirements enacted in the future, including potential requirements regarding climate change (discussed below), and also do not reflect costs relating to additional wind generation, energy efficiency and other CO2 emission offsets contemplated by the Collaboration Agreement or that may be required under the Missouri or Kansas renewable energy standards, which are discussed below. The estimate does not reflect the non-capital costs the Companies incur on an ongoing basis to comply with environmental laws, which may increase in the future due to the Companies’ ongoing compliance with current or future environmental laws. KCP&L expects to seek recovery of the costs associated with the Collaboration Agreement and the Companies expect to seek recovery of the costs associated with environmental requirements through rate increases; however, there can be no assurance that such rate increases would be granted. The Companies may be subject to materially adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies’ environmental reputation.

Clean Air Interstate Rule (CAIR) and Transport Rule

The CAIR requires reductions in SO2 and NOx emissions in 28 states, including Missouri. The reduction in both SO2 and NOx emissions is accomplished through statewide caps for NOx and SO2. More restrictive caps are scheduled to become effective January 1, 2015. Great Plains Energy’s and KCP&L’s fossil fuel-fired plants located in Missouri are subject to CAIR, while their fossil fuel-fired plants in Kansas are not.

On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety and remanded the matter to the EPA to promulgate a new rule consistent with its opinion. On December 23, 2008, the Court issued an order remanding CAIR to the EPA to revise the rule consistent with its July 2008 order. The CAIR thus remains in effect pending future EPA or court action, including the proposed Transport Rule discussed below.

CAIR currently establishes a market-based cap-and-trade program with an emission allowance allocation. Facilities demonstrate compliance with CAIR by holding sufficient allowances for each ton of SO2 and NOx emitted in any given year. KCP&L and GMO are currently allowed to utilize unused SO2 emission allowances that they have either accumulated during previous years of the Acid Rain Program or purchased to meet the more stringent CAIR requirements. At March 31, 2011, KCP&L had accumulated unused SO2 emission allowances sufficient to support over 150,000 tons of SO2 emissions (enough to support expected requirements under the current CAIR for the foreseeable future) under the provisions of the Acid Rain program, which are recorded in inventory at zero cost. At March 31, 2011, GMO had accumulated unused SO2 emission allowances sufficient to support just over 16,000 tons of SO2 emissions (enough to support expected requirements under the current CAIR through 2011), which it has received under the Acid Rain Program or purchased, and are recorded in inventory at average cost. KCP&L and GMO purchase NOx allowances as needed.

Analysis of the current CAIR rule indicates that NOx and SO2 control may be required for KCP&L’s Montrose Station and GMO’s Sibley and Lake Road Stations in Missouri, and control may be achieved through a combination of pollution control equipment and the use or purchase of emission allowances as needed.

In July 2010, the EPA proposed the Transport Rule to replace the current CAIR. The Transport Rule, like CAIR, will require the states within its scope to reduce power plant SO2 and NOx emissions that contribute to ozone and fine particle nonattainment in other states. The geographical scope of the Transport Rule is broader than CAIR, and includes Kansas in addition to Missouri and other states. The Transport Rule would also impose more stringent emissions limitations than CAIR and, unlike CAIR, would not utilize Acid Rain Program allowances for compliance. The EPA is proposing a preferred approach and is taking comment on two alternatives. In the EPA’s preferred approach, the EPA would set an emissions budget for each of the affected states and the District of Columbia. The preferred approach would allow limited interstate emissions allowance trading among power plants; however, it would not permit trading of SO2 allowances between the Companies’ Kansas and Missouri power plants. In the first alternative, the EPA is proposing to set an emissions budget for each state and allow emissions allowance trading only among power plants within a state. In the second alternative, the EPA is proposing to set an emissions budget for each state, specify the allowable emission limit for each power plant and allow some averaging. Compliance with the Transport Rule would begin in 2012. There would be additional reductions in SO2 allowances allocable to the Companies’ Missouri power plants taking effect in 2014 pursuant to the preferred approach. There is no such additional reduction in SO2 allowances allocable to the Companies’ Kansas power plants.

The proposed Transport Rule is complex and, as noted, contains alternative approaches. Great Plains Energy and KCP&L are unable to predict when the Transport Rule (or other rule replacing CAIR) might be adopted, or the actual requirements of such rule. Preliminary analysis of the Transport Rule has raised various questions regarding the emission allowances allocation to, and the allowable emission rates for, the Companies’ power plants pursuant to the preferred approach and alternatives, which the Companies addressed during the rule’s comment period. Regardless of the resolution of those questions, the Companies project that they may not be allocated sufficient SO2 or NOX emissions allowances to cover their currently expected operations starting in 2012 pursuant to the preferred approach. Any shortfall in allocated allowances would need to be addressed through permissible allowance trading, installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market, or a combination of these and other alternatives. Any final rule could have a significant adverse effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Best Available Retrofit Technology (BART) Rule

The EPA BART rule directs state air quality agencies to identify whether visibility-reducing emissions from sources subject to BART are below limits set by the state or whether retrofit measures are needed to reduce emissions. BART applies to specific eligible facilities including KCP&L’s LaCygne Nos. 1 and 2 in Kansas, KCP&L’s Iatan No. 1, in which GMO has an 18% interest, KCP&L’s Montrose No. 3 in Missouri, GMO’s Sibley Unit No. 3 and Lake Road Unit No. 6 in Missouri and Westar Energy, Inc.’s (Westar) Jeffrey Unit Nos. 1 and 2 in Kansas, in which GMO has an 8% interest. Initially, in Missouri, compliance with CAIR will be compliance with BART for individual sources. Both Missouri and Kansas have submitted BART plans to the EPA but neither Missouri nor Kansas has received EPA approval for their BART plans.

Mercury and Other Hazardous Air Pollutant Emissions

In January 2009, the EPA issued a memorandum stating that new electric steam generating units (EGUs) that began construction while the Clean Air Mercury Rule (CAMR) was effective are subject to a new source maximum achievable control technology (MACT) determination on a case-by-case basis.

In July 2009, the EPA sent letters notifying KCP&L that MACT determinations and schedules of compliance are required for coal and oil-fired EGUs that began actual construction or reconstruction after December 15, 2000, and identified Iatan No. 2 and Hawthorn No. 5 as affected EGUs. This was an outcome of the D.C. Court of Appeals’ vacatur of both the CAMR and the contemporaneously promulgated rule removing EGUs from MACT requirements. KCP&L believes that Hawthorn No. 5 is not an affected EGU based on the reconstruction dates of the unit, and provided supporting documentation to the Missouri Department of Natural Resources (MDNR). It is not currently known how MACT determinations and schedules of compliance will impact the permitting or operating requirements for these two units, but it is possible a MACT determination may ultimately require additional emission control equipment and permit limits at Iatan No. 2, Hawthorn No. 5, or both.

In April 2010, the EPA, in a court approved settlement, agreed to develop MACT standards for mercury and potentially other hazardous air pollutant emissions. In the settlement agreement, the EPA agreed to propose MACT standards in March 2011 with final standards by November 2011. In March 2011, the EPA issued a proposed rule that would reduce emissions of hazardous air pollutants from new and existing coal-fired EGUs with a capacity of 25MW or greater. The proposed rule would establish numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrogen chloride (a surrogate for acid gases). The proposed rule would establish work practices, instead of numerical emission limits, for organic hazardous air pollutants, including dioxin/furan. Compliance with the rule would need to be addressed by installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market or a combination of these and other alternatives. Any final rule could have a significant adverse effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Industrial Boiler Rule

In February 2011, the EPA issued a final rule that would reduce emissions of hazardous air pollutants from new and existing industrial boilers. The final rule establishes numeric emission limits for mercury, dioxin, particulate matter (as a surrogate for non-mercury metals), hydrogen chloride (as a surrogate for acid gases), and carbon monoxide (as a surrogate for non-dioxin organic hazardous air pollutants). The EPA also announced it will allow an administrative reconsideration of the final rule seeking additional comment. The final rule establishes emission limits for KCP&L’s and GMO’s new and existing units that produce steam other than for the generation of electricity. The final rule does not apply to KCP&L’s and GMO’s electricity generating boilers, but would apply to most of GMO’s Lake Road boilers, which also serve steam customers, and to auxiliary boilers at other generating facilities.

New Source Review

The Clean Air Act requires 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.

In January 2004, Westar received notification from the EPA alleging that it had violated new source review requirements and Kansas environmental regulations by making modifications to the Jeffrey Energy Center without obtaining the proper permits. In February 2009, the Attorney General of the United States filed a complaint against Westar alleging that it violated the Clean Air Act and related federal and state regulations by making major modifications to the Jeffrey Energy Center beginning in 1994 without first obtaining appropriate permits authorizing this construction and without installing and operating best available control technology to control emissions. The Jeffrey Energy Center consists of three coal-fired units located in Kansas that is 92% owned by Westar and operated exclusively by Westar. GMO has an 8% interest in the Jeffrey Energy Center and is generally responsible for its 8% share of the facility’s operating costs and capital expenditures. In January 2010, Westar entered into a settlement agreement, which was approved by the court in March 2010. The settlement agreement requires, among other things, the installation of a selective catalytic reduction (SCR) system at one of the Jeffrey Energy Center units by the end of 2014 and the payment of a $3 million civil penalty. Westar has preliminarily estimated the cost of this SCR at approximately $240 million. This amount could materially change depending on final engineering and design. Depending on the NOx emission reductions attained by that SCR and attainable through the installation of other controls at the other two units, the settlement agreement may require the installation of a second SCR system on one of the other two units by the end of 2016. There is no assurance that GMO’s share of these costs would be recovered in rates and failure to recover such costs could have a significant adverse effect on Great Plains Energy’s results of operations, financial position and cash flows.

KCP&L has received requests for information from the Kansas Department of Health and Environment (KDHE) pertaining to a past LaCygne No. 1 scrubber project. KCP&L is working with the KDHE to resolve this issue and management currently believes the outcome will not have a significant impact to Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Collaboration Agreement

In March 2007, KCP&L, the Sierra Club and the Concerned Citizens of Platte County entered into a Collaboration Agreement under which KCP&L agreed to pursue a set of initiatives including energy efficiency, additional wind generation, lower emission permit levels at its Iatan and LaCygne generating stations and other initiatives designed to offset CO2 emissions. Full implementation of the terms of the Collaboration Agreement will necessitate approval from the appropriate authorities, as some of the initiatives in the agreement require regulatory approval.

In 2006, KCP&L installed 100MW of wind generation at its Spearville wind site. KCP&L agreed in the Collaboration Agreement to pursue increasing its wind generation capacity to 500MW in total by the end of 2012 with 100MW to be added by the end of 2010 and the remainder added by the end of 2012, subject to regulatory approval. In 2010, KCP&L completed a 48MW wind project adjacent to its existing Spearville wind site with wind turbines it already owned and also secured 52MW of renewable energy credits. During 2011, KCP&L entered into a 20-year power purchase agreement for approximately 132MW of wind generation beginning in 2012. KCP&L is evaluating alternatives to meet the remaining wind generation capacity requirement, including the purchase of renewable energy credits, power purchase agreements, KCP&L-built installations or some combination thereof.

KCP&L agreed in the Collaboration Agreement to seek a consent agreement, which it has done, with the KDHE incorporating limits for stack particulate matter emissions, as well as limits for NOx and SO2 emissions at its LaCygne Station that will be below the presumptive limits under BART. KCP&L further agreed to use its best efforts to install emission control technologies to reduce those emissions from the LaCygne Station prior to the required compliance date under BART, but in no event later than June 1, 2015. KCP&L has issued requests for proposals for environmental equipment required to comply with BART at the LaCygne Station and is evaluating the responses. In February 2011, KCP&L filed a request with KCC for predetermination of the ratemaking treatment that will apply to the recovery of costs for its 50% share of the environmental equipment required to comply with BART at the LaCygne Station. The request for predetermination includes an estimated total project cost of $1.23 billion. KCP&L’s 50% share of the estimated cost is $615 million. A KCC decision on the predetermination filing is expected in August 2011. In a related proceeding, in January 2011, KCC opened a general investigation docket regarding KCP&L and Westar environmental retrofits upon the recommendation of the KCC Staff and the Citizens Utility Ratepayers Board. The Companies cannot predict the outcome or timing of this matter but the outcome could have the potential to impact the Companies’ resource planning in the future.

In the Collaboration Agreement, KCP&L also agreed to offset an additional 711,000 tons of CO2 by the end of 2012. KCP&L currently expects to achieve this offset through a number of alternatives, including improving the efficiency of its coal-fired units, equipping certain gas-fired units for winter operation and, if necessary, possibly reducing output of, or retiring, one or more coal-fired units.

Climate Change

The Companies are subject to existing greenhouse gas reporting regulations and, as discussed below, are subject to certain greenhouse gas permitting requirements starting in 2011. Management believes it is likely that additional federal or relevant state or local laws or regulations could be enacted to address global climate change. At the international level, while the United States is not a current party to the Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions. International agreements legally binding on the United States may be reached in the future. Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels. The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 23 million tons and 17 million tons per year for Great Plains Energy and KCP&L, respectively.

Laws have recently been passed in Missouri and Kansas, the states in which the Companies’ retail electric businesses are operated, setting renewable energy standards, and management believes that national clean or renewable energy standards are also likely. While management believes additional requirements addressing these matters will probably be enacted, the timing, provisions and impact of such requirements, including the cost to obtain and install new equipment to achieve compliance, cannot be reasonably estimated at this time. In addition, certain federal courts have held that state and local governments and private parties have standing to bring climate change tort suits seeking company-specific emission reductions and monetary or other damages. The U.S. Supreme Court has heard arguments and is expected to rule on an appeal of one of those suits. While the Companies are not a party to any climate change tort suit, there is no assurance that such suits may not be filed in the future or the outcome if such suits are filed. Such requirements or litigation outcomes could have the potential for a significant financial and operational impact on Great Plains Energy and KCP&L. The Companies would seek recovery of capital costs and expenses for compliance through rate increases; however, there can be no assurance that such rate increases would be granted.

Legislation concerning the reduction of emissions of greenhouse gases, including CO2, is being considered at the federal and state levels. The timing and effects of any such legislation cannot be determined at this time. In the absence of new Congressional mandates, the EPA is proceeding with the regulation of greenhouse gases under the existing Clean Air Act.

In May 2010, the EPA issued a final rule addressing greenhouse gas emissions from stationary sources under the Clean Air Act permitting programs. This final rule sets thresholds for greenhouse gas emissions that define when permits under the Prevention of Significant Deterioration (PSD) and Title V Operating Permit programs are required for new and existing industrial facilities. The EPA phased in the Clean Air Act permitting requirements for greenhouse gas emissions in two initial steps. In step 1, which started January 2, 2011, only sources currently subject to the PSD permitting program (i.e., those that are newly-constructed or modified in a way that significantly increases emissions of a pollutant other than greenhouse gas) are subject to Title V or PSD permitting requirements, respectively, for their greenhouse gas emissions. For these projects, only projects with new or increases of greenhouse gas emissions of 75,000 tons per year or more of total greenhouse gases, on a CO2 equivalent basis, need to determine the best available control technology for their greenhouse gas emissions. In addition, sources subject to the Title V Operating Permit Program need to address greenhouse gas emissions as those permits are applied for or renewed. In step 2, starting July 1, 2011, Title V and PSD permitting requirements will cover, for the first time, new construction projects that emit greenhouse gas emissions of at least 100,000 tons per year even if they do not exceed the permitting thresholds for any other pollutant. In addition, modifications at such existing facilities that increase greenhouse gas emissions by at least 75,000 tons per year will be subject to permitting requirements, even if they do not significantly increase emissions of any other pollutant. Great Plains Energy’s and KCP&L’s generating facilities that trigger these thresholds for new installations, modifications or Title V operating permits will be subject to this rule.

In March 2011, the EPA announced it finalized a settlement agreement to issue a rule that will address greenhouse gas emissions from EGUs. The rule would establish new source performance standards for new and modified EGUs and emission guidelines for existing EGUs. Under the settlement agreement, the EPA committed to issuing proposed regulations by July 2011, and final regulations by May 2012.

At the state level, a Kansas law enacted in May 2009 requires Kansas public electric utilities, including KCP&L, to have renewable energy generation capacity equal to at least 10% of their three-year average Kansas peak retail demand by 2011. The percentage increases to 15% by 2016 and 20% by 2020. A Missouri law enacted in November 2008 requires at least 2% of the electricity provided by Missouri investor-owned utilities (including KCP&L and GMO) to their Missouri retail customers to come from renewable resources, including wind, solar, biomass and hydropower, by 2011, increasing to 5% in 2014, 10% in 2018, and 15% in 2021, with a small portion (estimated to be about 2MW in 2011 for each of KCP&L and GMO) required to come from solar resources.

KCP&L and GMO project that their current renewable resources (including accumulated renewable energy credits) will be sufficient for compliance with the Missouri requirements, exclusive of the solar requirement, through 2021 and 2015, respectively. KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri requirements through 2011. The Companies have issued requests for proposals for compliance with the solar requirement beyond 2011 and are evaluating the proposals. KCP&L and GMO continue to evaluate options for compliance beyond these years.

KCP&L also projects that its current renewable resources (including accumulated renewable energy credits) combined with the 48MW wind project and 52MW of renewable energy credits discussed above will be sufficient for compliance with the 2011 Kansas requirements. During 2011, KCP&L entered into a 20-year power purchase agreement for approximately 132 MW of wind generation beginning in 2012. With this PPA, KCP&L anticipates its renewable resources will be sufficient for compliance with the Kansas requirements in 2012.

Additionally, in November 2007, governors from six Midwestern states, including Kansas, signed the Midwestern Greenhouse Gas Reduction Accord, which has established the goal of reducing member states’ greenhouse gas emissions to 15% to 20% below 2005 levels by 2020, and 60% to 80% below 2005 levels by 2050.

Greenhouse gas legislation or regulation has the potential of having significant financial and operational impacts on Great Plains Energy and KCP&L, including the potential costs and impacts of achieving compliance with limits that may be established. However, the ultimate financial and operational consequences to Great Plains Energy and KCP&L cannot be determined until such legislation is passed and/or regulations are issued. Management will continue to monitor the progress of relevant legislation and regulations.

Ozone NAAQS

In June 2007, monitor data indicated that the Kansas City area violated the 1997 primary eight-hour ozone national ambient air quality standard (NAAQS). Missouri and Kansas have implemented the responses established in the maintenance plans for control of ozone. The responses in both states do not require additional controls at Great Plains Energy’s and KCP&L’s generation facilities beyond the currently proposed controls for CAIR and BART. The EPA has various options over and above the implementation of the maintenance plans for control of ozone to address the violation but has not yet acted. At this time, management is unable to predict how the EPA will respond or how that response will impact Great Plains Energy’s and KCP&L’s operations. However, the EPA’s response could have a significant effect on Great Plains Energy's and KCP&L's results of operations, financial position and cash flows.

In March 2008, the EPA significantly strengthened its NAAQS for ground-level ozone. The EPA revised the primary eight-hour ozone standard, designed to protect public health, to a level of 0.075 parts per million (ppm). The EPA also strengthened the secondary eight-hour ozone standard to the level of 0.075 ppm making it identical to the revised primary standard. The previous primary and secondary standards, set in 1997, were effectively 0.084 ppm.

In March 2009, the MDNR and KDHE submitted to the EPA their determinations that the Kansas City area is a nonattainment area under the 2008 primary eight-hour ozone standard. The EPA will make final designations of attainment and nonattainment areas. By 2013, states must submit state implementation plans outlining how states will reduce ozone to meet the standards in nonattainment areas. Although the impact on Great Plains Energy’s and KCP&L’s operations will not be known until after the final nonattainment designations and the state implementation plans are submitted, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

In January 2010, the EPA proposed to reconsider and further strengthen the 2008 NAAQS for ground-level ozone. The EPA proposed to strengthen the primary eight-hour ozone standard to a level within the range of 0.060-0.070 ppm. The EPA also proposed to establish a distinct cumulative, seasonal secondary standard, designed to protect sensitive vegetation and ecosystems, to within the range of 7-15 ppm-hours. In December 2010, the EPA filed a motion requesting court approval for additional time, until July 2011, to finalize the rule.

SO2 NAAQS

In June 2010, the EPA strengthened the primary NAAQS for SO2. The EPA revised the primary SO2 standard by establishing a new 1-hour standard at a level of 0.075 ppm. The EPA revoked the two existing primary standards of 0.140 ppm evaluated over 24-hours and 0.030 ppm evaluated over an entire year. Although the impact on Great Plains Energy’s and KCP&L’s operations will not be known until after the nonattainment designations are approved and the state implementation plans are submitted, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Montrose Station Notice of Violation

In June 2009, KCP&L received notification from the MDNR alleging that its Montrose Station had excess particulate matter emissions in 2008. KCP&L is working with the MDNR to resolve this issue and management believes the outcome will not have a significant impact to Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Water

The Clean Water Act and associated regulations enacted by the EPA form a comprehensive program to preserve water quality. Like the Clean Air Act, states are required to establish regulations and programs to address all requirements of the Clean Water Act, and have the flexibility to enact more stringent requirements. All of Great Plains Energy’s and KCP&L’s generating facilities, and certain of their other facilities, are subject to the Clean Water Act.

In March 2011, the EPA proposed regulations pursuant to Section 316(b) of the Clean Water Act regarding cooling water intake structures pursuant to a court approved settlement. KCP&L generation facilities with cooling water intake structures would be subject to a limit on how many fish can be killed by being pinned against intake screens (impingement) and would be required to conduct studies to determine whether and what site-specific controls, if any, would be required to reduce the number of aquatic organisms drawn into cooling water systems (entrainment). The EPA agreed to finalize the rule by July 2012. Although the impact on Great Plains Energy’s and KCP&L’s operations will not be known until after the rule is finalized, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

KCP&L holds a permit from the MDNR covering water discharge from its Hawthorn Station. The permit authorizes KCP&L to, among other things, withdraw water from the Missouri river for cooling purposes and return the heated water to the Missouri river. KCP&L has applied for a renewal of this permit and the EPA has submitted an interim objection letter regarding the allowable amount of heat that can be contained in the returned water. Until this matter is resolved, KCP&L continues to operate under its current permit. KCP&L cannot predict the outcome of this matter; however, while less significant outcomes are possible, this matter may require KCP&L to reduce its generation at Hawthorn Station, install cooling towers or both, any of which could have a significant impact on KCP&L. The outcome could also affect the terms of water permit renewals at KCP&L’s Iatan Station and at GMO’s Sibley and Lake Road Stations.

Additionally, in September 2009, the EPA announced plans to revise the existing standards for water discharges from coal-fired power plants. In November 2010, the EPA filed a motion requesting court approval of a consent agreement in which the EPA agreed to propose a rule in July 2012 and to finalize it in January 2014. Until a rule is proposed and finalized, the financial and operational impacts to Great Plains Energy and KCP&L cannot be determined.

Solid Waste

Solid and hazardous waste generation, storage, transportation, treatment and disposal is regulated at the federal and state levels under various laws and regulations. In May 2010, the EPA proposed to regulate coal combustion residuals (CCRs) under the Resource Conservation and Recovery Act (RCRA) to address the risks from the disposal of CCRs generated from the combustion of coal at electric generating facilities. The EPA is considering two options in this proposal. Under the first proposal, the EPA would regulate CCRs as special wastes subject to regulation under subtitle C of RCRA (hazardous), when they are destined for disposal in landfills or surface impoundments. Under the second proposal, the EPA would regulate disposal of CCRs under subtitle D of RCRA (non-hazardous). The Companies principally use coal in generating electricity and dispose of the CCRs in both on-site facilities and facilities owned by third parties. The proposed CCR rule has the potential of having a significant financial and operational impact on Great Plains Energy and KCP&L in connection with achieving compliance with the proposed requirements. However, the financial and operational consequences to Great Plains Energy and KCP&L cannot be determined until an option is selected by the EPA and the final regulation is enacted.

Remediation

Certain federal and state laws, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) hold current and previous owners or operators of real property, and any person who arranges for the disposal or treatment of hazardous substances at a property, liable on a joint and several basis for the costs of cleaning up contamination at or migrating from such real property, even if they did not know of and were not responsible for such contamination. CERCLA and other laws also authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. GMO is named as a potentially responsible party at two disposal sites for polychlorinated biphenyls (PCBs), and retains some environmental liability for several operations and investments it no longer owns. In addition, GMO also owns, or has acquired liabilities from companies that once owned or operated, former manufactured gas plant (MGP) sites, which are subject to the supervision of the EPA and various state environmental agencies.

At March 31, 2011, and December 31, 2010, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site. At March 31, 2011, and December 31, 2010, Great Plains Energy had $0.4 million accrued for environmental remediation expenses, which includes the $0.3 million at KCP&L, and additional potential remediation and ground water monitoring costs relating to two GMO sites. The amounts accrued were established on an undiscounted basis and Great Plains Energy and KCP&L do not currently have an estimated time frame over which the accrued amounts may be paid.

In addition to the $0.4 million accrual above, at March 31, 2011, and December 31, 2010, Great Plains Energy had $2.1 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB sites and retained liabilities. This estimate was based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary. This estimate could change materially after further investigation, and could also be affected by the actions of environmental agencies and the financial viability of other potentially responsible parties.

GMO has pursued recovery of remediation costs from insurance carriers and other potentially responsible parties. As a result of a settlement with an insurance carrier, approximately $2.3 million in insurance proceeds less an annual deductible is available to GMO to recover qualified MGP remediation expenses. GMO would seek recovery of additional remediation costs and expenses through rate increases; however, there can be no assurance that such rate increases would be granted.

In January 2010, the EPA announced an advance notice of proposed rulemaking under CERCLA identifying classes of facilities for which the EPA will develop financial assurance requirements, including the electric power generation, transmission and distribution industry. The CERCLA financial assurance would be for risks associated with Great Plains Energy’s and KCP&L’s production, transportation, treatment, storage or disposal of CERCLA hazardous substances. The impact on Great Plains Energy and KCP&L cannot be determined until the regulations are finalized.

In April 2010, the EPA announced an advance notice of proposed rulemaking for the use and distribution in commerce of certain PCBs, PCB items and certain other areas of the PCB regulations. The EPA is reassessing the use, distribution in commerce, marking, and storage for reuse of liquid PCBs in electric and non-electric equipment and the use of the 50 ppm level for excluded PCB products among other things. The impact on Great Plains Energy and KCP&L cannot be determined until the regulations are finalized.

LEGAL PROCEEDINGS

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Legal Proceedings

11.	LEGAL PROCEEDINGS

KCP&L Spent Nuclear Fuel and Radioactive Waste

In January 2004, KCP&L and the other two Wolf Creek owners filed a lawsuit against the United States in the U.S. Court of Federal Claims seeking $14.1 million of damages resulting from the government’s failure to begin accepting spent nuclear fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982. The Wolf Creek case was tried before a U.S. Court of Federal Claims judge in June 2010, and a decision was issued in November 2010, granting KCP&L and the other two Wolf Creek owners $10.6 million ($5.0 million KCP&L share) in damages. In January 2011, KCP&L and the other two Wolf Creek owners as well as the United States filed appeals of the decision to the U.S. Court of Appeals for the Federal Circuit. The court has set a briefing schedule. Briefing likely will conclude in the fourth quarter of 2011, and the parties will present their oral arguments to the court sometime thereafter.

Iatan Levee Litigation

On May 22, 2009, several farmers filed suit against Great Plains Energy and KCP&L in the Circuit Court of Platte County, Missouri, alleging negligence, private nuisance, trespass and violations of the Missouri Crop Protection Act and seeking unspecified compensatory and punitive damages. These allegations stem from flooding at or near the Iatan Station in 2007 and 2008. The farmers allege the flooding was a result of maintenance of a nearby levee. The petition seeks class certification from the courts. Written discovery and depositions are underway. This matter is set for trial in November 2011. Management cannot predict the outcome of this matter.

GMO Price Reporting Litigation

In response to complaints of manipulation of the California energy market, in July 2001, FERC issued an order requiring net sellers of power in the California markets from October 2, 2000, through June 20, 2001, at prices above a FERC determined competitive market clearing price to make refunds to net purchasers of power in the California market during that time period. Because MPS Merchant was a net purchaser of power during the refund period, it has received approximately $8 million in refunds through settlements with certain sellers of power. MPS Merchant estimates that it is entitled to approximately $12 million in additional refunds under the standards FERC has used in this case. FERC has stated that interest will be applied to the refunds but the amount of interest has not yet been determined. However, in December 2001, various parties appealed the FERC order to the United States Court of Appeals for the Ninth Circuit seeking review of a number of issues, including changing the refund period to include periods prior to October 2, 2000. MPS Merchant was a net seller of power during the period prior to October 2, 2000. On August 2, 2006, the U.S. Court of Appeals for the Ninth Circuit issued an order finding, among other things, that FERC did not provide a sufficient justification for refusing to exercise its remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the period prior to October 2, 2000, and imposing a remedy for any such violations. The court remanded the matter to FERC to determine whether tariff violations occurred and, if so, the appropriate remedy. In March 2008, FERC issued an order declining to order refunds for the period prior to October 2, 2000. That order has been appealed to the U.S. Court of Appeals for the Ninth Circuit. If FERC ultimately includes the period prior to October 2, 2000, MPS Merchant could be found to owe refunds.

FERC initiated a separate docket, generally referred to as the Pacific Northwest refund proceeding, to determine if any refunds were warranted related to the potential impact of the California market issues on buyers in the Pacific Northwest between December 25, 2000, and June 20, 2001. FERC rejected the refund requests, but its decision was remanded by the Court of Appeals for FERC to consider whether any acts of market manipulation support the imposition of refunds. Claims against MPS Merchant total $5.1 million for the period addressed under the Pacific Northwest refund proceedings.

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

12.	RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO’s business and operate its facilities at cost. These costs totaled $29.5 million and $27.1 million, respectively, for the three months ended March 31, 2011 and 2010. Additionally, KCP&L and GMO engage in wholesale electricity transactions with each other. KCP&L and GMO are also authorized to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO. The following table summarizes KCP&L’s related party receivables and payables.


	March 31			December 31
	2011			2010
	(millions)
Receivable (payable) from/to GMO	$	(8.7	)	$	29.6
Receivable (payable) from/to Great Plains Energy		(2.6	)		13.3
Receivable from MPS Merchant		19.4			0.3

- Definition

This element may be used for the entire related party transactions disclosure as a single block of text. Disclosure may include: the nature of the relationship(s), a description of the transactions, the amount of the transactions, the effects of any change in the method of establishing the terms of the transaction from the previous period, stated interest rate, expiration date, terms and manner of settlement per the agreement with the related party, and amounts due to or from related parties. If the entity and one or more other entities are under common ownership or management control and this control affects the operating results or financial position, disclosure includes the nature of the control relationship even if there are no transactions between the entities. Disclosure may also include the aggregate amount of current and deferred tax expense for each statement of earnings presented where the entity is a member of a group that files a consolidated tax return, the amount of any tax related balances due to or from affiliates as of the date of each statement of financial position presented, the principal provisions of the method by which the consolidated amount of current and deferred tax expense is allocated to the members of the group and the nature and effect of any changes in that method. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References+ Details

DERIVATIVE INSTRUMENTS

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Derivative Instruments

13.	DERIVATIVE INSTRUMENTS

Great Plains Energy and KCP&L are exposed to a variety of market risks including interest rates and commodity prices. Management has established risk management policies and strategies to reduce the potentially adverse effects that the volatility of the markets may have on Great Plains Energy’s and KCP&L’s operating results. Commodity risk management activities, including the use of certain derivative instruments, are subject to the management, direction and control of an internal risk management committee. Management’s interest rate risk management strategy uses derivative instruments to adjust Great Plains Energy’s and KCP&L’s liability portfolio to optimize the mix of fixed and floating rate debt within an established range. In addition, Great Plains Energy and KCP&L use derivative instruments to hedge against future interest rate fluctuations on anticipated debt issuances. Management maintains commodity price risk management strategies that use derivative instruments to reduce the effects of fluctuations in fuel expense caused by commodity price volatility. Counterparties to commodity derivatives and interest rate swap agreements expose Great Plains Energy and KCP&L to credit loss in the event of nonperformance. This credit loss is limited to the cost of replacing these contracts at current market rates. Derivative instruments, excluding those instruments that qualify for the normal purchase normal sale election, which are accounted for by accrual accounting, are recorded on the balance sheet at fair value as an asset or liability. Changes in the fair value of derivative instruments are recognized currently in net income unless specific hedge accounting criteria are met, except GMO utility operations hedges that are recorded to a regulatory asset or liability consistent with MPSC regulatory orders, as discussed below.

Great Plains Energy and KCP&L have posted collateral, in the ordinary course of business, for the aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a liability position. At March 31, 2011, Great Plains Energy and KCP&L have posted collateral in excess of the aggregate fair value of its derivative instruments; therefore, if the credit risk-related contingent features underlying these agreements were triggered, Great Plains Energy and KCP&L would not be required to post additional collateral to its counterparties.

The Dodd-Frank Wall Street Reform and Consumer Protection Act, signed into law in July 2010, includes provisions related to the swaps and over-the-counter derivative markets. The Companies currently expect that their commodity and interest rate hedges will be exempt from mandatory clearing and exchange trading requirements. Capital and margin requirements for these hedges are expected to be determined over the next year as regulatory agencies implement rules. While the Companies currently do not anticipate this law and the associated regulatory rules will have a material impact on their financial condition, the ultimate impact cannot be reasonably determined until the final rules are issued.

Interest Rate Risk Management

In December 2009 and January 2010, Great Plains Energy entered into five forward starting swaps (FSS) with total notional amounts of $350.0 million to hedge against interest rate fluctuations on debt anticipated to be issued in the second quarter of 2011. The five FSS remove a portion of the interest rate variability on $350.0 million of the debt expected to be issued thereby enabling Great Plains Energy to predict with greater assurance its future interest costs on that debt. The five FSS are treated as cash flow hedges with no ineffectiveness for the three months ended March 31, 2011 and 2010. At March 31, 2011, a $20.3 million loss was recorded in OCI for the five FSS. The FSS will settle simultaneously with the issuance of the underlying long-term debt expected to be issued. Any gain or loss on the settlement will be recorded to OCI and reclassified to interest expense over the life of the debt.

Commodity Risk Management

KCP&L’s risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales. At March 31, 2011, KCP&L has hedged 62%, 47% and 25%, respectively, of the 2011, 2012 and 2013 projected natural gas usage for retail load and firm MWh sales, primarily by utilizing futures contracts and financial instruments. The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense. KCP&L has not recorded any ineffectiveness on natural gas hedges for the three months ended March 31, 2011 and 2010.

GMO’s risk management policy is to use derivative instruments to mitigate price exposure to natural gas price volatility in the market. The fair value of the portfolio relates to financial contracts that will settle against actual purchases of natural gas and purchased power. At March 31, 2011, GMO had financial contracts in place to hedge approximately 94%, 55% and 37% of the expected on-peak natural gas and natural gas equivalent purchased power price exposure for 2011, 2012 and 2013, respectively. In connection with GMO’s 2005 Missouri electric rate case, it was agreed that the settlement costs of these contracts would be recognized in fuel expense. The settlement cost is included in GMO’s FAC. A regulatory asset has been recorded to reflect the change in the timing of recognition authorized by the MPSC. To the extent recovery of actual costs incurred is allowed, amounts will not impact earnings, but will impact cash flows due to the timing of the recovery mechanism.

MPS Merchant manages the daily delivery of its remaining contractual commitments with economic hedges (non-hedging derivatives) to reduce its exposure to changes in market prices. Within the trading portfolio, MPS Merchant takes certain positions to hedge physical sale or purchase contracts. MPS Merchant records the fair value of physical trading energy contracts as derivative assets or liabilities with an offsetting entry to the consolidated statements of income.

The notional and recorded fair values of open positions for derivative instruments are summarized in the following table. The fair values of these derivatives are recorded on the consolidated balance sheets. The fair values below are gross values before netting agreements and netting of cash collateral.


	March 31					December 31
	2011					2010
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	6.0	$	-		$	4.0	$	-
Non-hedging derivatives		87.9		(0.7	)		59.5		(2.5	)
Forward contracts
Non-hedging derivatives		173.7		10.9			202.8		8.9
Option contracts
Non-hedging derivatives		0.6		0.1			0.2		-
Anticipated debt issuance
Forward starting swaps		350.0		(20.3	)		350.0		(20.8	)
KCP&L
Futures contracts
Cash flow hedges		6.0		-			4.0		-

The fair value of Great Plains Energy’s and KCP&L’s open derivative positions are summarized in the following tables. The tables contain derivative instruments designated as hedging instruments as well as derivative instruments not designated as hedging instruments (non-hedging derivatives) under GAAP. The fair values below are gross values before netting agreements and netting of cash collateral.

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
March 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	-
Interest rate contracts	Derivative instruments		-		20.3
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		11.8		1.5
Total Derivatives		$	11.8	$	21.8

December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9

KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
March 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	-

December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

The following tables summarize the amount of gain (loss) recognized in OCI or earnings for interest rate and commodity hedges.

Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
Three Months Ended March 31, 2011	(Effective Portion)			Classification	Amount
	(millions)				(millions)
Interest rate contracts	$	0.5		Interest Charges	$	(2.9	)
Commodity contracts		-		Fuel		-
Income Taxes		(0.1	)	Income Tax Expense		1.2
Total	$	0.4		Total	$	(1.7	)

Three Months Ended March 31, 2010
Interest rate contracts	$	(7.4	)	Interest Charges	$	(2.3	)
Commodity contracts		(0.4	)	Fuel		-
Income Taxes		3.1		Income Tax Expense		0.9
Total	$	(4.7	)	Total	$	(1.4	)

KCP&L
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
Three Months Ended March 31, 2011	(Effective Portion)			Classification	Amount
	(millions)				(millions)
Interest rate contracts	$	-		Interest Charges	$	(2.2	)
Commodity contracts		-		Fuel		-
Income Taxes		-		Income Tax Expense		0.9
Total	$	-		Total	$	(1.3	)

Three Months Ended March 31, 2010
Interest rate contracts	$	-		Interest Charges	$	(2.2	)
Commodity contracts		(0.4	)	Fuel		-
Income Taxes		0.2		Income Tax Expense		0.9
Total	$	(0.2	)	Total	$	(1.3	)

The following table summarizes the amount of gain (loss) recognized in a regulatory balance sheet account or earnings for GMO utility commodity hedges. GMO utility commodity derivatives fair value changes are recorded to either a regulatory asset or liability consistent with MPSC regulatory orders.

Great Plains Energy
Derivatives in Regulatory Account Relationship
					Gain (Loss) Reclassified from
					Regulatory Account
	Amount of Gain (Loss)
	Recognized in Regulatory
	Account on Derivatives				Income Statement
Three Months Ended March 31, 2011	(Effective Portion)				Classification	Amount
		(millions)				(millions)
Commodity contracts		$	(0.3	)	Fuel	$	(1.9	)
Total		$	(0.3	)	Total	$	(1.9	)

Three Months Ended March 31, 2010
Commodity contracts		$	(6.3	)	Fuel	$	(2.2	)
Total		$	(6.3	)	Total	$	(2.2	)

Great Plains Energy’s income statement reflects gains for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $1.9 million and $2.0 million, respectively, for the three months ended March 31, 2011 and 2010.

The amounts recorded in accumulated OCI related to the cash flow hedges are summarized in the following table.


	Great Plains Energy							KCP&L
	March 31			December 31				March 31			December 31
	2011			2010				2011			2010
	(millions)
Current assets	$	11.9			$	12.0		$	11.9			$	12.0
Current liabilities		(98.0	)			(101.5	)		(69.3	)			(71.6	)
Deferred income taxes		33.5				34.8			22.3				23.2
Total	$	(52.6	)		$	(54.7	)	$	(35.1	)		$	(36.4	)

Great Plains Energy’s accumulated OCI in the table above at March 31, 2011, includes $17.2 million that is expected to be reclassified to expenses over the next twelve months. KCP&L’s accumulated OCI includes $8.8 million that is expected to be reclassified to expense over the next twelve months.

FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Fair Value Measurements

14.	FAIR VALUE MEASUREMENTS

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad categories, giving the highest priority to quoted prices in active markets for identical assets or liabilities and lowest priority to unobservable inputs. A definition of the various levels, as well as discussion of the various measurements within the levels, is as follows:

Level 1 – Unadjusted quoted prices for identical assets or liabilities in active markets that Great Plains Energy and KCP&L have access to at the measurement date. Assets categorized within this level consist of Great Plains Energy’s and KCP&L’s various exchange traded derivative instruments and equity and U.S. Treasury securities that are actively traded within KCP&L’s decommissioning trust fund and GMO’s SERP rabbi trust fund.

Level 2 – Market-based inputs for assets or liabilities that are observable (either directly or indirectly) or inputs that are not observable but are corroborated by market data. Assets and liabilities categorized within this level consist of Great Plains Energy’s and KCP&L’s various non-exchange traded derivative instruments traded in over-the-counter markets and certain debt securities within KCP&L’s decommissioning trust fund and GMO’s SERP rabbi trust fund.

Level 3 – Unobservable inputs, reflecting Great Plains Energy’s and KCP&L’s own assumptions about the assumptions market participants would use in pricing the asset or liability. Assets categorized within this level consist of Great Plains Energy’s various non-exchange traded derivative instruments traded in over-the-counter markets for which sufficiently observable market data is not available to corroborate the valuation inputs.

The following tables include Great Plains Energy’s and KCP&L’s balances of financial assets and liabilities measured at fair value on a recurring basis at March 31, 2011, and December 31, 2010.


						Fair Value Measurements Using

						Quoted
						Prices in
						Active		Significant
						Markets for		Other		Significant
						Identical		Observable		Unobservable
	March 31					Assets		Inputs		Inputs
Description	2011		Netting(d)			(Level 1)		(Level 2)		(Level 3)
KCP&L	(millions)
Assets
Derivative instruments (a)	$	-	$	-		$	-	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		90.1		-			90.1		-		-
Debt securities
U.S. Treasury		9.2		-			9.2		-		-
U.S. Agency		4.7		-			-		4.7		-
State and local obligations		2.5		-			-		2.5		-
Corporate bonds		24.1		-			-		24.1		-
Foreign governments		0.7		-			-		0.7		-
Other		0.5		-			-		0.5		-
Total nuclear decommissioning trust		131.8		-			99.3		32.5		-
Total		131.8		-			99.3		32.5		-
Liabilities
Derivative instruments (a)		-		-			-		-		-
Total	$	-	$	-		$	-	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	11.0	$	(0.8	)	$	0.8	$	5.3	$	5.7
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		7.0		-			-		7.0		-
Total SERP rabbi trust		7.2		-			0.2		7.0		-
Total		18.2		(0.8	)		1.0		12.3		5.7
Liabilities
Derivative instruments (a)		20.3		(1.5	)		1.5		20.3		-
Total	$	20.3	$	(1.5	)	$	1.5	$	20.3	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	11.0	$	(0.8	)	$	0.8	$	5.3	$	5.7
Nuclear decommissioning trust (b)		131.8		-			99.3		32.5		-
SERP rabbi trust (c)		7.2		-			0.2		7.0		-
Total		150.0		(0.8	)		100.3		44.8		5.7
Liabilities
Derivative instruments (a)		20.3		(1.5	)		1.5		20.3		-
Total	$	20.3	$	(1.5	)	$	1.5	$	20.3	$	-


						Fair Value Measurements Using

						Quoted
						Prices in
						Active		Significant
						Markets for		Other		Significant
						Identical		Observable		Unobservable
	December 31					Assets		Inputs		Inputs
Description	2010		Netting(d)			(Level 1)		(Level 2)		(Level 3)
KCP&L	(millions)
Assets
Derivative instruments (a)	$	-	$	(0.1	)	$	0.1	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		85.5		-			85.5		-		-
Debt securities
U.S. Treasury		8.9		-			8.9		-		-
U.S. Agency		4.8		-			-		4.8		-
State and local obligations		2.5		-			-		2.5		-
Corporate bonds		23.7		-			-		23.7		-
Foreign governments		0.7		-			-		0.7		-
Other		0.4		-			-		0.4		-
Total nuclear decommissioning trust		126.5		-			94.4		32.1		-
Total		126.5		(0.1	)		94.5		32.1		-
Liabilities
Derivative instruments (a)		-		(0.1	)		0.1		-		-
Total	$	-	$	(0.1	)	$	0.1	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.5	)	$	0.5	$	5.2	$	3.7
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		7.0		-			-		7.0		-
Total SERP rabbi trust		7.2		-			0.2		7.0		-
Total		16.1		(0.5	)		0.7		12.2		3.7
Liabilities
Derivative instruments (a)		20.8		(3.0	)		3.0		20.8		-
Total	$	20.8	$	(3.0	)	$	3.0	$	20.8	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.6	)	$	0.6	$	5.2	$	3.7
Nuclear decommissioning trust (b)		126.5		-			94.4		32.1		-
SERP rabbi trust (c)		7.2		-			0.2		7.0		-
Total		142.6		(0.6	)		95.2		44.3		3.7
Liabilities
Derivative instruments (a)		20.8		(3.1	)		3.1		20.8		-
Total	$	20.8	$	(3.1	)	$	3.1	$	20.8	$	-

(a)	The fair value of derivative instruments is estimated using market quotes, over-the-counter forward price and volatility curves and correlations among fuel prices, net of estimated credit risk.

(b)

Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $3.3 million and $2.7 million at March 31, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(c)

Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $14.2 million and $14.6 million at March 31, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)

Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty. At March 31, 2011, and December 31, 2010, Great Plains Energy netted $0.7 million and $2.5 million, respectively, of cash collateral posted with counterparties.

The following tables reconcile the beginning and ending balances for all level 3 assets and liabilities, net measured at fair value on a recurring basis for the three months ended March 31, 2011 and 2010.


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other
	Great
	Plains
	Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains or (losses)
Included in non-operating income		5.0
Settlements		(3.0	)
Balance March 31, 2011	$	5.7

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at March 31, 2011	$	2.1


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other
				Great			Great
				Plains			Plains
	KCP&L			Energy			Energy
	State & Local			Derivative
	Obligations			Instruments			Total
	(millions)
Balance January 1, 2010	$	0.2		$	4.1		$	4.3
Total realized/unrealized gains or (losses)
Included in non-operating income		-			(2.5	)		(2.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			3.8			3.8
Balance March 31, 2010	$	-		$	5.4		$	5.4

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at March 31, 2010	$	-		$	1.5		$	1.5

- Definition

This item represents the complete disclosure regarding the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the Company is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risk is are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References+ Details

TAXES

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Taxes

15.

TAXES

Components of income tax expense (benefit) are detailed in the following tables.


Great Plains Energy
Three Months Ended March 31	2011			2010
Current income taxes	(millions)
Federal	$	1.1		$	(0.8	)
State		0.7			0.8
Foreign		(0.3	)		-
Total		1.5			-
Deferred income taxes
Federal		(3.4	)		3.8
State		(4.0	)		0.9
Total		(7.4	)		4.7
Noncurrent income taxes
Federal		1.0			0.8
State		0.1			0.2
Foreign		0.3			0.3
Total		1.4			1.3
Investment tax credit
Deferral		-			4.2
Amortization		(0.1	)		(0.5	)
Total		(0.1	)		3.7
Income tax expense (benefit)	$	(4.6	)	$	9.7


KCP&L
Three Months Ended March 31	2011			2010
Current income taxes	(millions)
Federal	$	1.1		$	16.2
State		0.3			3.1
Total		1.4			19.3
Deferred income taxes
Federal		(3.3	)		(14.4	)
State		(0.2	)		(1.7	)
Total		(3.5	)		(16.1	)
Noncurrent income taxes
Federal		0.9			0.5
State		0.1			0.1
Total		1.0			0.6
Investment tax credit
Deferral		-			4.2
Amortization		-			(0.4	)
Total		-			3.8
Income tax expense (benefit)	$	(1.1	)	$	7.6

Income Tax Expense (Benefit) and Effective Income Tax Rates

Income tax expense (benefit) and the effective income tax rates reflected in the financial statements and the reasons for their differences from the statutory federal rates are detailed in the following tables.


Great Plains Energy	Income Tax Expense (Benefit)							Income Tax Rate
Three Months Ended March 31		2011			2010			2011			2010
		(millions)
Federal statutory income tax		$	(0.7	)	$	10.5			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized			0.8			(2.6	)		(39.1	)		(8.6	)
Amortization of investment tax credits			(0.1	)		(0.5	)		7.1			(1.8	)
Federal income tax credits			(3.0	)		(1.9	)		140.2			(6.5	)
State income taxes			0.4			0.9			(18.1	)		3.1
Medicare Part D subsidy legislation			-			2.8			-			9.4
Changes in uncertain tax positions, net			0.3			0.3			(13.9	)		1.1
Valuation allowance			(2.4	)		-			112.8			-
Other			0.1			0.2			(9.5	)		0.3
Total		$	(4.6	)	$	9.7			214.5	%		32.0	%


KCP&L	Income Tax Expense (Benefit)							Income Tax Rate
Three Months Ended March 31		2011			2010			2011			2010
		(millions)
Federal statutory income tax		$	1.0		$	9.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized			0.8			(2.1	)		26.6			(7.8	)
Amortization of investment tax credits			-			(0.4	)		-			(1.3	)
Federal income tax credits			(3.0	)		(1.9	)		(102.2	)		(7.2	)
State income taxes			0.2			0.7			5.5			2.6
Medicare Part D subsidy legislation			-			2.8			-			10.5
Other			(0.1	)		(0.9	)		(1.4	)		(3.5	)
Total		$	(1.1	)	$	7.6			(36.5	) %		28.3	%

Uncertain Tax Positions

At March 31, 2011, and December 31, 2010, Great Plains Energy had $43.8 million and $42.0 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $17.6 million and $17.3 million, respectively, at March 31, 2011, and December 31, 2010, is expected to impact the effective tax rate if recognized.

At March 31, 2011, and December 31, 2010, KCP&L had $20.1 million and $19.1 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $0.3 million at March 31, 2011, and December 31, 2010, is expected to impact the effective tax rate if recognized.

The following table reflects activity for Great Plains Energy and KCP&L related to the liability for unrecognized tax benefits.


	Great Plains Energy							KCP&L
	March 31			December 31				March 31			December 31
	2011			2010				2011			2010
	(millions)
Beginning balance	$	42.0			$	51.4		$	19.1			$	20.9
Additions for current year tax positions		0.4				2.7			-				1.3
Additions for prior year tax positions		1.5				2.1			1.4				1.5
Reductions for prior year tax positions		(0.4	)			(10.6	)		(0.4	)			(1.6	)
Settlements		-				(3.8	)		-				(2.9	)
Statute expirations		-				(0.3	)		-				(0.1	)
Foreign currency translation adjustments		0.3				0.5			-				-
Ending balance	$	43.8			$	42.0		$	20.1			$	19.1

Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses. At March 31, 2011, and December 31, 2010, accrued interest related to unrecognized tax benefits for Great Plains Energy was $7.5 million and $6.7 million, respectively. Amounts accrued for penalties with respect to unrecognized tax benefits was $1.1 million at March 31, 2011, and December 31, 2010. KCP&L had accrued interest related to unrecognized tax benefits of $1.7 million and $1.4 million at March 31, 2011, and December 31, 2010, respectively. Amounts accrued for penalties with respect to unrecognized tax benefits for KCP&L are insignificant.

The IRS is currently auditing Great Plains Energy and its subsidiaries for the 2006-2008 tax years. The Company estimates that it is reasonably possible that $18.8 million for Great Plains Energy and $12.8 million for KCP&L of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities.

SEGMENTS AND RELATED INFORMATION

3 Months Ended

Mar. 31, 2011

Notes to Financial Statements [Abstract]

Segments and Related Information

16.	SEGMENTS AND RELATED INFORMATION

Great Plains Energy has one reportable segment based on its method of internal reporting, which generally segregates reportable segments based on products and services, management responsibility and regulation. The one reportable business segment is electric utility, consisting of KCP&L and GMO’s regulated utility operations. Other includes GMO activity other than its regulated utility operations, unallocated corporate charges, consolidating entries and intercompany eliminations. Intercompany eliminations include insignificant amounts of intercompany financing-related activities. The summary of significant accounting policies applies to the reportable segment. Segment performance is evaluated based on net income attributable to Great Plains Energy.

The following tables reflect summarized financial information concerning Great Plains Energy’s reportable segment.


Three Months Ended	Electric						Great Plains
March 31, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	492.9		$	-		$	492.9
Depreciation and amortization		(72.4	)		-			(72.4	)
Interest charges		(34.3	)		(10.6	)		(44.9	)
Income tax (expense) benefit		(0.9	)		5.5			4.6
Net income (loss) attributable to Great Plains Energy		7.0			(4.6	)		2.4



Three Months Ended	Electric						Great Plains
March 31, 2010	Utility			Other			Energy
	(millions)
Operating revenues	$	506.9		$	-		$	506.9
Depreciation and amortization		(82.2	)		-			(82.2	)
Interest charges		(36.2	)		(10.3	)		(46.5	)
Income tax (expense) benefit		(11.6	)		1.9			(9.7	)
Net income (loss) attributable to Great Plains Energy		24.9			(4.6	)		20.3


	Electric							Great Plains
	Utility		Other		Eliminations			Energy
March 31, 2011	(millions)
Assets	$	9,188.0	$	46.3	$	(431.8	)	$	8,802.5
Capital expenditures (a)		99.9		-		-			99.9
December 31, 2010
Assets	$	9,152.7	$	66.3	$	(400.8	)	$	8,818.2
Capital expenditures (a)		618.1		-		-			618.1
(a) Capital expenditures reflect year to date amounts for the periods presented.

Document Information	3 Months Ended
Document Information	Mar. 31, 2011
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2011

Entity Information (USD $)	3 Months Ended
Entity Information (USD $)	Mar. 31, 2011	Apr. 29, 2011	Jun. 30, 2010
Entity Registrant Name	Great Plains Energy Incorporated
Entity Central Index Key	0001143068
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,307,217,754
Entity Common Stock, Shares Outstanding		137,000,000
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q1