Prepaid expenses and other assets

116.3

7.5

Derivative instruments

1.0

23.1

19.7

Assets, Current, Total

821.1

619.1

Utility Plant, at Original Cost

Electric

11,112.4

10,924.8

Less-accumulated depreciation

4,390.9

4,235.8

Net utility plant in service

6,721.5

6,689.0

Construction work in progress

468.0

287.9

Nuclear Fuel, Net of Amortization

80.8

76.6

Public Utilities, Property, Plant and Equipment, Net

7,270.3

7,053.5

Investments and Other Assets

Nuclear decommissioning trust fund

152.1

135.3

Regulatory Assets

1,012.8

1,058.2

Goodwill

169.0

Derivative instruments

5.8

6.8

Other Assets, Noncurrent

71.3

76.1

Investments and Other Assets, Total

1,411.0

1,445.4

Assets, Total

9,502.4

9,118.0

Current Liabilities

Notes payable

31.0

22.0

Collateralized note payable

190.0

95.0

Commercial paper

427.0

267.0

Current maturities of long-term debt

257.1

801.4

Accounts payable

222.4

275.6

Accrued taxes

97.5

25.8

Accrued interest

60.1

76.9

Accrued compensation and benefits

42.3

40.8

Other Liabilities, Current

4.4

24.7

26.0

Liabilities, Current, Total

1,356.5

1,634.9

Deferred Credits and Other Liabilities

Asset retirement obligations

854.1

628.6

Deferred tax credits

129.4

131.2

156.6

149.6

Other Liabilities, Noncurrent

449.5

461.9

Regulatory Liabilities

282.7

268.5

106.3

101.1

Liabilities, Noncurrent, Total

1,978.6

1,740.9

Common shareholders' equity

Common Stock, Value, Issued

2,622.9

2,330.6

Retained earnings

787.8

684.7

Treasury Stock, Value

(5.2)

(5.6)

Accumulated other comprehensive loss

(40.1)

(49.8)

Common Shareholders' Equity, Total

3,365.4

2,959.9

Noncontrolling interest

1.0

Cumulative preferred stock $100 par value

3.8% - 100,000 shares issued

10.0

4.50% - 100,000 shares issued

10.0

4.20% - 70,000 shares issued

7.0

4.35% - 120,000 shares issued

12.0

Preferred Stock, Value, Issued

39.0

Long-term debt

2,762.9

^[1]

2,742.3

^[1]

Capitalization, Total

6,167.3

5,742.2

Commitments and Contingencies

Liabilities and Equity, Total

9,502.4

9,118.0

Kansas City Power and Light Company [Member]

Current Assets

Cash and cash equivalents

2.8

1.9

Funds on deposit

0.2

0.1

Receivables, net

207.1

172.9

Accounts receivable pledged as collateral

110.0

95.0

Fuel inventories, at average cost

65.2

59.0

Materials and supplies, at average cost

107.2

101.1

Deferred refueling outage costs

14.1

27.5

Refundable income taxes

5.7

Prepaid expenses and other assets

7.3

20.7

16.0

Assets, Current, Total

534.6

479.2

Utility Plant, at Original Cost

Electric

7,939.8

7,829.3

Less-accumulated depreciation

3,342.7

3,243.0

Net utility plant in service

4,597.1

4,586.3

Construction work in progress

381.5

203.5

Nuclear Fuel, Net of Amortization

80.8

76.6

Public Utilities, Property, Plant and Equipment, Net

5,059.4

4,866.4

Investments and Other Assets

Nuclear decommissioning trust fund

152.1

135.3

Regulatory Assets

743.9

780.7

Other Assets, Noncurrent

27.3

30.6

Investments and Other Assets, Total

923.3

946.6

Assets, Total

6,517.3

6,292.2

Current Liabilities

Notes payable

Collateralized note payable

110.0

95.0

Commercial paper

256.0

227.0

Current maturities of long-term debt

0.4

12.7

Accounts payable

193.1

214.8

Accrued taxes

91.1

20.6

Accrued interest

39.8

30.0

Accrued compensation and benefits

42.3

40.8

Other Liabilities, Current

3.0

12.7

13.7

Liabilities, Current, Total

748.4

657.6

Deferred Credits and Other Liabilities

Asset retirement obligations

825.5

772.7

Deferred tax credits

126.5

127.9

140.6

134.3

Other Liabilities, Noncurrent

428.7

440.9

Regulatory Liabilities

151.4

142.8

81.6

68.6

Liabilities, Noncurrent, Total

1,754.3

1,687.2

Common shareholders' equity

Common Stock, Value, Issued

1,563.1

Retained earnings

577.0

513.8

Accumulated other comprehensive loss

(27.1)

(31.4)

Common Shareholders' Equity, Total

2,113.0

2,045.5

Cumulative preferred stock $100 par value

Long-term debt

1,901.6

^[1]

1,901.9

^[1]

Capitalization, Total

4,014.6

3,947.4

Commitments and Contingencies

Liabilities and Equity, Total

$ 6,517.3

$ 6,292.2

[1]	Does not include $39.5 million EIRR Series 1993B, $63.3 million EIRR Series 2007 A-1 and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L

Consolidated Balance Sheets (Parenthetical) (unaudited) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Utility Plant, at Original Cost
Nuclear fuel, amortization	$ 149.6	$ 132.7
Common shareholder's equity
Common stock - shares authorized (in shares)	250,000,000	250,000,000
Common stock-shares issued (in shares)	153,717,021	136,406,306
Treasury stock- shares (in shares)	254,226	264,567
Cumulative Preferred Stock [Member] \| Preferred Stock 3 Point 80 [Member]
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100.00	$ 100.00
Cumulative preferred stock, Shares issued (in share)	100,000	100,000
Preferred Stock, Dividend Rate, Percentage	3.80%	3.80%
Cumulative Preferred Stock [Member] \| Preferred Stock 4 Point 50 [Member]
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100.00	$ 100.00
Cumulative preferred stock, Shares issued (in share)	100,000	100,000
Preferred Stock, Dividend Rate, Percentage	4.50%	4.50%
Cumulative Preferred Stock [Member] \| Preferred Stock 4 Point 20 [Member]
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100.00	$ 100.00
Cumulative preferred stock, Shares issued (in share)	70,000	70,000
Preferred Stock, Dividend Rate, Percentage	4.20%	4.20%
Cumulative Preferred Stock [Member] \| Preferred Stock 4 Point 35 [Member]
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100.00	$ 100.00
Cumulative preferred stock, Shares issued (in share)	120,000	120,000
Preferred Stock, Dividend Rate, Percentage	4.35%	4.35%
Kansas City Power and Light Company [Member]
Utility Plant, at Original Cost
Nuclear fuel, amortization	$ 149.6	$ 132.7
Common shareholder's equity
Common stock - shares authorized (in shares)	1,000	1,000
Common stock-shares issued (in shares)	1	1

Consolidated Statements of Income and Comprehensive Income (unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Operating Revenues
Electric revenues	$ 746.2	$ 773.7	$ 1,829.5	$ 1,831.7
Operating Expenses
Fuel	164.7	146.5	422.1	365.8
Purchased power	17.9	68.1	69.5	178.4
Transmission of electricity by others	9.8	8.6	25.9	23.1
Utility operating and maintenance expenses	156.8	169.1	484.0	487.7
Voluntary separation program	0	0	0	12.7
Depreciation and amortization	68.9	65.9	204.2	205.9
General taxes	50.8	52.3	140.3	134.6
Other General and Administrative Expense	0.3	0.5	7.5	4.0
Costs and Expenses, Total	469.2	511.0	1,353.5	1,412.2
Operating income	277.0	262.7	476.0	419.5
Non-operating income	2.1	1.4	4.6	5.8
Non-operating expenses	(1.9)	(1.3)	(9.5)	(6.3)
Interest charges	(48.1)	(60.8)	(170.8)	(156.0)
Income from continuing operations before income tax	229.1	202.0	300.3	263.0
Income tax (expense) benefit	(82.6)	(75.4)	(104.9)	(90.6)
Loss from equity investments, net of income taxes	(0.1)	0	(0.2)	(0.1)
Net income	146.4	126.6	195.2	172.3
Less: Net income attributable to noncontrolling interest	(0.2)	(0.1)	0	0
Net income (loss) attributable to Great Plains Energy	146.2	126.5	195.2	172.3
Preferred stock dividend requirements	0.4	0.4	1.2	1.2
Earnings available for common shareholders	145.8	126.1	194.0	171.1
Average number of basic common shares outstanding	153.2	135.7	142.9	135.6
Average number of diluted common shares outstanding	153.4	138.3	145.0	138.5
Basic earnings (loss) per common share
Basic earnings per common share	$ 0.95	$ 0.93	$ 1.36	$ 1.26
Diluted earnings (loss) per common share
Diluted earnings per common share	$ 0.95	$ 0.91	$ 1.34	$ 1.24
Cash dividends per common share	$ 0.2125	$ 0.2075	$ 0.6375	$ 0.6225
Comprehensive Income
Net income	146.4	126.6	195.2	172.3
Derivative Hedging Activity
Gain (loss) on derivative hedging instruments	0.1	(0.1)	(0.1)	(5.5)
Income tax benefit (expense)	(0.1)	0.1	0	2.2
Net gain (loss) on derivative hedging instruments	0	0	(0.1)	(3.3)
Reclassification to expenses, net of tax	3.4	3.1	9.6	7.3
Derivative hedging activity, net of tax	3.4	3.1	9.5	4.0
Defined benefit pension plans
Amortization of net losses included in net periodic benefit costs	0.1	0	0.3	0.2
Income tax benefit (expense)	0	0	(0.1)	(0.1)
Net change in unrecognized pension expense	0.1	0	0.2	0.1
Other comprehensive income (loss)	3.5	3.1	9.7	4.1
Comprehensive income	149.9	129.7	204.9	176.4
Less: comprehensive income attributable to noncontrolling interest	(0.2)	(0.1)	0	0
Comprehensive income attributable to Great Plains Energy	149.7	129.6	204.9	176.4
Kansas City Power and Light Company [Member]
Operating Revenues
Electric revenues	508.0	506.3	1,244.1	1,220.5
Operating Expenses
Fuel	114.5	99.3	297.8	249.0
Purchased power	10.1	24.9	23.7	66.7
Transmission of electricity by others	6.3	5.7	17.4	14.2
Utility operating and maintenance expenses	110.5	120.2	344.3	350.7
Voluntary separation program	0	0	0	9.2
Depreciation and amortization	46.9	45.4	138.6	147.0
General taxes	41.9	41.6	113.0	108.9
Other General and Administrative Expense	0	0	0	1.3
Costs and Expenses, Total	330.2	337.1	934.8	947.0
Operating income	177.8	169.2	309.3	273.5
Non-operating income	1.0	0.8	2.3	1.8
Non-operating expenses	(1.3)	(1.0)	(4.7)	(3.4)
Interest charges	(32.4)	(30.8)	(96.1)	(81.2)
Income from continuing operations before income tax	145.1	138.2	210.8	190.7
Income tax (expense) benefit	(54.9)	(52.8)	(74.6)	(67.9)
Net income	90.2	85.4	136.2	122.8
Comprehensive Income
Net income	90.2	85.4	136.2	122.8
Derivative Hedging Activity
Gain (loss) on derivative hedging instruments	0.1	(0.1)	(0.1)	(0.2)
Income tax benefit (expense)	(0.1)	0.1	0	0.1
Net gain (loss) on derivative hedging instruments	0	0	(0.1)	(0.1)
Reclassification to expenses, net of tax	1.7	1.3	4.4	4.0
Derivative hedging activity, net of tax	1.7	1.3	4.3	3.9
Defined benefit pension plans
Other comprehensive income (loss)	1.7	1.3	4.3	3.9
Comprehensive income	$ 91.9	$ 86.7	$ 140.5	$ 126.7

Consolidated Statements of Cash Flows (unaudited) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash Flows from Operating Activities
Net income	$ 195.2	$ 172.3
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	204.2	205.9
Amortization of:
Nuclear fuel	16.9	13.5
Other Amortization of Deferred Charges	22.6	7.5
Deferred income taxes, net	115.8	124.0
Investment tax credit amortization	(1.8)	(1.5)
Loss from equity investments, net of income taxes	0.2	0.1
Other operating activities	(66.8)	(154.3)
Net cash from operating activities	486.3	367.5
Cash Flows from Investing Activities
Utility capital expenditures	(409.5)	(317.8)
Allowance for borrowed funds used during construction	(3.9)	(3.1)
Purchases of nuclear decommissioning trust investments	(20.4)	(15.5)
Proceeds from nuclear decommissioning trust investments	17.9	13.0
Other investing activities	(12.1)	(17.4)
Net cash from investing activities	(428.0)	(340.8)
Cash Flows from Financing Activities
Issuance of common stock	291.6	4.5
Issuance of long-term debt	0	747.1
Issuance fees	(2.6)	(6.2)
Repayment of long-term debt	(513.8)	(448.5)
Net change in short-term borrowings	169.0	(234.5)
Net change in collateralized short-term borrowings	95.0	0
Dividends paid	(91.7)	(85.9)
Other financing activities	(5.1)	(5.1)
Net cash from financing activities	(57.6)	(28.6)
Net Change in Cash and Cash Equivalents	0.7	(1.9)
Cash and Cash Equivalents at Beginning of Year	6.2	10.8
Cash and Cash Equivalents at End of Year	6.9	8.9
Kansas City Power and Light Company [Member]
Cash Flows from Operating Activities
Net income	136.2	122.8
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	138.6	147.0
Amortization of:
Nuclear fuel	16.9	13.5
Other Amortization of Deferred Charges	23.1	22.3
Deferred income taxes, net	47.4	87.2
Investment tax credit amortization	(1.4)	(1.0)
Other operating activities	23.4	(74.3)
Net cash from operating activities	384.2	317.5
Cash Flows from Investing Activities
Utility capital expenditures	(324.5)	(236.7)
Allowance for borrowed funds used during construction	(2.3)	(1.6)
Purchases of nuclear decommissioning trust investments	(20.4)	(15.5)
Proceeds from nuclear decommissioning trust investments	17.9	13.0
Net money pool lending	0	(18.8)
Other investing activities	(8.2)	(9.3)
Net cash from investing activities	(337.5)	(268.9)
Cash Flows from Financing Activities
Issuance of long-term debt	0	397.4
Issuance fees	0	(3.7)
Repayment of long-term debt	(12.7)	(113.1)
Net change in short-term borrowings	29.0	(253.0)
Net change in collateralized short-term borrowings	15.0	0
Net money pool borrowings	(4.2)	(1.6)
Dividends paid	(73.0)	(75.0)
Other financing activities	0.1	0
Net cash from financing activities	(45.8)	(49.0)
Net Change in Cash and Cash Equivalents	0.9	(0.4)
Cash and Cash Equivalents at Beginning of Year	1.9	3.6
Cash and Cash Equivalents at End of Year	$ 2.8	$ 3.2

Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest (unaudited) (USD $) In Millions, except Share data, unless otherwise specified	Total	Kansas City Power and Light Company [Member]	Common Stock [Member]	Common Stock [Member] Kansas City Power and Light Company [Member]	Retained Earnings [Member]	Retained Earnings [Member] Kansas City Power and Light Company [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Other Comprehensive Income (Loss) [Member] Kansas City Power and Light Company [Member]	Noncontrolling Interest [Member]
Beginning balance at Dec. 31, 2010			$ 2,324.4		$ 626.5	$ 478.3	$ (8.9)	$ (56.1)	$ (36.4)	$ 1.2
Beginning balance (in shares) at Dec. 31, 2010			136,113,954				(400,889)
Distribution										0
Total Great Plains Energy Common Shareholders' Equity	2,982.8	2,056.7
Derivative hedging activity, net of tax	4.0	3.9						4.0	3.9
Change in unrecognized pension expense, net of tax	0.1							0.1
Net income (loss) attributable to Great Plains Energy	172.3				172.3	122.8
Loss on reissuance of treasury stock					(0.7)
Treasury shares acquired							(2.3)
Treasury shares acquired (in shares)							(125,024)
Treasury shares reissued							5.6
Treasury shares reissued (in shares)							259,024
Issuance of common stock			4.5
Issuance of common stock (in shares)			226,691
Equity compensation expense, net of forfeitures			0.2
Unearned Compensation [Abstract]
Forfeiture of restricted common stock			0.9
Compensation expense recognized			1.7
Issuance of restricted common stock			(3.5)
Stockholders' Equity, Other			0.3
Dividends:
Common stock					(84.7)	(75.0)
Preferred stock - at required rates					(1.2)
Net income attributable to noncontrolling interest	0
Performance shares					(0.3)
Ending balance at Sep. 30, 2011			2,328.5	1,563.1	711.9	526.1	(5.6)	(52.0)	(32.5)	1.2
Ending balance (in shares) at Sep. 30, 2011			136,340,645	1			(266,889)
Beginning balance at Jun. 30, 2011
Total Great Plains Energy Common Shareholders' Equity	2,982.8	2,056.7
Derivative hedging activity, net of tax	3.1	1.3
Change in unrecognized pension expense, net of tax	0
Net income (loss) attributable to Great Plains Energy	126.5
Dividends:
Net income attributable to noncontrolling interest	0.1
Ending balance at Sep. 30, 2011				1,563.1
Ending balance (in shares) at Sep. 30, 2011				1
Beginning balance at Dec. 31, 2011			2,330.6		684.7	513.8	(5.6)	(49.8)	(31.4)	1.0
Beginning balance (in shares) at Dec. 31, 2011			136,406,306				(264,567)
Distribution										(1.0)
Total Great Plains Energy Common Shareholders' Equity	3,365.4	2,113.0
Derivative hedging activity, net of tax	9.5	4.3						9.5	4.3
Change in unrecognized pension expense, net of tax	0.2							0.2
Net income (loss) attributable to Great Plains Energy	195.2				195.2	136.2
Loss on reissuance of treasury stock					(0.2)
Treasury shares acquired							(3.3)
Treasury shares acquired (in shares)							(164,454)
Treasury shares reissued							3.7
Treasury shares reissued (in shares)							174,795
Issuance of common stock			291.6
Issuance of common stock (in shares)			17,310,715
Equity compensation expense, net of forfeitures			0.2
Unearned Compensation [Abstract]
Forfeiture of restricted common stock			1.3
Compensation expense recognized			1.9
Issuance of restricted common stock			(3.2)
Stockholders' Equity, Other			0.5
Dividends:
Common stock					(90.5)	(73.0)
Preferred stock - at required rates					(1.2)
Net income attributable to noncontrolling interest	0
Performance shares					(0.2)
Ending balance at Sep. 30, 2012			2,622.9	1,563.1	787.8	577.0	(5.2)	(40.1)	(27.1)	0
Ending balance (in shares) at Sep. 30, 2012			153,717,021	1			(254,226)
Beginning balance at Jun. 30, 2012
Total Great Plains Energy Common Shareholders' Equity	3,365.4	2,113.0
Derivative hedging activity, net of tax	3.4	1.7
Change in unrecognized pension expense, net of tax	0.1
Net income (loss) attributable to Great Plains Energy	146.2
Dividends:
Net income attributable to noncontrolling interest	0.2
Ending balance at Sep. 30, 2012				$ 1,563.1
Ending balance (in shares) at Sep. 30, 2012				1

Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2012

Accounting Policies [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 (KCP&L 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 has two active wholly owned subsidiaries, GMO Receivables Company and MPS Merchant Services, Inc. (MPS Merchant). MPS Merchant 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. 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 income 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 September 30				Year to Date September 30
	2012		2011		2012		2011
Income	(millions, except per share amounts)
Net income	$	146.4	$	126.6	$	195.2	$	172.3
Less: net income attributable to noncontrolling interest	0.2		0.1		—		—
Less: preferred stock dividend requirements	0.4		0.4		1.2		1.2
Earnings available for common shareholders	$	145.8	$	126.1	$	194.0	$	171.1
Common Shares Outstanding
Average number of common shares outstanding	153.2		135.7		142.9		135.6
Add: effect of dilutive securities	0.2		2.6		2.1		2.9
Diluted average number of common shares outstanding	153.4		138.3		145.0		138.5
Basic EPS	$	0.95	$	0.93	$	1.36	$	1.26
Diluted EPS	$	0.95	$	0.91	$	1.34	$	1.24

Anti-dilutive shares excluded from the computation of diluted EPS are detailed in the following table.



	Three Months Ended September 30		Year to Date September 30
	2012	2011	2012	2011
Performance shares	192,723	102,032	209,000	102,032
Restricted stock shares	2,531	22,818	2,531	45,648
Stock options	—	80,140	—	80,140

Dividends Declared

In November 2012, Great Plains Energy's Board of Directors (Board) declared a quarterly dividend of $0.2175 per share on Great Plains Energy's common stock. The common dividend is payable December 20, 2012, to shareholders of record as of November 29, 2012. The Board also declared regular dividends on Great Plains Energy's preferred stock, payable March 1, 2013, to shareholders of record as of February 7, 2013.

In November 2012, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $23 million payable on December 19, 2012.

Supplemental Cash Flow Elements [Abstract]

The entire disclosure for the organization, consolidation and basis of presentation of financial statements disclosure, and significant accounting policies of the reporting entity. May be provided in more than one note to the financial statements, as long as users are provided with an understanding of (1) the significant judgments and assumptions made by an enterprise in determining whether it must consolidate a VIE and/or disclose information about its involvement with a VIE, (2) the nature of restrictions on a consolidated VIE's assets reported by an enterprise in its statement of financial position, including the carrying amounts of such assets, (3) the nature of, and changes in, the risks associated with an enterprise's involvement with the VIE, and (4) how an enterprise's involvement with the VIE affects the enterprise's financial position, financial performance, and cash flows. Describes procedure if disclosures are provided in more than one note to the financial statements.

+ References+ Details

Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2012

Supplemental Cash Flow Information

2. SUPPLEMENTAL CASH FLOW INFORMATION



Great Plains Energy Other Operating Activities
Year to Date September 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	12.5		$	(41.2	)
Accounts receivable pledged as collateral	(95.0		)	—
Fuel inventories	(5.4		)	12.9
Materials and supplies	(7.8		)	(4.8		)
Accounts payable	(49.4		)	(71.5		)
Accrued taxes	65.4			52.5
Accrued interest	(16.6		)	(6.1		)
Deferred refueling outage costs	13.4			(23.8		)
Fuel adjustment clauses	13.1			(27.3		)
Pension and post-retirement benefit obligations	21.9			22.0
Allowance for equity funds used during construction	(0.3		)	(0.3		)
Interest rate hedge settlements	—			(26.1		)
Iatan Nos. 1 and 2 impact of disallowed construction costs	—			2.3
Uncertain tax positions	(4.4		)	(20.2		)
Other	(14.2		)	(22.7		)
Total other operating activities	$	(66.8	)	$	(154.3	)
Cash paid during the period:
Interest	$	185.4		$	195.1
Income taxes	$	3.3		$	2.4
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	52.2		$	34.8



KCP&L Other Operating Activities
Year to Date September 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	(35.1	)	$	(39.5	)
Accounts receivable pledged as collateral	(15.0		)	—
Fuel inventories	(6.2		)	2.9
Materials and supplies	(6.1		)	(4.3		)
Accounts payable	(18.0		)	(43.2		)
Accrued taxes	76.5			40.3
Accrued interest	9.8			7.9
Deferred refueling outage costs	13.4			(23.8		)
Pension and post-retirement benefit obligations	24.7			32.1
Kansas Energy Cost Adjustment	(0.9		)	(22.0		)
Iatan Nos. 1 and 2 impact of disallowed construction costs	—			1.5
Uncertain tax positions	1.2			(10.1		)
Other	(20.9		)	(16.1		)
Total other operating activities	$	23.4		$	(74.3	)
Cash paid during the period:
Interest	$	77.3		$	74.6
Income taxes	$	—		$	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	48.0		$	30.7

Compensation and Retirement Disclosure [Abstract]

The entire disclosure for supplemental cash flow activities, including cash, noncash, and part noncash transactions, for the period. Noncash is defined as information about all investing and financing activities of an enterprise during a period that affect recognized assets or liabilities but that do not result in cash receipts or cash payments in the period. "Part noncash" refers to that portion of the transaction not resulting in cash receipts or cash payments in the period.

+ References+ Details

Receivables

9 Months Ended

Sep. 30, 2012

Receivables [Abstract]

Receivables

3. RECEIVABLES

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



	September 30 2012				December 31 2011
Great Plains Energy		(millions)
Customer accounts receivable - billed		$	27.7			$	69.8
Customer accounts receivable - unbilled		77.8				82.4
Allowance for doubtful accounts		(4.6		)		(2.5		)
Other receivables		117.7				81.5
Total		$	218.6			$	231.2
KCP&L
Customer accounts receivable - billed		$	28.9			$	16.4
Customer accounts receivable - unbilled		50.8				50.0
Allowance for doubtful accounts		(2.5		)		(1.4		)
Intercompany receivables		26.9				38.7
Other receivables		103.0				69.2
Total		$	207.1			$	172.9

Great Plains Energy's and KCP&L's other receivables at September 30, 2012, and December 31, 2011, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables.

Sale of Accounts Receivable – KCP&L and GMO

KCP&L sells all of its retail electric accounts receivable to its wholly owned subsidiary, KCP&L Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor. On May 31, 2012, GMO entered into an agreement to sell all of its retail electric and steam service accounts receivable to its wholly owned subsidiary, GMO Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation.

Each of KCP&L Receivables Company's and GMO 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 accounts receivable pledged as collateral and a corresponding short-term collateralized note payable recognized on the balance sheets. At September 30, 2012, and December 31, 2011, Great Plains Energy's accounts receivable pledged as collateral and the corresponding short-term collateralized note payable was $190.0 million and $95.0 million, respectively. At September 30, 2012, and December 31, 2011, KCP&L's accounts receivable pledged as collateral and the corresponding short-term collateralized note payable was $110.0 million and $95.0 million, respectively.

KCP&L and GMO each sell their receivables at a fixed price based upon the expected cost of funds and charge-offs. These costs comprise KCP&L's and GMO's loss on the sale of accounts receivable. KCP&L and GMO service the receivables and receive annual servicing fees of 1.5% and 1.25%, respectively, of the outstanding principal amount of the receivables sold to KCP&L Receivables Company and GMO Receivables Company. KCP&L and GMO do not recognize a servicing asset or liability because management determined the collection agent fees earned by KCP&L and GMO approximate market value. KCP&L's agreement expires in September 2014 and allows for $110 million in aggregate outstanding principal amount at any time. GMO's agreement expires in September 2014 and allows for $80 million in aggregate outstanding principal during the period of June 1 through October 31 and $65 million in aggregate outstanding principal during the period of November 1 through May 31 of each year.

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



		Three Months Ended September 30, 2012
	KCP&L				KCP&L Receivables Company				Consolidated KCP&L				GMO				GMO Receivables Company				Consolidated Great Plains Energy
		(millions)
Receivables (sold) purchased		$	(472.6	)		$	472.6			$	—			$	(341.7	)		$	341.7			$	—
Gain (loss) on sale of accounts receivable ^(a)		(6.0		)		5.8				(0.2		)		(4.3		)		3.4				(1.1		)
Servicing fees received (paid)		0.8				(0.8		)		—				0.5				(0.5		)		—
Fees paid to outside investor		—				(0.3		)		(0.3		)		—				(0.3		)		(0.6		)
Cash from customers (transferred) received		(466.1		)		466.1				—				(267.8		)		267.8				—
Cash received from (paid for) receivables purchased		460.4				(460.4		)		—				264.4				(264.4		)		—
Interest on intercompany note received (paid)		0.2				(0.2		)		—				0.1				(0.1		)		—



		Year to Date September 30, 2012
	KCP&L				KCP&L Receivables Company				Consolidated KCP&L				GMO				GMO Receivables Company				Consolidated Great Plains Energy
		(millions)
Receivables (sold) purchased		$	(1,134.7	)		$	1,134.7			$	—			$	(433.4	)		$	433.4			$	—
Gain (loss) on sale of accounts receivable ^(a)		(14.4		)		13.9				(0.5		)		(5.5		)		4.2				(1.8		)
Servicing fees received (paid)		1.9				(1.9		)		—				0.6				(0.6		)		—
Fees paid to outside investor		—				(0.9		)		(0.9		)		—				(0.4		)		(1.3		)
Cash from customers (transferred) received		(1,112.7		)		1,112.7				—				(332.5		)		332.5				—
Cash received from (paid for) receivables purchased		1,098.8				(1,098.8		)		—				328.3				(328.3		)		—
Interest on intercompany note received (paid)		0.3				(0.3		)		—				0.1				(0.1		)		—



		Three Months Ended September 30, 2011												Year to Date September 30, 2011
	KCP&L				KCP&L Receivables Company				Consolidated KCP&L				KCP&L				KCP&L Receivables Company				Consolidated KCP&L
		(millions)
Receivables (sold) purchased		$	(468.8	)		$	468.8			$	—			$	(1,108.4	)		$	1,108.4			$	—
Gain (loss) on sale of accounts receivable ^(a)		(5.9		)		5.8				(0.1		)		(14.0		)		13.6				(0.4		)
Servicing fees received (paid)		0.9				(0.9		)		—				2.0				(2.0		)		—
Fees paid to outside investor		—				(0.3		)		(0.3		)		—				(0.9		)		(0.9		)
Cash from customers (transferred) received		(463.4		)		463.4				—				(1,081.6		)		1,081.6				—
Cash received from (paid for) receivables purchased		457.6				(457.6		)		—				1,068.0				(1,068.0		)		—
Interest on intercompany note received (paid)		0.2				(0.2		)		—				0.4				(0.4		)		—

^(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

9 Months Ended

Sep. 30, 2012

Nuclear Plant [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.

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 2010, the DOE filed a motion with the NRC to withdraw its then pending 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. An NRC board denied the DOE's motion to withdraw its application, and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE's application by the end of September 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. The court has not yet issued a final decision in the case, but in August 2012, the court ordered the parties to report to it, no later than December 14, 2012, on whether Congress by then had provided funding for the NRC to proceed on the license application. 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.



	September 30 2012			December 31 2011
Decommissioning Trust		(millions)
Beginning balance January 1		$	135.3		$	129.2
Contributions		2.5			3.4
Earned income, net of fees		2.0			4.8
Net realized gains		0.9			0.3
Net unrealized gains (losses)		11.4			(2.4		)
Ending balance		$	152.1		$	135.3

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



	September 30 2012													December 31 2011
	Cost Basis		Unrealized Gains			Unrealized Losses				Fair Value			Cost Basis			Unrealized Gains			Unrealized Losses				Fair Value
	(millions)
Equity securities	$	79.5		$	20.9		$	(2.5	)		$	97.9		$	76.5		$	12.3		$	(4.5	)		$	84.3
Debt securities	45.9			5.2			—				51.1			44.2			4.5			(0.1		)		48.6
Other	3.1			—			—				3.1			2.4			—			—				2.4
Total	$	128.5		$	26.1		$	(2.5	)		$	152.1		$	123.1		$	16.8		$	(4.6	)		$	135.3

The weighted average maturity of debt securities held by the trust at September 30, 2012, was approximately 7 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 in the nuclear decommissioning trust fund.



	Three Months Ended September 30						Year to Date September 30
		2012			2011			2012			2011
		(millions)
Realized gains		$	0.5		$	0.2		$	1.2		$	1.0
Realized losses		(0.1		)	—			(0.3		)	(0.7		)

Regulatory Matters	9 Months Ended
Regulatory Matters	Sep. 30, 2012
Regulated Operations [Abstract]
Regulatory Matters	5. REGULATORY MATTERS KCP&L Kansas Rate Case Proceedings On April 20, 2012, KCP&L filed an application with The State Corporation Commission of the State of Kansas (KCC) to request an increase to its retail revenues of $63.6 million, with a return on equity of 10.4% and a rate-making equity ratio of 51.8%. In September 2012, KCP&L revised its requested return on equity to 10.3%. The request includes recovery of costs related to significant upgrades at its generating facilities, including environmental upgrades at the La Cygne Station; investments in additional wind generation; and increased investments in electrical infrastructure. KCP&L is also requesting that KCC approve a change to depreciation rates to reflect the increase in plant in service as well as a change to the current method of allocating costs between its Kansas and Missouri jurisdictions to better reflect KCP&L's summer peaking business. Testimony from KCC staff and other parties regarding the case was filed on August 22, 2012. The KCC staff's testimony recommended a return on equity of 9.2% and a revenue increase of approximately $27.5 million. In October 2012, KCP&L adjusted its requested increase to retail revenues to $56.4 million as the net result of updates to the case, which includes a non-unanimous stipulation and agreement filed in September 2012 by KCP&L and KCC staff to settle a number of issues in the case. The stipulation and agreement is pending KCC approval. The outcome of the KCP&L Kansas rate case will likely be different than either of the positions of KCP&L or KCC staff. The decision of the KCC cannot be predicted. The increase to retail revenues is anticipated to be effective in January 2013. KCP&L Missouri Rate Case Proceedings On February 27, 2012, KCP&L filed an application with the Public Service Commission of the State of Missouri (MPSC) to request an increase to its retail revenues of $105.7 million, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%. In September 2012, KCP&L revised its requested return on equity to 10.3%. The request includes recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service and also includes a lower annual offset to the revenue requirement for the Missouri jurisdictional portion of KCP&L's annual non-firm wholesale electric sales margin (wholesale margin offset). KCP&L currently expects that it will not be able to achieve the $45.9 million wholesale margin offset currently reflected in its retail rates due to transmission congestion, regional demand and low wholesale power prices. Testimony from MPSC staff and other parties regarding the case was filed on August 2, 2012. The MPSC staff's testimony recommended a return on equity range of 8.0% to 9.0% and a revenue increase range of approximately $16.5 million to $33.7 million. In November 2012, the MPSC issued an order approving multiple stipulation and agreements to settle a number of the issues in the case. An order on the remaining issues in the case is anticipated to be received to accommodate the increase to retail revenues to be effective in late January 2013. The final outcome of the KCP&L Missouri rate case will likely be different than either of the positions of KCP&L or MPSC staff. The final decision of the MPSC cannot be predicted. In a March 2011 order, the MPSC required KCP&L and GMO to apply to the Internal Revenue Service (IRS) to reallocate approximately $26.5 million of Iatan No. 2 qualifying advance coal project tax credits from KCP&L to GMO. KCP&L and GMO did apply to the IRS but in September 2011, the IRS denied KCP&L's and GMO's request. In November 2012, the MPSC issued an order that does not require a reallocation of Iatan No. 2 qualifying advance coal project tax credits from KCP&L to GMO. GMO Missouri Rate Case Proceedings On February 27, 2012, GMO filed an application with the MPSC to request an increase to its retail revenues of $58.3 million for its Missouri Public Service division and $25.2 million for its St. Joseph Light & Power (L&P) division, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%. In September 2012, GMO revised its requested return on equity to 10.3% for both its Missouri Public Service and L&P divisions. The requests include recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service, costs related to energy efficiency and demand side management programs, and increased fuel costs. Testimony from MPSC staff and other parties regarding the case was filed on August 9, 2012. The MPSC staff's testimony recommended a return on equity range of 8.0% to 9.0%, with a revenue increase of $0.4 million to $11.9 million for GMO's Missouri Public Service division and $0.7 million to $4.6 million for its L&P division. In November 2012, the MPSC issued an order approving multiple stipulation and agreements to settle a number of the issues in the case. An order on the remaining issues in the case is anticipated to be received to accommodate the increase to retail revenues to be effective in late January 2013. The final outcome of the GMO Missouri rate case will likely be different than either of the positions of GMO or MPSC staff. The final decision of the MPSC cannot be predicted. In December 2011, GMO filed a request with the MPSC seeking to recover costs for new and enhanced energy efficiency and demand side management programs under the Missouri Energy Efficiency Investment Act (MEEIA). In November 2012, the MPSC issued an order approving a stipulation and agreement to settle all of the issues in the MEEIA request. GMO Fuel Adjustment Clause (FAC) Prudence Review GMO's electric retail rates contain an FAC tariff under which 95% of the difference between actual fuel cost, purchased power costs and off-system sales margin and the amount provided in base rates for these costs is passed along to GMO's customers. The MPSC requires prudence reviews of the FAC no less frequently than at 18-month intervals. On November 28, 2011, the MPSC staff filed its prudence review report for the 18-month prudence review period covering June 1, 2009 through November 30, 2010. The MPSC staff recommended to the MPSC to order GMO to refund approximately $19 million, plus interest, (subsequently revised to $14.9 million) to customers through an adjustment to its FAC because the MPSC staff asserted that GMO was imprudent in its use of natural gas hedges to mitigate risk associated with its future purchases in the spot power market. On September 4, 2012, the MPSC issued an order denying the MPSC staff's request for refund and the time frame for appeal of the MPSC order has passed. 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) also investigated the circumstances surrounding this transmission system outage. GMO was assessed an immaterial penalty in 2012 resolving this matter.

Pension Plans and Other Employee Benefits

9 Months Ended

Sep. 30, 2012

Pension Plans and Other Employee Benefits

6. PENSION PLANS AND OTHER EMPLOYEE BENEFITS

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

The following tables provide 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 September 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	8.9		$	7.8		$	0.8		$	0.7
Interest cost	12.2			12.4			1.9			2.0
Expected return on plan assets	(10.7		)	(9.5		)	(0.4		)	(0.4		)
Prior service cost	1.1			1.1			1.8			1.8
Recognized net actuarial (gain) loss	11.1			9.7			—			(0.1		)
Transition obligation	—			—			0.3			0.3
Settlement charge	—			10.0			—			—
Net periodic benefit costs before regulatory adjustment	22.6			31.5			4.4			4.3
Regulatory adjustment	(3.9		)	(12.8		)	0.3			0.4
Net periodic benefit costs	$	18.7		$	18.7		$	4.7		$	4.7



	Pension Benefits						Other Benefits
Year to Date September 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	26.6		$	23.4		$	2.4		$	2.3
Interest cost	36.7			37.5			5.8			5.9
Expected return on plan assets	(32.1		)	(28.8		)	(1.3		)	(1.3		)
Prior service cost	3.3			3.4			5.4			5.4
Recognized net actuarial (gain) loss	33.4			28.9			—			(0.4		)
Transition obligation	—			—			0.8			1.0
Settlement charge	—			10.2			—			—
Net periodic benefit costs before regulatory adjustment	67.9			74.6			13.1			12.9
Regulatory adjustment	(11.6		)	(25.1		)	1.0			0.7
Net periodic benefit costs	$	56.3		$	49.5		$	14.1		$	13.6

The entire disclosure for pension and other postretirement benefits.

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5, 6, 7, 8

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-Name Statement of Financial Accounting Standard (FAS)

-Number 158

-Paragraph 7, 21, 22

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-Name Implementation Guide (Q and A)

-Number FAS88

-Paragraph 63

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-Name Emerging Issues Task Force (EITF)

-Number 03-2

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-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 87

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-Name Statement of Financial Accounting Standard (FAS)

-Number 106

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-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

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-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

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-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

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+ Details

Equity Compensation

9 Months Ended

Sep. 30, 2012

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, restricted stock units, bonus shares, stock options, stock appreciation rights, 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 the associated income tax benefit.



	Three Months Ended September 30				Year to Date September 30
	2012		2011		2012		2011
Great Plains Energy	(millions)
Compensation expense	$	1.2	$	1.2	$	4.0	$	4.5
Income tax benefit	0.4		0.4		1.7		1.8
KCP&L
Compensation expense	$	0.8	$	0.8	$	2.9	$	3.1
Income tax benefit	0.3		0.2		1.3		1.2

Performance Shares

Performance share activity year to date September 30, 2012, is summarized in the following table. Performance adjustment represents the number of shares of common stock related to performance shares ultimately issued that can vary from the number of performance shares initially granted depending on Great Plains Energy's performance over a stated period of time.



	Performance Shares			Grant Date Fair Value*
Beginning balance		442,042			$	21.06
Granted		164,158			19.02
Forfeited		(74,923	)		20.06
Performance adjustment		(160,717	)
Ending balance		370,560			22.97

* weighted-average

At September 30, 2012, the remaining weighted-average contractual term was 1.2 years. The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2012, was $18.12 and $19.02, respectively. The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2011, was $26.30 and $26.15, respectively. At September 30, 2012, there was $3.0 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. There were no performance shares earned and paid for the three months ended and year to date September 30, 2012. There were no performance shares earned and paid for the three months ended September 30, 2011. The total fair value of performance shares earned and paid year to date September 30, 2011, was $0.8 million.

The fair value of performance share awards is estimated using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of expected volatilities, dividend yield and risk-free rates. Expected volatility is based on daily stock price change during a historical period commensurate with the remaining term of the performance period of the grant. The risk-free rate is based upon the rate at the time of the evaluation for zero-coupon government bonds with a maturity consistent with the remaining performance period of the grant. The dividend yield is based on the most recent dividends paid and the actual closing stock price on the valuation date. For shares granted in 2012, inputs for expected volatility, dividend yield and risk-free rates were 21%, 4.32% and 0.40%, respectively.

Restricted Stock

Restricted stock activity year to date September 30, 2012, is summarized in the following table.



	Nonvested Restricted Stock			Grant Date Fair Value*
Beginning balance		386,183			$	17.06
Granted and issued		164,660			19.73
Vested		(206,838	)		15.78
Forfeited		(67,816	)		19.49
Ending balance		276,189			19.01

* weighted-average

At September 30, 2012, the remaining weighted-average contractual term was 1.8 years. The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2012, was $22.18 and $19.73, respectively. The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2011, was $17.89 and $19.03, respectively. At September 30, 2012, there was $2.9 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 and year to date September 30, 2012, was insignificant and $3.3 million, respectively. There were no shares vested for the three months ended September 30, 2011. The total fair value of shares vested year to date September 30, 2011, was $2.6 million.

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

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+ Details

Short-term Borrowings and Short-term Bank Lines of Credit	9 Months Ended
	Sep. 30, 2012
Short-term Borrowings and Short-term Bank Lines of Credit [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 December 2016. 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 September 30, 2012, Great Plains Energy was in compliance with this covenant. At September 30, 2012, Great Plains Energy had $31.0 million of outstanding cash borrowings at a weighted-average interest rate of 2.00% and had issued letters of credit totaling $1.8 million under the credit facility. At December 31, 2011, Great Plains Energy had $22.0 million of outstanding cash borrowings at a weighted-average interest rate of 2.06% and had issued letters of credit totaling $11.6 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 provides support for its issuance of commercial paper and other general corporate purposes and expires in December 2016. 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 September 30, 2012, KCP&L was in compliance with this covenant. At September 30, 2012, KCP&L had $256.0 million of commercial paper outstanding at a weighted-average interest rate of 0.49%, had issued letters of credit totaling $13.9 million and had no outstanding cash borrowings under the credit facility. At December 31, 2011, KCP&L had $227.0 million of commercial paper outstanding at a weighted-average interest rate of 0.50%, had issued letters of credit totaling $21.5 million and had no outstanding cash borrowings under the credit facility. GMO's $450 Million Revolving Credit Facility and Commercial Paper GMO's $450 million revolving credit facility with a group of banks provides support for its issuance of commercial paper and other general corporate purposes and expires in December 2016. 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 September 30, 2012, GMO was in compliance with this covenant. At September 30, 2012, GMO had $171.0 million of commercial paper outstanding at a weighted-average interest rate of 0.94%, had issued letters of credit totaling $15.1 million and had no outstanding cash borrowings under the credit facility. At December 31, 2011, GMO had $40.0 million of commercial paper outstanding at a weighted-average interest rate of 0.88%, had issued letters of credit totaling $13.2 million and had no outstanding cash borrowings under the credit facility.

Commitments and Contingencies Disclosure [Abstract]

The entire disclosure for short-term debt.

+ References+ Details

Long-Term Debt

9 Months Ended

Sep. 30, 2012

Debt Disclosure [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.



	Year Due	September 30 2012				December 31 2011
KCP&L			(millions)
General Mortgage Bonds
4.97% EIRR bonds^(a)	2015-2035		$	106.9			$	119.3
7.15% Series 2009A (8.59% rate)^(b)	2019		400.0				400.0
4.65% EIRR Series 2005	2035		50.0				50.0
5.375% EIRR Series 2007B	2035		73.2				73.2
Senior Notes
5.85% Series (5.72% rate)^(b)	2017		250.0				250.0
6.375% Series (7.49% rate)^(b)	2018		350.0				350.0
6.05% Series (5.78% rate)^(b)	2035		250.0				250.0
5.30% Series	2041		400.0				400.0
EIRR bonds 4.90% Series 2008	2038		23.4				23.4
Other	2013-2018		2.6				2.9
Current maturities			(0.4		)		(12.7		)
Unamortized discount			(4.1		)		(4.2		)
Total KCP&L excluding current maturities^(c)			1,901.6				1,901.9
Other Great Plains Energy
GMO First Mortgage Bonds 9.44% Series	2013-2021		10.1				11.2
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6				5.6
0.318% Wamego Series 1996^(d)	2026		7.3				7.3
0.316% State Environmental 1993^(d)	2028		5.0				5.0
GMO Senior Notes
11.875% Series	2012		—				500.0
8.27% Series	2021		80.9				80.9
Fair Value Adjustment			—				16.3
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)^(b)	2013		250.0				250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)^(b)	2017		100.0				100.0
Great Plains Energy 4.85% Senior Notes (7.34% rate)^(b)	2021		350.0				350.0
Great Plains Energy 5.292% Senior Notes	2022		287.5				—
Great Plains Energy 10.00% Equity Units Subordinated Notes			—				287.5
Current maturities			(256.7		)		(788.7		)
Unamortized discount and premium, net			5.6				(0.7		)
Total Great Plains Energy excluding current maturities^(c)			$	2,762.9			$	2,742.3


^(a)	Weighted-average interest rates at September 30, 2012


^(b)	Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments


^(c)	Does not include $39.5 million EIRR Series 1993B, $63.3 million EIRR Series 2007 A-1 and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L


^(d)	Variable rate

Fair Value of Long-Term Debt

The fair value of long-term debt is categorized as a Level 2 liability within the fair value hierarchy as it is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices are not available. At September 30, 2012, the book value and fair value of Great Plains Energy's long-term debt, including current maturities, were $3.0 billion and $3.5 billion, respectively. At December 31, 2011, the book value and fair value of Great Plains Energy's long-term debt, including current maturities, were $3.5 billion and $3.9 billion, respectively. At September 30, 2012, and December 31, 2011, the book value and fair value of KCP&L's long-term debt, including current maturities, were $1.9 billion and $2.2 billion, respectively.

GMO Senior Notes

GMO repaid its $500 million 11.875% Senior Notes at maturity in July 2012.

Great Plains Energy Equity Units

In May 2009, Great Plains Energy issued $287.5 million of Equity Units. Equity Units, each with a stated amount of $50, initially consisted of a 5% undivided beneficial interest in $1,000 principal amount of 10.00% subordinated notes due June 15, 2042, and a purchase contract requiring the holder to purchase the Company's common stock by June 15, 2012 (the settlement date).

In March 2012, Great Plains Energy remarketed $287.4 million of its 10% subordinated notes that were originally issued as components of the Equity Units as senior notes at a new interest rate of 5.292%. The 5.292% Senior Notes mature in June 2022. Great Plains Energy did not receive any proceeds from the remarketing. Proceeds from the remarketing were used to purchase a portfolio of U.S. Treasury securities that were pledged as collateral to secure the Equity Unit holders' obligation under the purchase contract. There were also $0.1 million of purchase contracts that settled early and did not participate in the remarketing.

In June 2012, Great Plains Energy settled the obligations under the purchase contracts underlying its 5.7 million outstanding Equity Units by issuing approximately 17.1 million shares of its common stock in exchange for $287.4 million, which had been raised through the remarketing completed in March 2012. The settlement rate of 2.9762 shares of common stock for each Equity Unit was determined according to the applicable market value of the Company's common stock at the settlement date. The applicable market value of $20.05 was measured by the average of the closing price per share of the Company's common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding June 15, 2012.

Commitments and Contingencies

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies

10. COMMITMENTS AND CONTINGENCIES

Environmental Matters

Great Plains Energy and KCP&L are subject to extensive federal, state and local environmental laws, regulations and permit requirements relating to air and water quality, waste management and disposal, natural resources and health and safety. In addition to imposing continuing compliance obligations and remediation costs, these 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 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 Overview

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 Allowance for Funds Used During Construction (AFUDC) and property taxes) to comply with the currently-effective Clean Air Interstate Rule (CAIR), the replacement to CAIR or the Cross-State Air Pollution Rule (CSAPR), the best available retrofit technology (BART) rule, the SO₂ National Ambient Air Quality Standard (NAAQS), the industrial boiler rule and the Mercury and Air Toxics Standards (MATS) rule that would reduce emissions of toxic air pollutants, (all of which are discussed below) is approximately $1 billion. The actual cost of compliance with any existing, proposed or future rules may be significantly different from the cost estimate provided.

The approximate $1 billion current estimate of capital expenditures reflects the following capital projects:


•	KCP&L's La Cygne No. 1 scrubber and baghouse installed by June 2015;


•	KCP&L's La Cygne No. 2 full air quality control system (AQCS) installed by June 2015;


•	KCP&L's Montrose No. 3 full AQCS installed by approximately 2020; and


•	GMO's Sibley No. 3 scrubber and baghouse installed by approximately 2017.

In September 2011, KCP&L commenced construction of the La Cygne project. Other capital projects at KCP&L's Montrose Nos. 1 and 2 and GMO's Sibley Nos. 1 and 2 and Lake Road No. 4/6 are possible but are currently considered less likely. In connection with KCP&L's and GMO's Integrated Resource Plan (IRP) filings with the MPSC in April 2012, the economics around Montrose No. 2 and Lake Road No. 4/6 have improved. Pending further evaluation, these projects may move from less likely to more likely but it is not expected to materially impact the overall $1 billion current estimate of capital expenditures. Any capacity and energy requirements resulting from a decision not to proceed with these less likely projects is currently expected to be met through renewable energy additions required under Missouri and Kansas renewable energy standards, demand side management programs, construction of combustion turbines and/or combined cycle units, and/or power purchase agreements.

The $1 billion current estimate of capital expenditures 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 current or future environmental laws. 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 Cross-State Air Pollution Rule (CSAPR)

The CAIR requires reductions in SO₂ and NO_x emissions in 28 states, including Missouri. The reductions in SO₂ and NO_x emissions are accomplished through statewide caps for NO_x and SO₂. 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.

In July 2008, the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit Court) vacated CAIR in its entirety and remanded the matter to the EPA to promulgate a new rule consistent with its opinion. In December 2008, the court issued an order reinstating CAIR pending EPA's development of a replacement regulation on remand. In July 2011, the EPA finalized the CSAPR to replace the currently-effective CAIR. Compliance with the CSAPR was scheduled to begin in 2012. Multiple states, utilities and other parties, including KCP&L, filed requests for reconsideration and stays with the EPA and/or the D.C. Circuit Court. In August 2012, the D.C. Circuit Court issued its opinion in which it vacated the CSAPR and remanded the rule to the EPA to revise in accordance with its opinion. The court directed the EPA to continue to administer the CAIR until a valid replacement is promulgated. The EPA and other parties have requested rehearing of this decision by the D.C. Circuit Court.

The CSAPR requires the states within its scope to reduce power plant SO₂ and NO_x emissions that contribute to ozone and fine particle nonattainment in other states. The geographical scope of the CSAPR includes Kansas, Missouri and other states. In the CSAPR, the EPA set an emissions budget for each of the affected states. The CSAPR allows limited interstate emissions allowance trading among power plants; however, it does not permit trading of SO₂ allowances between the Companies' Kansas and Missouri power plants. There are additional reductions in SO₂ allowances allocable to the Companies' Missouri power plants taking effect in 2014. There is no such 2014 additional reduction in SO₂ allowances allocable to the Companies' Kansas power plants.

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 La Cygne Nos. 1 and 2 in Kansas, KCP&L's Iatan No. 1, in which GMO has an 18% interest, and 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. Both Missouri and Kansas have submitted BART plans to the EPA. In December 2011, the EPA approved the Kansas BART plan.

In May 2012, the EPA finalized a rule that approves the CSAPR as an alternative to BART. As a result, states in the CSAPR will be able to substitute participation in the CSAPR for source-specific BART. In addition, the EPA finalized a limited disapproval of the BART plan that had been submitted by Missouri because it relied on requirements of the CAIR to satisfy certain regional haze requirements. To address deficiencies in a CAIR-dependent BART plan, the EPA promulgated a Federal Implementation Plan (FIP) to replace reliance on CAIR with reliance on the CSAPR in the BART plan for Missouri. In June 2012, the EPA finalized a limited approval of the Missouri BART plan that does not include the FIP-approved component of the BART plan.

Mercury and Air Toxics Standards (MATS) Rule

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 in effect are subject to a new source maximum achievable control technology (MACT) determination on a case-by-case basis. In July 2009, the EPA sent a letter notifying KCP&L that a MACT determination and schedule of compliance is required for coal and oil-fired EGUs that began actual construction or reconstruction after December 15, 2000, and identified Iatan No. 2 as an affected EGU. This was an outcome of the D.C. Circuit Court of Appeals' vacatur of both the CAMR and the contemporaneously promulgated rule removing EGUs from MACT requirements. It is not currently known how the MACT determination and schedule of compliance will impact the permitting or operating requirements for Iatan No. 2, but it is possible a MACT determination may ultimately require additional emission control equipment and permit limits.

In December 2011, the EPA finalized the MATS Rule that will reduce emissions of toxic air pollutants, also known as hazardous air pollutants, from new and existing coal- and oil-fired EGUs with a capacity of greater than 25 MWs. The rule establishes numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrochloric acid (a surrogate for acid gases). The rule establishes work practices, instead of numerical emission limits, for organic air toxics, including dioxin/furan. Compliance with the rule would need to be achieved 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. The rule allows three years for compliance with authority for state permitting authorities to grant an additional year as needed for technology installation. The EPA indicated that it expects this option to be broadly available. The Missouri Department of Natural Resources (MDNR) has granted an extension at KCP&L's Montrose Station and at GMO's Lake Road and Sibley Stations. The Kansas Department of Health and Environment (KDHE) has granted an extension at KCP&L's La Cygne Station.

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. In May 2011, the EPA announced it would stay the effective date of the final rule during reconsideration; although in January 2012, the D.C. Circuit Court vacated the stay and remanded the stay to the EPA. The EPA issued a proposed revised rule in December 2011 and intends to issue a final rule in 2012. The proposed revised rule establishes numeric emission limits for mercury, 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 final rule establishes emission limits for KCP&L's and GMO's existing units that produce steam other than for the generation of electricity. The existing boiler rule and its proposed revisions do 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's New Source Review program 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 2010, Westar settled a lawsuit filed by the Department of Justice on behalf of the EPA. The lawsuit asserted that certain projects completed at the Jeffrey Energy Center violated certain requirements of the New Source Review program. The Jeffrey Energy Center 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. The settlement agreement required, among other things, the installation of a selective catalytic reduction (SCR) system at one of the three Jeffrey Energy Center units by the end of 2014. Westar has estimated the cost of this SCR at approximately $240 million. Depending on the NO_x 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. GMO expects to seek recovery of its share of these costs through rate increases; however, there can be no assurance that such rate increases would be granted.

KCP&L had received requests for information from the KDHE pertaining to a past La Cygne No. 1 scrubber project. In April 2012, KCP&L and KDHE agreed to resolve this matter with KCP&L completing supplemental environmental projects in the amount of $800,000 and paying a penalty in the amount of $350,000.

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 designed to offset CO₂ emissions.

KCP&L agreed in the Collaboration Agreement to pursue increasing its wind generation capacity by 400 MWs by the end of 2012. KCP&L and GMO have added 379 MWs of wind generation and have also added the equivalent CO₂ offset of 21 MWs of wind through solar, landfill gas and other projects that were not required under the Collaboration Agreement.

KCP&L has a consent agreement with the KDHE incorporating limits for stack particulate matter emissions, as well as limits for NO_x and SO₂ emissions, at its La Cygne Station that, consistent with the Collaboration Agreement, 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 La Cygne Station prior to the required compliance date under BART, but in no event later than June 1, 2015. In August 2011, KCC issued its order on KCP&L's predetermination request that would apply to the recovery of costs for its 50% share of the environmental equipment required to comply with BART at the La Cygne Station. In the order, KCC stated that KCP&L's decision to retrofit La Cygne was reasonable, reliable, efficient and prudent and the $1.23 billion cost estimate is reasonable. If the cost for the project is at or below the $1.23 billion estimate, absent a showing of fraud or other intentional imprudence, KCC stated that it will not re-evaluate the prudency of the cost of the project. If the cost of the project exceeds the $1.23 billion estimate and KCP&L seeks to recover amounts exceeding the estimate, KCP&L will bear the burden of proving that any additional costs were prudently incurred. KCP&L's 50% share of the estimated cost is $615 million. KCP&L began the project in September 2011.

Also in the Collaboration Agreement, KCP&L agreed to offset an additional 711,000 tons of CO₂ by the end of 2012, which it has done.

Climate Change

The Companies are subject to existing greenhouse gas reporting regulations and certain greenhouse gas permitting requirements. Management believes it is possible 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 international 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 25 million tons and 18 million tons per year for Great Plains Energy and KCP&L, respectively.

Laws have 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 possible. While management believes additional requirements addressing these matters will possibly 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. 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 as to 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 likely 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 March 2012, the EPA proposed new source performance standards for emissions of CO₂ for new affected fossil-fuel-fired electric utility generating units. This action pursuant to the Clean Air Act would, for the first time, set national limits on the amount of CO₂ that power plants built in the future can emit. The proposal would not apply to Great Plains Energy's and KCP&L's existing units including modifications to those units.

At the state level, a Kansas law enacted in May 2009 required 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 required 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 2 MW for each of KCP&L and GMO) required to come from solar resources.

KCP&L and GMO project that they will be compliant with the Missouri renewable requirements, exclusive of the solar requirement, through 2023 for KCP&L and 2018 for GMO. KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri solar requirements for the foreseeable future. KCP&L also projects that it will be compliant with the Kansas renewable requirements through 2015.

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.

SO₂ NAAQS

In June 2010, the EPA strengthened the primary NAAQS for SO₂ by establishing a new 1-hour standard at a level of 0.075 ppm and revoking the two existing primary standards of 0.140 ppm evaluated over 24 hours and 0.030 ppm evaluated over an entire year. In July 2011, the MDNR recommended to the EPA that part of Jackson County, Missouri, which is in the Companies' service territory, be designated a nonattainment area for the new 1-hour SO₂ standard. In April 2012, the EPA announced it is seeking additional input from states, tribes, and other interested parties to refine the agency's approach for implementing the SO₂ standard.

Particulate Matter (PM) NAAQS

In June 2012, the EPA proposed to strengthen the NAAQS for fine particulate matter (PM2.5). The proposal strengthens the annual primary standard and seeks comment on alternative levels of the annual primary standard. The proposal retains the existing 24-hour PM2.5 primary standard, coarse particle matter (PM10) primary standard, and secondary standards for PM2.5 and PM10 identical to the primary standards. The proposal also includes a separate PM2.5 standard to improve visibility. The EPA is proposing two visibility options for this 24-hour standard and is seeking comment on alternative levels. The EPA agreed to finalize the rule by December 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.

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 June 2013. 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, the EPA plans to revise the existing standards for water discharges from coal-fired power plants with a proposed rule in December 2012 and final action in May 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 option, the EPA would regulate CCRs as special wastes under subtitle C of RCRA (hazardous), when they are destined for disposal in landfills or surface impoundments. Under the second option, the EPA would regulate disposal of CCRs under subtitle D of RCRA (non-hazardous). The Companies use coal in generating electricity and dispose of the CCRs in both on-site facilities and facilities owned by third parties. The cost of complying with the proposed CCR rule has the potential of having a significant financial and operational impact on Great Plains Energy and KCP&L. 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 contaminated facilities and persons who arranged for the disposal or treatment of hazardous substances liable for the cost of investigation and cleanup. 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 biphenyl (PCB) contamination, 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 September 30, 2012, and December 31, 2011, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site. At September 30, 2012, and December 31, 2011, 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 September 30, 2012, and December 31, 2011, Great Plains Energy had $3.0 million and $2.1 million, respectively, accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB contaminated 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; however, given the uncertainty of these items the possible loss or range of loss in excess of the amount accrued is not estimable.

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 $2.4 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.

The entire disclosure for commitments and contingencies.

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+ Details

Legal Proceedings	9 Months Ended
Legal Proceedings	Sep. 30, 2012
Legal Proceedings [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. On July 12, 2012, a three-judge panel of the Court of Appeals issued a decision reversing in part the trial court's decision and directing that the original award be increased by $2.1 million ($1.0 million KCP&L share). The United States requested a rehearing of that decision, but on October 1, 2012, the court denied the rehearing request. On November 1, 2012, the trial court amended its judgment to comply with the Court of Appeals decision. GMO Western Energy Crisis In response to complaints of manipulation of the California energy market, The Federal Energy Regulatory Commission (FERC) issued an order in July 2001 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. In December 2001, various parties appealed the July 2001 FERC order to the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) seeking review of a number of issues, including expansion of the refund period to include periods prior to October 2, 2000 (the Summer Period). MPS Merchant was a net seller of power during the Summer Period. On August 2, 2006, 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 Summer Period. The court remanded the matter to FERC for further consideration. In May 2011, FERC issued an order which clarified the scope of the hearing regarding spot-market transactions during the Summer Period and ruled on requests for rehearing and motions to dismiss. An evidentiary hearing before a FERC administrative law judge concluded on July 19, 2012. An initial decision by the FERC administrative law judge is due by February 2013. If FERC determines that MPS Merchant violated then-existing tariffs or laws during the Summer Period and that such violations affected market clearing prices in California, MPS Merchant could be found to owe refunds. A separate proceeding was also initiated, generally referred to as the Pacific Northwest refund proceeding, to determine if any refunds were warranted in the Pacific Northwest between December 25, 2000, and June 20, 2001. Refund claims brought against MPS Merchant were $5.1 million. MPS Merchant expects to settle these claims for an immaterial amount in the fourth quarter of 2012.

Tabular disclosure of the loss contingencies that were reported in the period or disclosed as of the balance sheet date.

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Related Party Transactions and Relationships

9 Months Ended

Sep. 30, 2012

12. RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO's business and operate its facilities at cost. These costs totaled $23.9 million and $76.8 million, respectively, for the three months ended and year to date September 30, 2012. These costs totaled $25.0 million and $82.2 million, respectively, for the same periods in 2011. 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.



	September 30 2012			December 31 2011
		(millions)
Net receivable from GMO		$	15.9		$	24.1
Net receivable from Great Plains Energy		6.7			9.5

The entire disclosure for related party transactions. 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.

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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Derivative Instruments

9 Months Ended

Sep. 30, 2012

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 commodity risk 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 and purchased power 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 purchases and normal sales (NPNS) 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 September 30, 2012, 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.

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 September 30, 2012, KCP&L had hedged 89% and 16%, respectively, of the 2013 and 2014 projected natural gas usage for retail load and firm MWh sales by utilizing futures contracts. KCP&L has designated the natural gas hedges as cash flow hedges. 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 and year to date September 30, 2012 and 2011.

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 September 30, 2012, GMO had financial contracts in place to hedge approximately 93% for the remainder of 2012, 71% for 2013 and 10% for 2014 of the expected on-peak natural gas generation and natural gas equivalent purchased power price exposure. GMO has designated its natural gas hedges as economic hedges (non-hedging derivatives). 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, which has certain long-term natural gas contracts remaining from its former non-regulated trading operations, 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.



	September 30 2012					December 31 2011
	Notional Contract Amount		Fair Value			Notional Contract Amount		Fair Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	1.0	$	(0.2	)	$	2.0	$	(0.5	)
Non-hedging derivatives	16.3		(1.9		)	23.6		(5.0		)
Forward contracts
Non-hedging derivatives	70.3		6.8			97.3		7.8
Option contracts
Non-hedging derivatives	—		—			0.4		—
KCP&L
Futures contracts
Cash flow hedges	$	1.0	$	(0.2	)	$	2.0	$	(0.5	)

The fair values of Great Plains Energy's and KCP&L's open derivative positions are summarized in the following tables. The tables contain both derivative instruments designated as hedging instruments as well as 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
September 30, 2012	Classification	Fair Value			Fair Value
Derivatives Designated as Hedging Instruments			(millions)
Commodity contracts	Derivative instruments		$	—		$	0.2
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.2			2.3
Total Derivatives			$	7.2		$	2.5

December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments		$	—		$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.8			5.0
Total Derivatives			$	7.8		$	5.5

KCP&L

Balance Sheet

Asset Derivatives

Liability Derivatives

September 30, 2012

Classification

Fair Value

Derivatives Designated as Hedging Instruments

(millions)

Commodity contracts

Derivative instruments

—

0.2

December 31, 2011

Derivatives Designated as Hedging Instruments

Commodity contracts

Derivative instruments

—

0.5

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 (Effective Portion)				Income Statement Classification	Amount
Three Months Ended September 30, 2012	(millions)					(millions)
Interest rate contracts		$	—		Interest charges	$	(5.0	)
Commodity contracts		0.1			Fuel	(0.5		)
Income tax expense		(0.1		)	Income tax benefit	2.1
Total		$	—		Total	$	(3.4	)
Year to Date September 30, 2012
Interest rate contracts		$	—		Interest charges	$	(15.1	)
Commodity contracts		(0.1		)	Fuel	(0.5		)
Income tax benefit		—			Income tax benefit	6.0
Total		$	(0.1	)	Total	$	(9.6	)
Three Months Ended September 30, 2011
Interest rate contracts		$	—		Interest charges	$	(5.1	)
Commodity contracts		(0.1		)	Fuel	(0.1		)
Income tax benefit		0.1			Income tax benefit	2.1
Total		$	—		Total	$	(3.1	)
Year to Date September 30, 2011
Interest rate contracts		$	(5.3	)	Interest charges	$	(11.9	)
Commodity contracts		(0.2		)	Fuel	(0.1		)
Income tax benefit		2.2			Income tax benefit	4.7
Total		$	(3.3	)	Total	$	(7.3	)



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 (Effective Portion)				Income Statement Classification	Amount
Three Months Ended September 30, 2012	(millions)					(millions)
Interest rate contracts		$	—		Interest charges	$	(2.2	)
Commodity contracts		0.1			Fuel	(0.5		)
Income tax expense		(0.1		)	Income tax benefit	1.0
Total		$	—		Total	$	(1.7	)
Year to Date September 30, 2012
Interest rate contracts		$	—		Interest charges	$	(6.6	)
Commodity contracts		(0.1		)	Fuel	(0.5		)
Income tax benefit		—			Income tax benefit	2.7
Total		$	(0.1	)	Total	$	(4.4	)
Three Months Ended September 30, 2011
Interest rate contracts		$	—		Interest charges	$	(2.1	)
Commodity contracts		(0.1		)	Fuel	(0.1		)
Income tax benefit		0.1			Income tax benefit	0.9
Total		$	—		Total	$	(1.3	)
Year to Date September 30, 2011
Interest rate contracts		$	—		Interest charges	$	(6.5	)
Commodity contracts		(0.2		)	Fuel	(0.1		)
Income tax benefit		0.1			Income tax benefit	2.6
Total		$	(0.1	)	Total	$	(4.0	)

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 Classification	Amount
Three Months Ended September 30, 2012	(millions)					(millions)
Commodity contracts		$	0.9		Fuel	$	(2.8	)
Total		$	0.9		Total	$	(2.8	)
Year to Date September 30, 2012
Commodity contracts		$	(1.8	)	Fuel	$	(5.5	)
Total		$	(1.8	)	Total	$	(5.5	)
Three Months Ended September 30, 2011
Commodity contracts		$	(2.2	)	Fuel	$	(0.6	)
Total		$	(2.2	)	Total	$	(0.6	)
Year to Date September 30, 2011
Commodity contracts		$	(3.5	)	Fuel	$	(3.5	)
Total		$	(3.5	)	Total	$	(3.5	)

Great Plains Energy's income statement reflects gains (losses) for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $0.1 million and $(1.0) million, respectively, for the three months ended and year to date September 30, 2012, and $(0.6) million and $0.4 million, respectively, for the same periods in 2011.

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



	Great Plains Energy								KCP&L
	September 30 2012				December 31 2011				September 30 2012				December 31 2011
		(millions)
Current assets		$	10.8			$	11.3			$	10.8			$	11.3
Current liabilities		(73.6		)		(89.5		)		(55.1		)		(62.5		)
Noncurrent liabilities		(0.1		)		(0.2		)		(0.1		)		(0.2		)
Deferred income taxes		24.5				30.5				17.3				20.0
Total		$	(38.4	)		$	(47.9	)		$	(27.1	)		$	(31.4	)

Great Plains Energy's accumulated OCI in the table above at September 30, 2012, includes $20.3 million that is expected to be reclassified to expenses over the next twelve months. KCP&L's accumulated OCI in the table above at September 30, 2012, includes $8.9 million that is expected to be reclassified to expenses over the next twelve months.

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

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+ Details

Fair Value Measurements

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [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 and liabilities 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 Supplemental Executive Retirement Plan (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 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 September 30, 2012, and December 31, 2011.



								Fair Value Measurements Using
Description	September 30 2012			Netting^(d)				Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
KCP&L		(millions)
Assets
Nuclear decommissioning trust ^(b)
Equity securities		$	97.9		$	—			$	97.9		$	—		$	—
Debt securities
U.S. Treasury		18.6			—				18.6			—			—
U.S. Agency		2.8			—				—			2.8			—
State and local obligations		2.7			—				—			2.7			—
Corporate bonds		26.4			—				—			26.4			—
Foreign governments		0.6			—				—			0.6			—
Other		0.2			—				—			0.2			—
Total nuclear decommissioning trust		149.2			—				116.5			32.7			—
Total		149.2			—				116.5			32.7			—
Liabilities
Derivative instruments ^(a)		—			(0.2		)		0.2			—			—
Total		$	—		$	(0.2	)		$	0.2		$	—		$	—
Other Great Plains Energy
Assets
Derivative instruments ^(a)		$	6.8		$	(0.4	)		$	0.4		$	4.4		$	2.4
SERP rabbi trust ^(c)
Equity securities		0.1			—				0.1			—			—
Debt securities		0.1			—				—			0.1			—
Total SERP rabbi trust		0.2			—				0.1			0.1			—
Total		7.0			(0.4		)		0.5			4.5			2.4
Liabilities
Derivative instruments ^(a)		—			(2.3		)		2.3			—			—
Total		$	—		$	(2.3	)		$	2.3		$	—		$	—
Great Plains Energy
Assets
Derivative instruments ^(a)		$	6.8		$	(0.4	)		$	0.4		$	4.4		$	2.4
Nuclear decommissioning trust ^(b)		149.2			—				116.5			32.7			—
SERP rabbi trust ^(c)		0.2			—				0.1			0.1			—
Total		156.2			(0.4		)		117.0			37.2			2.4
Liabilities
Derivative instruments ^(a)		—			(2.5		)		2.5			—			—
Total		$	—		$	(2.5	)		$	2.5		$	—		$	—



									Fair Value Measurements Using
Description	December 31 2011				Netting^(d)				Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
KCP&L		(millions)
Assets
Nuclear decommissioning trust ^(b)
Equity securities		$	84.3			$	—			$	84.3		$	—			$	—
Debt securities
U.S. Treasury		15.3				—				15.3			—				—
U.S. Agency		3.6				—				—			3.6				—
State and local obligations		2.6				—				—			2.6				—
Corporate bonds		26.4				—				—			26.4				—
Foreign governments		0.7				—				—			0.7				—
Other		(0.6		)		—				—			(0.6		)		—
Total nuclear decommissioning trust		132.3				—				99.6			32.7				—
Total		132.3				—				99.6			32.7				—
Liabilities
Derivative instruments ^(a)		—				(0.5		)		0.5			—				—
Total		$	—			$	(0.5	)		$	0.5		$	—			$	—
Other Great Plains Energy
Assets
Derivative instruments ^(a)		$	7.8			$	—			$	—		$	4.7			$	3.1
SERP rabbi trust ^(c)
Equity securities		0.2				—				0.2			—				—
Debt securities		0.1				—				—			0.1				—
Total SERP rabbi trust		0.3				—				0.2			0.1				—
Total		8.1				—				0.2			4.8				3.1
Liabilities
Derivative instruments ^(a)		—				(5.0		)		5.0			—				—
Total		$	—			$	(5.0	)		$	5.0		$	—			$	—
Great Plains Energy
Assets
Derivative instruments ^(a)		$	7.8			$	—			$	—		$	4.7			$	3.1
Nuclear decommissioning trust ^(b)		132.3				—				99.6			32.7				—
SERP rabbi trust ^(c)		0.3				—				0.2			0.1				—
Total		140.4				—				99.8			37.5				3.1
Liabilities
Derivative instruments ^(a)		—				(5.5		)		5.5			—				—
Total		$	—			$	(5.5	)		$	5.5		$	—			$	—


(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 $2.9 million and $3.0 million at September 30, 2012, and December 31, 2011, 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 $20.3 million at September 30, 2012, and December 31, 2011, 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 September 30, 2012, and December 31, 2011, Great Plains Energy netted $2.1 million and $5.5 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 and year to date September 30, 2012 and 2011.



Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative Instruments
	(millions)
Balance at July 1	$	2.2		$	4.9
Total realized/unrealized gains included in non-operating income	3.7			4.0
Settlements	(3.5		)	(4.4		)
Balance at September 30	$	2.4		$	4.5
Total unrealized gains and (losses) included in non-operating income relating to assets
and liabilities still on the consolidated balance sheet at September 30	$	0.3		$	(0.3	)



Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative Instruments
	(millions)
Balance at January 1	$	3.1		$	3.7
Total realized/unrealized gains included in non-operating income	4.8			11.1
Settlements	(5.5		)	(10.3		)
Balance at September 30	$	2.4		$	4.5
Total unrealized gains and (losses) included in non-operating income relating to assets
and liabilities still on the consolidated balance sheet at September 30	$	(0.4	)	$	1.2

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial 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 entity 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 risks 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.

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-Number 107

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+ Details

Taxes

9 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

Taxes

15. TAXES

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



	Three Months Ended September 30						Year to Date September 30
Great Plains Energy	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	(1.4	)	$	(10.2	)	$	(4.7	)	$	(6.4	)
State	(0.3		)	(0.8		)	—			(4.8		)
Foreign	—			—			—			(0.4		)
Total	(1.7		)	(11.0		)	(4.7		)	(11.6		)
Deferred income taxes
Federal	75.1			74.7			97.6			103.6
State	13.9			13.0			18.2			20.4
Total	89.0			87.7			115.8			124.0
Noncurrent income taxes
Federal	—			—			(0.2		)	(18.0		)
State	—			—			—			(1.9		)
Foreign	(4.1		)	(0.6		)	(4.2		)	(0.4		)
Total	(4.1		)	(0.6		)	(4.4		)	(20.3		)
Investment tax credit amortization	(0.6		)	(0.7		)	(1.8		)	(1.5		)
Income tax expense	$	82.6		$	75.4		$	104.9		$	90.6



	Three Months Ended September 30						Year to Date September 30
KCP&L	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	22.9		$	(10.2	)	$	23.1		$	(7.8	)
State	4.1			(0.9		)	4.2			(0.4		)
Total	27.0			(11.1		)	27.3			(8.2		)
Deferred income taxes
Federal	22.7			53.5			38.8			73.4
State	4.5			9.3			8.6			13.8
Total	27.2			62.8			47.4			87.2
Noncurrent income taxes
Federal	1.0			1.5			1.1			(9.1		)
State	0.2			0.1			0.2			(1.0		)
Total	1.2			1.6			1.3			(10.1		)
Investment tax credit amortization	(0.5		)	(0.5		)	(1.4		)	(1.0		)
Income tax expense	$	54.9		$	52.8		$	74.6		$	67.9

Income Tax Expense and Effective Income Tax Rates

Income tax expense 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						Income Tax Rate
Three Months Ended September 30	2012			2011			2012		2011
	(millions)
Federal statutory income tax	$	80.0		$	70.6		35.0	%	35.0	%
Differences between book and tax depreciation not
normalized	1.3			1.8			0.5		0.9
Amortization of investment tax credits	(0.6		)	(0.7		)	(0.3	)	(0.3	)
Federal income tax credits	(2.2		)	(2.9		)	(1.0	)	(1.4	)
State income taxes	8.8			8.1			3.8		4.0
Changes in uncertain tax positions, net	(4.1		)	(2.7		)	(1.8	)	(1.3	)
Other	(0.6		)	1.2			(0.1	)	0.4
Total	$	82.6		$	75.4		36.1	%	37.3	%



Great Plains Energy	Income Tax Expense						Income Tax Rate
Year to Date September 30	2012			2011			2012		2011
	(millions)
Federal statutory income tax	$	105.0		$	92.0		35.0	%	35.0	%
Differences between book and tax depreciation not
normalized	3.4			3.7			1.1		1.4
Amortization of investment tax credits	(1.8		)	(1.5		)	(0.6	)	(0.6	)
Federal income tax credits	(8.3		)	(9.7		)	(2.8	)	(3.7	)
State income taxes	11.7			11.1			3.9		4.2
Changes in uncertain tax positions, net	(4.2		)	(4.0		)	(1.4	)	(1.5	)
Valuation allowance	0.1			(2.2		)	—		(0.8	)
Other	(1.0		)	1.2			(0.3	)	0.5
Total	$	104.9		$	90.6		34.9	%	34.5	%



KCP&L	Income Tax Expense						Income Tax Rate
Three Months Ended September 30	2012			2011			2012		2011
	(millions)
Federal statutory income tax	$	50.8		$	48.3		35.0	%	35.0	%
Differences between book and tax depreciation not
normalized	1.0			1.7			0.7		1.2
Amortization of investment tax credits	(0.5		)	(0.5		)	(0.3	)	(0.4	)
Federal income tax credits	(2.2		)	(2.9		)	(1.5	)	(2.1	)
State income taxes	5.8			5.7			3.9		4.1
Other	—			0.5			—		0.4
Total	$	54.9		$	52.8		37.8	%	38.2	%



KCP&L	Income Tax Expense						Income Tax Rate
Year to Date September 30	2012			2011			2012		2011
	(millions)
Federal statutory income tax	$	73.8		$	66.7		35.0	%	35.0	%
Differences between book and tax depreciation not
normalized	2.8			3.3			1.3		1.7
Amortization of investment tax credits	(1.4		)	(1.0		)	(0.6	)	(0.5	)
Federal income tax credits	(8.3		)	(9.6		)	(4.0	)	(5.1	)
State income taxes	8.4			7.7			4.0		4.0
Changes in uncertain tax positions, net	—			0.4			—		0.2
Other	(0.7		)	0.4			(0.3	)	0.3
Total	$	74.6		$	67.9		35.4	%	35.6	%

Uncertain Tax Positions

At September 30, 2012, and December 31, 2011, Great Plains Energy had $21.0 million and $24.0 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $7.6 million and $11.8 million at September 30, 2012, and December 31, 2011, respectively, are expected to impact the effective tax rate if recognized. The $3.0 million decrease in unrecognized tax benefits is primarily due to a $4.5 million decrease of unrecognized tax benefits related to former GMO non-regulated operations.

At September 30, 2012, and December 31, 2011, KCP&L had $9.9 million and $8.7 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $0.2 million at September 30, 2012, and December 31, 2011, 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
	September 30 2012				December 31 2011				September 30 2012				December 31 2011
		(millions)
Beginning balance January 1		$	24.0			$	42.0			$	8.7			$	19.1
Additions for current year tax positions		2.8				1.4				2.7				—
Additions for prior year tax positions		—				2.4				—				2.3
Reductions for prior year tax positions		(6.1		)		(20.9		)		(1.5		)		(12.6		)
Statute expirations		—				(0.7		)		—				(0.1		)
Foreign currency translation adjustments		0.3				(0.2		)		—				—
Ending balance		$	21.0			$	24.0			$	9.9			$	8.7

Great Plains Energy and KCP&L recognize interest related to unrecognized tax benefits in interest expense and penalties in non-operating expenses. At September 30, 2012, and December 31, 2011, accrued interest related to unrecognized tax benefits for Great Plains Energy was $3.5 million and $5.7 million, respectively. The $2.2 million decrease in accrued interest was primarily related to former GMO non-regulated operations. Amounts accrued for penalties with respect to unrecognized tax benefits for Great Plains Energy were $0.7 million and $1.1 million at September 30, 2012, and December 31, 2011, respectively. Amounts accrued for interest and 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 2009 tax year. The Company estimates that it is reasonably possible that $4.8 million and $4.0 million for Great Plains Energy and KCP&L, respectively, of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities.

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

Segments and Related Information

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+ Details

Segments and Related Information

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

16. SEGMENTS AND RELATED INFORMATION

Great Plains Energy has one reportable segment based on its method of internal reporting, which segregates reportable segments based on products and services, management responsibility and regulation. The one reportable business segment is electric utility, consisting of KCP&L, GMO's regulated utility operations and GMO Receivables Company. 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 September 30, 2012	Electric Utility				Other			Great Plains Energy
		(millions)
Operating revenues		$	746.2			$	—		$	746.2
Depreciation and amortization		(68.9		)		—			(68.9		)
Interest (charges) income		(48.4		)		0.3			(48.1		)
Income tax (expense) benefit		(86.5		)		3.9			(82.6		)
Net income attributable to Great Plains Energy		141.9				4.3			146.2



Year to Date September 30, 2012	Electric Utility				Other				Great Plains Energy
		(millions)
Operating revenues		$	1,829.5			$	—			$	1,829.5
Depreciation and amortization		(204.2		)		—				(204.2		)
Interest charges		(149.5		)		(21.3		)		(170.8		)
Income tax (expense) benefit		(120.6		)		15.7				(104.9		)
Net income (loss) attributable to Great Plains Energy		210.2				(15.0		)		195.2



Three Months Ended September 30, 2011	Electric Utility				Other				Great Plains Energy
		(millions)
Operating revenues		$	773.7			$	—			$	773.7
Depreciation and amortization		(65.9		)		—				(65.9		)
Interest charges		(50.2		)		(10.6		)		(60.8		)
Income tax (expense) benefit		(82.9		)		7.5				(75.4		)
Net income (loss) attributable to Great Plains Energy		133.9				(7.4		)		126.5



Year to Date September 30, 2011	Electric Utility				Other				Great Plains Energy
		(millions)
Operating revenues		$	1,831.7			$	—			$	1,831.7
Depreciation and amortization		(205.9		)		—				(205.9		)
Interest charges		(124.8		)		(31.2		)		(156.0		)
Income tax (expense) benefit		(109.8		)		19.2				(90.6		)
Net income (loss) attributable to Great Plains Energy		189.9				(17.6		)		172.3



	Electric Utility			Other			Eliminations				Great Plains Energy
September 30, 2012		(millions)
Assets		$	9,765.3		$	152.5		$	(415.4	)		$	9,502.4
Capital expenditures ^(a)		409.5			—			—				409.5
December 31, 2011
Assets		$	9,483.4		$	51.9		$	(417.3	)		$	9,118.0
Capital expenditures ^(a)		456.6			—			—				456.6


^(a)	Capital expenditures reflect year to date amounts for the periods presented.

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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+ Details

Goodwill	9 Months Ended
Goodwill	Sep. 30, 2012
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	17. GOODWILL Accounting rules require goodwill to be tested for impairment annually and when an event occurs indicating the possibility that an impairment exists. The annual impairment test for the $169.0 million of GMO acquisition goodwill was conducted on September 1, 2012. The goodwill impairment test is a two step process. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill, to identify potential impairment. If the carrying amount exceeds the fair value of the reporting unit, the second step of the test is performed, consisting of assignment of the reporting unit's fair value to its assets and liabilities to determine an implied fair value of goodwill, which is compared to the carrying amount of goodwill to determine the impairment loss, if any, to be recognized in the financial statements. Great Plains Energy's regulated electric utility operations are considered one reporting unit for assessment of impairment, as they are included within the same operating segment and have similar economic characteristics. The determination of fair value of the reporting unit consisted of two valuation techniques: an income approach consisting of a discounted cash flow analysis and a market approach consisting of a determination of reporting unit invested capital using market multiples derived from the historical revenue, EBITDA and net utility asset values and market prices of stock of electric and gas company regulated peers. The results of the two techniques were evaluated and weighted to determine a point within the range that management considered representative of fair value for the reporting unit. Fair value of the reporting unit exceeded the carrying amount, including goodwill; therefore, there was no impairment of goodwill.

Basic and Diluted Earnings per Common Share Calculation

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References+ Details

Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

Organization


•	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 (KCP&L Receivables Company).

•

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

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

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



	Three Months Ended September 30				Year to Date September 30
	2012		2011		2012		2011
Income	(millions, except per share amounts)
Net income	$	146.4	$	126.6	$	195.2	$	172.3
Less: net income attributable to noncontrolling interest	0.2		0.1		—		—
Less: preferred stock dividend requirements	0.4		0.4		1.2		1.2
Earnings available for common shareholders	$	145.8	$	126.1	$	194.0	$	171.1
Common Shares Outstanding
Average number of common shares outstanding	153.2		135.7		142.9		135.6
Add: effect of dilutive securities	0.2		2.6		2.1		2.9
Diluted average number of common shares outstanding	153.4		138.3		145.0		138.5
Basic EPS	$	0.95	$	0.93	$	1.36	$	1.26
Diluted EPS	$	0.95	$	0.91	$	1.34	$	1.24

Anti-dilutive shares excluded from the computation of diluted EPS are detailed in the following table.



	Three Months Ended September 30		Year to Date September 30
	2012	2011	2012	2011
Performance shares	192,723	102,032	209,000	102,032
Restricted stock shares	2,531	22,818	2,531	45,648
Stock options	—	80,140	—	80,140

Disclosure of accounting policy for computing basic and diluted earnings or loss per share for each class of common stock and participating security. Addresses all significant policy factors, including any antidilutive items that have been excluded from the computation and takes into account stock dividends, splits and reverse splits that occur after the balance sheet date of the latest reporting period but before the issuance of the financial statements.

+ References+ Details

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

Basic and diluted earnings per share

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+ Details

Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

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



	Three Months Ended September 30				Year to Date September 30
	2012		2011		2012		2011
Income	(millions, except per share amounts)
Net income	$	146.4	$	126.6	$	195.2	$	172.3
Less: net income attributable to noncontrolling interest	0.2		0.1		—		—
Less: preferred stock dividend requirements	0.4		0.4		1.2		1.2
Earnings available for common shareholders	$	145.8	$	126.1	$	194.0	$	171.1
Common Shares Outstanding
Average number of common shares outstanding	153.2		135.7		142.9		135.6
Add: effect of dilutive securities	0.2		2.6		2.1		2.9
Diluted average number of common shares outstanding	153.4		138.3		145.0		138.5
Basic EPS	$	0.95	$	0.93	$	1.36	$	1.26
Diluted EPS	$	0.95	$	0.91	$	1.34	$	1.24

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]

Anti-dilutive shares excluded from the computation of diluted EPS are detailed in the following table.



	Three Months Ended September 30		Year to Date September 30
	2012	2011	2012	2011
Performance shares	192,723	102,032	209,000	102,032
Restricted stock shares	2,531	22,818	2,531	45,648
Stock options	—	80,140	—	80,140

Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2012

Supplemental Cash Flow Elements [Abstract]

Supplemental cash flow information



Great Plains Energy Other Operating Activities
Year to Date September 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	12.5		$	(41.2	)
Accounts receivable pledged as collateral	(95.0		)	—
Fuel inventories	(5.4		)	12.9
Materials and supplies	(7.8		)	(4.8		)
Accounts payable	(49.4		)	(71.5		)
Accrued taxes	65.4			52.5
Accrued interest	(16.6		)	(6.1		)
Deferred refueling outage costs	13.4			(23.8		)
Fuel adjustment clauses	13.1			(27.3		)
Pension and post-retirement benefit obligations	21.9			22.0
Allowance for equity funds used during construction	(0.3		)	(0.3		)
Interest rate hedge settlements	—			(26.1		)
Iatan Nos. 1 and 2 impact of disallowed construction costs	—			2.3
Uncertain tax positions	(4.4		)	(20.2		)
Other	(14.2		)	(22.7		)
Total other operating activities	$	(66.8	)	$	(154.3	)
Cash paid during the period:
Interest	$	185.4		$	195.1
Income taxes	$	3.3		$	2.4
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	52.2		$	34.8



KCP&L Other Operating Activities
Year to Date September 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	(35.1	)	$	(39.5	)
Accounts receivable pledged as collateral	(15.0		)	—
Fuel inventories	(6.2		)	2.9
Materials and supplies	(6.1		)	(4.3		)
Accounts payable	(18.0		)	(43.2		)
Accrued taxes	76.5			40.3
Accrued interest	9.8			7.9
Deferred refueling outage costs	13.4			(23.8		)
Pension and post-retirement benefit obligations	24.7			32.1
Kansas Energy Cost Adjustment	(0.9		)	(22.0		)
Iatan Nos. 1 and 2 impact of disallowed construction costs	—			1.5
Uncertain tax positions	1.2			(10.1		)
Other	(20.9		)	(16.1		)
Total other operating activities	$	23.4		$	(74.3	)
Cash paid during the period:
Interest	$	77.3		$	74.6
Income taxes	$	—		$	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	48.0		$	30.7

Receivables (Tables)

9 Months Ended

Sep. 30, 2012

Receivables [Abstract]

Schedule of receivables

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



	September 30 2012				December 31 2011
Great Plains Energy		(millions)
Customer accounts receivable - billed		$	27.7			$	69.8
Customer accounts receivable - unbilled		77.8				82.4
Allowance for doubtful accounts		(4.6		)		(2.5		)
Other receivables		117.7				81.5
Total		$	218.6			$	231.2
KCP&L
Customer accounts receivable - billed		$	28.9			$	16.4
Customer accounts receivable - unbilled		50.8				50.0
Allowance for doubtful accounts		(2.5		)		(1.4		)
Intercompany receivables		26.9				38.7
Other receivables		103.0				69.2
Total		$	207.1			$	172.9

Schedule of accounts receivable sold

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



		Three Months Ended September 30, 2012
	KCP&L				KCP&L Receivables Company				Consolidated KCP&L				GMO				GMO Receivables Company				Consolidated Great Plains Energy
		(millions)
Receivables (sold) purchased		$	(472.6	)		$	472.6			$	—			$	(341.7	)		$	341.7			$	—
Gain (loss) on sale of accounts receivable ^(a)		(6.0		)		5.8				(0.2		)		(4.3		)		3.4				(1.1		)
Servicing fees received (paid)		0.8				(0.8		)		—				0.5				(0.5		)		—
Fees paid to outside investor		—				(0.3		)		(0.3		)		—				(0.3		)		(0.6		)
Cash from customers (transferred) received		(466.1		)		466.1				—				(267.8		)		267.8				—
Cash received from (paid for) receivables purchased		460.4				(460.4		)		—				264.4				(264.4		)		—
Interest on intercompany note received (paid)		0.2				(0.2		)		—				0.1				(0.1		)		—



		Year to Date September 30, 2012
	KCP&L				KCP&L Receivables Company				Consolidated KCP&L				GMO				GMO Receivables Company				Consolidated Great Plains Energy
		(millions)
Receivables (sold) purchased		$	(1,134.7	)		$	1,134.7			$	—			$	(433.4	)		$	433.4			$	—
Gain (loss) on sale of accounts receivable ^(a)		(14.4		)		13.9				(0.5		)		(5.5		)		4.2				(1.8		)
Servicing fees received (paid)		1.9				(1.9		)		—				0.6				(0.6		)		—
Fees paid to outside investor		—				(0.9		)		(0.9		)		—				(0.4		)		(1.3		)
Cash from customers (transferred) received		(1,112.7		)		1,112.7				—				(332.5		)		332.5				—
Cash received from (paid for) receivables purchased		1,098.8				(1,098.8		)		—				328.3				(328.3		)		—
Interest on intercompany note received (paid)		0.3				(0.3		)		—				0.1				(0.1		)		—



		Three Months Ended September 30, 2011												Year to Date September 30, 2011
	KCP&L				KCP&L Receivables Company				Consolidated KCP&L				KCP&L				KCP&L Receivables Company				Consolidated KCP&L
		(millions)
Receivables (sold) purchased		$	(468.8	)		$	468.8			$	—			$	(1,108.4	)		$	1,108.4			$	—
Gain (loss) on sale of accounts receivable ^(a)		(5.9		)		5.8				(0.1		)		(14.0		)		13.6				(0.4		)
Servicing fees received (paid)		0.9				(0.9		)		—				2.0				(2.0		)		—
Fees paid to outside investor		—				(0.3		)		(0.3		)		—				(0.9		)		(0.9		)
Cash from customers (transferred) received		(463.4		)		463.4				—				(1,081.6		)		1,081.6				—
Cash received from (paid for) receivables purchased		457.6				(457.6		)		—				1,068.0				(1,068.0		)		—
Interest on intercompany note received (paid)		0.2				(0.2		)		—				0.4				(0.4		)		—

^(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 (Tables)

9 Months Ended

Sep. 30, 2012

Nuclear Plant [Abstract]

Changes in nuclear decommissioning trust fund

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



	September 30 2012			December 31 2011
Decommissioning Trust		(millions)
Beginning balance January 1		$	135.3		$	129.2
Contributions		2.5			3.4
Earned income, net of fees		2.0			4.8
Net realized gains		0.9			0.3
Net unrealized gains (losses)		11.4			(2.4		)
Ending balance		$	152.1		$	135.3

Detail of assets held in nuclear decommissioning trust fund

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



	September 30 2012													December 31 2011
	Cost Basis		Unrealized Gains			Unrealized Losses				Fair Value			Cost Basis			Unrealized Gains			Unrealized Losses				Fair Value
	(millions)
Equity securities	$	79.5		$	20.9		$	(2.5	)		$	97.9		$	76.5		$	12.3		$	(4.5	)		$	84.3
Debt securities	45.9			5.2			—				51.1			44.2			4.5			(0.1		)		48.6
Other	3.1			—			—				3.1			2.4			—			—				2.4
Total	$	128.5		$	26.1		$	(2.5	)		$	152.1		$	123.1		$	16.8		$	(4.6	)		$	135.3

Gains and losses from the sale of securities by the nuclear decommissioning trust fund

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 in the nuclear decommissioning trust fund.



	Three Months Ended September 30						Year to Date September 30
		2012			2011			2012			2011
		(millions)
Realized gains		$	0.5		$	0.2		$	1.2		$	1.0
Realized losses		(0.1		)	—			(0.3		)	(0.7		)

Pension Plans and Other Employee Benefits (Tables)

3 Months Ended

Sep. 30, 2012

Compensation and Retirement Disclosure [Abstract]

Components of net periodic benefit costs

The following tables provide 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 September 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	8.9		$	7.8		$	0.8		$	0.7
Interest cost	12.2			12.4			1.9			2.0
Expected return on plan assets	(10.7		)	(9.5		)	(0.4		)	(0.4		)
Prior service cost	1.1			1.1			1.8			1.8
Recognized net actuarial (gain) loss	11.1			9.7			—			(0.1		)
Transition obligation	—			—			0.3			0.3
Settlement charge	—			10.0			—			—
Net periodic benefit costs before regulatory adjustment	22.6			31.5			4.4			4.3
Regulatory adjustment	(3.9		)	(12.8		)	0.3			0.4
Net periodic benefit costs	$	18.7		$	18.7		$	4.7		$	4.7



	Pension Benefits						Other Benefits
Year to Date September 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	26.6		$	23.4		$	2.4		$	2.3
Interest cost	36.7			37.5			5.8			5.9
Expected return on plan assets	(32.1		)	(28.8		)	(1.3		)	(1.3		)
Prior service cost	3.3			3.4			5.4			5.4
Recognized net actuarial (gain) loss	33.4			28.9			—			(0.4		)
Transition obligation	—			—			0.8			1.0
Settlement charge	—			10.2			—			—
Net periodic benefit costs before regulatory adjustment	67.9			74.6			13.1			12.9
Regulatory adjustment	(11.6		)	(25.1		)	1.0			0.7
Net periodic benefit costs	$	56.3		$	49.5		$	14.1		$	13.6

Equity Compensation (Tables)

9 Months Ended

Sep. 30, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity compensation expense and associated income tax benefits

The following table summarizes Great Plains Energy's and KCP&L's equity compensation expense and the associated income tax benefit.



	Three Months Ended September 30				Year to Date September 30
	2012		2011		2012		2011
Great Plains Energy	(millions)
Compensation expense	$	1.2	$	1.2	$	4.0	$	4.5
Income tax benefit	0.4		0.4		1.7		1.8
KCP&L
Compensation expense	$	0.8	$	0.8	$	2.9	$	3.1
Income tax benefit	0.3		0.2		1.3		1.2

Performance share activity

Performance adjustment represents the number of shares of common stock related to performance shares ultimately issued that can vary from the number of performance shares initially granted depending on Great Plains Energy's performance over a stated period of time.



	Performance Shares			Grant Date Fair Value*
Beginning balance		442,042			$	21.06
Granted		164,158			19.02
Forfeited		(74,923	)		20.06
Performance adjustment		(160,717	)
Ending balance		370,560			22.97

* weighted-average

Restricted stock activity

Restricted stock activity year to date September 30, 2012, is summarized in the following table.



	Nonvested Restricted Stock			Grant Date Fair Value*
Beginning balance		386,183			$	17.06
Granted and issued		164,660			19.73
Vested		(206,838	)		15.78
Forfeited		(67,816	)		19.49
Ending balance		276,189			19.01

* weighted-average

Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Long-term debt

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



	Year Due	September 30 2012				December 31 2011
KCP&L			(millions)
General Mortgage Bonds
4.97% EIRR bonds^(a)	2015-2035		$	106.9			$	119.3
7.15% Series 2009A (8.59% rate)^(b)	2019		400.0				400.0
4.65% EIRR Series 2005	2035		50.0				50.0
5.375% EIRR Series 2007B	2035		73.2				73.2
Senior Notes
5.85% Series (5.72% rate)^(b)	2017		250.0				250.0
6.375% Series (7.49% rate)^(b)	2018		350.0				350.0
6.05% Series (5.78% rate)^(b)	2035		250.0				250.0
5.30% Series	2041		400.0				400.0
EIRR bonds 4.90% Series 2008	2038		23.4				23.4
Other	2013-2018		2.6				2.9
Current maturities			(0.4		)		(12.7		)
Unamortized discount			(4.1		)		(4.2		)
Total KCP&L excluding current maturities^(c)			1,901.6				1,901.9
Other Great Plains Energy
GMO First Mortgage Bonds 9.44% Series	2013-2021		10.1				11.2
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6				5.6
0.318% Wamego Series 1996^(d)	2026		7.3				7.3
0.316% State Environmental 1993^(d)	2028		5.0				5.0
GMO Senior Notes
11.875% Series	2012		—				500.0
8.27% Series	2021		80.9				80.9
Fair Value Adjustment			—				16.3
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)^(b)	2013		250.0				250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)^(b)	2017		100.0				100.0
Great Plains Energy 4.85% Senior Notes (7.34% rate)^(b)	2021		350.0				350.0
Great Plains Energy 5.292% Senior Notes	2022		287.5				—
Great Plains Energy 10.00% Equity Units Subordinated Notes			—				287.5
Current maturities			(256.7		)		(788.7		)
Unamortized discount and premium, net			5.6				(0.7		)
Total Great Plains Energy excluding current maturities^(c)			$	2,762.9			$	2,742.3


^(a)	Weighted-average interest rates at September 30, 2012


^(b)	Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments


^(c)	Does not include $39.5 million EIRR Series 1993B, $63.3 million EIRR Series 2007 A-1 and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L


^(d)	Variable rate

Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Values of open positions for derivative instruments



	September 30 2012					December 31 2011
	Notional Contract Amount		Fair Value			Notional Contract Amount		Fair Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	1.0	$	(0.2	)	$	2.0	$	(0.5	)
Non-hedging derivatives	16.3		(1.9		)	23.6		(5.0		)
Forward contracts
Non-hedging derivatives	70.3		6.8			97.3		7.8
Option contracts
Non-hedging derivatives	—		—			0.4		—
KCP&L
Futures contracts
Cash flow hedges	$	1.0	$	(0.2	)	$	2.0	$	(0.5	)

Fair value of open derivative positions, gross values before netting agreements and netting of cash collatral



Great Plains Energy
	Balance Sheet	Asset Derivatives			Liability Derivatives
September 30, 2012	Classification	Fair Value			Fair Value
Derivatives Designated as Hedging Instruments			(millions)
Commodity contracts	Derivative instruments		$	—		$	0.2
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.2			2.3
Total Derivatives			$	7.2		$	2.5

December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments		$	—		$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.8			5.0
Total Derivatives			$	7.8		$	5.5

KCP&L

Balance Sheet

Asset Derivatives

Liability Derivatives

September 30, 2012

Classification

Fair Value

Derivatives Designated as Hedging Instruments

(millions)

Commodity contracts

Derivative instruments

—

0.2

December 31, 2011

Derivatives Designated as Hedging Instruments

Commodity contracts

Derivative instruments

—

0.5

Gain (loss) recognized in other comprehensive income or earnings for interest rate and commodity hedges

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 (Effective Portion)				Income Statement Classification	Amount
Three Months Ended September 30, 2012	(millions)					(millions)
Interest rate contracts		$	—		Interest charges	$	(5.0	)
Commodity contracts		0.1			Fuel	(0.5		)
Income tax expense		(0.1		)	Income tax benefit	2.1
Total		$	—		Total	$	(3.4	)
Year to Date September 30, 2012
Interest rate contracts		$	—		Interest charges	$	(15.1	)
Commodity contracts		(0.1		)	Fuel	(0.5		)
Income tax benefit		—			Income tax benefit	6.0
Total		$	(0.1	)	Total	$	(9.6	)
Three Months Ended September 30, 2011
Interest rate contracts		$	—		Interest charges	$	(5.1	)
Commodity contracts		(0.1		)	Fuel	(0.1		)
Income tax benefit		0.1			Income tax benefit	2.1
Total		$	—		Total	$	(3.1	)
Year to Date September 30, 2011
Interest rate contracts		$	(5.3	)	Interest charges	$	(11.9	)
Commodity contracts		(0.2		)	Fuel	(0.1		)
Income tax benefit		2.2			Income tax benefit	4.7
Total		$	(3.3	)	Total	$	(7.3	)



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 (Effective Portion)				Income Statement Classification	Amount
Three Months Ended September 30, 2012	(millions)					(millions)
Interest rate contracts		$	—		Interest charges	$	(2.2	)
Commodity contracts		0.1			Fuel	(0.5		)
Income tax expense		(0.1		)	Income tax benefit	1.0
Total		$	—		Total	$	(1.7	)
Year to Date September 30, 2012
Interest rate contracts		$	—		Interest charges	$	(6.6	)
Commodity contracts		(0.1		)	Fuel	(0.5		)
Income tax benefit		—			Income tax benefit	2.7
Total		$	(0.1	)	Total	$	(4.4	)
Three Months Ended September 30, 2011
Interest rate contracts		$	—		Interest charges	$	(2.1	)
Commodity contracts		(0.1		)	Fuel	(0.1		)
Income tax benefit		0.1			Income tax benefit	0.9
Total		$	—		Total	$	(1.3	)
Year to Date September 30, 2011
Interest rate contracts		$	—		Interest charges	$	(6.5	)
Commodity contracts		(0.2		)	Fuel	(0.1		)
Income tax benefit		0.1			Income tax benefit	2.6
Total		$	(0.1	)	Total	$	(4.0	)

Gain (loss) recognized in a regulatory balance sheet account or earnings for utility commodity hedges



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 Classification	Amount
Three Months Ended September 30, 2012	(millions)					(millions)
Commodity contracts		$	0.9		Fuel	$	(2.8	)
Total		$	0.9		Total	$	(2.8	)
Year to Date September 30, 2012
Commodity contracts		$	(1.8	)	Fuel	$	(5.5	)
Total		$	(1.8	)	Total	$	(5.5	)
Three Months Ended September 30, 2011
Commodity contracts		$	(2.2	)	Fuel	$	(0.6	)
Total		$	(2.2	)	Total	$	(0.6	)
Year to Date September 30, 2011
Commodity contracts		$	(3.5	)	Fuel	$	(3.5	)
Total		$	(3.5	)	Total	$	(3.5	)

Accumulated other comprehensive income related to cash flow hedges

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



	Great Plains Energy								KCP&L
	September 30 2012				December 31 2011				September 30 2012				December 31 2011
		(millions)
Current assets		$	10.8			$	11.3			$	10.8			$	11.3
Current liabilities		(73.6		)		(89.5		)		(55.1		)		(62.5		)
Noncurrent liabilities		(0.1		)		(0.2		)		(0.1		)		(0.2		)
Deferred income taxes		24.5				30.5				17.3				20.0
Total		$	(38.4	)		$	(47.9	)		$	(27.1	)		$	(31.4	)

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

+ References+ Details

Tabular disclosure of the location and fair value amounts of derivative instruments (and nonderivative instruments that are designated and qualify as hedging instruments) reported in the statement of financial position.

+ References+ Details

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

Fair value of assets and liabilities

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+ Details

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

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 September 30, 2012, and December 31, 2011.



								Fair Value Measurements Using
Description	September 30 2012			Netting^(d)				Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
KCP&L		(millions)
Assets
Nuclear decommissioning trust ^(b)
Equity securities		$	97.9		$	—			$	97.9		$	—		$	—
Debt securities
U.S. Treasury		18.6			—				18.6			—			—
U.S. Agency		2.8			—				—			2.8			—
State and local obligations		2.7			—				—			2.7			—
Corporate bonds		26.4			—				—			26.4			—
Foreign governments		0.6			—				—			0.6			—
Other		0.2			—				—			0.2			—
Total nuclear decommissioning trust		149.2			—				116.5			32.7			—
Total		149.2			—				116.5			32.7			—
Liabilities
Derivative instruments ^(a)		—			(0.2		)		0.2			—			—
Total		$	—		$	(0.2	)		$	0.2		$	—		$	—
Other Great Plains Energy
Assets
Derivative instruments ^(a)		$	6.8		$	(0.4	)		$	0.4		$	4.4		$	2.4
SERP rabbi trust ^(c)
Equity securities		0.1			—				0.1			—			—
Debt securities		0.1			—				—			0.1			—
Total SERP rabbi trust		0.2			—				0.1			0.1			—
Total		7.0			(0.4		)		0.5			4.5			2.4
Liabilities
Derivative instruments ^(a)		—			(2.3		)		2.3			—			—
Total		$	—		$	(2.3	)		$	2.3		$	—		$	—
Great Plains Energy
Assets
Derivative instruments ^(a)		$	6.8		$	(0.4	)		$	0.4		$	4.4		$	2.4
Nuclear decommissioning trust ^(b)		149.2			—				116.5			32.7			—
SERP rabbi trust ^(c)		0.2			—				0.1			0.1			—
Total		156.2			(0.4		)		117.0			37.2			2.4
Liabilities
Derivative instruments ^(a)		—			(2.5		)		2.5			—			—
Total		$	—		$	(2.5	)		$	2.5		$	—		$	—



									Fair Value Measurements Using
Description	December 31 2011				Netting^(d)				Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
KCP&L		(millions)
Assets
Nuclear decommissioning trust ^(b)
Equity securities		$	84.3			$	—			$	84.3		$	—			$	—
Debt securities
U.S. Treasury		15.3				—				15.3			—				—
U.S. Agency		3.6				—				—			3.6				—
State and local obligations		2.6				—				—			2.6				—
Corporate bonds		26.4				—				—			26.4				—
Foreign governments		0.7				—				—			0.7				—
Other		(0.6		)		—				—			(0.6		)		—
Total nuclear decommissioning trust		132.3				—				99.6			32.7				—
Total		132.3				—				99.6			32.7				—
Liabilities
Derivative instruments ^(a)		—				(0.5		)		0.5			—				—
Total		$	—			$	(0.5	)		$	0.5		$	—			$	—
Other Great Plains Energy
Assets
Derivative instruments ^(a)		$	7.8			$	—			$	—		$	4.7			$	3.1
SERP rabbi trust ^(c)
Equity securities		0.2				—				0.2			—				—
Debt securities		0.1				—				—			0.1				—
Total SERP rabbi trust		0.3				—				0.2			0.1				—
Total		8.1				—				0.2			4.8				3.1
Liabilities
Derivative instruments ^(a)		—				(5.0		)		5.0			—				—
Total		$	—			$	(5.0	)		$	5.0		$	—			$	—
Great Plains Energy
Assets
Derivative instruments ^(a)		$	7.8			$	—			$	—		$	4.7			$	3.1
Nuclear decommissioning trust ^(b)		132.3				—				99.6			32.7				—
SERP rabbi trust ^(c)		0.3				—				0.2			0.1				—
Total		140.4				—				99.8			37.5				3.1
Liabilities
Derivative instruments ^(a)		—				(5.5		)		5.5			—				—
Total		$	—			$	(5.5	)		$	5.5		$	—			$	—


(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 $2.9 million and $3.0 million at September 30, 2012, and December 31, 2011, 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 $20.3 million at September 30, 2012, and December 31, 2011, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)

Unobservable inputs reconciliation



Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative Instruments
	(millions)
Balance at July 1	$	2.2		$	4.9
Total realized/unrealized gains included in non-operating income	3.7			4.0
Settlements	(3.5		)	(4.4		)
Balance at September 30	$	2.4		$	4.5
Total unrealized gains and (losses) included in non-operating income relating to assets
and liabilities still on the consolidated balance sheet at September 30	$	0.3		$	(0.3	)



Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative Instruments
	(millions)
Balance at January 1	$	3.1		$	3.7
Total realized/unrealized gains included in non-operating income	4.8			11.1
Settlements	(5.5		)	(10.3		)
Balance at September 30	$	2.4		$	4.5
Total unrealized gains and (losses) included in non-operating income relating to assets
and liabilities still on the consolidated balance sheet at September 30	$	(0.4	)	$	1.2

Components of income tax expense (benefit)

Tabular disclosure of the fair value measurement of assets using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets) and gains or losses recognized in other comprehensive income (loss), and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issues, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs), by class of asset.

+ References+ Details

Taxes (Tables)

9 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

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



	Three Months Ended September 30						Year to Date September 30
Great Plains Energy	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	(1.4	)	$	(10.2	)	$	(4.7	)	$	(6.4	)
State	(0.3		)	(0.8		)	—			(4.8		)
Foreign	—			—			—			(0.4		)
Total	(1.7		)	(11.0		)	(4.7		)	(11.6		)
Deferred income taxes
Federal	75.1			74.7			97.6			103.6
State	13.9			13.0			18.2			20.4
Total	89.0			87.7			115.8			124.0
Noncurrent income taxes
Federal	—			—			(0.2		)	(18.0		)
State	—			—			—			(1.9		)
Foreign	(4.1		)	(0.6		)	(4.2		)	(0.4		)
Total	(4.1		)	(0.6		)	(4.4		)	(20.3		)
Investment tax credit amortization	(0.6		)	(0.7		)	(1.8		)	(1.5		)
Income tax expense	$	82.6		$	75.4		$	104.9		$	90.6



	Three Months Ended September 30						Year to Date September 30
KCP&L	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	22.9		$	(10.2	)	$	23.1		$	(7.8	)
State	4.1			(0.9		)	4.2			(0.4		)
Total	27.0			(11.1		)	27.3			(8.2		)
Deferred income taxes
Federal	22.7			53.5			38.8			73.4
State	4.5			9.3			8.6			13.8
Total	27.2			62.8			47.4			87.2
Noncurrent income taxes
Federal	1.0			1.5			1.1			(9.1		)
State	0.2			0.1			0.2			(1.0		)
Total	1.2			1.6			1.3			(10.1		)
Investment tax credit amortization	(0.5		)	(0.5		)	(1.4		)	(1.0		)
Income tax expense	$	54.9		$	52.8		$	74.6		$	67.9

Income tax expense (benefit) and effective income tax rates

Income Tax Expense and Effective Income Tax Rates



Great Plains Energy	Income Tax Expense						Income Tax Rate
Three Months Ended September 30	2012			2011			2012		2011
	(millions)
Federal statutory income tax	$	80.0		$	70.6		35.0	%	35.0	%
Differences between book and tax depreciation not
normalized	1.3			1.8			0.5		0.9
Amortization of investment tax credits	(0.6		)	(0.7		)	(0.3	)	(0.3	)
Federal income tax credits	(2.2		)	(2.9		)	(1.0	)	(1.4	)
State income taxes	8.8			8.1			3.8		4.0
Changes in uncertain tax positions, net	(4.1		)	(2.7		)	(1.8	)	(1.3	)
Other	(0.6		)	1.2			(0.1	)	0.4
Total	$	82.6		$	75.4		36.1	%	37.3	%



Great Plains Energy	Income Tax Expense						Income Tax Rate
Year to Date September 30	2012			2011			2012		2011
	(millions)
Federal statutory income tax	$	105.0		$	92.0		35.0	%	35.0	%
Differences between book and tax depreciation not
normalized	3.4			3.7			1.1		1.4
Amortization of investment tax credits	(1.8		)	(1.5		)	(0.6	)	(0.6	)
Federal income tax credits	(8.3		)	(9.7		)	(2.8	)	(3.7	)
State income taxes	11.7			11.1			3.9		4.2
Changes in uncertain tax positions, net	(4.2		)	(4.0		)	(1.4	)	(1.5	)
Valuation allowance	0.1			(2.2		)	—		(0.8	)
Other	(1.0		)	1.2			(0.3	)	0.5
Total	$	104.9		$	90.6		34.9	%	34.5	%



KCP&L	Income Tax Expense						Income Tax Rate
Three Months Ended September 30	2012			2011			2012		2011
	(millions)
Federal statutory income tax	$	50.8		$	48.3		35.0	%	35.0	%
Differences between book and tax depreciation not
normalized	1.0			1.7			0.7		1.2
Amortization of investment tax credits	(0.5		)	(0.5		)	(0.3	)	(0.4	)
Federal income tax credits	(2.2		)	(2.9		)	(1.5	)	(2.1	)
State income taxes	5.8			5.7			3.9		4.1
Other	—			0.5			—		0.4
Total	$	54.9		$	52.8		37.8	%	38.2	%



KCP&L	Income Tax Expense						Income Tax Rate
Year to Date September 30	2012			2011			2012		2011
	(millions)
Federal statutory income tax	$	73.8		$	66.7		35.0	%	35.0	%
Differences between book and tax depreciation not
normalized	2.8			3.3			1.3		1.7
Amortization of investment tax credits	(1.4		)	(1.0		)	(0.6	)	(0.5	)
Federal income tax credits	(8.3		)	(9.6		)	(4.0	)	(5.1	)
State income taxes	8.4			7.7			4.0		4.0
Changes in uncertain tax positions, net	—			0.4			—		0.2
Other	(0.7		)	0.4			(0.3	)	0.3
Total	$	74.6		$	67.9		35.4	%	35.6	%

Summary of Income Tax Contingencies [Table Text Block]

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
	September 30 2012				December 31 2011				September 30 2012				December 31 2011
		(millions)
Beginning balance January 1		$	24.0			$	42.0			$	8.7			$	19.1
Additions for current year tax positions		2.8				1.4				2.7				—
Additions for prior year tax positions		—				2.4				—				2.3
Reductions for prior year tax positions		(6.1		)		(20.9		)		(1.5		)		(12.6		)
Statute expirations		—				(0.7		)		—				(0.1		)
Foreign currency translation adjustments		0.3				(0.2		)		—				—
Ending balance		$	21.0			$	24.0			$	9.9			$	8.7

Segment financial information

Tabular disclosure of tax positions taken in the tax returns filed or to be filed for which it is more likely than not that the tax position will not be sustained upon examination by taxing authorities (i.e., uncertain tax positions) and other types of income tax contingencies, including: (1) the policy on classification of interest and penalties; (2) a tabular reconciliation of the total amounts of unrecognized tax benefits at the beginning and end of the period; the total amount(s) of: (3) unrecognized tax benefits that, if recognized, would affect the effective tax rate, and (4) interest and penalties recognized in each of the income statement and balance sheet; (5) for positions for which it is reasonably possible that the total amounts unrecognized will significantly change within 12 months of the reporting date the: (i) nature of the uncertainty, (ii) nature of the event that could occur that would cause the change, and (iii) an estimate of the range of the reasonably possible change or a statement that an estimate of the range cannot be made; and (6) a description of tax years that remain subject to examination by major tax jurisdictions.

+ References+ Details

Segments and Related Information (Tables)

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

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



Three Months Ended September 30, 2012	Electric Utility				Other			Great Plains Energy
		(millions)
Operating revenues		$	746.2			$	—		$	746.2
Depreciation and amortization		(68.9		)		—			(68.9		)
Interest (charges) income		(48.4		)		0.3			(48.1		)
Income tax (expense) benefit		(86.5		)		3.9			(82.6		)
Net income attributable to Great Plains Energy		141.9				4.3			146.2



Year to Date September 30, 2012	Electric Utility				Other				Great Plains Energy
		(millions)
Operating revenues		$	1,829.5			$	—			$	1,829.5
Depreciation and amortization		(204.2		)		—				(204.2		)
Interest charges		(149.5		)		(21.3		)		(170.8		)
Income tax (expense) benefit		(120.6		)		15.7				(104.9		)
Net income (loss) attributable to Great Plains Energy		210.2				(15.0		)		195.2



Three Months Ended September 30, 2011	Electric Utility				Other				Great Plains Energy
		(millions)
Operating revenues		$	773.7			$	—			$	773.7
Depreciation and amortization		(65.9		)		—				(65.9		)
Interest charges		(50.2		)		(10.6		)		(60.8		)
Income tax (expense) benefit		(82.9		)		7.5				(75.4		)
Net income (loss) attributable to Great Plains Energy		133.9				(7.4		)		126.5



Year to Date September 30, 2011	Electric Utility				Other				Great Plains Energy
		(millions)
Operating revenues		$	1,831.7			$	—			$	1,831.7
Depreciation and amortization		(205.9		)		—				(205.9		)
Interest charges		(124.8		)		(31.2		)		(156.0		)
Income tax (expense) benefit		(109.8		)		19.2				(90.6		)
Net income (loss) attributable to Great Plains Energy		189.9				(17.6		)		172.3



	Electric Utility			Other			Eliminations				Great Plains Energy
September 30, 2012		(millions)
Assets		$	9,765.3		$	152.5		$	(415.4	)		$	9,502.4
Capital expenditures ^(a)		409.5			—			—				409.5
December 31, 2011
Assets		$	9,483.4		$	51.9		$	(417.3	)		$	9,118.0
Capital expenditures ^(a)		456.6			—			—				456.6


^(a)	Capital expenditures reflect year to date amounts for the periods presented.

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References+ Details

Summary of Significant Accounting Policies Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Income [Abstract]
Net income	$ 146.4	$ 126.6	$ 195.2	$ 172.3
Less: net income attributable to noncontrolling interest	0.2	0.1	0	0
Less: preferred stock dividend requirements	0.4	0.4	1.2	1.2
Net Income (Loss) Available to Common Stockholders, Basic	$ 145.8	$ 126.1	$ 194.0	$ 171.1
Common Shares Outstanding [Abstract]
Average number of common shares outstanding (in shares)	153.2	135.7	142.9	135.6
Add: effect of dilutive securities (in shares)	0.2	2.6	2.1	2.9
Diluted average number of common shares outstanding (in shares)	153.4	138.3	145.0	138.5
Earnings per share [Abstract]
Earnings Per Share, Basic	$ 0.95	$ 0.93	$ 1.36	$ 1.26
Earnings Per Share, Diluted	$ 0.95	$ 0.91	$ 1.34	$ 1.24

Summary of Significant Accounting Policies Antidilutive Securities (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Performance Shares [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	192,723	102,032	209,000	102,032
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2,531	22,818	2,531	45,648
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	80,140	0	80,140

Securities (including those issuable pursuant to contingent stock agreements) that could potentially dilute basic earnings per share (EPS) or earnings per unit (EPU) in the future that were not included in the computation of diluted EPS or EPU because to do so would increase EPS or EPU amounts or decrease loss per share or unit amounts for the period presented.

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

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Antidilution

-URI http://asc.fasb.org/extlink&oid=6505113

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

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Diluted Earnings Per Share

-URI http://asc.fasb.org/extlink&oid=6510752

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

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Contingent Stock Agreement

-URI http://asc.fasb.org/extlink&oid=6508534

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 260

-SubTopic 10

-Section 50

-Paragraph 1

-Subparagraph (c)

-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 40

-Subparagraph c

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 13, 14

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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

-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 07-4

-Paragraph 4

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 171

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Summary of Significant Accounting Policies Subsequent Events (Details) (Dividend Declared [Member], USD $) In Millions, except Per Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Dividends Declared [Abstract]
Subsequent Event, Date	Nov. 01, 2012
Subsequent Event Description	Great Plains Energy’s Board of Directors declared a quarterly dividend on common stock and also declared regular dividends on Great Plains Energys preferred stock.
Subsequent per common share amount (in dollars per share)	$ 0.2175
Kansas City Power and Light Company [Member]
Dividends Declared [Abstract]
Subsequent Event, Date	Nov. 01, 2012
Subsequent Event Amount	$ 23
Subsequent Event Description	KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy

Describes the event or transaction that occurred between the balance sheet date and the date the financial statements are issued or available to be issued.

+ References+ Details

Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash flows affected by changes in:
Receivables	$ 12.5	$ (41.2)
Accounts receivable pledged as collateral	(95.0)	0
Fuel inventories	(5.4)	12.9
Materials and supplies	(7.8)	(4.8)
Accounts payable	(49.4)	(71.5)
Accrued taxes	65.4	52.5
Accrued interest	(16.6)	(6.1)
Deferred refueling outage costs	13.4	(23.8)
Fuel adjustment clauses	13.1	(27.3)
Pension and post-retirement benefit obligations	21.9	22.0
Increase (Decrease) in Allowance for Equity Funds Used During Construction	(0.3)	(0.3)
Forward starting swaps settlement	0	(26.1)
Iatan Nos. 1 and 2 impact of disallowed construction costs	0	2.3
Uncertain tax positions	(4.4)	(20.2)
Other Operating Activities, Cash Flow Statement	(14.2)	(22.7)
Total other operating activities	(66.8)	(154.3)
Cash paid during the period:
Interest Paid, Net	185.4	195.1
Income Taxes Paid	3.3	2.4
Non-cash investing activities:
Liabilities assumed for capital expenditures	52.2	34.8
Kansas City Power and Light Company [Member]
Cash flows affected by changes in:
Receivables	(35.1)	(39.5)
Accounts receivable pledged as collateral	(15.0)	0
Fuel inventories	(6.2)	2.9
Materials and supplies	(6.1)	(4.3)
Accounts payable	(18.0)	(43.2)
Accrued taxes	76.5	40.3
Accrued interest	9.8	7.9
Deferred refueling outage costs	13.4	(23.8)
Fuel adjustment clauses	(0.9)	(22.0)
Pension and post-retirement benefit obligations	24.7	32.1
Iatan Nos. 1 and 2 impact of disallowed construction costs	0	1.5
Uncertain tax positions	1.2	(10.1)
Other Operating Activities, Cash Flow Statement	(20.9)	(16.1)
Total other operating activities	23.4	(74.3)
Cash paid during the period:
Interest Paid, Net	77.3	74.6
Income Taxes Paid	0	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$ 48.0	$ 30.7

Receivables Accounts, Notes, and Financing (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (4.6)	$ (2.5)
Other Receivables, Gross, Current	117.7	81.5
Receivables, net	218.6	231.2
Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	(2.5)	(1.4)
Other Receivables, Gross, Current	103.0	69.2
Receivables, net	207.1	172.9
Trade Accounts Receivable [Member] \| Billed Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	27.7	69.8
Trade Accounts Receivable [Member] \| Billed Revenues [Member] \| Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	28.9	16.4
Trade Accounts Receivable [Member] \| Unbilled Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	77.8	82.4
Trade Accounts Receivable [Member] \| Unbilled Revenues [Member] \| Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	50.8	50.0
Intercompany Receivables [Member] \| Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	$ 26.9	$ 38.7

Receivables Narrative (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Transfers Accounted for as Secured Borrowings, Assets, Carrying Amount	$ 190.0	$ 95.0
Kansas City Power and Light Company [Member]
Transfers Accounted for as Secured Borrowings, Assets, Carrying Amount	110.0	95.0
Maximum percentage servicing fee received on receivables sold (in hundredths)	1.50%
Maximum amount of outstanding principal under receivables agreement	110
KCPL Greater Missouri Operations [Member]
Maximum percentage servicing fee received on receivables sold (in hundredths)	1.25%
Maximum amount of outstanding principal under receivables agreement from June 1 to October 31 of each year	80
Maximum amount of outstanding principal under receivables agreement from November 1 to May 31 of each year	$ 65

Receivables (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

$ 0

(1.1)

^[1]

(1.8)

^[1]

Cash from customers (transferred to) received from Receivables Company

(0.6)

(1.3)

Cash received from (paid to) for receivables purchased

GMO Receivables Company Member

341.7

433.4

3.4

^[1]

4.2

^[1]

(0.5)

(0.6)

Cash from customers (transferred to) received from Receivables Company

(0.3)

(0.4)

267.8

332.5

Cash received from (paid to) for receivables purchased

(264.4)

(328.3)

(0.1)

Kansas City Power and Light Company [Member]

(0.2)

^[1]

(0.1)

^[1]

(0.5)

^[1]

(0.4)

^[1]

Cash from customers (transferred to) received from Receivables Company

(0.3)

(0.9)

Cash received from (paid to) for receivables purchased

Kansas City Power And Light Company Unconsolidated [Member]

(472.6)

(468.8)

(1,134.7)

(1,108.4)

(6.0)

^[1]

(5.9)

^[1]

(14.4)

^[1]

(14.0)

^[1]

0.8

0.9

1.9

2.0

Cash from customers (transferred to) received from Receivables Company

(466.1)

(463.4)

(1,112.7)

(1,081.6)

Cash received from (paid to) for receivables purchased

460.4

457.6

1,098.8

1,068.0

0.2

0.3

0.4

KCPL Receivables Company [Member]

472.6

468.8

1,134.7

1,108.4

5.8

^[1]

5.8

^[1]

13.9

^[1]

13.6

^[1]

(0.8)

(0.9)

(1.9)

(2.0)

Cash from customers (transferred to) received from Receivables Company

(0.3)

(0.9)

466.1

463.4

1,112.7

1,081.6

Cash received from (paid to) for receivables purchased

(460.4)

(457.6)

(1,098.8)

(1,068.0)

(0.2)

(0.3)

(0.4)

KCPL Greater Missouri Operations [Member]

(341.7)

(433.4)

(4.3)

^[1]

(5.5)

^[1]

0.5

0.6

Cash from customers (transferred to) received from Receivables Company

(267.8)

(332.5)

Cash received from (paid to) for receivables purchased

264.4

328.3

$ 0.1

[1]	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.

All amounts that are due to the servicer of a financial asset, excluding contractually specified servicing fees and late fees.

+ References+ Details

Nuclear Plant (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Dec. 31, 2010
Investments in decommissioning trust fund [Line Items]
Cost Basis	$ 128.5		$ 128.5		$ 123.1
Gross Unrealized Gains	26.1		26.1		16.8
Gross Unrealized Losses	(2.5)		(2.5)		(4.6)
Fair Value, Nuclear decommissioning trust fund	152.1		152.1		135.3	129.2
Weighted average maturity of debt securities	7		7
Realized Gains on investments in decommissioning trust fund	0.5	0.2	1.2	1.0
Realized Losses on investments in decommissioning trust fund	(0.1)	0	(0.3)	(0.7)
Equity Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	79.5		79.5		76.5
Gross Unrealized Gains	20.9		20.9		12.3
Gross Unrealized Losses	(2.5)		(2.5)		(4.5)
Fair Value, Nuclear decommissioning trust fund	97.9		97.9		84.3
Debt Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	45.9		45.9		44.2
Gross Unrealized Gains	5.2		5.2		4.5
Gross Unrealized Losses	0		0		(0.1)
Fair Value, Nuclear decommissioning trust fund	51.1		51.1		48.6
Other Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	3.1		3.1		2.4
Gross Unrealized Gains	0		0		0
Gross Unrealized Losses	0		0		0
Fair Value, Nuclear decommissioning trust fund	3.1		3.1		2.4
Kansas City Power and Light Company [Member]
Investments in decommissioning trust fund [Line Items]
Fair Value, Nuclear decommissioning trust fund	$ 152.1		$ 152.1		$ 135.3

This item represents the cost of debt and equity securities, which are categorized neither as held-to-maturity nor trading, net of adjustments including accretion, amortization, collection of cash, previous other-than-temporary impairments recognized in earnings (less any cumulative-effect adjustments recognized, as defined), and fair value hedge accounting adjustments, if any.

+ References+ Details

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

This item represents the gross unrealized gains for securities, at a point in time, which are categorized neither as held-to-maturity nor trading securities.

+ References+ Details

Nuclear Plant Decommissioning Trust (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Nuclear decommissioning trust fund [Roll Forward]
Nuclear decommissioning trust fund, beginning balance	$ 135.3	$ 129.2
Contributions to nuclear decommission trust fund	2.5	3.4
Nuclear decommissioning trust fund earned income, net of fees	2.0	4.8
Net realized gains (losses) on nuclear decommissioning trust fund	0.9	0.3
Net unrealized gains (losses) on nuclear decommissioning trust fund	11.4	(2.4)
Nuclear decommissioning trust fund, ending balance	152.1	135.3
Kansas City Power and Light Company [Member]
Nuclear decommissioning trust fund [Roll Forward]
Nuclear decommissioning trust fund, ending balance	$ 152.1	$ 135.3

Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012
Kansas City Power and Light Company [Member]
Regulatory Proceedings [Line Items]
Qualifying advance coal project tax credits to be reallocated from KCPL to GMO	$ 26.5
Kansas City Power and Light Company [Member] \| Rate jurisdiction - Kansas [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase	63.6
Revised annual revenue increase	56.4
Return on equity (in hundredths)	10.40%
Revised return on equity (in hundredths)	10.30%
Rate-making equity ratio (in hundredths)	51.80%
Annual revenue increase recommended by KCC staff	27.5
Return on equity (in hundredths) recommended by KCC staff	9.20%
Kansas City Power and Light Company [Member] \| Rate jurisdiction - Missouri [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase	105.7
Return on equity (in hundredths)	10.40%
Revised return on equity (in hundredths)	10.30%
Rate-making equity ratio (in hundredths)	52.50%
Wholesale Margin Offset	45.9
Annual revenue increase (decrease) recommended by MPSC staff, minimum	16.5
Annual revenue increase (decrease) recommended by MPSC staff, maximum	33.7
Return on equity (in hundredths) recommended by MPSC staff, minimum	8.00%
Return on equity (in hundredths) recommended by MPSC staff, maximum	9.00%
KCPL Greater Missouri Operations [Member]
Regulatory Proceedings [Line Items]
Amount of FAC refund recommended by MPSC staff	19
Revised amount of FAC refund recommended by MPSC staff	14.9
KCPL Greater Missouri Operations [Member] \| Rate jurisdiction - St. Joseph Light and Power division [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase	25.2
Return on equity (in hundredths)	10.40%
Revised return on equity (in hundredths)	10.30%
Rate-making equity ratio (in hundredths)	52.50%
Annual revenue increase (decrease) recommended by MPSC staff, minimum	0.7
Annual revenue increase (decrease) recommended by MPSC staff, maximum	4.6
Return on equity (in hundredths) recommended by MPSC staff, minimum	8.00%
Return on equity (in hundredths) recommended by MPSC staff, maximum	9.00%
KCPL Greater Missouri Operations [Member] \| Rate jurisdiction - Missouri Public Service division [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase	58.3
Return on equity (in hundredths)	10.40%
Revised return on equity (in hundredths)	10.30%
Rate-making equity ratio (in hundredths)	52.50%
Annual revenue increase (decrease) recommended by MPSC staff, minimum	0.4
Annual revenue increase (decrease) recommended by MPSC staff, maximum	$ 11.9
Return on equity (in hundredths) recommended by MPSC staff, minimum	8.00%
Return on equity (in hundredths) recommended by MPSC staff, maximum	9.00%

Pension Plans and Other Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$ 8.9	$ 7.8	$ 26.6	$ 23.4
Interest cost	12.2	12.4	36.7	37.5
Expected return on plan assets	(10.7)	(9.5)	(32.1)	(28.8)
Prior service cost	1.1	1.1	3.3	3.4
Recognized net actuarial (gain) loss	11.1	9.7	33.4	28.9
Transition obligation	0	0	0	0
Settlement charge	0	10.0	0	10.2
Net period benefit costs before regulatory adjustment	22.6	31.5	67.9	74.6
Regulatory adjustment	(3.9)	(12.8)	(11.6)	(25.1)
Net periodic benefit costs	18.7	18.7	56.3	49.5
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0.8	0.7	2.4	2.3
Interest cost	1.9	2.0	5.8	5.9
Expected return on plan assets	(0.4)	(0.4)	(1.3)	(1.3)
Prior service cost	1.8	1.8	5.4	5.4
Recognized net actuarial (gain) loss	0	(0.1)	0	(0.4)
Transition obligation	0.3	0.3	0.8	1.0
Settlement charge	0	0	0	0
Net period benefit costs before regulatory adjustment	4.4	4.3	13.1	12.9
Regulatory adjustment	0.3	0.4	1.0	0.7
Net periodic benefit costs	$ 4.7	$ 4.7	$ 14.1	$ 13.6

Equity Compensation (Details) (USD $)
In Millions, except Share data, unless otherwise specified

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Compensation expense

$ 1.2

$ 4.0

$ 4.5

Income tax benefits

0.4

1.7

1.8

Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Expected volatility (in hundredths)

21.00%

Expected dividend yield (in hundredths)

4.32%

Risk-free interest rates (in hundredths)

0.40%

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Beginning balance (in shares)

442,042

Performance adjustment (in shares)

(160,717)

Granted (in shares)

164,158

Forfeited (in shares)

(74,923)

Ending balance (in shares)

370,560

Granted and issued (in shares)

164,158

Weighted average beginning balance (in dollars per share)

$ 21.06

^[1]

Weighted average granted (in dollars per share)

$ 18.12

^[1]

$ 26.30

^[1]

$ 19.02

^[1]

$ 26.15

^[1]

Weighted average forfeited (in dollars per share)

$ 20.06

^[1]

Weighted average ending balance (in dollars per share)

$ 22.97

^[1]

$ 22.97

^[1]

Weighted average granted and issued (in dollars per share)

$ 18.12

^[1]

$ 26.30

^[1]

$ 19.02

^[1]

$ 26.15

^[1]

Remaining weighted-average contractual term (in years)

1 year 2 months

Fair value of performance shares earned and paid

0.8

Total unrecognized compensation expense

3.0

Restricted Stock [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Beginning balance (in shares)

386,183

Granted (in shares)

164,660

Forfeited (in shares)

(67,816)

Ending balance (in shares)

276,189

Granted and issued (in shares)

164,660

Vested (in shares)

(206,838)

Weighted average beginning balance (in dollars per share)

$ 17.06

^[1]

Weighted average granted (in dollars per share)

$ 22.18

^[1]

$ 17.89

^[1]

$ 19.73

^[1]

$ 19.03

^[1]

Weighted average forfeited (in dollars per share)

$ 19.49

^[1]

Weighted average ending balance (in dollars per share)

$ 19.01

^[1]

$ 19.01

^[1]

Total fair value of shares vested

3.3

2.6

Weighted average granted and issued (in dollars per share)

$ 22.18

^[1]

$ 17.89

^[1]

$ 19.73

^[1]

$ 19.03

^[1]

Remaining weighted-average contractual term (in years)

1 year 10 months

Weighted average vested (in dollars per share)

$ 15.78

^[1]

Total unrecognized compensation expense

2.9

Kansas City Power and Light Company [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Compensation expense

0.8

2.9

3.1

Income tax benefits

$ 0.3

$ 0.2

$ 1.3

$ 1.2

[1]	weighted-average

Short-term Borrowings and Short-term Bank Lines of Credit (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Short-term Debt [Line Items]
Amount of outstanding cash borrowings	$ 31.0	$ 22.0
Commercial paper outstanding	427.0	267.0
Parent Company [Member]
Short-term Debt [Line Items]
Amount of revolving credit facility	200
Revolving credit facility expiration date	Dec. 01, 2016
Covenant term - amount considered in default	50.0
Amount of outstanding cash borrowings	31.0	22.0
Weighted-average interest rate from outstanding borrowings	2.00%	2.06%
Amount of letters of credit outstanding	1.8	11.6
Covenant Term Ratio of Consolidated Indebtedness to Consolidated Capitalization Ratio, Maximum	0.65
Line of Credit Facility, Covenant Compliance	in compliance
Kansas City Power and Light Company [Member]
Short-term Debt [Line Items]
Amount of revolving credit facility	600
Revolving credit facility expiration date	Dec. 01, 2016
Covenant term - amount considered in default	50.0
Amount of outstanding cash borrowings	0	0
Commercial paper outstanding	256.0	227.0
Weighted-average interest rate from outstanding borrowings	0.49%	0.50%
Amount of letters of credit outstanding	13.9	21.5
Covenant Term Ratio of Consolidated Indebtedness to Consolidated Capitalization Ratio, Maximum	0.65
Line of Credit Facility, Covenant Compliance	in compliance
KCPL Greater Missouri Operations [Member]
Short-term Debt [Line Items]
Amount of revolving credit facility	450
Revolving credit facility expiration date	Dec. 01, 2016
Covenant term - amount considered in default	50.0
Amount of outstanding cash borrowings	0	0
Commercial paper outstanding	171.0	40.0
Weighted-average interest rate from outstanding borrowings	0.94%	0.88%
Amount of letters of credit outstanding	$ 15.1	$ 13.2
Covenant Term Ratio of Consolidated Indebtedness to Consolidated Capitalization Ratio, Maximum	0.65
Line of Credit Facility, Covenant Compliance	in compliance

Long-Term Debt (Details) (USD $)
In Millions, except Share data, unless otherwise specified

9 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Long-term debt excluding current maturities

Current maturities

$ (257.1)

$ (801.4)

2,762.9

^[1]

2,742.3

^[1]

Long-term debt detail [Abstract]

Subordinated Notes Successfully Remarketed

287.4

Purchase Contracts Settled Early

0.1

Number of outstanding Equity Units at settlement (in millions of units)

5,700,000

Number of common shares issued in settlement of purchase contracts (in millions of shares)

17,100,000

Settlement rate (in shares)

2.9762

Applicable market value (in dollars per share)

$ 20.05

Kansas City Power and Light Company [Member]

Long-term debt excluding current maturities

Current maturities

(0.4)

(12.7)

Unamortized discount

(4.1)

(4.2)

1,901.6

^[1]

1,901.9

^[1]

Kansas City Power and Light Company [Member] | Corporate Debt Securities [Member] | Senior notes due 2018 KCPL [Member]

350.0

Dec. 31, 2018

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

6.375%

7.49%

^[2]

Kansas City Power and Light Company [Member] | Corporate Debt Securities [Member] | Senior notes due 2035 KCPL [Member]

250.0

Dec. 31, 2035

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

6.05%

5.78%

^[2]

Kansas City Power and Light Company [Member] | Corporate Debt Securities [Member] | Senior notes due 2017 KCPL [Member]

250.0

Dec. 31, 2017

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

5.85%

5.72%

^[2]

Kansas City Power and Light Company [Member] | Corporate Debt Securities [Member] | Senior Notes Due 2041 KCPL [Member]

400.0

Dec. 31, 2041

5.30%

Kansas City Power and Light Company [Member] | Other Long-Term Debt [Member]

Debt Instrument Maturity Date Range Start

2.6

2.9

Dec. 31, 2013

Debt Instrument Maturity Date Range End

Dec. 31, 2018

Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds EIRR due 2015-2035 [Member]

Debt Instrument Maturity Date Range Start

106.9

119.3

Dec. 31, 2015

Debt Instrument Maturity Date Range End

Dec. 31, 2035

4.97%

^[3]

Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds Series 2009 due 2019 [Member]

400.0

Dec. 31, 2019

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

7.15%

8.59%

^[2]

Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds EIRR series 2005 due 2035 [Member]

50.0

Dec. 31, 2035

4.65%

Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds EIRR series 2007B due 2035 [Member]

73.2

Dec. 31, 2035

5.375%

Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | General Mortgage bonds Series 2007A-1 due 2035 [Member]

Bonds purchased in lieu of redemption

63.3

Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | 1993 B EIRR Bonds [Member]

Bonds purchased in lieu of redemption

39.5

Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | EIRR bonds 4.90 percent Series 2008

23.4

Dec. 31, 2038

4.90%

Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | General Mortgage bonds EIRR series 2007A-2 due 2035 [Member]

Bonds purchased in lieu of redemption

10.0

Other Consolidated Entities [Member]

Current maturities

(256.7)

(788.7)

Unamortized discount

5.6

(0.7)

Other Consolidated Entities [Member] | GMO First Mortgage Bonds [Member] | First mortgage bonds due 2013-2021 [Member]

Debt Instrument Maturity Date Range Start

10.1

11.2

Dec. 31, 2013

Debt Instrument Maturity Date Range End

Dec. 31, 2021

9.44%

Other Consolidated Entities [Member] | GMO Medium Term Notes [Member] | Medium term notes 7.17 percent series due 2023 [Member]

7.0

Dec. 31, 2023

7.17%

Other Consolidated Entities [Member] | GMO Medium Term Notes [Member] | Medium term notes 7.33 percent series due 2023 [Member]

3.0

Dec. 31, 2023

7.33%

Other Consolidated Entities [Member] | GMO Medium Term Notes [Member] | Medium term notes 7.16 percent series due 2013 [Member]

6.0

Dec. 31, 2013

7.16%

Other Consolidated Entities [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds SJLP due 2013 [Member]

5.6

Dec. 31, 2013

5.85%

Other Consolidated Entities [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds Wamego Series 1996 due 2026 [Member]

7.3

Variable rate (in hundredths)

Dec. 31, 2026

0.318%

^[4]

Other Consolidated Entities [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds state environmental 1993 due 2028 [Member]

5.0

Variable rate (in hundredths)

Dec. 31, 2028

0.316%

^[4]

Other Consolidated Entities [Member] | GMO Senior Notes [Member] | Senior notes 11.875 percent series due 2012 [Member]

500.0

Dec. 31, 2012

11.875%

Other Consolidated Entities [Member] | GMO Senior Notes [Member] | Fair value adjustment [Member]

16.3

Other Consolidated Entities [Member] | GMO Senior Notes [Member] | Senior notes 8.27 percent series due 2021 [Member]

80.9

Dec. 31, 2021

8.27%

Other Consolidated Entities [Member] | Great Plains Energy Equity Units Subordinated Notes [Member] | Equity Units Subordinated Notes [Member]

287.5

10.00%

Other Consolidated Entities [Member] | Great Plains Energy Senior Notes [Member] | Senior Notes Due 2021 [Member]

350.0

Dec. 31, 2021

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

4.85%

7.34%

^[2]

Other Consolidated Entities [Member] | Great Plains Energy Senior Notes [Member] | Senor notes due 2013 [Member]

250.0

Dec. 31, 2013

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

2.75%

3.67%

^[2]

Other Consolidated Entities [Member] | Great Plains Energy Senior Notes [Member] | Senior notes due 2017 [Member]

100.0

Dec. 31, 2017

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

6.875%

7.33%

^[2]

Other Consolidated Entities [Member] | Great Plains Energy Senior Notes [Member] | Senior Notes Due 2022 [Member]

$ 287.5

$ 0

Dec. 31, 2022

5.292%

[1]	Does not include $39.5 million EIRR Series 1993B, $63.3 million EIRR Series 2007 A-1 and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L
[2]	Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
[3]	Weighted-average interest rates at September 30, 2012
[4]	Variable rate

Long-Term Debt Long-Term Debt Fair Value (Details) (USD $) In Billions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair value of financial instruments [Abstract]
Long-term Debt	$ 3.0	$ 3.5
Carrying (Reported) Amount, Fair Value Disclosure [Member] \| Kansas City Power and Light Company [Member]
Fair value of financial instruments [Abstract]
Long-term Debt	1.9	1.9
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair value of financial instruments [Abstract]
Long-term debt fair value	3.5	3.9
Estimate of Fair Value, Fair Value Disclosure [Member] \| Kansas City Power and Light Company [Member]
Fair value of financial instruments [Abstract]
Long-term debt fair value	$ 2.2	$ 2.2

Carrying amount of long-term debt, net of unamortized discount or premium, including current and noncurrent amounts. Includes, but not limited to, notes payable, bonds payable, debentures, mortgage loans and commercial paper. Excludes capital lease obligations.

+ References+ Details

Commitments and Contingencies (Details) (USD $)	9 Months Ended
Commitments and Contingencies (Details) (USD $)	Sep. 30, 2012 MW T	Dec. 31, 2011
Air and Climate Change [Abstract]
Current estimate of capital expenditures	$ 1,000,000,000
Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule (CSAPR) [Abstract]
States required to reduce emissions for SO2 and NOX under the CAIR (In number of states)	28
Mercury and Other Hazardous Air Pollutant Emissions [Abstract]
Capacity of electric steam generating units that fall under MACT standards (in megawatts)	25
Climate Change [Abstract]
CO2 produced per year (in tons)	25,000,000
SO2 National Ambient Air Quality Standard (NAAQS) [Abstract]
Primary one-hour sulfur dioxide standard, as revised June 2010 (in parts per million)	0.075
Primary twenty-four hour sulfur dioxide standard, prior to June 2010 (in parts per million)	0.140
Primary one-year sulfur dioxide standard, prior to June 2010 (in parts per million)	0.030
Remediation [Abstract]
Accrued environmental remediation expenses	400,000	400,000
Amount accrued for future investigation remediation and of GMO retained liabilities	3,000,000	2,100,000
LaCygne Station Evironmental Retrofits [Member]
Collaboration Agreement with the Sierra Club and the Concerned Citizens of Platte County [Abstract]
Predetermination request for environmental equipment required at LaCygne Station to comply with BART	1,230,000,000
KCPL share of predetermination request for environmental equipment required at LaCygne Station to comply with BART	615,000,000
Kansas City Power and Light Company [Member]
Climate Change [Abstract]
CO2 produced per year (in tons)	18,000,000
Minimum required renewable energy generation capacity percentage in Kansas by 2011	10.00%
Minimum required renewable energy generation capacity percentage in Kansas by 2016	15.00%
Minimum required renewable energy generation capacity percentage in Kansas by 2020	20.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2011	2.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2014	5.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2018	10.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2021	15.00%
Estimated electricity required to come from solar resources (in megawatts)	2
Collaboration Agreement with the Sierra Club and the Concerned Citizens of Platte County [Abstract]
Additional CO2 agreed to be offset (in tons)	711,000
Increased wind generation capacity agreed to pursue in Collaboration Agreement by 2012 - Total (in megawatts)	400
Wind generation added under Collaboration Agreement (in megawatts)	379
Remediation [Abstract]
Accrued environmental remediation expenses	300,000	300,000
New Source Review [Abstract]
Cost of Supplemental Environmental Project	800,000
Amount of penalty agreed to in settlement agreement	350,000
Kansas City Power and Light Company [Member] \| LaCygne Station [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	50.00%
KCPL Greater Missouri Operations [Member]
Climate Change [Abstract]
Minimum required renewable energy generation capacity percentage in Missouri by 2011	2.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2014	5.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2018	10.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2021	15.00%
Estimated electricity required to come from solar resources (in megawatts)	2
Remediation [Abstract]
Estimated amount of insurance proceeds available to cover qualified remediation expenses	2,400,000
KCPL Greater Missouri Operations [Member] \| Jeffrey Units Nos 1 and 2 [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	8.00%
Westar Energy Inc [Member] \| Jeffrey Units Nos 1 and 2 [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	92.00%
New Source Review [Abstract]
Estimated cost to install a selective catalytic reduction system at jeffrey Energy Center pursuant to a settlement agreement	$ 240,000,000

Legal Proceedings Loss Contingencies (Details) (Pending Litigation [Member], KCPL Greater Missouri Operations [Member], Price Reporting Litigation [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Pending Litigation [Member] \| KCPL Greater Missouri Operations [Member] \| Price Reporting Litigation [Member]
Loss Contingencies [Line Items]
Approximate amount of refunds received as a net purchaser of power through settlements with sellers of power	$ 8
Estimated additional refunds entitled to receive	12
Amount of claims addressed under refund proceedings	$ 5.1

The value (monetary amount) of the award the plaintiff seeks in the legal matter.

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 450

-SubTopic 20

-Section 50

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14326-108349

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 5

-Paragraph 9

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 5

-Paragraph 10

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 450

-SubTopic 20

-Section 50

-Paragraph 4

-Subparagraph (a)

-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 450

-SubTopic 20

-Section 50

-Paragraph 9

-Subparagraph (a)

-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14557-108349

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 5

-Paragraph 11

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 5

-Paragraph 12

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Legal Proceedings (Details) (Positive Outcome of Litigation [Member], Spent Nuclear Fuel and Radioactive Waste [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Total Wolf Creek including KCPL [Member]
Gain Contingencies [Line Items]
Amount of pending claims against the United States in the U.S. Court	$ 14.1
Amount awarded but subject to appeal	10.6
Additional amount awarded upon appeal	2.1
Kansas City Power and Light Company [Member]
Gain Contingencies [Line Items]
Amount awarded but subject to appeal	5.0
Additional amount awarded upon appeal	$ 1.0

Related Party Transactions and Relationships (Details) (Kansas City Power and Light Company [Member], USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 KCPL Greater Missouri Operations [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member]	Sep. 30, 2012 Great Plains Energy [Member]	Dec. 31, 2011 Great Plains Energy [Member]
Related Party Transaction [Line Items]
Receivable from Related Party					$ 15.9	$ 24.1	$ 6.7	$ 9.5
KCP and L employees manage GMO's business and operate its facilities at cost	$ 23.9	$ 25.0	$ 76.8	$ 82.2

The aggregate amount of receivables to be collected from related parties where one party can exercise control or significant influence over another party; including affiliates, owners or officers and their immediate families, pension trusts, and so forth, at the financial statement date. which are usually due within one year (or one business cycle).

+ References+ Details

Amount of transactions with related party during the financial reporting period.

+ References+ Details

Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Futures contracts [Member] \| Cash Flow Hedging [Member]
Price Risk Derivatives [Abstract]
Notional Contract Amount	$ 1.0	$ 2.0
Fair Value	(0.2)	(0.5)
Futures contracts [Member] \| Not Designated as Hedging Instrument [Member]
Price Risk Derivatives [Abstract]
Notional Contract Amount	16.3	23.6
Fair Value	(1.9)	(5.0)
Forward Contracts [Member] \| Not Designated as Hedging Instrument [Member]
Price Risk Derivatives [Abstract]
Notional Contract Amount	70.3	97.3
Fair Value	6.8	7.8
Option contracts [Member] \| Not Designated as Hedging Instrument [Member]
Price Risk Derivatives [Abstract]
Notional Contract Amount	0	0.4
Fair Value	0	0
Kansas City Power and Light Company [Member]
Price Risk Derivatives [Abstract]
Percentage Of Projected Natural Gas Usage Hedged Year One	89.00%
Percentage Of Projected Natural Gas Usage Hedged Year Two	16.00%
Kansas City Power and Light Company [Member] \| Futures contracts [Member] \| Cash Flow Hedging [Member]
Price Risk Derivatives [Abstract]
Notional Contract Amount	1.0	2.0
Fair Value	$ (0.2)	$ (0.5)
KCPL Greater Missouri Operations [Member]
Price Risk Derivatives [Abstract]
Percentage Of Expected On Peak Natural Gas And Natural Gas Equivalent Purchased Power Price Exposure Hedged Current	93.00%
Percentage Of Expected On Peak Natural Gas And Natural Gas Equivalent Purchased Power Price Exposure Hedged Year One	71.00%
Percentage Of Expected On Peak Natural Gas And Natural Gas Equivalent Purchased Power Price Exposure Hedged Year Two	10.00%

Derivative Instruments Group 4 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Cash Flow Hedging [Member] \| Interest charges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ (5.0)	$ (5.1)	$ (15.1)	$ (11.9)
Cash Flow Hedging [Member] \| Interest charges [Member] \| Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(2.2)	(2.1)	(6.6)	(6.5)
Cash Flow Hedging [Member] \| Fuel Costs [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(0.5)	(0.1)	(0.5)	(0.1)
Cash Flow Hedging [Member] \| Fuel Costs [Member] \| Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(0.5)	(0.1)	(0.5)	(0.1)
Cash Flow Hedging [Member] \| Income tax benefit (expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	(0.1)	0.1	0	2.2
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	2.1	2.1	6.0	4.7
Cash Flow Hedging [Member] \| Income tax benefit (expense) [Member] \| Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	(0.1)	0.1	0	0.1
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	1.0	0.9	2.7	2.6
Regulatory Account [Member] \| Fuel Costs [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain(Loss) Reclassified from Regulatory Account into Income (Effective Portion)	(2.8)	(0.6)	(5.5)	(3.5)
Interest Rate Contract [Member] \| Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0	0	0	(5.3)
Interest Rate Contract [Member] \| Cash Flow Hedging [Member] \| Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0	0	0	0
Commodity Contract [Member] \| Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0.1	(0.1)	(0.1)	(0.2)
Commodity Contract [Member] \| Cash Flow Hedging [Member] \| Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0.1	(0.1)	(0.1)	(0.2)
Commodity Contract [Member] \| Regulatory Account [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized on Regulatory Account on Derivatives (Effective Portion)	0.9	(2.2)	(1.8)	(3.5)
Total Derivatives [Member] \| Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0	0	(0.1)	(3.3)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(3.4)	(3.1)	(9.6)	(7.3)
Total Derivatives [Member] \| Cash Flow Hedging [Member] \| Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0	0	(0.1)	(0.1)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ (1.7)	$ (1.3)	$ (4.4)	$ (4.0)

The effective portion of net gain (loss) reclassified from accumulated other comprehensive income into income on derivative instruments designated and qualifying as hedging instruments.

+ References+ Details

The effective portion of gains and losses (net) on derivative instruments designated and qualifying as hedging instruments that was recognized in other comprehensive income during the current period.

+ References+ Details

Derivative Instruments Gain and Losses (Details) (Not Designated as Hedging Instrument [Member], Commodity [Member], USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Not Designated as Hedging Instrument [Member] \| Commodity [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Gains (losses) reflected in the income statement for changes in fair value of commodity contracts not designated as hedging	$ 0.1	$ (0.6)	$ (1.0)	$ 0.4

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

The net gain (loss) on trading activities (including both derivative and nonderivative instruments) recognized in the statement of financial performance.

+ References+ Details

Derivative Instruments, Group 2 (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Cash Flow Hedging [Member] \| Derivative Instrument, Current and Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	$ (38.4)	$ (47.9)
Cash Flow Hedging [Member] \| Derivative Instrument, Current and Noncurrent [Member] \| Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(27.1)	(31.4)
Cash Flow Hedging [Member] \| Current assets [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	10.8	11.3
Cash Flow Hedging [Member] \| Current assets [Member] \| Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	10.8	11.3
Cash Flow Hedging [Member] \| Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(73.6)	(89.5)
Cash Flow Hedging [Member] \| Current liabilities [Member] \| Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(55.1)	(62.5)
Cash Flow Hedging [Member] \| Noncurrent liabilities [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(0.1)	(0.2)
Cash Flow Hedging [Member] \| Noncurrent liabilities [Member] \| Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(0.1)	(0.2)
Cash Flow Hedging [Member] \| Deferred income taxes [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	24.5	30.5
Cash Flow Hedging [Member] \| Deferred income taxes [Member] \| Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	17.3	20.0
Commodity Contract [Member] \| Designated as Hedging Instrument [Member] \| Derivative Instrument, Current and Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	0	0
Derivative liability, fair value, amount not offset against collateral	0.2	0.5
Commodity Contract [Member] \| Designated as Hedging Instrument [Member] \| Derivative Instrument, Current and Noncurrent [Member] \| Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	0	0
Derivative liability, fair value, amount not offset against collateral	0.2	0.5
Commodity Contract [Member] \| Not Designated as Hedging Instrument [Member] \| Derivative Instrument, Current and Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	7.2	7.8
Derivative liability, fair value, amount not offset against collateral	2.3	5.0
Total Derivatives [Member] \| Derivative Instrument, Current and Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	7.2	7.8
Derivative liability, fair value, amount not offset against collateral	$ 2.5	$ 5.5

Derivative Instruments Cash Flow Hedge (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 20.3
Kansas City Power and Light Company [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 8.9

Fair Value Measurements (Details) (USD $)
In Millions, unless otherwise specified

Sep. 30, 2012

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Cash and cash equivalents from nuclear decommissioning trust excluded from fair value disclosure

$ 2.9

$ 3.0

Other Great Plains [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash and cash equivalents from SERP rabbi trust excluded from fair value disclosure

20.3

Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash collateral posted with third parties as part of netting agreements

2.1

5.5

Debt securities related to nuclear decommissioning trust [Abstract]

6.8

^[1]

7.8

^[1]

149.2

^[2]

132.3

^[2]

0.2

^[3]

0.3

^[3]

156.2

140.4

^[1]

Fair Value, Measurements, Recurring [Member] | Netting [Member]

Debt securities related to nuclear decommissioning trust [Abstract]

(0.4)

^[1],[4]

^[2],[4]

^[3],[4]

(0.4)

^[4]

(2.5)

^[1],[4]

(5.5)

^[1],[4]

(2.5)

^[4]

(5.5)

^[4]

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

Debt securities related to nuclear decommissioning trust [Abstract]

0.4

^[1]

116.5

^[2]

99.6

^[2]

0.1

^[3]

0.2

^[3]

117.0

99.8

2.5

^[1]

5.5

^[1]

2.5

5.5

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]

Debt securities related to nuclear decommissioning trust [Abstract]

4.4

^[1]

4.7

^[1]

32.7

^[2]

32.7

^[2]

0.1

^[3]

0.1

^[3]

37.2

37.5

^[1]

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

Debt securities related to nuclear decommissioning trust [Abstract]

2.4

^[1]

3.1

^[1]

^[2]

^[3]

2.4

3.1

^[1]

Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]

Equity securities related to nuclear decommissioning trust

97.9

84.3

Debt securities related to nuclear decommissioning trust [Abstract]

18.6

15.3

2.8

3.6

2.7

2.6

26.4

0.6

0.7

0.2

(0.6)

149.2

^[2]

132.3

^[2]

149.2

132.3

^[1]

Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Netting [Member]

Equity securities related to nuclear decommissioning trust

^[4]

Debt securities related to nuclear decommissioning trust [Abstract]

^[4]

^[4]

^[4]

^[4]

^[4]

^[2],[4]

^[4]

(0.2)

^[1],[4]

(0.5)

^[1],[4]

(0.2)

^[4]

(0.5)

^[4]

Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Fair Value, Inputs, Level 1 [Member]

Equity securities related to nuclear decommissioning trust

97.9

84.3

Debt securities related to nuclear decommissioning trust [Abstract]

18.6

15.3

116.5

^[2]

99.6

^[2]

116.5

99.6

0.2

^[1]

0.5

^[1]

0.2

0.5

Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Fair Value, Inputs, Level 2 [Member]

Equity securities related to nuclear decommissioning trust

Debt securities related to nuclear decommissioning trust [Abstract]

2.8

3.6

2.7

2.6

26.4

0.6

0.7

0.2

(0.6)

32.7

^[2]

32.7

^[2]

32.7

^[1]

Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Fair Value, Inputs, Level 3 [Member]

Equity securities related to nuclear decommissioning trust

Debt securities related to nuclear decommissioning trust [Abstract]

^[2]

^[1]

Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]

6.8

^[1]

7.8

^[1]

0.1

0.2

0.1

0.2

^[3]

0.3

^[3]

7.0

8.1

^[1]

Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Netting [Member]

(0.4)

^[1],[4]

^[4]

^[4]

^[3],[4]

(0.4)

^[4]

(2.3)

^[1],[4]

(5.0)

^[1],[4]

(2.3)

^[4]

(5.0)

^[4]

Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Fair Value, Inputs, Level 1 [Member]

0.4

^[1]

0.1

0.2

0.1

^[3]

0.2

^[3]

0.5

0.2

2.3

^[1]

5.0

^[1]

2.3

5.0

Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Fair Value, Inputs, Level 2 [Member]

4.4

^[1]

4.7

^[1]

0.1

0.1

^[3]

0.1

^[3]

4.5

4.8

^[1]

Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Fair Value, Inputs, Level 3 [Member]

2.4

^[1]

3.1

^[1]

^[3]

2.4

3.1

^[1]

$ 0

[1]	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.
[2]	Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $2.9 million and $3.0 million at September 30, 2012, and December 31, 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.
[3]	Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $20.3 million at September 30, 2012, and December 31, 2011, of cash and cash equivalents, which are not subject to the fair value requirements.
[4]	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 September 30, 2012, and December 31, 2011, Great Plains Energy netted $2.1 million and $5.5 million, respectively, of cash collateral posted with counterparties.

Fair Value Measurements Level 3 (Details) (Derivative Financial Instruments, Assets [Member], USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Derivative Financial Instruments, Assets [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	$ 2.2	$ 4.9	$ 3.1	$ 3.7
Total realized/unrealized gains or (losses) included in non-operating income	3.7	4.0	4.8	11.1
Settlements	(3.5)	(4.4)	(5.5)	(10.3)
Balance at end of period	2.4	4.5	2.4	4.5
Total unrealized gains and (losses) included in non-operating income relating to assets and liabilities still on the consolidated balance sheet at period end	$ 0.3	$ (0.3)	$ (0.4)	$ 1.2

Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	$ (1.4)	$ (10.2)	$ (4.7)	$ (6.4)
State	(0.3)	(0.8)	0	(4.8)
Foreign	0	0	0	(0.4)
Current Income Tax Expense (Benefit), Total	(1.7)	(11.0)	(4.7)	(11.6)
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	75.1	74.7	97.6	103.6
State	13.9	13.0	18.2	20.4
Deferred Income Tax Expense (Benefit), Total	89.0	87.7	115.8	124.0
Noncurrent income taxes [Abstract]
Federal	0	0	(0.2)	(18.0)
State	0	0	0	(1.9)
Foreign	(4.1)	(0.6)	(4.2)	(0.4)
Noncurrent Income Tax Expense (Benefit), Total	(4.1)	(0.6)	(4.4)	(20.3)
Investment tax credit [Abstract]
Amortization	(0.6)	(0.7)	(1.8)	(1.5)
Total income tax expense	82.6	75.4	104.9	90.6
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Federal statutory income tax	80.0	70.6	105.0	92.0
Differences between book and tax depreciation not normalized	1.3	1.8	3.4	3.7
Amortization of investment tax credits	(0.6)	(0.7)	(1.8)	(1.5)
Federal income tax credits	(2.2)	(2.9)	(8.3)	(9.7)
State income taxes	8.8	8.1	11.7	11.1
Changes in uncertain tax positions, net	(4.1)	(2.7)	(4.2)	(4.0)
Valuation Allowance			0.1	(2.2)
Income Tax Reconciliation, Other Adjustments	(0.6)	1.2	(1.0)	1.2
Total income tax expense	82.6	75.4	104.9	90.6
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]
Federal statutory income tax (in hundredths)	35.00%	35.00%	35.00%	35.00%
Differences between book and tax depreciation not normalized (in hundredths)	0.50%	0.90%	1.10%	1.40%
Amortization of investments tax credits (in hundredths)	(0.30%)	(0.30%)	(0.60%)	(0.60%)
Federal income tax credits (in hundredths)	(1.00%)	(1.40%)	(2.80%)	(3.70%)
State income taxes (in hundredths)	3.80%	4.00%	3.90%	4.20%
Changes in uncertain tax positions, net (in hundredths)	(1.80%)	(1.30%)	(1.40%)	(1.50%)
Valuation allowance (in hundredths)			0.00%	(0.80%)
Effective Income Tax Rate Reconciliation, Other Adjustments	(0.10%)	0.40%	(0.30%)	0.50%
Effective Income Tax Rate, Continuing Operations, Total	36.10%	37.30%	34.90%	34.50%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period			24.0	42.0	42.0
Additions for current year tax positions			2.8		1.4
Additions for prior year tax positions			0		2.4
Reductions for prior year tax positions			(6.1)		(20.9)
Statute expirations			0		(0.7)
Unrecognized Tax Benefits, Increases Resulting from Foreign Currency Translation			0.3		(0.2)
Balance at end of period	21.0		21.0		24.0
Uncertain Tax Positions [Abstract]
Amount expected to impact the effective tax rate if recognized	7.6		7.6		11.8
Unrecognized Tax Benefits, Period Increase (Decrease)			3.0
Increase (decrease) in unrecognized tax benefits related to former GMO non-regulated operations			4.5
Accrued interest related to unrecognized tax benefits	3.5		3.5		5.7
Unrecognized tax benefits, increase (decrease) in interest on income taxes accrued			2.2
Accrued penalties with respect to unrecognized tax benefits	0.7		0.7		1.1
Amount of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities	4.8		4.8
Kansas City Power and Light Company [Member]
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	22.9	(10.2)	23.1	(7.8)
State	4.1	(0.9)	4.2	(0.4)
Current Income Tax Expense (Benefit), Total	27.0	(11.1)	27.3	(8.2)
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	22.7	53.5	38.8	73.4
State	4.5	9.3	8.6	13.8
Deferred Income Tax Expense (Benefit), Total	27.2	62.8	47.4	87.2
Noncurrent income taxes [Abstract]
Federal	1.0	1.5	1.1	(9.1)
State	0.2	0.1	0.2	(1.0)
Noncurrent Income Tax Expense (Benefit), Total	1.2	1.6	1.3	(10.1)
Investment tax credit [Abstract]
Amortization	(0.5)	(0.5)	(1.4)	(1.0)
Total income tax expense	54.9	52.8	74.6	67.9
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Federal statutory income tax	50.8	48.3	73.8	66.7
Differences between book and tax depreciation not normalized	1.0	1.7	2.8	3.3
Amortization of investment tax credits	(0.5)	(0.5)	(1.4)	(1.0)
Federal income tax credits	(2.2)	(2.9)	(8.3)	(9.6)
State income taxes	5.8	5.7	8.4	7.7
Changes in uncertain tax positions, net			0	0.4
Income Tax Reconciliation, Other Adjustments	0	0.5	(0.7)	0.4
Total income tax expense	54.9	52.8	74.6	67.9
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]
Federal statutory income tax (in hundredths)	35.00%	35.00%	35.00%	35.00%
Differences between book and tax depreciation not normalized (in hundredths)	0.70%	1.20%	1.30%	1.70%
Amortization of investments tax credits (in hundredths)	(0.30%)	(0.40%)	(0.60%)	(0.50%)
Federal income tax credits (in hundredths)	(1.50%)	(2.10%)	(4.00%)	(5.10%)
State income taxes (in hundredths)	3.90%	4.10%	4.00%	4.00%
Changes in uncertain tax positions, net (in hundredths)			0.00%	0.20%
Effective Income Tax Rate Reconciliation, Other Adjustments	0.00%	0.40%	(0.30%)	0.30%
Effective Income Tax Rate, Continuing Operations, Total	37.80%	38.20%	35.40%	35.60%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period			8.7	19.1	19.1
Additions for current year tax positions			2.7		0
Additions for prior year tax positions			0		2.3
Reductions for prior year tax positions			(1.5)		(12.6)
Statute expirations			0		(0.1)
Unrecognized Tax Benefits, Increases Resulting from Foreign Currency Translation			0		0
Balance at end of period	9.9		9.9		8.7
Uncertain Tax Positions [Abstract]
Amount expected to impact the effective tax rate if recognized	0.2		0.2		0.2
Amount of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities	$ 4.0		$ 4.0

Segments and Related Information (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

Depreciation and amortization

Operating revenues

$ 746.2

$ 773.7

$ 1,829.5

$ 1,831.7

(68.9)

(65.9)

(204.2)

(205.9)

Interest charges

(48.1)

(60.8)

(170.8)

(156.0)

Income tax (expense) benefit

(82.6)

(75.4)

(104.9)

(90.6)

Net income (loss) attributable to Great Plains Energy

146.2

126.5

195.2

172.3

9,502.4

9,118.0

409.5

^[1]

456.6

^[1]

All Other Segments [Member]

Depreciation and amortization

Operating revenues

Interest charges

0.3

(10.6)

(21.3)

(31.2)

Income tax (expense) benefit

3.9

7.5

15.7

19.2

Net income (loss) attributable to Great Plains Energy

4.3

(7.4)

(15.0)

(17.6)

152.5

51.9

^[1]

Intersegment Elimination [Member]

(415.4)

(417.3)

^[1]

Electric Utility Segment [Member]

Depreciation and amortization

Operating revenues

746.2

773.7

1,829.5

1,831.7

(68.9)

(65.9)

(204.2)

(205.9)

Interest charges

(48.4)

(50.2)

(149.5)

(124.8)

Income tax (expense) benefit

(86.5)

(82.9)

(120.6)

(109.8)

Net income (loss) attributable to Great Plains Energy

141.9

133.9

210.2

189.9

9,765.3

9,483.4

$ 409.5

^[1]

$ 456.6

^[1]

[1]	Capital expenditures reflect year to date amounts for the periods presented.

Sum of the carrying amounts as of the balance sheet date of all assets that are recognized. Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events.

+ References+ Details

The current period expense charged against earnings on long-lived, physical assets not used in production, and which are not intended for resale, to allocate or recognize the cost of such assets over their useful lives; or to record the reduction in book value of an intangible asset over the benefit period of such asset; or to reflect consumption during the period of an asset that is not used in production.

+ References+ Details

The sum of the current income tax expense or benefit and the deferred income tax expense or benefit pertaining to continuing operations.

+ References+ Details

The cost of borrowed funds accounted for as interest that was charged against earnings during the period.

+ References+ Details

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.