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Cash and cash equivalents

$ 9.3

$ 6.2

Funds on deposit

1.0

1.4

Receivables, net

154.5

231.2

Accounts receivable pledged as collateral

174.0

95.0

Fuel inventories, at average cost

95.1

89.0

Materials and supplies, at average cost

151.3

140.3

Deferred refueling outage costs

11.9

27.5

Refundable income taxes

9.5

0.3

Prepaid expenses and other assets

88.5

7.5

Derivative instruments

1.0

27.6

19.7

Less-accumulated depreciation

723.7

619.1

Utility Plant, at Original Cost

Electric

^[1]

11,160.5

10,924.8

4,424.2

4,235.8

Net utility plant in service

6,736.3

6,689.0

Construction work in progress

584.5

287.9

Nuclear Fuel, Net of Amortization

81.3

76.6

Public Utilities, Property, Plant and Equipment, Net

7,402.1

7,053.5

Nuclear decommissioning trust fund

154.7

135.3

Regulatory Assets

1,120.9

1,058.2

Goodwill

169.0

Derivative instruments

5.5

6.8

Other Assets, Noncurrent

71.4

76.1

Investments and Other Assets, Total

1,521.5

1,445.4

9,647.3

9,118.0

Collateralized note payable

12.0

22.0

174.0

95.0

Commercial paper

530.1

267.0

263.1

801.4

Accounts payable

330.2

275.6

27.1

25.8

Accrued compensation and benefits

41.5

76.9

44.8

40.8

Other Liabilities, Current

2.8

4.4

23.9

26.0

1,449.5

1,634.9

Asset retirement obligations

832.4

628.6

Deferred tax credits

128.8

131.2

149.3

149.6

557.5

461.9

Other Liabilities, Noncurrent

283.8

268.5

110.2

101.1

2,062.0

1,740.9

Common shareholders' equity

2,624.7

2,330.6

Accumulated other comprehensive loss

758.8

684.7

Treasury Stock, Value

(5.1)

(5.6)

(38.4)

(49.8)

3,340.0

2,959.9

Noncontrolling interest

0.0

1.0

39.0

^[2]

2,756.8

2,742.3

6,135.8

5,742.2

Cumulative Preferred Stock [Member] | Preferred Stock 3 Point 80 [Member]

9,647.3

9,118.0

Cumulative Preferred Stock [Member] | Preferred Stock 4 Point 50 [Member]

10.0

Cumulative Preferred Stock [Member] | Preferred Stock 4 Point 20 [Member]

10.0

Cumulative Preferred Stock [Member] | Preferred Stock 4 Point 35 [Member]

7.0

12.0

Cash and cash equivalents

5.2

1.9

Funds on deposit

0.1

Receivables, net

163.2

172.9

Accounts receivable pledged as collateral

110.0

95.0

Fuel inventories, at average cost

63.6

59.0

Materials and supplies, at average cost

110.1

101.1

Deferred refueling outage costs

11.9

27.5

Refundable income taxes

9.1

5.7

Prepaid expenses and other assets

4.6

0.0

23.8

16.0

Less-accumulated depreciation

501.6

479.2

Utility Plant, at Original Cost

Electric

^[3]

7,971.4

7,829.3

3,374.4

3,243.0

Net utility plant in service

4,597.0

4,586.3

Construction work in progress

486.5

203.5

Nuclear Fuel, Net of Amortization

81.3

76.6

Public Utilities, Property, Plant and Equipment, Net

5,164.8

4,866.4

Nuclear decommissioning trust fund

154.7

135.3

Regulatory Assets

853.2

780.7

Other Assets, Noncurrent

29.5

30.6

Investments and Other Assets, Total

1,037.4

946.6

6,703.8

6,292.2

Collateralized note payable

0.0

110.0

95.0

Commercial paper

361.0

227.0

0.4

12.7

Accounts payable

254.0

214.8

21.9

20.6

Accrued compensation and benefits

27.7

30.0

44.8

40.8

Other Liabilities, Current

1.4

3.0

12.8

13.7

834.0

657.6

Asset retirement obligations

836.4

772.7

Deferred tax credits

126.1

127.9

133.2

134.3

534.5

440.9

Other Liabilities, Noncurrent

153.0

142.8

88.2

68.6

1,871.4

1,687.2

Common shareholders' equity

1,563.1

Accumulated other comprehensive loss

559.4

513.8

(25.8)

(31.4)

2,096.7

2,045.5

^[2]

1,901.7

1,901.9

3,998.4

3,947.4

Summary of Significant Accounting Policies [Text Block]

$ 6,703.8

$ 6,292.2

[1]	(a) Includes $104.5 million and $105.5 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.
[2]	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
[3]	(a) Includes $54.7 million and $59.8 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Utility Plant, at Original Cost
Nuclear fuel, amortization	$ 157.4	$ 132.7
Common shareholder's equity
Common stock - shares authorized (in shares)	250,000,000	250,000,000
Common stock-shares issued (in shares)	153,779,806	136,406,306
Treasury stock- shares (in shares)	250,236	264,567
Cumulative Preferred Stock [Member]
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100
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	$ 157.4	$ 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 - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Revenues
Electric revenues	$ 2,309.9	$ 2,318.0	$ 2,255.5
Operating Expenses
Fuel	539.5	483.8	430.7
Purchased power	94.0	203.4	213.8
Transmission of electricity by others	35.4	30.2	27.4
Utility operating and maintenance expenses	647.3	658.2	602.5
Voluntary separation program	(4.3)	12.7	0.0
Depreciation and amortization	272.3	273.1	331.6
General taxes	179.3	170.9	155.1
Other General and Administrative Expense	7.5	5.9	22.1
Costs and Expenses, Total	1,771.0	1,838.2	1,783.2
Operating Income (Loss)	538.9	479.8	472.3
Non-operating income	7.3	5.9	43.9
Non-operating expenses	(20.5)	(8.2)	(19.5)
Interest charges	(220.8)	(218.4)	(184.8)
Income before income tax (expense) benefit and income (loss) from equity investments	304.9	259.1	311.9
Income tax (expense) benefit	(104.6)	(84.8)	(99.0)
Loss from equity investments, net of income taxes	(0.4)	(0.1)	(1.0)
Net income	199.9	174.2	211.9
Less: Net income attributable to noncontrolling interest	0.0	0.2	(0.2)
Net income (loss) attributable to Great Plains Energy	199.9	174.4	211.7
Preferred stock dividend requirements	1.6	1.6	1.6
Earnings available for common shareholders	$ 198.3	$ 172.8	$ 210.1
Average number of common shares outstanding (in shares)	145.5	135.6	135.1
Average number of diluted common shares outstanding	147.2	138.7	136.9
Basic earnings (loss) per common share
Basic earnings per common share	$ 1.36	$ 1.27	$ 1.55
Diluted earnings (loss) per common share
Diluted earnings per common share	1.35	1.25	1.53
Cash dividends per common share	$ 0.855	$ 0.835	$ 0.830
Comprehensive Income
Net income	$ 199.9	$ 174.2	$ 211.9
Other comprehensive income
Gain (loss) on derivative hedging instruments	(0.1)	(5.9)	(28.0)
Income tax benefit (expense)	0.0	2.3	10.8
Net gain (loss) on derivative hedging instruments	(0.1)	(3.6)	(17.2)
Reclassification to expenses, net of tax	12.6	10.4	6.6
Derivative hedging activity, net of tax	12.5	6.8	(10.6)
Net gain (loss) arising during period	(2.3)	(1.2)	(1.3)
Amortization of net losses included in net periodic benefit costs	0.5	0.4	0.3
Income tax benefit (expense)	0.7	0.3	0.4
Net change in unrecognized pension expense	(1.1)	(0.5)	(0.6)
Comprehensive income attributable to Great Plains Energy	211.3	180.7	200.5
Less: comprehensive income attributable to noncontrolling interest	0.0	0.2	(0.2)
Comprehensive income	211.3	180.5	200.7
Other comprehensive income (loss)	11.4	6.3	(11.2)
Kansas City Power and Light Company [Member]
Operating Revenues
Electric revenues	1,579.9	1,558.3	1,517.1
Operating Expenses
Fuel	384.8	333.5	278.8
Purchased power	35.5	70.8	78.9
Transmission of electricity by others	24.0	18.8	15.0
Utility operating and maintenance expenses	460.1	470.9	434.3
Voluntary separation program	(4.3)	9.2	0.0
Depreciation and amortization	185.6	193.1	256.4
General taxes	145.5	139.7	129.3
Other General and Administrative Expense	0.0	1.1	13.0
Costs and Expenses, Total	1,231.2	1,237.1	1,205.7
Operating Income (Loss)	348.7	321.2	311.4
Non-operating income	4.4	2.9	24.7
Non-operating expenses	(8.6)	(3.9)	(5.6)
Interest charges	(127.6)	(115.6)	(85.7)
Income before income tax (expense) benefit and income (loss) from equity investments	216.9	204.6	244.8
Income tax (expense) benefit	(75.3)	(69.1)	(81.6)
Net income	141.6	135.5	163.2
Comprehensive Income
Net income	141.6	135.5	163.2
Other comprehensive income
Gain (loss) on derivative hedging instruments	(0.1)	(0.6)	(0.9)
Income tax benefit (expense)	0.0	0.2	0.3
Net gain (loss) on derivative hedging instruments	(0.1)	(0.4)	(0.6)
Reclassification to expenses, net of tax	5.7	5.4	5.7
Derivative hedging activity, net of tax	5.6	5.0	5.1
Comprehensive income	147.2	140.5	168.3
Other comprehensive income (loss)	$ 5.6	$ 5.0	$ 5.1

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash Flows from Operating Activities
Net income	$ 199.9	$ 174.2	$ 211.9
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	272.3	273.1	331.6
Amortization of:
Nuclear fuel	24.7	21.4	25.1
Other Amortization of Deferred Charges	36.0	12.7	(4.7)
Deferred income taxes, net	121.2	111.2	123.8
Investment tax credit amortization	(2.4)	(2.2)	(2.9)
Loss from equity investments, net of income taxes	0.4	0.1	1.0
Other operating activities	11.7	(147.5)	(133.7)
Net cash from operating activities	663.8	443.0	552.1
Cash Flows from Investing Activities
Utility capital expenditures	(610.2)	(456.6)	(618.0)
Allowance for borrowed funds used during construction	(5.3)	(5.8)	(28.5)
Purchases of nuclear decommissioning trust investments	(24.2)	(18.5)	(83.3)
Proceeds from nuclear decommissioning trust investments	20.9	15.1	79.6
Other investing activities	(19.6)	(19.9)	(7.5)
Net cash from investing activities	(638.4)	(485.7)	(657.7)
Cash Flows from Financing Activities
Issuance of common stock	293.0	5.9	6.2
Issuance of long-term debt	0.0	747.1	249.9
Issuance fees	(2.9)	(10.7)	(12.1)
Repayment of long-term debt	(513.8)	(598.5)	(1.3)
Net change in short-term borrowings	253.1	16.0	(165.6)
Net change in collateralized short-term borrowings	79.0	0.0	95.0
Dividends paid	(125.5)	(115.1)	(114.2)
Other financing activities	(5.2)	(6.6)	(7.4)
Net cash from financing activities	(22.3)	38.1	50.5
Net Change in Cash and Cash Equivalents	3.1	(4.6)	(55.1)
Cash and Cash Equivalents at Beginning of Year	6.2	10.8	65.9
Cash and Cash Equivalents at End of Year	9.3	6.2	10.8
Kansas City Power and Light Company [Member]
Cash Flows from Operating Activities
Net income	141.6	135.5	163.2
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	185.6	193.1	256.4
Amortization of:
Nuclear fuel	24.7	21.4	25.1
Other Amortization of Deferred Charges	30.1	29.5	24.2
Deferred income taxes, net	60.2	80.6	83.2
Investment tax credit amortization	(1.8)	(1.5)	(2.1)
Other operating activities	27.9	(118.3)	(127.8)
Net cash from operating activities	468.3	340.3	422.2
Cash Flows from Investing Activities
Utility capital expenditures	(482.0)	(336.5)	(463.1)
Allowance for borrowed funds used during construction	(3.7)	(2.9)	(22.4)
Purchases of nuclear decommissioning trust investments	(24.2)	(18.5)	(83.3)
Proceeds from nuclear decommissioning trust investments	20.9	15.1	79.6
Net money pool lending	0.0	12.1	(6.1)
Other investing activities	(11.7)	(9.7)	(13.4)
Net cash from investing activities	(500.7)	(340.4)	(508.7)
Cash Flows from Financing Activities
Issuance of long-term debt	0.0	397.4	0.0
Issuance fees	0.0	(6.1)	(5.1)
Repayment of long-term debt	(12.7)	(263.1)	(0.2)
Net change in short-term borrowings	134.0	(36.5)	76.9
Net change in collateralized short-term borrowings	15.0	0.0	95.0
Net money pool borrowings	(4.7)	6.7	1.1
Dividends paid	(96.0)	(100.0)	(95.0)
Other financing activities	0.1	0.0	0.0
Net cash from financing activities	35.7	(1.6)	72.7
Net Change in Cash and Cash Equivalents	3.3	(1.7)	(13.8)
Cash and Cash Equivalents at Beginning of Year	1.9	3.6	17.4
Cash and Cash Equivalents at End of Year	$ 5.2	$ 1.9	$ 3.6

Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest - USD ($) $ in Millions	Total	Kansas City Power and Light Company [Member]	Parent 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, 2009				$ 2,313.7		$ 529.2	$ 410.1	$ (5.5)	$ (44.9)	$ (41.5)	$ 1.2
Beginning balance (in shares) at Dec. 31, 2009				135,636,538				213,423
Issuance of common stock				$ 6.6
Issuance of common stock (in shares)				347,279
Issuance of restricted common stock				$ 2.3
Issuance of restricted common stock (in shares)				130,137
Equity compensation expense, net of forfeitures				$ 1.0
Unearned Compensation [Abstract]
Issuance of restricted common stock				(2.3)
Forfeiture of restricted common stock				0.8
Compensation expense recognized				2.2
Stockholders' Equity, Other				0.1
Net income (loss) attributable to Great Plains Energy	$ 211.7					211.7	163.2
Loss on reissuance of treasury stock						0.0
Dividends:
Common stock						(112.6)	(95.0)
Preferred stock - at required rates						(1.6)
Performance shares						(0.2)
Treasury shares acquired								$ (3.4)
Treasury shares acquired (in shares)								(188,383)
Treasury shares reissued								$ 0.0
Treasury shares reissued (in shares)								917
Derivative hedging activity, net of tax	(10.6)	$ 5.1	$ (15.7)						(10.6)	5.1
Change in unrecognized pension expense, net of tax	(0.6)								(0.6)
Net income attributable to noncontrolling interest	(0.2)										0.2
Distribution											(0.2)
Ending balance at Dec. 31, 2010	2,885.9	2,005.0		$ 2,324.4	$ 1,563.1	626.5	478.3	$ (8.9)	(56.1)	(36.4)	1.2
Ending balance (in shares) at Dec. 31, 2010				136,113,954	1			400,889
Issuance of common stock				$ 5.9
Issuance of common stock (in shares)				292,352
Issuance of restricted common stock				$ 0.0
Issuance of restricted common stock (in shares)				0
Equity compensation expense, net of forfeitures				$ 0.3
Unearned Compensation [Abstract]
Issuance of restricted common stock				(3.5)
Forfeiture of restricted common stock				0.9
Compensation expense recognized				2.3
Stockholders' Equity, Other				0.3
Net income (loss) attributable to Great Plains Energy	174.4					174.4	135.5
Loss on reissuance of treasury stock						(0.7)
Dividends:
Common stock						(113.5)	(100.0)
Preferred stock - at required rates						(1.6)
Performance shares						(0.4)
Treasury shares acquired								$ (2.4)
Treasury shares acquired (in shares)								(125,234)
Treasury shares reissued								$ 5.7
Treasury shares reissued (in shares)								261,556
Derivative hedging activity, net of tax	6.8	5.0	1.8						6.8	5.0
Change in unrecognized pension expense, net of tax	(0.5)								(0.5)
Net income attributable to noncontrolling interest	0.2										(0.2)
Distribution											0.0
Ending balance at Dec. 31, 2011	2,959.9	2,045.5	2,959.9	$ 2,330.6	$ 1,563.1	684.7	513.8	$ (5.6)	(49.8)	(31.4)	1.0
Ending balance (in shares) at Dec. 31, 2011				136,406,306	1			264,567
Issuance of common stock				$ 293.0
Issuance of common stock (in shares)				17,373,500
Issuance of restricted common stock				$ 0.0
Issuance of restricted common stock (in shares)				0
Equity compensation expense, net of forfeitures				$ 0.3
Unearned Compensation [Abstract]
Issuance of restricted common stock				(3.3)
Forfeiture of restricted common stock				1.3
Compensation expense recognized				2.3
Stockholders' Equity, Other				0.5
Net income (loss) attributable to Great Plains Energy	199.9					199.9	141.6
Loss on reissuance of treasury stock						(0.2)
Dividends:
Common stock						(123.9)	(96.0)
Preferred stock - at required rates						(1.6)
Performance shares						(0.1)
Treasury shares acquired								$ (3.3)
Treasury shares acquired (in shares)								(164,454)
Treasury shares reissued								$ 3.8
Treasury shares reissued (in shares)								178,785
Derivative hedging activity, net of tax	12.5	5.6	6.9						12.5	5.6
Change in unrecognized pension expense, net of tax	(1.1)								(1.1)
Net income attributable to noncontrolling interest	0.0										0.0
Distribution											(1.0)
Ending balance at Dec. 31, 2012	$ 3,340.0	$ 2,096.7	$ 3,340.0	$ 2,624.7	$ 1,563.1	$ 758.8	$ 559.4	$ (5.1)	$ (38.4)	$ (25.8)	$ 0.0
Ending balance (in shares) at Dec. 31, 2012				153,779,806	1			250,236

Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock Transactions, Parenthetical Disclosures [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 0.855	$ 0.835	$ 0.830

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

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 21 for additional information.

Use of Estimates

The process of preparing financial statements in conformity with Generally Accepted Accounting Principles (GAAP) requires the use of estimates and assumptions that affect the reported amounts of certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.

Cash and Cash Equivalents

Cash equivalents consist of highly liquid investments with original maturities of three months or less at acquisition.

Funds on Deposit

Funds on deposit consist primarily of cash provided to counterparties in support of margin requirements related to commodity purchases, commodity swaps and futures contracts. Pursuant to individual contract terms with counterparties, deposit amounts required vary with changes in market prices, credit provisions and various other factors. Interest is earned on most funds on deposit. Great Plains Energy also holds funds on deposit from counterparties in the same manner. These funds are included in other current liabilities on the consolidated balance sheets.

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it is practicable to estimate that value.

Nuclear decommissioning trust fund - KCP&L's nuclear decommissioning trust fund assets are recorded at fair value based on quoted market prices of the investments held by the fund and/or valuation models.

Rabbi trust - GMO's rabbi trusts related to its Supplemental Executive Retirement Plan (SERP) are recorded at fair value based on quoted market prices and/or valuation models for equity and debt securities and Net Asset Value (NAV) per share for fixed income funds held by the trusts. The rabbi trusts are included in Other - Investments and Other Assets on Great Plains Energy's consolidated balance sheets.

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 December 31, 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 December 31, 2012 and 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.

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

Pension plans - For financial reporting purposes, the market value of plan assets is the fair value. For regulatory reporting purposes, a five-year smoothing of assets is used to determine fair value.

Derivative Instruments

The Company records derivative instruments on the balance sheet at fair value in accordance with GAAP. Great Plains Energy and KCP&L enter into derivative contracts to manage exposure to commodity price and interest rate fluctuations. Derivative instruments designated as normal purchases and normal sales (NPNS) and cash flow hedges are used solely for hedging purposes and are not issued or held for speculative reasons.

The Company considers various qualitative factors, such as contract and market place attributes, in designating derivative instruments at inception. Great Plains Energy and KCP&L may elect the NPNS exception, which requires the effects of the derivative to be recorded when the underlying contract settles. Great Plains Energy and KCP&L account for derivative instruments that are not designated as NPNS as cash flow hedges or non-hedging derivatives, which are recorded as assets or liabilities on the consolidated balance sheets at fair value. In addition, if a derivative instrument is designated as a cash flow hedge, Great Plains Energy and KCP&L document the method of determining hedge effectiveness and measuring ineffectiveness. See Note 18 for additional information regarding derivative financial instruments and hedging activities.

Great Plains Energy and KCP&L offset fair value amounts recognized for derivative instruments under master netting arrangements, which include rights to reclaim cash collateral (a receivable), or the obligation to return cash collateral (a payable). Great Plains Energy and KCP&L classify cash flows from derivative instruments in the same category as the cash flows from the items being hedged.

Utility Plant

Great Plains Energy's and KCP&L's utility plant is stated at historical cost. These costs include taxes, an allowance for the cost of borrowed and equity funds used to finance construction and payroll-related costs, including pensions and other fringe benefits. Replacements, improvements and additions to units of property are capitalized. Repairs of property and replacements of items not considered to be units of property are expensed as incurred (except as discussed under Deferred Refueling Outage Costs). When property units are retired or otherwise disposed, the original cost, net of salvage, is charged to accumulated depreciation. Substantially all of KCP&L's utility plant is pledged as collateral for KCP&L's mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented. Substantially all of GMO's St. Joseph Light & Power (L&P) division utility plant is pledged as collateral for GMO's mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented.

As prescribed by The Federal Energy Regulatory Commission (FERC), Allowance for Funds Used During Construction (AFUDC) is charged to the cost of the plant during construction. AFUDC equity funds are included as a non-cash item in non-operating income and AFUDC borrowed funds are a reduction of interest charges. The rates used to compute gross AFUDC are compounded semi-annually and averaged 0.2% in 2012 and 2011 and 6.8% in 2010 for KCP&L. The rates used to compute gross AFUDC for GMO averaged 2.4% in 2012, 5.4% in 2011 and 4.6% in 2010.

Great Plains Energy's and KCP&L's balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following tables.



Great Plains Energy
December 31	2012		2011
Utility plant, at original cost	(millions)
Generation (20 - 60 years)	$	6,697.1	$	6,594.0
Transmission (15 - 70 years)	754.0		734.8
Distribution (8 - 66 years)	3,019.6		2,921.1
General (5 - 50 years)	689.8		674.9
Total ^(a)	$	11,160.5	$	10,924.8

^(a) Includes $104.5 million and $105.5 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.



KCP&L
December 31	2012		2011
Utility plant, at original cost	(millions)
Generation (20 - 60 years)	$	5,140.0	$	5,078.1
Transmission (15 - 70 years)	414.7		412.9
Distribution (8 - 55 years)	1,893.8		1,840.2
General (5 - 50 years)	522.9		498.1
Total ^(a)	$	7,971.4	$	7,829.3

^(a) Includes $54.7 million and $59.8 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.

Depreciation and Amortization

Depreciation and amortization of utility plant other than nuclear fuel is computed using the straight-line method over the estimated lives of depreciable property based on rates approved by state regulatory authorities. Annual depreciation rates average approximately 3%. Nuclear fuel is amortized to fuel expense based on the quantity of heat produced during the generation of electricity.

Great Plains Energy's depreciation expense was $251.4 million, $239.9 million and $243.6 million for 2012, 2011 and 2010, respectively. KCP&L's depreciation expense was $168.0 million, $162.0 million and $170.9 million for 2012, 2011 and 2010, respectively. Great Plains Energy's and KCP&L's depreciation and amortization expense includes $14.4 million and $72.6 million for 2011 and 2010, respectively, of additional amortization to help maintain cash flow levels during KCP&L's Comprehensive Energy Plan pursuant to orders of the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC).

Nuclear Plant Decommissioning Costs

Nuclear plant decommissioning cost estimates are based on the immediate dismantlement method and include the costs of decontamination, dismantlement and site restoration. Based on these cost estimates, KCP&L contributes to a tax-qualified trust fund to be used to decommission Wolf Creek Generating Station (Wolf Creek). Related liabilities for decommissioning are included on Great Plains Energy's and KCP&L's balance sheets in Asset Retirement Obligations (AROs).

As a result of the authorized regulatory treatment and related regulatory accounting, differences between the decommissioning trust fund asset and the related ARO are recorded as a regulatory asset or liability. See Note 7 for discussion of AROs including those associated with nuclear plant decommissioning costs.

Deferred Refueling Outage Costs

KCP&L uses the deferral method to account for operations and maintenance expenses incurred in support of Wolf Creek's scheduled refueling outages and amortizes them evenly (monthly) over the unit's operating cycle, which is approximately 18 months, until the next scheduled outage. Replacement power costs during an outage are expensed as incurred.

Regulatory Matters

KCP&L and GMO defer items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded if KCP&L and GMO were not regulated. See Note 5 for additional information concerning regulatory matters.

Revenue Recognition

Great Plains Energy and KCP&L recognize revenues on sales of electricity when the service is provided. Revenues recorded include electric services provided but not yet billed by KCP&L and GMO. Unbilled revenues are recorded for kWh usage in the period following the customers' billing cycle to the end of the month. KCP&L's and GMO's estimate is based on net system kWh usage less actual billed kWhs. KCP&L's and GMO's estimated unbilled kWhs are allocated and priced by regulatory jurisdiction across the rate classes based on actual billing rates.

KCP&L and GMO collect from customers gross receipts taxes levied by state and local governments. These taxes from KCP&L's Missouri customers are recorded gross in operating revenues and general taxes on Great Plains Energy's and KCP&L's statements of income. KCP&L's gross receipts taxes collected from Missouri customers were $55.8 million, $55.6 million and $54.3 million in 2012, 2011 and 2010, respectively. These taxes from KCP&L's Kansas customers and GMO's customers are recorded net in operating revenues on Great Plains Energy's and KCP&L's statements of income.

Great Plains Energy and KCP&L collect sales taxes from customers and remit to state and local governments. These taxes are presented on a net basis on Great Plains Energy's and KCP&L's statements of income.

Great Plains Energy and KCP&L record sale and purchase activity on a net basis in wholesale revenue or purchased power when transacting with Regional Transmission Organization (RTO)/Independent System Operator (ISO) markets.

Allowance for Doubtful Accounts

This reserve represents estimated uncollectible accounts receivable and is based on management's judgment considering historical loss experience and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are charged off against the reserve when they are deemed uncollectible.

Property Gains and Losses

Net gains and losses from the sale of assets and businesses and from asset impairments are recorded in operating expenses.

Asset Impairments

Long-lived assets and finite-lived intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset to be held and used is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. The amount of impairment recognized is the excess of the carrying value of the asset over its fair value.

Goodwill and indefinite lived intangible assets are tested for impairment annually and when an event occurs indicating the possibility that an impairment exists. The annual test must be performed at the same time each year. If the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, the implied fair value of the reporting unit goodwill is compared with its carrying value.

Income Taxes

Income taxes are accounted for using the asset/liability approach. Deferred tax assets and liabilities are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, applying enacted statutory tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized.

Great Plains Energy and KCP&L recognize tax benefits based on a “more-likely-than-not” recognition threshold. In addition, Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.

Great Plains Energy files a consolidated federal income tax return as well as unitary and combined income tax returns in several state jurisdictions with Kansas and Missouri being the most significant. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss. KCP&L's income tax provision includes taxes allocated based on its separate company income or loss.

Great Plains Energy and KCP&L have established a net regulatory asset for the additional future revenues to be collected from customers for deferred income taxes. Tax credits are recognized in the year generated except for certain KCP&L and GMO investment tax credits that have been deferred and amortized over the remaining service lives of the related properties.

Environmental Matters

Environmental costs are accrued when it is probable a liability has been incurred and the amount of the liability can be reasonably estimated.

Basic and Diluted Earnings per Common Share Calculation

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

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



	2012		2011			2010
Income	(millions, except per share amounts)
Net income	$	199.9	$	174.2		$	211.9
Less: net income (loss) attributable to noncontrolling interest	—		(0.2		)	0.2
Less: preferred stock dividend requirements	1.6		1.6			1.6
Earnings available for common shareholders	$	198.3	$	172.8		$	210.1
Common Shares Outstanding
Average number of common shares outstanding	145.5		135.6			135.1
Add: effect of dilutive securities	1.7		3.1			1.8
Diluted average number of common shares outstanding	147.2		138.7			136.9
Basic EPS	$	1.36	$	1.27		$	1.55
Diluted EPS	$	1.35	$	1.25		$	1.53

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



	2012	2011	2010
Performance shares	—	50,897	340,690
Restricted stock shares	3,781	43,641	251,526
Stock options	—	6,000	196,137

Dividends Declared

In February 2013, 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 March 20, 2013, to shareholders of record as of February 27, 2013. The Board also declared regular dividends on Great Plains Energy's preferred stock, payable June 1, 2013, to shareholders of record as of May 10, 2013.

In February 2013, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $23 million payable on March 20, 2013.

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.

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2012

Cash Flow, Supplemental Disclosures [Text Block]

2. SUPPLEMENTAL CASH FLOW INFORMATION



Great Plains Energy Other Operating Activities
Year Ended December 31	2012			2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	76.8		$	3.6		$	(12.6	)
Accounts receivable pledged as collateral	(79.0		)	—			(95.0		)
Fuel inventories	(6.1		)	(3.9		)	(0.1		)
Materials and supplies	(11.0		)	(7.5		)	(11.5		)
Accounts payable	57.3			5.7			12.8
Accrued taxes	(7.8		)	1.4			6.7
Accrued interest	(35.2		)	1.5			2.9
Deferred refueling outage costs	15.6			(17.9		)	9.9
Fuel recovery mechanism	22.5			(1.7		)	2.7
Pension and post-retirement benefit obligations	14.4			(56.0		)	(10.2		)
Allowance for equity funds used during construction	(1.3		)	(1.0		)	(26.0		)
Write down of affordable housing investments	—			—			11.2
Interest rate hedge settlements	—			(26.1		)	(6.9		)
Iatan Nos. 1 and 2 impact of disallowed construction costs	—			2.3			16.8
Uncertain tax positions	(4.7		)	(20.8		)	(6.1		)
Other	(29.8		)	(27.1		)	(28.3		)
Total other operating activities	$	11.7		$	(147.5	)	$	(133.7	)
Cash paid during the period:
Interest	$	247.9		$	254.4		$	237.7
Income taxes	$	3.3		$	2.8		$	0.9
Non-cash investing activities:
Liabilities accrued for capital expenditures	$	57.5		$	39.7		$	44.9



KCP&L Other Operating Activities
Year Ended December 31	2012			2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	8.8		$	(20.2	)	$	(4.1	)
Accounts receivable pledged as collateral	(15.0		)	—			(95.0		)
Fuel inventories	(4.6		)	(14.1		)	0.7
Materials and supplies	(9.0		)	(6.7		)	(9.6		)
Accounts payable	48.3			11.0			0.8
Accrued taxes	(2.0		)	2.7			(15.7		)
Accrued interest	(2.3		)	3.8			(0.5		)
Deferred refueling outage costs	15.6			(17.9		)	9.9
Pension and post-retirement benefit obligations	18.0			(45.6		)	7.9
Allowance for equity funds used during construction	(1.3		)	(0.7		)	(21.9		)
Fuel recovery mechanism	5.1			(5.8		)	(8.8		)
Iatan Nos. 1 and 2 impact of disallowed construction costs	—			1.5			13.0
Uncertain tax positions	1.8			(10.4		)	(1.8		)
Other	(35.5		)	(15.9		)	(2.7		)
Total other operating activities	$	27.9		$	(118.3	)	$	(127.8	)
Cash paid during the period:
Interest	$	118.0		$	111.3		$	101.1
Income taxes	$	18.0		$	0.1		$	18.2
Non-cash investing activities:
Liabilities accrued for capital expenditures	$	48.4		$	32.0		$	37.4

Significant Non-Cash Items

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

Receivables

12 Months Ended

Dec. 31, 2012

Receivables [Abstract]

Receivables [Text Block]

3. RECEIVABLES

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



	December 31
	2012			2011
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	—		$	69.8
Customer accounts receivable - unbilled	58.3			82.4
Allowance for doubtful accounts - customer accounts receivable	(2.6		)	(2.5		)
Other receivables	98.8			81.5
Total	$	154.5		$	231.2
KCP&L
Customer accounts receivable - billed	$	—		$	16.4
Customer accounts receivable - unbilled	42.9			50.0
Allowance for doubtful accounts - customer accounts receivable	(1.5		)	(1.4		)
Intercompany receivables	40.0			38.7
Other receivables	81.8			69.2
Total	$	163.2		$	172.9

Great Plains Energy's and KCP&L's other receivables at December 31, 2012 and 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 and GMO sell all of their retail electric accounts receivable to their wholly owned subsidiaries, KCP&L Receivables Company and GMO Receivables Company, respectively, which in turn sell an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor. 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 December 31, 2012 and 2011, Great Plains Energy's accounts receivable pledged as collateral and the corresponding short-term collateralized note payable were $174.0 million and $95.0 million, respectively. At December 31, 2012 and 2011, KCP&L's accounts receivable pledged as collateral and the corresponding short-term collateralized note payable were $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.



2012	KCP&L				KCP&L Receivables Company				Consolidated KCP&L				GMO				GMO Receivables Company				Consolidated Great Plains Energy
	(millions)
Receivables (sold) purchased		$	(1,436.0	)		$	1,436.0			$	—			$	(597.8	)		$	597.8			$	—
Gain (loss) on sale of accounts receivable ^(a)		(18.2		)		18.3				0.1				(7.6		)		6.6				(0.9		)
Servicing fees received (paid)		2.5				(2.5		)		—				0.9				(0.9		)		—
Fees paid to outside investor		—				(1.2		)		(1.2		)		—				(0.5		)		(1.7		)
Cash from customers (transferred) received		(1,452.4		)		1,452.4				—				(524.0		)		524.0				—
Cash received from (paid for) receivables purchased		1,434.2				(1,434.2		)		—				517.5				(517.5		)		—
Interest on intercompany note received (paid)		0.3				(0.3		)		—				0.1				(0.1		)		—



2011		KCP&L				KCP&L Receivables Company				Consolidated KCP&L
	(millions)
Receivables (sold) purchased			$	(1,415.6	)		$	1,415.6			$	—
Gain (loss) on sale of accounts receivable ^(a)			(17.9		)		17.7				(0.2		)
Servicing fees received (paid)			2.6				(2.6		)		—
Fees paid to outside investor			—				(1.2		)		(1.2		)
Cash from customers (transferred) received			(1,412.4		)		1,412.4				—
Cash received from (paid for) receivables purchased			1,394.7				(1,394.7		)		—
Interest on intercompany note received (paid)			0.5				(0.5		)		—

^(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

12 Months Ended

Dec. 31, 2012

Nuclear Plant [Abstract]

Nuclear Plant

4. NUCLEAR PLANT

KCP&L owns 47% of 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 ordered the licensing board to close out its work on the DOE's application due to a lack of funding. These agency actions prompted multiple states and a municipality to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its review and to issue a decision on the license application. The court has not yet issued a final decision in the case. 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 15 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 dispose 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 Plant Decommissioning Costs

The MPSC and KCC require KCP&L and the other owners of Wolf Creek to submit an updated decommissioning cost study every three years and to propose funding levels. The most recent study was submitted to the MPSC and KCC in August 2011 and is the basis for the current cost of decommissioning estimates in the following table. Funding levels included in KCP&L retail rates have not changed.



	Total Station			KCP&L's 47% Share
	(millions)
Current cost of decommissioning (in 2011 dollars)		$	630		$	296
Future cost of decommissioning (in 2045-2053 dollars) ^(a)		1,788			840

Annual escalation factor	2.85%
Annual return on trust assets ^(b)	5.46%

^(a)Total future cost over an eight year decommissioning period

^(b)The 5.46% rate of return is through 2025. The rate then systematically decreases through 2053 to 0.76% based on the assumption that the fund's investment mix will become increasingly conservative as the decommissioning period approaches.

Nuclear Decommissioning Trust Fund

In 2012 and 2011, KCP&L contributed approximately $3.3 million and $3.4 million, respectively, to a tax-qualified trust fund to be used to decommission Wolf Creek. Amounts funded are charged to other operating expense and recovered in customers' rates. The funding level assumes a projected level of return on trust assets. If the actual return on trust assets is below the projected level or actual decommissioning costs are higher than estimated, KCP&L could be responsible for the balance of funds required; however, while there can be no assurances, management believes a rate increase would be allowed to recover decommissioning costs over the remaining life of the unit.

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



	2012			2011
Decommissioning Trust		(millions)
Beginning balance January 1		$	135.3		$	129.2
Contributions		3.3			3.4
Earned income, net of fees		3.0			4.8
Net realized gains		1.0			0.3
Net unrealized gains (losses)		12.1			(2.4		)
Ending balance December 31		$	154.7		$	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.



	December 31
	2012													2011
	Cost Basis		Unrealized Gains			Unrealized Losses				Fair Value			Cost Basis			Unrealized Gains			Unrealized Losses				Fair Value
	(millions)
Equity securities	$	80.6		$	21.1		$	(1.6	)		$	100.1		$	76.5		$	12.3		$	(4.5	)		$	84.3
Debt securities	46.6			4.9			(0.1		)		51.4			44.2			4.5			(0.1		)		48.6
Other	3.2			—			—				3.2			2.4			—			—				2.4
Total	$	130.4		$	26.0		$	(1.7	)		$	154.7		$	123.1		$	16.8		$	(4.6	)		$	135.3

The weighted average maturity of debt securities held by the trust at December 31, 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.



	2012			2011			2010
	(millions)
Realized gains	$	1.7		$	1.0		$	7.3
Realized losses	(0.7		)	(0.7		)	(0.6		)

Nuclear Insurance

The owners of Wolf Creek (Owners) maintain nuclear insurance for Wolf Creek for nuclear liability, nuclear property and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war. The nuclear property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for acts of terrorism and related losses, including replacement power costs. There is no industry aggregate limit for liability claims related to terrorism, regardless of the number of acts of terrorism affecting Wolf Creek or any other nuclear energy liability policy or the number of policies in place. An industry aggregate limit of $3.2 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), the Owners' insurance provider, exists for property claims related to terrorism, including accidental outage power costs for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits plus any recoverable reinsurance are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

In the event of a catastrophic loss at Wolf Creek, the insurance coverage may not be adequate to cover property damage and extra expenses incurred. Uninsured losses, to the extent not recovered through rates, would be assumed by KCP&L and the other owners and could have a material effect on Great Plains Energy's and KCP&L's results of operations, financial position and cash flows.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, which was reauthorized through December 31, 2025, by the Energy Policy Act of 2005, the Owners are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently $12.6 billion. This limit of liability consists of the maximum available commercial insurance of $0.4 billion and the remaining $12.2 billion is provided through an industry-wide retrospective assessment program mandated by law, known as the Secondary Financial Protection (SFP) program. Under the SFP program, the Owners can be assessed up to $117.5 million ($55.2 million, KCP&L's 47% share) per incident at any commercial reactor in the country, payable at no more than $17.5 million ($8.2 million, KCP&L's 47% share) per incident per year. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

Nuclear Property Insurance

The Owners carry decontamination liability, premature decommissioning liability and property damage insurance from NEIL for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, KCP&L's 47% share). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. KCP&L's share of any remaining proceeds can be used for further decontamination, property damage restoration and premature decommissioning costs. Premature decommissioning coverage applies only if an accident at Wolf Creek exceeds $500 million in property damage and decontamination expenses, and only after trust funds have been exhausted.

Accidental Nuclear Outage Insurance

The Owners also carry additional insurance from NEIL to cover costs of replacement power and other extra expenses incurred in the event of a prolonged outage resulting from accidental property damage at Wolf Creek.

Under all NEIL policies, the Owners are subject to retrospective assessments if NEIL losses, for each policy year, exceed the accumulated funds available to the insurer under that policy. The estimated maximum amount of retrospective assessments under the current policies could total approximately $30.2 million ($14.2 million, KCP&L's 47% share) per policy year.

Regulatory Matters

12 Months Ended

Dec. 31, 2012

Regulated Operations [Abstract]

Regulatory Matters

5. REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

In April 2012, KCP&L filed an application with KCC to request an increase to its retail revenues of $63.6 million (subsequently adjusted to $56.4 million), with a return on equity of 10.4% (subsequently adjusted to 10.3%) and a rate-making equity ratio of 51.8%. The request included 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 also requested 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.

In December 2012, KCC issued an order for KCP&L authorizing an increase in annual revenues of $33.2 million, a return on equity of 9.5% and a rate-making equity ratio of 51.8%. The rates established by the order took effect on January 1, 2013, and are effective unless and until modified by KCC or stayed by a court.

KCP&L Missouri Rate Case Proceedings

In February 2012, KCP&L filed an application with the MPSC to request an increase to its retail revenues of $105.7 million, with a return on equity of 10.4% (subsequently adjusted to 10.3%) and a rate-making equity ratio of 52.5%. The request included recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service and also included 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).

In January 2013, the MPSC issued an order for KCP&L authorizing an increase in annual revenues of $67.4 million, a return on equity of 9.7% and a rate-making equity ratio of 52.6% (or approximately 52.3% after including other comprehensive income). The rates established by the order took effect on January 26, 2013, and are effective unless and until modified by the MPSC or stayed by a court.

GMO Missouri Rate Case Proceedings

In February 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 L&P division, with a return on equity of 10.4% (subsequently adjusted to 10.3%) and a rate-making equity ratio of 52.5%. The requests included 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.

In January 2013, the MPSC issued an order for GMO authorizing an increase in annual revenues of $26.2 million for its Missouri Public Service division and $21.7 million for its L&P division, a return on equity of 9.7% and a rate-making equity ratio of 52.6% (or approximately 52.3% after including other comprehensive income). Included in the increase is recovery of costs for new and enhanced energy efficiency and demand side management programs under the Missouri Energy Efficiency Investment Act (MEEIA). The rates established by the order took effect on January 26, 2013, and are effective unless and until modified by the MPSC or stayed by a court.

Regulatory Assets and Liabilities

Great Plains Energy and KCP&L have recorded assets and liabilities on their consolidated balance sheets resulting from the effects of the ratemaking process, which would not otherwise be recorded if the Companies were not regulated. Regulatory assets represent incurred costs that are probable of recovery from future revenues. Regulatory liabilities represent future reductions in revenues or refunds to customers.

Management regularly assesses whether regulatory assets and liabilities are probable of future recovery or refund by considering factors such as decisions by the MPSC, KCC or FERC in KCP&L's and GMO's rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedent on matters applicable to the Companies; and changes in laws and regulations. If recovery or refund of regulatory assets or liabilities is not approved by regulators or is no longer deemed probable, these regulatory assets or liabilities are recognized in the current period results of operations. The Companies' continued ability to meet the criteria for recording regulatory assets and liabilities may be affected in the future by restructuring and deregulation in the electric industry or changes in accounting rules. In the event that the criteria no longer applied to any or all of the Companies' operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism were provided. Additionally, these factors could result in an impairment on utility plant assets. Great Plains Energy's and KCP&L's regulatory assets and liabilities are detailed in the following table.



	December 31
	2012								2011
	KCP&L			GMO			Great Plains Energy		KCP&L		GMO		Great Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	114.7		$	23.7		$	138.4	$	119.6	$	24.6	$	144.2
Loss on reacquired debt	8.1		^(a)	2.0		^(a)	10.1		9.1		2.7		11.8
Cost of removal	2.8			—			2.8		4.6		—		4.6
Asset retirement obligations	31.5			14.9			46.4		31.4		13.8		45.2
Pension and post-retirement costs	541.2		^(b)	129.7		^(b)	670.9		466.4		122.0		588.4
Deferred customer programs	49.8		^(c)	24.6		^(d)	74.4		48.2		20.6		68.8
Rate case expenses	7.5		^(e)	1.7		^(f)	9.2		9.6		3.8		13.4
Fuel recovery mechanisms	8.9		^(e)	16.9		^(e)	25.8		14.0		36.4		50.4
Acquisition transition costs	18.7		^(g)	15.5		^(g)	34.2		24.7		20.2		44.9
Derivative instruments	—			3.7		^(h)	3.7		—		7.6		7.6
Iatan No. 1 and common facilities depreciation and carrying costs	15.9		⁽ⁱ⁾	5.9		⁽ⁱ⁾	21.8		16.4		6.1		22.5
Iatan No. 2 construction accounting costs	30.6		^(j)	16.2		^(j)	46.8		27.9		15.4		43.3
Kansas property tax surcharge	5.4		^(e)	—			5.4		3.7		—		3.7
Solar rebates	5.8		^(k)	10.0		^(k)	15.8		—		—		—
Voluntary separation program	4.3		^(l)	—			4.3		—		—		—
Other	8.0		^(e)	2.9		^(e)	10.9		5.1		4.3		9.4
Total	$	853.2		$	267.7		$	1,120.9	$	780.7	$	277.5	$	1,058.2
Regulatory Liabilities
Emission allowances	$	78.0		$	0.1		$	78.1	$	82.0	$	0.2	$	82.2
Asset retirement obligations	63.1			—			63.1		49.3		—		49.3
Pension	1.5			44.6			46.1		0.7		40.8		41.5
Cost of removal	—			64.0		^(m)	64.0		—		61.9		61.9
Other	10.4			22.1			32.5		10.8		22.8		33.6
Total	$	153.0		$	130.8		$	283.8	$	142.8	$	125.7	$	268.5

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

^(b) Represents unrecognized gains and losses, prior service and transition costs that will be recognized in future net periodic pension and post-retirement costs, pension settlements amortized over various periods and financial and regulatory accounting method differences that will be eliminated over the life of the pension plans. Of these amounts, $526.5 million and $127.1 million for KCP&L and GMO, respectively, are not included in rate base and are amortized over various periods.

^(c) $5.0 million not included in rate base and amortized over various periods.

^(d)Included in rate base and amortized through 2019.

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

^(f)Not included in rate base and amortized through 2014.

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

^(h)Represents the fair value of derivative instruments for commodity contracts. Settlements of the contracts are recognized in fuel expense and included in GMO's Fuel Adjustment Clause (FAC).

⁽ⁱ⁾Included in rate base and amortized through 2038.

^(j)Included in rate base and amortized through 2058.

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

^(l)Not included in rate base and amortized through 2017.

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

Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets [Text Block]

6. GOODWILL AND INTANGIBLE ASSETS

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, 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.

Great Plains Energy's and KCP&L's intangible assets are included in electric utility plant on the consolidated balance sheets and are detailed in the following table.



		December 31, 2012							December 31, 2011
	Gross Carrying Amount			Accumulated Amortization				Gross Carrying Amount			Accumulated Amortization
Great Plains Energy	(millions)
Computer software		$	211.2		$	(152.9	)		$	202.5		$	(143.5	)
Asset improvements		26.5			(4.2		)		27.0			(3.7		)

KCP&L
Computer software		$	189.9		$	(142.9	)		$	171.7		$	(129.9	)
Asset improvements		11.2			(0.8		)		11.7			(0.6		)

Great Plains Energy's and KCP&L's amortization expense related to intangible assets is detailed in the following table.



	2012		2011
	(millions)
Great Plains Energy	$	15.6	$	13.5
KCP&L	13.2		12.6

The following table provides the estimated amortization expense related to Great Plains Energy's and KCP&L's intangible assets for 2013 through 2017 for the intangible assets included in the consolidated balance sheets at December 31, 2012.



	2013		2014		2015		2016		2017
	(millions)
Great Plains Energy	$	14.5	$	11.1	$	8.8	$	7.4	$	4.1
KCP&L	11.9		8.6		6.5		5.2		3.6

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.

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligations [Text Block]

7. ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations associated with tangible long-lived assets are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel. These liabilities are recognized at estimated fair value as incurred with a corresponding amount capitalized as part of the cost of the related long-lived assets and depreciated over their useful lives. Accretion of the liabilities due to the passage of time is recorded to a regulatory asset and/or liability. Changes in the estimated fair values of the liabilities are recognized when known.

KCP&L has AROs related to decommissioning Wolf Creek, site remediation of its Spearville Wind Energy Facilities, asbestos abatement and removal of storage tanks, an ash pond and landfill. GMO has AROs related to asbestos abatement and removal of storage tanks, an ash pond and landfill.

Additionally, certain wiring used in Great Plains Energy's and KCP&L's generating stations include asbestos insulation, which would require special handling if disturbed. Due to the inability to reasonably estimate the quantities or the amount of disturbance that will be necessary during dismantlement at the end of the life of a plant, the fair value of this ARO cannot be reasonably estimated at this time. Management will continue to monitor the obligation and will recognize a liability in the period in which sufficient information becomes available to reasonably estimate its fair value.

The following table summarizes the change in Great Plains Energy's and KCP&L's AROs.



	Great Plains Energy						KCP&L
	2012			2011			2012			2011
	(millions)
Beginning balance	$	149.6		$	143.3		$	134.3		$	129.7
Additions	—			0.8			—			—
Revision in timing and/or estimates	(7.7		)	(3.8		)	(7.7		)	(3.8		)
Settlements	(1.8		)	—			(1.8		)	—
Accretion	9.2			9.3			8.4			8.4
Ending balance	$	149.3		$	149.6		$	133.2		$	134.3

Pension Plans and Other Employee Benefits

12 Months Ended

Dec. 31, 2012

Compensation and Retirement Disclosure [Abstract]

Pension Plans and Other Employee Benefits

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

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

KCP&L and GMO record pension 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 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.

During 2011, Great Plains Energy recorded pension settlement charges of $10.1 million from the voluntary separation program as a result of accelerated pension distributions. The Companies deferred substantially all of the charges as a regulatory asset and will recover it over future periods pursuant to regulatory agreements. See below for information regarding the voluntary separation program.

The following pension benefits tables provide information relating to the funded status of all defined benefit pension plans on an aggregate basis as well as the components of net periodic benefit costs. For financial reporting purposes, the market value of plan assets is the fair value. For regulatory reporting purposes, a five-year smoothing of assets is used to determine fair value. Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with joint owners of power plants.



	Pension Benefits						Other Benefits
	2012			2011			2012			2011
Change in projected benefit obligation (PBO)	(millions)
PBO at beginning of year	$	980.6		$	911.4		$	154.2		$	143.6
Service cost	35.4			31.1			3.3			3.1
Interest cost	48.9			49.6			7.8			7.8
Contribution by participants	—			—			6.7			6.6
Amendments	1.1			—			—			—
Actuarial loss	127.0			83.2			26.7			7.4
Benefits paid	(58.1		)	(54.7		)	(12.2		)	(14.3		)
Settlements	(4.4		)	(40.0		)	—			—
PBO at end of plan year	$	1,130.5		$	980.6		$	186.5		$	154.2
Change in plan assets
Fair value of plan assets at beginning of year	$	591.1		$	557.6		$	77.4		$	65.8
Actual return on plan assets	71.2			(3.7		)	1.4			2.5
Contributions by employer and participants	60.4			128.8			23.7			23.0
Benefits paid	(56.3		)	(91.6		)	(12.2		)	(13.9		)
Fair value of plan assets at end of plan year	$	666.4		$	591.1		$	90.3		$	77.4
Funded status at end of year	$	(464.1	)	$	(389.5	)	$	(96.2	)	$	(76.8	)
Amounts recognized in the consolidated balance sheets
Current pension and other post-retirement liability	$	(1.9	)	$	(3.5	)	$	(0.9	)	$	(0.9	)
Noncurrent pension liability and other post-retirement liability	(462.2		)	(386.0		)	(95.3		)	(75.9		)
Net amount recognized before regulatory treatment	(464.1		)	(389.5		)	(96.2		)	(76.8		)
Accumulated OCI or regulatory asset/liability	559.5			491.8			70.4			52.5
Net amount recognized at December 31	$	95.4		$	102.3		$	(25.8	)	$	(24.3	)
Amounts in accumulated OCI or regulatory asset/liability not yet recognized as a component of net periodic benefit cost:
Actuarial loss	$	349.0		$	295.6		$	43.0		$	15.7
Prior service cost	7.3			10.7			29.8			36.9
Transition obligation	—			—			0.6			1.7
Other	203.2			185.5			(3.0		)	(1.8		)
Net amount recognized at December 31	$	559.5		$	491.8		$	70.4		$	52.5



	Pension Benefits									Other Benefits
	2012			2011			2010			2012			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	35.4		$	31.1		$	30.3		$	3.3		$	3.1		$	3.8
Interest cost	48.9			49.6			49.3			7.8			7.8			8.8
Expected return on plan assets	(42.9		)	(38.0		)	(36.6		)	(1.8		)	(1.8		)	(2.1		)
Prior service cost	4.5			4.6			4.6			7.1			7.2			7.2
Recognized net actuarial (gain) loss	44.5			38.7			37.4			(0.2		)	(0.5		)	(0.1		)
Transition obligation	—			—			0.1			1.1			1.3			1.3
Settlement charges	0.8			10.1			—			—			—			—
Net periodic benefit costs before regulatory adjustment	91.2			96.1			85.1			17.3			17.1			18.9
Regulatory adjustment	(15.5		)	(27.9		)	(32.3		)	1.5			1.1			—
Net periodic benefit costs	75.7			68.2			52.8			18.8			18.2			18.9
Other changes in plan assets and benefit obligations recognized in OCI or regulatory assets/liabilities
Current year net (gain) loss	97.9			114.8			29.1			27.1			6.7			(10.9		)
Amortization of gain (loss)	(44.5		)	(38.7		)	(37.4		)	0.2			0.5			0.1
Prior service cost	1.1			—			0.5			—			—			—
Amortization of prior service cost	(4.5		)	(4.6		)	(4.6		)	(7.1		)	(7.2		)	(7.2		)
Amortization of transition obligation	—			—			(0.1		)	(1.1		)	(1.3		)	(1.3		)
Other regulatory activity	17.7			17.1			29.5			(1.2		)	(1.0		)	0.1
Total recognized in OCI or regulatory asset/liability	67.7			88.6			17.0			17.9			(2.3		)	(19.2		)
Total recognized in net periodic benefit costs and OCI or regulatory asset/liability	$	143.4		$	156.8		$	69.8		$	36.7		$	15.9		$	(0.3	)

For financial reporting purposes, the estimated prior service cost and net loss for the defined benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2013 are $2.0 million and $54.9 million, respectively. For financial reporting purposes, net actuarial gains and losses are recognized on a rolling five-year average basis. For regulatory reporting purposes, net actuarial gains and losses are amortized over ten years. The estimated prior service cost, net gain and transition costs for the other post-retirement benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2013 are $7.2 million, $1.7 million and $0.2 million, respectively.

The accumulated benefit obligation (ABO) for all defined benefit pension plans was $985.8 million and $852.6 million at December 31, 2012 and 2011, respectively. The PBO, ABO and fair value of plan assets at year-end are aggregated by funded and underfunded plans in the following table.



	2012		2011
Pension plans with the ABO in excess of plan assets	(millions)
Projected benefit obligation	$	1,130.5	$	980.6
Accumulated benefit obligation	985.8		852.6
Fair value of plan assets	666.4		591.1
Pension plans with plan assets in excess of the ABO
Projected benefit obligation	$	—	$	—
Accumulated benefit obligation	—		—
Fair value of plan assets	—		—

The GMO SERP is reflected as an unfunded ABO of $24.0 million. Great Plains Energy has approximately $19.9 million of assets in a non-qualified trust for this plan as of December 31, 2012, and expects to fund future benefit payments from these assets.

The expected long-term rate of return on plan assets represents Great Plains Energy's estimate of the long-term return on plan assets and is based on historical and projected rates of return for current and planned asset classes in the plans' investment portfolios. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns of various asset classes. Based on the target asset allocation for each asset class, the overall expected rate of return for the portfolios was developed and adjusted for the effect of projected benefits paid from plan assets and future plan contributions. The following tables provide the weighted-average assumptions used to determine benefit obligations and net costs.



Weighted-average assumptions used to determine the benefit obligation at plan year-end	Pension Benefits				Other Benefits
	2012		2011		2012		2011
Discount rate	4.17	%	5.01	%	4.13	%	5.03	%
Rate of compensation increase	3.69	%	4.08	%	3.50	%	4.07	%



Weighted-average assumptions used to determine net costs for years ended December 31	Pension Benefits				Other Benefits
	2012		2011		2012			2011
Discount rate	5.01	%	5.54	%	5.03	%		5.50	%
Expected long-term return on plan assets	7.29	%	7.29	%	2.59	%	*	2.83	%	*
Rate of compensation increase	4.08	%	4.08	%	4.07	%		4.06	%

*after tax

Great Plains Energy expects to contribute $76.4 million to the pension plans in 2013 to meet Employee Retirement Income Security Act of 1974, as amended (ERISA) funding requirements and regulatory orders, the majority of which is expected to be paid by KCP&L. Great Plains Energy's funding policy is to contribute amounts sufficient to meet the ERISA funding requirements and MPSC and KCC rate orders plus additional amounts as considered appropriate; therefore, actual contributions may differ from expected contributions. Great Plains Energy also expects to contribute $18.7 million to other post-retirement benefit plans in 2013, the majority of which is expected to be paid by KCP&L.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid through 2022.



	Pension Benefits		Other Benefits
	(millions)
2013	$	84.6	$	8.6
2014	72.5		8.5
2015	73.8		8.6
2016	73.5		8.9
2017	76.0		9.3
2018-2022	407.9		51.1

Pension plan assets are managed in accordance with prudent investor guidelines contained in the ERISA requirements. The investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets within a reasonable and prudent level of risk. The portfolios are invested, and periodically rebalanced, to achieve targeted allocations of approximately 27% U.S. large cap and small cap equity securities, 20% international equity securities, 36% fixed income securities, 7% real estate, 6% commodities and 4% hedge funds. Fixed income securities include domestic and foreign corporate bonds, collateralized mortgage obligations and asset-backed securities, U.S. government agency, state and local obligations, U.S. Treasury notes and money market funds.

The fair values of Great Plains Energy's pension plan assets at December 31, 2012 and 2011, by asset category are in the following tables.



				Fair Value Measurements Using
Description	December 31 2012			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
		(millions)
Pension Plans
Equity securities
U.S. ^(a)		$	169.6		$	69.7		$	99.9		$	—
International ^(b)		151.2			36.6			114.6			—
Real estate ^(c)		43.4			—			5.0			38.4
Commodities ^(d)		37.3			—			37.3			—
Fixed income securities
Fixed income funds ^(e)		182.1			35.0			147.1			—
U.S. Treasury		4.5			4.5			—			—
U.S. Agency, state and local obligations		19.6			—			19.6			—
U.S. corporate bonds ^(f)		28.9			—			28.9			—
Foreign corporate bonds		2.6			—			2.6			—
Hedge funds ^(g)		21.6			—			—			21.6
Total		$	660.8		$	145.8		$	455.0		$	60.0
Cash equivalents - money market funds		5.6
Total Pension Plans		$	666.4



				Fair Value Measurements Using
Description	December 31 2011			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
		(millions)
Pension Plans
Equity securities
U.S. ^(a)		$	156.3		$	94.6		$	61.7		$	—
International ^(b)		117.0			40.9			76.1			—
Real estate ^(c)		34.7			—			—			34.7
Commodities ^(d)		34.6			—			34.6			—
Fixed income securities
Fixed income funds ^(e)		166.5			34.2			132.3			—
U.S. Treasury		4.9			4.9			—			—
U.S. Agency, state and local obligations		17.7			—			17.7			—
U.S. corporate bonds ^(f)		26.6			—			26.6			—
Foreign corporate bonds		2.6			—			2.6			—
Hedge funds ^(g)		21.7			—			—			21.7
Total		$	582.6		$	174.6		$	351.6		$	56.4
Cash equivalents - money market funds		8.5
Total Pension Plans		$	591.1

^(a) At December 31, 2012 and 2011, this category is comprised of $69.7 million and $94.6 million, respectively, of traded mutual funds valued at daily listed prices and $99.9 million and $61.7 million, respectively, of institutional common/collective trust funds valued at NAV per share.

^(b)At December 31, 2012 and 2011, this category is comprised of $36.6 million and $40.9 million, respectively, of traded mutual funds valued at daily listed prices and $114.6 million and $76.1 million, respectively, of institutional common/collective trust funds valued at daily NAV per share.

^(c)This category is comprised of institutional common/collective trust funds and a limited partnership valued at NAV on a quarterly basis.

^(d) This category is comprised of institutional common/collective trust funds valued at daily NAV per share.

^(e)At December 31, 2012 and 2011, this category is comprised of $35.0 million and $34.2 million, respectively, of traded mutual funds valued at daily listed prices and $147.1 million and $132.3 million, respectively, of institutional common/collective trust funds valued at daily NAV per share.

^(f)At December 31, 2012 and 2011, this category is comprised of $21.5 million and $18.1 million, respectively, of corporate bonds, $5.2 million and $6.1 million, respectively, of collateralized mortgage obligations and $2.2 million and $2.4 million, respectively, of other asset-backed securities.

^(g)This category is comprised of closely-held limited partnerships valued at NAV on a quarterly basis.

The following tables reconcile the beginning and ending balances for all level 3 pension plan assets measured at fair value on a recurring basis for 2012 and 2011.



Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Description	Real Estate			Hedge Funds				Total
	(millions)
Balance January 1, 2012		$	34.7		$	21.7			$	56.4
Actual return on plan assets
Relating to assets still held		1.6			0.6				2.2
Relating to assets sold		1.3			(0.4		)		0.9
Purchase, sales and settlements		0.8			(0.3		)		0.5
Balance December 31, 2012		$	38.4		$	21.6			$	60.0



Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Description	Real Estate			Hedge Funds				Limited Partnerships				Total
	(millions)
Balance January 1, 2011		$	30.3		$	8.4			$	0.1			$	38.8
Actual return on plan assets relating to assets still held		3.9			(1.3		)		(0.1		)		2.5
Purchase, sales and settlements		0.5			14.6				—				15.1
Balance December 31, 2011		$	34.7		$	21.7			$	—			$	56.4

Other post-retirement plan assets are also managed in accordance with prudent investor guidelines contained in the ERISA requirements. The investment strategy supports the objective of the funds, which is to preserve capital, maintain sufficient liquidity and earn a consistent rate of return. Other post-retirement plan assets are invested primarily in fixed income securities, which may include domestic and foreign corporate bonds, collateralized mortgage obligations and asset-backed securities, U.S. government agency, state and local obligations, U.S. Treasury notes and money market funds, as well as domestic and international equity funds.

The fair values of Great Plains Energy's other post-retirement plan assets at December 31, 2012 and 2011, by asset category are in the following tables.



				Fair Value Measurements Using
Description	December 31 2012			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
Equity securities		$	1.7		$	1.7		$	—		$	—
Fixed income securities
U.S. Treasury		13.7			13.7			—			—
U.S. Agency, state and local obligations		28.6			—			28.6			—
U.S. corporate bonds ^(a)		20.1			—			20.1			—
Foreign corporate bonds		2.2			—			2.2			—
Mutual funds		0.2			0.2			—			—
Total		$	66.5		$	15.6		$	50.9		$	—
Cash equivalents - money market funds		23.8
Total Other Post-Retirement Benefit Plans		$	90.3



				Fair Value Measurements Using
Description	December 31 2011			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
Equity securities		$	1.4		$	1.4		$	—		$	—
Fixed income securities
U.S. Treasury		14.3			14.3			—			—
U.S. Agency, state and local obligations		27.2			—			27.2			—
U.S. corporate bonds ^(a)		14.8			—			14.8			—
Foreign corporate bonds		1.5			—			1.5			—
Mutual funds		0.2			0.2			—			—
Total		$	59.4		$	15.9		$	43.5		$	—
Cash equivalents - money market funds		18.0
Total Other Post-Retirement Benefit Plans		$	77.4

^(a)At December 31, 2012 and 2011, this category is comprised of $17.1 million and $12.7 million, respectively, of corporate bonds, $1.4 million and $0.6 million, respectively, of collateralized mortgage obligations and $1.6 million and $1.5 million, respectively, of other asset-backed securities.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The cost trends assumed for 2012 and 2013 were 8.0% and 7.5%, respectively, with the rate declining through 2018 to the ultimate cost trend rate of 5%. The health care plan requires retirees to make monthly contributions on behalf of themselves and their dependents in an amount determined by Great Plains Energy.

The effects of a one-percentage point change in the assumed health care cost trend rates, holding all other assumptions constant, at December 31, 2012, are detailed in the following table. The results reflect the increase in the Medicare Part D employer subsidy which is assumed to increase with the medical trend and employer caps on post-65 plans.



	Increase		Decrease
	(millions)
Effect on total service and interest component	$	0.7	$	(0.6	)
Effect on post-retirement benefit obligation	5.0		(4.4		)

Employee Savings Plans

Great Plains Energy has defined contribution savings plans (401(k)) that cover substantially all employees. Great Plains Energy matches employee contributions, subject to limits. The annual cost of the plans was approximately $9.2 million in 2012 and 2011 and $8.9 million in 2010. KCP&L's annual cost of the plans was approximately $6.7 million in 2012 and 2011 and $6.5 million in 2010.

Voluntary Separation Program

In 2011, Great Plains Energy executed an organizational realignment and voluntary separation program to assist in the management of overall costs within the level reflected in the Company's retail electric rates and to enhance organizational efficiency. Great Plains Energy recorded expense of $12.7 million in 2011 related to this voluntary separation program reflecting severance and related payroll taxes provided by the Company to employees who elected to voluntarily separate from the Company. In 2012, KCP&L deferred $4.3 million of expense related to the voluntary separation program to a regulatory asset for recovery in rates beginning January 1, 2013, pursuant to KCP&L's December 2012 KCC rate order.

The entire disclosure for pension and other postretirement benefits.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI http://asc.fasb.org/topic&trid=2235017

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-Name Implementation Guide (Q and A)
-Number FAS88
-Paragraph 63
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-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
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-Number 03-2
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-Name Statement of Financial Accounting Standard (FAS)
-Number 87
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity Compensation

12 Months Ended

Dec. 31, 2012

Equity Compensation

9. 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. The maximum number of shares of Great Plains Energy common stock that can be issued under the plan is 8.0 million. Common stock shares delivered by Great Plains Energy under the Long-Term Incentive Plan may be authorized but unissued, held in the treasury or purchased on the open market (including private purchases) in accordance with applicable securities laws. Great Plains Energy has a policy of delivering newly issued shares, or shares surrendered by Long-Term Incentive Plan participants on account of withholding taxes and held in treasury, or both, and does not expect to repurchase common shares during 2013 to satisfy performance share payments and director deferred share unit conversion. 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.



	2012		2011		2010
Great Plains Energy	(millions)
Compensation expense	$	3.3	$	5.2	$	4.3
Income tax benefit	1.4		1.9		1.0
KCP&L
Compensation expense	$	2.3	$	3.5	$	3.0
Income tax benefit	1.0		1.3		0.5

Performance Shares

The payment of performance shares is contingent upon achievement of specific performance goals over a stated period of time as approved by the Compensation and Development Committee of the Board. The number of performance shares ultimately paid can vary from the number of shares initially granted depending on Great Plains Energy's performance over stated performance periods. Compensation expense for performance shares is calculated by taking the change in fair value between reporting periods for the portion for which the requisite service has been rendered. Dividends are accrued over the vesting period and paid in cash based on the number of performance shares ultimately paid.

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 ranged from 20%-21%, 4.27%-4.32%, and 0.33%-0.40%, respectively.

Performance share activity for 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			19.37
Forfeited		(74,923	)		20.10
Performance adjustment		(160,717	)		15.04
Ending balance		370,560			23.05

* weighted-average

At December 31, 2012, the remaining weighted-average contractual term was 0.9 years. The weighted-average grant-date fair value of shares granted was $19.37, $26.15 and $23.37 in 2012, 2011 and 2010, respectively. At December 31, 2012, there was $1.8 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 in 2012. The total fair value of performance shares earned and paid in 2011 was $0.8 million. The total fair value of performance shares earned and paid in 2010 was insignificant.

Restricted Stock

Restricted stock cannot be sold or otherwise transferred by the recipient prior to vesting and has a value equal to the fair market value of the shares on the issue date. Restricted stock shares vest over a stated period of time with accruing reinvested dividends subject to the same restrictions. Compensation expense, calculated by multiplying shares by the grant-date fair value related to restricted stock, is recognized over the stated vesting period. Restricted stock activity for 2012 is summarized in the following table.



	Nonvested Restricted Stock			Grant Date Fair Value*
Beginning balance		386,183			$	17.06
Granted and issued		165,910			19.75
Vested		(206,838	)		15.78
Forfeited		(67,816	)		19.49
Ending balance		277,439			19.03

* weighted-average

At December 31, 2012, the remaining weighted-average contractual term was 1.5 years. The weighted-average grant-date fair value of shares granted was $19.75, $19.03 and $17.80 in 2012, 2011 and 2010, respectively. At December 31, 2012, there was $2.5 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 was $3.3 million, $2.6 million and $7.3 million in 2012, 2011 and 2010, respectively.

Director Deferred Share Units

Non-employee directors receive shares of Great Plains Energy's common stock as part of their annual retainer. Each director may elect to defer receipt of their shares until the end of January in the year after they leave the Board. Director Deferred Share Units have a value equal to the market value of Great Plains Energy's common stock on the grant date with accruing dividends. Compensation expense, calculated by multiplying the director deferred share units by the related grant-date fair value, is recognized at the grant date. The total fair value of shares of Director Deferred Share Units issued was insignificant for 2012 and 2011. Director Deferred Share Units activity for 2012 is summarized in the following table.



	Share Units		Grant Date Fair Value*
Beginning balance		54,231		$	20.19
Issued		15,587		20.96
Ending balance		69,818		20.36

* weighted-average

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 50
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6406099&loc=d3e25284-112666

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6418621&loc=d3e17540-113929

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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
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-Publisher AICPA
-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
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Short-term Borrowings and Short-term Bank Lines of Credit	12 Months Ended
	Dec. 31, 2012
Short-term Borrowings and Short-term Bank Lines of Credit [Abstract]
Short-term Borrowings and Short-term Bank Lines of Credit [Text Block]	10. 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 December 31, 2012, Great Plains Energy was in compliance with this covenant. At December 31, 2012, Great Plains Energy had $12.0 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 December 31, 2012, KCP&L was in compliance with this covenant. At December 31, 2012, KCP&L had $361.0 million of commercial paper outstanding at a weighted-average interest rate of 0.48%, 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 December 31, 2012, GMO was in compliance with this covenant. At December 31, 2012, GMO had $169.1 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.

Long-Term Debt

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Long-Term Debt

11. LONG-TERM DEBT

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



		December 31
	Year Due	2012				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			(4.0		)		(4.2		)
Total KCP&L excluding current maturities^(c)			1,901.7				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
0.301% Wamego Series 1996^(d)	2026		7.3				7.3
0.303% State Environmental 1993^(d)	2028		5.0				5.0
GMO Senior Notes
8.27% Series	2021		80.9				80.9
11.875% Series			—				500.0
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			(262.7		)		(788.7		)
Unamortized discount and premium, net			5.4				(0.7		)
Total Great Plains Energy excluding current maturities^(c)			$	2,756.8			$	2,742.3


^(a)	Weighted-average interest rates at December 31, 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

Amortization of Debt Expense

Great Plains Energy's and KCP&L's amortization of debt expense is detailed in the following table.



	2012		2011		2010
	(millions)
KCP&L	$	2.9	$	3.6	$	2.8
Other Great Plains Energy	2.6		4.5		3.6
Total Great Plains Energy	$	5.5	$	8.1	$	6.4

KCP&L General Mortgage Bonds and EIRR Bonds

KCP&L has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented (Indenture). The Indenture creates a mortgage lien on substantially all of KCP&L's utility plant.

In 2011, KCP&L purchased in lieu of redemption its $63.3 million EIRR Series 2007A-1, $10.0 million EIRR Series 2007A-2 and $39.5 million EIRR Series 1993B bonds. As of December 31, 2012, the bonds were still outstanding, but were not reported as a liability on the balance sheet since they are being held by KCP&L. KCP&L has the ability to remarket these bonds to third parties whenever it determines market conditions are sufficiently attractive to do so.

Mortgage bonds totaling $630.1 million and $642.5 million were outstanding at December 31, 2012 and 2011, respectively.

KCP&L Municipal Bond Insurance Policies

KCP&L's EIRR Bonds Series 2007 A-1, 2007 A-2 and 2007B totaling $146.5 million are covered by a municipal bond insurance policy issued by Financial Guaranty Insurance Company (FGIC). The insurance agreement between KCP&L and FGIC provides for reimbursement by KCP&L for any amounts that FGIC pays under the municipal bond insurance policy. The policy also restricts the amount of secured debt KCP&L may issue. In 2009, because KCP&L issued debt secured by liens not permitted by the agreement or resulting in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization, KCP&L was required to issue and deliver collateral to FGIC in the form of $146.5 million of Mortgage Bonds Series 2007 EIRR Issuer due 2035. The bonds are not incremental debt for KCP&L but collateralize FGIC's claim on KCP&L if FGIC was required to meet its obligation under the insurance agreement.

KCP&L's secured 1992 Series EIRR bonds totaling $31.0 million, secured Series 1993A and 1993B EIRR bonds totaling $79.5 million, and secured and unsecured EIRR Bonds Series 2005 totaling $35.9 million and $50.0 million, respectively, are covered by a municipal bond insurance policy between KCP&L and Syncora Guarantee, Inc. (Syncora). The insurance agreements between KCP&L and Syncora provide for reimbursement by KCP&L for any amounts that Syncora pays under the municipal bond insurance policies. The insurance agreements contain a covenant that the indebtedness to total capitalization ratio of KCP&L and its consolidated subsidiaries will not be greater than 0.68 to 1.00. At December 31, 2012, KCP&L was in compliance with this covenant. KCP&L is also restricted from issuing additional bonds under its General Mortgage Indenture if, after giving effect to such additional bonds, the proportion of secured debt to total indebtedness would be more than 75%, or more than 50% if the long term rating for such bonds by Standard & Poor's or Moody's Investors Service would be at or below A- or A3, respectively. The insurance agreement covering the unsecured EIRR Bond Series 2005 also required KCP&L to provide collateral to Syncora in the form of $50.0 million of Mortgage Bonds Series 2005 EIRR Insurer due 2035 for KCP&L's obligations under the insurance agreement as a result of KCP&L issuing general mortgage bonds in 2009 (other than refunding of outstanding general mortgage bonds) that resulted in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization. The bonds are not incremental debt for KCP&L but collateralize Syncora's claim on KCP&L if Syncora was required to meet its obligation under the insurance agreement. In the event of a default under the insurance agreements, Syncora may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.

GMO First Mortgage Bonds

GMO has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented. The Indenture creates a mortgage lien on substantially all of GMO's L&P division utility plant. Mortgage bonds totaling $10.1 million and $11.2 million, respectively, were outstanding at December 31, 2012 and 2011.

GMO Senior Notes

The fair value adjustment represents the purchase accounting adjustment to record GMO's debt that was not fully reflected in electric retail rates as of the July 14, 2008, acquisition of GMO by Great Plains Energy, at estimated fair value, with the offset recorded to goodwill. The fair value adjustment was amortized as a reduction to interest expense over the remaining life of the individual debt issues. Amortization for 2012, 2011 and 2010 was $16.3 million, $33.6 million and $34.6 million, respectively.

In July 2012, GMO repaid its $500.0 million 11.875% Senior Notes at maturity.

Great Plains Energy Equity Units

In 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 $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.

Scheduled Maturities

Great Plains Energy's and KCP&L's long-term debt maturities for the next five years are detailed in the following table.



	2013		2014		2015		2016		2017
	(millions)
Great Plains Energy	$	263.1	$	1.5	$	15.5	$	1.6	$	382.6
KCP&L	0.4		0.4		14.4		0.4		281.5

Common Shareholders' Equity	12 Months Ended
Common Shareholders' Equity	Dec. 31, 2012
Stockholders' Equity Note [Abstract]
Common Shareholders' Equity	12. COMMON SHAREHOLDERS' EQUITY Great Plains Energy has an effective shelf registration statement for the sale of unspecified amounts of securities with the Securities and Exchange Commission (SEC) that was filed and became effective in March 2012. Great Plains Energy has 6.0 million shares of common stock registered with the SEC for its Dividend Reinvestment and Direct Stock Purchase Plan. The plan allows for the purchase of common shares by reinvesting dividends or making optional cash payments. Great Plains Energy can issue new shares or purchase shares on the open market for the plan. At December 31, 2012, 1.5 million shares remained available for future issuances. Great Plains Energy has 14.3 million shares of common stock registered with the SEC for a defined contribution savings plan. Shares issued under the plan may be either newly issued shares or shares purchased in the open market. At December 31, 2012, 2.0 million shares remained available for future issuances. Treasury shares are held for future distribution upon issuance of shares in conjunction with the Company's Long-Term Incentive Plan. Great Plains Energy's articles of incorporation restrict the payment of common stock dividends in the event common equity is 25% or less of total capitalization. In addition, if preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of directors necessary to constitute a majority of the full Board. Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at least 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress). Under the Federal Power Act, KCP&L and GMO generally can pay dividends only out of retained earnings. The revolving credit agreements of Great Plains Energy, KCP&L and GMO contain a covenant requiring each company to maintain a consolidated indebtedness to consolidated total capitalization ratio of not more than 0.65 to 1.00. As of December 31, 2012, all of Great Plains Energy's and KCP&L's retained earnings and net income were free of restrictions. As a result of the above restrictions, Great Plains Energy's subsidiaries had restricted net assets of approximately $2.8 billion as of December 31, 2012. The restrictions are not expected to affect the Companies' ability to pay dividends at the current level in the foreseeable future.

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-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 15: http://www.xbrl.org/2003/role/presentationRef
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Reference 17: http://www.xbrl.org/2003/role/presentationRef
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Reference 20: http://www.xbrl.org/2003/role/presentationRef
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Commitments and Contingencies Disclosure [Abstract]

Preferred Stock	12 Months Ended
Preferred Stock	Dec. 31, 2012
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Preferred Stock [Text Block]	13. PREFERRED STOCK At December 31, 2012, 1.6 million shares of Cumulative No Par Preferred Stock, 390,000 shares of Cumulative Preferred Stock, $100 par value and 11.0 million shares of no par Preference Stock were authorized under Great Plains Energy's articles of incorporation. All of the 390,000 authorized shares of Cumulative Preferred Stock are issued and outstanding. Great Plains Energy has the option to redeem the $39.0 million of issued Cumulative Preferred Stock at prices ranging from 101% to 103.7% of par value. If Great Plains Energy voluntarily files for dissolution or liquidation, the Cumulative Preferred Stock holders are entitled to receive the redemption prices. If a proceeding for dissolution or liquidation is filed against Great Plains Energy, the Cumulative Preferred Stock holders are entitled to receive the $100 par value per share plus accrued and unpaid dividends.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

14. 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 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, (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 projects and at December 31, 2012, had incurred approximately $234 million of cash capital expenditures, which is included in the approximate $1 billion estimate above. 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. The Companies are continuously evaluating the approximate $1 billion estimate and the capital projects contained therein. Any capacity and energy requirements resulting from a decision not to proceed with the less likely projects are 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, accomplished through statewide caps. 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. The CSAPR required states within its scope to reduce power plant SO₂and NO_xemissions that contribute to ozone and fine particle nonattainment in other states. 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 D.C. Circuit Court directed the EPA to continue to administer the CAIR until a valid replacement is promulgated.

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 approved BART plans.

KCP&L has a consent agreement with the Kansas Department of Health and Environment (KDHE) incorporating limits for stack particulate matter emissions, as well as limits for NO_x and SO₂ emissions, at its La Cygne Station that will be below the presumptive limits under BART. KCP&L further agreed to use its best efforts to install emission control technologies to reduce those emissions from the 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.

Mercury and Air Toxics Standards (MATS) Rule

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 electric utility generating units 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 to four years for compliance.

Industrial Boiler Rule

In December 2012, the EPA issued a final rule that would reduce emissions of hazardous air pollutants from new and existing industrial boilers. The final rule establishes numeric emission limits for mercury, 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 final rule does not apply to KCP&L's and GMO's electricity generating boilers, but would apply to most of GMO's Lake Road boilers, which also serve steam customers, and to auxiliary boilers at other generating facilities. The rule allows three to four years for compliance.

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 and agreed to install a selective catalytic reduction (SCR) system at one of the three Jeffrey Energy Center units by the end of 2014. 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. 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. Westar has informed the EPA that they believe that the terms of the settlement can be met through the installation of less expensive NO_xreduction equipment rather than a second SCR system. 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.

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. The EPA has not yet made its final designation.

Particulate Matter (PM) NAAQS

In December 2012, the EPA strengthened the annual primary NAAQS for fine particulate matter (PM2.5). With the final rule, the EPA provided recent ambient air monitoring data for the Kansas City area indicating it would be in attainment of the revised fine particle standard. States will now make recommendations to designate areas as meeting the standards or not meeting them with the EPA making the final designation.

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 19 million tons per year for Great Plains Energy and KCP&L, respectively.

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.

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.

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.

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 increasing 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.

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's results of operations, financial position and cash flows. 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 April 2013 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 December 31, 2012 and 2011, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site. The amount accrued was established on an undiscounted basis and KCP&L does not currently have an estimated time frame over which the accrued amount may be paid.

In addition to the $0.3 million accrual above, at December 31, 2012 and 2011, Great Plains Energy had $2.0 million and $2.1 million, respectively, accrued for the future investigation and remediation of certain additional GMO identified MGP 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 $2.6 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.

Contractual Commitments

Great Plains Energy's and KCP&L's expenses related to lease commitments are detailed in the following table.



	2012		2011		2010
	(millions)
Great Plains Energy	$	21.8	$	20.9	$	17.2
KCP&L	17.7		17.0		13.2

Great Plains Energy's and KCP&L's contractual commitments at December 31, 2012, excluding pensions and long-term debt, are detailed in the following tables.



Great Plains Energy
	2013		2014		2015		2016		2017		After 2017			Total
Lease commitments	(millions)
Operating lease	$	16.8	$	14.9	$	13.7	$	9.9	$	9.6		$	146.5		$	211.4
Capital lease	0.4		0.4		0.4		0.4		0.4			4.9			6.9
Purchase commitments
Fuel	323.2		209.9		104.9		66.7		36.7			85.4			826.8
Power	39.3		44.9		44.9		44.9		43.5			651.5			869.0
Capacity	11.3		3.3		3.0		1.2		—			—			18.8
La Cygne environmental project	329.0		129.6		4.4		—		—			—			463.0
Non-regulated natural gas transportation	3.2		3.6		3.6		3.6		0.9			—			14.9
Other	124.7		34.0		27.2		15.2		6.3			43.3			250.7
Total contractual commitments	$	847.9	$	440.6	$	202.1	$	141.9	$	97.4		$	931.6		$	2,661.5



KCP&L
	2013		2014		2015		2016		2017		After 2017			Total
Lease commitments	(millions)
Operating lease	$	14.5	$	13.1	$	12.3	$	9.8	$	9.6		$	146.4		$	205.7
Capital lease	0.2		0.2		0.2		0.2		0.2			2.5			3.5
Purchase commitments
Fuel	261.7		177.6		91.8		61.4		36.7			85.4			714.6
Power	29.2		34.8		34.8		34.8		34.8			464.3			632.7
Capacity	2.9		2.9		3.0		1.2		—			—			10.0
La Cygne environmental project	329.0		129.6		4.4		—		—			—			463.0
Other	118.8		33.2		26.4		14.4		5.5			34.2			232.5
Total contractual commitments	$	756.3	$	391.4	$	172.9	$	121.8	$	86.8		$	732.8		$	2,262.0

Great Plains Energy's and KCP&L's lease commitments end in 2048. Operating lease commitments include rail cars to serve jointly-owned generating units where KCP&L is the managing partner. Of the amounts included in the table above, KCP&L will be reimbursed by the other owners for approximately $2.0 million per year from 2013 to 2015 and approximately $0.4 million per year from 2016 to 2025, for a total of $10.3 million.

Fuel commitments consist of commitments for nuclear fuel, coal and coal transportation. Power commitments consist of commitments for renewable energy under power purchase agreements. KCP&L and GMO purchase capacity from other utilities and nonutility suppliers. Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable. KCP&L has capacity sales agreements not included above that total $5.9 million for 2013 and $4.3 million per year from 2014 to 2016. La Cygne environmental project represents 100% of the contractual commitments related to environmental upgrades at KCP&L's La Cygne Station. KCP&L owns 50% of the La Cygne Station and expects to be reimbursed by the other owner for its 50% share of the costs. Non-regulated natural gas transportation consists of MPS Merchant's commitments. Other represents individual commitments entered into in the ordinary course of business.

The entire disclosure for commitments and contingencies.

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Legal Proceedings	12 Months Ended
Legal Proceedings	Dec. 31, 2012
Legal Proceedings [Abstract]
Legal Proceedings [Text Block]	15. 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). On November 1, 2012, the trial court amended its judgment to comply with the Court of Appeals decision. KCP&L received payment of the $6.0 million award in February 2013. 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. 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.

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

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Guarantees

12 Months Ended

Dec. 31, 2012

Guarantees [Abstract]

Guarantees [Text Block]

16. GUARANTEES

In the ordinary course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include, for example, guarantees and letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiary's intended business purposes. The majority of these agreements guarantee the Company's own future performance, so a liability for the fair value of the obligation is not recorded.

At December 31, 2012, Great Plains Energy has provided $155.1 million of credit support for GMO as follows:


•	Great Plains Energy direct guarantees to GMO counterparties totaling $40.7 million, which expire in 2014,


•	Great Plains Energy letters of credit to GMO counterparties totaling $1.8 million, which expire in 2013, and


•	Great Plains Energy guarantee of GMO long-term debt totaling $112.6 million, which includes debt with maturity dates ranging from 2013-2023.

Great Plains Energy has also guaranteed GMO's $450 million revolving line of credit with a group of banks expiring in December 2016. At December 31, 2012, GMO had $169.1 million of commercial paper outstanding, had issued letters of credit totaling $15.1 million and had no outstanding cash borrowings under this credit facility.

Related Party Transactions and Relationships

12 Months Ended

Dec. 31, 2012

17. RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO's business and operate its facilities at cost. These costs totaled $103.7 million for 2012, $108.4 million for 2011 and $100.9 million for 2010. Additionally, KCP&L and GMO engage in wholesale electricity transactions with each other. KCP&L's net wholesale sales to GMO were $29.4 million, $18.2 million and $10.6 million in 2012, 2011 and 2010, respectively. 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.



	December 31
	2012		2011
	(millions)
Net receivable from GMO	$	26.2	$	24.1
Net receivable from Great Plains Energy	13.8		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.

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Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Text Block]

18. 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 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 hedges for GMO's utility operations 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 December 31, 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 December 31, 2012, KCP&L had fully hedged 2013 and had hedged 81% of the 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 in 2012, 2011 or 2010.

GMO's risk management policy is to use derivative instruments to mitigate price exposure to natural gas price volatility in the market. The fair value of the portfolio relates to financial contracts that will settle against actual purchases of natural gas and purchased power. At December 31, 2012, GMO had financial contracts in place to hedge approximately 84%, 17% and 2% of the expected on-peak natural gas generation and natural gas equivalent purchased power price exposure for 2013, 2014 and 2015, respectively. 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.



	December 31
	2012					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	17.9		(2.8		)	23.6		(5.0		)
Forward contracts
Non-hedging derivatives	65.5		6.5			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
December 31, 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		6.5			2.8
Total Derivatives			$	6.5		$	3.0

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

December 31, 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
2012	(millions)					(millions)
Interest rate contracts		$	—		Interest charges	$	(20.2	)
Commodity contracts		(0.1		)	Fuel	(0.5		)
Income tax benefit		—			Income tax benefit	8.1
Total		$	(0.1	)	Total	$	(12.6	)
2011
Interest rate contracts		$	(5.3	)	Interest charges	$	(16.9	)
Commodity contracts		(0.6		)	Fuel	(0.1		)
Income tax benefit		2.3			Income tax benefit	6.6
Total		$	(3.6	)	Total	$	(10.4	)



KCP&L
Derivatives in Cash Flow Hedging Relationship
					Gain (Loss) Reclassified from
					Accumulated OCI into Income
					(Effective Portion)
	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)				Income Statement Classification	Amount
2012	(millions)					(millions)
Interest rate contracts		$	—		Interest charges	$	(8.7	)
Commodity contracts		(0.1		)	Fuel	(0.5		)
Income tax benefit		—			Income tax benefit	3.5
Total		$	(0.1	)	Total	$	(5.7	)
2011
Interest rate contracts		$	—		Interest charges	$	(8.7	)
Commodity contracts		(0.6		)	Fuel	(0.1		)
Income tax benefit		0.2			Income tax benefit	3.4
Total		$	(0.4	)	Total	$	(5.4	)

The following table summarizes the amount of loss recognized in a regulatory asset 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 Asset on Derivatives				Income Statement Classification	Amount
2012	(millions)					(millions)
Commodity contracts		$	(2.7	)	Fuel	$	(6.6	)
Total		$	(2.7	)	Total	$	(6.6	)
2011
Commodity contracts		$	(8.3	)	Fuel	$	(3.8	)
Total		$	(8.3	)	Total	$	(3.8	)

Great Plains Energy's income statement reflects losses for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $1.3 million for 2012 and $1.1 million for 2011.

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



	Great Plains Energy								KCP&L
	December 31								December 31
	2012				2011				2012				2011
		(millions)
Current assets		$	10.6			$	11.3			$	10.6			$	11.3
Current liabilities		(68.4		)		(89.5		)		(52.8		)		(62.5		)
Noncurrent liabilities		(0.1		)		(0.2		)		(0.1		)		(0.2		)
Deferred income taxes		22.5				30.5				16.5				20.0
Total		$	(35.4	)		$	(47.9	)		$	(25.8	)		$	(31.4	)

Great Plains Energy's accumulated OCI in the table above at December 31, 2012, includes $20.4 million that is expected to be reclassified to expenses over the next twelve months. KCP&L's accumulated OCI in the table above at December 31, 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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Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

19. 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 SERP rabbi trusts.

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 and fixed income funds within KCP&L's decommissioning trust fund and GMO's SERP rabbi trusts.

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 December 31, 2012 and 2011.



								Fair Value Measurements Using
Description	December 31 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 ^(a)
Equity securities		$	100.1		$	—			$	100.1		$	—		$	—
Debt securities
U.S. Treasury		18.5			—				18.5			—			—
U.S. Agency		2.8			—				—			2.8			—
State and local obligations		3.3			—				—			3.3			—
Corporate bonds		26.8			—				—			26.8			—
Other		0.3			—				—			0.3			—
Total nuclear decommissioning trust		151.8			—				118.6			33.2			—
Total		151.8			—				118.6			33.2			—
Liabilities
Derivative instruments ^(b)		—			(0.2		)		0.2			—			—
Total		$	—		$	(0.2	)		$	0.2		$	—		$	—
Other Great Plains Energy
Assets
Derivative instruments ^(b)		$	6.5		$	—			$	—		$	4.2		$	2.3
SERP rabbi trusts ^(c)
Equity securities		0.1			—				0.1			—			—
Fixed income funds		20.2			—				—			20.2			—
Total SERP rabbi trusts		20.3			—				0.1			20.2			—
Total		26.8			—				0.1			24.4			2.3
Liabilities
Derivative instruments ^(b)		—			(2.8		)		2.8			—			—
Total		$	—		$	(2.8	)		$	2.8		$	—		$	—
Great Plains Energy
Assets
Derivative instruments ^(b)		$	6.5		$	—			$	—		$	4.2		$	2.3
Nuclear decommissioning trust ^(a)		151.8			—				118.6			33.2			—
SERP rabbi trusts ^(c)		20.3			—				0.1			20.2			—
Total		178.6			—				118.7			57.6			2.3
Liabilities
Derivative instruments ^(b)		—			(3.0		)		3.0			—			—
Total		$	—		$	(3.0	)		$	3.0		$	—		$	—



									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 ^(a)
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 ^(b)		—				(0.5		)		0.5			—				—
Total		$	—			$	(0.5	)		$	0.5		$	—			$	—
Other Great Plains Energy
Assets
Derivative instruments ^(b)		$	7.8			$	—			$	—		$	4.7			$	3.1
SERP rabbi trusts ^(c)
Equity securities		0.2				—				0.2			—				—
Debt securities		0.1				—				—			0.1				—
Total SERP rabbi trusts		0.3				—				0.2			0.1				—
Total		8.1				—				0.2			4.8				3.1
Liabilities
Derivative instruments ^(b)		—				(5.0		)		5.0			—				—
Total		$	—			$	(5.0	)		$	5.0		$	—			$	—
Great Plains Energy
Assets
Derivative instruments ^(b)		$	7.8			$	—			$	—		$	4.7			$	3.1
Nuclear decommissioning trust ^(a)		132.3				—				99.6			32.7				—
SERP rabbi trusts ^(c)		0.3				—				0.2			0.1				—
Total		140.4				—				99.8			37.5				3.1
Liabilities
Derivative instruments ^(b)		—				(5.5		)		5.5			—				—
Total		$	—			$	(5.5	)		$	5.5		$	—			$	—


^(a)	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 December 31, 2012 and 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.


^(b)	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.


^(c)	Fair value is based on quoted market prices and/or valuation models for equity and debt securities and NAV per share for fixed income funds. The total does not include $0.1 million and $20.3 million at December 31, 2012 and 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.


^(d)	Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheets where a master netting agreement exists between the Company and the counterparty. At December 31, 2012 and 2011, Great Plains Energy netted $3.0 million and $5.5 million, respectively, of cash collateral posted with counterparties.

The following table reconciles the beginning and ending balances for all Level 3 assets and liabilities, net, measured at fair value on a recurring basis for 2012 and 2011.



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	8.2			10.9
Settlements	(9.0		)	(11.5		)
Balance at December 31	$	2.3		$	3.1
Total unrealized losses included in non-operating income relating to assets
and liabilities still on the consolidated balance sheet at December 31	$	(0.4	)	$	(0.2	)

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
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-Subparagraph a, b
-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 133
-Paragraph 44A, 44B
-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 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 17-22, 27, 28
-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 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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-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 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
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-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 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
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-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 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Income Tax Disclosure [Text Block]

Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

20. TAXES

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



Great Plains Energy	2012			2011			2010
Current income taxes	(millions)
Federal	$	(3.2	)	$	2.9		$	(7.4	)
State	(6.3		)	(6.0		)	(4.3		)
Foreign	—			(0.4		)	0.1
Total	(9.5		)	(3.5		)	(11.6		)
Deferred income taxes
Federal	96.3			90.5			99.8
State	24.9			20.7			24.0
Total	121.2			111.2			123.8
Noncurrent income taxes
Federal	(0.2		)	(18.0		)	(4.8		)
State	(0.3		)	(2.1		)	(1.8		)
Foreign	(4.2		)	(0.6		)	0.5
Total	(4.7		)	(20.7		)	(6.1		)
Investment tax credit
Deferral	—			—			(4.2		)
Amortization	(2.4		)	(2.2		)	(2.9		)
Total	(2.4		)	(2.2		)	(7.1		)
Income tax expense	$	104.6		$	84.8		$	99.0



KCP&L	2012			2011			2010
Current income taxes	(millions)
Federal	$	13.1		$	1.0		$	5.5
State	2.0			(0.6		)	1.1
Total	15.1			0.4			6.6
Deferred income taxes
Federal	48.8			66.0			69.8
State	11.4			14.6			13.4
Total	60.2			80.6			83.2
Noncurrent income taxes
Federal	1.7			(9.3		)	(1.6		)
State	0.1			(1.1		)	(0.3		)
Total	1.8			(10.4		)	(1.9		)
Investment tax credit
Deferral	—			—			(4.2		)
Amortization	(1.8		)	(1.5		)	(2.1		)
Total	(1.8		)	(1.5		)	(6.3		)
Income tax expense	$	75.3		$	69.1		$	81.6

Effective Income Tax Rates

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	2012		2011		2010
Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Differences between book and tax depreciation not normalized	1.2		1.5		(1.7	)
Amortization of investment tax credits	(0.8	)	(0.8	)	(0.9	)
Federal income tax credits	(3.1	)	(5.0	)	(4.1	)
State income taxes	4.0		4.0		3.7
Medicare Part D subsidy legislation	—		—		0.9
Changes in uncertain tax positions, net	(1.5	)	(1.7	)	0.1
Valuation allowance	—		(0.8	)	(0.9	)
Other	(0.5	)	0.5		(0.3	)
Effective income tax rate	34.3	%	32.7	%	31.8	%



KCP&L	2012		2011		2010
Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Differences between book and tax depreciation not normalized	1.3		1.6		(1.8	)
Amortization of investment tax credits	(0.8	)	(0.7	)	(0.9	)
Federal income tax credits	(4.3	)	(6.3	)	(3.5	)
State income taxes	4.1		3.9		3.6
Medicare Part D subsidy legislation	—		—		1.1
Changes in uncertain tax positions, net	—		0.1		—
Other	(0.6	)	0.2		(0.2	)
Effective income tax rate	34.7	%	33.8	%	33.3	%

Deferred Income Taxes

The tax effects of major temporary differences resulting in deferred income tax assets (liabilities) in the consolidated balance sheets are in the following tables.



	Great Plains Energy						KCP&L
December 31	2012			2011			2012			2011
Current deferred income tax asset (liability)	(millions)
Net operating loss carryforward	$	77.8		$	—		$	—		$	—
Other	12.7			7.9			4.6			(0.1		)
Net current deferred income tax asset (liability) before valuation allowance	90.5			7.9			4.6			(0.1		)
Valuation allowance	(2.0		)	(0.4		)	—			—
Net current deferred income tax asset (liability)	88.5			7.5			4.6			(0.1		)
Noncurrent deferred income taxes
Plant related	(1,297.2		)	(1,193.6		)	(930.7		)	(861.6		)
Income taxes on future regulatory recoveries	(138.3		)	(144.3		)	(114.7		)	(119.6		)
Derivative instruments	37.7			43.3			27.4			31.1
Pension and post-retirement benefits	(26.6		)	(34.2		)	(3.4		)	(11.7		)
SO₂emission allowance sales	29.7			31.1			30.4			31.9
Fuel recovery mechanisms	(8.6		)	(17.2		)	(3.5		)	(5.4		)
Transition costs	(13.3		)	(17.4		)	(7.3		)	(9.6		)
Tax credit carryforwards	217.5			213.7			126.3			116.8
Long-term debt fair value adjustment	—			6.3			—			—
Customer demand programs	(28.7		)	(26.4		)	(19.2		)	(18.6		)
Net operating loss carryforward	439.4			543.7			72.4			77.9
Other	(22.2		)	(10.1		)	(14.1		)	(3.9		)
Net noncurrent deferred income tax liability before valuation allowance	(810.6		)	(605.1		)	(836.4		)	(772.7		)
Valuation allowance	(21.8		)	(23.5		)	—			—
Net noncurrent deferred income tax liability	(832.4		)	(628.6		)	(836.4		)	(772.7		)
Net deferred income tax liability	$	(743.9	)	$	(621.1	)	$	(831.8	)	$	(772.8	)



	Great Plains Energy						KCP&L
December 31	2012			2011			2012			2011
	(millions)
Gross deferred income tax assets	$	1,209.8		$	1,203.6		$	656.9		$	618.7
Gross deferred income tax liabilities	(1,953.7		)	(1,824.7		)	(1,488.7		)	(1,391.5		)
Net deferred income tax liability	$	(743.9	)	$	(621.1	)	$	(831.8	)	$	(772.8	)

Tax Credit Carryforwards

At December 31, 2012 and 2011, Great Plains Energy had $127.6 million and $118.0 million, respectively, of federal general business income tax credit carryforwards. At December 31, 2012 and 2011, KCP&L had $126.3 million and $116.8 million, respectively, of federal general business income tax credit carryforwards. The carryforwards for both Great Plains Energy and KCP&L relate primarily to Advanced Coal Investment Tax Credits and Wind Production tax credits and expire in the years 2028 to 2032. Approximately $0.5 million of Great Plains Energy's credits are related to Low Income Housing credits that were acquired in the GMO acquisition. Due to federal limitations on the utilization of income tax attributes acquired in the GMO acquisition, management expects a portion of these credits to expire unutilized and has provided a valuation allowance against $0.4 million of the federal income tax benefit.

At December 31, 2012 and 2011, Great Plains Energy had $87.9 million and $91.0 million, respectively, of federal alternative minimum tax credit carryforwards. Of these amounts, $87.6 million and $89.8 million, at December 31, 2012 and 2011, respectively, were acquired in the GMO acquisition. These credits do not expire and can be used to reduce taxes paid in the future.

At December 31, 2012 and 2011, Great Plains Energy had $2.0 million and $4.7 million, respectively, of state income tax credit carryforwards. The state income tax credits relate primarily to the Company's Missouri affordable housing investment portfolio, and the carryforwards expire in the years 2013 to 2016. Management expects that a portion of these credits will expire unutilized and has provided a valuation allowance against $0.1 million of the state income tax benefit.

Net Operating Loss Carryforwards

At December 31, 2012 and 2011, Great Plains Energy had $451.1 million and $473.1 million, respectively, of tax benefits related to federal net operating loss (NOL) carryforwards. Approximately $304.8 million and $315.7 million, at December 31, 2012 and 2011, respectively, are tax benefits related to NOLs that were acquired in the GMO acquisition. The tax benefits for NOLs originating in 2003 are $21.7 million, $152.4 million originating in 2004, $74.1 million originating in 2005, $53.3 million originating in 2006, $1.3 million originating in 2007, $2.4 million originating in 2008, $23.8 million originating in 2009, $12.0 million originating in 2010 and $110.1 million originating in 2011. The federal NOL carryforwards expire in years 2023 to 2031.

In addition, Great Plains Energy also had deferred tax benefits of $66.1 million and $70.6 million related to state NOLs as of December 31, 2012 and 2011, respectively. Of these amounts, approximately $47.9 million and $49.9 million at December 31, 2012 and 2011, respectively, were acquired in the GMO acquisition. Management does not expect to utilize $23.3 million of NOLs in state tax jurisdictions where the Company does not expect to operate in the future. Therefore, a valuation allowance has been provided against $23.3 million of state tax benefits.

On January 2, 2013, the American Taxpayer Relief Act of 2012 was enacted. The new law extends the 50% bonus depreciation election to 2013. Due to the additional deductions available for income tax purposes with the extension of bonus depreciation, the Company expects to reduce the current deferred income tax asset for NOLs from $77.8 million at December 31, 2012, to a range of approximately zero to $10.0 million in the first quarter of 2013. The reduction to the current deferred income tax asset for NOLs will be offset by an increase to the noncurrent deferred income tax asset for NOLs, which should result in no impact to net income.

Valuation Allowances

Great Plains Energy is required to assess the ultimate realization of deferred tax assets using a “more likely than not” assessment threshold. This assessment takes into consideration tax planning strategies within Great Plains Energy's control. As a result of this assessment, Great Plains Energy has established a partial valuation allowance for state tax NOL carryforwards, and tax credit carryforwards.

There was no change to the total valuation allowance in 2012. During 2011, a $2.7 million tax benefit was recorded and primarily related to a portion of the valuation allowance against state NOL carryforwards.

Uncertain Tax Positions

At December 31, 2012 and 2011, Great Plains Energy had $21.4 million and $24.0 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $7.3 million and $11.8 million at December 31, 2012 and 2011, respectively, are expected to impact the effective tax rate if recognized. The $2.6 million decrease in unrecognized tax benefits is primarily due to a decrease of $4.5 million of unrecognized tax benefits related to former GMO non-regulated operations.

At December 31, 2010, Great Plains Energy had $42.0 million of liabilities related to unrecognized tax benefits of which $17.3 million was expected to impact the effective tax rate if recognized. The $18.0 million decrease in unrecognized tax benefits in 2011 is primarily due to a decrease of $18.4 million related to the settlement of the IRS audit for Great Plains Energy's 2006-2008 tax years. The $18.4 million tax benefit recognized related to the 2006-2008 audit was offset by an increase of $16.4 million in deferred income tax liabilities since a significant portion of the unrecognized tax benefits were related to temporary tax differences, which resulted in an increase to net income of $2.0 million.

At December 31, 2012 and 2011, KCP&L had $10.5 million and $8.7 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, none and $0.2 million at December 31, 2012 and 2011, respectively, are expected to impact the effective tax rate if recognized. The $1.8 million increase in unrecognized tax benefits is primarily due to an increase of $3.6 million related to temporary tax differences for the current tax year.

At December 31, 2010, KCP&L had $19.1 million of liabilities related to unrecognized tax benefits of which $0.3 million was expected to impact the effective rate if recognized. The $10.4 million decrease in unrecognized tax benefits in 2011 was primarily due to a decrease of $12.1 million related to the settlement of the IRS audit for Great Plains Energy's 2006-2008 tax years. The tax benefit recognized related to the 2006-2008 audit was offset by an increase in deferred income tax liabilities which resulted in an insignificant impact to net income.

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
	2012			2011			2010			2012			2011			2010
	(millions)
Beginning balance January 1	$	24.0		$	42.0		$	51.4		$	8.7		$	19.1		$	20.9
Additions for current year tax positions	3.7			1.4			2.7			3.6			—			1.3
Additions for prior year tax positions	—			2.4			2.1			—			2.3			1.5
Reductions for prior year tax positions	(1.8		)	(20.9		)	(10.6		)	(1.6		)	(12.6		)	(1.6		)
Settlements	—			—			(3.8		)	—			—			(2.9		)
Statute expirations	(4.7		)	(0.7		)	(0.3		)	(0.2		)	(0.1		)	(0.1		)
Foreign currency translation adjustments	0.2			(0.2		)	0.5			—			—			—
Ending balance December 31	$	21.4		$	24.0		$	42.0		$	10.5		$	8.7		$	19.1

Great Plains Energy and KCP&L recognize interest related to unrecognized tax benefits in interest expense and penalties in non-operating expenses. At December 31, 2012, 2011 and 2010, accrued interest related to unrecognized tax benefits for Great Plains Energy was $3.5 million, $5.7 million and $6.7 million, respectively. Amounts accrued for penalties with respect to unrecognized tax benefits for Great Plains Energy was $0.7 million at December 31, 2012, and $1.1 million at December 31, 2011 and 2010. In 2012 and 2011, Great Plains Energy recognized a decrease of $2.3 million and $0.9 million, respectively, of interest expense related to unrecognized tax benefits. In 2010, Great Plains Energy recognized an increase of interest expense related to unrecognized tax benefits of $0.5 million.

KCP&L had accrued interest related to unrecognized tax benefits of $0.1 million, $0.2 million and $1.4 million, at December 31, 2012, 2011 and 2010, respectively. Amounts accrued for penalties with respect to unrecognized tax benefits for KCP&L are insignificant. In 2012, 2011 and 2010, KCP&L recognized a decrease of $0.1 million, $1.2 million and $0.3 million, respectively, of interest expense related to unrecognized tax benefits.

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 $5.5 million and $4.4 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

Segments and Related Information

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

21. 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 and unallocated corporate charges. 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.



2012	Electric Utility				Other				Eliminations			Great Plains Energy
		(millions)
Operating revenues		$	2,309.9			$	—			$	—		$	2,309.9
Depreciation and amortization		(272.3		)		—				—			(272.3		)
Interest charges		(197.3		)		(67.3		)		43.8			(220.8		)
Income tax (expense) benefit		(122.0		)		17.4				—			(104.6		)
Net income (loss) attributable to Great Plains Energy		216.6				(16.7		)		—			199.9



2011	Electric Utility				Other				Eliminations			Great Plains Energy
		(millions)
Operating revenues		$	2,318.0			$	—			$	—		$	2,318.0
Depreciation and amortization		(273.1		)		—				—			(273.1		)
Interest charges		(176.9		)		(67.2		)		25.7			(218.4		)
Income tax (expense) benefit		(109.3		)		24.5				—			(84.8		)
Net income (loss) attributable to Great Plains Energy		199.9				(25.5		)		—			174.4



2010	Electric Utility				Other				Eliminations			Great Plains Energy
		(millions)
Operating revenues		$	2,255.5			$	—			$	—		$	2,255.5
Depreciation and amortization		(331.6		)		—				—			(331.6		)
Interest charges		(143.1		)		(45.5		)		3.8			(184.8		)
Income tax (expense) benefit		(123.3		)		24.3				—			(99.0		)
Net income (loss) attributable to Great Plains Energy		235.3				(23.6		)		—			211.7



	Electric Utility			Other			Eliminations				Great Plains Energy
2012		(millions)
Assets		$	9,910.6		$	122.4		$	(385.7	)		$	9,647.3
Capital expenditures		610.2			—			—				610.2
2011
Assets		$	9,483.4		$	51.9		$	(417.3	)		$	9,118.0
Capital expenditures		456.6			—			—				456.6
2010
Assets		$	9,152.7		$	66.3		$	(400.8	)		$	8,818.2
Capital expenditures		618.1			—			—				618.1

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-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.

Jointly Owned Electric Utility Plants [Abstract]

Jointly Owned Electric Utility Plants

12 Months Ended

Dec. 31, 2012

Jointly Owned Electric Utility Plants [Text Block]

22. JOINTLY-OWNED ELECTRIC UTILITY PLANTS

Great Plains Energy's and KCP&L's share of jointly-owned electric utility plants at December 31, 2012, are detailed in the following tables.



Great Plains Energy
	Wolf Creek Unit			La Cygne Units			Iatan No. 1 Unit			Iatan No. 2 Unit			Iatan Common			Jeffrey Energy Center
	(millions, except MW amounts)
Great Plains Energy's share		47%			50%			88%			73%			79%			8%

Utility plant in service		$	1,483.6		$	504.5		$	667.5		$	1,297.9		$	374.9		$	167.2
Accumulated depreciation		801.1			308.6			264.9			294.7			42.9			75.2
Nuclear fuel, net		81.3			—			—			—			—			—
Construction work in progress		99.8			262.0			14.1			5.7			25.9			6.3
2013 accredited capacity-MWs		547			711			620			641			NA			172



KCP&L
	Wolf Creek Unit			La Cygne Units			Iatan No. 1 Unit			Iatan No. 2 Unit			Iatan Common
	(millions, except MW amounts)
KCP&L's share		47%			50%			70%			55%			61%

Utility plant in service		$	1,483.6		$	504.5		$	541.3		$	987.2		$	295.3
Accumulated depreciation		801.1			308.6			217.6			279.6			36.8
Nuclear fuel, net		81.3			—			—			—			—
Construction work in progress		99.8			262.0			5.5			4.5			6.9
2013 accredited capacity-MWs		547			711			493			482			NA

Each owner must fund its own portion of the plant's operating expenses and capital expenditures. KCP&L's and GMO's share of direct expenses are included in the appropriate operating expense classifications in Great Plains Energy's and KCP&L's financial statements.

Quarterly Operating Results (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

23. QUARTERLY OPERATING RESULTS (UNAUDITED)



	Quarter
Great Plains Energy	1st			2nd		3rd		4th
2012	(millions, except per share amounts)
Operating revenue	$	479.7		$	603.6	$	746.2	$	480.4
Operating income	49.0			150.0		277.0		62.9
Net income (loss)	(9.3		)	58.1		146.4		4.7
Net income (loss) attributable to Great Plains Energy	(9.1		)	58.1		146.2		4.7
Basic and diluted earnings (loss) per common share	(0.07		)	0.41		0.95		0.03
2011
Operating revenue	$	492.9		$	565.1	$	773.7	$	486.3
Operating income	41.2			115.6		262.7		60.3
Net income	2.3			43.4		126.6		1.9
Net income attributable to Great Plains Energy	2.4			43.4		126.5		2.1
Basic earnings per common share	0.02			0.32		0.93		0.01
Diluted earnings per common share	0.01			0.31		0.91		0.01



	Quarter
KCP&L	1st		2nd		3rd		4th
2012	(millions)
Operating revenue	$	327.0	$	409.1	$	508.0	$	335.8
Operating income	31.6		99.9		177.8		39.4
Net income	2.3		43.7		90.2		5.4
2011
Operating revenue	$	330.8	$	383.4	$	506.3	$	337.8
Operating income	26.5		77.8		169.2		47.7
Net income	4.0		33.4		85.4		12.7

Quarterly data is subject to seasonal fluctuations with peak periods occurring in the summer months.

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

Schedule I Financial Statements of Parent Company

12 Months Ended

Dec. 31, 2012

Parent Company [Member]

Schedule I - Parent Company Financial Statements



GREAT PLAINS ENERGY INCORPORATED
Statements of Income and Comprehensive Income of Parent Company

Year Ended December 31	2012			2011			2010
Operating Expenses	(millions, except per share amounts)
General and administrative	$	3.3		$	0.8		$	1.2
General taxes	0.7			0.9			0.9
Total	4.0			1.7			2.1
Operating loss	(4.0		)	(1.7		)	(2.1		)
Equity in earnings from subsidiaries	219.2			200.8			239.3
Non-operating income	42.7			24.7			3.4
Interest charges	(69.6		)	(66.5		)	(44.7		)
Income before income taxes	188.3			157.3			195.9
Income tax benefit	11.6			17.1			15.8
Net income	199.9			174.4			211.7
Preferred stock dividend requirements	1.6			1.6			1.6
Earnings available for common shareholders	$	198.3		$	172.8		$	210.1

Average number of basic common shares outstanding	145.5			135.6			135.1
Average number of diluted common shares outstanding	147.2			138.7			136.9

Basic earnings per common share	$	1.36		$	1.27		$	1.55
Diluted earnings per common share	$	1.35		$	1.25		$	1.53

Cash dividends per common share	$	0.855		$	0.835		$	0.83
Comprehensive Income
Net income	$	199.9		$	174.4		$	211.7
Other comprehensive income
Derivative hedging activity
Loss on derivative hedging instruments	—			(5.3		)	(27.1		)
Income tax benefit	—			2.1			10.5
Net loss on derivative hedging instruments	—			(3.2		)	(16.6		)
Reclassification to expenses	11.5			8.2			1.3
Income tax benefit	(4.6		)	(3.2		)	(0.4		)
Net reclassification to expenses	6.9			5.0			0.9
Derivative hedging activity, net of tax	6.9			1.8			(15.7		)
Other comprehensive income from subsidiaries, net of tax	4.5			4.5			4.5
Total other comprehensive income (loss)	11.4			6.3			(11.2		)
Comprehensive income attributable to Great Plains Energy	$	211.3		$	180.7		$	200.5

The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.



GREAT PLAINS ENERGY INCORPORATED
Balance Sheets of Parent Company

	December 31
	2012				2011
ASSETS	(millions, except share amounts)
Current Assets
Accounts receivable from subsidiaries		$	0.1			$	—
Notes receivable from subsidiaries		0.6				0.6
Money pool receivable		4.0				0.9
Taxes receivable		—				0.9
Other		2.4				0.6
Total		7.1				3.0
Investments and Other Assets
Investment in KCP&L		2,096.7				2,045.5
Investment in other subsidiaries		1,405.4				1,377.0
Note receivable from subsidiaries		883.6				596.2
Deferred income taxes		32.3				33.7
Other		7.6				6.4
Total		4,425.6				4,058.8
Total		$	4,432.7			$	4,061.8

LIABILITIES AND CAPITALIZATION
Current Liabilities
Notes payable		$	12.0			$	22.0
Current maturities of long-term debt		250.0				287.5
Accounts payable to subsidiaries		34.1				31.8
Accrued taxes		0.5				5.1
Accrued interest		6.8				7.6
Other		2.1				2.9
Total		305.5				356.9
Deferred Credits and Other Liabilities		5.2				6.7
Capitalization
Great Plains Energy common shareholders' equity
Common stock - 250,000,000 shares authorized without par value
153,779,806 and 136,406,306 shares issued, stated value		2,624.7				2,330.6
Retained earnings		758.8				684.7
Treasury stock - 250,236 and 264,567 shares, at cost		(5.1		)		(5.6		)
Accumulated other comprehensive loss		(38.4		)		(49.8		)
Total		3,340.0				2,959.9
Cumulative preferred stock $100 par value
3.80% - 100,000 shares issued		10.0				10.0
4.50% - 100,000 shares issued		10.0				10.0
4.20% - 70,000 shares issued		7.0				7.0
4.35% - 120,000 shares issued		12.0				12.0
Total		39.0				39.0
Long-term debt		743.0				699.3
Total		4,122.0				3,698.2
Commitments and Contingencies
Total		$	4,432.7			$	4,061.8

The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.



GREAT PLAINS ENERGY INCORPORATED
Statements of Cash Flows of Parent Company

Year Ended December 31	2012			2011			2010
Cash Flows from Operating Activities	(millions)
Net income	$	199.9		$	174.4		$	211.7
Adjustments to reconcile income to net cash from operating activities:
Amortization	12.6			11.2			3.9
Deferred income taxes, net	(4.8		)	(18.6		)	13.9
Equity in earnings from subsidiaries	(219.2		)	(200.8		)	(239.3		)
Cash flows affected by changes in:
Accounts receivable from subsidiaries	(0.1		)	—			(2.6		)
Taxes receivable	0.9			6.3			—
Accounts payable to subsidiaries	2.3			(0.3		)	2.2
Other accounts payable	—			—			(0.1		)
Accrued taxes	(4.4		)	5.2			—
Accrued interest	6.1			1.2			2.7
Cash dividends from subsidiaries	144.0			148.0			138.6
Interest rate hedge settlement	—			(26.1		)	(6.9		)
Other	2.7			2.1			(0.9		)
Net cash from operating activities	140.0			102.6			123.2
Cash Flows from Investing Activities
Intercompany lending	(287.4		)	(347.4		)	(248.8		)
Net money pool lending	(3.1		)	1.1			(1.1		)
Net cash from investing activities	(290.5		)	(346.3		)	(249.9		)
Cash Flows from Financing Activities
Issuance of common stock	293.0			5.9			6.2
Issuance of long-term debt	—			349.7			249.9
Issuance fees	(2.7		)	(3.2		)	(3.2		)
Net change in short-term borrowings	(10.0		)	12.5			(10.5		)
Dividends paid	(125.5		)	(115.1		)	(114.2		)
Other financing activities	(4.3		)	(6.4		)	(7.3		)
Net cash from financing activities	150.5			243.4			120.9
Net Change in Cash and Cash Equivalents	—			(0.3		)	(5.8		)
Cash and Cash Equivalents at Beginning of Year	—			0.3			6.1
Cash and Cash Equivalents at End of Year	$	—		$	—		$	0.3

The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED

NOTES TO FINANCIAL STATEMENTS OF PARENT COMPANY

The Great Plains Energy Incorporated Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Great Plains Energy Incorporated Parent Company Financial Statements.

The Great Plains Energy Incorporated Parent Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Great Plains Energy on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

Valuation and Qualifying Accounts [Abstract]

Schedule II Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2012

Schedule II Valuation and Qualifying Accounts



Great Plains Energy Incorporated
Valuation and Qualifying Accounts
Years Ended December 31, 2012, 2011 and 2010

				Additions
				Charged
	Balance At			To Costs				Charged								Balance
	Beginning			And				To Other								At End
Description	Of Period			Expenses				Accounts				Deductions				Of Period
Year Ended December 31, 2012	(millions)
Allowance for uncollectible accounts		$	6.8		$	12.0			$	7.8	^(a)		$	19.7	^(b)		$	6.9
Legal reserves		6.7			(0.2		)		—				1.9		^(c)		4.6
Environmental reserves		2.5			—				—				0.2				2.3
Tax valuation allowance		23.9			0.3				—				0.4		^(d)		23.8
Year Ended December 31, 2011
Allowance for uncollectible accounts		$	7.0		$	13.7			$	6.9	^(a)		$	20.8	^(b)		$	6.8
Legal reserves		10.2			(0.1		)		—				3.4		^(c)		6.7
Environmental reserves		2.5			—				—				—				2.5
Tax valuation allowance		26.6			0.1				—				2.8		^(d)		23.9
Year Ended December 31, 2010
Allowance for uncollectible accounts		$	7.1		$	9.7			$	6.9	^(a)		$	16.7	^(b)		$	7.0
Legal reserves		5.1			7.0				—				1.9		^(c)		10.2
Environmental reserves		2.4			0.1				—				—				2.5
Tax valuation allowance		29.8			0.2				—				3.4		^(d)		26.6

(a) Recoveries.

(b) Uncollectible accounts charged off.

(d) Reversal of tax valuation allowance.



Kansas City Power & Light Company
Valuation and Qualifying Accounts
Years Ended December 31, 2012, 2011 and 2010

				Additions
				Charged
	Balance At			To Costs			Charged								Balance
	Beginning			And			To Other								At End
Description	Of Period			Expenses			Accounts				Deductions				Of Period
Year Ended December 31, 2012	(millions)
Allowance for uncollectible accounts		$	1.4		$	7.9		$	5.2	^(a)		$	13.0	^(b)		$	1.5
Legal reserves		3.9			0.5			—				1.5		^(c)		2.9
Environmental reserves		0.3			—			—				—				0.3
Year Ended December 31, 2011
Allowance for uncollectible accounts		$	1.5		$	8.8		$	4.5	^(a)		$	13.4	^(b)		$	1.4
Legal reserves		3.0			1.3			—				0.4		^(c)		3.9
Environmental reserves		0.3			—			—				—				0.3
Year Ended December 31, 2010
Allowance for uncollectible accounts		$	1.7		$	6.2		$	4.3	^(a)		$	10.7	^(b)		$	1.5
Legal reserves		2.3			1.9			—				1.2		^(c)		3.0
Environmental reserves		0.3			—			—				—				0.3

(a) Recoveries.

(b) Uncollectible accounts charged off.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Organization [Policy Text Block]

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 21 for additional information.

Use of Estimates [Policy Text Block]

Use of Estimates

Cash and Cash Equivalents [Policy Text Block]

Cash and Cash Equivalents

Cash equivalents consist of highly liquid investments with original maturities of three months or less at acquisition.

Funds on Deposit [Policy Text Block]

Funds on Deposit

Fair Value of Financial Instruments [Policy Text Block]

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it is practicable to estimate that value.

Derivative Instruments [Policy Text Block]

Derivative Instruments

Utility Plant [Policy Text Block]

Utility Plant

Great Plains Energy's and KCP&L's balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following tables.



Great Plains Energy
December 31	2012		2011
Utility plant, at original cost	(millions)
Generation (20 - 60 years)	$	6,697.1	$	6,594.0
Transmission (15 - 70 years)	754.0		734.8
Distribution (8 - 66 years)	3,019.6		2,921.1
General (5 - 50 years)	689.8		674.9
Total ^(a)	$	11,160.5	$	10,924.8

^(a) Includes $104.5 million and $105.5 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.



KCP&L
December 31	2012		2011
Utility plant, at original cost	(millions)
Generation (20 - 60 years)	$	5,140.0	$	5,078.1
Transmission (15 - 70 years)	414.7		412.9
Distribution (8 - 55 years)	1,893.8		1,840.2
General (5 - 50 years)	522.9		498.1
Total ^(a)	$	7,971.4	$	7,829.3

^(a) Includes $54.7 million and $59.8 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.

Depreciation and Amortization [Policy Text Block]

Depreciation and Amortization

Nuclear Plant Decommissioning Costs [Policy Text Block]

Nuclear Plant Decommissioning Costs

Deferred Refueling Outage Costs [Policy Text Block]

Deferred Refueling Outage Costs

Regulatory Matters [Policy Text Block]

Regulatory Matters

Revenue Recognition [Policy Text Block]

Revenue Recognition

Allowance for Doubtful Accounts [Policy Text Block]

Allowance for Doubtful Accounts This reserve represents estimated uncollectible accounts receivable and is based on management's judgment considering historical loss experience and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are charged off against the reserve when they are deemed uncollectible.

Property Gains and Losses [Policy Text Block]

Property Gains and Losses

Net gains and losses from the sale of assets and businesses and from asset impairments are recorded in operating expenses.

Asset Impairments [Policy Text Block]

Asset Impairments

Income Taxes [Policy Text Block]

Income Taxes

Environmental Matters [Policy Text Block]

Environmental Matters

Environmental costs are accrued when it is probable a liability has been incurred and the amount of the liability can be reasonably estimated.

Basic and Diluted Earnings per Common Share Calculation [Policy Text Block]

Basic and Diluted Earnings per Common Share Calculation

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



	2012		2011			2010
Income	(millions, except per share amounts)
Net income	$	199.9	$	174.2		$	211.9
Less: net income (loss) attributable to noncontrolling interest	—		(0.2		)	0.2
Less: preferred stock dividend requirements	1.6		1.6			1.6
Earnings available for common shareholders	$	198.3	$	172.8		$	210.1
Common Shares Outstanding
Average number of common shares outstanding	145.5		135.6			135.1
Add: effect of dilutive securities	1.7		3.1			1.8
Diluted average number of common shares outstanding	147.2		138.7			136.9
Basic EPS	$	1.36	$	1.27		$	1.55
Diluted EPS	$	1.35	$	1.25		$	1.53

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



	2012	2011	2010
Performance shares	—	50,897	340,690
Restricted stock shares	3,781	43,641	251,526
Stock options	—	6,000	196,137

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Schedule of Public Utility Property, Plant, and Equipment [Table Text Block]

Great Plains Energy's and KCP&L's balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following tables.



Great Plains Energy
December 31	2012		2011
Utility plant, at original cost	(millions)
Generation (20 - 60 years)	$	6,697.1	$	6,594.0
Transmission (15 - 70 years)	754.0		734.8
Distribution (8 - 66 years)	3,019.6		2,921.1
General (5 - 50 years)	689.8		674.9
Total ^(a)	$	11,160.5	$	10,924.8

^(a) Includes $104.5 million and $105.5 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.



KCP&L
December 31	2012		2011
Utility plant, at original cost	(millions)
Generation (20 - 60 years)	$	5,140.0	$	5,078.1
Transmission (15 - 70 years)	414.7		412.9
Distribution (8 - 55 years)	1,893.8		1,840.2
General (5 - 50 years)	522.9		498.1
Total ^(a)	$	7,971.4	$	7,829.3

^(a) Includes $54.7 million and $59.8 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

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



	2012		2011			2010
Income	(millions, except per share amounts)
Net income	$	199.9	$	174.2		$	211.9
Less: net income (loss) attributable to noncontrolling interest	—		(0.2		)	0.2
Less: preferred stock dividend requirements	1.6		1.6			1.6
Earnings available for common shareholders	$	198.3	$	172.8		$	210.1
Common Shares Outstanding
Average number of common shares outstanding	145.5		135.6			135.1
Add: effect of dilutive securities	1.7		3.1			1.8
Diluted average number of common shares outstanding	147.2		138.7			136.9
Basic EPS	$	1.36	$	1.27		$	1.55
Diluted EPS	$	1.35	$	1.25		$	1.53

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.



	2012	2011	2010
Performance shares	—	50,897	340,690
Restricted stock shares	3,781	43,641	251,526
Stock options	—	6,000	196,137

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]



Great Plains Energy Other Operating Activities
Year Ended December 31	2012			2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	76.8		$	3.6		$	(12.6	)
Accounts receivable pledged as collateral	(79.0		)	—			(95.0		)
Fuel inventories	(6.1		)	(3.9		)	(0.1		)
Materials and supplies	(11.0		)	(7.5		)	(11.5		)
Accounts payable	57.3			5.7			12.8
Accrued taxes	(7.8		)	1.4			6.7
Accrued interest	(35.2		)	1.5			2.9
Deferred refueling outage costs	15.6			(17.9		)	9.9
Fuel recovery mechanism	22.5			(1.7		)	2.7
Pension and post-retirement benefit obligations	14.4			(56.0		)	(10.2		)
Allowance for equity funds used during construction	(1.3		)	(1.0		)	(26.0		)
Write down of affordable housing investments	—			—			11.2
Interest rate hedge settlements	—			(26.1		)	(6.9		)
Iatan Nos. 1 and 2 impact of disallowed construction costs	—			2.3			16.8
Uncertain tax positions	(4.7		)	(20.8		)	(6.1		)
Other	(29.8		)	(27.1		)	(28.3		)
Total other operating activities	$	11.7		$	(147.5	)	$	(133.7	)
Cash paid during the period:
Interest	$	247.9		$	254.4		$	237.7
Income taxes	$	3.3		$	2.8		$	0.9
Non-cash investing activities:
Liabilities accrued for capital expenditures	$	57.5		$	39.7		$	44.9



KCP&L Other Operating Activities
Year Ended December 31	2012			2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	8.8		$	(20.2	)	$	(4.1	)
Accounts receivable pledged as collateral	(15.0		)	—			(95.0		)
Fuel inventories	(4.6		)	(14.1		)	0.7
Materials and supplies	(9.0		)	(6.7		)	(9.6		)
Accounts payable	48.3			11.0			0.8
Accrued taxes	(2.0		)	2.7			(15.7		)
Accrued interest	(2.3		)	3.8			(0.5		)
Deferred refueling outage costs	15.6			(17.9		)	9.9
Pension and post-retirement benefit obligations	18.0			(45.6		)	7.9
Allowance for equity funds used during construction	(1.3		)	(0.7		)	(21.9		)
Fuel recovery mechanism	5.1			(5.8		)	(8.8		)
Iatan Nos. 1 and 2 impact of disallowed construction costs	—			1.5			13.0
Uncertain tax positions	1.8			(10.4		)	(1.8		)
Other	(35.5		)	(15.9		)	(2.7		)
Total other operating activities	$	27.9		$	(118.3	)	$	(127.8	)
Cash paid during the period:
Interest	$	118.0		$	111.3		$	101.1
Income taxes	$	18.0		$	0.1		$	18.2
Non-cash investing activities:
Liabilities accrued for capital expenditures	$	48.4		$	32.0		$	37.4

Receivables (Tables)

12 Months Ended

Dec. 31, 2012

Receivables [Abstract]

Schedule of receivables [Table Text Block]

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



	December 31
	2012			2011
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	—		$	69.8
Customer accounts receivable - unbilled	58.3			82.4
Allowance for doubtful accounts - customer accounts receivable	(2.6		)	(2.5		)
Other receivables	98.8			81.5
Total	$	154.5		$	231.2
KCP&L
Customer accounts receivable - billed	$	—		$	16.4
Customer accounts receivable - unbilled	42.9			50.0
Allowance for doubtful accounts - customer accounts receivable	(1.5		)	(1.4		)
Intercompany receivables	40.0			38.7
Other receivables	81.8			69.2
Total	$	163.2		$	172.9

Schedule of accounts receivable sold [Table Text Block]

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.



2012	KCP&L				KCP&L Receivables Company				Consolidated KCP&L				GMO				GMO Receivables Company				Consolidated Great Plains Energy
	(millions)
Receivables (sold) purchased		$	(1,436.0	)		$	1,436.0			$	—			$	(597.8	)		$	597.8			$	—
Gain (loss) on sale of accounts receivable ^(a)		(18.2		)		18.3				0.1				(7.6		)		6.6				(0.9		)
Servicing fees received (paid)		2.5				(2.5		)		—				0.9				(0.9		)		—
Fees paid to outside investor		—				(1.2		)		(1.2		)		—				(0.5		)		(1.7		)
Cash from customers (transferred) received		(1,452.4		)		1,452.4				—				(524.0		)		524.0				—
Cash received from (paid for) receivables purchased		1,434.2				(1,434.2		)		—				517.5				(517.5		)		—
Interest on intercompany note received (paid)		0.3				(0.3		)		—				0.1				(0.1		)		—



2011		KCP&L				KCP&L Receivables Company				Consolidated KCP&L
	(millions)
Receivables (sold) purchased			$	(1,415.6	)		$	1,415.6			$	—
Gain (loss) on sale of accounts receivable ^(a)			(17.9		)		17.7				(0.2		)
Servicing fees received (paid)			2.6				(2.6		)		—
Fees paid to outside investor			—				(1.2		)		(1.2		)
Cash from customers (transferred) received			(1,412.4		)		1,412.4				—
Cash received from (paid for) receivables purchased			1,394.7				(1,394.7		)		—
Interest on intercompany note received (paid)			0.5				(0.5		)		—

^(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)

12 Months Ended

Dec. 31, 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.



	2012			2011
Decommissioning Trust		(millions)
Beginning balance January 1		$	135.3		$	129.2
Contributions		3.3			3.4
Earned income, net of fees		3.0			4.8
Net realized gains		1.0			0.3
Net unrealized gains (losses)		12.1			(2.4		)
Ending balance December 31		$	154.7		$	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.



	December 31
	2012													2011
	Cost Basis		Unrealized Gains			Unrealized Losses				Fair Value			Cost Basis			Unrealized Gains			Unrealized Losses				Fair Value
	(millions)
Equity securities	$	80.6		$	21.1		$	(1.6	)		$	100.1		$	76.5		$	12.3		$	(4.5	)		$	84.3
Debt securities	46.6			4.9			(0.1		)		51.4			44.2			4.5			(0.1		)		48.6
Other	3.2			—			—				3.2			2.4			—			—				2.4
Total	$	130.4		$	26.0		$	(1.7	)		$	154.7		$	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.



	2012			2011			2010
	(millions)
Realized gains	$	1.7		$	1.0		$	7.3
Realized losses	(0.7		)	(0.7		)	(0.6		)

Nuclear Plant Decommissioning Costs



	Total Station			KCP&L's 47% Share
	(millions)
Current cost of decommissioning (in 2011 dollars)		$	630		$	296
Future cost of decommissioning (in 2045-2053 dollars) ^(a)		1,788			840

Annual escalation factor	2.85%
Annual return on trust assets ^(b)	5.46%

^(a)Total future cost over an eight year decommissioning period

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2012

Regulated Operations [Abstract]

Regulatory assets



	December 31
	2012								2011
	KCP&L			GMO			Great Plains Energy		KCP&L		GMO		Great Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	114.7		$	23.7		$	138.4	$	119.6	$	24.6	$	144.2
Loss on reacquired debt	8.1		^(a)	2.0		^(a)	10.1		9.1		2.7		11.8
Cost of removal	2.8			—			2.8		4.6		—		4.6
Asset retirement obligations	31.5			14.9			46.4		31.4		13.8		45.2
Pension and post-retirement costs	541.2		^(b)	129.7		^(b)	670.9		466.4		122.0		588.4
Deferred customer programs	49.8		^(c)	24.6		^(d)	74.4		48.2		20.6		68.8
Rate case expenses	7.5		^(e)	1.7		^(f)	9.2		9.6		3.8		13.4
Fuel recovery mechanisms	8.9		^(e)	16.9		^(e)	25.8		14.0		36.4		50.4
Acquisition transition costs	18.7		^(g)	15.5		^(g)	34.2		24.7		20.2		44.9
Derivative instruments	—			3.7		^(h)	3.7		—		7.6		7.6
Iatan No. 1 and common facilities depreciation and carrying costs	15.9		⁽ⁱ⁾	5.9		⁽ⁱ⁾	21.8		16.4		6.1		22.5
Iatan No. 2 construction accounting costs	30.6		^(j)	16.2		^(j)	46.8		27.9		15.4		43.3
Kansas property tax surcharge	5.4		^(e)	—			5.4		3.7		—		3.7
Solar rebates	5.8		^(k)	10.0		^(k)	15.8		—		—		—
Voluntary separation program	4.3		^(l)	—			4.3		—		—		—
Other	8.0		^(e)	2.9		^(e)	10.9		5.1		4.3		9.4
Total	$	853.2		$	267.7		$	1,120.9	$	780.7	$	277.5	$	1,058.2

Regulatory liabilities



	December 31
	2012			2011
	KCP&L	GMO	Great Plains Energy	KCP&L	GMO	Great Plains Energy

Regulatory Liabilities
Emission allowances	78.0	0.1	78.1	82.0	0.2	82.2
Asset retirement obligations	63.1	—	63.1	49.3	—	49.3
Pension	1.5	44.6	46.1	0.7	40.8	41.5
Cost of removal	—	64.0	64.0	—	61.9	61.9
Other	10.4	22.1	32.5	10.8	22.8	33.6
Total	153.0	130.8	283.8	142.8	125.7	268.5

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

^(b)Represents unrecognized gains and losses, prior service and transition costs that will be recognized in future net periodic pension and post-retirement costs, pension settlements amortized over various periods and financial and regulatory accounting method differences that will be eliminated over the life of the pension plans. Of these amounts, $526.5 million and $127.1 million for KCP&L and GMO, respectively, are not included in rate base and are amortized over various periods.

^(c)$5.0 million not included in rate base and amortized over various periods.

^(d)Included in rate base and amortized through 2019.

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

^(f)Not included in rate base and amortized through 2014.

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

^(h)Represents the fair value of derivative instruments for commodity contracts. Settlements of the contracts are recognized in fuel expense and included in GMO's Fuel Adjustment Clause (FAC).

⁽ⁱ⁾Included in rate base and amortized through 2038.

^(j)Included in rate base and amortized through 2058.

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

^(l)Not included in rate base and amortized through 2017.

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

Goodwill and Intangible Assets Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets [Table Text Block]

Great Plains Energy's and KCP&L's intangible assets are included in electric utility plant on the consolidated balance sheets and are detailed in the following table.



		December 31, 2012							December 31, 2011
	Gross Carrying Amount			Accumulated Amortization				Gross Carrying Amount			Accumulated Amortization
Great Plains Energy	(millions)
Computer software		$	211.2		$	(152.9	)		$	202.5		$	(143.5	)
Asset improvements		26.5			(4.2		)		27.0			(3.7		)

KCP&L
Computer software		$	189.9		$	(142.9	)		$	171.7		$	(129.9	)
Asset improvements		11.2			(0.8		)		11.7			(0.6		)

Amortization Expense Related to Intangible Assets [Table Text Block]

Great Plains Energy's and KCP&L's amortization expense related to intangible assets is detailed in the following table.



	2012		2011
	(millions)
Great Plains Energy	$	15.6	$	13.5
KCP&L	13.2		12.6

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]



	2013		2014		2015		2016		2017
	(millions)
Great Plains Energy	$	14.5	$	11.1	$	8.8	$	7.4	$	4.1
KCP&L	11.9		8.6		6.5		5.2		3.6

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following table summarizes the change in Great Plains Energy's and KCP&L's AROs.



	Great Plains Energy						KCP&L
	2012			2011			2012			2011
	(millions)
Beginning balance	$	149.6		$	143.3		$	134.3		$	129.7
Additions	—			0.8			—			—
Revision in timing and/or estimates	(7.7		)	(3.8		)	(7.7		)	(3.8		)
Settlements	(1.8		)	—			(1.8		)	—
Accretion	9.2			9.3			8.4			8.4
Ending balance	$	149.3		$	149.6		$	133.2		$	134.3

Pension Plans and Other Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Defined Benefit Plan Disclosure [Line Items]

Fair value of assets using significant unobservable inputs

The following table reconciles the beginning and ending balances for all Level 3 assets and liabilities, net, measured at fair value on a recurring basis for 2012 and 2011.



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	8.2			10.9
Settlements	(9.0		)	(11.5		)
Balance at December 31	$	2.3		$	3.1
Total unrealized losses included in non-operating income relating to assets
and liabilities still on the consolidated balance sheet at December 31	$	(0.4	)	$	(0.2	)

Schedule of Net Funded Status [Table Text Block]



	Pension Benefits						Other Benefits
	2012			2011			2012			2011
Change in projected benefit obligation (PBO)	(millions)
PBO at beginning of year	$	980.6		$	911.4		$	154.2		$	143.6
Service cost	35.4			31.1			3.3			3.1
Interest cost	48.9			49.6			7.8			7.8
Contribution by participants	—			—			6.7			6.6
Amendments	1.1			—			—			—
Actuarial loss	127.0			83.2			26.7			7.4
Benefits paid	(58.1		)	(54.7		)	(12.2		)	(14.3		)
Settlements	(4.4		)	(40.0		)	—			—
PBO at end of plan year	$	1,130.5		$	980.6		$	186.5		$	154.2
Change in plan assets
Fair value of plan assets at beginning of year	$	591.1		$	557.6		$	77.4		$	65.8
Actual return on plan assets	71.2			(3.7		)	1.4			2.5
Contributions by employer and participants	60.4			128.8			23.7			23.0
Benefits paid	(56.3		)	(91.6		)	(12.2		)	(13.9		)
Fair value of plan assets at end of plan year	$	666.4		$	591.1		$	90.3		$	77.4
Funded status at end of year	$	(464.1	)	$	(389.5	)	$	(96.2	)	$	(76.8	)
Amounts recognized in the consolidated balance sheets
Current pension and other post-retirement liability	$	(1.9	)	$	(3.5	)	$	(0.9	)	$	(0.9	)
Noncurrent pension liability and other post-retirement liability	(462.2		)	(386.0		)	(95.3		)	(75.9		)
Net amount recognized before regulatory treatment	(464.1		)	(389.5		)	(96.2		)	(76.8		)
Accumulated OCI or regulatory asset/liability	559.5			491.8			70.4			52.5
Net amount recognized at December 31	$	95.4		$	102.3		$	(25.8	)	$	(24.3	)
Amounts in accumulated OCI or regulatory asset/liability not yet recognized as a component of net periodic benefit cost:
Actuarial loss	$	349.0		$	295.6		$	43.0		$	15.7
Prior service cost	7.3			10.7			29.8			36.9
Transition obligation	—			—			0.6			1.7
Other	203.2			185.5			(3.0		)	(1.8		)
Net amount recognized at December 31	$	559.5		$	491.8		$	70.4		$	52.5

Schedule of Net Benefit Costs [Table Text Block]



	Pension Benefits									Other Benefits
	2012			2011			2010			2012			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	35.4		$	31.1		$	30.3		$	3.3		$	3.1		$	3.8
Interest cost	48.9			49.6			49.3			7.8			7.8			8.8
Expected return on plan assets	(42.9		)	(38.0		)	(36.6		)	(1.8		)	(1.8		)	(2.1		)
Prior service cost	4.5			4.6			4.6			7.1			7.2			7.2
Recognized net actuarial (gain) loss	44.5			38.7			37.4			(0.2		)	(0.5		)	(0.1		)
Transition obligation	—			—			0.1			1.1			1.3			1.3
Settlement charges	0.8			10.1			—			—			—			—
Net periodic benefit costs before regulatory adjustment	91.2			96.1			85.1			17.3			17.1			18.9
Regulatory adjustment	(15.5		)	(27.9		)	(32.3		)	1.5			1.1			—
Net periodic benefit costs	75.7			68.2			52.8			18.8			18.2			18.9
Other changes in plan assets and benefit obligations recognized in OCI or regulatory assets/liabilities
Current year net (gain) loss	97.9			114.8			29.1			27.1			6.7			(10.9		)
Amortization of gain (loss)	(44.5		)	(38.7		)	(37.4		)	0.2			0.5			0.1
Prior service cost	1.1			—			0.5			—			—			—
Amortization of prior service cost	(4.5		)	(4.6		)	(4.6		)	(7.1		)	(7.2		)	(7.2		)
Amortization of transition obligation	—			—			(0.1		)	(1.1		)	(1.3		)	(1.3		)
Other regulatory activity	17.7			17.1			29.5			(1.2		)	(1.0		)	0.1
Total recognized in OCI or regulatory asset/liability	67.7			88.6			17.0			17.9			(2.3		)	(19.2		)
Total recognized in net periodic benefit costs and OCI or regulatory asset/liability	$	143.4		$	156.8		$	69.8		$	36.7		$	15.9		$	(0.3	)

Periodic benefit obligation and accumulated benefit obligation and the fair value of plan assets by funded and under funded plans



	2012		2011
Pension plans with the ABO in excess of plan assets	(millions)
Projected benefit obligation	$	1,130.5	$	980.6
Accumulated benefit obligation	985.8		852.6
Fair value of plan assets	666.4		591.1
Pension plans with plan assets in excess of the ABO
Projected benefit obligation	$	—	$	—
Accumulated benefit obligation	—		—
Fair value of plan assets	—		—

Schedule of Assumptions Used [Table Text Block]



Weighted-average assumptions used to determine the benefit obligation at plan year-end	Pension Benefits				Other Benefits
	2012		2011		2012		2011
Discount rate	4.17	%	5.01	%	4.13	%	5.03	%
Rate of compensation increase	3.69	%	4.08	%	3.50	%	4.07	%



Weighted-average assumptions used to determine net costs for years ended December 31	Pension Benefits				Other Benefits
	2012		2011		2012			2011
Discount rate	5.01	%	5.54	%	5.03	%		5.50	%
Expected long-term return on plan assets	7.29	%	7.29	%	2.59	%	*	2.83	%	*
Rate of compensation increase	4.08	%	4.08	%	4.07	%		4.06	%

*after tax

Schedule of Expected Benefit Payments [Table Text Block]



	Pension Benefits		Other Benefits
	(millions)
2013	$	84.6	$	8.6
2014	72.5		8.5
2015	73.8		8.6
2016	73.5		8.9
2017	76.0		9.3
2018-2022	407.9		51.1

Fair Value of Plan Assets [Table Text Block]



				Fair Value Measurements Using
Description	December 31 2012			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
		(millions)
Pension Plans
Equity securities
U.S. ^(a)		$	169.6		$	69.7		$	99.9		$	—
International ^(b)		151.2			36.6			114.6			—
Real estate ^(c)		43.4			—			5.0			38.4
Commodities ^(d)		37.3			—			37.3			—
Fixed income securities
Fixed income funds ^(e)		182.1			35.0			147.1			—
U.S. Treasury		4.5			4.5			—			—
U.S. Agency, state and local obligations		19.6			—			19.6			—
U.S. corporate bonds ^(f)		28.9			—			28.9			—
Foreign corporate bonds		2.6			—			2.6			—
Hedge funds ^(g)		21.6			—			—			21.6
Total		$	660.8		$	145.8		$	455.0		$	60.0
Cash equivalents - money market funds		5.6
Total Pension Plans		$	666.4



				Fair Value Measurements Using
Description	December 31 2012			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
Equity securities		$	1.7		$	1.7		$	—		$	—
Fixed income securities
U.S. Treasury		13.7			13.7			—			—
U.S. Agency, state and local obligations		28.6			—			28.6			—
U.S. corporate bonds ^(a)		20.1			—			20.1			—
Foreign corporate bonds		2.2			—			2.2			—
Mutual funds		0.2			0.2			—			—
Total		$	66.5		$	15.6		$	50.9		$	—
Cash equivalents - money market funds		23.8
Total Other Post-Retirement Benefit Plans		$	90.3



				Fair Value Measurements Using
Description	December 31 2011			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
Equity securities		$	1.4		$	1.4		$	—		$	—
Fixed income securities
U.S. Treasury		14.3			14.3			—			—
U.S. Agency, state and local obligations		27.2			—			27.2			—
U.S. corporate bonds ^(a)		14.8			—			14.8			—
Foreign corporate bonds		1.5			—			1.5			—
Mutual funds		0.2			0.2			—			—
Total		$	59.4		$	15.9		$	43.5		$	—
Cash equivalents - money market funds		18.0
Total Other Post-Retirement Benefit Plans		$	77.4



				Fair Value Measurements Using
Description	December 31 2011			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
		(millions)
Pension Plans
Equity securities
U.S. ^(a)		$	156.3		$	94.6		$	61.7		$	—
International ^(b)		117.0			40.9			76.1			—
Real estate ^(c)		34.7			—			—			34.7
Commodities ^(d)		34.6			—			34.6			—
Fixed income securities
Fixed income funds ^(e)		166.5			34.2			132.3			—
U.S. Treasury		4.9			4.9			—			—
U.S. Agency, state and local obligations		17.7			—			17.7			—
U.S. corporate bonds ^(f)		26.6			—			26.6			—
Foreign corporate bonds		2.6			—			2.6			—
Hedge funds ^(g)		21.7			—			—			21.7
Total		$	582.6		$	174.6		$	351.6		$	56.4
Cash equivalents - money market funds		8.5
Total Pension Plans		$	591.1

^(c)This category is comprised of institutional common/collective trust funds and a limited partnership valued at NAV on a quarterly basis.

^(d) This category is comprised of institutional common/collective trust funds valued at daily NAV per share.

^(g)This category is comprised of closely-held limited partnerships valued at NAV on a quarterly basis.

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]



	Increase		Decrease
	(millions)
Effect on total service and interest component	$	0.7	$	(0.6	)
Effect on post-retirement benefit obligation	5.0		(4.4		)

Pension Plans, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Fair value of assets using significant unobservable inputs



Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Description	Real Estate			Hedge Funds				Total
	(millions)
Balance January 1, 2012		$	34.7		$	21.7			$	56.4
Actual return on plan assets
Relating to assets still held		1.6			0.6				2.2
Relating to assets sold		1.3			(0.4		)		0.9
Purchase, sales and settlements		0.8			(0.3		)		0.5
Balance December 31, 2012		$	38.4		$	21.6			$	60.0



Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Description	Real Estate			Hedge Funds				Limited Partnerships				Total
	(millions)
Balance January 1, 2011		$	30.3		$	8.4			$	0.1			$	38.8
Actual return on plan assets relating to assets still held		3.9			(1.3		)		(0.1		)		2.5
Purchase, sales and settlements		0.5			14.6				—				15.1
Balance December 31, 2011		$	34.7		$	21.7			$	—			$	56.4

Equity Compensation (Tables)

12 Months Ended

Dec. 31, 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.



	2012		2011		2010
Great Plains Energy	(millions)
Compensation expense	$	3.3	$	5.2	$	4.3
Income tax benefit	1.4		1.9		1.0
KCP&L
Compensation expense	$	2.3	$	3.5	$	3.0
Income tax benefit	1.0		1.3		0.5

Performance share activity



	Performance Shares			Grant Date Fair Value*
Beginning balance		442,042			$	21.06
Granted		164,158			19.37
Forfeited		(74,923	)		20.10
Performance adjustment		(160,717	)		15.04
Ending balance		370,560			23.05

* weighted-average

Restricted stock activity

Restricted stock activity for 2012 is summarized in the following table.



	Nonvested Restricted Stock			Grant Date Fair Value*
Beginning balance		386,183			$	17.06
Granted and issued		165,910			19.75
Vested		(206,838	)		15.78
Forfeited		(67,816	)		19.49
Ending balance		277,439			19.03

* weighted-average

Schedule of Deferred Compensation Arrangement with Individual, Share-based Payments [Table Text Block]

Director Deferred Share Units activity for 2012 is summarized in the following table.



	Share Units		Grant Date Fair Value*
Beginning balance		54,231		$	20.19
Issued		15,587		20.96
Ending balance		69,818		20.36

* weighted-average

Tabular disclosure of an equity-based arrangement (such as stock or unit options and stock or unit awards) with an individual employee, which is generally an employment contract between the entity and a selected officer or key employee containing a promise by the employer to pay certain equity-based awards at future dates, sometimes including a period after retirement, upon compliance with stipulated requirements. This type of arrangement is distinguished from broader based employee benefit plans as it is usually tailored to the employee. Disclosure also typically includes the amount of related compensation expense recognized during the reporting period, the number of shares or units issued during the period under such arrangements, and the carrying amount as of the balance sheet date of the related liability.

Schedule of Debt [Table Text Block]

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

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



		December 31
	Year Due	2012				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			(4.0		)		(4.2		)
Total KCP&L excluding current maturities^(c)			1,901.7				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
0.301% Wamego Series 1996^(d)	2026		7.3				7.3
0.303% State Environmental 1993^(d)	2028		5.0				5.0
GMO Senior Notes
8.27% Series	2021		80.9				80.9
11.875% Series			—				500.0
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			(262.7		)		(788.7		)
Unamortized discount and premium, net			5.4				(0.7		)
Total Great Plains Energy excluding current maturities^(c)			$	2,756.8			$	2,742.3


^(a)	Weighted-average interest rates at December 31, 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

Amortization of debt expense [Table Text Block]

Amortization of Debt Expense

Great Plains Energy's and KCP&L's amortization of debt expense is detailed in the following table.



	2012		2011		2010
	(millions)
KCP&L	$	2.9	$	3.6	$	2.8
Other Great Plains Energy	2.6		4.5		3.6
Total Great Plains Energy	$	5.5	$	8.1	$	6.4

Schedule of Maturities of Long-term Debt [Table Text Block]

Scheduled Maturities

Great Plains Energy's and KCP&L's long-term debt maturities for the next five years are detailed in the following table.



	2013		2014		2015		2016		2017
	(millions)
Great Plains Energy	$	263.1	$	1.5	$	15.5	$	1.6	$	382.6
KCP&L	0.4		0.4		14.4		0.4		281.5

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Schedule of Rent Expense [Table Text Block]

Great Plains Energy's and KCP&L's expenses related to lease commitments are detailed in the following table.



	2012		2011		2010
	(millions)
Great Plains Energy	$	21.8	$	20.9	$	17.2
KCP&L	17.7		17.0		13.2

Lease and purchase commitments

Great Plains Energy's and KCP&L's contractual commitments at December 31, 2012, excluding pensions and long-term debt, are detailed in the following tables.



Great Plains Energy
	2013		2014		2015		2016		2017		After 2017			Total
Lease commitments	(millions)
Operating lease	$	16.8	$	14.9	$	13.7	$	9.9	$	9.6		$	146.5		$	211.4
Capital lease	0.4		0.4		0.4		0.4		0.4			4.9			6.9
Purchase commitments
Fuel	323.2		209.9		104.9		66.7		36.7			85.4			826.8
Power	39.3		44.9		44.9		44.9		43.5			651.5			869.0
Capacity	11.3		3.3		3.0		1.2		—			—			18.8
La Cygne environmental project	329.0		129.6		4.4		—		—			—			463.0
Non-regulated natural gas transportation	3.2		3.6		3.6		3.6		0.9			—			14.9
Other	124.7		34.0		27.2		15.2		6.3			43.3			250.7
Total contractual commitments	$	847.9	$	440.6	$	202.1	$	141.9	$	97.4		$	931.6		$	2,661.5



KCP&L
	2013		2014		2015		2016		2017		After 2017			Total
Lease commitments	(millions)
Operating lease	$	14.5	$	13.1	$	12.3	$	9.8	$	9.6		$	146.4		$	205.7
Capital lease	0.2		0.2		0.2		0.2		0.2			2.5			3.5
Purchase commitments
Fuel	261.7		177.6		91.8		61.4		36.7			85.4			714.6
Power	29.2		34.8		34.8		34.8		34.8			464.3			632.7
Capacity	2.9		2.9		3.0		1.2		—			—			10.0
La Cygne environmental project	329.0		129.6		4.4		—		—			—			463.0
Other	118.8		33.2		26.4		14.4		5.5			34.2			232.5
Total contractual commitments	$	756.3	$	391.4	$	172.9	$	121.8	$	86.8		$	732.8		$	2,262.0

Related Party Transactions and Relationships (Tables)

12 Months Ended

Dec. 31, 2012

The following table summarizes KCP&L's related party receivables and payables.



	December 31
	2012		2011
	(millions)
Net receivable from GMO	$	26.2	$	24.1
Net receivable from Great Plains Energy	13.8		9.5

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Values of open positions for derivative instruments [Table Text Block]



	December 31
	2012					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	17.9		(2.8		)	23.6		(5.0		)
Forward contracts
Non-hedging derivatives	65.5		6.5			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 [Table Text Block]



Great Plains Energy
	Balance Sheet	Asset Derivatives			Liability Derivatives
December 31, 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		6.5			2.8
Total Derivatives			$	6.5		$	3.0

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

December 31, 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 [Table Text Block]

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
2012	(millions)					(millions)
Interest rate contracts		$	—		Interest charges	$	(20.2	)
Commodity contracts		(0.1		)	Fuel	(0.5		)
Income tax benefit		—			Income tax benefit	8.1
Total		$	(0.1	)	Total	$	(12.6	)
2011
Interest rate contracts		$	(5.3	)	Interest charges	$	(16.9	)
Commodity contracts		(0.6		)	Fuel	(0.1		)
Income tax benefit		2.3			Income tax benefit	6.6
Total		$	(3.6	)	Total	$	(10.4	)



KCP&L
Derivatives in Cash Flow Hedging Relationship
					Gain (Loss) Reclassified from
					Accumulated OCI into Income
					(Effective Portion)
	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)				Income Statement Classification	Amount
2012	(millions)					(millions)
Interest rate contracts		$	—		Interest charges	$	(8.7	)
Commodity contracts		(0.1		)	Fuel	(0.5		)
Income tax benefit		—			Income tax benefit	3.5
Total		$	(0.1	)	Total	$	(5.7	)
2011
Interest rate contracts		$	—		Interest charges	$	(8.7	)
Commodity contracts		(0.6		)	Fuel	(0.1		)
Income tax benefit		0.2			Income tax benefit	3.4
Total		$	(0.4	)	Total	$	(5.4	)

Gain (loss) recognized in a regulatory balance sheet account or earnings for utility commodity hedges [Table Text Block]



Great Plains Energy
Derivatives in Regulatory Account Relationship
					Gain (Loss) Reclassified from
					Regulatory Account
	Amount of Gain (Loss) Recognized in Regulatory Asset on Derivatives				Income Statement Classification	Amount
2012	(millions)					(millions)
Commodity contracts		$	(2.7	)	Fuel	$	(6.6	)
Total		$	(2.7	)	Total	$	(6.6	)
2011
Commodity contracts		$	(8.3	)	Fuel	$	(3.8	)
Total		$	(8.3	)	Total	$	(3.8	)

Accumulated other comprehensive income related to cash flow hedges [Table Text Block]

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



	Great Plains Energy								KCP&L
	December 31								December 31
	2012				2011				2012				2011
		(millions)
Current assets		$	10.6			$	11.3			$	10.6			$	11.3
Current liabilities		(68.4		)		(89.5		)		(52.8		)		(62.5		)
Noncurrent liabilities		(0.1		)		(0.2		)		(0.1		)		(0.2		)
Deferred income taxes		22.5				30.5				16.5				20.0
Total		$	(35.4	)		$	(47.9	)		$	(25.8	)		$	(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.

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Publisher FASB
-Name Accounting Standards Codification
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Fair value of assets and liabilities

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 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 December 31, 2012 and 2011.



								Fair Value Measurements Using
Description	December 31 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 ^(a)
Equity securities		$	100.1		$	—			$	100.1		$	—		$	—
Debt securities
U.S. Treasury		18.5			—				18.5			—			—
U.S. Agency		2.8			—				—			2.8			—
State and local obligations		3.3			—				—			3.3			—
Corporate bonds		26.8			—				—			26.8			—
Other		0.3			—				—			0.3			—
Total nuclear decommissioning trust		151.8			—				118.6			33.2			—
Total		151.8			—				118.6			33.2			—
Liabilities
Derivative instruments ^(b)		—			(0.2		)		0.2			—			—
Total		$	—		$	(0.2	)		$	0.2		$	—		$	—
Other Great Plains Energy
Assets
Derivative instruments ^(b)		$	6.5		$	—			$	—		$	4.2		$	2.3
SERP rabbi trusts ^(c)
Equity securities		0.1			—				0.1			—			—
Fixed income funds		20.2			—				—			20.2			—
Total SERP rabbi trusts		20.3			—				0.1			20.2			—
Total		26.8			—				0.1			24.4			2.3
Liabilities
Derivative instruments ^(b)		—			(2.8		)		2.8			—			—
Total		$	—		$	(2.8	)		$	2.8		$	—		$	—
Great Plains Energy
Assets
Derivative instruments ^(b)		$	6.5		$	—			$	—		$	4.2		$	2.3
Nuclear decommissioning trust ^(a)		151.8			—				118.6			33.2			—
SERP rabbi trusts ^(c)		20.3			—				0.1			20.2			—
Total		178.6			—				118.7			57.6			2.3
Liabilities
Derivative instruments ^(b)		—			(3.0		)		3.0			—			—
Total		$	—		$	(3.0	)		$	3.0		$	—		$	—



									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 ^(a)
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 ^(b)		—				(0.5		)		0.5			—				—
Total		$	—			$	(0.5	)		$	0.5		$	—			$	—
Other Great Plains Energy
Assets
Derivative instruments ^(b)		$	7.8			$	—			$	—		$	4.7			$	3.1
SERP rabbi trusts ^(c)
Equity securities		0.2				—				0.2			—				—
Debt securities		0.1				—				—			0.1				—
Total SERP rabbi trusts		0.3				—				0.2			0.1				—
Total		8.1				—				0.2			4.8				3.1
Liabilities
Derivative instruments ^(b)		—				(5.0		)		5.0			—				—
Total		$	—			$	(5.0	)		$	5.0		$	—			$	—
Great Plains Energy
Assets
Derivative instruments ^(b)		$	7.8			$	—			$	—		$	4.7			$	3.1
Nuclear decommissioning trust ^(a)		132.3				—				99.6			32.7				—
SERP rabbi trusts ^(c)		0.3				—				0.2			0.1				—
Total		140.4				—				99.8			37.5				3.1
Liabilities
Derivative instruments ^(b)		—				(5.5		)		5.5			—				—
Total		$	—			$	(5.5	)		$	5.5		$	—			$	—


^(a)	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 December 31, 2012 and 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.


^(b)	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.


^(c)	Fair value is based on quoted market prices and/or valuation models for equity and debt securities and NAV per share for fixed income funds. The total does not include $0.1 million and $20.3 million at December 31, 2012 and 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.


^(d)	Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheets where a master netting agreement exists between the Company and the counterparty. At December 31, 2012 and 2011, Great Plains Energy netted $3.0 million and $5.5 million, respectively, of cash collateral posted with counterparties.

Unobservable inputs reconciliation

The following table reconciles the beginning and ending balances for all Level 3 assets and liabilities, net, measured at fair value on a recurring basis for 2012 and 2011.



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	8.2			10.9
Settlements	(9.0		)	(11.5		)
Balance at December 31	$	2.3		$	3.1
Total unrealized losses included in non-operating income relating to assets
and liabilities still on the consolidated balance sheet at December 31	$	(0.4	)	$	(0.2	)

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.

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

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



Great Plains Energy	2012			2011			2010
Current income taxes	(millions)
Federal	$	(3.2	)	$	2.9		$	(7.4	)
State	(6.3		)	(6.0		)	(4.3		)
Foreign	—			(0.4		)	0.1
Total	(9.5		)	(3.5		)	(11.6		)
Deferred income taxes
Federal	96.3			90.5			99.8
State	24.9			20.7			24.0
Total	121.2			111.2			123.8
Noncurrent income taxes
Federal	(0.2		)	(18.0		)	(4.8		)
State	(0.3		)	(2.1		)	(1.8		)
Foreign	(4.2		)	(0.6		)	0.5
Total	(4.7		)	(20.7		)	(6.1		)
Investment tax credit
Deferral	—			—			(4.2		)
Amortization	(2.4		)	(2.2		)	(2.9		)
Total	(2.4		)	(2.2		)	(7.1		)
Income tax expense	$	104.6		$	84.8		$	99.0



KCP&L	2012			2011			2010
Current income taxes	(millions)
Federal	$	13.1		$	1.0		$	5.5
State	2.0			(0.6		)	1.1
Total	15.1			0.4			6.6
Deferred income taxes
Federal	48.8			66.0			69.8
State	11.4			14.6			13.4
Total	60.2			80.6			83.2
Noncurrent income taxes
Federal	1.7			(9.3		)	(1.6		)
State	0.1			(1.1		)	(0.3		)
Total	1.8			(10.4		)	(1.9		)
Investment tax credit
Deferral	—			—			(4.2		)
Amortization	(1.8		)	(1.5		)	(2.1		)
Total	(1.8		)	(1.5		)	(6.3		)
Income tax expense	$	75.3		$	69.1		$	81.6

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

Effective Income Tax Rates

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	2012		2011		2010
Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Differences between book and tax depreciation not normalized	1.2		1.5		(1.7	)
Amortization of investment tax credits	(0.8	)	(0.8	)	(0.9	)
Federal income tax credits	(3.1	)	(5.0	)	(4.1	)
State income taxes	4.0		4.0		3.7
Medicare Part D subsidy legislation	—		—		0.9
Changes in uncertain tax positions, net	(1.5	)	(1.7	)	0.1
Valuation allowance	—		(0.8	)	(0.9	)
Other	(0.5	)	0.5		(0.3	)
Effective income tax rate	34.3	%	32.7	%	31.8	%



KCP&L	2012		2011		2010
Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Differences between book and tax depreciation not normalized	1.3		1.6		(1.8	)
Amortization of investment tax credits	(0.8	)	(0.7	)	(0.9	)
Federal income tax credits	(4.3	)	(6.3	)	(3.5	)
State income taxes	4.1		3.9		3.6
Medicare Part D subsidy legislation	—		—		1.1
Changes in uncertain tax positions, net	—		0.1		—
Other	(0.6	)	0.2		(0.2	)
Effective income tax rate	34.7	%	33.8	%	33.3	%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

Deferred Income Taxes

The tax effects of major temporary differences resulting in deferred income tax assets (liabilities) in the consolidated balance sheets are in the following tables.



	Great Plains Energy						KCP&L
December 31	2012			2011			2012			2011
Current deferred income tax asset (liability)	(millions)
Net operating loss carryforward	$	77.8		$	—		$	—		$	—
Other	12.7			7.9			4.6			(0.1		)
Net current deferred income tax asset (liability) before valuation allowance	90.5			7.9			4.6			(0.1		)
Valuation allowance	(2.0		)	(0.4		)	—			—
Net current deferred income tax asset (liability)	88.5			7.5			4.6			(0.1		)
Noncurrent deferred income taxes
Plant related	(1,297.2		)	(1,193.6		)	(930.7		)	(861.6		)
Income taxes on future regulatory recoveries	(138.3		)	(144.3		)	(114.7		)	(119.6		)
Derivative instruments	37.7			43.3			27.4			31.1
Pension and post-retirement benefits	(26.6		)	(34.2		)	(3.4		)	(11.7		)
SO₂emission allowance sales	29.7			31.1			30.4			31.9
Fuel recovery mechanisms	(8.6		)	(17.2		)	(3.5		)	(5.4		)
Transition costs	(13.3		)	(17.4		)	(7.3		)	(9.6		)
Tax credit carryforwards	217.5			213.7			126.3			116.8
Long-term debt fair value adjustment	—			6.3			—			—
Customer demand programs	(28.7		)	(26.4		)	(19.2		)	(18.6		)
Net operating loss carryforward	439.4			543.7			72.4			77.9
Other	(22.2		)	(10.1		)	(14.1		)	(3.9		)
Net noncurrent deferred income tax liability before valuation allowance	(810.6		)	(605.1		)	(836.4		)	(772.7		)
Valuation allowance	(21.8		)	(23.5		)	—			—
Net noncurrent deferred income tax liability	(832.4		)	(628.6		)	(836.4		)	(772.7		)
Net deferred income tax liability	$	(743.9	)	$	(621.1	)	$	(831.8	)	$	(772.8	)



	Great Plains Energy						KCP&L
December 31	2012			2011			2012			2011
	(millions)
Gross deferred income tax assets	$	1,209.8		$	1,203.6		$	656.9		$	618.7
Gross deferred income tax liabilities	(1,953.7		)	(1,824.7		)	(1,488.7		)	(1,391.5		)
Net deferred income tax liability	$	(743.9	)	$	(621.1	)	$	(831.8	)	$	(772.8	)

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
	2012			2011			2010			2012			2011			2010
	(millions)
Beginning balance January 1	$	24.0		$	42.0		$	51.4		$	8.7		$	19.1		$	20.9
Additions for current year tax positions	3.7			1.4			2.7			3.6			—			1.3
Additions for prior year tax positions	—			2.4			2.1			—			2.3			1.5
Reductions for prior year tax positions	(1.8		)	(20.9		)	(10.6		)	(1.6		)	(12.6		)	(1.6		)
Settlements	—			—			(3.8		)	—			—			(2.9		)
Statute expirations	(4.7		)	(0.7		)	(0.3		)	(0.2		)	(0.1		)	(0.1		)
Foreign currency translation adjustments	0.2			(0.2		)	0.5			—			—			—
Ending balance December 31	$	21.4		$	24.0		$	42.0		$	10.5		$	8.7		$	19.1

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.

Segment financial information

Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

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



2012	Electric Utility				Other				Eliminations			Great Plains Energy
		(millions)
Operating revenues		$	2,309.9			$	—			$	—		$	2,309.9
Depreciation and amortization		(272.3		)		—				—			(272.3		)
Interest charges		(197.3		)		(67.3		)		43.8			(220.8		)
Income tax (expense) benefit		(122.0		)		17.4				—			(104.6		)
Net income (loss) attributable to Great Plains Energy		216.6				(16.7		)		—			199.9



2011	Electric Utility				Other				Eliminations			Great Plains Energy
		(millions)
Operating revenues		$	2,318.0			$	—			$	—		$	2,318.0
Depreciation and amortization		(273.1		)		—				—			(273.1		)
Interest charges		(176.9		)		(67.2		)		25.7			(218.4		)
Income tax (expense) benefit		(109.3		)		24.5				—			(84.8		)
Net income (loss) attributable to Great Plains Energy		199.9				(25.5		)		—			174.4



2010	Electric Utility				Other				Eliminations			Great Plains Energy
		(millions)
Operating revenues		$	2,255.5			$	—			$	—		$	2,255.5
Depreciation and amortization		(331.6		)		—				—			(331.6		)
Interest charges		(143.1		)		(45.5		)		3.8			(184.8		)
Income tax (expense) benefit		(123.3		)		24.3				—			(99.0		)
Net income (loss) attributable to Great Plains Energy		235.3				(23.6		)		—			211.7



	Electric Utility			Other			Eliminations				Great Plains Energy
2012		(millions)
Assets		$	9,910.6		$	122.4		$	(385.7	)		$	9,647.3
Capital expenditures		610.2			—			—				610.2
2011
Assets		$	9,483.4		$	51.9		$	(417.3	)		$	9,118.0
Capital expenditures		456.6			—			—				456.6
2010
Assets		$	9,152.7		$	66.3		$	(400.8	)		$	8,818.2
Capital expenditures		618.1			—			—				618.1

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.

Jointly Owned Electric Utility Plants [Abstract]

Jointly Owned Electric Utility Plants (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Jointly Owned Utility Plants [Table Text Block]

Great Plains Energy's and KCP&L's share of jointly-owned electric utility plants at December 31, 2012, are detailed in the following tables.



Great Plains Energy
	Wolf Creek Unit			La Cygne Units			Iatan No. 1 Unit			Iatan No. 2 Unit			Iatan Common			Jeffrey Energy Center
	(millions, except MW amounts)
Great Plains Energy's share		47%			50%			88%			73%			79%			8%

Utility plant in service		$	1,483.6		$	504.5		$	667.5		$	1,297.9		$	374.9		$	167.2
Accumulated depreciation		801.1			308.6			264.9			294.7			42.9			75.2
Nuclear fuel, net		81.3			—			—			—			—			—
Construction work in progress		99.8			262.0			14.1			5.7			25.9			6.3
2013 accredited capacity-MWs		547			711			620			641			NA			172



KCP&L
	Wolf Creek Unit			La Cygne Units			Iatan No. 1 Unit			Iatan No. 2 Unit			Iatan Common
	(millions, except MW amounts)
KCP&L's share		47%			50%			70%			55%			61%

Utility plant in service		$	1,483.6		$	504.5		$	541.3		$	987.2		$	295.3
Accumulated depreciation		801.1			308.6			217.6			279.6			36.8
Nuclear fuel, net		81.3			—			—			—			—
Construction work in progress		99.8			262.0			5.5			4.5			6.9
2013 accredited capacity-MWs		547			711			493			482			NA

Quarterly Operating Results (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]



	Quarter
Great Plains Energy	1st			2nd		3rd		4th
2012	(millions, except per share amounts)
Operating revenue	$	479.7		$	603.6	$	746.2	$	480.4
Operating income	49.0			150.0		277.0		62.9
Net income (loss)	(9.3		)	58.1		146.4		4.7
Net income (loss) attributable to Great Plains Energy	(9.1		)	58.1		146.2		4.7
Basic and diluted earnings (loss) per common share	(0.07		)	0.41		0.95		0.03
2011
Operating revenue	$	492.9		$	565.1	$	773.7	$	486.3
Operating income	41.2			115.6		262.7		60.3
Net income	2.3			43.4		126.6		1.9
Net income attributable to Great Plains Energy	2.4			43.4		126.5		2.1
Basic earnings per common share	0.02			0.32		0.93		0.01
Diluted earnings per common share	0.01			0.31		0.91		0.01



	Quarter
KCP&L	1st		2nd		3rd		4th
2012	(millions)
Operating revenue	$	327.0	$	409.1	$	508.0	$	335.8
Operating income	31.6		99.9		177.8		39.4
Net income	2.3		43.7		90.2		5.4
2011
Operating revenue	$	330.8	$	383.4	$	506.3	$	337.8
Operating income	26.5		77.8		169.2		47.7
Net income	4.0		33.4		85.4		12.7

Summary of Significant Accounting Policies Fair Value of Financial Instruments (Details) - USD ($) $ in Billions	Dec. 31, 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

Summary of Significant Accounting Policies Summary of Significant Accounting Policies Utility Plant (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service

3.00%

$ 251.4

$ 239.9

$ 243.6

Public Utilities, Property, Plant and Equipment, Generation or Processing

6,697.1

6,594.0

Public Utilities, Property, Plant and Equipment, Transmission

754.0

734.8

Public Utilities, Property, Plant and Equipment, Distribution

3,019.6

2,921.1

Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment

689.8

674.9

Public Utilities, Property, Plant and Equipment, Plant in Service

^[1]

$ 11,160.5

10,924.8

Minimum [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Property, Plant and Equipment, Generation, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Transmission, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Distribution, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Estimated Useful Life

Maximum [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Property, Plant and Equipment, Generation, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Transmission, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Distribution, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Estimated Useful Life

Land and other assets not depreciated [Member]

Public Utilities, Property, Plant and Equipment, Plant in Service

$ 104.5

105.5

Energy Plan [Member]

Public Utility, Property, Plant and Equipment [Line Items]

14.4

72.6

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service

3.00%

Public Utilities, Allowance for Funds Used During Construction, Rate

$ 168.0

$ 162.0

$ 170.9

0.20%

6.80%

Public Utilities, Property, Plant and Equipment, Generation or Processing

$ 5,140.0

$ 5,078.1

Public Utilities, Property, Plant and Equipment, Transmission

414.7

412.9

Public Utilities, Property, Plant and Equipment, Distribution

1,893.8

1,840.2

Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment

522.9

498.1

Public Utilities, Property, Plant and Equipment, Plant in Service

^[2]

$ 7,971.4

7,829.3

Kansas City Power and Light Company [Member] | Minimum [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Property, Plant and Equipment, Generation, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Transmission, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Distribution, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Estimated Useful Life

Kansas City Power and Light Company [Member] | Maximum [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Property, Plant and Equipment, Generation, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Transmission, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Distribution, Estimated Useful Life

Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Estimated Useful Life

Kansas City Power and Light Company [Member] | Land and other assets not depreciated [Member]

Public Utilities, Property, Plant and Equipment, Plant in Service

$ 54.7

59.8

Kansas City Power and Light Company [Member] | Energy Plan [Member]

Public Utility, Property, Plant and Equipment [Line Items]

$ 14.4

$ 72.6

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Allowance for Funds Used During Construction, Rate

2.40%

5.40%

4.60%

[1]	(a) Includes $104.5 million and $105.5 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.
[2]	(a) Includes $54.7 million and $59.8 million at December 31, 2012 and 2011, respectively, of land and other assets that are not depreciated.

Summary of Significant Accounting Policies Summary of Significant Accounting Policies Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Kansas City Power and Light Company [Member]
Excise and Sales Taxes	$ 55.8	$ 55.6	$ 54.3

Summary of Significant Accounting Policies Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income [Abstract]
Net income	$ 4.7	$ 146.4	$ 58.1	$ (9.3)	$ 1.9	$ 126.6	$ 43.4	$ 2.3	$ 199.9	$ 174.2	$ 211.9
Less: net income (loss) attributable to noncontrolling interest									0.0	(0.2)	0.2
Less: preferred stock dividend requirements									1.6	1.6	1.6
Earnings available for common shareholders									$ 198.3	$ 172.8	$ 210.1
Common Shares Outstanding [Abstract]
Average number of common shares outstanding (in shares)									145.5	135.6	135.1
Add: effect of dilutive securities (in shares)									1.7	3.1	1.8
Diluted average number of common shares outstanding (in shares)									147.2	138.7	136.9
Earnings per share [Abstract]
Earnings Per Share, Basic					$ 0.01	$ 0.93	$ 0.32	$ 0.02	$ 1.36	$ 1.27	$ 1.55
Earnings Per Share, Diluted					$ 0.01	$ 0.91	$ 0.31	$ 0.01	$ 1.35	$ 1.25	$ 1.53

Summary of Significant Accounting Policies Antidilutive Securities (Details) - shares	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Performance Shares [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	50,897	340,690
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	3,781	43,641	251,526
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	6,000	196,137

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.

Summary of Significant Accounting Policies Subsequent Events (Details) - Dividend Declared [Member] $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2012 USD ($) $ / shares
Dividends Declared [Abstract]
Subsequent Event, Date	Feb. 12, 2013
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 Energy's preferred stock.
Subsequent per common share amount (in dollars per share) \| $ / shares	$ 0.2175
Kansas City Power and Light Company [Member]
Dividends Declared [Abstract]
Subsequent Event, Date	Feb. 12, 2013
Subsequent Event Amount \| $	$ 23
Subsequent Event Description	KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounts receivable pledged as collateral	$ 174.0	$ 95.0	$ 95.0
Collateralized note payable	174.0	95.0	95.0
Cash flows affected by changes in:
Receivables	76.8	3.6	(12.6)
Accounts receivable pledged as collateral	(79.0)	0.0	(95.0)
Fuel inventories	(6.1)	(3.9)	(0.1)
Materials and supplies	(11.0)	(7.5)	(11.5)
Accounts payable	57.3	5.7	12.8
Accrued taxes	(7.8)	1.4	6.7
Accrued interest	(35.2)	1.5	2.9
Deferred refueling outage costs	15.6	(17.9)	9.9
Fuel recovery mechanism	22.5	(1.7)	2.7
Pension and post-retirement benefit obligations	14.4	(56.0)	(10.2)
Increase (Decrease) in Allowance for Equity Funds Used During Construction	(1.3)	(1.0)	(26.0)
Write down of affordable housing investments	0.0	0.0	11.2
Interest rate hedge settlement	0.0	(26.1)	(6.9)
Iatan Nos. 1 and 2 impact of disallowed construction costs	0.0	2.3	16.8
Uncertain tax positions	(4.7)	(20.8)	(6.1)
Other Operating Activities, Cash Flow Statement	(29.8)	(27.1)	(28.3)
Total other operating activities	11.7	(147.5)	(133.7)
Cash paid during the period:
Interest Paid, Net	247.9	254.4	237.7
Income Taxes Paid	3.3	2.8	0.9
Non-cash investing activities:
Liabilities assumed for capital expenditures	57.5	39.7	44.9
Kansas City Power and Light Company [Member]
Accounts receivable pledged as collateral	110.0	95.0	95.0
Collateralized note payable	110.0	95.0	95.0
Cash flows affected by changes in:
Receivables	8.8	(20.2)	(4.1)
Accounts receivable pledged as collateral	(15.0)	0.0	(95.0)
Fuel inventories	(4.6)	(14.1)	0.7
Materials and supplies	(9.0)	(6.7)	(9.6)
Accounts payable	48.3	11.0	0.8
Accrued taxes	(2.0)	2.7	(15.7)
Accrued interest	(2.3)	3.8	(0.5)
Deferred refueling outage costs	15.6	(17.9)	9.9
Fuel recovery mechanism	5.1	(5.8)	(8.8)
Pension and post-retirement benefit obligations	18.0	(45.6)	7.9
Increase (Decrease) in Allowance for Equity Funds Used During Construction	(1.3)	(0.7)	(21.9)
Iatan Nos. 1 and 2 impact of disallowed construction costs	0.0	1.5	13.0
Uncertain tax positions	1.8	(10.4)	(1.8)
Other Operating Activities, Cash Flow Statement	(35.5)	(15.9)	(2.7)
Total other operating activities	27.9	(118.3)	(127.8)
Cash paid during the period:
Interest Paid, Net	118.0	111.3	101.1
Income Taxes Paid	18.0	0.1	18.2
Non-cash investing activities:
Liabilities assumed for capital expenditures	$ 48.4	$ 32.0	$ 37.4

Receivables Accounts, Notes, and Financing (Details) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (2.6)	$ (2.5)
Other Receivables, Gross, Current	98.8	81.5
Receivables, net	154.5	231.2
Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	(1.5)	(1.4)
Other Receivables, Gross, Current	81.8	69.2
Receivables, net	163.2	172.9
Trade Accounts Receivable [Member] \| Billed Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	0.0	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	0.0	16.4
Trade Accounts Receivable [Member] \| Unbilled Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	58.3	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	42.9	50.0
Intercompany Receivables [Member] \| Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	$ 40.0	$ 38.7

Receivables Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Receivables Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounts receivable pledged as collateral	$ 174.0	$ 95.0	$ 95.0
Kansas City Power and Light Company [Member]
Accounts receivable pledged as collateral	$ 110.0	$ 95.0	$ 95.0
Contractually Specified Servicing Fees Percentage Amount	1.50%
Maximum amount of outstanding principal under receivables agreement	$ 110.0
KCPL Greater Missouri Operations [Member]
Contractually Specified Servicing Fees Percentage Amount	1.25%
Maximum amount of outstanding principal under receivables agreement from June 1 to October 31 of each year	$ 80.0
Maximum amount of outstanding principal under receivables agreement from November 1 to May 31 of each year	$ 65.0

Receivables (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

$ 0.0

^[1]

(0.9)

0.0

Cash from customers (transferred to) received from Receivables Company

(1.7)

0.0

Cash received from (paid to) for receivables purchased

0.0

0.0

0.0

$ 0.0

^[1]

0.1

(0.2)

0.0

Cash from customers (transferred to) received from Receivables Company

(1.2)

0.0

Cash received from (paid to) for receivables purchased

0.0

Kansas City Power And Light Company Unconsolidated [Member]

0.0

(1,436.0)

(1,415.6)

^[1]

(18.2)

(17.9)

2.5

2.6

Cash from customers (transferred to) received from Receivables Company

0.0

(1,452.4)

(1,412.4)

Cash received from (paid to) for receivables purchased

1,434.2

1,394.7

KCPL Receivables Company [Member]

0.3

0.5

1,436.0

1,415.6

^[1]

18.3

17.7

(2.5)

(2.6)

Cash from customers (transferred to) received from Receivables Company

(1.2)

1,452.4

1,412.4

Cash received from (paid to) for receivables purchased

(1,434.2)

(1,394.7)

(0.3)

$ (0.5)

(597.8)

^[1]

(7.6)

0.9

Cash from customers (transferred to) received from Receivables Company

0.0

(524.0)

Cash received from (paid to) for receivables purchased

517.5

GMO Receivables Company Member

0.1

597.8

^[1]

6.6

(0.9)

Cash from customers (transferred to) received from Receivables Company

(0.5)

524.0

Cash received from (paid to) for receivables purchased

(517.5)

$ (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.

Nuclear Plant (Details) $ in Millions	12 Months Ended
Nuclear Plant (Details) $ in Millions	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)
Investments in decommissioning trust fund [Line Items]
Cost Basis	$ 130.4	$ 123.1
Gross Unrealized Gains	26.0	16.8
Gross Unrealized Losses	(1.7)	(4.6)
Fair Value, Nuclear decommissioning trust fund	$ 154.7	135.3	$ 129.2
Weighted average maturity of debt securities (in years)	7
Realized Gains on investments in decommissioning trust fund	$ 1.7	1.0	7.3
Realized Losses on investments in decommissioning trust fund	(0.7)	(0.7)	$ (0.6)
Equity Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	80.6	76.5
Gross Unrealized Gains	21.1	12.3
Gross Unrealized Losses	(1.6)	(4.5)
Fair Value, Nuclear decommissioning trust fund	100.1	84.3
Debt Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	46.6	44.2
Gross Unrealized Gains	4.9	4.5
Gross Unrealized Losses	(0.1)	(0.1)
Fair Value, Nuclear decommissioning trust fund	51.4	48.6
Other Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	3.2	2.4
Gross Unrealized Gains	0.0	0.0
Gross Unrealized Losses	0.0	0.0
Fair Value, Nuclear decommissioning trust fund	3.2	2.4
Kansas City Power and Light Company [Member]
Investments in decommissioning trust fund [Line Items]
Fair Value, Nuclear decommissioning trust fund	$ 154.7	$ 135.3

Nuclear Plant Decommissioning Trust (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Nuclear decommissioning trust fund [Roll Forward]
Nuclear decommissioning trust fund, beginning balance	$ 135.3	$ 129.2
Contributions to nuclear decommissioning trust fund	3.3	3.4
Nuclear decommissioning trust fund earned income, net of fees	3.0	4.8
Net realized gains (losses) on nuclear decommissioning trust fund	1.0	0.3
Net unrealized gains (losses) on nuclear decommissioning trust fund	12.1	(2.4)
Nuclear decommissioning trust fund, ending balance	154.7	135.3
Kansas City Power and Light Company [Member]
Nuclear decommissioning trust fund [Roll Forward]
Nuclear decommissioning trust fund, beginning balance	135.3
Nuclear decommissioning trust fund, ending balance	154.7	$ 135.3
Wolf Creek Unit [Member]
Nuclear Plant Decommissioning Costs [Abstract]
Current cost of decommissioning (in 2011 dollars)	630.0
Future cost of decommissioning (in 2045 through 2053 dollars)	$ 1,788.0
Annual Escalation Factor	2.85%
Annual return on trust assets through 2025	5.46%
Annual return on trusts assets beginning in 2053	0.76%
Nuclear Insurance [Abstract]
Industry aggregate limit on nuclear insurance for property claims including accidental damages	$ 3,200.0
Amount of insurance against public liability claims resulting from nuclear incidents to full limit of public liability	12,600.0
Maximum available commercial insurance	400.0
Remaining balance provided through industry wide retrospective assesment program mandated by law	12,200.0
Maximum amount able to be assessed to owners	117.5
SFP Program-annual amount payable per incident	17.5
Amount of decontamination liability, premature decommissioning liability and property damage insurance	2,800.0
Premature decommissioning coverage applies only if property damage exceeds this amount and trust funds have been exhausted	500.0
Estimated maximum amount of retrospective assessments under the current policies	30.2
Wolf Creek Unit [Member] \| Kansas City Power and Light Company [Member]
Nuclear Plant Decommissioning Costs [Abstract]
Current cost of decommissioning (in 2011 dollars)	296.0
Future cost of decommissioning (in 2045 through 2053 dollars)	840.0
Nuclear Insurance [Abstract]
Maximum amount able to be assessed to owners	55.2
SFP Program-annual amount payable per incident	8.2
Amount of decontamination liability, premature decommissioning liability and property damage insurance	1,300.0
Estimated maximum amount of retrospective assessments under the current policies	$ 14.2
Ownership percentage in Wolf Creek, a nuclear generating unit (in hundredths)	47.00%

Regulatory Matters (Details) $ in Millions	Dec. 31, 2012 USD ($)
Kansas City Power and Light Company [Member] \| Rate jurisdiction - Kansas [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase, requested	$ 63.6
Revised annual revenue increase, requested	$ 56.4
Return on equity, requested (in hundredths)	10.40%
Revised return on equity, requested (in hundredths)	10.30%
Rate-making equity ratio, requested (in hundredths)	51.80%
Annual revenue increase authorized	$ 33.2
Return on equity, approved (in hundredths)	9.50%
Ratemaking equity ratio, approved (in hundredths)	51.80%
Kansas City Power and Light Company [Member] \| Rate jurisdiction - Missouri [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase, requested	$ 105.7
Return on equity, requested (in hundredths)	10.40%
Revised return on equity, requested (in hundredths)	10.30%
Rate-making equity ratio, requested (in hundredths)	52.50%
Annual revenue increase authorized	$ 67.4
Return on equity, approved (in hundredths)	9.70%
Ratemaking equity ratio, approved (in hundredths)	52.60%
Rate making equity ratio after including other comprehensive income, approved	52.30%
KCPL Greater Missouri Operations [Member] \| Rate jurisdiction - St. Joseph Light and Power division [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase, requested	$ 25.2
Return on equity, requested (in hundredths)	10.40%
Revised return on equity, requested (in hundredths)	10.30%
Rate-making equity ratio, requested (in hundredths)	52.50%
Annual revenue increase authorized	$ 21.7
Return on equity, approved (in hundredths)	9.70%
Ratemaking equity ratio, approved (in hundredths)	52.60%
Rate making equity ratio after including other comprehensive income, approved	52.30%
KCPL Greater Missouri Operations [Member] \| Rate jurisdiction - Missouri Public Service division [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase, requested	$ 58.3
Return on equity, requested (in hundredths)	10.40%
Revised return on equity, requested (in hundredths)	10.30%
Rate-making equity ratio, requested (in hundredths)	52.50%
Annual revenue increase authorized	$ 26.2
Return on equity, approved (in hundredths)	9.70%
Ratemaking equity ratio, approved (in hundredths)	52.60%
Rate making equity ratio after including other comprehensive income, approved	52.30%

Regulatory Matters Asset (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Regulatory Liability, Noncurrent

$ 1,120.9

$ 1,058.2

283.8

268.5

Taxes recoverable through future rates [Member]

Loss on reacquired debt [Member]

138.4

144.2

Cost of removal, asset [Member]

10.1

11.8

Asset Retirement Obligation Costs [Member]

2.8

4.6

Pension and post-retirement costs [Member]

46.4

45.2

Deferred customer programs [Member]

670.9

588.4

Rate case expenses [Member]

74.4

68.8

Fuel recovery mechanisms [Member]

9.2

13.4

Acquisition transition costs [Member]

25.8

50.4

Derivative instruments [Member]

34.2

44.9

Iatan No. 1 and Common facilities depreciation and carrying costs [Member]

3.7

7.6

Iatan No. 2 construction accounting costs [Member]

21.8

22.5

Kansas property tax surcharge [Member]

46.8

43.3

5.4

3.7

Solar Rebates [Member]

Voluntary Separation Program [Member]

15.8

0.0

Other regulatory noncurrent assets [Member]

4.3

0.0

10.9

9.4

Regulatory Liability, Noncurrent

853.2

780.7

153.0

142.8

Kansas City Power and Light Company [Member] | Taxes recoverable through future rates [Member]

Kansas City Power and Light Company [Member] | Loss on reacquired debt [Member]

114.7

119.6

$ 8.1

^[1]

9.1

Kansas City Power and Light Company [Member] | Cost of removal, asset [Member]

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

Kansas City Power and Light Company [Member] | Asset Retirement Obligation Costs [Member]

$ 2.8

4.6

Kansas City Power and Light Company [Member] | Pension and post-retirement costs [Member]

31.5

31.4

Amount not included in rate base

541.2

^[2]

466.4

$ 526.5

Kansas City Power and Light Company [Member] | Deferred customer programs [Member]

various

Amount not included in rate base

$ 49.8

^[3]

48.2

$ 5.0

Kansas City Power and Light Company [Member] | Rate case expenses [Member]

various

$ 7.5

^[4]

9.6

Kansas City Power and Light Company [Member] | Fuel recovery mechanisms [Member]

various

$ 8.9

^[4]

14.0

Kansas City Power and Light Company [Member] | Acquisition transition costs [Member]

various

$ 18.7

^[5]

24.7

Kansas City Power and Light Company [Member] | Derivative instruments [Member]

through 2016

Kansas City Power and Light Company [Member] | Iatan No. 1 and Common facilities depreciation and carrying costs [Member]

$ 0.0

0.0

$ 15.9

^[6]

16.4

Kansas City Power and Light Company [Member] | Iatan No. 2 construction accounting costs [Member]

through 2038

$ 30.6

^[7]

27.9

Kansas City Power and Light Company [Member] | Kansas property tax surcharge [Member]

through 2058

$ 5.4

^[4]

3.7

Kansas City Power and Light Company [Member] | Solar Rebates [Member]

various

$ 5.8

^[8]

0.0

Kansas City Power and Light Company [Member] | Voluntary Separation Program [Member]

through 2015

$ 4.3

^[9]

0.0

Kansas City Power and Light Company [Member] | Other regulatory noncurrent assets [Member]

through 2017

$ 8.0

^[4]

5.1

various

Regulatory Liability, Noncurrent

$ 267.7

277.5

130.8

125.7

KCPL Greater Missouri Operations [Member] | Taxes recoverable through future rates [Member]

KCPL Greater Missouri Operations [Member] | Loss on reacquired debt [Member]

23.7

24.6

$ 2.0

^[1]

2.7

KCPL Greater Missouri Operations [Member] | Cost of removal, asset [Member]

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

KCPL Greater Missouri Operations [Member] | Asset Retirement Obligation Costs [Member]

$ 0.0

0.0

KCPL Greater Missouri Operations [Member] | Pension and post-retirement costs [Member]

14.9

13.8

Amount not included in rate base

129.7

^[2]

122.0

$ 127.1

KCPL Greater Missouri Operations [Member] | Deferred customer programs [Member]

various

$ 24.6

^[10]

20.6

KCPL Greater Missouri Operations [Member] | Rate case expenses [Member]

through 2019

$ 1.7

^[11]

3.8

KCPL Greater Missouri Operations [Member] | Fuel recovery mechanisms [Member]

through 2014

$ 16.9

^[4]

36.4

KCPL Greater Missouri Operations [Member] | Acquisition transition costs [Member]

various

$ 15.5

^[5]

20.2

KCPL Greater Missouri Operations [Member] | Derivative instruments [Member]

2016

KCPL Greater Missouri Operations [Member] | Iatan No. 1 and Common facilities depreciation and carrying costs [Member]

$ 3.7

^[12]

7.6

$ 5.9

^[6]

6.1

KCPL Greater Missouri Operations [Member] | Iatan No. 2 construction accounting costs [Member]

through 2038

$ 16.2

^[7]

15.4

KCPL Greater Missouri Operations [Member] | Kansas property tax surcharge [Member]

through 2058

KCPL Greater Missouri Operations [Member] | Solar Rebates [Member]

$ 0.0

0.0

$ 10.0

^[8]

0.0

KCPL Greater Missouri Operations [Member] | Voluntary Separation Program [Member]

through 2015

KCPL Greater Missouri Operations [Member] | Other regulatory noncurrent assets [Member]

$ 0.0

0.0

$ 2.9

^[4]

$ 4.3

various

[1]	(a) Amortized over the life of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.
[2]	(b) Represents unrecognized gains and losses, prior service and transition costs that will be recognized in future net periodic pension and post-retirement costs, pension settlements amortized over various periods and financial and regulatory accounting method differences that will be eliminated over the life of the pension plans. Of these amounts, $526.5 million and $127.1 million for KCP&L and GMO, respectively, are not included in rate base and are amortized over various periods.
[3]	(c) $5.0 million not included in rate base and amortized over various periods.
[4]	(e) Not included in rate base and amortized over various periods.
[5]	(g) Not included in rate base and amortized through 2016.
[6]	(i) Included in rate base and amortized through 2038.
[7]	(j) Included in rate base and amortized through 2058.
[8]	(k) Not included in rate base and amortized through 2015.
[9]	(l) Not included in rate base and amortized through 2017.
[10]	(d) Included in rate base and amortized through 2019.
[11]	(f) Not included in rate base and amortized through 2014.
[12]	(h) Represents the fair value of derivative instruments for commodity contracts. Settlements of the contracts are recognized in fuel expense and included in GMO's Fuel Adjustment Clause (FAC).

Regulatory Matters Liabilities (Details) - USD ($)
$ in Millions

Dec. 31, 2012

Dec. 31, 2011

Emission allowances [Member]

$ 283.8

$ 268.5

Asset retirement obligations [Member]

78.1

82.2

63.1

49.3

Pension [Member]

Cost of removal, liability [Member]

46.1

41.5

Other regulatory noncurrent liabilities [Member]

64.0

61.9

32.5

33.6

Kansas City Power and Light Company [Member] | Emission allowances [Member]

153.0

142.8

Kansas City Power and Light Company [Member] | Asset retirement obligations [Member]

78.0

82.0

Kansas City Power and Light Company [Member] | Pension [Member]

63.1

49.3

Kansas City Power and Light Company [Member] | Cost of removal, liability [Member]

1.5

0.7

Kansas City Power and Light Company [Member] | Other regulatory noncurrent liabilities [Member]

0.0

10.4

10.8

KCPL Greater Missouri Operations [Member] | Emission allowances [Member]

130.8

125.7

KCPL Greater Missouri Operations [Member] | Asset retirement obligations [Member]

0.1

0.2

KCPL Greater Missouri Operations [Member] | Pension [Member]

0.0

KCPL Greater Missouri Operations [Member] | Cost of removal, liability [Member]

44.6

40.8

KCPL Greater Missouri Operations [Member] | Other regulatory noncurrent liabilities [Member]

64.0

^[1]

61.9

Amounts recognized in the consolidated balance sheets [Abstract]

$ 22.1

$ 22.8

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

Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	$ 169.0	$ 169.0
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	15.6	13.5
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	14.5
Finite-Lived Intangible Assets, Amortization Expense, Year Two	11.1
Finite-Lived Intangible Assets, Amortization Expense, Year Three	8.8
Finite-Lived Intangible Assets, Amortization Expense, Year Four	7.4
Finite-Lived Intangible Assets, Amortization Expense, Year Five	4.1
Kansas City Power and Light Company [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	13.2	12.6
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	11.9
Finite-Lived Intangible Assets, Amortization Expense, Year Two	8.6
Finite-Lived Intangible Assets, Amortization Expense, Year Three	6.5
Finite-Lived Intangible Assets, Amortization Expense, Year Four	5.2
Finite-Lived Intangible Assets, Amortization Expense, Year Five	3.6
Computer Software, Intangible Asset [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	211.2	202.5
Finite-Lived Intangible Assets, Accumulated Amortization	(152.9)	(143.5)
Computer Software, Intangible Asset [Member] \| Kansas City Power and Light Company [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	189.9	171.7
Finite-Lived Intangible Assets, Accumulated Amortization	(142.9)	(129.9)
Asset Improvements [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	26.5	27.0
Finite-Lived Intangible Assets, Accumulated Amortization	(4.2)	(3.7)
Asset Improvements [Member] \| Kansas City Power and Light Company [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	11.2	11.7
Finite-Lived Intangible Assets, Accumulated Amortization	$ (0.8)	$ (0.6)

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Additions	$ 0.0	$ 0.8
Revision in timing and/or estimates	(7.7)	(3.8)
Settlements	(1.8)	0.0
Accretion	9.2	9.3
Asset Retirement Obligation	149.3	149.6	$ 143.3
Kansas City Power and Light Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Additions	0.0	0.0
Revision in timing and/or estimates	(7.7)	(3.8)
Settlements	(1.8)	0.0
Accretion	8.4	8.4
Asset Retirement Obligation	$ 133.2	$ 134.3	$ 129.7

Pension Plans and Other Employee Benefits (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Pension and Other Postretirement Defined Benefit Plans, Current Liabilities

$ (2.8)

$ (4.4)

Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent

(557.5)

(461.9)

Other Changes In Plan Assets And Benefit Obligations Recognized In Other Comprehensive Income Regulatory Assets/Liabilities [Abstract]

Net gain (loss) arising during period

2.3

1.2

$ 1.3

Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax

(0.5)

(0.4)

(0.3)

Pension plans with the accumulated benefit obligation in excess of plans assets [Abstract]

Unfunded accumulated benefit obligation for GMO SERP

24.0

Segregated assets for GMO SERP

19.9

Employee Savings Plans [Abstract]

Defined contribution savings plan, cost of plan

9.2

8.9

Voluntary Separation Program [Abstract]

Voluntary separation program

(4.3)

12.7

0.0

Amounts recognized in the consolidated balance sheets [Abstract]

Pension and Other Postretirement Defined Benefit Plans, Current Liabilities

(1.4)

(3.0)

Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent

(534.5)

(440.9)

Employee Savings Plans [Abstract]

Defined contribution savings plan, cost of plan

6.7

6.5

Voluntary Separation Program [Abstract]

Voluntary separation program

(4.3)

9.2

0.0

Pension Plans, Defined Benefit [Member]

Change in projected benefit obligation [Roll Forward]

$ 1,130.5

980.6

911.4

35.4

31.1

30.3

Defined Benefit Plan, Contributions by Plan Participants

48.9

49.6

49.3

0.0

Defined Benefit Plan, Plan Amendments

1.1

0.0

Actuarial (gain) loss

127.0

83.2

Defined Benefit Plan, Benefits Paid

(58.1)

(54.7)

Defined Benefit Plan, Settlements, Benefit Obligation

(4.4)

(40.0)

Change in plan assets [Roll Forward]

1,130.5

980.6

911.4

Fair value of plan assets at beginning of the year

666.4

591.1

557.6

Actual return on plan assets

71.2

(3.7)

Defined benefit plan, contributions by employer and participants

60.4

128.8

Defined benefit plan, benefits paid, portion paid from plan assets

(56.3)

(91.6)

Fair value of plan assets at end of the year

666.4

591.1

557.6

Funded status at end of year

(464.1)

(389.5)

Amounts recognized in the consolidated balance sheets [Abstract]

Pension and Other Postretirement Defined Benefit Plans, Current Liabilities

(1.9)

(3.5)

Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent

(462.2)

(386.0)

Defined Benefit Plan Amounts Recognized in Balance Sheet before Regulatory Treatment

(464.1)

(389.5)

Defined benefit plan amount recognized in Accumulated Other Comprehensive Income or regulatory asset/liability

559.5

491.8

Defined Benefit Plan, Amounts Recognized in Balance Sheet

95.4

102.3

Amounts in accumulated other comprehensive income or regulatory asset/liability not yet recognized as a component of net periodic benefit cost [Abstract]

Defined Benefit Plan Accumulated Other Comprehensive Income Or Regulatory Asset/Liability Net Gains/Losses Before Tax

349.0

295.6

Defined Benefit Plan Accumulated Other Comprehensive Income Or Regulatory Asset/Liability Net Prior Service Cost Credit Before Tax

7.3

10.7

Defined Benefit Plan Accumulated Other Comprehensive Income Or Regulatory Asset/Liability Net Transition Obligation Before Tax

0.0

Defined Benefit Plan Accumulated Other Comprehensive Income Other Before Tax

203.2

185.5

Defined benefit plan amount recognized in Accumulated Other Comprehensive Income or regulatory asset/liability

559.5

491.8

Components of net periodic benefit costs [Abstract]

35.4

31.1

30.3

Defined Benefit Plan, Expected Return on Plan Assets

48.9

49.6

49.3

(42.9)

(38.0)

(36.6)

Defined Benefit Plan, Amortization of Prior Service Cost (Credit)

4.5

4.6

Defined Benefit Plan, Amortization of Gains (Losses)

44.5

38.7

37.4

Defined Benefit Plan, Amortization of Transition Obligations (Assets)

0.0

0.1

Settlement charges

0.8

10.1

0.0

Net periodic benefit costs before regulatory adjustment

91.2

96.1

85.1

Defined benefit plan, regulatory adjustment

(15.5)

(27.9)

(32.3)

Defined Benefit Plan, Net Periodic Benefit Cost

75.7

68.2

52.8

Other Changes In Plan Assets And Benefit Obligations Recognized In Other Comprehensive Income Regulatory Assets/Liabilities [Abstract]

Net gain (loss) arising during period

97.9

114.8

29.1

Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax

(44.5)

(38.7)

(37.4)

Prior service cost

1.1

0.0

0.5

Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Benefit Cost, before Tax

(4.5)

(4.6)

Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Transition Asset (Obligation), Recognized in Net Periodic Benefit Cost, before Tax

0.0

(0.1)

Other regulatory activity

17.7

17.1

29.5

Total Recognized In Other Comprehensive Income Or Regulatory Asset/Liability

67.7

88.6

17.0

Total Recognized In Net Periodic Benefit Costs And Other Comprehensive Income Or Regulatory Asset/Liability

143.4

156.8

69.8

Estimated prior service cost that will be amortized in the next fiscal year

2.0

Net loss for the defined benefit plans that will be amortized in the next fiscal year

$ 54.9

Length Of Time For Amortization Of Net Actuarial Gains And Losses For Financial Reporting Purposes

rolling five-year average

Length Of Time For Amortization Of Net Actuarial Gains And Losses For Regulatory Reporting Purposes

ten years

Accumulated benefit obligation (ABO) for all defined benefit plans

$ 985.8

852.6

Pension plans with the accumulated benefit obligation in excess of plans assets [Abstract]

Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation

1,130.5

980.6

Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation

985.8

852.6

Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets

666.4

591.1

Pension plans with plan assets in excess of accumulated benefit obligations [Abstract]

Defined benefit plans with plan assets in excess of accumulated benefit obligations, projected benefit obligation

0.0

Defined benefit plans with plan assets in excess of accumulated benefit obligations, accumulated benefit obligation

0.0

Defined benefit plans with plan assets in excess of accumulated benefit obligations, fair value of plan assets

$ 0.0

Weighted average assumptions used to determine the benefit obligation [Abstract]

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.17%

5.01%

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase

3.69%

4.08%

Weighted average assumptions used to determine net costs [Abstract]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate

5.01%

5.54%

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets

7.29%

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

4.08%

Contribute to plans in next year

$ 76.4

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

84.6

Defined Benefit Plan, Expected Future Benefit Payments, Year Two

72.5

Defined Benefit Plan, Expected Future Benefit Payments, Year Three

73.8

Defined Benefit Plan, Expected Future Benefit Payments, Year Four

73.5

Defined Benefit Plan, Expected Future Benefit Payments, Year Five

76.0

Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter

$ 407.9

Defined Benefit Plan, Target Allocation Percentage

The portfolios are invested, and periodically rebalanced, to achieve targeted allocations of approximately 27% U.S. large cap and small cap equity securities, 20% international equity securities, 36% fixed income securities, 7% real estate, 6% commodities and 4% hedge funds.

Other Postretirement Benefit Plans, Defined Benefit [Member]

Change in projected benefit obligation [Roll Forward]

186.5

$ 154.2

$ 143.6

3.3

3.1

3.8

Defined Benefit Plan, Contributions by Plan Participants

7.8

8.8

6.7

6.6

Defined Benefit Plan, Plan Amendments

0.0

Actuarial (gain) loss

26.7

7.4

Defined Benefit Plan, Benefits Paid

(12.2)

(14.3)

Defined Benefit Plan, Settlements, Benefit Obligation

0.0

Change in plan assets [Roll Forward]

186.5

154.2

143.6

Fair value of plan assets at beginning of the year

$ 90.3

77.4

65.8

Actual return on plan assets

1.4

2.5

Defined benefit plan, contributions by employer and participants

23.7

23.0

Defined benefit plan, benefits paid, portion paid from plan assets

(12.2)

(13.9)

Fair value of plan assets at end of the year

90.3

77.4

65.8

Funded status at end of year

(96.2)

(76.8)

Amounts recognized in the consolidated balance sheets [Abstract]

Pension and Other Postretirement Defined Benefit Plans, Current Liabilities

(0.9)

Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent

(95.3)

(75.9)

Defined Benefit Plan Amounts Recognized in Balance Sheet before Regulatory Treatment

(96.2)

(76.8)

Defined benefit plan amount recognized in Accumulated Other Comprehensive Income or regulatory asset/liability

70.4

52.5

Defined Benefit Plan, Amounts Recognized in Balance Sheet

(25.8)

(24.3)

Amounts in accumulated other comprehensive income or regulatory asset/liability not yet recognized as a component of net periodic benefit cost [Abstract]

Defined Benefit Plan Accumulated Other Comprehensive Income Or Regulatory Asset/Liability Net Gains/Losses Before Tax

43.0

15.7

Defined Benefit Plan Accumulated Other Comprehensive Income Or Regulatory Asset/Liability Net Prior Service Cost Credit Before Tax

29.8

36.9

Defined Benefit Plan Accumulated Other Comprehensive Income Or Regulatory Asset/Liability Net Transition Obligation Before Tax

0.6

1.7

Defined Benefit Plan Accumulated Other Comprehensive Income Other Before Tax

(3.0)

(1.8)

Defined benefit plan amount recognized in Accumulated Other Comprehensive Income or regulatory asset/liability

70.4

52.5

Components of net periodic benefit costs [Abstract]

3.3

3.1

3.8

Defined Benefit Plan, Expected Return on Plan Assets

7.8

8.8

(1.8)

(2.1)

Defined Benefit Plan, Amortization of Prior Service Cost (Credit)

7.1

7.2

Defined Benefit Plan, Amortization of Gains (Losses)

(0.2)

(0.5)

(0.1)

Defined Benefit Plan, Amortization of Transition Obligations (Assets)

1.1

1.3

Settlement charges

0.0

Net periodic benefit costs before regulatory adjustment

17.3

17.1

18.9

Defined benefit plan, regulatory adjustment

1.5

1.1

0.0

Defined Benefit Plan, Net Periodic Benefit Cost

18.8

18.2

18.9

Other Changes In Plan Assets And Benefit Obligations Recognized In Other Comprehensive Income Regulatory Assets/Liabilities [Abstract]

Net gain (loss) arising during period

27.1

6.7

(10.9)

Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax

0.2

0.5

0.1

Prior service cost

0.0

Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Benefit Cost, before Tax

(7.1)

(7.2)

Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Transition Asset (Obligation), Recognized in Net Periodic Benefit Cost, before Tax

(1.1)

(1.3)

Other regulatory activity

(1.2)

(1.0)

0.1

Total Recognized In Other Comprehensive Income Or Regulatory Asset/Liability

17.9

(2.3)

(19.2)

Total Recognized In Net Periodic Benefit Costs And Other Comprehensive Income Or Regulatory Asset/Liability

36.7

$ 15.9

$ (0.3)

Estimated prior service cost that will be amortized in the next fiscal year

7.2

Net loss for the defined benefit plans that will be amortized in the next fiscal year

1.7

Transition costs for the defined benefit plans that will be amortized in the next fiscal year

$ 0.2

Weighted average assumptions used to determine the benefit obligation [Abstract]

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.13%

5.03%

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase

3.50%

4.07%

Weighted average assumptions used to determine net costs [Abstract]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate

5.03%

5.50%

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets

^[1]

2.59%

2.83%

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

4.07%

4.06%

Contribute to plans in next year

$ 18.7

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

8.6

Defined Benefit Plan, Expected Future Benefit Payments, Year Two

8.5

Defined Benefit Plan, Expected Future Benefit Payments, Year Three

8.6

Defined Benefit Plan, Expected Future Benefit Payments, Year Four

8.9

Defined Benefit Plan, Expected Future Benefit Payments, Year Five

9.3

Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter

$ 51.1

Health care cost trend (in hundredths)

7.50%

8.00%

Health care cost rate declining through

2018

Ultimate cost trend rate (in hundredths)

5.00%

Effect on total service and interest component, increase

$ 0.7

Effect on total service and interest component, decrease

(0.6)

Effect on post-retirement benefit obligation, increase

5.0

Effect on post-retirement benefit obligation, decrease

$ (4.4)

[1]	*after tax

Equity Compensation (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

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

Maximum number of shares of common shares authorized (in shares)

8,000,000

Compensation expense

$ 3.3

$ 5.2

$ 4.3

Income tax benefits

$ 1.4

$ 1.9

$ 1.0

Performance Shares [Member]

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

Expected volatility, minimum (in hundredths)

20.00%

Expected volatility, maximum (in hundredths)

21.00%

Expected dividend yield range (in hundredths)

4.27%-4.32%

Risk-free interest rate, minimum (in hundredths)

0.33%

Risk-free interest rate, maximum (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

Granted (in shares)

164,158

Forfeited (in shares)

(74,923)

Performance adjustment (in shares)

(160,717)

Ending balance (in shares)

370,560

442,042

Weighted average beginning balance (in dollars per share)

^[1]

$ 21.06

Weighted average granted (in dollars per share)

19.37

^[1]

$ 26.15

$ 23.37

Weighted average forfeited (in dollars per share)

^[1]

20.10

Weighted average performance adjustment (in dollars per share)

^[1]

15.04

Weighted average ending balance (in dollars per share)

^[1]

$ 23.05

$ 21.06

Total unrecognized compensation expense

$ 1.8

Remaining weighted-average contractual term (in years)

11 months

Fair value of performance shares earned and paid

$ 0.8

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)

165,910

Vested (in shares)

(206,838)

Forfeited (in shares)

(67,816)

Ending balance (in shares)

277,439

386,183

Weighted average beginning balance (in dollars per share)

^[1]

$ 17.06

Weighted average granted (in dollars per share)

19.75

^[1]

$ 19.03

$ 17.80

Weighted average vested (in dollars per share)

^[1]

15.78

Weighted average forfeited (in dollars per share)

^[1]

19.49

Weighted average ending balance (in dollars per share)

^[1]

$ 19.03

$ 17.06

Total unrecognized compensation expense

$ 2.5

Total fair value of shares vested

$ 3.3

$ 2.6

$ 7.3

Remaining weighted-average contractual term (in years)

1 year 6 months

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

Compensation expense

$ 2.3

3.5

3.0

Income tax benefits

$ 1.0

$ 1.3

$ 0.5

[1]	* weighted-average

Equity Compensation Equity Compensation Deferred Directors (Details) - Director [Member] - Director Deferred Share Units [Member]

12 Months Ended

Dec. 31, 2012

$ / shares

Director deferred share units [Roll Forward]

Director deferred share units, beginning balance (in shares) | shares

54,231

Director deferred share units, issued (in shares) | shares

15,587

Director deferred share units, ending balance (in shares) | shares

69,818

Weighted-average grant date fair value, director deferred share units, beginning balance (in dollars per share) | $ / shares

$ 20.19

^[1]

Weighted-average grant date fair value, director deferred share units, issued (in dollars per share) | $ / shares

20.96

^[1]

Weighted-average grant date fair value, director deferred share units, ending balance (in dollars per share) | $ / shares

$ 20.36

^[1]

[1]	* weighted-average

Short-term Borrowings and Short-term Bank Lines of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Short-term Debt [Line Items]
Amount of outstanding cash borrowings	$ 12.0	$ 22.0
Commercial paper outstanding	530.1	267.0
Parent Company [Member]
Short-term Debt [Line Items]
Amount of revolving credit facility	$ 200.0
Revolving credit facility expiration date	Dec. 01, 2016
Covenant term - amount considered in default	$ 50.0
Covenant Term Ratio of Consolidated Indebtedness to Consolidated Capitalization Ratio, Maximum	0.65
Line of Credit Facility, Covenant Compliance	in compliance
Amount of outstanding cash borrowings	$ 12.0	$ 22.0
Weighted-average interest rate from outstanding borrowings	2.00%	2.06%
Amount of letters of credit outstanding	$ 1.8	$ 11.6
Kansas City Power and Light Company [Member]
Short-term Debt [Line Items]
Amount of revolving credit facility	$ 600.0
Revolving credit facility expiration date	Dec. 01, 2016
Covenant term - amount considered in default	$ 50.0
Covenant Term Ratio of Consolidated Indebtedness to Consolidated Capitalization Ratio, Maximum	0.65
Line of Credit Facility, Covenant Compliance	in compliance
Amount of outstanding cash borrowings	$ 0.0	0.0
Commercial paper outstanding	$ 361.0	$ 227.0
Weighted-average interest rate from outstanding borrowings	0.48%	0.50%
Amount of letters of credit outstanding	$ 13.9	$ 21.5
KCPL Greater Missouri Operations [Member]
Short-term Debt [Line Items]
Amount of revolving credit facility	$ 450.0
Revolving credit facility expiration date	Dec. 01, 2016
Covenant term - amount considered in default	$ 50.0
Covenant Term Ratio of Consolidated Indebtedness to Consolidated Capitalization Ratio, Maximum	0.65
Line of Credit Facility, Covenant Compliance	in compliance
Amount of outstanding cash borrowings	$ 0.0	0.0
Commercial paper outstanding	$ 169.1	$ 40.0
Weighted-average interest rate from outstanding borrowings	0.94%	0.88%
Amount of letters of credit outstanding	$ 15.1	$ 13.2

Long-Term Debt (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Long-term debt excluding current maturities

$ (263.1)

$ (801.4)

^[1]

2,756.8

2,742.3

Amortization of Financing Costs

5.5

8.1

$ 6.4

Equity Units Remarketing [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

Long-term Debt, Fiscal Year Maturity [Abstract]

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

$ 263.1

Long-term Debt, Maturities, Repayments of Principal in Year Two

1.5

Long-term Debt, Maturities, Repayments of Principal in Year Three

15.5

Long-term Debt, Maturities, Repayments of Principal in Year Four

1.6

Long-term Debt, Maturities, Repayments of Principal in Year Five

382.6

Long-term debt excluding current maturities

(0.4)

(12.7)

Unamortized discount

(4.0)

(4.2)

^[1]

1,901.7

1,901.9

Amortization of Financing Costs

2.9

3.6

2.8

Long-term Debt, Fiscal Year Maturity [Abstract]

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

0.4

Long-term Debt, Maturities, Repayments of Principal in Year Two

0.4

Long-term Debt, Maturities, Repayments of Principal in Year Three

14.4

Long-term Debt, Maturities, Repayments of Principal in Year Four

0.4

Long-term Debt, Maturities, Repayments of Principal in Year Five

281.5

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

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

^[2]

4.97%

$ 400.0

400.0

Dec. 31, 2019

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

7.15%

^[3]

8.59%

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

$ 50.0

50.0

Dec. 31, 2035

KCPL Municipal Bond Insurance Policies [Abstract]

4.65%

Additional collateral necessary due to issuance of additional mortgage bonds

$ 50.0

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

$ 73.2

73.2

Dec. 31, 2035

KCPL Municipal Bond Insurance Policies [Abstract]

5.375%

Principal outstanding covered by insurance policies

$ 73.2

Additional collateral necessary due to issuance of additional mortgage bonds

73.2

Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds Series 2007A-1 due 2035 [Member]

KCPL Municipal Bond Insurance Policies [Abstract]

Principal outstanding covered by insurance policies

63.3

Additional collateral necessary due to issuance of additional mortgage bonds

63.3

Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds EIRR series 2007A-2 due 2035 [Member]

KCPL Municipal Bond Insurance Policies [Abstract]

Principal outstanding covered by insurance policies

10.0

Additional collateral necessary due to issuance of additional mortgage bonds

10.0

Kansas City Power and Light Company [Member] | Secured Debt [Member] | Secured 1992 Series EIRR Bonds [Member]

KCPL Municipal Bond Insurance Policies [Abstract]

Principal outstanding covered by insurance policies

$ 31.0

Insurance agreement covenant indebtedness to total capitalization ratio maximum

0.68

Proportion of secured debt to total indebtedness maximum (in hundredths)

in compliance

75.00%

Proportion of secured debt to total indebtedness based on bond ratings maximum (in hundredths)

50.00%

Aggregate amount of outstanding general mortgage bonds as percentage of total capitalization maximum (in hundredths)

10.00%

Kansas City Power and Light Company [Member] | Secured Debt [Member] | Secured Series 1993a And 1993b Eirr Bonds Member

KCPL Municipal Bond Insurance Policies [Abstract]

Principal outstanding covered by insurance policies

$ 79.5

Insurance agreement covenant indebtedness to total capitalization ratio maximum

0.68

Proportion of secured debt to total indebtedness maximum (in hundredths)

in compliance

75.00%

Proportion of secured debt to total indebtedness based on bond ratings maximum (in hundredths)

50.00%

Aggregate amount of outstanding general mortgage bonds as percentage of total capitalization maximum (in hundredths)

10.00%

Kansas City Power and Light Company [Member] | Secured Debt [Member] | Secured EIRR Bonds Series 2005 [Member]

KCPL Municipal Bond Insurance Policies [Abstract]

Principal outstanding covered by insurance policies

$ 35.9

Insurance agreement covenant indebtedness to total capitalization ratio maximum

0.68

Proportion of secured debt to total indebtedness maximum (in hundredths)

in compliance

75.00%

Proportion of secured debt to total indebtedness based on bond ratings maximum (in hundredths)

50.00%

Aggregate amount of outstanding general mortgage bonds as percentage of total capitalization maximum (in hundredths)

10.00%

Kansas City Power and Light Company [Member] | Secured Debt [Member] | Unsecured EIRR Bonds Series 2005 [Member]

KCPL Municipal Bond Insurance Policies [Abstract]

Principal outstanding covered by insurance policies

$ 50.0

Insurance agreement covenant indebtedness to total capitalization ratio maximum

0.68

Proportion of secured debt to total indebtedness maximum (in hundredths)

in compliance

75.00%

Proportion of secured debt to total indebtedness based on bond ratings maximum (in hundredths)

50.00%

Aggregate amount of outstanding general mortgage bonds as percentage of total capitalization maximum (in hundredths)

10.00%

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

$ 250.0

250.0

Dec. 31, 2017

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

5.85%

^[3]

5.72%

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

$ 350.0

350.0

Dec. 31, 2018

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

6.375%

^[3]

7.49%

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

$ 250.0

250.0

Dec. 31, 2035

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

6.05%

^[3]

5.78%

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

$ 400.0

400.0

Dec. 31, 2041

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

5.30%

$ 23.4

23.4

Dec. 31, 2038

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

4.90%

Bonds purchased in lieu of redemption

$ 63.3

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

Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | Secured Series 1993a And 1993b Eirr Bonds Member

Bonds purchased in lieu of redemption

39.5

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

KCPL Greater Missouri Operations [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

KCPL Greater Missouri Operations [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds SJLP due 2013 [Member]

9.44%

$ 5.6

5.6

Dec. 31, 2013

KCPL Greater Missouri Operations [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds Wamego Series 1996 due 2026 [Member]

5.85%

$ 7.3

7.3

Variable rate (in hundredths)

Dec. 31, 2026

^[4]

0.301%

KCPL Greater Missouri Operations [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds state environmental 1993 due 2028 [Member]

$ 5.0

5.0

Variable rate (in hundredths)

Dec. 31, 2028

^[4]

0.303%

KCPL Greater Missouri Operations [Member] | GMO Senior Notes [Member] | Senior notes 8.27 percent series due 2021 [Member]

$ 80.9

80.9

Dec. 31, 2021

KCPL Greater Missouri Operations [Member] | GMO Senior Notes [Member] | Senior notes 11.875 percent series due 2012 [Member]

8.27%

$ 0.0

500.0

KCPL Greater Missouri Operations [Member] | GMO Senior Notes [Member] | Fair value adjustment [Member]

11.875%

Amortization expense related to fair value adjustment

$ 0.0

16.3

16.3

33.6

34.6

KCPL Greater Missouri Operations [Member] | GMO Medium Term Notes [Member] | Medium term notes 7.16 percent series due 2013 [Member]

$ 6.0

6.0

Dec. 31, 2013

KCPL Greater Missouri Operations [Member] | GMO Medium Term Notes [Member] | Medium term notes 7.33 percent series due 2023 [Member]

7.16%

$ 3.0

3.0

Dec. 31, 2023

KCPL Greater Missouri Operations [Member] | GMO Medium Term Notes [Member] | Medium term notes 7.17 percent series due 2023 [Member]

7.33%

$ 7.0

7.0

Dec. 31, 2023

7.17%

Parent Company [Member]

Long-term debt excluding current maturities

$ (250.0)

(287.5)

743.0

699.3

Parent Company [Member] | Great Plains Energy Senior Notes [Member] | Senor notes due 2013 [Member]

$ 250.0

250.0

Dec. 31, 2013

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

2.75%

^[3]

3.67%

Parent Company [Member] | Great Plains Energy Senior Notes [Member] | Senior notes due 2017 [Member]

$ 100.0

100.0

Dec. 31, 2017

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

6.875%

^[3]

7.33%

Parent Company [Member] | Great Plains Energy Senior Notes [Member] | Senior Notes Due 2021 [Member]

$ 350.0

350.0

Dec. 31, 2021

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

4.85%

^[3]

7.34%

Parent Company [Member] | Great Plains Energy Senior Notes [Member] | Senior Notes Due 2022 [Member]

$ 287.5

0.0

Dec. 31, 2022

Parent Company [Member] | Great Plains Energy Equity Units Subordinated Notes [Member] | Equity Units Subordinated Notes [Member]

5.292%

$ 0.0

287.5

Other Consolidated Entities [Member]

10.00%

Unarmortized discount and premium, net

$ (262.7)

(788.7)

5.4

(0.7)

Amortization of Financing Costs

$ 2.6

$ 4.5

$ 3.6

[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]	Weighted-average interest rates at December 31, 2012
[3]	Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
[4]	Variable rate

Long-Term Debt Long-Term Debt Fair Value (Details) - USD ($) $ in Billions	Dec. 31, 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

Common Shareholders' Equity Common Shareholders' Equity (Details) shares in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2012 USD ($) shares
Common Shareholders' Equity [Abstract]
Shares authorized under the Dividend Reinvestment and Direct Stock Purchase Plan (in shares)	6.0
Number of shares available for grant under the Dividend Reinvestment and Direct Stock Purchase Plan (in shares)	1.5
Shares registered under the defined contribution savings plan (in shares)	14.3
Number of shares available under the defined contribution savings plan (in shares)	2.0
Restrictions on the payment of common stock dividends contained in the articles of incorporation	Great Plains Energy's articles of incorporation restrict the payment of common stock dividends in the event common equity is 25% or less of total capitalization. In addition, if preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of directors necessary to constitute a majority of the full Board.
Regulatory restrictions on the payment of dividends	Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at least 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress). Under the Federal Power Act, KCP&L and GMO generally can pay dividends only out of retained earnings.
Consolidated indebtedness to consolidated total capitalization ratio required under the revolving credit agreement	The revolving credit agreements of Great Plains Energy, KCP&L and GMO contain a covenant requiring each company to maintain a consolidated indebtedness to consolidated total capitalization ratio of not more than 0.65 to 1.00.
Restricted net assets of subsidiaries \| $	$ 2.8

Preferred Stock Preferred Stock (Details) $ / shares in Units, $ in Millions	Dec. 31, 2012 USD ($) $ / shares shares
No Par Preference Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	11,000,000
Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	390,000
Preferred Stock, Shares Outstanding	390,000
Preferred Stock, Par or Stated Value Per Share \| $ / shares	$ 100
Preferred Stock, Value, Outstanding \| $	$ 39.0
Cumulative No Par Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	1,600,000
Minimum [Member]
Class of Stock [Line Items]
Optional Redemption Percentage of Par Value	101.00%
Maximum [Member]
Class of Stock [Line Items]
Optional Redemption Percentage of Par Value	103.70%

Commitments and Contingencies Environmental Matters (Details) T in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2012 USD ($) T MW	Dec. 31, 2011 USD ($)
Air and Climate Change [Abstract]
Current estimate of capital expenditures	$ 1,000.0
Cash capital expenditures incurred for La Cygne environmental project	$ 234.0
Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule (CSAPR) [Abstract]
Number Of States Required To Reduce Emissions Under Cair	28
Mercury and Other Hazardous Air Pollutant Emissions [Abstract]
Capacity of electric steam generating units that fall under MACT standards (in megawatts) \| MW	25
Climate Change [Abstract]
CO2 produced per year (in tons) \| T	25
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]
Amount accrued for future investigation remediation and of GMO retained liabilities	$ 2.0	$ 2.1
LaCygne Station Environmental Retrofits [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Predetermination request for environmental equipment required at LaCygne Station to comply with BART	$ 1,230.0
Kansas City Power and Light Company [Member]
Climate Change [Abstract]
CO2 produced per year (in tons) \| T	19
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) \| MW	2
Remediation [Abstract]
Accrued environmental remediation expenses	$ 0.3	$ 0.3
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%
Kansas City Power and Light Company [Member] \| LaCygne Station Environmental Retrofits [Member]
Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule (CSAPR) [Abstract]
KCPL share of predetermination request for environmental equipment required at LaCygne Station to comply with BART	$ 615.0
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) \| MW	2
Remediation [Abstract]
Estimated amount of insurance proceeds available to cover qualified remediation expenses	$ 2.6
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] \| LaCygne Station [Member]
New Source Review [Abstract]
Estimated cost to install a selective catalytic reduction system at Jeffrey Energy Center pursuant to a settlement agreement	$ 240.0
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%

Commitments and Contingencies Commitments and Contingencies Contractual Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Lease Expense [Abstract]
Lease expense	$ 21.8	$ 20.9	$ 17.2
Total Commitments [Abstract]
Total Commitments, Due in Next Twelve Months	847.9
Total Commitments, Due within Two Years	440.6
Total Commitments, Due within Three Years	202.1
Total Commitments, Due within Four Years	141.9
Total Commitments, Due within Five Years	97.4
Total Commitments, Due Thereafter	931.6
Total Commitments Due	2,661.5
Property, Plant Equipment under operating leases [Member]
Operating Leases [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	16.8
Operating Leases, Future Minimum Payments, Due in Two Years	14.9
Operating Leases, Future Minimum Payments, Due in Three Years	13.7
Operating Leases, Future Minimum Payments, Due in Four Years	9.9
Operating Leases, Future Minimum Payments, Due in Five Years	9.6
Operating Leases, Future Minimum Payments, Due Thereafter	146.5
Operating Leases, Future Minimum Payments Due, Total	211.4
Property, Plant and Equipment under capital leases [Member]
Capital Leases [Abstract]
Capital Leases, Future Minimum Payments Due, Next Twelve Months	0.4
Capital Leases, Future Minimum Payments Due in Two Years	0.4
Capital Leases, Future Minimum Payments Due in Three Years	0.4
Capital Leases, Future Minimum Payments Due in Four Years	0.4
Capital Leases, Future Minimum Payments Due in Five Years	0.4
Capital Leases, Future Minimum Payments Due Thereafter	4.9
Capital Leases, Future Minimum Payments Due, Total	6.9
Public Utilities, Inventory, Fuel [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	323.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	209.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	104.9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	66.7
Unrecorded Unconditional Purchase Obligation, Due within Five Years	36.7
Unrecorded Unconditional Purchase Obligation, Due after Five Years	85.4
Unrecorded Unconditional Purchase Obligation, Total	826.8
Purchased Power [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	39.3
Unrecorded Unconditional Purchase Obligation, Due within Two Years	44.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	44.9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	44.9
Unrecorded Unconditional Purchase Obligation, Due within Five Years	43.5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	651.5
Unrecorded Unconditional Purchase Obligation, Total	869.0
Capacity [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	11.3
Unrecorded Unconditional Purchase Obligation, Due within Two Years	3.3
Unrecorded Unconditional Purchase Obligation, Due within Three Years	3.0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	1.2
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Total	18.8
Non-regulated natural gas transportation [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	3.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	3.6
Unrecorded Unconditional Purchase Obligation, Due within Three Years	3.6
Unrecorded Unconditional Purchase Obligation, Due within Four Years	3.6
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0.9
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Total	14.9
La Cygne Environmental Project [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	329.0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	129.6
Unrecorded Unconditional Purchase Obligation, Due within Three Years	4.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Total	463.0
Other purchase commitments [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	124.7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	34.0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	27.2
Unrecorded Unconditional Purchase Obligation, Due within Four Years	15.2
Unrecorded Unconditional Purchase Obligation, Due within Five Years	6.3
Unrecorded Unconditional Purchase Obligation, Due after Five Years	43.3
Unrecorded Unconditional Purchase Obligation, Total	250.7
Kansas City Power and Light Company [Member]
Lease Expense [Abstract]
Lease expense	17.7	$ 17.0	$ 13.2
Total Commitments [Abstract]
Total Commitments, Due in Next Twelve Months	756.3
Total Commitments, Due within Two Years	391.4
Total Commitments, Due within Three Years	172.9
Total Commitments, Due within Four Years	121.8
Total Commitments, Due within Five Years	86.8
Total Commitments, Due Thereafter	732.8
Total Commitments Due	2,262.0
Kansas City Power and Light Company [Member] \| Supply Commitment [Member]
Total Commitments [Abstract]
Capacity Sales Agreements in 2013	5.9
Capacity Sales Agreements per Year (2014 to 2016)	4.3
Kansas City Power and Light Company [Member] \| Reimbursement Commitments [Member]
Total Commitments [Abstract]
Reimbursement by Other Owners per Year (2013 to 2015)	2.0
Reimbursements by Other Owners per Year (2016 to 2025)	0.4
Reimbursements by Other Owners Total	10.3
Kansas City Power and Light Company [Member] \| Property, Plant Equipment under operating leases [Member]
Operating Leases [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	14.5
Operating Leases, Future Minimum Payments, Due in Two Years	13.1
Operating Leases, Future Minimum Payments, Due in Three Years	12.3
Operating Leases, Future Minimum Payments, Due in Four Years	9.8
Operating Leases, Future Minimum Payments, Due in Five Years	9.6
Operating Leases, Future Minimum Payments, Due Thereafter	146.4
Operating Leases, Future Minimum Payments Due, Total	205.7
Kansas City Power and Light Company [Member] \| Property, Plant and Equipment under capital leases [Member]
Capital Leases [Abstract]
Capital Leases, Future Minimum Payments Due, Next Twelve Months	0.2
Capital Leases, Future Minimum Payments Due in Two Years	0.2
Capital Leases, Future Minimum Payments Due in Three Years	0.2
Capital Leases, Future Minimum Payments Due in Four Years	0.2
Capital Leases, Future Minimum Payments Due in Five Years	0.2
Capital Leases, Future Minimum Payments Due Thereafter	2.5
Capital Leases, Future Minimum Payments Due, Total	3.5
Kansas City Power and Light Company [Member] \| Public Utilities, Inventory, Fuel [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	261.7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	177.6
Unrecorded Unconditional Purchase Obligation, Due within Three Years	91.8
Unrecorded Unconditional Purchase Obligation, Due within Four Years	61.4
Unrecorded Unconditional Purchase Obligation, Due within Five Years	36.7
Unrecorded Unconditional Purchase Obligation, Due after Five Years	85.4
Unrecorded Unconditional Purchase Obligation, Total	714.6
Kansas City Power and Light Company [Member] \| Purchased Power [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	29.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	34.8
Unrecorded Unconditional Purchase Obligation, Due within Three Years	34.8
Unrecorded Unconditional Purchase Obligation, Due within Four Years	34.8
Unrecorded Unconditional Purchase Obligation, Due within Five Years	34.8
Unrecorded Unconditional Purchase Obligation, Due after Five Years	464.3
Unrecorded Unconditional Purchase Obligation, Total	632.7
Kansas City Power and Light Company [Member] \| Capacity [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	2.9
Unrecorded Unconditional Purchase Obligation, Due within Two Years	2.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	3.0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	1.2
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Total	10.0
Kansas City Power and Light Company [Member] \| La Cygne Environmental Project [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	329.0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	129.6
Unrecorded Unconditional Purchase Obligation, Due within Three Years	4.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Total	463.0
Kansas City Power and Light Company [Member] \| Other purchase commitments [Member]
Purchase Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	118.8
Unrecorded Unconditional Purchase Obligation, Due within Two Years	33.2
Unrecorded Unconditional Purchase Obligation, Due within Three Years	26.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years	14.4
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5.5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	34.2
Unrecorded Unconditional Purchase Obligation, Total	$ 232.5

Legal Proceedings Loss Contingencies (Details) - Pending Litigation [Member] - KCPL Greater Missouri Operations [Member] $ in Millions	Dec. 31, 2012 USD ($)
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

Legal Proceedings (Details) - Positive Outcome of Litigation [Member] $ in Millions	12 Months Ended
	Dec. 31, 2012 USD ($)
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
Kansas City Power and Light Company [Member] \| Subsequent Event [Member]
Gain Contingencies [Line Items]
Subsequent Event Amount	$ 6.0
Subsequent Event Description	KCP&L received payment of the $6.0 million award in February 2013.

Guarantees Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
Guarantees Guarantees (Details) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Guarantor Obligations [Line Items]
Commercial paper	$ 530.1	$ 267.0
Commercial paper outstanding	530.1	267.0
Amount of outstanding cash borrowings	12.0	22.0
KCPL Greater Missouri Operations [Member]
Guarantor Obligations [Line Items]
Commercial paper	169.1	40.0
Commercial paper outstanding	169.1	40.0
Letters of Credit Outstanding, Amount	15.1	13.2
Amount of outstanding cash borrowings	0.0	0.0
KCPL Greater Missouri Operations [Member] \| Direct Guarantee [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 40.7
Guarantor Obligations, Term	expire in 2014
KCPL Greater Missouri Operations [Member] \| Standby Letters of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1.8
Guarantor Obligations, Term	expire in 2013
KCPL Greater Missouri Operations [Member] \| Guarantee of Indebtedness of Others [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 112.6
Guarantor Obligations, Term	maturity dates ranging from 2013-2023
KCPL Greater Missouri Operations [Member] \| Revolving Credit Facility [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 450.0
Guarantor Obligations, Term	expiring in December 2016
Kansas City Power and Light Company [Member]
Guarantor Obligations [Line Items]
Commercial paper	$ 361.0	227.0
Commercial paper outstanding	361.0	227.0
Letters of Credit Outstanding, Amount	13.9	21.5
Amount of outstanding cash borrowings	$ 0.0	$ 0.0

Related Party Transactions and Relationships (Details) - Kansas City Power and Light Company [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
KCP and L employees manage GMO's business and operate its facilities at cost	$ 103.7	$ 108.4	$ 100.9
KCP and L net wholesale sales to GMO	29.4	18.2	$ 10.6
KCPL Greater Missouri Operations [Member]
Related Party Transaction [Line Items]
Receivable from Related Party	26.2	24.1
Great Plains Energy [Member]
Related Party Transaction [Line Items]
Receivable from Related Party	$ 13.8	$ 9.5

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).

Derivative Instruments (Details) - USD ($) $ in Millions	Dec. 31, 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	17.9	23.6
Fair Value	(2.8)	(5.0)
Forward Contracts [Member] \| Not Designated as Hedging Instrument [Member]
Price Risk Derivatives [Abstract]
Notional Contract Amount	65.5	97.3
Fair Value	6.5	7.8
Option contracts [Member] \| Not Designated as Hedging Instrument [Member]
Price Risk Derivatives [Abstract]
Notional Contract Amount	0.0	0.4
Fair Value	$ 0.0	0.0
Kansas City Power and Light Company [Member]
Price Risk Derivatives [Abstract]
Percentage of projected natural gas usage hedged year one	100.00%
Percentage of projected natural gas usage hedged year two	81.00%
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 year one	84.00%
Percentage of expected on peak natural gas and natural gas equivalent purchased power price exposure hedged year two	17.00%
Percentage of expected on peak natural gas and natural gas equivalent purchased power price exposure hedged year three	2.00%

Derivative Instruments Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	$ 6.5	$ 7.8
Derivative liability, fair value, amount not offset against collateral	3.0	5.5
Cash Flow Hedging [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(35.4)	(47.9)
Cash Flow Hedging [Member] \| Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(25.8)	(31.4)
Cash Flow Hedging [Member] \| Current assets [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	10.6	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	10.6	11.3
Cash Flow Hedging [Member] \| Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(68.4)	(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	(52.8)	(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	22.5	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	16.5	20.0
Commodity Contract [Member] \| Designated as Hedging Instrument [Member] \| Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	0.0	0.0
Derivative liability, fair value, amount not offset against collateral	0.2	0.5
Commodity Contract [Member] \| Designated as Hedging Instrument [Member] \| Derivative [Member] \| Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	0.0	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 [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	6.5	7.8
Derivative liability, fair value, amount not offset against collateral	$ 2.8	$ 5.0

Derivative Instruments by Hedging Relationship by Income Statement Location (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	$ (0.1)	$ (3.6)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(12.6)	(10.4)
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)	(0.4)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(5.7)	(5.4)
Cash Flow Hedging [Member] \| Interest charges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(20.2)	(16.9)
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)	(8.7)	(8.7)
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)
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)
Cash Flow Hedging [Member] \| Income tax benefit (expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	8.1	6.6
Cash Flow Hedging [Member] \| Income tax benefit (expense) [Member] \| Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	3.5	3.4
Regulatory Account [Member] \| Fuel Costs [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain(Loss) Reclassified from Regulatory Account into Income (Effective Portion)	(6.6)	(3.8)
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	(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)	(0.6)
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)	(0.6)
Commodity Contract [Member] \| Regulatory Account [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized on Regulatory Account on Derivatives (Effective Portion)	(2.7)	(8.3)
Income tax benefit (expense) [Member] \| Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0.0	2.3
Income tax benefit (expense) [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	$ 0.2

Derivative Instruments Gain and Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 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	$ 1.3	$ 1.1

Derivative Instruments Cash Flow Hedge (Details) $ in Millions	12 Months Ended
	Dec. 31, 2012 USD ($)
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 20.4
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

Dec. 31, 2012

Dec. 31, 2011

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

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

0.1

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

3.0

5.5

Debt securities related to nuclear decommissioning trust [Abstract]

^[1]

6.5

7.8

^[2]

151.8

132.3

^[3]

20.3

0.3

178.6

140.4

^[1]

0.0

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

0.0

Debt securities related to nuclear decommissioning trust [Abstract]

^[1],[4]

0.0

^[2],[4]

0.0

^[3],[4]

0.0

^[4]

0.0

^[1],[4]

(3.0)

(5.5)

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

^[4]

(3.0)

(5.5)

Debt securities related to nuclear decommissioning trust [Abstract]

^[1]

0.0

^[2]

118.6

99.6

^[3]

0.1

0.2

118.7

99.8

^[1]

3.0

5.5

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

3.0

5.5

Debt securities related to nuclear decommissioning trust [Abstract]

^[1]

4.2

4.7

^[2]

33.2

32.7

^[3]

20.2

0.1

57.6

37.5

^[1]

0.0

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

0.0

Debt securities related to nuclear decommissioning trust [Abstract]

^[1]

2.3

3.1

^[2]

0.0

^[3]

0.0

2.3

3.1

^[1]

0.0

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

0.0

Equity securities related to nuclear decommissioning trust

100.1

84.3

Debt securities related to nuclear decommissioning trust [Abstract]

18.5

15.3

2.8

3.6

3.3

2.6

26.8

26.4

0.7

0.3

(0.6)

^[2]

151.8

132.3

151.8

132.3

^[1]

0.0

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

0.0

Equity securities related to nuclear decommissioning trust

^[4]

0.0

Debt securities related to nuclear decommissioning trust [Abstract]

^[4]

0.0

^[4]

0.0

^[4]

0.0

^[4]

0.0

^[4]

0.0

^[4]

0.0

^[2],[4]

0.0

^[4]

0.0

^[1],[4]

(0.2)

(0.5)

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

^[4]

(0.2)

(0.5)

Equity securities related to nuclear decommissioning trust

100.1

84.3

Debt securities related to nuclear decommissioning trust [Abstract]

18.5

15.3

0.0

0.0

0.0

0.0

^[2]

118.6

99.6

118.6

99.6

^[1]

0.2

0.5

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

0.2

0.5

Equity securities related to nuclear decommissioning trust

0.0

Debt securities related to nuclear decommissioning trust [Abstract]

0.0

2.8

3.6

3.3

2.6

26.8

26.4

0.7

0.3

(0.6)

^[2]

33.2

32.7

33.2

32.7

^[1]

0.0

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

0.0

Equity securities related to nuclear decommissioning trust

0.0

Debt securities related to nuclear decommissioning trust [Abstract]

0.0

0.0

0.0

0.0

0.0

^[2]

0.0

0.0

^[1]

0.0

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

0.0

^[1]

6.5

7.8

0.1

0.2

20.2

0.1

^[3]

20.3

0.3

26.8

8.1

^[1]

0.0

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

0.0

^[1],[4]

0.0

^[4]

0.0

^[4]

0.0

^[3],[4]

0.0

^[4]

0.0

^[1],[4]

(2.8)

(5.0)

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

^[4]

(2.8)

(5.0)

^[1]

0.0

0.1

0.2

0.0

^[3]

0.1

0.2

0.1

0.2

^[1]

2.8

5.0

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

2.8

5.0

^[1]

4.2

4.7

0.0

20.2

0.1

^[3]

20.2

0.1

24.4

4.8

^[1]

0.0

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

0.0

^[1]

2.3

3.1

0.0

0.0

^[3]

0.0

2.3

3.1

^[1]

0.0

$ 0.0

[1]	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 December 31, 2012 and 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.
[2]	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.
[3]	Fair value is based on quoted market prices and/or valuation models for equity and debt securities and NAV per share for fixed income funds. The total does not include $0.1 million and $20.3 million at December 31, 2012 and 2011, respectively, 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 sheets where a master netting agreement exists between the Company and the counterparty. At December 31, 2012 and 2011, Great Plains Energy netted $3.0 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	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	$ 3.1	$ 3.7
Total realized/unrealized gains or (losses) included in non-operating income	8.2	10.9
Settlements	(9.0)	(11.5)
Balance at end of period	2.3	3.1
Total unrealized gains and (losses) included in non-operating income relating to assets and liabilities still on the consolidated balance sheet at period end	$ (0.4)	$ (0.2)

Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
Income Tax Expense (Details) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current income taxes
Federal	$ (3.2)	$ 2.9	$ (7.4)
State	(6.3)	(6.0)	(4.3)
Foreign	0.0	(0.4)	0.1
Current Income Tax Expense (Benefit), Total	(9.5)	(3.5)	(11.6)
Deferred income taxes
Federal	96.3	90.5	99.8
State	24.9	20.7	24.0
Deferred Income Tax Expense (Benefit), Total	121.2	111.2	123.8
Noncurrent income taxes
Federal	(0.2)	(18.0)	(4.8)
State	(0.3)	(2.1)	(1.8)
Foreign	(4.2)	(0.6)	0.5
Noncurrent Income Tax Expense (Benefit), Total	(4.7)	(20.7)	(6.1)
Investment tax credit
Deferral	0.0	0.0	(4.2)
Amortization	(2.4)	(2.2)	(2.9)
Investment Tax Credit, Total	(2.4)	(2.2)	(7.1)
Total income tax expense	$ 104.6	$ 84.8	$ 99.0
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]
Federal statutory income tax (in hundredths)	35.00%	35.00%	35.00%
Differences between book and tax depreciation not normalized (in hundredths)	1.20%	1.50%	(1.70%)
Amortization of investments tax credits (in hundredths)	(0.80%)	(0.80%)	(0.90%)
Federal income tax credits (in hundredths)	(3.10%)	(5.00%)	(4.10%)
State income taxes (in hundredths)	4.00%	4.00%	3.70%
Effective Income Tax Rate Reconciliation, Deductions, Medicare Prescription Drug Benefit	0.00%	0.00%	0.90%
Changes in uncertain tax positions, net (in hundredths)	(1.50%)	(1.70%)	0.10%
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance	0.00%	(0.80%)	(0.90%)
Effective Income Tax Rate Reconciliation, Other Adjustments	(0.50%)	0.50%	(0.30%)
Effective Income Tax Rate, Continuing Operations, Total	34.30%	32.70%	31.80%
Kansas City Power and Light Company [Member]
Current income taxes
Federal	$ 13.1	$ 1.0	$ 5.5
State	2.0	(0.6)	1.1
Current Income Tax Expense (Benefit), Total	15.1	0.4	6.6
Deferred income taxes
Federal	48.8	66.0	69.8
State	11.4	14.6	13.4
Deferred Income Tax Expense (Benefit), Total	60.2	80.6	83.2
Noncurrent income taxes
Federal	1.7	(9.3)	(1.6)
State	0.1	(1.1)	(0.3)
Noncurrent Income Tax Expense (Benefit), Total	1.8	(10.4)	(1.9)
Investment tax credit
Deferral	0.0	0.0	(4.2)
Amortization	(1.8)	(1.5)	(2.1)
Investment Tax Credit, Total	(1.8)	(1.5)	(6.3)
Total income tax expense	$ 75.3	$ 69.1	$ 81.6
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]
Federal statutory income tax (in hundredths)	35.00%	35.00%	35.00%
Differences between book and tax depreciation not normalized (in hundredths)	1.30%	1.60%	(1.80%)
Amortization of investments tax credits (in hundredths)	(0.80%)	(0.70%)	(0.90%)
Federal income tax credits (in hundredths)	(4.30%)	(6.30%)	(3.50%)
State income taxes (in hundredths)	4.10%	3.90%	3.60%
Effective Income Tax Rate Reconciliation, Deductions, Medicare Prescription Drug Benefit	0.00%	0.00%	1.10%
Changes in uncertain tax positions, net (in hundredths)	0.00%	0.10%	0.00%
Effective Income Tax Rate Reconciliation, Other Adjustments	(0.60%)	0.20%	(0.20%)
Effective Income Tax Rate, Continuing Operations, Total	34.70%	33.80%	33.30%
Parent Company [Member]
Deferred income taxes
Deferred Income Tax Expense (Benefit), Total	$ (4.8)	$ (18.6)	$ 13.9
Investment tax credit
Total income tax expense	$ (11.6)	$ (17.1)	$ (15.8)

Taxes Deferred Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Deferred Tax Assets (Liabilities), Net of Valuation Allowance, Current Classification [Abstract]
Net operating loss carryforward, current	$ 77.8	$ 0.0
Deferred tax assets, other current	12.7	7.9
Deferred Tax Assets, Gross, Current	90.5	7.9
Valuation allowance, current	(2.0)	(0.4)
Deferred Tax Assets (Liabilities), Net, Current	88.5	7.5
Deferred Tax Assets (Liabilities), Net of Valuation Allowance, Noncurrent Classification [Abstract]
Plant related	(1,297.2)	(1,193.6)
Income taxes on future regulatory recoveries	(138.3)	(144.3)
Derivative instruments	37.7	43.3
Pension and post-retirement benefits	(26.6)	(34.2)
SO2 emission allowance sales	29.7	31.1
Fuel recovery mechanisms	(8.6)	(17.2)
Transition costs	(13.3)	(17.4)
Tax credit carryforwards	217.5	213.7
Long-term debt fair value adjustment	0.0	6.3
Customer demand programs	(28.7)	(26.4)
Net operating loss carryforward, noncurrent	439.4	543.7
Deferred tax assets, other noncurrent	(22.2)	(10.1)
Deferred Tax Assets, Gross, Noncurrent	(810.6)	(605.1)
Valuation allowance, noncurrent	(21.8)	(23.5)
Deferred Tax Assets (Liabilities), Net, Noncurrent	(832.4)	(628.6)
Deferred Tax Assets (Liabilities), Net	(743.9)	(621.1)
Deferred Tax Assets (Liabilities), Gross [Abstract]
Deferred Tax Assets, Gross	1,209.8	1,203.6
Deferred Tax Liabilities, Gross	(1,953.7)	(1,824.7)
Deferred Tax Assets, Net	(743.9)	(621.1)
Valuation Allowance [Abstract]
Valuation Allowance, Deferred Tax Asset, Change in Amount	0.0	$ 2.7
Valuation Allowance, Deferred Tax Asset, Explanation of Change		Tax benefit recorded primarily related to a portion of the valuation allowance against state NOL carryforwards
Kansas City Power and Light Company [Member]
Deferred Tax Assets (Liabilities), Net of Valuation Allowance, Current Classification [Abstract]
Net operating loss carryforward, current	0.0	$ 0.0
Deferred tax assets, other current	4.6	(0.1)
Deferred Tax Assets, Gross, Current	4.6	(0.1)
Valuation allowance, current	0.0	0.0
Deferred Tax Assets (Liabilities), Net, Current	4.6	(0.1)
Deferred Tax Assets (Liabilities), Net of Valuation Allowance, Noncurrent Classification [Abstract]
Plant related	(930.7)	(861.6)
Income taxes on future regulatory recoveries	(114.7)	(119.6)
Derivative instruments	27.4	31.1
Pension and post-retirement benefits	(3.4)	(11.7)
SO2 emission allowance sales	30.4	31.9
Fuel recovery mechanisms	(3.5)	(5.4)
Transition costs	(7.3)	(9.6)
Tax credit carryforwards	126.3	116.8
Long-term debt fair value adjustment	0.0	0.0
Customer demand programs	(19.2)	(18.6)
Net operating loss carryforward, noncurrent	72.4	77.9
Deferred tax assets, other noncurrent	(14.1)	(3.9)
Deferred Tax Assets, Gross, Noncurrent	(836.4)	(772.7)
Valuation allowance, noncurrent	0.0	0.0
Deferred Tax Assets (Liabilities), Net, Noncurrent	(836.4)	(772.7)
Deferred Tax Assets (Liabilities), Net	(831.8)	(772.8)
Deferred Tax Assets (Liabilities), Gross [Abstract]
Deferred Tax Assets, Gross	656.9	618.7
Deferred Tax Liabilities, Gross	(1,488.7)	(1,391.5)
Deferred Tax Assets, Net	$ (831.8)	$ (772.8)

Taxes Tax Credit Carryforwards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Valuation Allowance	$ 0.1
General Business Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	127.6	$ 118.0
Amount of tax credit acquired in business combination	$ 0.5
Tax Credit Carryforward, Description	Federal general business income tax credit carryforwards.	Federal general business income tax credit carryforwards.
Tax Credit Carryforward, Valuation Allowance	$ 0.4
Federal Alternative Minimum Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	87.9	$ 91.0
Amount of tax credit acquired in business combination	$ 87.6	$ 89.8
Tax Credit Carryforward, Description	Federal alternative minimum tax credit carryforwards which do not expire and can be used to reduce taxes paid in the future.	Federal alternative minimum tax credit carryforwards which do not expire and can be used to reduce taxes paid in the future.
State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	$ 2.0	$ 4.7
Tax Credit Carryforward, Description	State income tax credit carryforwards, which relate primarily to the Company's Missouri affordable housing investment portfolio and expire in the years 2013 to 2016.	State income tax credit carryforwards, which relate primarily to the Company's Missouri affordable housing investment portfolio and expire in the years 2013 to 2016.
Kansas City Power and Light Company [Member] \| General Business Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	$ 126.3	$ 116.8
Tax Credit Carryforward, Description		Federal general business income tax credit carryforwards, which relate primarily to Advanced Coal Credit Investment Tax Credits and Wind Production tax credits and expire in the years 2028 to 2032.

The portion of the deferred tax asset arising from a tax credit carryforward for which it is more likely than not that a tax benefit will not be realized.

Taxes Net Operating Loss Carryforwards (Details) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 451.1	$ 473.1
Amount of Net Operating Losses related to business acquisition	304.8	315.7
Net operating losses year of origination [Abstract]
Net operating loss carryforwards originating in 2003	21.7
Net operating loss carryfowards originating in 2004	152.4
Net operating loss carryfowards originating in 2005	74.1
Net operating loss carryfowards originating in 2006	53.3
Net operating loss carryfowards originating in 2007	1.3
Net operating loss carryfowards originating in 2008	2.4
Net operating loss carryfowards originating in 2009	23.8
Net operating loss carryfowards originating in 2010	12.0
Net operating loss carryfowards originating in 2011	110.1
Internal Revenue Service (IRS) [Member] \| Minimum [Member]
Operating Loss Carryforwards [Line Items]
Expected revised current deferred income tax asset for net operating losses	0.0
Internal Revenue Service (IRS) [Member] \| Maximum [Member]
Operating Loss Carryforwards [Line Items]
Expected revised current deferred income tax asset for net operating losses	10.0
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	66.1	70.6
Amount of Net Operating Losses related to business acquisition	47.9	$ 49.9
Operating Loss Carryforwards, Valuation Allowance	$ 23.3

Taxes Uncertain Tax Positions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Uncertain Tax Positions [Line Items]
Amount expected to impact the effective tax rate if recognized	$ 7.3	$ 11.8	$ 17.3
Unrecognized Tax Benefits, Period Increase (Decrease)	(2.6)	(18.0)
Unrecognized tax benefit increase (decrease) related to former GMO non-regulated operations	(4.5)
Unrecognized tax benefit increase (decrease) related to audit settlements		(18.4)
Deferred income tax liability increase (decrease) related to audit settlements		16.4
Increase (decrease) in net income related to settlement of tax audit		2.0
Accrued interest related to unrecognized tax benefits	3.5	5.7	6.7
Accrued penalties with respect to unrecognized tax benefits	0.7	1.1	1.1
Interest expense related to unrecognized tax benefits	2.3	0.9	(0.5)
Amount of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities	5.5
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	24.0	42.0	51.4
Additions for current year tax positions	3.7	1.4	2.7
Additions for prior year tax positions	0.0	2.4	2.1
Reductions for prior year tax positions	(1.8)	(20.9)	(10.6)
Settlements	0.0	0.0	(3.8)
Statute expirations	(4.7)	(0.7)	(0.3)
Foreign currency translation adjustments	0.2	(0.2)	0.5
Balance at end of period	21.4	24.0	42.0
Kansas City Power and Light Company [Member]
Uncertain Tax Positions [Line Items]
Amount expected to impact the effective tax rate if recognized	0.0	0.2	0.3
Unrecognized Tax Benefits, Period Increase (Decrease)	1.8	(10.4)
Unrecognized tax benefit increase (decrease) related to audit settlements		(12.1)
Uncertain tax position increase (decrease) related to temporary differences	3.6
Accrued interest related to unrecognized tax benefits	0.1	0.2	1.4
Interest expense related to unrecognized tax benefits	0.1	1.2	0.3
Amount of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities	4.4
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	8.7	19.1	20.9
Additions for current year tax positions	3.6	0.0	1.3
Additions for prior year tax positions	0.0	2.3	1.5
Reductions for prior year tax positions	(1.6)	(12.6)	(1.6)
Settlements	0.0	0.0	(2.9)
Statute expirations	(0.2)	(0.1)	(0.1)
Foreign currency translation adjustments	0.0	0.0	0.0
Balance at end of period	$ 10.5	$ 8.7	$ 19.1

Segments and Related Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Operating revenues	$ 480.4	$ 746.2	$ 603.6	$ 479.7	$ 486.3	$ 773.7	$ 565.1	$ 492.9	$ 2,309.9	$ 2,318.0	$ 2,255.5
Depreciation and amortization									(272.3)	(273.1)	(331.6)
Interest charges									(220.8)	(218.4)	(184.8)
Income tax (expense) benefit									(104.6)	(84.8)	(99.0)
Net income (loss) attributable to Great Plains Energy	4.7	$ 146.2	$ 58.1	$ (9.1)	2.1	$ 126.5	$ 43.4	$ 2.4	199.9	174.4	211.7
Assets, Total	9,647.3				9,118.0				9,647.3	9,118.0	8,818.2
Capital expenditures									610.2	456.6	618.1
Electric Utility Segment [Member]
Segment Reporting Information [Line Items]
Operating revenues									2,309.9	2,318.0	2,255.5
Depreciation and amortization									(272.3)	(273.1)	(331.6)
Interest charges									(197.3)	(176.9)	(143.1)
Income tax (expense) benefit									(122.0)	(109.3)	(123.3)
Net income (loss) attributable to Great Plains Energy									216.6	199.9	235.3
Assets, Total	9,910.6				9,483.4				9,910.6	9,483.4	9,152.7
Capital expenditures									610.2	456.6	618.1
All Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues									0.0	0.0	0.0
Depreciation and amortization									0.0	0.0	0.0
Interest charges									(67.3)	(67.2)	(45.5)
Income tax (expense) benefit									17.4	24.5	24.3
Net income (loss) attributable to Great Plains Energy									(16.7)	(25.5)	(23.6)
Assets, Total	122.4				51.9				122.4	51.9	66.3
Capital expenditures									0.0	0.0	0.0
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Operating revenues									0.0	0.0	0.0
Depreciation and amortization									0.0	0.0	0.0
Interest charges									43.8	25.7	3.8
Income tax (expense) benefit									0.0	0.0	0.0
Net income (loss) attributable to Great Plains Energy									0.0	0.0	0.0
Assets, Total	$ (385.7)				$ (417.3)				(385.7)	(417.3)	(400.8)
Capital expenditures									$ 0.0	$ 0.0	$ 0.0

Jointly Owned Electric Utility Plants (Details) $ in Millions	Dec. 31, 2012 USD ($) MW	Dec. 31, 2011 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Nuclear fuel, net	$ 81.3	$ 76.6
Jointly Owned Electricity Generation Plant [Member] \| LaCygne Station [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	50.00%
Utility plant in service	$ 504.5
Accumulated depreciation	308.6
Nuclear fuel, net	0.0
Construction work in progress	$ 262.0
Accredited capacity (in MW's) \| MW	711
Jointly Owned Electricity Generation Plant [Member] \| Iatan No. 1 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	88.00%
Utility plant in service	$ 667.5
Accumulated depreciation	264.9
Nuclear fuel, net	0.0
Construction work in progress	$ 14.1
Accredited capacity (in MW's) \| MW	620
Jointly Owned Electricity Generation Plant [Member] \| Iatan No. 2 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	73.00%
Utility plant in service	$ 1,297.9
Accumulated depreciation	294.7
Nuclear fuel, net	0.0
Construction work in progress	$ 5.7
Accredited capacity (in MW's) \| MW	641
Jointly Owned Electricity Generation Plant [Member] \| Iatan Common [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	79.00%
Utility plant in service	$ 374.9
Accumulated depreciation	42.9
Nuclear fuel, net	0.0
Construction work in progress	$ 25.9
Jointly Owned Electricity Generation Plant [Member] \| Jeffrey Energy Center [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	8.00%
Utility plant in service	$ 167.2
Accumulated depreciation	75.2
Nuclear fuel, net	0.0
Construction work in progress	$ 6.3
Accredited capacity (in MW's) \| MW	172
Jointly Owned Nuclear Power Plant [Member] \| Wolf Creek Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	47.00%
Utility plant in service	$ 1,483.6
Accumulated depreciation	801.1
Nuclear fuel, net	81.3
Construction work in progress	$ 99.8
Accredited capacity (in MW's) \| MW	547
Kansas City Power and Light Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Nuclear fuel, net	$ 81.3	$ 76.6
Kansas City Power and Light Company [Member] \| LaCygne Station [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	50.00%
Kansas City Power and Light Company [Member] \| Jointly Owned Electricity Generation Plant [Member] \| LaCygne Station [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	50.00%
Utility plant in service	$ 504.5
Accumulated depreciation	308.6
Nuclear fuel, net	0.0
Construction work in progress	$ 262.0
Accredited capacity (in MW's) \| MW	711
Kansas City Power and Light Company [Member] \| Jointly Owned Electricity Generation Plant [Member] \| Iatan No. 1 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	70.00%
Utility plant in service	$ 541.3
Accumulated depreciation	217.6
Nuclear fuel, net	0.0
Construction work in progress	$ 5.5
Accredited capacity (in MW's) \| MW	493
Kansas City Power and Light Company [Member] \| Jointly Owned Electricity Generation Plant [Member] \| Iatan No. 2 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	55.00%
Utility plant in service	$ 987.2
Accumulated depreciation	279.6
Nuclear fuel, net	0.0
Construction work in progress	$ 4.5
Accredited capacity (in MW's) \| MW	482
Kansas City Power and Light Company [Member] \| Jointly Owned Electricity Generation Plant [Member] \| Iatan Common [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	61.00%
Utility plant in service	$ 295.3
Accumulated depreciation	36.8
Nuclear fuel, net	0.0
Construction work in progress	$ 6.9
Kansas City Power and Light Company [Member] \| Jointly Owned Nuclear Power Plant [Member] \| Wolf Creek Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	47.00%
Utility plant in service	$ 1,483.6
Accumulated depreciation	801.1
Nuclear fuel, net	81.3
Construction work in progress	$ 99.8
Accredited capacity (in MW's) \| MW	547

Quarterly Operating Results Quarterly Operating Results (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating revenues	$ 480.4	$ 746.2	$ 603.6	$ 479.7	$ 486.3	$ 773.7	$ 565.1	$ 492.9	$ 2,309.9	$ 2,318.0	$ 2,255.5
Operating income (loss)	62.9	277.0	150.0	49.0	60.3	262.7	115.6	41.2	538.9	479.8	472.3
Net income	4.7	146.4	58.1	(9.3)	1.9	126.6	43.4	2.3	199.9	174.2	211.9
Net income (loss) attributable to Great Plains Energy	$ 4.7	$ 146.2	$ 58.1	$ (9.1)	$ 2.1	$ 126.5	$ 43.4	$ 2.4	$ 199.9	$ 174.4	$ 211.7
Earnings Per Share, Basic					$ 0.01	$ 0.93	$ 0.32	$ 0.02	$ 1.36	$ 1.27	$ 1.55
Earnings Per Share, Diluted					$ 0.01	$ 0.91	$ 0.31	$ 0.01	$ 1.35	$ 1.25	$ 1.53
Earnings Per Share, Basic and Diluted	$ 0.03	$ 0.95	$ 0.41	$ (0.07)
Kansas City Power and Light Company [Member]
Operating revenues	$ 335.8	$ 508.0	$ 409.1	$ 327.0	$ 337.8	$ 506.3	$ 383.4	$ 330.8	$ 1,579.9	$ 1,558.3	$ 1,517.1
Operating income (loss)	39.4	177.8	99.9	31.6	47.7	169.2	77.8	26.5	348.7	321.2	311.4
Net income	$ 5.4	$ 90.2	$ 43.7	$ 2.3	$ 12.7	$ 85.4	$ 33.4	$ 4.0	$ 141.6	$ 135.5	$ 163.2

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.21)
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 18
-Article 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 36, 37, 38
-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 9: http://www.xbrl.org/2003/role/presentationRef
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-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 10: http://www.xbrl.org/2003/role/presentationRef
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-Number 210
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 21
-Article 9

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Net Income
-URI http://asc.fasb.org/extlink&oid=6518256

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
-Topic 944
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-Name Accounting Standards Codification
-Topic 260
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-Article 9

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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Schedule I Financial Statements of Parent Company Statements of Income & OCI (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Expenses
Selling, general and administrative									$ 7.5	$ 5.9	$ 22.1
General taxes									179.3	170.9	155.1
Operating Income (Loss)	$ 62.9	$ 277.0	$ 150.0	$ 49.0	$ 60.3	$ 262.7	$ 115.6	$ 41.2	538.9	479.8	472.3
Non-operating income									7.3	5.9	43.9
Interest charges									(220.8)	(218.4)	(184.8)
Income before income tax (expense) benefit and income (loss) from equity investments									304.9	259.1	311.9
Income tax (expense) benefit									(104.6)	(84.8)	(99.0)
Net income	4.7	146.4	58.1	(9.3)	$ 1.9	$ 126.6	$ 43.4	$ 2.3	199.9	174.2	211.9
Preferred stock dividend requirements									1.6	1.6	1.6
Earnings available for common shareholders									$ 198.3	$ 172.8	$ 210.1
Average number of common shares outstanding (in shares)									145.5	135.6	135.1
Weighted Average Number of Shares Outstanding, Basic									145.5	135.6	135.1
Weighted Average Number of Shares Outstanding, Diluted									147.2	138.7	136.9
Earnings Per Share, Basic					$ 0.01	$ 0.93	$ 0.32	$ 0.02	$ 1.36	$ 1.27	$ 1.55
Earnings Per Share, Diluted					$ 0.01	$ 0.91	$ 0.31	$ 0.01	1.35	1.25	1.53
Common Stock, Dividends, Per Share, Declared									$ 0.855	$ 0.835	$ 0.830
Comprehensive Income
Net income	$ 4.7	$ 146.4	$ 58.1	$ (9.3)	$ 1.9	$ 126.6	$ 43.4	$ 2.3	$ 199.9	$ 174.2	$ 211.9
Other comprehensive income
Gain (loss) on derivative hedging instruments									(0.1)	(5.9)	(28.0)
Income tax benefit (expense) on derivative hedging instruments									0.0	2.3	10.8
Net gain (loss) on derivative hedging instruments									(0.1)	(3.6)	(17.2)
Reclassification to expenses, net of tax									12.6	10.4	6.6
Derivative hedging activity, net of tax									12.5	6.8	(10.6)
Total other comprehensive income (loss)									11.4	6.3	(11.2)
Comprehensive income attributable to Great Plains Energy									211.3	180.7	200.5
Parent Company [Member]
Operating Expenses
Selling, general and administrative									3.3	0.8	1.2
General taxes									0.7	0.9	0.9
Operating Expenses									4.0	1.7	2.1
Operating Income (Loss)									(4.0)	(1.7)	(2.1)
Equity in earnings (loss) from Subsidiaries									219.2	200.8	239.3
Non-operating income									42.7	24.7	3.4
Interest charges									(69.6)	(66.5)	(44.7)
Income before income tax (expense) benefit and income (loss) from equity investments									188.3	157.3	195.9
Income tax (expense) benefit									11.6	17.1	15.8
Net income									199.9	174.4	211.7
Preferred stock dividend requirements									1.6	1.6	1.6
Earnings available for common shareholders									$ 198.3	$ 172.8	$ 210.1
Average number of common shares outstanding (in shares)									145.5	135.6	135.1
Weighted Average Number of Shares Outstanding, Basic									145.5	135.6	135.1
Weighted Average Number of Shares Outstanding, Diluted									147.2	138.7	136.9
Earnings Per Share, Basic									$ 1.36	$ 1.27	$ 1.55
Earnings Per Share, Diluted									1.35	1.25	1.53
Common Stock, Dividends, Per Share, Declared									$ 0.855	$ 0.835	$ 0.83
Comprehensive Income
Net income									$ 199.9	$ 174.4	$ 211.7
Other comprehensive income
Gain (loss) on derivative hedging instruments									0.0	(5.3)	(27.1)
Income tax benefit (expense) on derivative hedging instruments									0.0	2.1	10.5
Net gain (loss) on derivative hedging instruments									0.0	(3.2)	(16.6)
Reclassification to expenses									11.5	8.2	1.3
Income tax (benefit) expense on reclassification to expenses									(4.6)	(3.2)	(0.4)
Reclassification to expenses, net of tax									6.9	5.0	0.9
Derivative hedging activity, net of tax									6.9	1.8	(15.7)
Other comprehensive income from subsidiaries, net of tax									4.5	4.5	4.5
Total other comprehensive income (loss)									11.4	6.3	(11.2)
Comprehensive income attributable to Great Plains Energy									$ 211.3	$ 180.7	$ 200.5

Schedule I Financial Statements of Parent Company Schedule I Financial Statements of Parent Company Balance Sheet (Details) - USD ($)
$ in Millions

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Taxes receivable

$ 9.5

$ 0.3

723.7

619.1

Other investments and other assets

(832.4)

(628.6)

71.4

76.1

9,647.3

9,118.0

$ 8,818.2

12.0

22.0

263.1

801.4

27.1

25.8

Other current liabilities

41.5

76.9

23.9

26.0

1,449.5

1,634.9

2,062.0

1,740.9

2,624.7

2,330.6

Accumulated Other Comprehensive Income (Loss), Net of Tax

758.8

684.7

Treasury Stock, Value

(5.1)

(5.6)

(38.4)

(49.8)

3,340.0

2,959.9

$ 2,885.9

39.0

^[1]

2,756.8

2,742.3

6,135.8

5,742.2

9,647.3

9,118.0

Parent Company [Member]

Accounts receivable from subsidiaries

0.1

0.0

Notes receivable from subsidiaries, current

0.6

Money pool receivable

4.0

0.9

Taxes receivable

0.0

0.9

Other current assets

2.4

0.6

7.1

3.0

Investment in other subsidiaries

Investment in KCP&L

2,096.7

2,045.5

1,405.4

1,377.0

Notes receivable from subsidiaries, noncurrent

883.6

596.2

Other investments and other assets

32.3

33.7

7.6

6.4

Total investments and other assets

4,425.6

4,058.8

4,432.7

4,061.8

12.0

22.0

Accounts payable to subsidiaries

250.0

287.5

34.1

31.8

0.5

5.1

Other current liabilities

6.8

7.6

2.1

2.9

305.5

356.9

5.2

6.7

2,624.7

2,330.6

Accumulated Other Comprehensive Income (Loss), Net of Tax

758.8

684.7

Treasury Stock, Value

(5.1)

(5.6)

(38.4)

(49.8)

3,340.0

2,959.9

39.0

743.0

699.3

4,122.0

3,698.2

Preferred Stock 3 Point 80 [Member] | Parent Company [Member]

4,432.7

4,061.8

Preferred Stock 4 Point 50 [Member] | Parent Company [Member]

10.0

Preferred Stock 4 Point 20 [Member] | Parent Company [Member]

10.0

Preferred Stock 4 Point 35 [Member] | Parent Company [Member]

7.0