Document And Entity Information (USD $)	12 Months Ended
Document And Entity Information (USD $)	Dec. 31, 2011	Feb. 21, 2012	Jun. 30, 2011
Entity Registrant Name	Great Plains Energy Inc
Entity Central Index Key	0001143068
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,819,307,073
Entity Common Stock, Shares Outstanding		136,161,064
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011

Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010
Operating Revenues
Electric revenues	$ 2,318.0	$ 2,255.5	$ 1,965.0
Operating Expenses
Fuel	483.8	430.7	405.5
Purchased power	203.4	213.8	183.7
Transmission of electricity by others	30.2	27.4	26.9
Utility operating and maintenance expenses	658.2	602.5	572.4
Voluntary separation program	12.7
Depreciation and amortization	273.1	331.6	302.2
General taxes	170.9	155.1	139.8
Other	5.9	22.1	14.4
Total	1,838.2	1,783.2	1,644.9
Operating income	479.8	472.3	320.1
Non-operating income	5.9	43.9	49.5
Non-operating expenses	(8.2)	(19.5)	(6.9)
Interest charges	(218.4)	(184.8)	(180.9)
Income from continuing operations before income tax	259.1	311.9	181.8
Income tax (expense) benefit	(84.8)	(99.0)	(29.5)
Loss from equity investments, net of income taxes	(0.1)	(1.0)	(0.4)
Income from continuing operations	174.2	211.9	151.9
Income (loss) from discontinued operations, net of income taxes (Note 22)	0	0	(1.5)
Net income	174.2	211.9	150.4
Less: Net income attributable to noncontrolling interest	0.2	(0.2)	(0.3)
Net income (loss) attributable to Great Plains Energy	174.4	211.7	150.1
Preferred stock dividend requirements	1.6	1.6	1.6
Earnings available for common shareholders	172.8	210.1	148.5
Average number of basic common shares outstanding	135.6	135.1	129.3
Average number of diluted common shares outstanding	138.7	136.9	129.8
Basic earnings (loss) per common share
Continuing operations	$ 1.27	$ 1.55	$ 1.16
Discontinued operations	$ 0.00	$ 0.00	$ (0.01)
Basic earnings per common share	$ 1.27	$ 1.55	$ 1.15
Diluted earnings (loss) per common share
Continuing operations	$ 1.25	$ 1.53	$ 1.15
Discontinued operations	$ 0.00	$ 0.00	$ (0.01)
Diluted earnings per common share	$ 1.25	$ 1.53	$ 1.14
Cash dividends per common share	$ 0.835	$ 0.83	$ 0.83
Kansas City Power and Light Company [Member]
Operating Revenues
Electric revenues	1,558.3	1,517.1	1,318.2
Operating Expenses
Fuel	333.5	278.8	251.3
Purchased power	70.8	78.9	70.8
Transmission of electricity by others	18.8	15.0	12.3
Utility operating and maintenance expenses	470.9	434.3	403.3
Voluntary separation program	9.2
Depreciation and amortization	193.1	256.4	229.6
General taxes	139.7	129.3	118.7
Other	1.1	13.0	0
Total	1,237.1	1,205.7	1,086.0
Operating income	321.2	311.4	232.2
Non-operating income	2.9	24.7	33.2
Non-operating expenses	(3.9)	(5.6)	(4.7)
Interest charges	(115.6)	(85.7)	(84.9)
Income from continuing operations before income tax	204.6	244.8	175.8
Income tax (expense) benefit	(69.1)	(81.6)	(46.9)
Net income	$ 135.5	$ 163.2	$ 128.9

Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 6.2	$ 10.8
Funds on deposit	1.4	5.2
Receivables, net	231.2	241.7
Accounts receivable pledged as collateral	95.0	95.0
Fuel inventories, at average cost	89.0	85.1
Materials and supplies, at average cost	140.3	132.8
Deferred refueling outage costs	27.5	9.6
Refundable income taxes	0.3	2.1
Deferred income taxes	7.5	14.3
Derivative instruments	1.0	1.1
Prepaid expenses and other assets	19.7	13.9
Total	619.1	611.6
Utility Plant, at Original Cost
Electric	10,924.8	10,536.9
Less-accumulated depreciation	4,235.8	4,031.3
Net utility plant in service	6,689.0	6,505.6
Construction work in progress	287.9	307.5
Nuclear fuel, net of amortization of $132.7 and $131.1	76.6	79.2
Total	7,053.5	6,892.3
Investments and Other Assets
Nuclear decommissioning trust fund	135.3	129.2
Regulatory Assets	1,058.2	924.0
Goodwill	169.0	169.0
Derivative instruments	6.8	7.8
Other	76.1	84.3
Total	1,445.4	1,314.3
Total	9,118.0	8,818.2
Current Liabilities
Notes payable	22.0	9.5
Collateralized note payable	95.0	95.0
Commercial paper	267.0	263.5
Current maturities of long-term debt	801.4	485.7
Accounts payable	275.6	276.3
Accrued taxes	25.8	26.6
Accrued interest	76.9	75.4
Accrued compensation and benefits	40.8	46.8
Pension and post-retirement liability	4.4	4.1
Derivative instruments	0	20.8
Other	26.0	35.6
Total	1,634.9	1,339.3
Deferred Credits and Other Liabilities
Deferred income taxes	628.6	518.3
Deferred tax credits	131.2	133.4
Asset retirement obligations	149.6	143.3
Pension and post-retirement liability	461.9	427.5
Regulatory Liabilities	268.5	258.2
Other	101.1	129.4
Total	1,740.9	1,610.1
Common shareholders' equity
Common stock - Great Plains - 250,000,000 shares authorized without par value 136,406,306 and 136,113,954 shares issued, stated value; Kansas City Power and Light Company - 1,000 shares authorized without par value, 1 share issued, stated value	2,330.6	2,324.4
Retained earnings	684.7	626.5
Treasury stock-264,567 and 400,889 shares, at cost	(5.6)	(8.9)
Accumulated other comprehensive loss	(49.8)	(56.1)
Total	2,959.9	2,885.9
Noncontrolling interest	1.0	1.2
Cumulative preferred stock $100 par value
3.8% - 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 (Note 11)	2,742.3	2,942.7
Total	5,742.2	5,868.8
Commitments and Contingencies (Note 14)
Total	9,118.0	8,818.2
Kansas City Power and Light Company [Member]
Current Assets
Cash and cash equivalents	1.9	3.6
Funds on deposit	0.1	0.4
Receivables, net	172.9	169.4
Accounts receivable pledged as collateral	95.0	95.0
Fuel inventories, at average cost	59.0	44.9
Materials and supplies, at average cost	101.1	94.4
Deferred refueling outage costs	27.5	9.6
Refundable income taxes	5.7	9.0
Deferred income taxes	0	5.6
Prepaid expenses and other assets	16.0	10.0
Total	479.2	441.9
Utility Plant, at Original Cost
Electric	7,829.3	7,540.9
Less-accumulated depreciation	3,243.0	3,104.4
Net utility plant in service	4,586.3	4,436.5
Construction work in progress	203.5	227.6
Nuclear fuel, net of amortization of $132.7 and $131.1	76.6	79.2
Total	4,866.4	4,743.3
Investments and Other Assets
Nuclear decommissioning trust fund	135.3	129.2
Regulatory Assets	780.7	679.6
Other	30.6	32.3
Total	946.6	841.1
Total	6,292.2	6,026.3
Current Liabilities
Notes payable	0	0
Collateralized note payable	95.0	95.0
Commercial paper	227.0	263.5
Current maturities of long-term debt	12.7	150.3
Accounts payable	214.8	201.7
Accrued taxes	20.6	21.3
Accrued interest	30.0	26.2
Accrued compensation and benefits	40.8	46.8
Pension and post-retirement liability	3.0	2.6
Other	13.7	7.8
Total	657.6	815.2
Deferred Credits and Other Liabilities
Deferred income taxes	772.7	692.0
Deferred tax credits	127.9	129.4
Asset retirement obligations	134.3	129.7
Pension and post-retirement liability	440.9	407.3
Regulatory Liabilities	142.8	141.3
Other	68.6	76.7
Total	1,687.2	1,576.4
Common shareholders' equity
Common stock - Great Plains - 250,000,000 shares authorized without par value 136,406,306 and 136,113,954 shares issued, stated value; Kansas City Power and Light Company - 1,000 shares authorized without par value, 1 share issued, stated value	1,563.1	1,563.1
Retained earnings	513.8	478.3
Accumulated other comprehensive loss	(31.4)	(36.4)
Total	2,045.5	2,005.0
Cumulative preferred stock $100 par value
Long-term debt (Note 11)	1,901.9	1,629.7
Total	3,947.4	3,634.7
Total	$ 6,292.2	$ 6,026.3

Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Utility Plant, at Original Cost
Nuclear fuel, amortization	$ 132.7	$ 131.1
Common shareholder's equity
Common stock - shares authorized (in shares)	250,000,000	250,000,000
Common stock-shares issued (in shares)	136,406,306	136,113,954
Treasury stock- shares (in shares)	264,567	400,889
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100.00	$ 100.00
Preferred Stock 3 Point 80 [Member]
Cumulative preferred stock
Cumulative preferred stock, Shares issued (in share)	100,000	100,000
Cumulative preferred stock, Dividend rate (in hundredths)	3.80%	3.80%
Preferred Stock 4 Point 50 [Member]
Cumulative preferred stock
Cumulative preferred stock, Shares issued (in share)	100,000	100,000
Cumulative preferred stock, Dividend rate (in hundredths)	4.50%	4.50%
Preferred Stock 4 Point 20 [Member]
Cumulative preferred stock
Cumulative preferred stock, Shares issued (in share)	70,000	70,000
Cumulative preferred stock, Dividend rate (in hundredths)	4.20%	4.20%
Preferred Stock 4 Point 35 [Member]
Cumulative preferred stock
Cumulative preferred stock, Shares issued (in share)	120,000	120,000
Cumulative preferred stock, Dividend rate (in hundredths)	4.35%	4.35%
Subsidiaries [Member]
Utility Plant, at Original Cost
Nuclear fuel, amortization	$ 132.7	$ 131.1
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 Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010
Cash Flows from Operating Activities
Net income	$ 174.2	$ 211.9	$ 150.4
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	273.1	331.6	302.2
Amortization of:
Nuclear fuel	21.4	25.1	16.1
Other	12.7	(4.7)	(10.1)
Deferred income taxes, net	111.2	123.8	(3.6)
Investment tax credit amortization	(2.2)	(2.9)	(2.2)
Loss from equity investments, net of income taxes	0.1	1.0	0.4
Other operating activities (Note 2)	(147.5)	(133.7)	(117.8)
Net cash from operating activities	443.0	552.1	335.4
Cash Flows from Investing Activities
Utility capital expenditures	(456.6)	(618.0)	(841.1)
Allowance for borrowed funds used during construction	(5.8)	(28.5)	(37.7)
Payment to Black Hills for asset sale working capital adjustment	0	0	(7.7)
Purchases of nuclear decommissioning trust investments	(18.5)	(83.3)	(99.0)
Proceeds from nuclear decommissioning trust investments	15.1	79.6	95.3
Other investing activities	(19.9)	(7.5)	(7.4)
Net cash from investing activities	(485.7)	(657.7)	(897.6)
Cash Flows from Financing Activities
Issuance of common stock	5.9	6.2	219.9
Issuance of long-term debt	747.1	249.9	700.7
Issuance fees	(10.7)	(12.1)	(22.8)
Repayment of long-term debt	(598.5)	(1.3)	(70.7)
Net change in short-term borrowings	16.0	(165.6)	(145.6)
Net change in collateralized short-term borrowings	0	95.0	0
Dividends paid	(115.1)	(114.2)	(110.5)
Other financing activities	(6.6)	(7.4)	(4.0)
Net cash from financing activities	38.1	50.5	567.0
Net Change in Cash and Cash Equivalents	(4.6)	(55.1)	4.8
Cash and Cash Equivalents at Beginning of Year		65.9
Cash and Cash Equivalents at End of Year	6.2	10.8
Kansas City Power and Light Company [Member]
Cash Flows from Operating Activities
Net income	135.5	163.2	128.9
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	193.1	256.4	229.6
Amortization of:
Nuclear fuel	21.4	25.1	16.1
Other	29.5	24.2	19.0
Deferred income taxes, net	80.6	83.2	(38.2)
Investment tax credit amortization	(1.5)	(2.1)	(1.4)
Other operating activities (Note 2)	(118.3)	(127.8)	(66.1)
Net cash from operating activities	340.3	422.2	287.9
Cash Flows from Investing Activities
Utility capital expenditures	(336.5)	(463.1)	(626.5)
Allowance for borrowed funds used during construction	(2.9)	(22.4)	(31.1)
Purchases of nuclear decommissioning trust investments	(18.5)	(83.3)	(99.0)
Proceeds from nuclear decommissioning trust investments	15.1	79.6	95.3
Net money pool lending	(12.1)	6.1	6.0
Other investing activities	(9.7)	(13.4)	(0.6)
Net cash from investing activities	(340.4)	(508.7)	(667.9)
Cash Flows from Financing Activities
Issuance of long-term debt	397.4	0	413.2
Issuance fees	(6.1)	(5.1)	(4.0)
Repayment of long-term debt	(263.1)	(0.2)	0
Net change in short-term borrowings	(36.5)	76.9	(193.6)
Net change in collateralized short-term borrowings	0	95.0	0
Dividends paid	(100.0)	(95.0)	(72.0)
Net money pool borrowings	6.7	1.1	0.9
Equity contribution from Great Plains Energy			247.5
Net cash from financing activities	(1.6)	72.7	392.0
Net Change in Cash and Cash Equivalents	(1.7)	(13.8)	12.0
Cash and Cash Equivalents at Beginning of Year		17.4
Cash and Cash Equivalents at End of Year	$ 1.9	$ 3.6

Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest (USD $) In Millions, except Share data, unless otherwise specified	Total	Kansas City Power and Light Company [Member]	Common Stock [Member]	Common Stock [Member] Kansas City Power and Light Company [Member]	Retained Earnings [Member]	Retained Earnings [Member] Kansas City Power and Light Company [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Other Comprehensive Income (Loss) [Member] Kansas City Power and Light Company [Member]	Noncontrolling Interest [Member]
Beginning balance at Dec. 31, 2009			$ 2,313.7	$ 1,563.1	$ 529.2	$ 410.1	$ (5.5)	$ (44.9)	$ (41.5)	$ 1.2
Beginning balance (in shares) at Dec. 31, 2009			135,636,538	1			(213,423)
Distribution										(0.2)
Total Great Plains Energy Common Shareholders' Equity	2,885.9	2,005.0
Derivative hedging activity, net of tax	(10.6)	5.1						(10.6)	5.1
Change in unrecognized pension expense, net of tax	(0.6)							(0.6)
Net income (loss) attributable to Great Plains Energy	211.7				211.7	163.2
Treasury shares acquired							(3.4)
Treasury shares acquired (in shares)							(188,383)
Treasury shares reissued							0
Treasury shares reissued (in shares)							917
Issuance of common stock			6.6
Issuance of common stock (in shares)			347,279
Common stock issuance fees			0
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
Equity Units allocated fees and expenses and the present value of contract adjustment payments			0
Other			0.1
Equity contribution from Great Plains Energy				0
Dividends:
Common stock					(112.6)	(95.0)
Preferred stock - at required rates					(1.6)
Performance shares					(0.2)
Performance shares amendment					0
Net income attributable to noncontrolling interest										0.2
Ending balance at Dec. 31, 2010			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)
Beginning balance at Jan. 01, 2011
Distribution										0
Total Great Plains Energy Common Shareholders' Equity	2,959.9	2,045.5
Derivative hedging activity, net of tax	6.8	5.0						6.8	5.0
Change in unrecognized pension expense, net of tax	(0.5)							(0.5)
Net income (loss) attributable to Great Plains Energy	174.4				174.4	135.5
Loss On Reissuance Of Treasury Stock					(0.7)
Treasury shares acquired							(2.4)
Treasury shares acquired (in shares)							(125,234)
Treasury shares reissued							5.7
Treasury shares reissued (in shares)							261,556
Issuance of common stock			5.9
Issuance of common stock (in shares)			292,352
Common stock issuance fees			0
Issuance of restricted common stock			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
Equity Units allocated fees and expenses and the present value of contract adjustment payments			0
Other			0.3
Equity contribution from Great Plains Energy				0
Dividends:
Common stock					(113.5)	(100.0)
Preferred stock - at required rates					(1.6)
Performance shares					(0.4)
Performance shares amendment					0
Net income attributable to noncontrolling interest										(0.2)
Ending balance at Dec. 31, 2011			$ 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)

Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010
Net income	$ 174.2	$ 211.9	$ 150.4
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	(5.9)	(28.0)	(0.4)
Income tax benefit (expense)	2.3	10.8	0.1
Net gain (loss) on derivative hedging instruments	(3.6)	(17.2)	(0.3)
Reclassification to expenses, net of tax (Note 18)	10.4	6.6	5.6
Derivative hedging activity, net of tax	6.8	(10.6)	5.3
Defined benefit pension plans
Net gain (loss) arising during period	(1.2)	(1.3)	5.0
Amortization of net gains included in net periodic benefit costs	0.4	0.3	0.4
Income tax benefit (expense)	0.3	0.4	(2.1)
Net change in unrecognized pension expense	(0.5)	(0.6)	3.3
Comprehensive income	180.5	200.7	159.0
Less: comprehensive income attributable to noncontrolling interest	0.2	(0.2)	(0.3)
Comprehensive income attributable to Great Plains Energy	180.7	200.5	158.7
Kansas City Power and Light Company [Member]
Net income	135.5	163.2	128.9
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	(0.6)	(0.9)	0.2
Income tax benefit (expense)	0.2	0.3	(0.1)
Net gain (loss) on derivative hedging instruments	(0.4)	(0.6)	0.1
Reclassification to expenses, net of tax (Note 18)	5.4	5.7	5.3
Derivative hedging activity, net of tax	5.0	5.1	5.4
Defined benefit pension plans
Comprehensive income	$ 140.5	$ 168.3	$ 134.3

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

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

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

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

Each of Great Plains Energy’s and KCP&L’s consolidated financial statements includes the accounts of their subsidiaries. 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. Fair value is 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, which are based on quoted market prices of the investments held by the trusts and/or valuation models. The rabbi trusts are included in Other – Investments and Other Assets on Great Plains Energy’s consolidated balance sheets.

Long-term debt – Fair value is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices were not available. At 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, 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. At December 31, 2010, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.4 billion and $3.7 billion, respectively. At December 31, 2010, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.8 billion and $1.9 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. KCP&L uses a five-year smoothing of assets to determine fair value for regulatory reporting purposes.

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 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 2011, 6.8% in 2010 and 7.6% in 2009 for KCP&L and for GMO averaged 5.4% in 2011, 4.6% in 2010 and 5.4% in 2009.

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	2011		2010
Utility Plant, at original cost	(millions)
Generation (20 - 60 years)	$	6,594.0	$	6,369.4
Transmission (15 - 70 years)		734.8		716.9
Distribution (8 - 66 years)		2,921.1		2,813.4
General (5 - 50 years)		674.9		637.2
Total (a)	$	10,924.8	$	10,536.9
(a) Includes $105.5 million and $103.0 million at December 31,
2011 and 2010, respectively, of land and other assets that
are not depreciated.

KCP&L
December 31	2011		2010
Utility Plant, at original cost	(millions)
Generation (20 - 60 years)	$	5,078.1	$	4,886.2
Transmission (15 - 70 years)		412.9		408.7
Distribution (8 - 55 years)		1,840.2		1,776.4
General (5 - 50 years)		498.1		469.6
Total (a)	$	7,829.3	$	7,540.9
(a) Includes $59.8 million and $59.9 million at December 31,
2011 and 2010, 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 $239.9 million, $243.6 million and $228.9 million for 2011, 2010 and 2009, respectively. KCP&L’s depreciation expense was $162.0 million, $170.9 million and $158.4 million for 2011, 2010 and 2009, respectively. Great Plains Energy’s and KCP&L’s depreciation and amortization expense includes $14.4 million, $72.6 million and $58.2 million for 2011, 2010 and 2009, 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). This additional amortization concluded following the December 2010 and May 2011 effective dates of new retail rates for KCP&L in Kansas and Missouri, respectively.

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 of 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 $55.6 million, $54.3 million, and $46.8 million in 2011, 2010 and 2009, respectively. These taxes from KCP&L’s Kansas customers and GMO’s customers are recorded net in operating revenues on Great Plains Energy’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 income from continuing operations and net income before dividing by the average number of common shares outstanding. The loss per share impact of discontinued operations is determined by dividing loss from discontinued operations, net of income taxes, 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 from continuing operations.


	2011			2010		2009
Income	(millions, except per share amounts)
Income from continuing operations	$	174.2		$	211.9	$	151.9
Less: net income (loss) attributable to noncontrolling interest		(0.2	)		0.2		0.3
Less: preferred stock dividend requirements		1.6			1.6		1.6
Income from continuing operations available for common shareholders	$	172.8		$	210.1	$	150.0
Common Shares Outstanding
Average number of common shares outstanding		135.6			135.1		129.3
Add: effect of dilutive securities		3.1			1.8		0.5
Diluted average number of common shares outstanding		138.7			136.9		129.8
Basic EPS from continuing operations	$	1.27		$	1.55	$	1.16
Diluted EPS from continuing operations	$	1.25		$	1.53	$	1.15

The computation of diluted EPS for 2011 excludes anti-dilutive shares consisting of 50,897 performance shares, 43,641 restricted stock shares and 6,000 stock options.

The computation of diluted EPS for 2010 excludes anti-dilutive shares consisting of 340,690 performance shares, 251,526 restricted stock shares and 196,137 stock options.

The computation of diluted EPS for 2009 excludes anti-dilutive shares consisting of 150,895 performance shares, 438,281 restricted stock shares and 231,670 stock options.

Dividends Declared

In February 2012, Great Plains Energy’s Board of Directors (Board) declared a quarterly dividend of $0.2125 per share on Great Plains Energy’s common stock. The common dividend is payable March 20, 2012, to shareholders of record as of February 28, 2012. The Board also declared regular dividends on Great Plains Energy’s preferred stock, payable March 20, 2012, to shareholders of record as of June 1, 2011.

In February 2012, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $25 million payable on March 19, 2012.

- Definition

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

+ References+ Details

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

2.	SUPPLEMENTAL CASH FLOW INFORMATION

Great Plains Energy Other Operating Activities
Year Ended December 31	2011			2010			2009
Cash flows affected by changes in:	(millions)
Receivables	$	3.6		$	(12.6	)	$	7.9
Accounts receivable pledged as collateral		-			(95.0	)		-
Fuel inventories		(3.9	)		(0.1	)		2.0
Materials and supplies		(7.5	)		(11.5	)		(22.0	)
Accounts payable		5.7			12.8			(70.9	)
Accrued taxes		1.4			6.7			42.2
Accrued interest		1.5			2.9			2.9
Deferred refueling outage costs		(17.9	)		9.9			(7.1	)
Fuel adjustment clauses		(1.7	)		2.7			7.8
Pension and post-retirement benefit obligations		(56.0	)		(10.2	)		18.4
Allowance for equity funds used during construction		(1.0	)		(26.0	)		(39.6	)
Write down of affordable housing investments		-			11.2			-
Interest rate hedge settlements		(26.1	)		(6.9	)		(79.1	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		2.3			16.8			-
Uncertain tax positions		(20.8	)		(6.1	)		10.7
Other		(27.1	)		(28.3	)		9.0
Total other operating activities	$	(147.5	)	$	(133.7	)	$	(117.8	)
Cash paid during the period:
Interest	$	254.4		$	237.7		$	211.9
Income taxes	$	2.8		$	0.9		$	5.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	39.7		$	44.9		$	82.8

KCP&L Other Operating Activities
Year Ended December 31	2011			2010			2009
Cash flows affected by changes in:	(millions)
Receivables	$	(20.2	)	$	(4.1	)	$	(7.6	)
Accounts receivable pledged as collateral		-			(95.0	)		-
Fuel inventories		(14.1	)		0.7			6.1
Materials and supplies		(6.7	)		(9.6	)		(16.5	)
Accounts payable		11.0			0.8			(54.3	)
Accrued taxes		2.7			(15.7	)		51.8
Accrued interest		3.8			(0.5	)		8.6
Deferred refueling outage costs		(17.9	)		9.9			(7.1	)
Pension and post-retirement benefit obligations		(45.6	)		7.9			39.3
Allowance for equity funds used during construction		(0.7	)		(21.9	)		(30.6	)
Kansas Energy Cost Adjustment		(5.8	)		(8.8	)		2.2
Iatan Nos. 1 and 2 impact of disallowed construction costs		1.5			13.0			-
Interest rate hedge settlements		-			-			(79.1	)
Uncertain tax positions		(10.4	)		(1.8	)		3.3
Other		(15.9	)		(2.7	)		17.8
Total other operating activities	$	(118.3	)	$	(127.8	)	$	(66.1	)
Cash paid during the period:
Interest	$	111.3		$	101.1		$	77.2
Income taxes	$	0.1		$	18.2		$	31.9
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	32.0		$	37.4		$	75.5

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.

- Definition

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

+ References+ Details

Receivables

12 Months Ended

Dec. 31, 2011

Receivables [Abstract]

Receivables

3.	RECEIVABLES

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


	December 31
	2011			2010
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	69.8		$	62.0
Customer accounts receivable - unbilled		82.4			82.3
Allowance for doubtful accounts		(2.5	)		(2.7	)
Other receivables		81.5			100.1
Total	$	231.2		$	241.7
KCP&L
Customer accounts receivable - billed	$	16.4		$	6.5
Customer accounts receivable - unbilled		50.0			50.1
Allowance for doubtful accounts		(1.4	)		(1.5	)
Intercompany receivables		38.7			43.2
Other receivables		69.2			71.1
Total	$	172.9		$	169.4

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

Sale of Accounts Receivable – KCP&L

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

KCP&L sells its receivables at a fixed price based upon the expected cost of funds and charge-offs. These costs comprise KCP&L’s loss on the sale of accounts receivable. KCP&L services the receivables and receives an annual servicing fee of 1.5% of the outstanding principal amount of the receivables sold to Receivables Company. KCP&L does not recognize a servicing asset or liability because management determined the collection agent fee earned by KCP&L approximates market value. The agreement expires in September 2014 and allows for $110 million in aggregate outstanding principal amount at any time.

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


				Receivables			Consolidated
2011	KCP&L			Company			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		2.6			(2.6	)		-
Fees to outside investor		-			(1.2	)		(1.2	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(1,412.4	)		1,412.4			-
Cash paid to KCP&L for receivables purchased		1,394.7			(1,394.7	)		-
Servicing fees		2.6			(2.6	)		-
Interest on intercompany note		0.5			(0.5	)		-


				Receivables			Consolidated
2010	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,341.0	)	$	1,341.0		$	-
Gain (loss) on sale of accounts receivable (a)		(17.0	)		16.8			(0.2	)
Servicing fees		3.2			(3.2	)		-
Fees to outside investor		-			(1.2	)		(1.2	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(1,337.4	)		1,337.4			-
Cash paid to KCP&L for receivables purchased		1,320.7			(1,320.7	)		-
Servicing fees		3.2			(3.2	)		-
Interest on intercompany note		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, 2011

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. Wolf Creek is operating in the category of nuclear plants receiving the lowest level of NRC oversight.

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 Nuclear Regulatory Commission (NRC) to withdraw its then pending application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application, and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of September 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. Oral argument to the court is expected later in 2012. 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 store in another state most of the remainder of Wolf Creek’s low-level radioactive waste (Classes B and C waste, which is higher in radioactivity but much lower in volume). Should on-site waste storage be needed in the future, Wolf Creek has current storage capacity on site for about four years’ generation of Classes B and C waste and believes it will be able to expand that storage capacity as needed if it becomes necessary to do so.

Nuclear 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		KCP&L's
		Station		47% Share
		(millions)
Current cost of decommissioning (in 2011 dollars)		$	630	$	296
Future cost of decommissioning (in 2045-2053 dollars) (a)			2,455		1,154

Annual escalation factor		3.73%
Annual return on trust assets (b)		6.89%
(a)	Total future cost over an eight year decommissioning period.
(b)	The 6.89% rate of return is through 2025. The rate then systematically decreases
	through 2053 to 1.81% based on the assumption that the fund's investment mix
	will become increasingly more conservative as the decommissioning period
	approaches.

Nuclear Decommissioning Trust Fund

In 2011 and 2010, KCP&L contributed approximately $3.4 million and $3.7 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.


December 31	2011			2010
Decommissioning Trust	(millions)
Beginning balance January 1	$	129.2		$	112.5
Contributions		3.4			3.7
Earned income, net of fees		4.8			2.0
Net realized gains		0.3			6.7
Net unrealized gains (losses)		(2.4	)		4.3
Ending balance	$	135.3		$	129.2

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


	December 31
	2011									2010
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	76.5	$	12.3	$	(4.5	)	$	84.3	$	73.4	$	13.1	$	(1.0	)	$	85.5
Debt securities		44.2		4.5		(0.1	)		48.6		38.1		2.6		(0.1	)		40.6
Other		2.4		-		-			2.4		3.1		-		-			3.1
Total	$	123.1	$	16.8	$	(4.6	)	$	135.3	$	114.6	$	15.7	$	(1.1	)	$	129.2

The weighted average maturity of debt securities held by the trust at December 31, 2011, 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.


	2011			2010			2009
	(millions)
Realized gains	$	1.0		$	7.3		$	2.8
Realized losses		(0.7	)		(0.6	)		(8.3	)

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 $30.9 million ($14.5 million, KCP&L’s 47% share) per policy year.

Regulatory Matters

12 Months Ended

Dec. 31, 2011

Regulatory Matters [Abstract]

Regulatory Matters

5.	REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

In November 2010, KCC issued an order, effective December 1, 2010, for KCP&L, authorizing an increase in annual revenues of $21.8 million, a return on equity of 10.0%, an equity ratio of approximately 49.7% and a Kansas jurisdictional rate base of $1.781 billion. The annual revenue increase was subsequently adjusted by KCC in a January 2011 reconsideration order to $22.0 million. In February 2011, KCC issued an order granting KCP&L and another party to the case their respective petitions for reconsideration regarding rate case expenses. In January 2012, KCC issued its order allowing approximately $0.2 million of additional rate case expenses to be included in rates and amortized over three years. The rates authorized by KCC are effective unless and until modified by KCC or stayed by a court.

KCP&L Missouri Rate Case Proceedings

On February 27, 2012, KCP&L filed an application with the MPSC to request an increase of its retail rates of $105.7 million, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%. The request includes recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service and also includes a lower annual offset to the revenue requirement for the Missouri jurisdictional portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset). KCP&L currently expects that it will not be able to achieve the $45.9 million wholesale margin offset currently reflected in its retail rates due to a decline in wholesale power prices, which is being driven by low natural gas prices.

On April 12, 2011, the MPSC issued an order and on April 14, 2011, the MPSC Staff filed a report which quantified an authorized revenue increase of approximately $34.8 million on an annual basis, which reflects a wholesale margin offset of approximately $45.9 million and authorizes a return on equity of 10.0%, an equity ratio of approximately 46.3% and a Missouri jurisdictional rate base of approximately $2.0 billion effective May 4, 2011. If the actual Missouri jurisdiction wholesale margin amount exceeds the $45.9 million level reflected in the MPSC order, the difference will be recorded as a regulatory liability and will be returned, with interest, to KCP&L Missouri customers in a future rate case. The MPSC order provides the opportunity for KCP&L to retain a larger amount of non-firm wholesale electric sales margin than KCP&L proposed; however, there are no assurances that KCP&L will achieve the $45.9 million wholesale margin offset amount and there are no means for KCP&L to recover any shortfall through its retail rates unless the MPSC authorizes future recovery.

As a result of disallowances in the April 2011 MPSC order, KCP&L recognized losses of $1.5 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project during 2011. KCP&L also recorded a $2.4 million loss for other disallowed costs in the MPSC order.

In a related order, the MPSC required KCP&L and GMO to apply to the Internal Revenue Service (IRS) to reallocate approximately $26.5 million of Iatan No. 2 qualifying advance coal project tax credits from KCP&L to GMO. KCP&L and GMO did apply to the IRS but in September 2011, the IRS denied KCP&L’s and GMO’s request. The MPSC has indicated it will consider the ratemaking treatment of the tax credits in a future rate case. Certain ratemaking treatments that may be pursued by the MPSC could trigger the loss or repayment to the IRS of a portion of unamortized deferred investment tax credits. At December 31, 2011, KCP&L and GMO had $127.9 million and $3.3 million, respectively, of unamortized deferred investment tax credits.

GMO Missouri Rate Case Proceedings

On February 27, 2012, GMO filed an application with the MPSC to request an increase of its retail rates 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% and a rate-making equity ratio of 52.5%. The requests include recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service, costs related to energy efficiency and demand side management programs, and increased fuel costs.

In December 2011, GMO filed a request with the MPSC seeking to recover costs for new and enhanced energy efficiency and demand side management programs under the Missouri Energy Efficiency Investment Act (MEEIA). If approved, the costs would be recovered through a rider mechanism and GMO would reduce its request to increase retail rates that it filed with the MPSC on February 27, 2012. A decision on the MEEIA request is expected in the second quarter of 2012.

On May 4, 2011, the MPSC issued an order and on May 10, 2011, the MPSC Staff filed a report which quantified authorized revenue increases on an annual basis of $30.1 million for GMO’s Missouri Public Service division and $29.3 million for GMO’s St. Joseph Light & Power (L&P) division. The MPSC order authorized a return on equity of 10.0%, an equity ratio of approximately 46.6% and a Missouri jurisdictional rate base of $1.76 billion. In response to applications for clarification and rehearing of the MPSC order, the MPSC on May 27, 2011, issued an order of clarification and modification. The modified MPSC order revised the authorized annual revenue increases to approximately $35.7 million for GMO’s Missouri Public Service division and approximately $29.8 million for GMO’s L&P division, resulting primarily from a clarification of the amount of fuel costs shifted from GMO’s fuel adjustment clause to base rates. However, because the MPSC authorized an annual revenue increase that was greater than the amount originally requested by GMO for its L&P division and communicated to GMO’s L&P customers, the modified MPSC order deferred approximately $7.7 million of the L&P division increase, which is the amount over GMO’s requested $22.1 million increase for that division, and will phase in the deferred revenue amount in equal parts over a two-year period, plus carrying costs. In addition, GMO shall be allowed to recover the revenue which would have been allowed in the absence of a phase in.

As a result of disallowances in the May 2011 MPSC order, GMO recognized losses of $0.8 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project during 2011. GMO also recorded a $1.5 million loss for other disallowed costs in the MPSC order.

Additionally, with respect to GMO’s Missouri Public Service division, the MPSC concluded that GMO’s decision to add Crossroads Energy Center (Crossroads) to its generation asset resources was prudent and reasonable; however, the order disallowed from rate base approximately $50 million for Crossroads, disallowed $4.9 million in associated annual transmission expense and offset rate base by approximately $15 million to reflect accumulated deferred taxes associated with Crossroads. GMO’s request included a net plant amount of approximately $104 million for Crossroads. In assessing the impact of the Crossroads disallowances, management considered that KCP&L’s and GMO’s generation asset resources include a diverse fuel mix consisting primarily of coal and nuclear fuel providing base load generation with natural gas facilities such as Crossroads to provide critical peaking and capacity support. This combined collection of generating assets meets KCP&L’s and GMO’s service obligations and produces joint cash flows based on system-wide average costs. Great Plains Energy conducted an analysis to assess the recoverability of the combined collection of generation asset resources and determined that no potential impairment exists.

The rates established by the modified MPSC order took effect on June 25, 2011. On June 24, 2011, GMO filed its appeal of the MPSC order with the Cole County, Missouri, Circuit Court regarding the Crossroads issues discussed above. Other parties to the case have also filed appeals of the MPSC order. However, the rates authorized by the modified MPSC order will be effective unless and until modified by the MPSC or stayed by a court.

GMO Fuel Adjustment Clause (FAC) Prudence Review

GMO’s electric retail rates contain an FAC tariff under which 95% of the difference between actual fuel cost, purchased power costs and off-system sales margin and the amount provided in base rates for these costs is passed along to GMO’s customers. The MPSC requires prudence reviews of the FAC no less frequently than at 18-month intervals. On November 28, 2011, the MPSC staff filed its prudence review report for the 18-month prudence review period covering June 1, 2009 through November 30, 2010. The MPSC staff recommended to the MPSC to order GMO to refund approximately $19 million, plus interest, to customers through an adjustment to its FAC because the MPSC staff asserts that GMO was imprudent in its use of natural gas hedges to mitigate risk associated with its future purchases in the spot power market. GMO is disputing the MPSC staff’s claim of imprudence and filed its testimony on February 22, 2012. A hearing is scheduled for May 16 – 17, 2012, with an order expected in June 2012.

SPP and NERC Inquiries

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

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 tables.


							Great
December 31, 2011	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	119.6		$	24.6		$	144.2
Loss on reacquired debt		9.1	(a)		2.7	(a)		11.8
Cost of removal		4.6			-			4.6
Asset retirement obligations		31.4			13.8			45.2
Pension and post-retirement costs		466.4	(b)		122.0	(b)		588.4
Deferred customer programs		48.2	(c)		20.6			68.8
Rate case expenses		9.6	(d)		3.8	(d)		13.4
Skill set realignment costs		3.4	(e)		-			3.4
Fuel adjustment clauses		14.0	(d)		36.4	(d)		50.4
Acquisition transition costs		24.7	(f )		20.2	(f )		44.9
Derivative instruments		-			7.6	(g)		7.6
Iatan No. 1 and Common facilities depreciation and carrying costs		16.4			6.1			22.5
Iatan No. 2 construction accounting costs		27.9			15.4			43.3
Kansas property tax surcharge		3.7	(d)		-			3.7
Other		1.7	(h)		4.3	(h)		6.0
Total	$	780.7		$	277.5		$	1,058.2
Regulatory Liabilities
Emission allowances	$	82.0		$	0.2		$	82.2
Asset retirement obligations		49.3			-			49.3
Pension		0.7			40.8			41.5
Cost of removal		-			61.9	(i)		61.9
Other		10.8			22.8			33.6
Total	$	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 not included in rate base that will be eliminated over the life of the pension plans.

(c)	$10.4 million not included in rate base and amortized over various periods.

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

(e)	$2.4 million not included in rate base and amortized through 2017.

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

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

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

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


					Great
December 31, 2010	KCP&L		GMO		Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	117.2	$	25.3	$	142.5
Loss on reacquired debt		5.0		0.7		5.7
Cost of removal		8.5		-		8.5
Asset retirement obligations		27.5		12.8		40.3
Pension and post-retirement costs		386.1		106.7		492.8
Deferred customer programs		44.7		15.6		60.3
Rate case expenses		12.3		3.3		15.6
Skill set realignment costs		4.8		-		4.8
Fuel adjustment clauses		8.4		37.1		45.5
Acquisition transition costs		29.3		22.5		51.8
Derivative instruments		-		3.1		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		15.1		4.3		19.4
Iatan No. 2 construction accounting costs		17.2		6.5		23.7
Other		3.5		6.5		10.0
Total	$	679.6	$	244.4	$	924.0
Regulatory Liabilities
Emission allowances	$	85.9	$	0.5	$	86.4
Asset retirement obligations		44.9		-		44.9
Pension		-		37.1		37.1
Cost of removal		-		62.8		62.8
Other		10.5		16.5		27.0
Total	$	141.3	$	116.9	$	258.2

Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2011

Goodwill and Intangible Assets [Abstract]

Goodwill and Intangible Assets

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, 2011. The goodwill impairment test is a two step process. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill, to identify potential impairment. If the carrying amount exceeds the fair value of the reporting unit, the second step of the test is performed, consisting of assignment of the reporting unit’s fair value to its assets and liabilities to determine an implied fair value of goodwill, which is compared to the carrying amount of goodwill to determine the impairment loss, if any, to be recognized in the financial statements. Great Plains Energy’s regulated electric utility operations are considered one reporting unit for assessment of impairment, as they are included within the same operating segment and have similar economic characteristics. The determination of fair value of the reporting unit consisted of two valuation techniques: an income approach consisting of a discounted cash flow analysis and a market approach consisting of a determination of reporting unit invested capital using market multiples derived from the historical revenue, EBITDA and net utility asset values and market prices of stock of electric and gas company regulated peers. The results of the two techniques were evaluated and weighted to determine a point within the range that management considered representative of fair value for the reporting unit. Fair value of the reporting unit exceeded the carrying amount, including goodwill; therefore, there was no impairment of goodwill.

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, 2011					December 31, 2010
	Gross Carrying		Accumulated			Gross Carrying		Accumulated
	Amount		Amortization			Amount		Amortization
KCP&L	(millions)
Computer software	$	171.7	$	(129.9	)	$	168.2	$	(118.0	)
Asset improvements		11.7		(0.6	)		5.8		-

Great Plains Energy
Computer software	$	202.5	$	(143.5	)	$	201.1	$	(137.3	)
Asset improvements		27.0		(3.7	)		27.9		(4.4	)

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

The following table provides the estimated amortization expense related to Great Plains Energy’s and KCP&L’s intangible assets for 2012 through 2016 for the intangible assets included in the consolidated balance sheets at December 31, 2011.


	2012		2013		2014		2015		2016
	(millions)
Great Plains Energy	$	13.9	$	11.2	$	8.1	$	6.0	$	4.7
KCP&L		11.0		8.3		5.3		3.4		2.1

- Definition

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

+ References+ Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

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 and 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 for removal of storage tanks, an ash pond and landfill. GMO has AROs related to asbestos abatement, an ash pond and landfill and removal of storage tanks and communication towers.

GPE and KCP&L have identified an additional asbestos ARO. Certain wiring used in generating stations includes 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, a fair value of the obligation 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
	2011			2010		2011			2010
	(millions)
Beginning balance	$	143.3		$	132.6	$	129.7		$	119.8
Additions		0.8			2.0		-			2.0
Revision in timing and/or estimates		(3.8	)		-		(3.8	)		-
Accretion		9.3			8.7		8.4			7.9
Ending balance	$	149.6		$	143.3	$	134.3		$	129.7

- Definition

The entire disclosure for an asset retirement obligation and the associated long-lived asset. An asset retirement obligation is a legal obligation associated with the disposal or retirement from service of a tangible long-lived asset that results from the acquisition, construction or development, or the normal operations of a long-lived asset, except for certain obligations of lessees.

+ References+ Details

Pension Plans and Other Employee Benefits

12 Months Ended

Dec. 31, 2011

Pension Plans and Other Employee Benefits [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 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 expect to 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. KCP&L uses a five-year smoothing of assets to determine fair value for regulatory reporting purposes. 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
	2011			2010			2011			2010
Change in projected benefit obligation (PBO)	(millions)
PBO at beginning of year	$	911.4		$	836.3		$	143.6		$	148.9
Service cost		31.1			30.3			3.1			3.8
Interest cost		49.6			49.3			7.8			8.8
Contribution by participants		-			-			6.6			5.6
Amendments		-			0.5			-			-
Actuarial (gain) loss		83.2			55.1			7.4			(12.5	)
Benefits paid		(54.7	)		(60.1	)		(14.3	)		(11.0	)
Settlements		(40.0	)		-			-			-
PBO at end of plan year	$	980.6		$	911.4		$	154.2		$	143.6
Change in plan assets
Fair value of plan assets at beginning of year	$	557.6		$	488.2		$	65.8		$	52.0
Actual return on plan assets		(3.7	)		62.7			2.5			0.5
Contributions by employer and participants		128.8			64.5			23.0			23.9
Benefits paid		(91.6	)		(57.8	)		(13.9	)		(10.6	)
Fair value of plan assets at end of plan year	$	591.1		$	557.6		$	77.4		$	65.8
Funded status at end of year	$	(389.5	)	$	(353.8	)	$	(76.8	)	$	(77.8	)
Amounts recognized in the consolidated balance sheets
Current pension and other post-retirement liability	$	(3.5	)	$	(3.1	)	$	(0.9	)	$	(1.0	)
Noncurrent pension liability and other post-retirement liability		(386.0	)		(350.7	)		(75.9	)		(76.8	)
Net amount recognized before regulatory treatment		(389.5	)		(353.8	)		(76.8	)		(77.8	)
Accumulated OCI or regulatory asset/liability		491.8			403.2			52.5			54.8
Net amount recognized at December 31	$	102.3		$	49.4		$	(24.3	)	$	(23.0	)
Amounts in accumulated OCI or regulatory asset/liability
not yet recognized as a component of net periodic benefit cost:
Actuarial loss	$	295.6		$	219.5		$	15.7		$	8.5
Prior service cost		10.7			15.3			36.9			44.1
Transition obligation		-			-			1.7			3.0
Other		185.5			168.4			(1.8	)		(0.8	)
Net amount recognized at December 31	$	491.8		$	403.2		$	52.5		$	54.8


	Pension Benefits									Other Benefits
	2011			2010			2009			2011			2010			2009
Components of net periodic benefit costs	(millions)
Service cost	$	31.1		$	30.3		$	29.1		$	3.1		$	3.8		$	4.1
Interest cost		49.6			49.3			47.3			7.8			8.8			8.3
Expected return on plan assets		(38.0	)		(36.6	)		(32.4	)		(1.8	)		(2.1	)		(1.6	)
Prior service cost		4.6			4.6			4.2			7.2			7.2			6.9
Recognized net actuarial (gain) loss		38.7			37.4			36.3			(0.5	)		(0.1	)		(0.4	)
Transition obligation		-			0.1			0.1			1.3			1.3			1.3
Settlement charges		10.1			-			0.1			-			-			-
Net periodic benefit costs before
regulatory adjustment		96.1			85.1			84.7			17.1			18.9			18.6
Regulatory adjustment		(27.9	)		(32.3	)		(28.4	)		1.1			-			(0.3	)
Net periodic benefit costs		68.2			52.8			56.3			18.2			18.9			18.3
Other changes in plan assets and benefit
obligations recognized in OCI or
regulatory assets/liabilities
Current year net (gain) loss		114.8			29.1			(9.2	)		6.7			(10.9	)		(0.2	)
Amortization of gain (loss)		(38.7	)		(37.4	)		(36.3	)		0.5			0.1			0.4
Prior service cost		-			0.5			5.7			-			-			24.8
Amortization of prior service cost		(4.6	)		(4.6	)		(4.2	)		(7.2	)		(7.2	)		(6.9	)
Transition obligation		-			-			-			-			-			1.2
Amortization of transition obligation		-			(0.1	)		(0.1	)		(1.3	)		(1.3	)		(1.3	)
Other regulatory activity		17.1			29.5			10.1			(1.0	)		0.1			(3.1	)
Total recognized in OCI or regulatory asset/liability		88.6			17.0			(34.0	)		(2.3	)		(19.2	)		14.9
Total recognized in net periodic benefit costs
and OCI or regulatory asset/liability	$	156.8		$	69.8		$	22.3		$	15.9		$	(0.3	)	$	33.2

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 2012 are $4.5 million and $44.5 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 2012 are $7.2 million, $(0.1) million and $1.0 million, respectively.

The accumulated benefit obligation (ABO) for all defined benefit pension plans was $852.6 million and $808.8 million at December 31, 2011 and 2010, respectively. The PBO, ABO and fair value of plan assets at plan year-end are aggregated by funded and underfunded plans in the following table.


	2011		2010
Pension plans with the ABO in excess of plan assets	(millions)
Projected benefit obligation	$	980.6	$	911.4
Accumulated benefit obligation		852.6		808.8
Fair value of plan assets		591.1		557.6
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 $20.6 million. Great Plains Energy has segregated approximately $20.1 million of assets for this plan as of December 31, 2011, 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	Pension Benefits						Other Benefits
the benefit obligation at plan year-end	2011			2010			2011			2010
Discount rate		5.01	%		5.54	%		5.03	%		5.50	%
Rate of compensation increase		4.08	%		4.08	%		4.07	%		4.06	%


Weighted-average assumptions used to determine	Pension Benefits						Other Benefits
net costs for years ended December 31	2011			2010			2011			2010
Discount rate		5.54	%		5.92	%		5.50	%		5.87	%
Expected long-term return on plan assets		7.29	%		8.00	%		2.83	% *		4.25	% *
Rate of compensation increase		4.08	%		4.26	%		4.06	%		4.25	%
* after tax

For pension benefits, Great Plains Energy's 2012 projected weighted-average long-term rate of return on plan assets is 7.3%, unchanged from 2011.

Great Plains Energy expects to contribute $94.5 million to the pension plans in 2012 to meet Employee Retirement Income Security Act of 1974 (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 $16.7 million to other post-retirement benefit plans in 2012, 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 2021.


	Pension		Other
	Benefits		Benefits
	(millions)
2012	$	76.6	$	8.6
2013		65.5		8.1
2014		67.3		8.3
2015		66.5		8.2
2016		70.1		8.4
2017-2021		381.0		46.3

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, 2011 and 2010, by asset category are in the following tables.


			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


				Fair Value Measurements Using
Description		December 31 2010		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)	$	158.5	$	90.5	$	68.0	$	-
	International(b)		122.4		39.4		83.0		-
	Limited partnerships		0.1		-		-		0.1
	Real estate(c)		30.3		-		-		30.3
	Commodities(d)		37.0		-		37.0		-
	Fixed income securities
	Fixed income funds(e)		148.7		23.0		125.7		-
	U.S. Treasury		1.8		1.8		-		-
	U.S. Agency, state and local obligations		14.8		-		14.8		-
	U.S. corporate bonds(f)		24.2				24.2		-
	Foreign corporate bonds		1.5		-		1.5		-
	Hedge funds(g)		8.4		-		-		8.4
	Total	$	547.7	$	154.7	$	354.2	$	38.8
	Cash equivalents - money market funds		9.9
	Total Pension Plans	$	557.6

(a)	At December 31, 2011 and 2010, this category is comprised of $94.6 million and $90.5 million, respectively, of traded mutual funds valued at daily listed prices and $61.7 million and $68.0 million, respectively,
	of institutional common/collective trust funds valued at daily Net Asset Values (NAV) per share.
(b)	At December 31, 2011 and 2010, this category is comprised of $40.9 million and $39.4 million, respectively, of traded mutual funds valued at daily listed prices and $76.1 million and $83.0 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, 2011 and 2010, this category is comprised of $34.2 million and $23.0 million, respectively, of traded mutual funds valued at daily listed prices and $132.3 million and $125.7 million, respectively, of institutional common/collective trust funds valued at daily NAV per share.
(f)	At December 31, 2011 and 2010, this category is comprised of $18.1 million and $13.9 million, respectively, of corporate bonds, $6.1 million and $8.0 million, respectively, of collateralized mortgage obligations
	and $2.4 million and $2.3 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 2011 and 2010.


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Real		Hedge			Limited
Description	Estate		Funds			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
Relating to assets sold		-		-			-			-
Purchase, sales, and settlements		0.5		14.6			-			15.1
Transfers in and/or out of Level 3		-		-			-			-
Balance December 31, 2011	$	34.7	$	21.7		$	-		$	56.4


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Real		Hedge			Limited
Description	Estate		Funds			Partnerships		Total
	(millions)
Balance January 1, 2010	$	26.8	$	2.4		$	0.1	$	29.3
Actual return on plan assets
Relating to assets still held		2.5		(0.2	)		-		2.3
Relating to assets sold		-		(0.7	)		-		(0.7	)
Purchase, sales, and settlements		1.0		6.9			-		7.9
Transfers in and/or out of Level 3		-		-			-		-
Balance December 31, 2010	$	30.3	$	8.4		$	0.1	$	38.8

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, 2011 and 2010, by asset category are in the following tables.


				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
	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 and cash equivalents - money market funds		18.0
	Total Other Post-Retirement Benefit Plans	$	77.4

(a)	This category is comprised of $12.7 million of corporate bonds, $0.6 million of collateralized mortgage obligations and $1.5 million
	of other asset-backed securities.


				Fair Value Measurements Using
Description		December 31 2010		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
	Fixed income
	U.S. Treasury	$	12.1	$	12.1	$	-	$	-
	U.S. Agency, state and local obligations		22.2		-		22.2		-
	U.S. corporate bonds (a)		11.4		-		11.4		-
	Foreign corporate bonds		1.0				1.0
	Mutual funds		0.1		0.1		-		-
	Total	$	46.8	$	12.2	$	34.6	$	-
	Cash and cash equivalents - money market funds		19.0
	Total Other Post-Retirement Benefit Plans	$	65.8

(a)	This category is comprised of $9.2 million of corporate bonds, $0.9 million of collateralized mortgage obligations and $1.3 million
	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 trend assumed for 2011 and 2012 was 8.0%, 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, 2011, 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	$	0.5	$	(0.4	)
Effect on post-retirement benefit obligation		4.0		(3.5	)

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, $8.9 million and $8.8 million in 2011, 2010 and 2009, respectively. KCP&L’s annual cost of the plans was approximately $6.7 million, $6.5 million and $6.5 million in 2011, 2010 and 2009, respectively.

Voluntary Separation Program

In March 2011, Great Plains Energy and KCP&L announced an organizational realignment and voluntary separation program to assist in the management of overall costs within the level reflected in the Companies’ retail electric rates and to enhance organizational efficiency. Savings from the realignment process and voluntary separation program, including approximately $15 million in labor costs on an annual basis, are expected to partially offset projected cost increases. Under the voluntary separation program, any non-union employee could voluntarily elect to separate and receive a severance payment equal to two weeks of salary for every year of employment, with a minimum severance payment equal to fourteen weeks of salary. There were 140 employees that made such elections and the majority separated on April 30, 2011. Great Plains Energy recorded $12.7 million in 2011 related to this voluntary separation program reflecting severance and related payroll taxes to employees who elected to voluntarily separate. KCP&L recorded $9.2 million in 2011 related to this voluntary separation program.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

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

-Publisher FASB

-Name Implementation Guide (Q and A)

-Number FAS88

-Paragraph 63

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-URI http://asc.fasb.org/topic&trid=2235017

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 158

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-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

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-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

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+ Details

Equity Compensation

12 Months Ended

Dec. 31, 2011

Equity Compensation [Abstract]

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 2012 to satisfy performance share payments, stock option exercises 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 associated income tax benefits.


	2011		2010		2009
Great Plains Energy	(millions)
Compensation expense	$	5.2	$	4.3	$	6.3
Income tax benefits		1.9		1.0		1.6
KCP&L
Compensation expense		3.5		3.0		4.3
Income tax benefits		1.3		0.5		0.8

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 Great Plains Energy’s Board of Directors. 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 2011, inputs for expected volatility, dividend yield and risk-free rates ranged from 28%-30%, 3.98%-4.35%, and 0.61%-1.15%, respectively.

Performance share activity for 2011 is summarized in the following table.


	Performance			Grant Date
	Shares			Fair Value*
Beginning balance		431,784		$	18.01
Granted		140,128			26.15
Earned		(68,258	)		11.04
Forfeited		(61,612	)		22.38
Ending balance		442,042			21.06
* weighted-average

At December 31, 2011, the remaining weighted-average contractual term was 0.9 years. The weighted-average grant-date fair value of shares granted was $26.15, $23.37, and $15.04 in 2011, 2010 and 2009, respectively. At December 31, 2011, there was $3.4 million of total unrecognized compensation expense, net of forfeiture rates, related to performance shares granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term. The total fair value of performance shares earned and paid in 2011 was $0.8 million. The total fair value of performance shares earned and paid in 2010 was insignificant. There were no performance shares earned and paid during 2009.

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 2011 is summarized in the following table.


	Nonvested			Grant Date
	Restricted Stock			Fair Value*
Beginning balance		406,657		$	16.23
Granted and issued		182,385			19.03
Vested		(149,688	)		17.29
Forfeited		(53,171	)		17.25
Ending balance		386,183			17.06
* weighted-average

At December 31, 2011, the remaining weighted-average contractual term was 1.3 years. The weighted-average grant-date fair value of shares granted was $19.03, $17.80, and $14.36 during 2011, 2010 and 2009, respectively. At December 31, 2011, there was $2.9 million of total unrecognized compensation expense, net of forfeiture rates, related to nonvested restricted stock granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term. The total fair value of shares vested was $2.6 million, $7.3 million, and $5.4 million in 2011, 2010 and 2009, respectively.

Stock Options

Stock options were granted under the Long-Term Incentive Plan during 2001-2003 at market value of the shares on the grant date. The options vested three years after the grant date and expire in ten years if not exercised. The fair value for the stock options was estimated at the date of grant using the Black-Scholes option-pricing model. Compensation expense and accrued dividends related to stock options were recognized over the stated vesting period. GMO stock options outstanding on the July 14, 2008, acquisition date of GMO were converted to Great Plains Energy stock options upon acquisition. As of December 31, 2011, there are no outstanding GMO converted stock options.

Stock option activity under all plans for 2011 is summarized in the following table. All stock options are fully vested at December 31, 2011.


				Exercise
Stock Options	Shares			Price*
Beginning balance		198,781		$	32.51
Forfeited or expired		(189,428	)		32.83
Outstanding and exercisable at December 31, 2011		9,353			25.91
* weighted-average

There were no options exercised in 2011. The weighted-average grant-date fair value of options exercised for 2010 was $9.21. The aggregate intrinsic value and cash received for options exercised in 2010 was insignificant. At December 31, 2011, there were no in the money outstanding and exercisable options. The weighted-average remaining contractual life for options still outstanding at December 31, 2011 was 0.6 years.

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 2011 and 2010. Director Deferred Share Units activity for 2011 is summarized in the following table.


	Share		Grant Date
	Units		Fair Value*
Beginning balance		39,063	$	20.04
Issued		15,168		20.57
Ending balance		54,231		20.19
* weighted-average

- Definition

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.

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 123R

-Paragraph 64, 65, A240

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

-Publisher AICPA

-Name Statement of Position (SOP)

-Number 93-6

-Paragraph 53

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

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

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-Name Staff Accounting Bulletin (SAB)

-Number Topic 14

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+ Details

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

12 Months Ended

Dec. 31, 2011

Short-term Borrowings and Short-term Bank Lines of Credit [Abstract]

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

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

Great Plains Energy’s $200 Million Revolving Credit Facility

In December 2011, Great Plains Energy entered into an amendment to its $200 million revolving credit facility with a group of banks to extend the term to December 2016 from August 2013. The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time. A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At December 31, 2011, Great Plains Energy was in compliance with this covenant. 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. At December 31, 2010, Great Plains Energy had $9.5 million of outstanding cash borrowings at a weighted-average interest rate of 3.06% and had issued letters of credit totaling $15.8 million under the credit facility.

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

In December 2011, KCP&L entered into an amendment to its $600 million revolving credit facility with a group of banks that provides support for its issuance of commercial paper and other general corporate purposes to extend the term to December 2016 from August 2013. Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities. A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At December 31, 2011, KCP&L was in compliance with this covenant. 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. At December 31, 2010, KCP&L had $263.5 million of commercial paper outstanding, at a weighted-average interest rate of 0.41%, had issued letters of credit totaling $24.4 million and had no outstanding cash borrowings under the credit facility.

GMO’s $450 Million Revolving Credit Facility and Commercial Paper

In December 2011, GMO entered into an amendment to its $450 million revolving credit facility with a group of banks that provides support for its issuance of commercial paper and other general corporate purposes to extend the term to December 2016 from August 2013. Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities. A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At December 31, 2011, GMO was in compliance with this covenant. 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. At December 31, 2010, GMO had no outstanding cash borrowings and had issued letters of credit totaling $13.2 million under the credit facility.

- Definition

The entire disclosure for short-term debt.

+ References+ Details

Long-Term Debt

12 Months Ended

Dec. 31, 2011

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		2011			2010
KCP&L			(millions)
General Mortgage Bonds
4.87% EIRR bonds(a)(b)		2012-2035	$	119.3		$	158.8
7.15% Series 2009A (8.59% rate)(c)		2019		400.0			400.0
4.65% EIRR Series 2005		2035		50.0			50.0
EIRR Series 2007A-1(d)		2035		-			63.3
EIRR Series 2007A-2(d)		2035		-			10.0
5.375% EIRR Series 2007B		2035		73.2			73.2
Senior Notes
6.50% Series				-			150.0
5.85% Series (5.72% rate)(c)		2017		250.0			250.0
6.375% Series (7.49% rate)(c)		2018		350.0			350.0
6.05% Series (5.78% rate)(c)		2035		250.0			250.0
5.30% Series		2041		400.0			-
EIRR bonds 4.90% Series 2008		2038		23.4			23.4
Other		2012-2018		2.9			3.3
Current maturities				(12.7	)		(150.3	)
Unamortized discount				(4.2	)		(2.0	)
Total KCP&L excluding current maturities				1,901.9			1,629.7
Other Great Plains Energy
GMO First Mortgage Bonds 9.44% Series		2012-2021		11.2			12.4
GMO Pollution Control Bonds
5.85% SJLP Pollution Control		2013		5.6			5.6
0.164% Wamego Series 1996(e)		2026		7.3			7.3
0.353% State Environmental 1993(e)		2028		5.0			5.0
GMO Senior Notes
7.95% Series				-			137.3
7.75% Series				-			197.0
11.875% Series		2012		500.0			500.0
8.27% Series		2021		80.9			80.9
Fair Value Adjustment				16.3			49.9
GMO Medium Term Notes
7.16% Series		2013		6.0			6.0
7.33% Series		2023		3.0			3.0
7.17% Series		2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(c)		2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(c)		2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes		2012		287.5			287.5
Great Plains Energy 4.85% Senior Notes (7.34% rate)(c)		2021		350.0			-
Current maturities				(788.7	)		(335.4	)
Unamortized discount				(0.7	)		(0.5	)
Total Great Plains Energy excluding current maturities			$	2,742.3		$	2,942.7
(a) Weighted-average interest rates at December 31, 2011
(b) December 31, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by KCP&L
(c) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(d) December 31, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have
been repurchased and are held by KCP&L
(e) Variable rate

Amortization of Debt Expense

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


	2011		2010		2009
	(millions)
KCP&L	$	3.6	$	2.8	$	2.0
Other Great Plains Energy		4.5		3.6		2.4
Total Great Plains Energy	$	8.1	$	6.4	$	4.4

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 April 2011, KCP&L purchased in lieu of redemption its $63.3 million EIRR Series 2007A-1, $10.0 million EIRR Series 2007A-2 and $39.5 million EIRR Series 1993B bonds. KCP&L opted to purchase rather than remarket the bonds given the poor conditions in the tax-exempt market. As of December 31, 2011, 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 $642.5 million and $755.3 million were outstanding at December 31, 2011 and 2010, 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, 2011, 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.

KCP&L Senior Notes

In September 2011, KCP&L issued $400.0 million of 5.30% unsecured Senior Notes, maturing in 2041. In November 2011, KCP&L repaid its $150.0 million 6.5% Senior Notes at maturity.

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 St. Joseph Light & Power division utility plant. Mortgage bonds totaling $11.2 million and $12.4 million, respectively, were outstanding at December 31, 2011 and 2010.

GMO Senior Notes

The fair value adjustment for GMO represents the $133.3 million purchase accounting adjustment to record GMO’s debt related to the 11.875% and 7.75% Senior Notes that are not fully reflected in electric retail rates as of the July 14, 2008, acquisition date, at estimated fair value, with the offset recorded to goodwill. The fair value adjustment is being amortized as a reduction to interest expense over the remaining life of the individual debt issues. Amortization for 2011, 2010 and 2009 was $33.6 million, $34.6 million and $33.0 million, respectively. The fair value adjustment will be fully amortized in 2012 with amortization of $16.3 million.

GMO repaid its $137.3 million 7.95% Senior Notes that matured in February 2011 and $197.0 million 7.75% Senior Notes that matured in June 2011.

Great Plains Energy Senior Notes

In May 2011, Great Plains Energy issued $350.0 million of 4.85% unsecured Senior Notes, maturing in 2021. As a result of amortizing the loss recognized in Other Comprehensive Income (OCI) on Great Plains Energy’s three-year Forward Starting Swaps (FSS), the effective interest rate is 7.34% through May 2014.

Great Plains Energy 10.00% Equity Units Subordinated Notes Classified As Current Maturities

In May 2009, Great Plains Energy issued $287.5 million of Equity Units. Equity Units, each with a stated amount of $50, initially consist 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). Each purchase contract obligates the holder of the purchase contract to purchase, and Great Plains Energy to sell, no later than June 15, 2012, for $50 in cash, newly issued shares of the Company’s common stock equal to the settlement rate. The purchase contracts may be settled earlier at the option of the holder subject to certain conditions, including but not limited to, the occurrence of a fundamental change (as defined in the agreement) at least 20 business days prior to June 15, 2012. The settlement rate will vary according to the applicable market value of the Company’s common stock at the settlement date. The applicable market value will be 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. The settlement rate will be applied to the 5,750,000 Equity Units at the settlement date to issue a number of common shares determined as described in the following table.


Applicable		Settlement rate	Market value
market value		(in common shares)	per Equity Unit (a)
$16.80 or greater		2.9762 to 1	Greater than $50 per Equity Unit

$16.80 to $14.00		$50 divided by the applicable	Equal to $50 per Equity Unit
		market value to 1

$14.00 or less		3.5714 to 1	Less than $50 per Equity Unit
(a)	Assumes that the market price of the Company's common stock on June 15, 2012,
	is the same as the applicable market value.

Great Plains Energy makes quarterly contract adjustment payments at the rate of 2.00% per year of the stated amount of $50 per Equity Unit and interest payments at the rate of 10.00% per year on the subordinated notes. Great Plains Energy must attempt to remarket the subordinated notes, in whole but not in part, by June 12, 2012. In connection with a successful remarketing of the notes, Great Plains Energy may elect, without the consent of any of the holders, to modify the notes’ stated maturity to any date on or after June 15, 2014 and earlier than June 15, 2042. The proceeds from a successful remarketing will be used to satisfy the holders’ obligation under the purchase contract. If the notes have not been successfully remarketed by June 12, 2012, the holders of all notes will have the right to put their notes to Great Plains Energy on June 15, 2012, in satisfaction of the holders’ obligation under the purchase contracts and Great Plains Energy will issue to the holders newly issued shares of the Company’s common stock equal to the settlement rate.

The May 2009 present value of the contract adjustment payments of $15.1 million was recorded as a liability in other current liabilities and other deferred credits and other liabilities with a corresponding amount recorded as capital stock premium and expense on Great Plains Energy’s consolidated balance sheet. The liability is being relieved as Great Plains Energy makes quarterly contract adjustment payments.

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.


	2012		2013		2014		2015		2016
	(millions)
Great Plains Energy $		801.4	$	263.1	$	1.5	$	15.5	$	1.6
KCP&L		12.7		0.4		0.4		14.4		0.4

At December 31, 2011, Great Plains Energy’s current maturities of long-term debt were $801.4 million. In January 2012, KCP&L repaid $12.4 million of 4.00% EIRR bonds at maturity. Great Plains Energy’s $287.5 million of Equity Units subordinated notes mature in 2042 but must be remarketed by June 12, 2012. GMO’s $500.0 million of 11.875% Senior Notes mature in July 2012 and Great Plains Energy is evaluating alternatives to refinance this long-term debt. Based on current market conditions and Great Plains Energy’s unused bank lines of credit, Great Plains Energy expects to have the ability to access the markets to complete the necessary refinancing.

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

+ Details

Common Shareholders' Equity

12 Months Ended

Dec. 31, 2011

Common Shareholders' Equity [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 May 2009.

Great Plains Energy has 5.0 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, 2011, 0.7 million shares remained available for future issuances.

Great Plains Energy has 12.3 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, 2011, 0.4 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. In addition, Great Plains Energy is prohibited from paying dividends on its common and preferred stock in the event its Equity Unit contract payments or interest payments on the debt underlying the Equity Units are deferred until such deferrals have been paid.

As of December 31, 2011, 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, 2011. The restrictions are not expected to affect the Companies’ ability to pay dividends at the current level in the foreseeable future.

- Definition

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.

+ References

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+ Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 that would reduce emissions of toxic air pollutants, (all of which are discussed below) is approximately $1 billion. The actual cost of compliance with any existing, proposed or future rules may be significantly different from the cost estimate provided.

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

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

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

·	KCP&L’s Montrose No. 3 full AQCS installed by approximately 2017; and

·	GMO’s Sibley No. 3 scrubber and baghouse installed by approximately 2017.

In September 2011, KCP&L commenced construction of the La Cygne project. Other capital projects at KCP&L’s Montrose Nos. 1 and 2 and GMO’s Sibley Nos. 1 and 2 and Lake Road Nos. 4 and 6 are possible but are currently considered less likely. Any capacity and energy requirements resulting from a decision not to proceed with these less likely projects is currently expected to be met through renewable energy additions required under Missouri and Kansas renewable energy standards, demand side management programs, construction of combustion turbines and/or combined cycle units, and/or power purchase agreements.

The estimate does not reflect the non-capital costs the Companies incur on an ongoing basis to comply with environmental laws, which may increase in the future due to the Companies’ ongoing compliance with current or future environmental laws. 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 NOx emissions in 28 states, including Missouri. The reductions in SO2 and NOx emissions are accomplished through statewide caps for NOx and SO2. Great Plains Energy’s and KCP&L’s fossil fuel-fired plants located in Missouri are subject to CAIR, while their fossil fuel-fired plants in Kansas are not.

On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety and remanded the matter to the EPA to promulgate a new rule consistent with its opinion. On December 23, 2008, the Court issued an order remanding CAIR to the EPA to revise the rule consistent with its July 2008 order.

In July 2011, the EPA finalized the CSAPR to replace the currently-effective CAIR. The CSAPR requires the states within its scope to reduce power plant SO2 and NOx emissions that contribute to ozone and fine particle nonattainment in other states. The geographical scope of the CSAPR includes Kansas, Missouri and other states. Kansas and Missouri are included in the annual SO2 and NOx programs for the control of fine particulate matter in the CSAPR. In December 2011, the EPA finalized a rulemaking to include Missouri for ozone season control but not Kansas. The EPA will address the inclusion of Kansas in a separate action and revisit Kansas’ status in the CSAPR at that time. In the CSAPR, the EPA set an emissions budget for each of the affected states. The CSAPR allows limited interstate emissions allowance trading among power plants; however, it does not permit trading of SO2 allowances between the Companies’ Kansas and Missouri power plants. There would be additional reductions in SO2 allowances allocable to the Companies’ Missouri power plants taking effect in 2014. There is no such 2014 additional reduction in SO2 allowances allocable to the Companies’ Kansas power plants. In February 2012, the EPA finalized technical adjustments to the final CSAPR. The rules amend the assurance penalty provisions, which would further restrict interstate trading of emission allowances, to start in 2014 instead of 2012. The EPA revised certain unit-level allocations in certain states, including Kansas and Missouri, which would re-allocate allowances to assist KCP&L in compliance with the CSAPR.

Compliance with the CSAPR was 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 December 2011, the D.C. Circuit Court issued an order staying the CSAPR pending the Court's resolution of the petitions for review of the rule. The order requires the EPA to continue administering the CAIR while the CSAPR is stayed.

The CSAPR is complex and Great Plains Energy and KCP&L are evaluating its impacts. The Companies project that they may not be allocated sufficient SO2 or NOX emissions allowances to cover their currently expected operations when the rule becomes effective. Any shortfall in allocated allowances is anticipated to be addressed through a combination of permissible allowance trading, installing additional emission control equipment, changes in plant processes, or purchasing additional power in the wholesale market.

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, KCP&L’s Montrose No. 3 in Missouri, GMO’s Sibley Unit No. 3 and Lake Road Unit No. 6 in Missouri and Westar Energy, Inc.’s (Westar) Jeffrey Unit Nos. 1 and 2 in Kansas, in which GMO has an 8% interest. Both Missouri and Kansas have submitted BART plans to the EPA. In December 2011, the EPA issued a proposal that would approve the CSAPR as an alternative to determining BART. As a result, states in the CSAPR would be able to substitute participation in the CSAPR for source-specific BART. In December 2011, the EPA approved the Kansas BART plan.

Mercury and Air Toxics Standards (MATS) Rule

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

In December 2011, the EPA finalized the Mercury and Air Toxics Standards (MATS) Rule that will reduce emissions of toxic air pollutants, also known as hazardous air pollutants, from new and existing coal- and oil-fired EGUs with a capacity of greater than 25 MWs. The rule establishes numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrochloric acid (a surrogate for acid gases). The rule establishes work practices, instead of numerical emission limits, for organic air toxics, including dioxin/furan. Compliance with the rule would need to be addressed by installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market or a combination of these and other alternatives. The rule allows three years for compliance with authority for state permitting authorities to grant an additional year as needed for technology installation. The EPA indicated that it expects this option to be broadly available.

Industrial Boiler Rule

In February 2011, the EPA issued a final rule that would reduce emissions of hazardous air pollutants from new and existing industrial boilers. In May 2011, the EPA announced it would stay the effective date of the final rule during reconsideration; although in January 2012, the D.C. Circuit Court vacated the stay and remanded the stay to the EPA. In December 2011, the EPA issued a proposed revised rule and intends to issue a final rule in the spring of 2012. The proposed revised rule establishes numeric emission limits for mercury, particulate matter (as a surrogate for non-mercury metals), hydrogen chloride (as a surrogate for acid gases), and carbon monoxide (as a surrogate for non-dioxin organic hazardous air pollutants). The final rule establishes emission limits for KCP&L’s and GMO’s existing units that produce steam other than for the generation of electricity. The existing boiler rule and its proposed revisions do not apply to KCP&L’s and GMO’s electricity generating boilers, but would apply to most of GMO’s Lake Road boilers, which also serve steam customers, and to auxiliary boilers at other generating facilities.

New Source Review

The Clean Air Act 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 March 2010, the U.S. District Court in the District of Kansas approved a settlement agreement between Westar and the parties of a lawsuit filed by the Department of Justice on behalf of the EPA. The lawsuit asserted that certain projects completed at the Jeffrey Energy Center violated certain requirements of the EPA’s New Source Review program. The Jeffrey Energy Center consists of three coal-fired units located in Kansas that is 92% owned by Westar and operated exclusively by Westar. GMO has an 8% interest in the Jeffrey Energy Center and is generally responsible for its 8% share of the facility’s operating costs and capital expenditures. The settlement agreement required, among other things, the installation of a selective catalytic reduction (SCR) system at one of the Jeffrey Energy Center units by the end of 2014 and the payment of a $3 million civil penalty. Westar has estimated the cost of this SCR at approximately $240 million. Depending on the NOx emission reductions attained by that SCR and attainable through the installation of other controls at the other two units, the settlement agreement may require the installation of a second SCR system on one of the other two units by the end of 2016. There is no assurance that GMO’s share of these costs would be recovered in rates and failure to recover such costs could have a significant effect on Great Plains Energy’s results of operations, financial position and cash flows.

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

Collaboration Agreement

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

In 2006, KCP&L installed 100 MWs of wind generation at its Spearville wind site. KCP&L agreed in the Collaboration Agreement to pursue increasing its wind generation capacity to 500 MWs in total by the end of 2012 with 100 MWs to be added by the end of 2010 and the remainder added by the end of 2012, subject to regulatory approval. In 2010, KCP&L completed a 48 MWs wind project adjacent to its existing Spearville wind site with wind turbines it already owned and also secured 52 MWs of renewable energy credits. During 2011, KCP&L entered into long-term power purchase agreements for approximately 231 MWs of wind generation beginning in 2012 and GMO entered into a long-term power purchase agreement for approximately 100 MWs of wind generation beginning in 2012, which expire in 2032.

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

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

Climate Change

The Companies are subject to existing greenhouse gas reporting regulations and certain greenhouse gas permitting requirements. Management believes it is possible that additional federal or relevant state or local laws or regulations could be enacted to address global climate change. At the international level, while the United States is not a current party to the international Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions. International agreements legally binding on the United States may be reached in the future. Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels. The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 25 million tons and 18 million tons per year for Great Plains Energy and KCP&L, respectively.

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

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

In March 2011, the EPA announced it finalized a settlement agreement to issue a rule that will address greenhouse gas emissions from EGUs. The rule would establish new source performance standards for new and modified EGUs and emission guidelines for existing EGUs. Under the settlement agreement, the EPA committed to issuing proposed regulations by September 2011, although the EPA did not meet that date, and final regulations by May 2012.

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

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

SO2 NAAQS

In June 2010, the EPA strengthened the primary NAAQS for SO2. The EPA revised the primary SO2 standard by establishing a new 1-hour standard at a level of 0.075 ppm. The EPA revoked the two existing primary standards of 0.140 ppm evaluated over 24 hours and 0.030 ppm evaluated over an entire year. 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.

Montrose Station Notice of Violation

In June 2009, KCP&L received notification from the MDNR alleging that its Montrose Station had excess particulate matter emissions in 2008. In November 2011, KCP&L and MDNR Executed an Abatement Order on Consent that resolved all claims for the violations alleged without KCP&L admitting the validity or accuracy of such claims. KCP&L agreed in compromise and satisfaction of MDNR’s claims to complete a supplemental environmental project in the amount of $150,000.

Water

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

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

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

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

Solid Waste

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

Remediation

Certain federal and state laws, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) hold current and previous owners or operators of real property, and any person who arranges for the disposal or treatment of hazardous substances at a property, liable on a joint and several basis for the costs of cleaning up contamination at or migrating from such real property, even if they did not know of and were not responsible for such contamination. CERCLA and other laws also authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. GMO is named as a potentially responsible party at two disposal sites for polychlorinated 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, 2011 and 2010, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site. At December 31, 2011 and 2010, Great Plains Energy had $0.4 million accrued for environmental remediation expenses, which includes the $0.3 million at KCP&L, and additional potential remediation and ground water monitoring costs relating to two GMO sites. The amounts accrued were established on an undiscounted basis and Great Plains Energy and KCP&L do not currently have an estimated time frame over which the accrued amounts may be paid.

In addition to the $0.4 million accrual above, at December 31, 2011 and 2010, Great Plains Energy had $2.1 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB contaminated sites and retained liabilities. This estimate was based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary. This estimate could change materially after further investigation, and could also be affected by the actions of environmental agencies and the financial viability of other potentially responsible parties; however, given the uncertainty of these items the possible loss or range of loss in excess of the amount accrued is not estimable.

GMO has pursued recovery of remediation costs from insurance carriers and other potentially responsible parties. As a result of a settlement with an insurance carrier, approximately $2.4 million in insurance proceeds less an annual deductible is available to GMO to recover qualified MGP remediation expenses. GMO would seek recovery of additional remediation costs and expenses through rate increases; however, there can be no assurance that such rate increases would be granted.

Contractual Commitments

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


	2011		2010		2009
	(millions)
Great Plains Energy	$	20.9	$	17.2	$	23.4
KCP&L		17.0		13.2		19.3

Great Plains Energy’s and KCP&L’s contractual commitments at December 31, 2011, excluding pensions and long-term debt, are detailed in the following tables.


Great Plains Energy
	2012		2013		2014		2015		2016		After 2016		Total
Lease commitments	(millions)
Operating lease	$	19.7	$	16.3	$	14.8	$	13.6	$	9.8	$	119.2	$	193.4
Capital lease		0.4		0.4		0.4		0.4		0.4		4.7		6.7
Purchase commitments
Fuel		397.4		360.5		202.0		103.9		83.2		94.1		1,241.1
Power		8.5		29.2		34.8		34.8		34.8		686.3		828.4
Capacity		13.4		12.4		4.5		4.2		2.4		-		36.9
La Cygne environmental project		376.6		300.2		125.4		5.5		-		-		807.7
Non-regulated natural gas
transportation		2.8		3.6		3.6		3.6		3.6		0.9		18.1
Other		54.4		101.7		21.0		25.4		3.7		49.8		256.0
Total contractual commitments	$	873.2	$	824.3	$	406.5	$	191.4	$	137.9	$	955.0	$	3,388.3


KCP&L
	2012		2013		2014		2015		2016		After 2016		Total
Lease commitments	(millions)
Operating lease	$	16.0	$	14.0	$	13.0	$	12.2	$	9.7	$	119.2	$	184.1
Capital lease		0.2		0.2		0.2		0.2		0.2		2.6		3.6
Purchase commitments
Fuel		336.0		298.8		169.1		91.5		79.1		94.1		1,068.6
Power		8.5		29.2		34.8		34.8		34.8		499.1		641.2
Capacity		4.7		3.7		2.9		3.0		1.2		-		15.5
La Cygne environmental project		376.6		300.2		125.4		5.5		-		-		807.7
Other		40.3		100.9		20.2		24.6		2.9		39.5		228.4
Total contractual commitments	$	782.3	$	747.0	$	365.6	$	171.8	$	127.9	$	754.5	$	2,949.1

Great Plains Energy has expected sublease income of $1.2 million for the years 2012-2013. 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 $2.2 million per year from 2012 to 2015 and then $0.4 million per year from 2016 to 2025, for a total of $13.0 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 $3.8 million for 2012 and $1.6 million for 2013. La Cygne environmental project represents 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.

- Definition

The entire disclosure for commitments and contingencies.

+ References

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

-Publisher FASB

-Name FASB Interpretation (FIN)

-Number 14

-Paragraph 3

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 5

-Paragraph 9, 10, 11, 12

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-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

+ Details

Legal Proceedings

12 Months Ended

Dec. 31, 2011

Legal Proceedings [Abstract]

Legal Proceedings

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. Briefing to the Court was completed in December 2011, and oral argument has been scheduled for March 7, 2012.

GMO Price Reporting Litigation

In response to complaints of manipulation of the California energy market 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. However, in December 2001, various parties appealed the FERC order to the United States Court of Appeals for the Ninth Circuit seeking review of a number of issues, including changing the refund period to include periods prior to October 2, 2000. MPS Merchant was a net seller of power during the period prior to October 2, 2000. On August 2, 2006, the U.S. Court of Appeals for the Ninth Circuit issued an order finding, among other things, that FERC did not provide a sufficient justification for refusing to exercise its remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the period prior to October 2, 2000, and imposing a remedy for any such violations. The court remanded the matter to FERC for further consideration. In May 2011, FERC issued an order which clarified the scope of the hearing in the refund proceeding and ruled on requests for rehearing and motions to dismiss. A hearing is set for April 2012. If FERC ultimately includes the period prior to October 2, 2000, MPS Merchant could be found to owe refunds.

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

- Definition

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

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 5

-Paragraph 9-12, 22-40

-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.

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+ Details

Guarantees

12 Months Ended

Dec. 31, 2011

Guarantees [Abstract]

Guarantees

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 subsidiaries’ 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, 2011, Great Plains Energy has provided $666.0 million of credit support for GMO as follows:

·	Great Plains Energy direct guarantees to GMO counterparties totaling $40.7 million, which expire in 2012,

·	Great Plains Energy letters of credit to GMO counterparties totaling $11.6 million, which expire in 2012, and

·	Great Plains Energy guarantee of GMO long-term debt totaling $613.7 million, which includes debt with maturity dates ranging from 2012-2023.

Great Plains Energy has also guaranteed GMO’s $450 million revolving line of credit with a group of banks as amended December 2011 and expiring in December 2016. At December 31, 2011, GMO had $40.0 million of commercial paper outstanding, had issued letters of credit totaling $13.2 million and had no outstanding cash borrowings under this credit facility.

Related Party Transactions and Relationships

12 Months Ended

Dec. 31, 2011

17.	RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO’s business and operate its facilities at cost. These costs totaled $108.4 million for 2011, $100.9 million for 2010 and $102.7 million for 2009. Additionally, KCP&L and GMO engage in wholesale electricity transactions with each other. KCP&L and GMO are also authorized to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO. The following table summarizes KCP&L’s related party receivables and payables.


	December 31
	2011		2010
	(millions)
Net receivable from GMO	$	24.1	$	29.9
Net receivable from Great Plains Energy		9.5		13.3

- Definition

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

+ References

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-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Article 4

-Section 08

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+ Details

Derivative Instruments

12 Months Ended

Dec. 31, 2011

Derivative Instruments [Abstract]

Derivative Instruments

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

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

Interest Rate Risk Management

In May 2011, Great Plains Energy issued $350.0 million of long-term debt and settled six FSS simultaneously with the issuance of this long-term fixed rate debt. Great Plains Energy had entered into the six FSS with notional amounts totaling $350.0 million to hedge against interest rate variability on the debt issuance. The six FSS were treated as cash flow hedges with no ineffectiveness recorded in 2011 or 2010. A pre-tax loss of $26.1 million was recorded to OCI and is being reclassified to interest expense over the first three years of the ten-year debt. In 2011, a $5.4 million loss has been reclassified from OCI to interest expense.

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, 2011, KCP&L had hedged 66%, 56% and 13%, respectively, of the 2012, 2013 and 2014 projected natural gas usage for retail load and firm MWh sales by utilizing futures contracts. KCP&L has designated the natural gas hedges as cash flow hedges. The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense. KCP&L has not recorded any ineffectiveness on natural gas hedges in 2011, 2010 or 2009.

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, 2011, GMO had financial contracts in place to hedge approximately 45%, 38% and 38%, respectively, of the expected on-peak natural gas and natural gas equivalent purchased power price exposure for 2012, 2013 and 2014. 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					December 31
	2011					2010
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	2.0	$	(0.5	)	$	4.0	$	-
Non-hedging derivatives		23.6		(5.0	)		59.5		(2.5	)
Forward contracts
Non-hedging derivatives		97.3		7.8			202.8		8.9
Option contracts
Non-hedging derivatives		0.4		-			0.2		-
Anticipated debt issuance
Forward starting swaps		-		-			350.0		(20.8	)
KCP&L
Futures contracts
Cash flow hedges		2.0		(0.5	)		4.0		-

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, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
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

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


KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5

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

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


Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)

	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
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	)

2010
Interest rate contracts	$	(27.1	)	Interest charges	$	(10.1	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		10.8		Income tax benefit		4.0
Total	$	(17.2	)	Total	$	(6.6	)


KCP&L
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)

	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
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	)

2010
Interest rate contracts	$	-		Interest charges	$	(8.8	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		0.3		Income tax benefit		3.6
Total	$	(0.6	)	Total	$	(5.7	)

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


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

2010
Commodity contracts	$	(8.2	)	Fuel	$	(7.2	)
Total	$	(8.2	)	Total	$	(7.2	)

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 $1.1 million for 2011 and $0.2 million for 2010.

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
	2011			2010			2011			2010
	(millions)
Current assets	$	11.3		$	12.0		$	11.3		$	12.0
Current liabilities		(89.5	)		(101.5	)		(62.5	)		(71.6	)
Noncurrent liabilities		(0.2	)		-			(0.2	)		-
Deferred income taxes		30.5			34.8			20.0			23.2
Total	$	(47.9	)	$	(54.7	)	$	(31.4	)	$	(36.4	)

Great Plains Energy’s accumulated OCI in the table above at December 31, 2011, includes $20.5 million that is expected to be reclassified to expenses over the next twelve months. KCP&L’s accumulated OCI includes $9.1 million that is expected to be reclassified to expense over the next twelve months.

- Definition

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.

+ References

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-Publisher FASB

-Name Accounting Standards Codification

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-SubTopic 10

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+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [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 categorized within this level consist of Great Plains Energy’s and KCP&L’s various exchange traded derivative instruments and equity and U.S. Treasury securities that are actively traded within KCP&L’s decommissioning trust fund and GMO’s SERP rabbi trust fund.

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

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

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


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


						Fair Value Measurements Using
Description	December 31 2010		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
Derivative instruments (a)	$	-	$	(0.1	)	$	0.1	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		85.5		-			85.5		-		-
Debt securities
U.S. Treasury		8.9		-			8.9		-		-
U.S. Agency		4.8		-			-		4.8		-
State and local obligations		2.5		-			-		2.5		-
Corporate bonds		23.7		-			-		23.7		-
Foreign governments		0.7		-			-		0.7		-
Other		0.4		-			-		0.4		-
Total nuclear decommissioning trust		126.5		-			94.4		32.1		-
Total		126.5		(0.1	)		94.5		32.1		-
Liabilities
Derivative instruments (a)		-		(0.1	)		0.1		-		-
Total	$	-	$	(0.1	)	$	0.1	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.5	)	$	0.5	$	5.2	$	3.7
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		7.0		-			-		7.0		-
Total SERP rabbi trust		7.2		-			0.2		7.0		-
Total		16.1		(0.5	)		0.7		12.2		3.7
Liabilities
Derivative instruments (a)		20.8		(3.0	)		3.0		20.8		-
Total	$	20.8	$	(3.0	)	$	3.0	$	20.8	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.6	)	$	0.6	$	5.2	$	3.7
Nuclear decommissioning trust (b)		126.5		-			94.4		32.1		-
SERP rabbi trust (c)		7.2		-			0.2		7.0		-
Total		142.6		(0.6	)		95.2		44.3		3.7
Liabilities
Derivative instruments (a)		20.8		(3.1	)		3.1		20.8		-
Total	$	20.8	$	(3.1	)	$	3.1	$	20.8	$	-

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

(b)	Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $3.0 million and $2.7 million at December 31, 2011 and 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(c)	Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $20.3 million and $14.6 million at December 31, 2011 and 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)

Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty. At December 31, 2011 and 2010, Great Plains Energy netted $5.5 million and $2.5 million, respectively, of cash collateral posted with counterparties.

The following tables reconcile the beginning and ending balances for all Level 3 assets and liabilities, net measured at fair value on a recurring basis for 2011 and 2010.


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other
	Great
	Plains
	Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains
included in non-operating income		10.9
Settlements		(11.5	)
Balance December 31, 2011	$	3.1

Total unrealized losses included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at December 31, 2011	$	(0.2	)


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other
				Great			Great
				Plains			Plains
	KCP&L			Energy			Energy
	State & Local			Derivative
	Obligations			Instruments			Total
	(millions)
Balance January 1, 2010	$	0.2		$	4.1		$	4.3
Total realized/unrealized losses
included in non-operating income		-			(12.5	)		(12.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			12.1			12.1
Balance December 31, 2010	$	-		$	3.7		$	3.7

Total unrealized gains included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at December 31, 2010	$	-		$	0.1		$	0.1

Investments in Affordable Housing Limited Partnerships

Nearly all of Great Plains Energy’s investments in affordable housing limited partnerships were recorded at cost; the equity method was used for the remainder. Accounting guidance requires entities to evaluate whether an event or change in circumstances has occurred that may have a significant adverse effect on the fair value of the investment (an impairment indicator). During 2010, an impairment indicator occurred, which required Great Plains Energy to evaluate if its cost method investments in affordable housing limited partnerships were impaired. The value of these investments was derived from tax credits and potential cash distributions from the partnerships upon sales of the underlying properties. All of the tax credits had been received and management did not anticipate receiving any cash distributions from the partnerships; therefore, management concluded that the investments were impaired and that the impairment was other than temporary since the partnerships were in the process of liquidating over the next 2 – 3 years. As a result of the evaluation, management concluded that the cost method investments had no value and accordingly, Great Plains Energy recorded an $11.2 million pre-tax impairment loss in non-operating expense on the consolidated income statement in 2010.

- Definition

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.

+ References

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-Name Accounting Standards Codification

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-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.

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+ Details

Taxes

12 Months Ended

Dec. 31, 2011

Taxes [Abstract]

Taxes

20.

TAXES

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


Great Plains Energy	2011			2010			2009
Current income taxes	(millions)
Federal	$	2.9		$	(7.4	)	$	(11.1	)
State		(6.0	)		(4.3	)		(0.9	)
Foreign		(0.4	)		0.1			1.3
Total		(3.5	)		(11.6	)		(10.7	)
Deferred income taxes
Federal		90.5			99.8			(13.6	)
State		20.7			24.0			10.0
Total		111.2			123.8			(3.6	)
Noncurrent income taxes
Federal		(18.0	)		(4.8	)		8.3
State		(2.1	)		(1.8	)		1.1
Foreign		(0.6	)		0.5			(1.5	)
Total		(20.7	)		(6.1	)		7.9
Investment tax credit
Deferral		-			(4.2	)		37.2
Amortization		(2.2	)		(2.9	)		(2.2	)
Total		(2.2	)		(7.1	)		35.0
Total income tax expense		84.8			99.0			28.6
Less: taxes on discontinued operations
Current tax benefit		-			-			(1.1	)
Deferred tax expense		-			-			0.2
Income tax expense on continuing operations	$	84.8		$	99.0		$	29.5


KCP&L	2011			2010			2009
Current income taxes	(millions)
Federal	$	1.0		$	5.5		$	41.2
State		(0.6	)		1.1			4.8
Total		0.4			6.6			46.0
Deferred income taxes
Federal		66.0			69.8			(41.7	)
State		14.6			13.4			3.5
Total		80.6			83.2			(38.2	)
Noncurrent income taxes
Federal		(9.3	)		(1.6	)		3.4
State		(1.1	)		(0.3	)		(0.1	)
Total		(10.4	)		(1.9	)		3.3
Investment tax credit
Deferral		-			(4.2	)		37.2
Amortization		(1.5	)		(2.1	)		(1.4	)
Total		(1.5	)		(6.3	)		35.8
Total	$	69.1		$	81.6		$	46.9

Income Tax Expense and Effective Income Tax Rates

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


	Income Tax Expense									Income Tax Rate
Great Plains Energy	2011			2010			2009			2011			2010			2009
	(millions)
Federal statutory income tax	$	90.7		$	108.7		$	63.4			35.0	%		35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		4.0			(5.2	)		(9.9	)		1.5			(1.7	)		(5.5	)
Amortization of investment tax credits		(2.2	)		(2.9	)		(2.2	)		(0.8	)		(0.9	)		(1.2	)
Federal income tax credits		(13.1	)		(12.5	)		(8.0	)		(5.0	)		(4.1	)		(4.4	)
State income taxes		10.5			11.4			7.9			4.0			3.7			4.4
Medicare Part D subsidy legislation		-			2.8			-			-			0.9			-
Changes in uncertain tax positions, net		(4.4	)		0.3			(72.1	)		(1.7	)		0.1			(39.8	)
Valuation allowance		(2.2	)		(2.7	)		55.8			(0.8	)		(0.9	)		30.8
Other		1.5			(0.9	)		(5.4	)		0.5			(0.3	)		(3.0	)
Total	$	84.8		$	99.0		$	29.5			32.7	%		31.8	%		16.3	%


	Income Tax Expense									Income Tax Rate
KCP&L	2011			2010			2009			2011			2010			2009
	(millions)
Federal statutory income tax	$	71.6		$	85.7		$	61.5			35.0	%		35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		3.4			(4.5	)		(7.7	)		1.6			(1.8	)		(4.4	)
Amortization of investment tax credits		(1.5	)		(2.1	)		(1.4	)		(0.7	)		(0.9	)		(0.8	)
Federal income tax credits		(13.0	)		(8.5	)		(7.8	)		(6.3	)		(3.5	)		(4.4	)
State income taxes		8.1			8.9			5.8			3.9			3.6			3.3
Medicare Part D subsidy legislation		-			2.8			-			-			1.1			-
Changes in uncertain tax positions, net		0.3			-			(0.5	)		0.1			-			(0.3	)
Other		0.2			(0.7	)		(3.0	)		0.2			(0.2	)		(1.7	)
Total	$	69.1		$	81.6		$	46.9			33.8	%		33.3	%		26.7	%

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	2011			2010			2011			2010
Current deferred income tax asset (liability)	(millions)
Other	$	7.9		$	14.7		$	(0.1	)	$	5.6
Net current deferred income tax asset (liability) before
valuation allowance		7.9			14.7			(0.1	)		5.6
Valuation allowance		(0.4	)		(0.4	)		-			-
Net current deferred income tax asset (liability)		7.5			14.3			(0.1	)		5.6
Noncurrent deferred income taxes
Plant related		(1,193.6	)		(975.5	)		(861.6	)		(711.5	)
Income taxes on future regulatory recoveries		(144.3	)		(142.6	)		(119.6	)		(117.2	)
Derivative instruments		43.3			46.0			31.1			34.4
Pension and postretirement benefits		(34.2	)		(16.3	)		(11.7	)		2.0
SO2 emission allowance sales		31.1			30.8			31.9			33.4
Fuel clause adjustments		(17.2	)		(16.6	)		(5.4	)		(3.2	)
Transition costs		(17.4	)		(20.0	)		(9.6	)		(11.4	)
Tax credit carryforwards		213.7			204.3			116.8			101.5
Long-term debt fair value adjustment		6.3			19.2			-			-
Customer demand programs		(26.4	)		(23.3	)		(18.6	)		(17.3	)
Net operating loss carryforward		543.7			409.2			77.9			1.1
Other		(10.1	)		(7.3	)		(3.9	)		(3.8	)
Net noncurrent deferred income tax liability before
valuation allowance		(605.1	)		(492.1	)		(772.7	)		(692.0	)
Valuation allowance		(23.5	)		(26.2	)		-			-
Net noncurrent deferred income tax liability		(628.6	)		(518.3	)		(772.7	)		(692.0	)
Net deferred income tax liability	$	(621.1	)	$	(504.0	)	$	(772.8	)	$	(686.4	)


	Great Plains Energy						KCP&L
December 31	2011			2010			2011			2010
	(millions)
Gross deferred income tax assets	$	1,203.6		$	1,140.7		$	618.7		$	602.4
Gross deferred income tax liabilities		(1,824.7	)		(1,644.7	)		(1,391.5	)		(1,288.8	)
Net deferred income tax liability	$	(621.1	)	$	(504.0	)	$	(772.8	)	$	(686.4	)

Tax Credit Carryforwards

At December 31, 2011 and 2010, Great Plains Energy had $118.0 million and $102.6 million, respectively, of federal general business income tax credit carryforwards. At December 31, 2011 and 2010, KCP&L had $116.8 million and $101.5 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 2031. 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 these credits to expire unutilized and has provided a valuation allowance against $0.4 million of the federal income tax benefit.

At December 31, 2011 and 2010, Great Plains Energy had $91.0 million and $90.0 million, respectively, of federal alternative minimum tax credit carryforwards. Of this amount, $89.8 million was acquired in the GMO acquisition. These credits do not expire and can be used to reduce taxes paid in the future.

At December 31, 2011 and 2010, Great Plains Energy had $4.7 million and $11.8 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 2012 to 2016. Management expects that a portion of these credits will expire unutilized and has provided a valuation allowance against $0.3 million of the state income tax benefit.

Net Operating Loss Carryforwards

At December 31, 2011 and 2010, Great Plains Energy had $473.1 million and $353.0 million, respectively, of tax benefits related to federal net operating loss (NOL) carryforwards. Approximately $315.7 million and $317.5 million, at December 31, 2011 and 2010, respectively, are tax benefits related to NOLs that were acquired in the GMO acquisition. The tax benefits for NOLs are $32.6 million originating in 2003, $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, $23.4 million originating in 2009, $11.6 million originating in 2010, and $122.0 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 $70.6 million and $56.2 million related to state NOLs as of December 31, 2011 and 2010, respectively. Approximately $49.9 million and $49.4 million at December 31, 2011 and 2010, respectively, were acquired in the GMO acquisition. Management does not expect to utilize $23.2 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 $23.2 million of state tax benefits.

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 federal and state tax NOL carryforwards, and tax credit carryforwards.

During 2011 and 2010, $2.7 million and $3.2 million, respectively, of tax benefit was recorded in continuing operations. These adjustments are primarily related to a portion of the valuation allowance against federal and state NOL carryforwards.

Uncertain Tax Positions

At December 31, 2011 and 2010, Great Plains Energy had $24.0 million and $42.0 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $11.8 million and $17.3 million at December 31, 2011 and 2010, respectively, are 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 of unrecognized tax benefits 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, 2009, Great Plains Energy had $51.4 million of liabilities related to unrecognized tax benefits of which $17.3 million was expected to impact the effective rate if recognized. The $9.4 million decrease in unrecognized tax benefits in 2010 was primarily due to a decrease of $8.6 million of unrecognized tax benefits related to the sale of certain GMO property during 2010.

At December 31, 2011 and 2010, KCP&L had $8.7 million and $19.1 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $0.2 million and $0.3 million at December 31, 2011 and 2010, respectively, are expected to impact the effective tax rate if recognized. The $10.4 million decrease in unrecognized tax benefits in 2011 is primarily due to a decrease of $12.1 million related to the settlements 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 of deferred income tax liabilities which resulted in an insignificant impact to net income. At December 31, 2009, KCP&L had $20.9 million of liabilities related to unrecognized tax benefits of which $0.4 million was expected to impact the effective rate if recognized.

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


	Great Plains Energy									KCP&L
	2011			2010			2009			2011			2010			2009
	(millions)
Balance at January 1	$	42.0		$	51.4		$	97.3		$	19.1		$	20.9		$	17.6
Additions for current year tax positions		1.4			2.7			13.2			-			1.3			3.9
Additions for prior year tax positions		2.4			2.1			8.2			2.3			1.5			3.0
Additions for GMO prior year tax positions		-			-			11.6			-			-			-
Reductions for prior year tax positions		(20.9	)		(10.6	)		(1.3	)		(12.6	)		(1.6	)		(0.8	)
Settlements		-			(3.8	)		(76.7	)		-			(2.9	)		(2.2	)
Statute expirations		(0.7	)		(0.3	)		(0.7	)		(0.1	)		(0.1	)		(0.6	)
Foreign currency translation adjustments		(0.2	)		0.5			(0.2	)		-			-			-
Balance at December 31	$	24.0		$	42.0		$	51.4		$	8.7		$	19.1		$	20.9

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, 2011, 2010 and 2009, accrued interest related to unrecognized tax benefits for Great Plains Energy was $5.7 million, $6.7 million and $5.9 million, respectively. Amounts accrued for penalties with respect to unrecognized tax benefits was $1.1 million at December 31, 2011, 2010 and 2009. In 2011, Great Plains Energy recognized a decrease of $0.9 million of interest expense related to unrecognized tax benefits. In 2010 and 2009, Great Plains Energy recognized an increase of interest expense related to unrecognized tax benefits of $0.5 million and $1.4 million, respectively.

KCP&L had accrued interest related to unrecognized tax benefits of $0.2 million, $1.4 million and $1.7 million, at December 31, 2011, 2010 and 2009, respectively. Amounts accrued for penalties with respect to unrecognized tax benefits for KCP&L are insignificant. In 2011 and 2010, KCP&L recognized a reduction of $1.2 million and $0.3 million of interest expense, respectively.

The IRS is currently auditing Great Plains Energy and its subsidiaries for the 2009-2010 tax years. The Company estimates that it is reasonably possible that $4.7 million for Great Plains Energy and $0.2 million for KCP&L of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities.

- Definition

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.

+ References

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 08

-Paragraph h

-Article 4

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 109

-Paragraph 136, 172

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

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

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-Name Accounting Standards Codification

-Topic 235

-SubTopic 10

-Section S99

-Paragraph 1

-Subparagraph (SX 210.4-08.(h))

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+ Details

Segments and Related Information

12 Months Ended

Dec. 31, 2011

Segments and Related Information

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 and GMO’s regulated utility operations. Other includes GMO activity other than its regulated utility operations, unallocated corporate charges, consolidating entries and intercompany eliminations. Intercompany eliminations include insignificant amounts of intercompany financing-related activities. The summary of significant accounting policies applies to the reportable segment. Segment performance is evaluated based on net income attributable to Great Plains Energy.

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


	Electric						Great Plains
2011	Utility			Other			Energy
	(millions)
Operating revenues	$	2,318.0		$	-		$	2,318.0
Depreciation and amortization		(273.1	)		-			(273.1	)
Interest charges		(176.9	)		(41.5	)		(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


	Electric						Great Plains
2010	Utility			Other			Energy
	(millions)
Operating revenues	$	2,255.5		$	-		$	2,255.5
Depreciation and amortization		(331.6	)		-			(331.6	)
Interest charges		(143.1	)		(41.7	)		(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						Great Plains
2009	Utility			Other			Energy
	(millions)
Operating revenues	$	1,965.0		$	-		$	1,965.0
Depreciation and amortization		(302.2	)		-			(302.2	)
Interest charges		(151.0	)		(29.9	)		(180.9	)
Income tax (expense) benefit		(63.6	)		34.1			(29.5	)
Discontinued operations		-			(1.5	)		(1.5	)
Net income (loss) attributable to Great Plains Energy		157.8			(7.7	)		150.1


	Electric							Great Plains
	Utility		Other		Eliminations			Energy
2011	(millions)
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
2009
Assets	$	8,765.3	$	152.5	$	(435.0	)	$	8,482.8
Capital expenditures		841.3		-		-			841.3

- Definition

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

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+ Details

Discontinued Operations

12 Months Ended

Dec. 31, 2011

Discontinued Operations [Abstract]

Discontinued Operations

22.	DISCONTINUED OPERATIONS

On June 2, 2008, Great Plains Energy completed the sale of Strategic Energy, LLC, to Direct Energy Services, LLC, a subsidiary of Centrica plc. In 2009, Great Plains Energy had a loss from discontinued operations of Strategic Energy before income taxes of $2.4 million and a loss net of income taxes of $1.5 million relating to gross receipt taxes for periods prior to the sale and the reversal of a reserve that had been established for certain indemnification obligations.

- Definition

The entire disclosure for the facts and circumstances leading to the completed or expected disposal, manner and timing of disposal, the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the segment in which the disposal group was reported, and the classification (whether sold or classified as held for sale) and carrying value of the assets and liabilities comprising the disposal group. Includes all disposal groups, including those classified as components of the entity (discontinued operations).

+ References

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-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 144

-Paragraph 43-48

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-Section 45

-Paragraph 5

-URI http://asc.fasb.org/extlink&oid=6390789&loc=d3e2443-110228

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 205

-SubTopic 20

-Section 50

-Paragraph 2

-URI http://asc.fasb.org/extlink&oid=6360339&loc=d3e1436-107760

+ Details

Jointly Owned Electric Utility Plants

12 Months Ended

Dec. 31, 2011

Jointly Owned Electric Utility Plants [Abstract]

Jointly Owned Electric Utility Plants

23.	JOINTLY-OWNED ELECTRIC UTILITY PLANTS

Great Plains Energy’s and KCP&L’s share of jointly-owned electric utility plants at December 31, 2011, are detailed in the following tables.


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

Utility plant in service	$	1,473.8		$	493.6		$	667.9		$	1,293.0		$	364.4		$	158.4
Accumulated depreciation		776.3			303.1			252.8			270.0			30.4			75.5
Nuclear fuel, net		76.6			-			-			-			-			-
Construction work in progress		39.4			79.1			6.5			5.9			30.2			5.3
2012 accredited capacity-MWs		547			711			620			641		NA				174


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

Utility plant in service	$	1,473.8		$	493.6		$	542.3		$	985.1		$	287.5
Accumulated depreciation		776.3			303.1			207.9			261.3			26.0
Nuclear fuel, net		76.6			-			-			-			-
Construction work in progress		39.4			79.1			2.6			4.4			9.3
2012 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, 2011

Quarterly Operating Results (Unaudited) [Abstract]

Quarterly Operating Results (Unaudited)

24.	QUARTERLY OPERATING RESULTS (UNAUDITED)


	Quarter
Great Plains Energy	1st		2nd		3rd		4th
2011	(millions, except per share amounts)
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
2010
Operating revenue	$	506.9	$	552.0	$	728.8	$	467.8
Operating income		62.0		134.9		243.8		31.6
Net income (loss)		20.3		64.4		132.0		(4.8	)
Net income (loss) attributable to Great Plains Energy		20.3		64.3		132.0		(4.9	)
Basic earnings (loss) per common share		0.15		0.47		0.97		(0.04	)
Diluted earnings (loss) per common share		0.15		0.47		0.96		(0.04	)


	Quarter
KCP&L	1st		2nd		3rd		4th
2011	(millions)
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
2010
Operating revenue	$	335.6	$	372.6	$	486.5	$	322.4
Operating income		40.5		84.7		163.6		22.6
Net income		19.2		48.2		92.6		3.2

Quarterly data is subject to seasonal fluctuations with peak periods occurring in the summer months. In the third and fourth quarters of 2010, Great Plains Energy recorded a $4.0 million and $12.8 million, respectively, pre-tax loss for KCP&L’s and GMO’s combined share of certain Iatan construction costs. In the fourth quarter of 2010, Great Plains Energy recorded an $11.2 million pre-tax impairment loss related to its investments in affordable housing limited partnerships.

- Definition

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.

+ References+ Details

Schedule I Financial Statements of Parent Company

12 Months Ended

Dec. 31, 2011

Schedule I Financial Statements of Parent Company [Abstract]

Schedule I Financial Statements of Parent Company

Schedule I – Parent Company Financial Statements

GREAT PLAINS ENERGY INCORPORATED
Income Statements of Parent Company


Year Ended December 31	2011			2010			2009
Operating Expenses	(millions, except per share amounts)
Selling, general and administrative	$	0.8		$	1.2		$	8.8
Maintenance		-			-			0.2
General taxes		0.9			0.9			1.1
Total		1.7			2.1			10.1
Operating loss		(1.7	)		(2.1	)		(10.1	)
Equity in earnings from subsidiaries		200.8			239.3			174.7
Non-operating income		24.7			3.4			-
Interest charges		(66.5	)		(44.7	)		(28.2	)
Income from continuing operations before income taxes		157.3			195.9			136.4
Income tax benefit		17.1			15.8			15.2
Income from continuing operations		174.4			211.7			151.6
Equity in loss from discontinued subsidiary		-			-			(1.5	)
Net income		174.4			211.7			150.1
Preferred stock dividend requirements		1.6			1.6			1.6
Earnings available for common shareholders	$	172.8		$	210.1		$	148.5

Average number of basic common shares outstanding		135.6			135.1			129.3
Average number of diluted common shares outstanding		138.7			136.9			129.8

Basic earnings (loss) per common share
Continuing operations	$	1.27		$	1.55		$	1.16
Discontinued operations		-			-			(0.01	)
Basic earnings per common share	$	1.27		$	1.55		$	1.15

Diluted earnings (loss) per common share
Continuing operations	$	1.25		$	1.53		$	1.15
Discontinued operations		-			-			(0.01	)
Diluted earnings per common share	$	1.25		$	1.53		$	1.14

Cash dividends per common share	$	0.835		$	0.83		$	0.83

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	2011			2010
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	-		$	0.3
Notes receivable from subsidiaries		0.6			249.4
Money pool receivable		0.9			2.0
Taxes receivable		0.9			7.2
Other		0.6			0.7
Total		3.0			259.6
Investments and Other Assets
Investment in KCP&L		2,045.5			2,005.0
Investments in other subsidiaries		1,377.0			1,360.2
Note receivable from subsidiaries		596.2			-
Deferred income taxes		33.7			7.2
Other		6.4			6.2
Total		4,058.8			3,378.6
Total	$	4,061.8		$	3,638.2

LIABILITIES AND CAPITALIZATION
Current Liabilities
Notes payable	$	22.0		$	9.5
Current maturities of long-term debt		287.5			-
Accounts payable to subsidiaries		31.8			31.1
Accrued taxes		5.1			-
Accrued interest		7.6			6.4
Derivative instruments		-			20.8
Other		2.9			7.1
Total		356.9			74.9
Deferred Credits and Other Liabilities
Other		6.7			1.4
Total		6.7			1.4
Capitalization
Common shareholders' equity
Common stock - 250,000,000 shares authorized without par value
136,406,306 and 136,113,954 shares issued, stated value		2,330.6			2,324.4
Retained earnings		684.7			626.5
Treasury stock - 264,567 and 400,889 shares, at cost		(5.6	)		(8.9	)
Accumulated other comprehensive loss		(49.8	)		(56.1	)
Total		2,959.9			2,885.9
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		699.3			637.0
Total		3,698.2			3,561.9
Commitments and Contingencies
Total	$	4,061.8		$	3,638.2

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	2011			2010			2009
Cash Flows from Operating Activities	(millions)
Net income	$	174.4		$	211.7		$	150.1
Adjustments to reconcile income to net cash from operating activities:
Amortization		11.2			3.9			1.9
Deferred income taxes, net		(18.6	)		13.9			(6.1	)
Equity in earnings from subsidiaries		(200.8	)		(239.3	)		(174.7	)
Equity in (earnings) loss from discontinued subsidiary		-			-			1.5
Cash flows affected by changes in:
Accounts receivable from subsidiaries		-			(2.6	)		3.7
Taxes receivable		6.3			-			4.8
Accounts payable to subsidiaries		(0.3	)		2.2			0.2
Other accounts payable		-			(0.1	)		0.1
Accrued taxes		5.2			-			-
Accrued interest		1.2			2.7			1.4
Cash dividends from subsidiaries		148.0			138.6			94.0
Interest hedge settlement		(26.1	)		(6.9	)		-
Other		2.1			(0.9	)		8.8
Net cash from operating activities		102.6			123.2			85.7
Cash Flows from Investing Activities
Equity contributions to subsidiaries		-			-			(455.0	)
Intercompany lending		(347.4	)		(248.8	)		-
Net money pool lending		1.1			(1.1	)		(0.9	)
Net cash from investing activities		(346.3	)		(249.9	)		(455.9	)
Cash Flows from Financing Activities
Issuance of common stock		5.9			6.2			219.9
Issuance of long-term debt		349.7			249.9			287.5
Issuance fees		(3.2	)		(3.2	)		(18.8	)
Net change in short-term borrowings		12.5			(10.5	)		(10.0	)
Dividends paid		(115.1	)		(114.2	)		(110.5	)
Other financing activities		(6.4	)		(7.3	)		(3.8	)
Net cash from financing activities		243.4			120.9			364.3
Net Change in Cash and Cash Equivalents		(0.3	)		(5.8	)		(5.9	)
Cash and Cash Equivalents at Beginning of Year		0.3			6.1			12.0
Cash and Cash Equivalents at End of Year	$	-		$	0.3		$	6.1

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

GREAT PLAINS ENERGY INCORPORATED

Statements of Common Shareholders’ Equity of Parent Company

Statements of Comprehensive Income of Parent Company

Incorporated by reference is Great Plains Energy Consolidated Statements of Common Shareholders’ Equity and Consolidated Statements of Comprehensive Income.

- Definition

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.

+ References+ Details

Schedule II Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2011

Schedule II Valuation and Qualifying Accounts [Abstract]

Schedule II Valuation and Qualifying Accounts

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.

Schedule II – Valuation and Qualifying Accounts and Reserves


Great Plains Energy Incorporated
Valuation and Qualifying Accounts
Years Ended December 31, 2011, 2010 and 2009

				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, 2011		(millions)
	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
Year Ended December 31, 2009
	Allowance for uncollectible accounts	$	6.8	$	8.7		$	6.0	(a)	$	14.4	(b)	$	7.1
	Legal reserves		10.2		2.6			-			7.7	(c)		5.1
	Environmental reserves		0.5		2.0			-			0.1			2.4
	Tax valuation allowance		75.8		57.0			-			103.0	(d)		29.8
(a)	Recoveries.
(b)	Uncollectible accounts charged off.
(c)	Payment of claims.
(d)	Reversal of tax valuation allowance.

Kansas City Power & Light Company
Valuation and Qualifying Accounts
Years Ended December 31, 2011, 2010 and 2009

				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, 2011		(millions)
	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
Year Ended December 31, 2009
	Allowance for uncollectible accounts	$	1.2	$	5.5	$	3.9	(a)	$	8.9	(b)	$	1.7
	Legal reserves		2.4		1.2		-			1.3	(c)		2.3
	Environmental reserves		0.3		-		-			-			0.3
(a)	Recoveries.
(b)	Uncollectible accounts charged off.
(c)	Payment of claims.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Organization

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

Cash and Cash Equivalents

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

Funds on Deposit

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

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	2011		2010
Utility Plant, at original cost	(millions)
Generation (20 - 60 years)	$	6,594.0	$	6,369.4
Transmission (15 - 70 years)		734.8		716.9
Distribution (8 - 66 years)		2,921.1		2,813.4
General (5 - 50 years)		674.9		637.2
Total (a)	$	10,924.8	$	10,536.9
(a) Includes $105.5 million and $103.0 million at December 31,
2011 and 2010, respectively, of land and other assets that
are not depreciated.

KCP&L
December 31	2011		2010
Utility Plant, at original cost	(millions)
Generation (20 - 60 years)	$	5,078.1	$	4,886.2
Transmission (15 - 70 years)		412.9		408.7
Distribution (8 - 55 years)		1,840.2		1,776.4
General (5 - 50 years)		498.1		469.6
Total (a)	$	7,829.3	$	7,540.9
(a) Includes $59.8 million and $59.9 million at December 31,
2011 and 2010, respectively, of land and other assets that
are not depreciated.

Depreciation and Amortization

Nuclear Plant Decommissioning Costs

Deferred Refueling Outage Costs

Regulatory Matters

Revenue Recognition

Allowance for Doubtful Accounts

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

Income Taxes

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

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


	2011			2010		2009
Income	(millions, except per share amounts)
Income from continuing operations	$	174.2		$	211.9	$	151.9
Less: net income (loss) attributable to noncontrolling interest		(0.2	)		0.2		0.3
Less: preferred stock dividend requirements		1.6			1.6		1.6
Income from continuing operations available for common shareholders	$	172.8		$	210.1	$	150.0
Common Shares Outstanding
Average number of common shares outstanding		135.6			135.1		129.3
Add: effect of dilutive securities		3.1			1.8		0.5
Diluted average number of common shares outstanding		138.7			136.9		129.8
Basic EPS from continuing operations	$	1.27		$	1.55	$	1.16
Diluted EPS from continuing operations	$	1.25		$	1.53	$	1.15

The computation of diluted EPS for 2011 excludes anti-dilutive shares consisting of 50,897 performance shares, 43,641 restricted stock shares and 6,000 stock options.

The computation of diluted EPS for 2010 excludes anti-dilutive shares consisting of 340,690 performance shares, 251,526 restricted stock shares and 196,137 stock options.

The computation of diluted EPS for 2009 excludes anti-dilutive shares consisting of 150,895 performance shares, 438,281 restricted stock shares and 231,670 stock options.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Utility plant schedule

Great Plains Energy
December 31	2011		2010
Utility Plant, at original cost	(millions)
Generation (20 - 60 years)	$	6,594.0	$	6,369.4
Transmission (15 - 70 years)		734.8		716.9
Distribution (8 - 66 years)		2,921.1		2,813.4
General (5 - 50 years)		674.9		637.2
Total (a)	$	10,924.8	$	10,536.9
(a) Includes $105.5 million and $103.0 million at December 31,
2011 and 2010, respectively, of land and other assets that
are not depreciated.

KCP&L
December 31	2011		2010
Utility Plant, at original cost	(millions)
Generation (20 - 60 years)	$	5,078.1	$	4,886.2
Transmission (15 - 70 years)		412.9		408.7
Distribution (8 - 55 years)		1,840.2		1,776.4
General (5 - 50 years)		498.1		469.6
Total (a)	$	7,829.3	$	7,540.9
(a) Includes $59.8 million and $59.9 million at December 31,
2011 and 2010, respectively, of land and other assets that
are not depreciated.

Basic and diluted earnings per share


	2011			2010		2009
Income	(millions, except per share amounts)
Income from continuing operations	$	174.2		$	211.9	$	151.9
Less: net income (loss) attributable to noncontrolling interest		(0.2	)		0.2		0.3
Less: preferred stock dividend requirements		1.6			1.6		1.6
Income from continuing operations available for common shareholders	$	172.8		$	210.1	$	150.0
Common Shares Outstanding
Average number of common shares outstanding		135.6			135.1		129.3
Add: effect of dilutive securities		3.1			1.8		0.5
Diluted average number of common shares outstanding		138.7			136.9		129.8
Basic EPS from continuing operations	$	1.27		$	1.55	$	1.16
Diluted EPS from continuing operations	$	1.25		$	1.53	$	1.15

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Elements [Abstract]

Supplemental cash flow information

Great Plains Energy Other Operating Activities
Year Ended December 31	2011			2010			2009
Cash flows affected by changes in:	(millions)
Receivables	$	3.6		$	(12.6	)	$	7.9
Accounts receivable pledged as collateral		-			(95.0	)		-
Fuel inventories		(3.9	)		(0.1	)		2.0
Materials and supplies		(7.5	)		(11.5	)		(22.0	)
Accounts payable		5.7			12.8			(70.9	)
Accrued taxes		1.4			6.7			42.2
Accrued interest		1.5			2.9			2.9
Deferred refueling outage costs		(17.9	)		9.9			(7.1	)
Fuel adjustment clauses		(1.7	)		2.7			7.8
Pension and post-retirement benefit obligations		(56.0	)		(10.2	)		18.4
Allowance for equity funds used during construction		(1.0	)		(26.0	)		(39.6	)
Write down of affordable housing investments		-			11.2			-
Interest rate hedge settlements		(26.1	)		(6.9	)		(79.1	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		2.3			16.8			-
Uncertain tax positions		(20.8	)		(6.1	)		10.7
Other		(27.1	)		(28.3	)		9.0
Total other operating activities	$	(147.5	)	$	(133.7	)	$	(117.8	)
Cash paid during the period:
Interest	$	254.4		$	237.7		$	211.9
Income taxes	$	2.8		$	0.9		$	5.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	39.7		$	44.9		$	82.8

KCP&L Other Operating Activities
Year Ended December 31	2011			2010			2009
Cash flows affected by changes in:	(millions)
Receivables	$	(20.2	)	$	(4.1	)	$	(7.6	)
Accounts receivable pledged as collateral		-			(95.0	)		-
Fuel inventories		(14.1	)		0.7			6.1
Materials and supplies		(6.7	)		(9.6	)		(16.5	)
Accounts payable		11.0			0.8			(54.3	)
Accrued taxes		2.7			(15.7	)		51.8
Accrued interest		3.8			(0.5	)		8.6
Deferred refueling outage costs		(17.9	)		9.9			(7.1	)
Pension and post-retirement benefit obligations		(45.6	)		7.9			39.3
Allowance for equity funds used during construction		(0.7	)		(21.9	)		(30.6	)
Kansas Energy Cost Adjustment		(5.8	)		(8.8	)		2.2
Iatan Nos. 1 and 2 impact of disallowed construction costs		1.5			13.0			-
Interest rate hedge settlements		-			-			(79.1	)
Uncertain tax positions		(10.4	)		(1.8	)		3.3
Other		(15.9	)		(2.7	)		17.8
Total other operating activities	$	(118.3	)	$	(127.8	)	$	(66.1	)
Cash paid during the period:
Interest	$	111.3		$	101.1		$	77.2
Income taxes	$	0.1		$	18.2		$	31.9
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	32.0		$	37.4		$	75.5

Receivables (Tables)

12 Months Ended

Dec. 31, 2011

Receivables [Abstract]

Schedule of receivables


	December 31
	2011			2010
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	69.8		$	62.0
Customer accounts receivable - unbilled		82.4			82.3
Allowance for doubtful accounts		(2.5	)		(2.7	)
Other receivables		81.5			100.1
Total	$	231.2		$	241.7
KCP&L
Customer accounts receivable - billed	$	16.4		$	6.5
Customer accounts receivable - unbilled		50.0			50.1
Allowance for doubtful accounts		(1.4	)		(1.5	)
Intercompany receivables		38.7			43.2
Other receivables		69.2			71.1
Total	$	172.9		$	169.4

Schedule of accounts receivable sold


				Receivables			Consolidated
2011	KCP&L			Company			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		2.6			(2.6	)		-
Fees to outside investor		-			(1.2	)		(1.2	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(1,412.4	)		1,412.4			-
Cash paid to KCP&L for receivables purchased		1,394.7			(1,394.7	)		-
Servicing fees		2.6			(2.6	)		-
Interest on intercompany note		0.5			(0.5	)		-


				Receivables			Consolidated
2010	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,341.0	)	$	1,341.0		$	-
Gain (loss) on sale of accounts receivable (a)		(17.0	)		16.8			(0.2	)
Servicing fees		3.2			(3.2	)		-
Fees to outside investor		-			(1.2	)		(1.2	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(1,337.4	)		1,337.4			-
Cash paid to KCP&L for receivables purchased		1,320.7			(1,320.7	)		-
Servicing fees		3.2			(3.2	)		-
Interest on intercompany note		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, 2011

Nuclear Plant [Abstract]

Changes in nuclear decommissioning trust fund


December 31	2011			2010
Decommissioning Trust	(millions)
Beginning balance January 1	$	129.2		$	112.5
Contributions		3.4			3.7
Earned income, net of fees		4.8			2.0
Net realized gains		0.3			6.7
Net unrealized gains (losses)		(2.4	)		4.3
Ending balance	$	135.3		$	129.2

Detail of assets held in nuclear decommissioning trust fund


	December 31
	2011									2010
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	76.5	$	12.3	$	(4.5	)	$	84.3	$	73.4	$	13.1	$	(1.0	)	$	85.5
Debt securities		44.2		4.5		(0.1	)		48.6		38.1		2.6		(0.1	)		40.6
Other		2.4		-		-			2.4		3.1		-		-			3.1
Total	$	123.1	$	16.8	$	(4.6	)	$	135.3	$	114.6	$	15.7	$	(1.1	)	$	129.2

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


	2011			2010			2009
	(millions)
Realized gains	$	1.0		$	7.3		$	2.8
Realized losses		(0.7	)		(0.6	)		(8.3	)

Nuclear Plant Decommissioning Costs


		Total		KCP&L's
		Station		47% Share
		(millions)
Current cost of decommissioning (in 2011 dollars)		$	630	$	296
Future cost of decommissioning (in 2045-2053 dollars) (a)			2,455		1,154

Annual escalation factor		3.73%
Annual return on trust assets (b)		6.89%
(a)	Total future cost over an eight year decommissioning period.
(b)	The 6.89% rate of return is through 2025. The rate then systematically decreases
	through 2053 to 1.81% based on the assumption that the fund's investment mix
	will become increasingly more conservative as the decommissioning period
	approaches.

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Regulatory Matters [Abstract]

Regulatory assets


							Great
December 31, 2011	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	119.6		$	24.6		$	144.2
Loss on reacquired debt		9.1	(a)		2.7	(a)		11.8
Cost of removal		4.6			-			4.6
Asset retirement obligations		31.4			13.8			45.2
Pension and post-retirement costs		466.4	(b)		122.0	(b)		588.4
Deferred customer programs		48.2	(c)		20.6			68.8
Rate case expenses		9.6	(d)		3.8	(d)		13.4
Skill set realignment costs		3.4	(e)		-			3.4
Fuel adjustment clauses		14.0	(d)		36.4	(d)		50.4
Acquisition transition costs		24.7	(f )		20.2	(f )		44.9
Derivative instruments		-			7.6	(g)		7.6
Iatan No. 1 and Common facilities depreciation and carrying costs		16.4			6.1			22.5
Iatan No. 2 construction accounting costs		27.9			15.4			43.3
Kansas property tax surcharge		3.7	(d)		-			3.7
Other		1.7	(h)		4.3	(h)		6.0
Total	$	780.7		$	277.5		$	1,058.2


					Great
December 31, 2010	KCP&L		GMO		Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	117.2	$	25.3	$	142.5
Loss on reacquired debt		5.0		0.7		5.7
Cost of removal		8.5		-		8.5
Asset retirement obligations		27.5		12.8		40.3
Pension and post-retirement costs		386.1		106.7		492.8
Deferred customer programs		44.7		15.6		60.3
Rate case expenses		12.3		3.3		15.6
Skill set realignment costs		4.8		-		4.8
Fuel adjustment clauses		8.4		37.1		45.5
Acquisition transition costs		29.3		22.5		51.8
Derivative instruments		-		3.1		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		15.1		4.3		19.4
Iatan No. 2 construction accounting costs		17.2		6.5		23.7
Other		3.5		6.5		10.0
Total	$	679.6	$	244.4	$	924.0

Regulatory liabilities

Regulatory Liabilities
Emission allowances	$	82.0	$	0.2		$	82.2
Asset retirement obligations		49.3		-			49.3
Pension		0.7		40.8			41.5
Cost of removal		-		61.9	(i)		61.9
Other		10.8		22.8			33.6
Total	$	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)

accounting method differences not included in rate base that will be eliminated over the life of the pension plans.

(c)	$10.4 million not included in rate base and amortized over various periods.

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

(e)	$2.4 million not included in rate base and amortized through 2017.

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

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

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

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

Regulatory Liabilities
Emission allowances	$	85.9	$	0.5	$	86.4
Asset retirement obligations		44.9		-		44.9
Pension		-		37.1		37.1
Cost of removal		-		62.8		62.8
Other		10.5		16.5		27.0
Total	$	141.3	$	116.9	$	258.2

- Definition

Tabular disclosure of assets that are created when regulatory agencies permit public utilities to defer certain costs included in rate-setting to the balance sheet.

+ References+ Details

Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2011

Goodwill and Intangible Assets [Abstract]

Intangible Assets included in Electric Utility Plant


	December 31, 2011					December 31, 2010
	Gross Carrying		Accumulated			Gross Carrying		Accumulated
	Amount		Amortization			Amount		Amortization
KCP&L	(millions)
Computer software	$	171.7	$	(129.9	)	$	168.2	$	(118.0	)
Asset improvements		11.7		(0.6	)		5.8		-

Great Plains Energy
Computer software	$	202.5	$	(143.5	)	$	201.1	$	(137.3	)
Asset improvements		27.0		(3.7	)		27.9		(4.4	)

Amortization expense

Schedule of future amortization expense for intangible assets


	2012		2013		2014		2015		2016
	(millions)
Great Plains Energy	$	13.9	$	11.2	$	8.1	$	6.0	$	4.7
KCP&L		11.0		8.3		5.3		3.4		2.1

- Definition

Tabular disclosure of amortizable intangibles assets, in total and by major class, including the gross carrying amount and accumulated amortization. A major class is composed of intangible assets that can be grouped together because they are similar, either by their nature or by their use in the operations of a company.

+ References+ Details

Pension Plans and Other Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Pension Plans and Other Employee Benefits [Abstract]

Funded status of plans


	Pension Benefits						Other Benefits
	2011			2010			2011			2010
Change in projected benefit obligation (PBO)	(millions)
PBO at beginning of year	$	911.4		$	836.3		$	143.6		$	148.9
Service cost		31.1			30.3			3.1			3.8
Interest cost		49.6			49.3			7.8			8.8
Contribution by participants		-			-			6.6			5.6
Amendments		-			0.5			-			-
Actuarial (gain) loss		83.2			55.1			7.4			(12.5	)
Benefits paid		(54.7	)		(60.1	)		(14.3	)		(11.0	)
Settlements		(40.0	)		-			-			-
PBO at end of plan year	$	980.6		$	911.4		$	154.2		$	143.6
Change in plan assets
Fair value of plan assets at beginning of year	$	557.6		$	488.2		$	65.8		$	52.0
Actual return on plan assets		(3.7	)		62.7			2.5			0.5
Contributions by employer and participants		128.8			64.5			23.0			23.9
Benefits paid		(91.6	)		(57.8	)		(13.9	)		(10.6	)
Fair value of plan assets at end of plan year	$	591.1		$	557.6		$	77.4		$	65.8
Funded status at end of year	$	(389.5	)	$	(353.8	)	$	(76.8	)	$	(77.8	)
Amounts recognized in the consolidated balance sheets
Current pension and other post-retirement liability	$	(3.5	)	$	(3.1	)	$	(0.9	)	$	(1.0	)
Noncurrent pension liability and other post-retirement liability		(386.0	)		(350.7	)		(75.9	)		(76.8	)
Net amount recognized before regulatory treatment		(389.5	)		(353.8	)		(76.8	)		(77.8	)
Accumulated OCI or regulatory asset/liability		491.8			403.2			52.5			54.8
Net amount recognized at December 31	$	102.3		$	49.4		$	(24.3	)	$	(23.0	)
Amounts in accumulated OCI or regulatory asset/liability
not yet recognized as a component of net periodic benefit cost:
Actuarial loss	$	295.6		$	219.5		$	15.7		$	8.5
Prior service cost		10.7			15.3			36.9			44.1
Transition obligation		-			-			1.7			3.0
Other		185.5			168.4			(1.8	)		(0.8	)
Net amount recognized at December 31	$	491.8		$	403.2		$	52.5		$	54.8

Components of net periodic benefit costs


	Pension Benefits									Other Benefits
	2011			2010			2009			2011			2010			2009
Components of net periodic benefit costs	(millions)
Service cost	$	31.1		$	30.3		$	29.1		$	3.1		$	3.8		$	4.1
Interest cost		49.6			49.3			47.3			7.8			8.8			8.3
Expected return on plan assets		(38.0	)		(36.6	)		(32.4	)		(1.8	)		(2.1	)		(1.6	)
Prior service cost		4.6			4.6			4.2			7.2			7.2			6.9
Recognized net actuarial (gain) loss		38.7			37.4			36.3			(0.5	)		(0.1	)		(0.4	)
Transition obligation		-			0.1			0.1			1.3			1.3			1.3
Settlement charges		10.1			-			0.1			-			-			-
Net periodic benefit costs before
regulatory adjustment		96.1			85.1			84.7			17.1			18.9			18.6
Regulatory adjustment		(27.9	)		(32.3	)		(28.4	)		1.1			-			(0.3	)
Net periodic benefit costs		68.2			52.8			56.3			18.2			18.9			18.3
Other changes in plan assets and benefit
obligations recognized in OCI or
regulatory assets/liabilities
Current year net (gain) loss		114.8			29.1			(9.2	)		6.7			(10.9	)		(0.2	)
Amortization of gain (loss)		(38.7	)		(37.4	)		(36.3	)		0.5			0.1			0.4
Prior service cost		-			0.5			5.7			-			-			24.8
Amortization of prior service cost		(4.6	)		(4.6	)		(4.2	)		(7.2	)		(7.2	)		(6.9	)
Transition obligation		-			-			-			-			-			1.2
Amortization of transition obligation		-			(0.1	)		(0.1	)		(1.3	)		(1.3	)		(1.3	)
Other regulatory activity		17.1			29.5			10.1			(1.0	)		0.1			(3.1	)
Total recognized in OCI or regulatory asset/liability		88.6			17.0			(34.0	)		(2.3	)		(19.2	)		14.9
Total recognized in net periodic benefit costs
and OCI or regulatory asset/liability	$	156.8		$	69.8		$	22.3		$	15.9		$	(0.3	)	$	33.2

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


	2011		2010
Pension plans with the ABO in excess of plan assets	(millions)
Projected benefit obligation	$	980.6	$	911.4
Accumulated benefit obligation		852.6		808.8
Fair value of plan assets		591.1		557.6
Pension plans with plan assets in excess of the ABO
Projected benefit obligation	$	-	$	-
Accumulated benefit obligation		-		-
Fair value of plan assets		-		-

Weighted average assumptions


Weighted-average assumptions used to determine	Pension Benefits						Other Benefits
the benefit obligation at plan year-end	2011			2010			2011			2010
Discount rate		5.01	%		5.54	%		5.03	%		5.50	%
Rate of compensation increase		4.08	%		4.08	%		4.07	%		4.06	%


Weighted-average assumptions used to determine	Pension Benefits						Other Benefits
net costs for years ended December 31	2011			2010			2011			2010
Discount rate		5.54	%		5.92	%		5.50	%		5.87	%
Expected long-term return on plan assets		7.29	%		8.00	%		2.83	% *		4.25	% *
Rate of compensation increase		4.08	%		4.26	%		4.06	%		4.25	%
* after tax

Future benefit payments


	Pension		Other
	Benefits		Benefits
	(millions)
2012	$	76.6	$	8.6
2013		65.5		8.1
2014		67.3		8.3
2015		66.5		8.2
2016		70.1		8.4
2017-2021		381.0		46.3

Fair value of plan assets


			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


				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
	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 and cash equivalents - money market funds		18.0
	Total Other Post-Retirement Benefit Plans	$	77.4

(a)	This category is comprised of $12.7 million of corporate bonds, $0.6 million of collateralized mortgage obligations and $1.5 million
	of other asset-backed securities.


				Fair Value Measurements Using
Description		December 31 2010		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)	$	158.5	$	90.5	$	68.0	$	-
	International(b)		122.4		39.4		83.0		-
	Limited partnerships		0.1		-		-		0.1
	Real estate(c)		30.3		-		-		30.3
	Commodities(d)		37.0		-		37.0		-
	Fixed income securities
	Fixed income funds(e)		148.7		23.0		125.7		-
	U.S. Treasury		1.8		1.8		-		-
	U.S. Agency, state and local obligations		14.8		-		14.8		-
	U.S. corporate bonds(f)		24.2				24.2		-
	Foreign corporate bonds		1.5		-		1.5		-
	Hedge funds(g)		8.4		-		-		8.4
	Total	$	547.7	$	154.7	$	354.2	$	38.8
	Cash equivalents - money market funds		9.9
	Total Pension Plans	$	557.6

(a)	At December 31, 2011 and 2010, this category is comprised of $94.6 million and $90.5 million, respectively, of traded mutual funds valued at daily listed prices and $61.7 million and $68.0 million, respectively,
	of institutional common/collective trust funds valued at daily Net Asset Values (NAV) per share.
(b)	At December 31, 2011 and 2010, this category is comprised of $40.9 million and $39.4 million, respectively, of traded mutual funds valued at daily listed prices and $76.1 million and $83.0 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, 2011 and 2010, this category is comprised of $34.2 million and $23.0 million, respectively, of traded mutual funds valued at daily listed prices and $132.3 million and $125.7 million, respectively, of institutional common/collective trust funds valued at daily NAV per share.
(f)	At December 31, 2011 and 2010, this category is comprised of $18.1 million and $13.9 million, respectively, of corporate bonds, $6.1 million and $8.0 million, respectively, of collateralized mortgage obligations
	and $2.4 million and $2.3 million, respectively, of other asset-backed securities.
(g)	This category is comprised of closely-held limited partnerships valued at NAV on a quarterly basis.


				Fair Value Measurements Using
Description		December 31 2010		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
	Fixed income
	U.S. Treasury	$	12.1	$	12.1	$	-	$	-
	U.S. Agency, state and local obligations		22.2		-		22.2		-
	U.S. corporate bonds (a)		11.4		-		11.4		-
	Foreign corporate bonds		1.0				1.0
	Mutual funds		0.1		0.1		-		-
	Total	$	46.8	$	12.2	$	34.6	$	-
	Cash and cash equivalents - money market funds		19.0
	Total Other Post-Retirement Benefit Plans	$	65.8

(a)	This category is comprised of $9.2 million of corporate bonds, $0.9 million of collateralized mortgage obligations and $1.3 million
	of other asset-backed securities.

Fair value of assets using significant unobservable inputs


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Real		Hedge			Limited
Description	Estate		Funds			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
Relating to assets sold		-		-			-			-
Purchase, sales, and settlements		0.5		14.6			-			15.1
Transfers in and/or out of Level 3		-		-			-			-
Balance December 31, 2011	$	34.7	$	21.7		$	-		$	56.4


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Real		Hedge			Limited
Description	Estate		Funds			Partnerships		Total
	(millions)
Balance January 1, 2010	$	26.8	$	2.4		$	0.1	$	29.3
Actual return on plan assets
Relating to assets still held		2.5		(0.2	)		-		2.3
Relating to assets sold		-		(0.7	)		-		(0.7	)
Purchase, sales, and settlements		1.0		6.9			-		7.9
Transfers in and/or out of Level 3		-		-			-		-
Balance December 31, 2010	$	30.3	$	8.4		$	0.1	$	38.8

Effective of one percent change in health care costs


	Increase		Decrease
	(millions)
Effect on total service and interest component	$	0.5	$	(0.4	)
Effect on post-retirement benefit obligation		4.0		(3.5	)

Equity Compensation (Tables)

12 Months Ended

Dec. 31, 2011

Equity Compensation [Abstract]

Equity compensation expense and associated income tax benefits


	2011		2010		2009
Great Plains Energy	(millions)
Compensation expense	$	5.2	$	4.3	$	6.3
Income tax benefits		1.9		1.0		1.6
KCP&L
Compensation expense		3.5		3.0		4.3
Income tax benefits		1.3		0.5		0.8

Performance share activity


	Performance			Grant Date
	Shares			Fair Value*
Beginning balance		431,784		$	18.01
Granted		140,128			26.15
Earned		(68,258	)		11.04
Forfeited		(61,612	)		22.38
Ending balance		442,042			21.06
* weighted-average

Restricted stock activity


	Nonvested			Grant Date
	Restricted Stock			Fair Value*
Beginning balance		406,657		$	16.23
Granted and issued		182,385			19.03
Vested		(149,688	)		17.29
Forfeited		(53,171	)		17.25
Ending balance		386,183			17.06
* weighted-average

Stock option activity


				Exercise
Stock Options	Shares			Price*
Beginning balance		198,781		$	32.51
Forfeited or expired		(189,428	)		32.83
Outstanding and exercisable at December 31, 2011		9,353			25.91
* weighted-average

Director deferred share units activity


	Share		Grant Date
	Units		Fair Value*
Beginning balance		39,063	$	20.04
Issued		15,168		20.57
Ending balance		54,231		20.19
* weighted-average

- Definition

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.

+ References+ Details

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Debt Disclosure [Abstract]

Long-term debt


			December 31
	Year Due		2011			2010
KCP&L			(millions)
General Mortgage Bonds
4.87% EIRR bonds(a)(b)		2012-2035	$	119.3		$	158.8
7.15% Series 2009A (8.59% rate)(c)		2019		400.0			400.0
4.65% EIRR Series 2005		2035		50.0			50.0
EIRR Series 2007A-1(d)		2035		-			63.3
EIRR Series 2007A-2(d)		2035		-			10.0
5.375% EIRR Series 2007B		2035		73.2			73.2
Senior Notes
6.50% Series				-			150.0
5.85% Series (5.72% rate)(c)		2017		250.0			250.0
6.375% Series (7.49% rate)(c)		2018		350.0			350.0
6.05% Series (5.78% rate)(c)		2035		250.0			250.0
5.30% Series		2041		400.0			-
EIRR bonds 4.90% Series 2008		2038		23.4			23.4
Other		2012-2018		2.9			3.3
Current maturities				(12.7	)		(150.3	)
Unamortized discount				(4.2	)		(2.0	)
Total KCP&L excluding current maturities				1,901.9			1,629.7
Other Great Plains Energy
GMO First Mortgage Bonds 9.44% Series		2012-2021		11.2			12.4
GMO Pollution Control Bonds
5.85% SJLP Pollution Control		2013		5.6			5.6
0.164% Wamego Series 1996(e)		2026		7.3			7.3
0.353% State Environmental 1993(e)		2028		5.0			5.0
GMO Senior Notes
7.95% Series				-			137.3
7.75% Series				-			197.0
11.875% Series		2012		500.0			500.0
8.27% Series		2021		80.9			80.9
Fair Value Adjustment				16.3			49.9
GMO Medium Term Notes
7.16% Series		2013		6.0			6.0
7.33% Series		2023		3.0			3.0
7.17% Series		2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(c)		2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(c)		2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes		2012		287.5			287.5
Great Plains Energy 4.85% Senior Notes (7.34% rate)(c)		2021		350.0			-
Current maturities				(788.7	)		(335.4	)
Unamortized discount				(0.7	)		(0.5	)
Total Great Plains Energy excluding current maturities			$	2,742.3		$	2,942.7
(a) Weighted-average interest rates at December 31, 2011
(b) December 31, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by KCP&L
(c) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(d) December 31, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have
been repurchased and are held by KCP&L
(e) Variable rate

Amortization of debt expense


	2011		2010		2009
	(millions)
KCP&L	$	3.6	$	2.8	$	2.0
Other Great Plains Energy		4.5		3.6		2.4
Total Great Plains Energy	$	8.1	$	6.4	$	4.4

Schedule of settlement rate by applicable market value


Applicable		Settlement rate	Market value
market value		(in common shares)	per Equity Unit (a)
$16.80 or greater		2.9762 to 1	Greater than $50 per Equity Unit

$16.80 to $14.00		$50 divided by the applicable	Equal to $50 per Equity Unit
		market value to 1

$14.00 or less		3.5714 to 1	Less than $50 per Equity Unit
(a)	Assumes that the market price of the Company's common stock on June 15, 2012,
	is the same as the applicable market value.

Scheduled maturities


	2012		2013		2014		2015		2016
	(millions)
Great Plains Energy $		801.4	$	263.1	$	1.5	$	15.5	$	1.6
KCP&L		12.7		0.4		0.4		14.4		0.4

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Expenses related to lease commitments


	2011		2010		2009
	(millions)
Great Plains Energy	$	20.9	$	17.2	$	23.4
KCP&L		17.0		13.2		19.3

Lease and purchase commitments


Great Plains Energy
	2012		2013		2014		2015		2016		After 2016		Total
Lease commitments	(millions)
Operating lease	$	19.7	$	16.3	$	14.8	$	13.6	$	9.8	$	119.2	$	193.4
Capital lease		0.4		0.4		0.4		0.4		0.4		4.7		6.7
Purchase commitments
Fuel		397.4		360.5		202.0		103.9		83.2		94.1		1,241.1
Power		8.5		29.2		34.8		34.8		34.8		686.3		828.4
Capacity		13.4		12.4		4.5		4.2		2.4		-		36.9
La Cygne environmental project		376.6		300.2		125.4		5.5		-		-		807.7
Non-regulated natural gas
transportation		2.8		3.6		3.6		3.6		3.6		0.9		18.1
Other		54.4		101.7		21.0		25.4		3.7		49.8		256.0
Total contractual commitments	$	873.2	$	824.3	$	406.5	$	191.4	$	137.9	$	955.0	$	3,388.3


KCP&L
	2012		2013		2014		2015		2016		After 2016		Total
Lease commitments	(millions)
Operating lease	$	16.0	$	14.0	$	13.0	$	12.2	$	9.7	$	119.2	$	184.1
Capital lease		0.2		0.2		0.2		0.2		0.2		2.6		3.6
Purchase commitments
Fuel		336.0		298.8		169.1		91.5		79.1		94.1		1,068.6
Power		8.5		29.2		34.8		34.8		34.8		499.1		641.2
Capacity		4.7		3.7		2.9		3.0		1.2		-		15.5
La Cygne environmental project		376.6		300.2		125.4		5.5		-		-		807.7
Other		40.3		100.9		20.2		24.6		2.9		39.5		228.4
Total contractual commitments	$	782.3	$	747.0	$	365.6	$	171.8	$	127.9	$	754.5	$	2,949.1

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Instruments [Abstract]

Values of open positions for derivative instruments


	December 31					December 31
	2011					2010
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	2.0	$	(0.5	)	$	4.0	$	-
Non-hedging derivatives		23.6		(5.0	)		59.5		(2.5	)
Forward contracts
Non-hedging derivatives		97.3		7.8			202.8		8.9
Option contracts
Non-hedging derivatives		0.4		-			0.2		-
Anticipated debt issuance
Forward starting swaps		-		-			350.0		(20.8	)
KCP&L
Futures contracts
Cash flow hedges		2.0		(0.5	)		4.0		-

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


Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
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

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


KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5

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

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


Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)

	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
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	)

2010
Interest rate contracts	$	(27.1	)	Interest charges	$	(10.1	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		10.8		Income tax benefit		4.0
Total	$	(17.2	)	Total	$	(6.6	)


KCP&L
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)

	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
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	)

2010
Interest rate contracts	$	-		Interest charges	$	(8.8	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		0.3		Income tax benefit		3.6
Total	$	(0.6	)	Total	$	(5.7	)

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


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

2010
Commodity contracts	$	(8.2	)	Fuel	$	(7.2	)
Total	$	(8.2	)	Total	$	(7.2	)

Accumulated other comprehensive income related to cash flow hedges


	Great Plains Energy						KCP&L
	December 31						December 31
	2011			2010			2011			2010
	(millions)
Current assets	$	11.3		$	12.0		$	11.3		$	12.0
Current liabilities		(89.5	)		(101.5	)		(62.5	)		(71.6	)
Noncurrent liabilities		(0.2	)		-			(0.2	)		-
Deferred income taxes		30.5			34.8			20.0			23.2
Total	$	(47.9	)	$	(54.7	)	$	(31.4	)	$	(36.4	)

- Definition

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

+ References+ Details

- Definition

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

+ References+ Details

- Definition

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.

+ References

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 25

-Section 50

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 1A

-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5579245-113959

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 4B

-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5624163-113959

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 4C

-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5624171-113959

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 8

-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41678-113959

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 235

-SubTopic 10

-Section S99

-Paragraph 1

-Subparagraph (SX 210.4-08.(n)(2))

-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 4

-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41638-113959

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 1B

-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5580258-113959

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5579240-113959

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 5

-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41641-113959

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 2

-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41620-113959

+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Fair value of assets and liabilities


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


						Fair Value Measurements Using
Description	December 31 2010		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
Derivative instruments (a)	$	-	$	(0.1	)	$	0.1	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		85.5		-			85.5		-		-
Debt securities
U.S. Treasury		8.9		-			8.9		-		-
U.S. Agency		4.8		-			-		4.8		-
State and local obligations		2.5		-			-		2.5		-
Corporate bonds		23.7		-			-		23.7		-
Foreign governments		0.7		-			-		0.7		-
Other		0.4		-			-		0.4		-
Total nuclear decommissioning trust		126.5		-			94.4		32.1		-
Total		126.5		(0.1	)		94.5		32.1		-
Liabilities
Derivative instruments (a)		-		(0.1	)		0.1		-		-
Total	$	-	$	(0.1	)	$	0.1	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.5	)	$	0.5	$	5.2	$	3.7
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		7.0		-			-		7.0		-
Total SERP rabbi trust		7.2		-			0.2		7.0		-
Total		16.1		(0.5	)		0.7		12.2		3.7
Liabilities
Derivative instruments (a)		20.8		(3.0	)		3.0		20.8		-
Total	$	20.8	$	(3.0	)	$	3.0	$	20.8	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.6	)	$	0.6	$	5.2	$	3.7
Nuclear decommissioning trust (b)		126.5		-			94.4		32.1		-
SERP rabbi trust (c)		7.2		-			0.2		7.0		-
Total		142.6		(0.6	)		95.2		44.3		3.7
Liabilities
Derivative instruments (a)		20.8		(3.1	)		3.1		20.8		-
Total	$	20.8	$	(3.1	)	$	3.1	$	20.8	$	-

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

(b)	Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $3.0 million and $2.7 million at December 31, 2011 and 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(c)	Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $20.3 million and $14.6 million at December 31, 2011 and 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)

Unobservable inputs reconciliation


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other
	Great
	Plains
	Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains
included in non-operating income		10.9
Settlements		(11.5	)
Balance December 31, 2011	$	3.1

Total unrealized losses included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at December 31, 2011	$	(0.2	)


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other
				Great			Great
				Plains			Plains
	KCP&L			Energy			Energy
	State & Local			Derivative
	Obligations			Instruments			Total
	(millions)
Balance January 1, 2010	$	0.2		$	4.1		$	4.3
Total realized/unrealized losses
included in non-operating income		-			(12.5	)		(12.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			12.1			12.1
Balance December 31, 2010	$	-		$	3.7		$	3.7

Total unrealized gains included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at December 31, 2010	$	-		$	0.1		$	0.1

- Definition

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, 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, issuances, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs), by class of asset.

+ References+ Details

Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Taxes [Abstract]

Components of income tax expense (benefit)


Great Plains Energy	2011			2010			2009
Current income taxes	(millions)
Federal	$	2.9		$	(7.4	)	$	(11.1	)
State		(6.0	)		(4.3	)		(0.9	)
Foreign		(0.4	)		0.1			1.3
Total		(3.5	)		(11.6	)		(10.7	)
Deferred income taxes
Federal		90.5			99.8			(13.6	)
State		20.7			24.0			10.0
Total		111.2			123.8			(3.6	)
Noncurrent income taxes
Federal		(18.0	)		(4.8	)		8.3
State		(2.1	)		(1.8	)		1.1
Foreign		(0.6	)		0.5			(1.5	)
Total		(20.7	)		(6.1	)		7.9
Investment tax credit
Deferral		-			(4.2	)		37.2
Amortization		(2.2	)		(2.9	)		(2.2	)
Total		(2.2	)		(7.1	)		35.0
Total income tax expense		84.8			99.0			28.6
Less: taxes on discontinued operations
Current tax benefit		-			-			(1.1	)
Deferred tax expense		-			-			0.2
Income tax expense on continuing operations	$	84.8		$	99.0		$	29.5


KCP&L	2011			2010			2009
Current income taxes	(millions)
Federal	$	1.0		$	5.5		$	41.2
State		(0.6	)		1.1			4.8
Total		0.4			6.6			46.0
Deferred income taxes
Federal		66.0			69.8			(41.7	)
State		14.6			13.4			3.5
Total		80.6			83.2			(38.2	)
Noncurrent income taxes
Federal		(9.3	)		(1.6	)		3.4
State		(1.1	)		(0.3	)		(0.1	)
Total		(10.4	)		(1.9	)		3.3
Investment tax credit
Deferral		-			(4.2	)		37.2
Amortization		(1.5	)		(2.1	)		(1.4	)
Total		(1.5	)		(6.3	)		35.8
Total	$	69.1		$	81.6		$	46.9

Income tax expense (benefit) and effective income tax rates


	Income Tax Expense									Income Tax Rate
Great Plains Energy	2011			2010			2009			2011			2010			2009
	(millions)
Federal statutory income tax	$	90.7		$	108.7		$	63.4			35.0	%		35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		4.0			(5.2	)		(9.9	)		1.5			(1.7	)		(5.5	)
Amortization of investment tax credits		(2.2	)		(2.9	)		(2.2	)		(0.8	)		(0.9	)		(1.2	)
Federal income tax credits		(13.1	)		(12.5	)		(8.0	)		(5.0	)		(4.1	)		(4.4	)
State income taxes		10.5			11.4			7.9			4.0			3.7			4.4
Medicare Part D subsidy legislation		-			2.8			-			-			0.9			-
Changes in uncertain tax positions, net		(4.4	)		0.3			(72.1	)		(1.7	)		0.1			(39.8	)
Valuation allowance		(2.2	)		(2.7	)		55.8			(0.8	)		(0.9	)		30.8
Other		1.5			(0.9	)		(5.4	)		0.5			(0.3	)		(3.0	)
Total	$	84.8		$	99.0		$	29.5			32.7	%		31.8	%		16.3	%


	Income Tax Expense									Income Tax Rate
KCP&L	2011			2010			2009			2011			2010			2009
	(millions)
Federal statutory income tax	$	71.6		$	85.7		$	61.5			35.0	%		35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		3.4			(4.5	)		(7.7	)		1.6			(1.8	)		(4.4	)
Amortization of investment tax credits		(1.5	)		(2.1	)		(1.4	)		(0.7	)		(0.9	)		(0.8	)
Federal income tax credits		(13.0	)		(8.5	)		(7.8	)		(6.3	)		(3.5	)		(4.4	)
State income taxes		8.1			8.9			5.8			3.9			3.6			3.3
Medicare Part D subsidy legislation		-			2.8			-			-			1.1			-
Changes in uncertain tax positions, net		0.3			-			(0.5	)		0.1			-			(0.3	)
Other		0.2			(0.7	)		(3.0	)		0.2			(0.2	)		(1.7	)
Total	$	69.1		$	81.6		$	46.9			33.8	%		33.3	%		26.7	%

Deferred income tax assets and liabilities


	Great Plains Energy						KCP&L
December 31	2011			2010			2011			2010
Current deferred income tax asset (liability)	(millions)
Other	$	7.9		$	14.7		$	(0.1	)	$	5.6
Net current deferred income tax asset (liability) before
valuation allowance		7.9			14.7			(0.1	)		5.6
Valuation allowance		(0.4	)		(0.4	)		-			-
Net current deferred income tax asset (liability)		7.5			14.3			(0.1	)		5.6
Noncurrent deferred income taxes
Plant related		(1,193.6	)		(975.5	)		(861.6	)		(711.5	)
Income taxes on future regulatory recoveries		(144.3	)		(142.6	)		(119.6	)		(117.2	)
Derivative instruments		43.3			46.0			31.1			34.4
Pension and postretirement benefits		(34.2	)		(16.3	)		(11.7	)		2.0
SO2 emission allowance sales		31.1			30.8			31.9			33.4
Fuel clause adjustments		(17.2	)		(16.6	)		(5.4	)		(3.2	)
Transition costs		(17.4	)		(20.0	)		(9.6	)		(11.4	)
Tax credit carryforwards		213.7			204.3			116.8			101.5
Long-term debt fair value adjustment		6.3			19.2			-			-
Customer demand programs		(26.4	)		(23.3	)		(18.6	)		(17.3	)
Net operating loss carryforward		543.7			409.2			77.9			1.1
Other		(10.1	)		(7.3	)		(3.9	)		(3.8	)
Net noncurrent deferred income tax liability before
valuation allowance		(605.1	)		(492.1	)		(772.7	)		(692.0	)
Valuation allowance		(23.5	)		(26.2	)		-			-
Net noncurrent deferred income tax liability		(628.6	)		(518.3	)		(772.7	)		(692.0	)
Net deferred income tax liability	$	(621.1	)	$	(504.0	)	$	(772.8	)	$	(686.4	)


	Great Plains Energy						KCP&L
December 31	2011			2010			2011			2010
	(millions)
Gross deferred income tax assets	$	1,203.6		$	1,140.7		$	618.7		$	602.4
Gross deferred income tax liabilities		(1,824.7	)		(1,644.7	)		(1,391.5	)		(1,288.8	)
Net deferred income tax liability	$	(621.1	)	$	(504.0	)	$	(772.8	)	$	(686.4	)

Liability for unrecognized tax benefits


	Great Plains Energy									KCP&L
	2011			2010			2009			2011			2010			2009
	(millions)
Balance at January 1	$	42.0		$	51.4		$	97.3		$	19.1		$	20.9		$	17.6
Additions for current year tax positions		1.4			2.7			13.2			-			1.3			3.9
Additions for prior year tax positions		2.4			2.1			8.2			2.3			1.5			3.0
Additions for GMO prior year tax positions		-			-			11.6			-			-			-
Reductions for prior year tax positions		(20.9	)		(10.6	)		(1.3	)		(12.6	)		(1.6	)		(0.8	)
Settlements		-			(3.8	)		(76.7	)		-			(2.9	)		(2.2	)
Statute expirations		(0.7	)		(0.3	)		(0.7	)		(0.1	)		(0.1	)		(0.6	)
Foreign currency translation adjustments		(0.2	)		0.5			(0.2	)		-			-			-
Balance at December 31	$	24.0		$	42.0		$	51.4		$	8.7		$	19.1		$	20.9

- Definition

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

+ References+ Details

Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2011

Segment financial information


	Electric						Great Plains
2011	Utility			Other			Energy
	(millions)
Operating revenues	$	2,318.0		$	-		$	2,318.0
Depreciation and amortization		(273.1	)		-			(273.1	)
Interest charges		(176.9	)		(41.5	)		(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


	Electric						Great Plains
2010	Utility			Other			Energy
	(millions)
Operating revenues	$	2,255.5		$	-		$	2,255.5
Depreciation and amortization		(331.6	)		-			(331.6	)
Interest charges		(143.1	)		(41.7	)		(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						Great Plains
2009	Utility			Other			Energy
	(millions)
Operating revenues	$	1,965.0		$	-		$	1,965.0
Depreciation and amortization		(302.2	)		-			(302.2	)
Interest charges		(151.0	)		(29.9	)		(180.9	)
Income tax (expense) benefit		(63.6	)		34.1			(29.5	)
Discontinued operations		-			(1.5	)		(1.5	)
Net income (loss) attributable to Great Plains Energy		157.8			(7.7	)		150.1


	Electric							Great Plains
	Utility		Other		Eliminations			Energy
2011	(millions)
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
2009
Assets	$	8,765.3	$	152.5	$	(435.0	)	$	8,482.8
Capital expenditures		841.3		-		-			841.3

- Definition

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

+ References+ Details

Jointly Owned Electric Utility Plants (Tables)

12 Months Ended

Dec. 31, 2011

Jointly Owned Electric Utility Plants [Abstract]

Schedule of jointly owned electric utility plants


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

Utility plant in service	$	1,473.8		$	493.6		$	667.9		$	1,293.0		$	364.4		$	158.4
Accumulated depreciation		776.3			303.1			252.8			270.0			30.4			75.5
Nuclear fuel, net		76.6			-			-			-			-			-
Construction work in progress		39.4			79.1			6.5			5.9			30.2			5.3
2012 accredited capacity-MWs		547			711			620			641		NA				174


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

Utility plant in service	$	1,473.8		$	493.6		$	542.3		$	985.1		$	287.5
Accumulated depreciation		776.3			303.1			207.9			261.3			26.0
Nuclear fuel, net		76.6			-			-			-			-
Construction work in progress		39.4			79.1			2.6			4.4			9.3
2012 accredited capacity-MWs		547			711			493			482		NA

- Definition

Tabular disclosure of proportionate interests in jointly owned utility plants. Includes the amount of plants in service, the accumulated provision for depreciation (if available), the amount of plants under construction, and the proportionate share. The amounts presented may be further subdivided to show amounts applicable to plant subcategories (for example, production, transmission, distribution). Includes statements that the amounts represent the utility's share in each joint plant and that it must provide its own financing. Information concerning two or more generating plants on the same site may be combined. States that the utility's share of direct expenses of the joint plants is included in the corresponding operating expenses on its income statement (for example, fuel, maintenance of plant, other operating expense). If the share of direct expenses is charged to purchased power, then disclose the amount so charged and the proportionate amounts charged to specific operating expenses on the records maintained for the joint plants.

+ References+ Details

Quarterly Operating Results (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Operating Results (Unaudited) [Abstract]

Schedule of quarterly operating results


	Quarter
Great Plains Energy	1st		2nd		3rd		4th
2011	(millions, except per share amounts)
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
2010
Operating revenue	$	506.9	$	552.0	$	728.8	$	467.8
Operating income		62.0		134.9		243.8		31.6
Net income (loss)		20.3		64.4		132.0		(4.8	)
Net income (loss) attributable to Great Plains Energy		20.3		64.3		132.0		(4.9	)
Basic earnings (loss) per common share		0.15		0.47		0.97		(0.04	)
Diluted earnings (loss) per common share		0.15		0.47		0.96		(0.04	)


	Quarter
KCP&L	1st		2nd		3rd		4th
2011	(millions)
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
2010
Operating revenue	$	335.6	$	372.6	$	486.5	$	322.4
Operating income		40.5		84.7		163.6		22.6
Net income		19.2		48.2		92.6		3.2

Summary of Significant Accounting Policies (Details) (USD $)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Jan. 02, 2010

Utility plant [Abstract]

Cost

$ 10,924,800,000

^[1]

$ 10,536,900,000

^[1]

Depreciation and Amortization [Abstract]

Annual depreciation rates (in hundredths)

3.00%

Depreciation expense

239,900,000

243,600,000

228,900,000

Revenue Recognition [Abstract]

Gross receipts taxes collected

55,600,000

54,300,000

46,800,000

Income [Abstract]

Income from continuing operations

174,200,000

211,900,000

151,900,000

Less: net income attributable to noncontrolling interest

(200,000)

200,000

300,000

Less: preferred stock dividend requirements

1,600,000

Income from continuing operations available for common shareholders

172,800,000

210,100,000

150,000,000

Common Shares Outstanding [Abstract]

Average number of common shares outstanding (in shares)

135,600,000

135,100,000

129,300,000

Add: effect of dilutive securities (in shares)

3,100,000

1,800,000

500,000

Diluted average number of common shares outstanding (in shares)

138,700,000

136,900,000

129,800,000

Earnings per share [Abstract]

Basic EPS from continuing operations (in dollars per share)

$ 1.27

$ 1.55

$ 1.16

Diluted EPS from continuing operations (in dollars per share)

$ 1.25

$ 1.53

$ 1.15

Dividends Declared [Abstract]

Subsequent Event Description

Great Plains Energys Board of Directors declared a quarterly dividend and also declared regular dividends on Great Plains Energys preferred stock.

Dividend Declared [Member]

Dividends Declared [Abstract]

Subsequent event date

Feb. 01, 2012

Subsequent per share amount (in dollars per share)

$ 0.2125

Restricted Stock [Member]

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

Anti-dilutive shares (in shares)

43,641

251,526

438,281

Stock Options [Member]

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

Anti-dilutive shares (in shares)

6,000

196,137

231,670

Performance Shares [Member]

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

Anti-dilutive shares (in shares)

50,897

340,690

150,895

Utility plant generation [Member]

Utility plant [Abstract]

Cost

6,594,000,000

6,369,400,000

Useful life minimum

Useful life maximum

Utiltiy plant transmission [Member]

Utility plant [Abstract]

Cost

734,800,000

716,900,000

Useful life minimum

Useful life maximum

Utility plant distribution [Member]

Utility plant [Abstract]

Cost

2,921,100,000

2,813,400,000

Useful life minimum

Useful life maximum

Utility plant general [Member]

Utility plant [Abstract]

Cost

674,900,000

637,200,000

Useful life minimum

Useful life maximum

Land and other assets [Member]

Utility plant [Abstract]

Cost

105,500,000

103,000,000

Energy Plan [Member]

Depreciation and Amortization [Abstract]

Depreciation expense

14,400,000

72,600,000

58,200,000

Kansas City Power and Light Company [Member]

Utility plant [Abstract]

Cost

7,829,300,000

^[2]

7,540,900,000

^[2]

Interest rate on allowance for funds used during construction

0.20%

6.80%

7.60%

Depreciation and Amortization [Abstract]

Annual depreciation rates (in hundredths)

3.00%

Depreciation expense

162,000,000

170,900,000

158,400,000

Revenue Recognition [Abstract]

Gross receipts taxes collected

55,600,000

54,300,000

46,800,000

Kansas City Power and Light Company [Member] | Dividend Declared [Member]

Dividends Declared [Abstract]

Subsequent event date

Feb. 01, 2012

Subsequent Event Amount

25,000,000

Subsequent Event Description

KCP&Ls Board of Directors declared a cash dividend payable to Great Plains Energy

Kansas City Power and Light Company [Member] | Utility plant generation [Member]

Utility plant [Abstract]

Cost

5,078,100,000

4,886,200,000

Useful life minimum

Useful life maximum

Kansas City Power and Light Company [Member] | Utiltiy plant transmission [Member]

Utility plant [Abstract]

Cost

412,900,000

408,700,000

Useful life minimum

Useful life maximum

Kansas City Power and Light Company [Member] | Utility plant distribution [Member]

Utility plant [Abstract]

Cost

1,840,200,000

1,776,400,000

Useful life minimum

Useful life maximum

Kansas City Power and Light Company [Member] | Utility plant general [Member]

Utility plant [Abstract]

Cost

498,100,000

469,600,000

Useful life minimum

Useful life maximum

Kansas City Power and Light Company [Member] | Land and other assets [Member]

Utility plant [Abstract]

Cost

59,800,000

59,900,000

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

Depreciation and Amortization [Abstract]

Depreciation expense

14,400,000

72,600,000

58,200,000

KCPL Greater Missouri Operations [Member]

Utility plant [Abstract]

Interest rate on allowance for funds used during construction

5.40%

4.60%

5.40%

Carrying (Reported) Amount, Fair Value Disclosure [Member]

Fair value of financial instruments [Abstract}

Long-term debt

3,500,000,000

3,400,000,000

Carrying (Reported) Amount, Fair Value Disclosure [Member] | Kansas City Power and Light Company [Member]

Fair value of financial instruments [Abstract}

Long-term debt

1,900,000,000

1,800,000,000

Estimate of Fair Value, Fair Value Disclosure [Member]

Fair value of financial instruments [Abstract}

Long-term debt

3,900,000,000

3,700,000,000

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

Fair value of financial instruments [Abstract}

Long-term debt

$ 2,200,000,000

$ 1,900,000,000

[1]	Includes $105.5 million and $103.0 million at December 31, 2011 and 2010, respectively, of land and other assets that are not depreciated.
[2]	Includes $59.8 million and $59.9 million at December 31, 2011 and 2010, respectively, of land and other assets that are not depreciated.

Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010
Cash flows affected by changes in:
Receivables	$ 3.6	$ (12.6)	$ 7.9
Accounts receivable pledged as collateral	0	(95.0)	0
Fuel inventories	(3.9)	(0.1)	2.0
Materials and supplies	(7.5)	(11.5)	(22.0)
Accounts payable	5.7	12.8	(70.9)
Accrued taxes	1.4	6.7	42.2
Accrued interest	1.5	2.9	2.9
Deferred refueling outage costs	(17.9)	9.9	(7.1)
Fuel adjustment clauses	(1.7)	2.7	7.8
Pension and post-retirement benefit obligations	(56.0)	(10.2)	18.4
Allowance for equity funds used during construction	(1.0)	(26.0)	(39.6)
Write down of affordable housing investments	0	11.2	0
Iatan Nos. 1 and 2 impact of disallowed construction costs	2.3	16.8	0
Interest rate hedge settlements	(26.1)	(6.9)	(79.1)
Other	(27.1)	(28.3)	9.0
Total other operating activities	(147.5)	(133.7)	(117.8)
Cash paid during the period:
Interest	254.4	237.7	211.9
Income taxes	2.8	0.9	5.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	39.7	44.9	82.8
Uncertian tax positions	(27.1)	(28.3)	9.0
Kansas City Power and Light Company [Member]
Cash flows affected by changes in:
Receivables	(20.2)	(4.1)	(7.6)
Accounts receivable pledged as collateral	0	(95.0)	0
Fuel inventories	(14.1)	0.7	6.1
Materials and supplies	(6.7)	(9.6)	(16.5)
Accounts payable	11.0	0.8	(54.3)
Accrued taxes	2.7	(15.7)	51.8
Accrued interest	3.8	(0.5)	8.6
Deferred refueling outage costs	(17.9)	9.9	(7.1)
Fuel adjustment clauses	(5.8)	(8.8)	2.2
Pension and post-retirement benefit obligations	(45.6)	7.9	39.3
Allowance for equity funds used during construction	(0.7)	(21.9)	(30.6)
Iatan Nos. 1 and 2 impact of disallowed construction costs	1.5	13.0	0
Interest rate hedge settlements	0	0	(79.1)
Other	(15.9)	(2.7)	17.8
Total other operating activities	(118.3)	(127.8)	(66.1)
Cash paid during the period:
Interest	111.3	101.1	77.2
Income taxes	0.1	18.2	31.9
Non-cash investing activities:
Liabilities assumed for capital expenditures	32.0	37.4	75.5
Uncertian tax positions	$ (10.4)	$ (1.8)	$ 3.3

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

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Accounts, Notes, Loans and Financing Receivable [Line Items]

Allowance for doubtful accounts

$ (2.5)

$ (2.7)

Receivables, net

231.2

241.7

Statement [Line Items]

Accounts receivables pledged as collateral

95.0

Kansas City Power and Light Company [Member]

Accounts, Notes, Loans and Financing Receivable [Line Items]

Allowance for doubtful accounts

(1.4)

(1.5)

Receivables, net

172.9

169.4

Statement [Line Items]

Accounts receivables pledged as collateral

95.0

Maximum percentage servicing fee received on receivables sold (in hundredths)

1.50%

Maximum amount of outstanding principal under receivables agreement

110.0

Accounts Receivable Sold [Line Items]

Receivables (sold) purchased

Gain (loss) on sale of accounts receivable

(0.2)

^[1]

(0.2)

^[1]

Servicing fees

Fees to outside investor

(1.2)

Cash flows during the period [Abstract]

Cash from customers transferred to Receivables Company

Cash paid to KCP and L for receivables purchased

Interest on intercompany note

Kansas City Power and Light Company [Member] | Kansas City Power And Light Company Unconsolidated [Member]

Accounts Receivable Sold [Line Items]

Receivables (sold) purchased

(1,415.6)

(1,341.0)

Gain (loss) on sale of accounts receivable

(17.9)

^[1]

(17.0)

^[1]

Servicing fees

2.6

3.2

Fees to outside investor

Cash flows during the period [Abstract]

Cash from customers transferred to Receivables Company

(1,412.4)

(1,337.4)

Cash paid to KCP and L for receivables purchased

1,394.7

1,320.7

Interest on intercompany note

0.5

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

Accounts Receivable Sold [Line Items]

Receivables (sold) purchased

1,415.6

1,341.0

Gain (loss) on sale of accounts receivable

17.7

^[1]

16.8

^[1]

Servicing fees

(2.6)

(3.2)

Fees to outside investor

(1.2)

Cash flows during the period [Abstract]

Cash from customers transferred to Receivables Company

1,412.4

1,337.4

Cash paid to KCP and L for receivables purchased

(1,394.7)

(1,320.7)

Interest on intercompany note

(0.5)

Trade Accounts Receivable [Member] | Billed Revenues [Member]

Accounts, Notes, Loans and Financing Receivable [Line Items]

Accounts receivable, Gross, Current

69.8

62.0

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

16.4

6.5

Trade Accounts Receivable [Member] | Unbilled Revenues [Member]

Accounts, Notes, Loans and Financing Receivable [Line Items]

Accounts receivable, Gross, Current

82.4

82.3

Trade Accounts Receivable [Member] | Unbilled Revenues [Member] | Kansas City Power and Light Company [Member]

Accounts, Notes, Loans and Financing Receivable [Line Items]

Accounts receivable, Gross, Current

50.0

50.1

Other Receivables [Member]

Accounts, Notes, Loans and Financing Receivable [Line Items]

Accounts receivable, Gross, Current

81.5

100.1

Other Receivables [Member] | Kansas City Power and Light Company [Member]

Accounts, Notes, Loans and Financing Receivable [Line Items]

Accounts receivable, Gross, Current

69.2

71.1

Intercompany Receivables [Member] | Kansas City Power and Light Company [Member]

Accounts, Notes, Loans and Financing Receivable [Line Items]

Accounts receivable, Gross, Current

$ 38.7

$ 43.2

[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) (USD $)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Jan. 02, 2010

Investments in decommissioning trust fund [Line Items]

Cost Basis

$ 123,100,000

$ 114,600,000

Gross Unrealized Gains

16,800,000

15,700,000

Gross Unrealized Losses

(4,600,000)

(1,100,000)

Fair Value, Nuclear decommissioning trust fund

135,300,000

129,200,000

Weighted average maturity of debt securities

7.0

Realized Gains on investments in decommissioning trust fund

1,000,000

7,300,000

2,800,000

Realized Losses on investments in decommissioning trust fund

(700,000)

(600,000)

(8,300,000)

Nuclear decommissioning trust fund [Abstract]

Nuclear decommissioning trust fund, ending balance

135,300,000

129,200,000

Wolf Creek Unit [Member]

Jointly Owned Utility Plant Interests [Line Items]

Current cost of decommissioning (in 2011 dollars)

630,000,000

Future cost of decommissioning (in 2045-2053 dollars)

2,455,000,000

^[1]

Annual escalation factor

3.73%

Annual return on trust assets through 2025

6.89%

^[2]

Annual return on trust assets beginning in 2053

1.81%

Nuclear decommissioning trust fund [Abstract]

Industry aggregate limit on nuclear insurance for property claims including accidental outage

3,200,000,000

Amount of insurance against public liability claims resulting from nuclear incidents to the full limit of public liability

12,600,000,000

Maximum available commercial insurance

400,000,000

Remaining balance provided through an industry-wide retrospective assessment program mandated by law

12,200,000,000

Maximum amount able to be assessed to owners

117,500,000

SFP Program-annual amount payable per incident

17,500,000

Amount of decontamination liability, premature decommissioning liability and property damage insurance

2,800,000,000

Premature decommissioning coverage applies only if property damage exceeds this amount and trust funds have been exhausted

500,000,000

Estimated maximum amount of retrospective assessments under the current policies

30,900,000

Equity Securities [Member]

Investments in decommissioning trust fund [Line Items]

Cost Basis

76,500,000

73,400,000

Gross Unrealized Gains

12,300,000

13,100,000

Gross Unrealized Losses

(4,500,000)

(1,000,000)

Fair Value, Nuclear decommissioning trust fund

84,300,000

85,500,000

Nuclear decommissioning trust fund [Abstract]

Nuclear decommissioning trust fund, ending balance

84,300,000

85,500,000

Debt Securities [Member]

Investments in decommissioning trust fund [Line Items]

Cost Basis

44,200,000

38,100,000

Gross Unrealized Gains

4,500,000

2,600,000

Gross Unrealized Losses

(100,000)

Fair Value, Nuclear decommissioning trust fund

48,600,000

40,600,000

Nuclear decommissioning trust fund [Abstract]

Nuclear decommissioning trust fund, ending balance

48,600,000

40,600,000

Other Securities [Member]

Investments in decommissioning trust fund [Line Items]

Cost Basis

2,400,000

3,100,000

Gross Unrealized Gains

Gross Unrealized Losses

Fair Value, Nuclear decommissioning trust fund

2,400,000

3,100,000

Nuclear decommissioning trust fund [Abstract]

Nuclear decommissioning trust fund, ending balance

2,400,000

3,100,000

Kansas City Power and Light Company [Member]

Investments in decommissioning trust fund [Line Items]

Fair Value, Nuclear decommissioning trust fund

135,300,000

129,200,000

Nuclear decommissioning trust fund [Abstract]

Nuclear decommissioning trust fund, beginning balance

112,500,000

Contributions to nuclear decommission trust fund

3,400,000

3,700,000

Nuclear decommissioning trust fund earned income, net of fees

4,800,000

2,000,000

Net realized gains (losses) on nuclear decommissioning trust fund

300,000

6,700,000

Net unrealized gains (losses) on nuclear decommissioning trust fund

(2,400,000)

4,300,000

Nuclear decommissioning trust fund, ending balance

135,300,000

129,200,000

Kansas City Power and Light Company [Member] | Wolf Creek Unit [Member]

Jointly Owned Utility Plant Interests [Line Items]

Ownership percentage in Wolf Creek, a nuclear generating unit (in hundredths)

47.00%

Current cost of decommissioning (in 2011 dollars)

296,000,000

Future cost of decommissioning (in 2045-2053 dollars)

1,154,000,000

^[1]

Nuclear decommissioning trust fund [Abstract]

Maximum amount able to be assessed to owners

55,200,000

SFP Program-annual amount payable per incident

8,200,000

Amount of decontamination liability, premature decommissioning liability and property damage insurance

1,300,000,000

Estimated maximum amount of retrospective assessments under the current policies

$ 14,500,000

[1]	Total future cost over an eight year decommissioning period.
[2]	The 6.89% rate of return is through 2025. The rate then systematically decreases through 2053 to 1.81% based on the assumption that the fund's investment mix will become increasingly more conservative as the decommissioning period approaches.

Regulatory Matters (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

12 Months Ended

Dec. 31, 2010

Sep. 30, 2010

Dec. 31, 2011

Emission allowances [Member]

Dec. 31, 2010

Emission allowances [Member]

Dec. 31, 2011

Asset retirement obligations [Member]

Dec. 31, 2010

Asset retirement obligations [Member]

Dec. 31, 2011

Pension [Member]

Dec. 31, 2010

Pension [Member]

Dec. 31, 2011

Cost of removal, liability [Member]

Dec. 31, 2010

Cost of removal, liability [Member]

Dec. 31, 2011

Other regulatory noncurrent liabilities [Member]

Dec. 31, 2010

Other regulatory noncurrent liabilities [Member]

Dec. 31, 2011

Taxes recoverable through future rates [Member]

Dec. 31, 2010

Taxes recoverable through future rates [Member]

Dec. 31, 2011

Loss on reacquired debt [Member]

Dec. 31, 2010

Loss on reacquired debt [Member]

Dec. 31, 2011

Cost of removal, asset [Member]

Dec. 31, 2010

Cost of removal, asset [Member]

Dec. 31, 2011

Asset Retirement Obligation Costs [Member]

Dec. 31, 2010

Asset Retirement Obligation Costs [Member]

Dec. 31, 2011

Pension and post-retirement costs [Member]

Dec. 31, 2010

Pension and post-retirement costs [Member]

Dec. 31, 2011

Deferred customer programs [Member]

Dec. 31, 2010

Deferred customer programs [Member]

Dec. 31, 2011

Rate case expenses [Member]

Dec. 31, 2010

Rate case expenses [Member]

Dec. 31, 2011

Skill set realignment costs [Member]

Dec. 31, 2010

Skill set realignment costs [Member]

Dec. 31, 2011

Fuel adjustment clauses [Member]

Dec. 31, 2010

Fuel adjustment clauses [Member]

Dec. 31, 2011

Acquisition transition costs [Member]

Dec. 31, 2010

Acquisition transition costs [Member]

Dec. 31, 2011

Derivative instruments [Member]

Dec. 31, 2010

Derivative instruments [Member]

Dec. 31, 2011

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

Dec. 31, 2010

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

Dec. 31, 2011

Iatan No. 2 construction accounting costs [Member]

Dec. 31, 2010

Iatan No. 2 construction accounting costs [Member]

Dec. 31, 2011

Kansas property tax surcharge [Member]

Dec. 31, 2011

Other regulatory noncurrent assets [Member]

Dec. 31, 2010

Other regulatory noncurrent assets [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Emission allowances [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Emission allowances [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Asset retirement obligations [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Asset retirement obligations [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Pension [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Pension [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Other regulatory noncurrent liabilities [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Other regulatory noncurrent liabilities [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Taxes recoverable through future rates [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Taxes recoverable through future rates [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Loss on reacquired debt [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Loss on reacquired debt [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Cost of removal, asset [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Cost of removal, asset [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Asset Retirement Obligation Costs [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Asset Retirement Obligation Costs [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Pension and post-retirement costs [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Pension and post-retirement costs [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Deferred customer programs [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Deferred customer programs [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Rate case expenses [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Rate case expenses [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Skill set realignment costs [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Skill set realignment costs [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Fuel adjustment clauses [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Fuel adjustment clauses [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Acquisition transition costs [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Acquisition transition costs [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Derivative instruments [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Derivative instruments [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

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

Dec. 31, 2010

Kansas City Power and Light Company [Member]

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

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Iatan No. 2 construction accounting costs [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Iatan No. 2 construction accounting costs [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Kansas property tax surcharge [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Other regulatory noncurrent assets [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Other regulatory noncurrent assets [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Rate jurisdiction - Kansas [Member]

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Rate jurisdiction - Missouri [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Emission allowances [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Emission allowances [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Pension [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Pension [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Cost of removal, liability [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Cost of removal, liability [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Other regulatory noncurrent liabilities [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Other regulatory noncurrent liabilities [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Taxes recoverable through future rates [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Taxes recoverable through future rates [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Loss on reacquired debt [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Loss on reacquired debt [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Cost of removal, asset [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Cost of removal, asset [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Asset Retirement Obligation Costs [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Asset Retirement Obligation Costs [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Pension and post-retirement costs [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Pension and post-retirement costs [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Deferred customer programs [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Deferred customer programs [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Rate case expenses [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Rate case expenses [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Skill set realignment costs [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Skill set realignment costs [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Fuel adjustment clauses [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Fuel adjustment clauses [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Acquisition transition costs [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Acquisition transition costs [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Derivative instruments [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Derivative instruments [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

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

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

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

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Iatan No. 2 construction accounting costs [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Iatan No. 2 construction accounting costs [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Other regulatory noncurrent assets [Member]

Dec. 31, 2010

KCPL Greater Missouri Operations [Member]

Other regulatory noncurrent assets [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Rate jurisdiction - Missouri public service division [Member]

Dec. 31, 2011

KCPL Greater Missouri Operations [Member]

Rate jurisdiction - St. Joseph Light and Power division [Member]

Regulatory Proceedings [Line Items]

Annual revenue increase

$ 105.7

$ 58.3

$ 25.2

Modified annual revenue increase

22.0

35.7

29.8

Return on equity (in hundredths)

10.40%

Rate-making equity ratio (in hundredths)

52.50%

Annual revenue increase authorized

21.8

34.8

30.1

29.3

Return on equity, approved (in hundredths)

10.00%

Rate-making equity ratio, approved (in hundredths)

49.70%

46.30%

46.60%

Jurisdictional rate base

1,781

2,000

1,760

Disallowed construction costs on Iatan Nos 1 and 2

12.8

4.0

1.5

0.8

Other disallowed costs

2.4

1.5

Wholesale Margin Offset

45.9

Qualifying advance coal project tax credits to be reallocated from KCPL to GMO

26.5

Unamortized deferred investment tax credits

127.9

3.3

Amount of Crossroads disallowed from rate base

50.0

Amount of Crossroads transmission expense disallowed

4.9

Amount of Crossroads accumulated deferred taxes offset against rate base

15.0

Amount of Crossroads net plant requested

104.0

Amount of approved annual revenue increase deferred

7.7

Amount of revenue increase requested

22.1

Amount of FAC refund recommended by MPSC staff

19.0

Additional rate case expenses allowed in rates

0.2

Regulatory Assets [Line Items]

Regulatory Assets

924.0

1,058.2

144.2

142.5

11.8

5.7

4.6

8.5

45.2

40.3

588.4

492.8

68.8

60.3

13.4

15.6

3.4

4.8

50.4

45.5

44.9

51.8

7.6

3.1

22.5

19.4

43.3

23.7

3.7

6.0

10.0

780.7

679.6

119.6

117.2

9.1

^[1]

5.0

4.6

8.5

31.4

27.5

466.4

^[2]

386.1

48.2

^[3]

44.7

9.6

^[4]

12.3

3.4

^[5]

4.8

14.0

^[4]

8.4

24.7

^[6]

29.3

16.4

15.1

27.9

17.2

3.7

^[4]

1.7

^[7]

3.5

277.5

244.4

24.6

25.3

2.7

^[1]

0.7

13.8

12.8

122.0

^[2]

106.7

20.6

15.6

3.8

^[4]

3.3

36.4

^[4]

37.1

20.2

^[6]

22.5

7.6

^[8]

3.1

6.1

4.3

15.4

6.5

4.3

^[7]

6.5

Amount not included in rate base

10.4

2.4

Regulatory amortization period

various

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

various

through 2017

various

through 2016

various

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

various

through 2016

various

Regulatory Liabilities [Line Items]

Regulatory Liabilities

$ 258.2

$ 268.5

$ 82.2

$ 86.4

$ 49.3

$ 44.9

$ 41.5

$ 37.1

$ 61.9

^[9]

$ 62.8

$ 33.6

$ 27.0

$ 142.8

$ 141.3

$ 82.0

$ 85.9

$ 49.3

$ 44.9

$ 0.7

$ 0

$ 10.8

$ 10.5

$ 125.7

$ 116.9

$ 0.2

$ 0.5

$ 40.8

$ 37.1

$ 61.9

$ 62.8

$ 22.8

$ 16.5

[1]	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]	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 not included in rate base that will be eliminated over the life of the pension plans.
[3]	$10.4 million not included in rate base and amortized over various periods.
[4]	Not included in rate base and amortized over various periods.
[5]	$2.4 million not included in rate base and amortized through 2017.
[6]	Not included in rate base and amortized through 2016.
[7]	Certain insignificant items are not included in rate base and amortized over various periods.
[8]	Represents the fair value of derivative instruments for commodity contracts. Settlements of the contracts are recognized in fuel expense and included in GMOs FAC.
[9]	Estimated cumulative net provision for future removal costs.

Goodwill and Intangible Assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Finite-Lived Intangible Assets, Net [Abstract]
Amortization Expense	$ 13.5	$ 13.1
Estimated amortization expense [Abstract]
Future Amortization Expense, Year One	13.9
Future Amortization Expense, Year Two	11.2
Future Amortization Expense, Year Three	8.1
Future Amortization Expense, Year Four	6.0
Future Amortization Expense, Year Five	4.7
Goodwill	169.0	169.0
Computer Software, Intangible Asset [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	202.5	201.1
Accumulated Amortization	(143.5)	(137.3)
Asset Improvements [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	27.0	27.9
Accumulated Amortization	(3.7)	(4.4)
Kansas City Power and Light Company [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Amortization Expense	12.6	12.2
Estimated amortization expense [Abstract]
Future Amortization Expense, Year One	11.0
Future Amortization Expense, Year Two	8.3
Future Amortization Expense, Year Three	5.3
Future Amortization Expense, Year Four	3.4
Future Amortization Expense, Year Five	2.1
Kansas City Power and Light Company [Member] \| Computer Software, Intangible Asset [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	171.7	168.2
Accumulated Amortization	(129.9)	(118.0)
Kansas City Power and Light Company [Member] \| Asset Improvements [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	11.7	5.8
Accumulated Amortization	$ (0.6)	$ 0

Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Asset retirement obligations [Roll Forward]
Beginning balance		$ 132.6
Additions	0.8	2.0
Revision in timing and/or estimates	(3.8)	0
Accretion	9.3	8.7
Ending balance	149.6	143.3
Kansas City Power and Light Company [Member]
Asset retirement obligations [Roll Forward]
Beginning balance		119.8
Additions	0	2.0
Revision in timing and/or estimates	(3.8)	0
Accretion	8.4	7.9
Ending balance	$ 134.3	$ 129.7

- Definition

Amount of accretion expense recognized during the period that is associated with an asset retirement obligation. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.

+ References+ Details

Pension Plans and Other Employee Benefits (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Jan. 02, 2010

Dec. 31, 2011

Kansas City Power and Light Company [Member]

Dec. 31, 2010

Kansas City Power and Light Company [Member]

Jan. 02, 2010

Kansas City Power and Light Company [Member]

Dec. 31, 2012

(millions)

Great Plains Energy