Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
GREAT PLAINS ENERGY INCORPORATED
Current Assets
Cash and cash equivalents	$ 10.8	$ 65.9
Funds on deposit	5.2	4.4
Receivables, net	241.7	230.5
Accounts receivable pledged as collateral	95.0	0
Fuel inventories, at average cost	85.1	85.0
Materials and supplies, at average cost	132.8	121.3
Deferred refueling outage costs	9.6	19.5
Refundable income taxes	2.1	13.5
Deferred income taxes	14.3	36.8
Assets held for sale	0	19.4
Derivative instruments	1.1	1.5
Prepaid expenses and other assets	13.9	14.7
Total	611.6	612.5
Utility Plant, at Original Cost
Electric	10,536.9	8,849.0
Less-accumulated depreciation	4,031.3	3,774.5
Net utility plant in service	6,505.6	5,074.5
Construction work in progress	307.5	1,508.4
Nuclear fuel, net of amortization	79.2	68.2
Total	6,892.3	6,651.1
Investments and Other Assets
Affordable housing limited partnerships	0.3	13.2
Nuclear decommissioning trust fund	129.2	112.5
Regulatory assets	924.0	822.2
Goodwill	169.0	169.0
Derivative instruments	7.8	7.9
Other	84.0	94.4
Total	1,314.3	1,219.2
Total	8,818.2	8,482.8
Current Liabilities
Notes payable	9.5	252.0
Collateralized note payable	95.0	0
Commercial paper	263.5	186.6
Current maturities of long-term debt	485.7	1.3
Accounts payable	276.3	315.0
Accrued taxes	26.6	27.9
Accrued interest	75.4	72.5
Accrued compensation and benefits	46.8	45.1
Pension and post-retirement liability	4.1	4.6
Derivative instruments	20.8	0.3
Other	35.6	53.0
Total	1,339.3	958.3
Deferred Credits and Other Liabilities
Deferred income taxes	518.3	381.9
Deferred tax credits	133.4	140.5
Asset retirement obligations	143.3	132.6
Pension and post-retirement liability	427.5	440.4
Regulatory liabilities	258.2	237.8
Derivative instruments	0	0.5
Other	129.4	145.1
Total	1,610.1	1,478.8
Common shareholders' equity
Common Stock	2,324.4	2,313.7
Retained earnings	626.5	529.2
Treasury stock	(8.9)	(5.5)
Accumulated other comprehensive gain (loss)	(56.1)	(44.9)
Total	2,885.9	2,792.5
Noncontrolling interest	1.2	1.2
Cumulative preferred stock
3.80%	10.0	10.0
4.50%	10.0	10.0
4.20%	7.0	7.0
4.35%	12.0	12.0
Total	39.0	39.0
Long-term debt	2,942.7	3,213.0
Total	5,868.8	6,045.7
Commitments and Contingencies
Total	8,818.2	8,482.8
KANSAS CITY POWER AND LIGHT COMPANY
Current Assets
Cash and cash equivalents	3.6	17.4
Funds on deposit	0.4	0.1
Receivables, net	169.4	161.7
Accounts receivable pledged as collateral	95.0	0
Fuel inventories, at average cost	44.9	45.6
Materials and supplies, at average cost	94.4	84.8
Deferred refueling outage costs	9.6	19.5
Refundable income taxes	9.0	0
Deferred income taxes	5.6	0.3
Derivative instruments	0	0.2
Prepaid expenses and other assets	10.0	11.0
Total	441.9	340.6
Utility Plant, at Original Cost
Electric	7,540.9	6,258.5
Less-accumulated depreciation	3,104.4	2,899.0
Net utility plant in service	4,436.5	3,359.5
Construction work in progress	227.6	1,144.1
Nuclear fuel, net of amortization	79.2	68.2
Total	4,743.3	4,571.8
Investments and Other Assets
Nuclear decommissioning trust fund	129.2	112.5
Regulatory assets	679.6	612.1
Other	32.3	65.3
Total	841.1	789.9
Total	6,026.3	5,702.3
Current Liabilities
Collateralized note payable	95.0	0
Commercial paper	263.5	186.6
Current maturities of long-term debt	150.3	0.2
Accounts payable	201.7	237.9
Accrued taxes	21.3	23.7
Accrued interest	26.2	26.7
Accrued compensation and benefits	46.8	45.1
Pension and post-retirement liability	2.6	3.2
Other	7.8	26.1
Total	815.2	549.5
Deferred Credits and Other Liabilities
Deferred income taxes	692.0	559.4
Deferred tax credits	129.4	135.7
Asset retirement obligations	129.7	119.8
Pension and post-retirement liability	407.3	421.2
Regulatory liabilities	141.3	126.9
Other	76.7	78.2
Total	1,576.4	1,441.2
Common shareholders' equity
Common Stock	1,563.1	1,563.1
Retained earnings	478.3	410.1
Accumulated other comprehensive gain (loss)	(36.4)	(41.5)
Total	2,005.0	1,931.7
Cumulative preferred stock
Long-term debt	1,629.7	1,779.9
Total	3,634.7	3,711.6
Commitments and Contingencies
Total	$ 6,026.3	$ 5,702.3

Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2010	Dec. 31, 2009
GREAT PLAINS ENERGY INCORPORATED
Utility Plant, at Original Cost
Nuclear fuel accumulated amortization	$ 131.1	$ 106.0
Capitalization
Common Stock, Shares, Authorized	250,000,000	250,000,000
Common Stock, Shares, Issued	136,113,954	135,636,538
Treasury Stock, Shares	400,889	213,423
Cumulative preferred stock par value	$ 100	$ 100
3.80% - shares issued	100,000	100,000
4.50% - shares issued	100,000	100,000
4.20% - shares issued	70,000	70,000
4.35% - shares issued	120,000	120,000
KANSAS CITY POWER AND LIGHT COMPANY
Utility Plant, at Original Cost
Nuclear fuel accumulated amortization	$ 131.1	$ 106.0
Capitalization
Common Stock, Shares, Authorized	1,000	1,000
Common Stock, Shares, Issued	1	1

Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
GREAT PLAINS ENERGY INCORPORATED
Operating Revenues
Electric revenues	$ 2,255.5	$ 1,965.0	$ 1,670.1
Operating Expenses
Fuel	430.7	405.5	311.4
Purchased power	213.8	183.7	208.9
Transmission of electricity by others	27.4	26.9	22.5
Utility operating and maintenance expenses	602.5	572.4	477.2
Depreciation and amortization	331.6	302.2	235.0
General taxes	155.1	139.8	128.1
Other	22.1	14.4	12.0
Total	1,783.2	1,644.9	1,395.1
Operating income (loss)	472.3	320.1	275.0
Non-operating income	43.9	49.5	31.9
Non-operating expenses	(19.5)	(6.9)	(10.8)
Interest charges	(184.8)	(180.9)	(111.3)
Income (loss) before income tax (expense) benefit and loss from equity investments	311.9	181.8	184.8
Income tax (expense) benefit	(99.0)	(29.5)	(63.8)
Loss from equity investments, net of income taxes	(1.0)	(0.4)	(1.3)
Income from continuing operations	211.9	151.9	119.7
Income (loss) from discontinued operations, net of income taxes	0	(1.5)	35.0
Net income	211.9	150.4	154.7
Less: Net income attributable to noncontrolling interest	(0.2)	(0.3)	(0.2)
Net income (loss) attributable to Great Plains Energy	211.7	150.1	154.5
Preferred stock dividend requirements	1.6	1.6	1.6
Earnings available for common shareholders	210.1	148.5	152.9
Average number of basic common shares outstanding	135.1	129.3	101.1
Average number of diluted common shares outstanding	136.9	129.8	101.2
Basic and diluted earnings (loss) per common share
Basic earnings per common share - continuing operations	$ 1.55	$ 1.16	$ 1.16
Basic earnings (loss) per common share - discontinued operations	$ 0	$ (0.01)	$ 0.35
Basic earnings per common share	$ 1.55	$ 1.15	$ 1.51
Diluted earnings per common share - continuing operations	$ 1.53	$ 1.15	$ 1.16
Diluted earnings (loss) per common share - discontinued operations	$ 0	$ (0.01)	$ 0.35
Diluted earnings per common share	$ 1.53	$ 1.14	$ 1.51
Cash dividends per common share	$ 0.83	$ 0.83	$ 1.66
KANSAS CITY POWER AND LIGHT COMPANY
Operating Revenues
Electric revenues	1,517.1	1,318.2	1,343.0
Operating Expenses
Fuel	278.8	251.3	253.3
Purchased power	78.9	70.8	119.0
Transmission of electricity by others	15.0	12.3	11.1
Utility operating and maintenance expenses	434.3	403.3	398.1
Depreciation and amortization	256.4	229.6	204.3
General taxes	129.3	118.7	118.9
Other	13.0	0	0.2
Total	1,205.7	1,086.0	1,104.9
Operating income (loss)	311.4	232.2	238.1
Non-operating income	24.7	33.2	25.9
Non-operating expenses	(5.6)	(4.7)	(6.7)
Interest charges	(85.7)	(84.9)	(72.3)
Income (loss) before income tax (expense) benefit and loss from equity investments	244.8	175.8	185.0
Income tax (expense) benefit	(81.6)	(46.9)	(59.8)
Net income	$ 163.2	$ 128.9	$ 125.2

Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
GREAT PLAINS ENERGY INCORPORATED
Cash Flows from Operating Activities
Net income (loss)	$ 211.9	$ 150.4	$ 154.7
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	331.6	302.2	238.3
Amortization of:
Nuclear fuel	25.1	16.1	14.5
Other	(4.7)	(10.1)	(1.9)
Deferred income taxes, net	123.8	(3.6)	44.1
Investment tax credit amortization	(2.9)	(2.2)	(1.8)
Loss from equity investments, net of income taxes	1.0	0.4	1.3
Fair value impacts from interest rate hedging	0	0	9.2
Fair value impacts from energy contracts - Strategic Energy	0	0	(189.1)
Loss on sale of Strategic Energy	0	0	116.2
Other operating activities	(133.7)	(117.8)	52.4
Net cash from operating activities	552.1	335.4	437.9
Cash Flows from Investing Activities
Utility capital expenditures	(618.0)	(841.1)	(1,023.7)
Allowance for borrowed funds used during construction	(28.5)	(37.7)	(31.7)
Payment to Black Hills for asset sale working capital adjustment	0	(7.7)	0
Proceeds from sale of Strategic Energy, net of cash sold	0	0	218.8
GMO acquisition, net cash received	0	0	271.9
Purchases of nuclear decommissioning trust investments	(83.3)	(99.0)	(49.1)
Proceeds from nuclear decommissioning trust investments	79.6	95.3	45.4
Other investing activities	(7.5)	(7.4)	(10.7)
Net cash from investing activities	(657.7)	(897.6)	(579.1)
Cash Flows from Financing Activities
Issuance of common stock	6.2	219.9	15.3
Issuance of long-term debt	249.9	700.7	363.4
Issuance fees	(12.1)	(22.8)	(5.3)
Repayment of long-term debt	(1.3)	(70.7)	(169.9)
Net change in short-term borrowings	(165.6)	(145.6)	118.4
Net change in collateralized short-term borrowings	95.0	0	0
Dividends paid	(114.2)	(110.5)	(172.0)
Credit facility termination fees	0	0	(12.5)
Other financing activities	(7.4)	(4.0)	(2.2)
Net cash from financing activities	50.5	567.0	135.2
Net Change in Cash and Cash Equivalents	(55.1)	4.8	(6.0)
Cash and Cash Equivalents at Beginning of Year	65.9	61.1	67.1
Cash and Cash Equivalents at End of Period	10.8	65.9	61.1
KANSAS CITY POWER AND LIGHT COMPANY
Cash Flows from Operating Activities
Net income (loss)	163.2	128.9	125.2
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	256.4	229.6	204.3
Amortization of:
Nuclear fuel	25.1	16.1	14.5
Other	24.2	19.0	11.1
Deferred income taxes, net	83.2	(38.2)	(7.5)
Investment tax credit amortization	(2.1)	(1.4)	(1.4)
Other operating activities	(127.8)	(66.1)	72.8
Net cash from operating activities	422.2	287.9	419.0
Cash Flows from Investing Activities
Utility capital expenditures	(463.1)	(626.5)	(810.5)
Allowance for borrowed funds used during construction	(22.4)	(31.1)	(23.6)
Purchases of nuclear decommissioning trust investments	(83.3)	(99.0)	(49.1)
Proceeds from nuclear decommissioning trust investments	79.6	95.3	45.4
Net money pool lending	(6.1)	(6.0)	0
Other investing activities	(13.4)	(0.6)	(8.5)
Net cash from investing activities	(508.7)	(667.9)	(846.3)
Cash Flows from Financing Activities
Issuance of long-term debt	0	413.2	363.4
Issuance fees	(5.1)	(4.0)	(4.3)
Repayment of long-term debt	(0.2)	0	0
Net change in short-term borrowings	76.9	(193.6)	14.4
Net change in collateralized short-term borrowings	95.0	0	0
Net money pool borrowings	1.1	0.9	0
Dividends paid	(95.0)	(72.0)	(144.0)
Equity contribution from Great Plains Energy	0	247.5	200.0
Net cash from financing activities	72.7	392.0	429.5
Net Change in Cash and Cash Equivalents	(13.8)	12.0	2.2
Cash and Cash Equivalents at Beginning of Year	17.4	5.4	3.2
Cash and Cash Equivalents at End of Period	$ 3.6	$ 17.4	$ 5.4

Consolidated Statements of Cash Flows (Parenthetical) (GREAT PLAINS ENERGY INCORPORATED, USD $) In Millions, unless otherwise specified	Dec. 31, 2007
GREAT PLAINS ENERGY INCORPORATED
Cash and Cash Equivalents, Beginning Balance Included in Discontinued Operations	$ 43.1

Consolidated Statements of Common Shareholders' Equity (USD $) In Millions, except Share data, unless otherwise specified	GREAT PLAINS ENERGY INCORPORATED	KANSAS CITY POWER AND LIGHT COMPANY	Common Stock GREAT PLAINS ENERGY INCORPORATED	Common Stock KANSAS CITY POWER AND LIGHT COMPANY	Retained Earnings GREAT PLAINS ENERGY INCORPORATED	Retained Earnings KANSAS CITY POWER AND LIGHT COMPANY	Treasury Stock GREAT PLAINS ENERGY INCORPORATED	Accumulated Other Comprehensive Income (Loss) GREAT PLAINS ENERGY INCORPORATED	Accumulated Other Comprehensive Income (Loss) KANSAS CITY POWER AND LIGHT COMPANY	Noncontrolling Interest GREAT PLAINS ENERGY INCORPORATED	Total Great Plains Energy Common Shareholders' Equity [Member] GREAT PLAINS ENERGY INCORPORATED
Beginning balance (in shares) at Dec. 31, 2007			86,325,136	1			(90,929)
Beginning balance at Dec. 31, 2007			$ 1,065.9	$ 1,115.6	$ 506.9	$ 371.3	$ (2.8)	$ (2.1)	$ (7.5)	$ 0
Equity contribution from Great Plains Energy		200.0		200.0
Issuance of common stock			1,042.0
Issuance of common stock (in shares)			32,962,723
Common stock issuance fees			0
Issuance of restricted common stock			2.3
Issuance of restricted common stock (in shares)			88,064
Equity compensation expense, net of forfeitures			5.9
Unearned Compensation
Issuance of restricted common stock			(2.3)
Forfeiture of restricted common stock			0
Compensation expense recognized			5.6
Equity Units allocated fees and expenses and the present value of contract adjustment payments			0
Other			(1.0)
Cumulative Effect of Initial Adoption of New Accounting Principle					(0.1)
Net income (loss) attributable to Great Plains Energy	154.5				154.5	125.2
Transfer of HSS to KLT Inc.						0.7
Dividends:
Common stock					(170.4)	(144.0)
Preferred stock - at required rates					(1.6)
Performance shares					0
Performance shares amendment					0
Treasury shares acquired							(1.1)
Treasury shares acquired (in shares)							(39,856)
Treasury shares reissued							0.3
Treasury shares reissued (in shares)							10,108
Derivative hedging activity, net of tax	(47.5)	(39.4)						(47.5)	(39.4)
Change in unrecognized pension expense, net of tax	(3.9)							(3.9)
GMO acquisition										0.8
Net income attributable to noncontrolling interest										0.2
Distribution										0
Ending balance (in shares) at Dec. 31, 2008			119,375,923	1			(120,677)
Ending balance at Dec. 31, 2008		1,621.9	2,118.4	1,315.6	489.3	353.2	(3.6)	(53.5)	(46.9)	1.0	2,550.6
Equity contribution from Great Plains Energy		247.5		247.5
Issuance of common stock			220.1
Issuance of common stock (in shares)			15,883,948
Common stock issuance fees			(7.0)
Issuance of restricted common stock			5.4
Issuance of restricted common stock (in shares)			376,667
Equity compensation expense, net of forfeitures			0.8
Unearned Compensation
Issuance of restricted common stock			(5.4)
Forfeiture of restricted common stock			1.1
Compensation expense recognized			3.8
Equity Units allocated fees and expenses and the present value of contract adjustment payments			(22.5)
Other			(1.0)
Cumulative Effect of Initial Adoption of New Accounting Principle					0
Net income (loss) attributable to Great Plains Energy	150.1				150.1	128.9
Transfer of HSS to KLT Inc.						0
Dividends:
Common stock					(108.9)	(72.0)
Preferred stock - at required rates					(1.6)
Performance shares					(0.1)
Performance shares amendment					0.4
Treasury shares acquired							(2.9)
Treasury shares acquired (in shares)							(132,593)
Treasury shares reissued							1.0
Treasury shares reissued (in shares)							39,847
Derivative hedging activity, net of tax	5.3	5.4						5.3	5.4
Change in unrecognized pension expense, net of tax	3.3							3.3
GMO acquisition										0
Net income attributable to noncontrolling interest										0.3
Distribution										(0.1)
Common Stockholders' Equity attributable to Parent	2,792.5	1,931.7
Ending balance (in shares) at Dec. 31, 2009			135,636,538	1			(213,423)
Ending balance at Dec. 31, 2009			2,313.7	1,563.1	529.2	410.1	(5.5)	(44.9)	(41.5)	1.2
Equity contribution from Great Plains Energy		0		0
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
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
Cumulative Effect of Initial Adoption of New Accounting Principle					0
Net income (loss) attributable to Great Plains Energy	211.7				211.7	163.2
Transfer of HSS to KLT Inc.						0
Dividends:
Common stock					(112.6)	(95.0)
Preferred stock - at required rates					(1.6)
Performance shares					(0.2)
Performance shares amendment					0
Treasury shares acquired							(3.4)
Treasury shares acquired (in shares)							(188,383)
Treasury shares reissued							0
Treasury shares reissued (in shares)							917
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)
GMO acquisition										0
Net income attributable to noncontrolling interest										0.2
Distribution										(0.2)
Common Stockholders' Equity attributable to Parent	2,885.9	2,005.0
Ending balance (in shares) at Dec. 31, 2010			136,113,954	1			(400,889)
Ending balance at Dec. 31, 2010			$ 2,324.4	$ 1,563.1	$ 626.5	$ 478.3	$ (8.9)	$ (56.1)	$ (36.4)	$ 1.2

Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
GREAT PLAINS ENERGY INCORPORATED
Net income (loss)	$ 211.9	$ 150.4	$ 154.7
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	(28.0)	(0.4)	27.0
Income tax (expense) benefit	10.8	0.1	(12.5)
Net gain (loss) on derivative hedging instruments	(17.2)	(0.3)	14.5
Reclassification to expenses, net of tax	6.6	5.6	(62.0)
Derivative hedging activity, net of tax	(10.6)	5.3	(47.5)
Defined benefit pension plans
Net gain (loss) arising during period	(1.3)	5.0	(6.7)
Amortization of net gain included in net periodic benefit costs	0.3	0.4	0.3
Less: amortization of prior service costs included in net periodic benefit costs	0	0	0.1
Income tax expense	0.4	(2.1)	2.4
Net change in unrecognized pension expense	(0.6)	3.3	(3.9)
Comprehensive income (loss)	200.7	159.0	103.3
Less: comprehensive income attributable to noncontrolling interest	(0.2)	(0.3)	(0.2)
Comprehensive income (loss) attributable to Great Plains Energy	200.5	158.7	103.1
KANSAS CITY POWER AND LIGHT COMPANY
Net income (loss)	163.2	128.9	125.2
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	(0.9)	0.2	(65.0)
Income tax (expense) benefit	0.3	(0.1)	25.4
Net gain (loss) on derivative hedging instruments	(0.6)	0.1	(39.6)
Reclassification to expenses, net of tax	5.7	5.3	0.2
Derivative hedging activity, net of tax	5.1	5.4	(39.4)
Defined benefit pension plans
Comprehensive income (loss)	$ 168.3	$ 134.3	$ 85.8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Summary of Significant Accounting Policies

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

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

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

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

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

Great Plains Energy’s sole reportable business segment is electric utility. See Note 22 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 instruments 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 Plans (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, 2010, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, was $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, was $1.8 billion and $1.9 billion, respectively. At December 31, 2009, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, was $3.2 billion and $3.4 billion, respectively. At December 31, 2009, the book value and fair value of KCP&L’s long-term debt, including current maturities, was $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 19 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 and Accounting for Planned Major Maintenance). 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 6.8% in 2010, 7.6% in 2009, and 7.1% in 2008 for KCP&L and for GMO averaged 4.6% in 2010, 5.4% in 2009 and 4.9% in 2008 subsequent to its acquisition on July 14, 2008.

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		2010		2009
Utility Plant, at original cost		(millions)
	Production (20 - 60 years)	$	6,369.4	$	4,892.3
	Transmission (15 - 70 years)		716.9		660.4
	Distribution (8 - 66 years)		2,813.4		2,708.3
	General (5 - 50 years)		637.2		588.0
Total (a)		$	10,536.9	$	8,849.0
(a)	Includes $103.0 million and $96.3 million at December 31,
	2010 and 2009, respectively, of land and other assets that
	are not depreciated.

KCP&L
December 31		2010		2009
Utility Plant, at original cost		(millions)
	Production (20 - 60 years)	$	4,886.2	$	3,742.6
	Transmission (15 - 70 years)		408.7		371.3
	Distribution (8 - 55 years)		1,776.4		1,709.5
	General (5 - 50 years)		469.6		435.1
Total (a)		$	7,540.9	$	6,258.5
(a)	Includes $59.9 million and $56.1 million at December 31,
	2010 and 2009, 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 $243.6 million, $228.9 million, and $175.1 million for 2010, 2009, and 2008, respectively. KCP&L’s depreciation expense was $170.9 million, $158.4 million, and $145.4 million for 2010, 2009 and 2008, respectively. Great Plains Energy’s and KCP&L’s depreciation and amortization expense includes $72.6 million, $58.2 million, and $47.4 million for 2010, 2009 and 2008, respectively, of additional amortization to help maintain cash flow levels during KCP&L’s Comprehensive Energy Plan pursuant to orders of the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC).

Nuclear Plant Decommissioning Costs

Nuclear plant decommissioning cost estimates are based on the immediate dismantlement method and include the costs of decontamination, dismantlement and site restoration. Based on these cost estimates, KCP&L contributes to a tax-qualified trust fund to be used to decommission Wolf Creek Generating Station (Wolf Creek). Related liabilities for decommissioning are included on Great Plains Energy’s and KCP&L’s balance sheet 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 8 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 6 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 $54.3 million, $46.8 million and $45.9 million in 2010, 2009 and 2008, 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 sales of assets, businesses and 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

Great Plains Energy has recognized deferred taxes for temporary book to tax differences using the liability method. The liability method requires that deferred tax balances be adjusted to reflect enacted tax rates that are anticipated to be in effect when the temporary differences 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 and its subsidiaries file consolidated federal and combined and separate state income tax returns. 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 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 earnings (loss) per share impact of discontinued operations is determined by dividing income (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.


	2010		2009		2008
Income	(millions, except per share amounts)
Income from continuing operations	$	211.9	$	151.9	$	119.7
Less: net income attributable to noncontrolling interest		0.2		0.3		0.2
Less: preferred stock dividend requirements		1.6		1.6		1.6
Income from continuing operations available for common shareholders	$	210.1	$	150.0	$	117.9
Common Shares Outstanding
Average number of common shares outstanding		135.1		129.3		101.1
Add: effect of dilutive securities		1.8		0.5		0.1
Diluted average number of common shares outstanding		136.9		129.8		101.2
Basic EPS from continuing operations	$	1.55	$	1.16	$	1.16
Diluted EPS from continuing operations	$	1.53	$	1.15	$	1.16

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.

The computation of diluted EPS for 2008 excludes anti-dilutive shares consisting of 364,217 performance shares, 530,398 restricted stock shares and 455,469 stock options.

Dividends Declared

In February 2011, Great Plains Energy’s Board of Directors (Board) declared a quarterly dividend of $0.2075 per share on Great Plains Energy’s common stock. The common dividend is payable March 21, 2011, to shareholders of record as of February 28, 2011. The Board also declared regular dividends on Great Plains Energy’s preferred stock, payable June 1, 2011, to shareholders of record as of May 10, 2011.

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

SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Supplemental Cash Flow Information

2.	SUPPLEMENTAL CASH FLOW INFORMATION

Great Plains Energy Other Operating Activities
	2010			2009			2008
Cash flows affected by changes in:	(millions)
Receivables	$	(12.6	)	$	7.9		$	61.9
Accounts receivable pledged as collateral		(95.0	)		-			-
Fuel inventories		(0.1	)		2.0			(16.7	)
Materials and supplies		(11.5	)		(22.0	)		(3.7	)
Accounts payable		12.8			(70.9	)		56.2
Accrued taxes		6.7			42.2			73.2
Accrued interest		2.9			2.9			17.8
Deferred refueling outage costs		9.9			(7.1	)		(5.9	)
Accrued plant maintenance costs		1.7			2.9			2.1
Fuel adjustment clauses		2.7			7.8			(18.0	)
Pension and post-retirement benefit obligations		(10.2	)		18.4			3.1
Allowance for equity funds used during construction		(26.0	)		(39.6	)		(24.2	)
Write down of affordable housing investments		11.2			-			-
Iatan Nos. 1 and 2 impact of disallowed construction costs		16.8			-			-
Deferred acquisition costs		-			-			(15.8	)
Interest rate hedge settlements		(6.9	)		(79.1	)		(41.2	)
Other		(36.1	)		16.8			(36.4	)
Total other operating activities	$	(133.7	)	$	(117.8	)	$	52.4
Cash paid during the period:
Interest	$	237.7		$	211.9		$	95.0
Income taxes	$	0.9		$	5.1		$	27.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	44.9		$	82.8		$	104.7

KCP&L Other Operating Activities
	2010			2009			2008
Cash flows affected by changes in:	(millions)
Receivables	$	(4.1	)	$	(7.6	)	$	50.9
Accounts receivable pledged as collateral		(95.0	)		-			-
Fuel inventories		0.7			6.1			(16.0	)
Materials and supplies		(9.6	)		(16.5	)		(4.3	)
Accounts payable		0.8			(54.3	)		57.3
Accrued taxes		(15.7	)		51.8			81.3
Accrued interest		(0.5	)		8.6			8.5
Deferred refueling outage costs		9.9			(7.1	)		(5.9	)
Pension and post-retirement benefit obligations		7.9			39.3			(5.1	)
Allowance for equity funds used during construction		(21.9	)		(30.6	)		(22.5	)
Kansas Energy Cost Adjustment		(8.8	)		2.2			(1.6	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		13.0			-			-
Interest rate hedge settlements		-			(79.1	)		(41.2	)
Other		(4.5	)		21.1			(28.6	)
Total other operating activities	$	(127.8	)	$	(66.1	)	$	72.8
Cash paid during the period:
Interest	$	101.1		$	77.2		$	63.0
Income taxes	$	18.2		$	31.9		$	23.5
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	37.4		$	75.5		$	90.8

Significant Non-Cash Items

On January 1, 2010, Great Plains Energy and KCP&L adopted new accounting guidance for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivables pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s and KCP&L’s balance sheets at December 31, 2010. See Note 3 for additional information. 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 at December 31, 2010.

On July 14, 2008, Great Plains Energy closed its acquisition of GMO. The total purchase price of the acquisition was approximately $1.7 billion. The fair value of the 32.2 million shares of Great Plains Energy common stock issued was approximately $1.0 billion. Great Plains Energy paid approximately $0.7 billion of cash consideration.

In May 2008, KCP&L’s Series 2008 Environmental Improvement Revenue Refunding (EIRR) bonds totaling $23.4 million maturing in 2038 were issued. The proceeds were deposited with a trustee pending KCP&L’s submission of qualifying expenses for reimbursement. At December 31, 2008, KCP&L had received $13.4 million in cash proceeds and had a $10.0 million short-term receivable for the proceeds that were deposited with the trustee. In 2009, KCP&L received the remaining $10.0 million in cash.

In 2008, KCP&L recorded a $12.6 million net increase in AROs, consisting of a $14.2 million increase as a result of changes in cost estimates and timing used to compute the present value of asbestos AROs for KCP&L’s generating stations, with a corresponding increase in net utility plant and a decrease of $1.6 million resulting from an update to the cost estimates to decommission Wolf Creek, with a corresponding increase in regulatory liabilities. This activity had no impact on Great Plains Energy’s or KCP&L’s 2008 cash flows.

RECEIVABLES

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Receivables

3.	RECEIVABLES

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


	December 31
	2010			2009
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	62.0		$	47.3
Customer accounts receivable - unbilled		82.3			77.9
Allowance for doubtful accounts		(2.7	)		(2.8	)
Other receivables		100.1			108.1
Total	$	241.7		$	230.5
KCP&L
Customer accounts receivable - billed	$	6.5		$	-
Customer accounts receivable - unbilled		50.1			44.6
Allowance for doubtful accounts		(1.5	)		(1.7	)
Intercompany receivables		43.2			42.4
Other receivables		71.1			76.4
Total	$	169.4		$	161.7

Great Plains Energy’s and KCP&L’s other receivables at December 31, 2010 and 2009, 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. On January 1, 2010, Great Plains Energy and KCP&L adopted new accounting guidance for transfers of financial assets, which resulted in the sale of the undivided percentage ownership interest in accounts receivable by Receivables Company no longer meeting the criteria for derecognition and now being accounted for as a secured borrowing. As a result, $95.0 million of accounts receivables pledged as collateral are recognized with a corresponding short-term collateralized note payable on Great Plains Energy’s and KCP&L’s balance sheets at December 31, 2010.

KCP&L sells its receivables at a fixed price based upon the expected cost of funds and charge-offs. These costs comprise KCP&L’s loss on the sale of accounts receivable. KCP&L services the receivables and receives an annual servicing fee of 1.5% to 2.5% 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. In February 2011, the agreement was amended to extend the expiration date of the agreement from May 2011 to October 2011.

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


				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	)		-


					Receivables			Consolidated
2009		KCP&L			Company			KCP&L
		(millions)
Receivables (sold) purchased		$	(1,172.4	)	$	1,172.4		$	-
Gain (loss) on sale of accounts receivable (a)			(14.8	)		14.6			(0.2	)
Servicing fees			2.0			(2.0	)		-
Fees to outside investor			-			(1.2	)		(1.2	)

Cash flows during the period
Cash from customers transferred to Receivables Company			(1,167.6	)		1,167.6			-
Cash paid to KCP&L for receivables purchased			1,153.0			(1,153.0	)		-
Servicing fees			2.0			(2.0	)		-
Interest on intercompany note			0.4			(0.4	)		-
(a)	Any net gain (loss) is the result of the timing difference inherent in collecting receivables and
	over the life of the agreement will net to zero.

ASSETS HELD FOR SALE

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Assets Held for Sale

4.	ASSETS HELD FOR SALE

As of December 31, 2009, Great Plains Energy had several real estate properties available for immediate sale in their present condition and management was actively marketing these properties. The carrying amounts for these assets were presented at fair value less estimated selling cost and were included in assets held for sale on Great Plains Energy’s consolidated balance sheets as of December 31, 2009. In March 2010, one of the properties with a book value of $0.6 million was sold resulting in an insignificant loss on the sale. In October 2010, one of the properties included in the electric utility segment with a book value of $11.1 million was sold resulting in an insignificant gain on the sale. As of December 31, 2010, management determined that the sale of the remaining properties was no longer considered probable. Accordingly, the $7.7 million of properties were reclassified from assets held for sale to other-investments and other assets on the consolidated balance sheet as of December 31, 2010.

NUCLEAR PLANT

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Nuclear Plant

5.	NUCLEAR PLANT

KCP&L owns 47% of Wolf Creek, its only nuclear generating unit. Wolf Creek is regulated by the Nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety-related requirements.

Spent Nuclear Fuel and High-Level Radioactive Waste

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kWh of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel. These disposal costs are charged to fuel expense. In March 2010, the DOE filed a motion to withdraw its application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada, which would bring the licensing process to an end. An NRC board denied the DOE’s motion to withdraw its application in June 2010, and the DOE appealed that decision to the full NRC in early July 2010. The NRC has not yet decided that appeal. The question of the DOE’s legal authority to withdraw its license application also is pending in multiple lawsuits filed with a federal appellate court. Oral argument to the court is set for late March 2011. 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 16 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 2008 and is the basis for the current cost of decommissioning estimates in the table below. KCC issued its order in August 2009 approving the 2008 decommissioning cost study, and approved funding levels in its order issued in November 2010. The MPSC does not explicitly approve or disapprove of the decommissioning cost study and issued its order approving the funding levels in May 2009.


		Total	KCP&L's
		Station	47% Share
		(millions)
Current cost of decommissioning (in 2008 dollars)		$ 594	$ 279
Future cost of decommissioning (in 2045-2053 dollars) (a)		2,575	1,210

Annual escalation factor		3.73%
Annual return on trust assets (b)		6.83%
(a)	Total future cost over an eight year decommissioning period.
(b)	The 6.83% rate of return is through 2025. The rate then systematically decreases through 2053 to 1.87%
	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 2010 and 2009, KCP&L contributed approximately $3.7 million 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 decommissioning trust fund.


December 31	2010		2009
Decommissioning Trust	(millions)
Beginning balance January 1	$	112.5	$	96.9
Contributions		3.7		3.7
Earned income, net of fees		2.0		2.8
Net realized gains/(losses)		6.7		(5.5	)
Net unrealized gains		4.3		14.6
Ending balance	$	129.2	$	112.5

The decommissioning trust is reported at fair value on the balance sheets and is invested in assets as detailed in the following table. At December 31, 2009, KCP&L was holding short-term investments in the decommissioning trust fund, which were invested in equity securities in early 2010 as a result of a change in the asset allocation of the trust to a higher proportion of equity securities given the 20-year extension of Wolf Creek’s operating license approved by the NRC in November 2008.


	December 31
	2010				2009
		Gross	Gross			Gross	Gross
	Cost	Unrealized	Unrealized	Fair	Cost	Unrealized	Unrealized	Fair
	Basis	Gains	Losses	Value	Basis	Gains	Losses	Value
	(millions)
Equity securities	$ 73.4	$ 13.1	$ (1.0)	$ 85.5	$ 36.3	$ 8.9	$ (0.7)	$ 44.5
Debt securities	38.1	2.6	(0.1)	40.6	35.3	2.1	-	37.4
Other	3.1	-	-	3.1	30.6	-	-	30.6
Total	$ 114.6	$ 15.7	$ (1.1)	$ 129.2	$ 102.2	$ 11.0	$ (0.7)	$ 112.5

The weighted average maturity of debt securities held by the trust at December 31, 2010, was approximately 7.6 years. The costs of securities sold are determined on the basis of specific identification. The following table summarizes the realized gains and losses from the sale of securities by the nuclear decommissioning trust fund.


	2010			2009			2008
	(millions)
Realized Gains	$	7.3		$	2.8		$	2.7
Realized Losses		(0.6	)		(8.3	)		(10.9	)

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, regardless of the number of acts 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, 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 adverse 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 $26.2 million ($12.3 million, KCP&L’s 47% share) per policy year.

REGULATORY MATTERS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Regulatory Matters

6.	REGULATORY MATTERS

KCP&L’s Comprehensive Energy Plan

KCP&L’s Comprehensive Energy Plan included construction of Iatan No. 2, wind generation, environmental upgrades at certain coal-fired generating stations, infrastructure investments, and energy efficiency, affordability and demand response programs. With the construction of Iatan No. 2 completed in 2010, the remaining component of KCP&L’s Comprehensive Energy Plan is to obtain state regulatory approval to include the cost of Iatan No. 2 in rate base and begin recovering the investment in rates.

In August 2010, Iatan No. 2 successfully completed in-service testing, which was confirmed by KCC in October 2010, but is still subject to confirmation by the MPSC, which is expected during the current Missouri rate cases.

In the fourth quarter of 2010, Great Plains Energy and KCP&L completed a final cost estimate for Iatan No. 2. The final cost estimate and previous cost estimate ranges are shown in the following table. The cost estimate ranges do not include AFUDC or the cost of common facilities that were identified at the time of the start-up of the Iatan No. 1 environmental project that will be used by both Iatan No. 1 and Iatan No. 2.


	Final Cost			Previous Estimate
	Estimate Range			Range			Change
	(millions)
Great Plains Energy's 73% share of Iatan No. 2	$ 1,203	-	$ 1,218	$ 1,222	-	$ 1,251	$ (19)	-	$ (33)
KCP&L's 55% share of Iatan No. 2	905	-	917	919	-	941	(14)	-	(24)

Kansas Regulatory Proceedings

In December 2009, KCP&L filed a request with KCC to increase retail electric annual revenues by $55.2 million. The request was subsequently adjusted by KCP&L during the rate case proceedings to $50.9 million as the net result of updates to the case. The request included costs related to Iatan No. 2, a new coal-fired generation unit, upgrades to the transmission and distribution system to improve reliability and overall increased costs of service.

In November 2010, KCC issued its order, effective December 1, 2010, 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. The $22.0 million annual revenue increase is considered as interim subject to refund or true-up pending the outcome of the reconsideration proceedings regarding rate case expenses. Also in February 2011, KCP&L and another party to the case filed petitions for judicial review with the Court of Appeals of the State of Kansas, which are stayed until conclusion of the reconsideration proceedings. The rates authorized by KCC will be effective unless and until modified by KCC or stayed by a court.

Accounting rules state that when it becomes probable that part of the cost of a recently completed plant will be disallowed for rate-making purposes and a reasonable estimate of the amount of the disallowance can be made, the estimated amount of the probable disallowance shall be deducted from the reported cost of the plant and recognized as a loss. As a result of disallowances in the KCC order, KCP&L recognized Kansas jurisdictional losses of $4.4 million for construction costs related to Iatan No. 2 and $2.0 million for construction costs related to the Iatan No. 1 environmental project. Management determined it is probable that the MPSC would disallow these costs as well in KCP&L’s and GMO’s pending rate cases. Therefore, KCP&L’s Missouri jurisdictional portion and GMO’s portion of these costs were recognized as a loss in addition to the KCP&L Kansas jurisdictional portion resulting in a $16.8 million pre-tax loss representing KCP&L’s and GMO’s combined share for construction costs incurred through December 31, 2010.

Missouri Regulatory Proceedings

The following table summarizes pending requests for retail rate increases with the MPSC.

Annual

Revenue

Return on

Rate-Making

Rate Jurisdiction

File Date

Increase

Equity

Equity Ratio

(millions)

KCP&L - Missouri (a)

6/4/2010

92.1

(b)

11.00

(b)

46.16

(b)

GMO - Missouri Public Service division (a)

6/4/2010

75.8

(c)

11.00

(c)

46.16

(c)

GMO - St. Joseph Light & Power division (a)

6/4/2010

22.1

(d)

11.00

(d)

46.16

(d)

(a)

The request includes costs related to Iatan No. 2, a new coal-fired generation unit, upgrades to the transmission

and distribution system to improve reliability and overall increased costs of service. For KCP&L, it also includes

increased coal transportation costs due to the expiration in 2010 of the majority of KCP&L's current coal

transportation contracts. Any authorized changes to retail rates are expected to be effective in May 2011 for

KCP&L and June 2011 for GMO.

(b)

The requested increase was adjusted by KCP&L in a February 22, 2011, filing with the MPSC to $55.8 million

mainly due to lower fuel and purchased power costs, as there is no fuel recovery mechanism, and increased

deferred income taxes from bonus depreciation. The lower fuel and purchased power costs were driven by more

favorable coal transportation costs and lower actual 2010 fuel and purchased power costs than the amounts

included in the June 4, 2010, initial request. The requested return on equity was adjusted by KCP&L to 10.75%

and the rate-making equity ratio was adjusted to 46.286%.

(c)

The requested increase was adjusted by GMO in a February 22, 2011, filing with the MPSC to $65.2 million as

the net result of updates to the case. The requested return on equity was adjusted by GMO to 10.75% and the

rate-making equity ratio was adjusted to 46.286%.

(d)

The requested increase was adjusted by GMO in a February 22, 2011, filing with the MPSC to $23.2 million as

the net result of updates to the case. The requested return on equity was adjusted by GMO to 10.75% and the

rate-making equity ratio was adjusted to 46.286%.

In September 2010, GMO received an order from the MPSC approving construction accounting for the Iatan No. 2 project from the Iatan No. 2 in-service date to the effective date of new rates in the current rate case. The effect of the order is to defer GMO’s share of Iatan No. 2 operating costs, depreciation expense and carrying costs (interest) offset by Iatan No. 2’s system energy value to a regulatory asset rather than impacting the income statement until new rates are effective. KCP&L (Missouri jurisdiction only) was granted construction accounting as part of the Comprehensive Energy Plan.

In November 2010, the MPSC staff filed its construction audit and prudence review regarding construction expenditures through June 30, 2010, for Iatan No. 2 and the Iatan No. 1 environmental project. The MPSC staff recommended disallowances of approximately $130 million and $70 million of the total costs incurred through June 30, 2010, for Iatan No. 2 and the Iatan No. 1 environmental project, respectively, representing all audited expenditures above the associated December 2006 control budget estimates of approximately $1.685 billion and $377 million.

The MPSC staff also filed testimony in KCP&L’s and GMO’s rate cases in November 2010. The MPSC staff’s testimony recommended a return on equity range of 8.5% to 9.5% and revenue increase/(decrease) ranges of approximately $(0.2) million to $14 million for KCP&L, approximately $0.9 million to $10.1 million for GMO’s Missouri Public Service division, and approximately $28.8 million to $32.6 million for GMO’s St. Joseph Light & Power division. On February 22, 2011, the MPSC Staff filed updated testimony recommending the same return on equity range of 8.5% to 9.5% and revenue increase ranges of approximately $2.2 million to $17.0 million for KCP&L, approximately $29,000 to $9.2 million for GMO's Missouri Public Service division, and approximately $14.9 million to $18.4 million for GMO's St. Joseph Light & Power division. The revenue recommendations reflect the MPSC staff’s proposed construction cost disallowancesof all audited expenditures as of October 31, 2010, above the control budget estimates, among other differences from KCP&L’s and GMO’s requests.

Hearings were held beginning in late January 2011 for KCP&L and ran through mid-February 2011 for GMO. The MPSC Staff will file reconciliations of the differences between its February 22, 2011, recommendations and KCP&L's and GMO's February 22, 2011, recommendations with hearings scheduled for March 3 - 4, 2011. New rates are expected to go into effect in May 2011 for KCP&L and June 2011 for GMO.

SPP and NERC Audits

In November 2009, the Southwest Power Pool, Inc. (SPP) and the North American Electric Reliability Corporation (NERC) conducted scheduled audits of KCP&L and GMO regarding compliance with NERC reliability and critical infrastructure protection standards. KCP&L and GMO received the final audit report alleging violation of certain standards and management anticipates paying a penalty that will have an immaterial impact to cash flows and results of operations. The SPP also conducted a compliance inquiry regarding a transmission system outage that occurred in the St. Joseph, Missouri area in the summer of 2009. NERC is also investigating the circumstances surrounding this transmission system outage. The outcome of the outage inquiry cannot be predicted at this time.

Energy Efficiency

Great Plains Energy and KCP&L have implemented various energy efficiency programs. KCP&L also agreed in the Collaboration Agreement to pursue initiatives, including energy efficiency, designed to offset CO2 emissions. The Companies currently recover energy efficiency program expenses on a deferred basis with no recovery mechanism for associated lost revenues. An MPSC rulemaking proceeding in Missouri to address recovery of and earnings on investments in energy efficiency programs is near completion with final rules expected to be effective in the second quarter of 2011. Great Plains Energy and KCP&L will evaluate alternatives for future energy efficiency programs under these new rules.

MPSC Regulatory Approval of the GMO Acquisition

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

GMO Missouri 2007 Rate Case Appeal

Appeals of the May 2007 MPSC order approving an approximate $59 million increase in annual revenues were filed in July and August of 2007 with the Circuit Court of Cole County, Missouri, by the Office of Public Counsel, AG Processing, Sedalia Industrial Energy Users’ Association and AARP seeking to set aside or remand the order of the MPSC. In February 2009, the Circuit Court affirmed the MPSC order. The Circuit Court’s decision was affirmed by the Court of Appeals in August 2009. The case was transferred to the Missouri Supreme Court in August 2010. In December 2010, the Missouri Supreme Court re-transferred the case to the Court of Appeals, Western District, which re-adopted its opinion and re-affirmed the MPSC order on January 4, 2011. The Company does not currently expect any further action with respect to this matter.

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 is 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, 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	(a)		0.7	(a)		5.7
Cost of removal		8.5			-			8.5
Asset retirement obligations		27.5			12.8			40.3
Pension settlements		9.0	(b)		-			9.0
Pension and post-retirement costs		377.1	(c)		106.7	(c)		483.8
Deferred customer programs		44.7	(d)		15.6			60.3
Rate case expenses		12.3	(e)		3.3	(e)		15.6
Skill set realignment costs		4.8	(f)		-			4.8
Fuel adjustment clauses		8.4	(e)		37.1	(e)		45.5
Acquisition transition costs		29.3	(g)		22.5	(g)		51.8
St. Joseph Light & Power acquisition		-			2.6	(h)		2.6
Storm damage		-			3.2	(i)		3.2
Derivative instruments		-			3.1	(j)		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		15.1	(k)		4.3	(l)		19.4
Iatan No. 2 construction accounting costs		17.2	(l)		6.5	(l)		23.7
Other		3.5	(m)		0.7	(m)		4.2
Total	$	679.6		$	244.4		$	924.0
Regulatory Liabilities
Emission allowances	$	85.9		$	0.5		$	86.4
Asset retirement obligations		44.9			-			44.9
Pension		-			37.1			37.1
Cost of removal		-			62.8	(n)		62.8
Other		10.5			16.5			27.0
Total	$	141.3		$	116.9		$	258.2

(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)	$5.0 million not included in rate base and amortized through 2012.

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

(d)	$13.2 million not included in rate base and amortized over various periods.

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

(f)	$2.8 million not included in rate base and amortized through 2017.

(g)

Not included in rate base. The MPSC order provided for the deferral of transition costs to be amortized over a five-year period to the extent that synergy savings exceed transition cost amortization. The Company settled its first post-transaction rate cases and the settlement agreements did not address transition costs. The Company will continue to defer transition costs until amortization is ordered by the MPSC. KCC order approved the deferral of up to $10.0 million of transition costs to be amortized over a five-year period beginning with rates effective in December 2010.

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

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

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

(k)	$11.6 million not included in rate base and under consideration in the pending Missouri rate case.

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

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

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


					Great
December 31, 2009	KCP&L		GMO		Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	77.6	$	22.9	$	100.5
Loss on reacquired debt		5.3		0.3		5.6
Cost of removal		7.9		-		7.9
Asset retirement obligations		23.8		11.9		35.7
Pension settlements		13.5		-		13.5
Pension and post-retirement costs		395.0		84.5		479.5
Deferred customer programs		35.6		7.1		42.7
Rate case expenses		7.4		1.5		8.9
Skill set realignment costs		6.1		-		6.1
Fuel adjustment clauses		0.7		47.5		48.2
Acquisition transition costs		29.3		22.2		51.5
St. Joseph Light & Power acquisition		-		3.1		3.1
Storm damage		-		4.8		4.8
Derivative instruments		-		2.1		2.1
Iatan No. 1 and Common facilities depreciation and carrying costs		4.6		1.4		6.0
Other		5.3		0.8		6.1
Total	$	612.1	$	210.1	$	822.2
Regulatory Liabilities
Emission allowances	$	86.2	$	0.8	$	87.0
Asset retirement obligations		33.4		-		33.4
Pension		-		34.0		34.0
Cost of removal		-		62.5		62.5
Other		7.3		13.6		20.9
Total	$	126.9	$	110.9	$	237.8

GOODWILL AND INTANGIBLE ASSETS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Goodwill and Intangible Assets

7.	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, 2010. 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, 2010						December 31, 2009
	Gross Carrying			Accumulated			Gross Carrying			Accumulated
		Amount		Amortization				Amount		Amortization
KCP&L		(millions)
Computer software		$	168.2	$	(118.0	)		$	147.0	$	(106.3	)
Transmission line			5.8		-				-		-

Great Plains Energy
Computer software		$	201.1	$	(137.3	)		$	170.8	$	(117.8	)
Transmission line and upgrades			27.9		(4.4	)			22.1		(3.7	)
Organization start-up costs			0.1		-				0.1		-

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


	2010		2009
	(millions)
Great Plains Energy	$	13.1	$	10.9
KCP&L		12.2		10.4

The following table provides the estimated amortization expense related to Great Plains Energy’s and KCP&L’s intangible assets for 2011 through 2015 for the intangible assets included in the consolidated balance sheets at December 31, 2010.


	2011		2012		2013		2014		2015
	(millions)
Great Plains Energy	$	12.7	$	10.8	$	8.4	$	5.0	$	2.9
KCP&L		11.9		10.0		7.6		4.3		2.3

- Definition

Discloses 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 or 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. This element may be used as a single block of text to include the entire intangible asset disclosure including data and tables.

+ References+ Details

ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Asset Retirement Obligations

8.	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.

Management has 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
	2010		2009			2010		2009
	(millions)
Beginning balance	$	132.6	$	124.3		$	119.8	$	111.9
Additions		2.0		1.2			2.0		0.6
Revision in timing and/or estimates		-		(1.0	)		-		-
Accretion		8.7		8.1			7.9		7.3
Ending balance	$	143.3	$	132.6		$	129.7	$	119.8

PENSION PLANS AND OTHER EMPLOYEE BENEFITS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Pension Plans and Other Employee Benefits

9.	PENSION PLANS AND OTHER EMPLOYEE BENEFITS

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

KCP&L and GMO record pension expense in accordance with rate orders from the MPSC and KCC that allow the difference between pension costs under GAAP and pension 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 pension plans.

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. The cost of post-retirement benefits charged to KCP&L and GMO are accrued during an employee's years of service and recovered through rates.

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. As a result of the GMO acquisition on July 14, 2008, the Company’s 2008 pension and post-retirement expenses under GAAP increased $2.4 million and $1.1 million, respectively. The underfunded status of the pension and other post-retirement benefit plans transferred at the date of acquisition was $48.9 million. 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
	2010			2009			2010			2009
Change in projected benefit obligation (PBO)	(millions)
PBO at beginning of year	$	836.3		$	772.5		$	148.9		$	135.4
Service cost		30.3			29.1			3.8			4.1
Interest cost		49.3			47.3			8.8			8.3
Contribution by participants		-			-			5.6			5.3
Amendments		0.5			5.7			-			3.4
Actuarial (gain) loss		55.1			33.1			(12.5	)		3.9
Benefits paid		(60.1	)		(49.3	)		(11.0	)		(11.5	)
Settlements		-			(2.1	)		-			-
PBO at end of plan year	$	911.4		$	836.3		$	143.6		$	148.9
Change in plan assets
Fair value of plan assets at beginning of year	$	488.2		$	418.7		$	52.0		$	38.9
Actual return on plan assets		62.7			75.1			0.5			0.7
Contributions by employer and participants		64.5			42.1			23.9			22.0
Benefits paid		(57.8	)		(47.7	)		(10.6	)		(9.6	)
Fair value of plan assets at end of plan year	$	557.6		$	488.2		$	65.8		$	52.0
Funded status at end of year	$	(353.8	)	$	(348.1	)	$	(77.8	)	$	(96.9	)
Amounts recognized in the consolidated balance sheets
Current pension and other post-retirement liability	$	(3.1	)	$	(3.7	)	$	(1.0	)	$	(0.9	)
Noncurrent pension liability and other post-retirement liability		(350.7	)		(344.4	)		(76.8	)		(96.0	)
Net amount recognized before regulatory treatment		(353.8	)		(348.1	)		(77.8	)		(96.9	)
Accumulated OCI or regulatory asset/liability		403.2			386.2			54.8			74.0
Net amount recognized at December 31	$	49.4		$	38.1		$	(23.0	)	$	(22.9	)
Amounts in accumulated OCI or regulatory asset/liability
not yet recognized as a component of net periodic cost:
Actuarial loss	$	219.5		$	227.8		$	8.5		$	19.3
Prior service cost		15.3			19.4			44.1			51.3
Transition obligation		-			0.1			3.0			4.3
Other		168.4			138.9			(0.8	)		(0.9	)
Net amount recognized at December 31	$	403.2		$	386.2		$	54.8		$	74.0


	Pension Benefits									Other Benefits
	2010			2009			2008			2010			2009			2008
Components of net periodic benefit costs	(millions)
Service cost	$	30.3		$	29.1		$	20.8		$	3.8		$	4.1		$	1.7
Interest cost		49.3			47.3			37.6			8.8			8.3			5.7
Expected return on plan assets		(36.6	)		(32.4	)		(38.6	)		(2.1	)		(1.6	)		(1.0	)
Prior service cost		4.6			4.2			4.2			7.2			6.9			2.7
Recognized net actuarial (gain) loss		37.4			36.3			32.3			(0.1	)		(0.4	)		0.6
Transition obligation		0.1			0.1			0.1			1.3			1.3			1.2
Settlement charges		-			0.1			-			-			-			-
Net periodic benefit costs before
regulatory adjustment		85.1			84.7			56.4			18.9			18.6			10.9
Regulatory adjustment		(32.3	)		(28.4	)		(3.5	)		-			(0.3	)		-
Net periodic benefit costs		52.8			56.3			52.9			18.9			18.3			10.9
Other changes in plan assets and benefit
obligations recognized in OCI or
regulatory assets/liabilities (a)
Current year net (gain) loss		29.1			(9.2	)		227.1			(10.9	)		(0.2	)		6.0
Amortization of gain (loss)		(37.4	)		(36.3	)		(39.9	)		0.1			0.4			(0.7	)
Prior service cost		0.5			5.7			-			-			24.8			18.7
Amortization of prior service cost		(4.6	)		(4.2	)		(5.2	)		(7.2	)		(6.9	)		(3.4	)
Transition obligation		-			-			-			-			1.2			-
Amortization of transition obligation		(0.1	)		(0.1	)		-			(1.3	)		(1.3	)		(1.4	)
Other regulatory activity		29.5			10.1			52.8			0.1			(3.1	)		2.1
Total recognized in OCI or regulatory asset/liability		17.0			(34.0	)		234.8			(19.2	)		14.9			21.3
Total recognized in net periodic benefit costs
and OCI or regulatory asset/liability	$	69.8		$	22.3		$	287.7		$	(0.3	)	$	33.2		$	32.2
(a) 2008 includes the effect of the remeasurement adjustment

For financial reporting purposes, the estimated prior service cost, net loss and transition costs for the defined benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2011 are $4.5 million, $38.5 million and $0.1 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 2011 are $7.2 million, $(1.0) million and $1.3 million, respectively.

The accumulated benefit obligation (ABO) for all defined benefit pension plans was $808.8 million and $741.4 million at December 31, 2010 and 2009, respectively. The PBO, ABO and the fair value of plan assets at plan year-end are aggregated by funded and under funded plans in the following table.


	2010		2009
Pension plans with the ABO in excess of plan assets	(millions)
Projected benefit obligation	$	911.4	$	836.3
Accumulated benefit obligation		808.8		741.4
Fair value of plan assets		557.6		488.2
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 $21.1 million. The Company has segregated approximately $21.5 million of assets for this plan as of December 31, 2010, and expects to fund future benefit payments from these assets.

The expected long-term rate of return on plan assets represents the Company’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	2010	2009	2010	2009
Discount rate	5.54%	5.92%	5.50%	5.87%
Rate of compensation increase	4.08%	4.26%	4.06%	4.25%


Weighted average assumptions used to determine	Pension Benefits		Other Benefits
net costs for years ended at December 31	2010	2009	2010	2009
Discount rate	5.92%	6.11%	5.87%	6.10%
Expected long-term return on plan assets	8.00%	8.00%	4.25% *	4.00% *
Rate of compensation increase	4.26%	4.27%	4.25%	4.25%
* after tax

For pension benefits, the Company's 2011 projected weighted average long-term rate of return on plan assets is 7.3%, a 0.7% decrease from 2010. The reduction in the rate of return is expected to increase 2011 GAAP pension expense approximately $4 million.

The Company expects to contribute $104.6 million to the pension plans in 2011 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. The Company’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. The Company also expects to contribute $15.8 million to other post-retirement benefit plans in 2011, 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 2020.


	Pension		Other
	Benefits		Benefits
	(millions)
2011	$	71.4	$	8.4
2012		66.9		8.3
2013		66.2		8.4
2014		65.3		8.6
2015		67.9		8.6
2016-2020		370.0		47.7

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 28% U.S. large cap and small cap equity securities, 22% international equity securities, 37% fixed income securities, 7% real estate and 6% commodities. 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 the Company’s pension plan assets at December 31, 2010 and 2009, by asset category are in the following tables.


			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 notes		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


				Fair Value Measurements Using
Description		December 31 2009		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)	$	188.8	$	102.9	$	85.9	$	-
	International (b)		75.2		18.4		56.8		-
	Limited partnerships		0.1		-		-		0.1
	Real estate (c)		26.8		-		-		26.8
	Commodities (d)		17.6		-		17.6		-
	Fixed income securities
	Fixed income funds (e)		117.9		3.0		114.9		-
	U.S. Treasury notes		1.3		1.3		-		-
	U.S. Agency, state and local obligations		18.7		-		18.7		-
	U.S. corporate bonds (f)		25.5		0.9		24.6		-
	Foreign corporate bonds		1.2		-		1.2		-
	Hedge fund		2.4		-		-		2.4
	Total	$	475.5	$	126.5	$	319.7	$	29.3
	Cash equivalents - money market funds		12.7
	Total Pension Plans	$	488.2

(a)	At December 31, 2010 and 2009, this category is comprised of $90.5 million and $102.9 million, respectively, of traded
	mutual funds valued at daily listed prices and $68.0 million and $85.9 million, respectively, of institutional common/collective
	trust funds valued at daily Net Asset Values (NAV) per share.
(b)	At December 31, 2010 and 2009, this category is comprised of $39.4 million and $18.4 million, respectively, of traded mutual
	funds valued at daily listed prices and $83.0 million and $56.8 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, 2010 and 2009, this category is comprised of $23.0 million and $3.0 million, respectively, of traded mutual
	funds valued at daily listed prices and $125.7 million and $114.9 million, respectively, of institutional common/collective trust
	funds valued at daily NAV per share.
(f)	At December 31, 2010 and 2009, this category is comprised of $13.9 million and $13.0 million, respectively, of corporate
	bonds, $8.0 million and $9.3 million, respectively, of collateralized mortgage obligations and $2.3 million and $3.2 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 2010 and 2009.


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Real		Hedge			Limited
Description	Estate		Fund			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, issuances, 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


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Real			Hedge			Limited
Description	Estate			Fund			Partnerships			Total
	(millions)
Balance January 1, 2009	$	36.9		$	6.6		$	0.5		$	44.0
Actual return on plan assets
Relating to assets still held		(10.2	)		0.1			0.2			(9.9	)
Relating to assets sold		0.1			(1.3	)		-			(1.2	)
Purchase, issuances, and settlements		-			(3.0	)		(0.6	)		(3.6	)
Transfers in and/or out of Level 3		-			-			-			-
Balance December 31, 2009	$	26.8		$	2.4		$	0.1		$	29.3

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 entirely 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.

The fair values of the Company’s other post-retirement plan assets at December 31, 2010 and 2009, by asset category are in the following tables.


			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		21.7		-		21.7		-
State and local obligations		0.5		-		0.5		-
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 Measurements Using
Description		December 31 2009		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	$	0.8	$	0.8	$	-	$	-
	U.S. Agency		0.6		-		0.6		-
	Corporate bonds		1.0		-		1.0		-
	Mutual funds		0.1		0.1		-		-
	Total	$	2.5	$	0.9	$	1.6	$	-
	Cash and cash equivalents - money market funds		49.5
	Total Other Post-Retirement Benefit Plans	$	52.0

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The cost trend assumed for 2010 and 2011 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 the Company.

The effects of a one-percentage point change in the assumed health care cost trend rates, holding all other assumptions constant, at December 31, 2010, 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	$	0.2	$	(0.3	)
Effect on post-retirement benefit obligation		2.2		(2.1	)

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 $8.9 million, $8.8 million and $6.9 million in 2010, 2009 and 2008, respectively. KCP&L’s annual cost of the plans was approximately $6.5 million, $6.5 million and $5.8 million in 2010, 2009, and 2008, respectively.

- Definition

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

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 158

-Paragraph 7, 21, 22

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5, 6, 7, 8

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 8

-Subparagraph m

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 106

-Paragraph 518

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 87

-Paragraph 264

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph b

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph a

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph h

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph q

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

-Publisher FASB

-Name FASB Staff Position (FSP)

-Number FAS106-2

-Paragraph 20, 21, 22

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

-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 03-2

-Paragraph 8

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

-Publisher AICPA

-Name Accounting Principles Board Opinion (APB)

-Number 30

-Paragraph 26

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

-Publisher FASB

-Name Implementation Guide (Q and A)

-Number FAS88

-Paragraph 63

+ Details

EQUITY COMPENSATION

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Equity Compensation

10.	EQUITY COMPENSATION

Great Plains Energy’s Long-Term Incentive Plan is an equity compensation plan approved by Great Plains Energy’s shareholders. The Long-Term Incentive Plan permits the grant of restricted stock, stock options, limited stock appreciation rights, director shares, director deferred share units and performance shares to directors, officers and other employees of Great Plains Energy and KCP&L. The maximum number of shares of Great Plains Energy common stock that can be issued under the plan is 5.0 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 2011 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.


	2010		2009		2008
Great Plains Energy	(millions)
Compensation expense	$	4.3	$	6.3	$	9.0
Income tax benefits		1.0		1.6		2.7
KCP&L
Compensation expense		3.0		4.3		5.5
Income tax benefits		0.5		0.8		2.0

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 and Great Plains Energy’s stock price following the end of the performance period as compared to the stock price on the grant date. Compensation expense for performance shares issued subsequent to the amendment discussed below 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 2010, inputs for expected volatility, dividend yield and risk-free rates were 31%, 4.65%, and 1.2%, respectively.

Performance share activity for 2010 is summarized in the following table. Performance adjustment represents the number of shares of common stock related to performance shares ultimately issued that can vary from the number of performance shares initially granted depending on Great Plains Energy’s performance over stated performance periods and Great Plains Energy’s stock price following the end of the performance period as compared to the stock price on the grant date.


	Performance	Grant Date
	Shares	Fair Value*
Beginning balance	294,641	$ 13.62
Performance adjustment	(21,674)
Granted	231,598	23.37
Earned	(8,433)	10.87
Forfeited	(64,348)	20.54
Ending balance	431,784	18.01
* weighted-average

At December 31, 2010, the remaining weighted-average contractual term was 1.3 years. The weighted-average grant-date fair value of shares granted was $23.37, $15.04 and $26.22 in 2010, 2009 and 2008, respectively. At December 31, 2010, there was $2.5 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 2010 was insignificant. There were no performance shares earned and paid during 2009. The fair value of common stock issued related to performance shares earned and paid during 2008 was $1.6 million.

Amendment to Performance Shares

In May 2009, the independent members of the Board approved amendments to certain outstanding performance share agreements (Original Agreements) for the 2007-2009 and 2008-2010 performance periods. The Original Agreements, as amended, are referred to as the Amended Agreements. Due to changes in economic and financial market conditions since the Original Agreements were entered into, the Compensation and Development Committee (Committee) and Board determined that the Original Agreements no longer provided meaningful incentives.

The Original Agreements granted performance shares based on a single performance metric – the Company’s total shareholder return (TSR) as compared to the Edison Electric Institute TSR index for electric utility companies over the relevant performance periods. The Amended Agreements provide for a combination of performance shares and time-based restricted stock. In calculating the number of performance shares and restricted stock under the Amended Agreements, the value of the performance shares granted under the Original Agreements (determined as of the date of the original awards) was first reduced by two-thirds (for the 2007-2009 performance awards) and one-third (for the 2008-2010 performance awards). The resulting amounts were then divided by the fair market value (as defined in the Long-Term Incentive Plan) of Great Plains Energy stock on the amendment date to arrive at a number of shares, which was then divided equally between performance shares and restricted stock. The two equally weighted performance share award metrics under the Amended Agreements are funds from operations as a percentage of total adjusted debt and EPS, with the number of shares of common stock ultimately issued varying depending on Great Plains Energy’s performance over stated performance periods.

The performance shares under the Amended Agreements will be re-measured at fair value each reporting period, with compensation cost to be recorded at the greater of the grant-date fair value of the Original Agreements or the fair value of the Amended Agreements for the portion for which the requisite service has been rendered. The amendment resulted in an insignificant amount of incremental compensation cost for Great Plains Energy and KCP&L.

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 2010 is summarized in the following table.


	Nonvested	Grant Date
	Restricted Stock	Fair Value*
Beginning balance	612,587	$ 20.24
Granted and issued	130,137	17.80
Vested	(291,787)	25.00
Forfeited	(44,280)	17.99
Ending balance	406,657	16.23
* weighted-average

At December 31, 2010, the remaining weighted-average contractual term was 1.2 years. The weighted-average grant-date fair value of shares granted was $17.80, $14.36, and $26.09 during 2010, 2009 and 2008, respectively. At December 31, 2010, there was $2.8 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 $7.3 million, $5.4 million, and $2.2 million in 2010, 2009 and 2008, respectively.

Stock Options

Granted Under Long-Term Incentive Plan

Stock options were granted under the 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 Acquisition

GMO stock options outstanding on the July 14, 2008, acquisition date of GMO, were converted to Great Plains Energy stock options upon acquisition.

Stock option activity under all plans for 2010 is summarized in the following table. All stock options are fully vested at December 31, 2010.


		Exercise
Stock Options	Shares	Price*
Beginning balance	244,610	$ 36.73
Exercised	(917)	9.21
Forfeited or expired	(44,912)	55.97
Outstanding and exercisable at December 31, 2010	198,781	32.51
* weighted-average

The weighted-average grant-date fair value of options exercised for 2010 and 2009 was $9.21 and $11.53, respectively. The aggregate intrinsic value and cash received for options exercised in 2010 and 2009 was insignificant. At December 31, 2010, there were no in the money outstanding and exercisable options. The following table summarizes all outstanding and exercisable stock options as of December 31, 2010.

Outstanding and Exercisable Options
		Weighted Average
		Remaining	Weighted
Exercise	Number of	Contractual Life	Average
Price Range	Shares	in Years	Exercise Price
$23.91 - $27.73	189,852	1.0	$ 24.44
$181.11	3,998	0.1	181.11
$221.82 - $251.86	4,931	0.3	222.48
Total	198,781	0.9	32.51

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 2010 and 2009. Director Deferred Share Units activity for 2010 is summarized in the following table.


	Share	Grant Date
	Units	Fair Value*
Beginning balance	21,443	$ 22.36
Issued	17,620	17.21
Ending balance	39,063	20.04
* weighted-average

SHORT TERM BORROWINGS AND SHORT TERM BANK LINES OF CREDIT

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

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

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

Great Plains Energy’s $200 Million Revolving Credit Facility

Great Plains Energy’s $200 million revolving credit facility with a group of banks expires in August 2013. The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time. A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At December 31, 2010, Great Plains Energy was in compliance with this covenant. At December 31, 2010, Great Plains Energy had $9.5 million of outstanding cash borrowings with a weighted-average interest rate of 3.06% and had issued letters of credit totaling $15.8 million under the credit facility. At December 31, 2009, Great Plains Energy had $20.0 million of outstanding cash borrowings with a weighted-average interest rate of 0.68% and had issued letters of credit totaling $25.4 million under the credit facility.

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

KCP&L’s $600 million revolving credit facility with a group of banks to provide support for its issuance of commercial paper and other general corporate purposes expires in August 2013. Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities. A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At December 31, 2010, KCP&L was in compliance with this covenant. At December 31, 2010, KCP&L had $263.5 million of commercial paper outstanding, at a weighted-average interest rate of 0.41%, $24.4 million of letters of credit outstanding and no outstanding cash borrowings under the facility. At December 31, 2009, KCP&L had $186.6 million of commercial paper outstanding, at a weighted-average interest rate of 0.58%, $20.9 million of letters of credit outstanding and no outstanding cash borrowings under the facility.

GMO’s $450 Million Revolving Credit Facility

GMO’s $450 million revolving credit facility with a group of banks expires in August 2013. Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities. A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At December 31, 2010, GMO was in compliance with this covenant. At December 31, 2010, GMO had no outstanding cash borrowings and had issued letters of credit totaling $13.2 million under the credit facility. At December 31, 2009, GMO had $232.0 million of outstanding cash borrowings with a weighted-average interest rate of 1.50%, and had issued letters of credit totaling $13.2 million under the credit facility.

LONG TERM DEBT

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Long-Term Debt

12.	LONG-TERM DEBT

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


		December 31
	Year Due	2010			2009
KCP&L		(millions)
General Mortgage Bonds
4.90%* EIRR bonds	2012-2035	$	158.8		$	158.8
7.15% Series 2009A (8.59% rate**)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
5.125% EIRR Series 2007A-1	2035		63.3			63.3
2.625% EIRR Series 2007A-2	2035		10.0			10.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
6.50% Series	2011		150.0			150.0
5.85% Series (5.72% rate**)	2017		250.0			250.0
6.375% Series (7.49% rate**)	2018		350.0			350.0
6.05% Series (5.78% rate**)	2035		250.0			250.0
EIRR Bonds
4.90% Series 2008	2038		23.4			23.4
Other	2011-2018		3.3			3.5
Current maturities			(150.3	)		(0.2	)
Unamortized discount			(2.0	)		(2.1	)
Total KCP&L			1,629.7			1,779.9

Other Great Plains Energy
GMO First Mortgage Bonds
9.44% Series	2011-2021		12.4			13.5
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.298%*** Wamego Series 1996	2026		7.3			7.3
0.650%*** State Environmental 1993	2028		5.0			5.0
GMO Senior Notes
7.95% Series	2011		137.3			137.3
7.75% Series	2011		197.0			197.0
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			49.9			84.5
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate**)	2013		250.0			-
Great Plains Energy 6.875% Senior Notes (7.33% rate**)	2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes	2042		287.5			287.5
Current maturities			(335.4	)		(1.1	)
Unamortized discount			(0.5	)		(0.4	)
Total Great Plains Energy excluding current maturities		$	2,942.7		$	3,213.0
* Weighted-average interest rates at December 31, 2010
** Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
*** Variable rate

Amortization of Debt Expense

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


	2010		2009		2008
	(millions)
KCP&L	$	2.8	$	2.0	$	1.6
Other Great Plains Energy		3.6		2.4		1.0
Total Great Plains Energy	$	6.4	$	4.4	$	2.6

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. Mortgage bonds totaling $755.3 million were outstanding at December 31, 2010 and 2009.

In March 2010, KCP&L remarketed its 5.00% EIRR Series 2007A-2 general mortgage bonds maturing in 2035 totaling $10.0 million to a new fixed rate of 2.625% from April 1, 2010, through March 31, 2011.

KCP&L Municipal Bond Insurance Policies

KCP&L’s EIRR Bonds Series 2007A-1, 2007A-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. 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 first mortgage bonds, equal in principal amount to the principal amount of the EIRR Bonds Series 2007A-1, 2007A-2 and 2007B then outstanding. In 2009, KCP&L issued $146.5 million of Mortgage Bonds Series 2007 EIRR Insurer due 2035 to FGIC. 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, 2010, 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) resulting in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization. The bonds are not incremental debt for KCP&L but collateralize Syncora’s claim on KCP&L if Syncora was required to meet its obligation under the insurance agreement. In the event of a default under the insurance agreements, Syncora may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.

GMO First Mortgage Bonds

GMO has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented. The Indenture creates a mortgage lien on substantially all of GMO’s St. Joseph Light & Power division utility plant. Mortgage bonds totaling $12.4 million and $13.5 million, respectively, were outstanding at December 31, 2010 and 2009.

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% series and 7.75% series 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 2010, 2009 and 2008 was $34.6 million, $33.0 million and $15.8 million, respectively. Amortization for 2011 and 2012 is estimated at $33.8 million and $16.1 million, respectively.

Great Plains Energy 2.75% Senior Notes

In August 2010, Great Plains Energy issued $250.0 million of 2.75% unsecured Senior Notes, maturing in 2013. As a result of amortizing the loss recognized in Other Comprehensive Income (OCI) on Great Plains Energy’s Forward Starting Swaps (FSS), the effective interest rate is 3.67%.

Great Plains Energy 10.00% Equity Units Subordinated Notes

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, between December 15, 2011, and 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.


	2011		2012		2013		2014		2015
	(millions)
Great Plains Energy	$	485.7	$	513.9	$	263.1	$	1.5	$	15.5
KCP&L		150.3		12.7		0.4		0.4		14.4

At December 31, 2010, Great Plains Energy’s long-term debt maturities in 2011 and 2012 were $485.7 million and $513.9 million, respectively. In February 2011, repayment of GMO’s $137.3 million of 7.95% Senior Notes that matured in February 2011 reduced the 2011 long-term debt maturities to $348.4 million. Great Plains Energy is evaluating alternatives to refinance the remaining long-term debt, including issuing new 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.

COMMON SHAREHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Common Shareholders' Equity

13.	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.

In August 2008, Great Plains Energy entered into a Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC (BNYMCM). Under the terms of the agreement, Great Plains Energy may offer and sell up to 8.0 million shares of its common stock from time to time through BNYMCM, as agent, for a period of no more than three years. Great Plains Energy will pay BNYMCM a commission equal to 1% of the sales price of all shares sold under the agreement. No shares were sold during 2010. During 2009, 3.8 million shares were sold for $49.5 million in net proceeds. During 2008, 0.2 million shares were sold for $3.5 million in net proceeds.

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, 2010, 0.8 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 plans may be either newly issued shares or shares purchased in the open market. At December 31, 2010, 1.9 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, 2010, 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, 2010. The restrictions are not expected to affect the Companies’ ability to pay dividends at the current level in the foreseeable future.

- Definition

Disclosures related to accounts comprising shareholders' equity, including other comprehensive income. Includes: (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+ Details

PREFERRED STOCK

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Preferred Stock

14.	PREFERRED STOCK

At December 31, 2010, 1.6 million shares of Cumulative No Par Preferred Stock, 390,000 shares of Cumulative Preferred Stock, $100 par value and 11.0 million shares of no par Preference Stock were authorized under Great Plains Energy’s Articles of Incorporation. All of the 390,000 authorized shares of Cumulative Preferred Stock are issued and outstanding. Great Plains Energy has the option to redeem the $39.0 million of issued Cumulative Preferred Stock at prices ranging from 101% to 103.7% of par value. If Great Plains Energy voluntarily files for dissolution or liquidation, the Cumulative Preferred Stock holders are entitled to receive the redemption prices. If a proceeding for dissolution or liquidation is filed against Great Plains Energy, the Cumulative Preferred Stock holders are entitled to receive the $100 par value per share plus accrued and unpaid dividends.

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Commitments and Contingencies

15.	COMMITMENTS AND CONTINGENCIES

Environmental Matters

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

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

Air and Climate Change

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

Great Plains Energy’s and KCP&L’s current estimate of capital expenditures (exclusive of AFUDC and property taxes) to comply with the currently effective Clean Air Interstate Rule (CAIR) and with the best available retrofit technology (BART) rule is approximately $1 billion. As discussed below, CAIR has been remanded to the EPA, but remains in effect until the EPA issues final rules consistent with the court’s order or until the court takes further action. In July 2010, the EPA proposed the Transport Rule to replace CAIR. However, due to uncertainties regarding the proposal (discussed below), it is not possible to predict what the final rules may be, when the rules may be issued, or the costs associated with such rules. The actual cost of compliance with any future rules, and with BART, may be significantly different from the cost estimate provided.

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

Clean Air Interstate Rule (CAIR) and Transport Rule

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

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

CAIR currently establishes a market-based cap-and-trade program with an emission allowance allocation. Facilities demonstrate compliance with CAIR by holding sufficient allowances for each ton of SO2 and NOx emitted in any given year. KCP&L and GMO are currently allowed to utilize unused SO2 emission allowances that they have either accumulated during previous years of the Acid Rain Program or purchased to meet the more stringent CAIR requirements. At December 31, 2010, KCP&L had accumulated unused SO2 emission allowances sufficient to support over 135,000 tons of SO2 emissions (enough to support expected requirements under the current CAIR for the foreseeable future) under the provisions of the Acid Rain program, which are recorded in inventory at zero cost. At December 31, 2010, GMO had accumulated unused SO2 emission allowances sufficient to support just over 13,000 tons of SO2 emissions (enough to support expected requirements under the current CAIR through 2011), which it has received under the Acid Rain Program or purchased, and are recorded in inventory at average cost. KCP&L and GMO purchase NOx allowances as needed. Analysis of the current CAIR rule indicates that NOx and SO2 control may be required for KCP&L’s Montrose Station and GMO’s Sibley and Lake Road Stations in Missouri, and control may be achieved through a combination of pollution control equipment and the use or purchase of emission allowances as needed.

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

In January 2011, the EPA supplemented the record supporting the proposed Transport Rule. The EPA made available additional information relevant to the rulemaking, including, among other things, unit-level allowances for existing units calculated using two alternative methodologies and data supporting those calculations.

The proposed Transport Rule is complex and, as noted, contains alternative approaches. Great Plains Energy and KCP&L are unable to predict when the Transport Rule (or other rule replacing CAIR) might be adopted, or the actual requirements of such rule. Preliminary analysis of the Transport Rule has raised various questions regarding the emission allowances allocation to, and the allowable emission rates for, the Companies’ power plants pursuant to the preferred approach and alternatives, which the Companies addressed during the rule’s comment period. Regardless of the resolution of those questions, the Companies project that they may not be allocated sufficient SO2 or NOX emissions allowances to cover their currently expected operations starting in 2012 pursuant to the preferred approach. Any shortfall in allocated allowances would need to be addressed through permissible allowance trading, installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market, or a combination of these and other alternatives. While Great Plains Energy and KCP&L cannot reasonably predict at this time the impacts of the final Transport Rule, if it were finalized as currently proposed, the Companies expect that any required capital expenditures would not exceed the $1 billion estimate of capital expenditures (exclusive of AFUDC and property taxes) to comply with the currently effective CAIR and BART rule disclosed above. Any final rule could have a significant adverse effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Best Available Retrofit Technology (BART) Rule

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

Mercury and Other Hazardous Air Pollutant Emissions

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

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

In April 2010, the EPA, in a court approved settlement, agreed to develop MACT standards for mercury and potentially other hazardous air pollutant emissions. In the settlement agreement, the EPA agreed to propose MACT standards in March 2011 with final standards by November 2011. These MACT standards, if adopted, could impact KCP&L’s and GMO’s new and existing facilities.

Management cannot predict the outcome of further judicial, administrative or regulatory actions or their financial or operational effects on Great Plains Energy and KCP&L. Such actions could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows. Some of the control technology for SO2 and NOx could also aid in the control of mercury.

Industrial Boiler Rule

In April 2010, the EPA issued a proposed rule that would set MACT standards for hazardous air pollutants from industrial boilers. The proposed rule would establish emission limits for KCP&L’s and GMO’s new and existing units that produce steam other than for the generation of electricity. This proposed rule does not apply to KCP&L’s and GMO’s electricity generating boilers, but would apply to most of GMO’s Lake Road boilers, which also serve steam customers, and to auxiliary boilers at other generating facilities. The EPA finalized the rule in late February 2011. The financial and operational impacts to Great Plains Energy and KCP&L, which could be material, are being evaluated but cannot be determined at this time.

New Source Review

The Clean Air Act requires companies to obtain permits and, if necessary, install control equipment to reduce emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in regulated emissions.

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

Collaboration Agreement

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

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

KCP&L agreed in the Collaboration Agreement to seek a consent agreement, which it has done, with the Kansas Department of Health and Environment (KDHE) incorporating limits for stack particulate matter emissions, as well as limits for NOx and SO2 emissions at its LaCygne Station that will be below the presumptive limits under BART. KCP&L further agreed to use its best efforts to install emission control technologies to reduce those emissions from the LaCygne Station prior to the required compliance date under BART, but in no event later than June 1, 2015. KCP&L has issued requests for proposals for environmental equipment required to comply with BART at the LaCygne Station and is evaluating the responses. In February 2011, KCP&L filed a request with KCC for predetermination of the ratemaking treatment that will apply to the recovery of costs for its 50% share of the environmental equipment required to comply with BART at the LaCygne Station. The request for predetermination includes an estimated total project cost of $1.23 billion. KCP&L’s 50% share of the estimated cost is $615 million. In the Collaboration Agreement, KCP&L also agreed to offset an additional 711,000 tons of CO2 by the end of 2012. KCP&L currently expects to achieve this offset through a number of alternatives, including improving the efficiency of its coal-fired units, equipping certain gas-fired units for winter operation and, if necessary, possibly reducing output of, or retiring, one or more coal-fired units.

Climate Change

The Companies are subject to existing greenhouse gas reporting regulations and, as discussed below, will be subject to certain greenhouse gas permitting requirements starting in 2011. Management believes it is likely that additional federal or relevant state or local laws or regulations could be enacted to address global climate change. At the international level, while the United States is not a current party to the Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions. International agreements legally binding on the United States may be reached in the future. Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels. The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 28 million tons and 21 million tons per year for Great Plains Energy and KCP&L, respectively.

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

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

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

In December 2010, the EPA announced it entered into a proposed 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 would commit to issuing proposed regulations by July 2011, and final regulations by May 2012.

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

KCP&L and GMO project that their current renewable resources (including accumulated renewable energy credits) will be sufficient for compliance with the Missouri requirements, exclusive of the solar requirement, through 2017 and 2015, respectively. KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri requirements through 2011. The Companies have issued requests for proposals for compliance with the solar requirement beyond 2011 and are evaluating the proposals. KCP&L and GMO continue to evaluate options for compliance beyond these years.

KCP&L also projects that its current renewable resources (including accumulated renewable energy credits) combined with the 48MW wind project and 52MW of renewable energy credits discussed above will be sufficient for compliance with the 2011 Kansas requirements. KCP&L issued requests for proposals to add up to 100MW of wind generation in 2012 and is evaluating the proposals.

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

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

Ozone NAAQS

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

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

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

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

SO2 NAAQS

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

Montrose Station Notice of Violation

In June 2009, KCP&L received notification from the MDNR alleging that its Montrose Station had excess particulate matter emissions in 2008. KCP&L is working with the MDNR to resolve this issue and management believes the outcome will have an insignificant impact to Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Water

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

Section 316(b) of the Clean Water Act is designed to protect aquatic life from being killed or injured by cooling water intake structures. The EPA had previously issued regulations pursuant to Section 316(b) of the Clean Water Act regarding cooling water intake structures. Subsequent to an appellate court ruling, the EPA suspended the regulations and is engaged in further rulemaking on this matter. In December 2010, in a court approved settlement, the EPA agreed to propose a new rule in March 2011 and to finalize it in July 2012. At this time, management is unable to predict how the EPA will respond or how that response will impact Great Plains Energy’s and KCP&L’s operations.

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

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

Solid Waste

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

Remediation

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

At December 31, 2010 and 2009, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site. At December 31, 2010 and 2009, 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, 2010, Great Plains Energy had $2.1 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB sites and retained liabilities. This estimate was based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary. This estimate could change materially after further investigation, and could also be affected by the actions of environmental agencies and the financial viability of other potentially responsible parties.

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

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

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

Contractual Commitments

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


	2010		2009		2008
	(millions)
Great Plains Energy	$	17.2	$	23.4	$	20.7
KCP&L	$	13.2	$	19.3	$	18.1

Great Plains Energy’s and KCP&L’s contractual commitments at December 31, 2010, excluding pensions and long-term debt, are detailed in the following tables.

Great Plains Energy
	2011		2012		2013		2014		2015		After 2015		Total
Lease commitments	(millions)
Operating lease	$	17.9	$	16.8	$	15.0	$	14.3	$	13.5	$	129.4	$	206.9
Capital lease		0.4		0.4		0.4		0.4		0.4		5.5		7.5
Purchase commitments
Fuel		348.7		282.7		287.7		164.8		108.8		125.3		1,318.0
Purchased capacity		20.3		13.4		12.4		4.5		4.2		2.4		57.2
Non-regulated natural gas
transportation		4.6		2.9		2.9		2.9		2.9		3.4		19.6
Other		163.4		17.6		6.8		8.1		2.7		55.1		253.7
Total contractual commitments	$	555.3	$	333.8	$	325.2	$	195.0	$	132.5	$	321.1	$	1,862.9

KCP&L
	2011		2012		2013		2014		2015		After 2015		Total
Lease commitments	(millions)
Operating lease	$	14.1	$	13.1	$	12.7	$	12.5	$	12.1	$	129.4	$	193.9
Capital lease		0.2		0.2		0.2		0.2		0.2		3.2		4.2
Purchase commitments
Fuel		296.8		241.5		249.1		144.4		104.9		125.3		1,162.0
Purchased capacity		5.5		4.7		3.7		2.9		3.0		1.2		21.0
Other		127.5		15.0		6.0		7.3		1.9		40.8		198.5
Total contractual commitments	$	444.1	$	274.5	$	271.7	$	167.3	$	122.1	$	299.9	$	1,579.6

Great Plains Energy has expected sublease income of $2.0 million for the years 2011-2013. Lease commitments end in 2032. Operating lease commitments include rail cars to serve jointly-owned generating units where KCP&L is the managing partner. KCP&L will be reimbursed by the other owners for approximately $2.0 million per year ($13.7 million total) of the amounts included in the table above.

Fuel commitments consist of commitments for nuclear fuel, coal and coal transportation. 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 $6.9 million for 2011, $3.8 million for 2012, and $1.6 million for 2013. Non-regulated natural gas transportation consists of MPS Merchant’s commitments. Other represents individual commitments entered into in the ordinary course of business.

LEGAL PROCEEDINGS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Legal Proceedings

16.	LEGAL PROCEEDINGS

KCP&L Hawthorn No. 5 Litigation

KCP&L received reimbursement for the 1999 Hawthorn No. 5 boiler explosion under a property damage insurance policy with Travelers Property Casualty Company of America (Travelers). Travelers filed suit in the U.S. District Court for the Eastern District of Missouri in November 2005, against National Union Fire Insurance Company of Pittsburgh, Pennsylvania, (National Union) and KCP&L was added as a defendant in June 2006. The case was subsequently transferred to the U.S. District Court for the Western District of Missouri. Travelers sought recovery of $10 million that KCP&L recovered through subrogation litigation. On July 24, 2008, the Court held that Travelers is not entitled to any recovery from KCP&L. Travelers appealed this decision on March 11, 2009, to the Court of Appeals for the Eighth Circuit. In September 2010, the Court of Appeals affirmed the District Court’s decision. The Company does not currently expect any further action with respect to this matter.

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 of the U.S. Court of Federal Claims to the U.S. Court of Appeals for the Federal Circuit.

KCP&L Advanced Coal Credit Arbitration

In July 2009, KCP&L was served a notice to arbitrate by The Empire District Electric Company (Empire), Kansas Electric Cooperative, Inc. (KEPCO) and Missouri Joint Municipal Electric Utility Commission (MJMEUC), the non-Company joint owners of Iatan No. 2. These joint owners asserted that they were entitled to receive proportionate shares (or the monetary equivalent) of approximately $125 million of qualifying advance coal project credits for Iatan No. 2. As independent entities, the joint owners are taxed separately and the non-Company joint owners do not dispute that they did not, in fact, apply for the credits themselves. Notwithstanding this, they contended that they should receive proportional shares of the credit. On December 30, 2009, an arbitration panel issued its order denying the KEPCO and MJMEUC claims but ordering KCP&L and Empire to jointly seek a reallocation of the tax credit from the IRS giving Empire its representative percentage of the total tax credit, worth approximately $17.7 million. The order further specified that if the IRS denies the parties’ reallocation request or if Empire is allocated less than its proportionate share of the tax credits, KCP&L will be responsible for paying Empire the full value of its representative percentage of the tax credits (less the amount of tax credits, if any, Empire ultimately receives) in cash. In September 2010, the IRS issued an amended memorandum of understanding to reallocate $17.7 million of the original $125 million of the advanced coal project credits to Empire, meeting the requirements of the arbitration order issued on December 30, 2009. KCP&L subsequently dismissed its March 31, 2010, appeal of the arbitration order. In 2010, KCP&L reversed a $17.7 million liability previously recorded in other current liabilities for this matter.

Iatan Levee Litigation

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

GMO Price Reporting Litigation

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

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

In October 2006, the MPSC filed suit in the Circuit Court of Jackson County, Missouri against 18 companies, including GMO and MPS Merchant alleging that the companies manipulated natural gas prices through the misreporting of natural gas trade data and, therefore, violated Missouri antitrust laws. The suit does not specify alleged damages and was filed on behalf of all local distribution gas companies in Missouri who bought and sold natural gas from June 2000 to October 2002. The defendants’ motions to dismiss the case were granted in January 2009. In February 2009, the MPSC appealed the dismissal to the Missouri Court of Appeals for the Western District of Missouri. In December 2009, the Missouri Court of Appeals affirmed the dismissal and the MPSC filed a request for rehearing or, in the alternative, transfer to the Missouri Supreme Court. The Missouri Supreme Court accepted the transfer in April 2010, but in September 2010, transferred the case back to the Court of Appeals, which then reaffirmed its earlier opinion. The Company does not currently expect any further action with respect to this matter.

GUARANTEES

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Guarantees

17.	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, 2010, Great Plains Energy has provided $1,030.4 million of credit support for GMO as follows:

·	Great Plains Energy direct guarantees to GMO counterparties totaling $65.4 million, of which $45.4 million expire in 2011 and $20.0 million expire in 2012,

·	Great Plains Energy letters of credit to GMO counterparties totaling $15.8 million , which expire in 2011, and

·	Great Plains Energy guarantee of GMO long-term debt totaling $949.2 million, which includes debt with maturity dates ranging from 2011-2023.

Great Plains Energy has also guaranteed GMO’s $450 million revolving line of credit dated August 9, 2010, with a group of banks, expiring August 9, 2013. At December 31, 2010, GMO had no outstanding cash borrowings and had issued letters of credit totaling $13.2 million under this facility.

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

18.	RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO’s business and operate its facilities at cost. These costs totaled $100.9 million for 2010, $102.7 million for 2009 and $41.0 million for 2008, subsequent to the July 14, 2008, acquisition of GMO. 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
	2010	2009
	(millions)
Receivable from GMO	$ 29.6	$	26.4
Payable to Great Plains Energy Services Incorporated	-		(0.2	)
Receivable from Great Plains Energy	13.3		15.1
Receivable from MPS Merchant	0.3		0.9

- Definition

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

+ References+ Details

DERIVATIVE INSTRUMENTS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Derivative Instruments

19.	DERIVATIVE INSTRUMENTS

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

Great Plains Energy and KCP&L have posted collateral, in the ordinary course of business, for the aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a liability position. At December 31, 2010, Great Plains Energy and KCP&L have posted collateral in excess of the aggregate fair value of its derivative instruments; therefore, if the credit risk-related contingent features underlying these agreements were triggered, Great Plains Energy and KCP&L would not be required to post additional collateral to its counterparties.

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

Interest Rate Risk Management

In August 2010, Great Plains Energy issued $250.0 million of long-term debt and settled two FSS simultaneously with the issuance of the long-term fixed rate debt. Great Plains Energy had entered into the two FSS with notional amounts of $125.0 million to hedge against interest rate fluctuations on a portion of the August 2010 debt issuance. The two FSS were treated as cash flow hedges with no ineffectiveness recorded in 2010 or 2009. A pre-tax loss of $6.9 million was recorded to OCI and is being reclassified to interest expense over the life of the three-year debt. At December 31, 2010, $0.9 million of the loss has been reclassified from OCI to interest expense.

In December 2009 and January 2010, Great Plains Energy entered into five FSS with total notional amounts of $350.0 million to hedge against interest rate fluctuations on debt anticipated to be issued in 2011. The five FSS remove a portion of the interest rate variability on $350.0 million of the debt expected to be issued thereby enabling Great Plains Energy to predict with greater assurance its future interest costs on that debt. The five FSS are treated as cash flow hedges with no ineffectiveness in 2010 or 2009. At December 31, 2010, a $20.8 million loss was recorded in OCI for the five FSS. The FSS will settle simultaneously with the issuance of the underlying long-term debt expected to be issued. Any gain or loss on the settlement will be recorded to OCI and reclassified to interest expense over the life of the debt.

Commodity Risk Management

KCP&L’s risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales. At December 31, 2010, KCP&L has hedged 66%, 45% and 22%, respectively, of the 2011, 2012 and 2013 projected natural gas usage for retail load and firm MWh sales, primarily by utilizing futures contracts and financial instruments. The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense. KCP&L has not recorded any ineffectiveness on natural gas hedges in 2010, 2009 or 2008.

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, 2010, GMO had financial contracts in place to hedge approximately 67%, 45% and 38% of the expected on-peak natural gas and natural gas equivalent purchased power price exposure for 2011, 2012 and 2013, respectively. In connection with GMO’s 2005 Missouri electric rate case, it was agreed that the settlement costs of these contracts would be recognized in fuel expense. The settlement cost is included in GMO’s FAC. A regulatory asset has been recorded to reflect the change in the timing of recognition authorized by the MPSC. To the extent recovery of actual costs incurred is allowed, amounts will not impact earnings, but will impact cash flows due to the timing of the recovery mechanism.

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

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


	December 31
	2010					2009
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	4.0	$	-		$	3.2	$	-
Non-hedging derivatives		59.5		(2.5	)		29.8		(0.9	)
Forward contracts
Non-hedging derivatives		202.8		8.9			234.4		9.1
Option contracts
Cash flow hedges		-		-			2.3		0.2
Non-hedging derivatives		0.2		-			-		-
Anticipated debt issuance
Forward starting swaps		350.0		(20.8	)		362.5		(0.7	)
KCP&L
Futures contracts
Cash flow hedges		4.0		-			3.2		-
Option contracts
Cash flow hedges		-		-			2.3		0.2

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

Great Plains Energy
	Balance Sheet	Asset Derivatives	Liability Derivatives
December 31, 2010	Classification	Fair Value	Fair Value
Derivatives Designated as Hedging Instruments		(millions)
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

December 31, 2009
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$ 0.4	$ 0.2
Interest rate contracts	Derivative instruments	-	0.7
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments	9.9	1.7
Total Derivatives		$ 10.3	$ 2.6

KCP&L
	Balance Sheet	Asset Derivatives	Liability Derivatives
December 31, 2010	Classification	Fair Value	Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$ 0.1	$ 0.1

December 31, 2009
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$ 0.4	$ 0.2

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

2009
Interest rate contracts	$ 0.4	Interest charges	$ (8.0)
Commodity contracts	(0.8)	Fuel	(1.1)
Income tax benefit (expense)	0.1	Income tax benefit (expense)	3.5
Total	$ (0.3)	Total	$ (5.6)

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

2009
Interest rate contracts	$ 1.0	Interest charges	$ (7.5)
Commodity contracts	(0.8)	Fuel	(1.1)
Income tax benefit (expense)	(0.1)	Income tax benefit (expense)	3.3
Total	$ 0.1	Total	$ (5.3)

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

Great Plains Energy
Derivatives in Regulatory Account Relationship
		Gain (Loss) Reclassified from
		Regulatory Account
	Amount of Gain (Loss)
	Recognized on Regulatory
	Account on Derivatives	Income Statement
	(Effective Portion)	Classification	Amount
	(millions)		(millions)
2010
Commodity contracts	$ (8.2)	Fuel	$ (7.2)
Total	$ (8.2)	Total	$ (7.2)

2009
Commodity contracts	$ (12.8)	Fuel	$ (20.5)
Total	$ (12.8)	Total	$ (20.5)

Great Plains Energy’s income statement reflects a loss for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $0.2 million for 2010 and a gain of $1.6 million for 2009.

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
	2010			2009			2010			2009
	(millions)
Current assets	$	12.0		$	13.3		$	12.0		$	13.3
Current liabilities		(101.5	)		(84.9	)		(71.6	)		(81.2	)
Noncurrent liabilities		-			(0.5	)		-			-
Deferred income taxes		34.8			28.0			23.2			26.4
Total	$	(54.7	)	$	(44.1	)	$	(36.4	)	$	(41.5	)

Great Plains Energy’s accumulated OCI in the table above at December 31, 2010, includes $15.6 million that is expected to be reclassified to expenses over the next twelve months. KCP&L’s accumulated OCI includes $8.8 million that is expected to be reclassified to expense over the next twelve months.

The amounts reclassified to expenses for 2008 are summarized in the following table.


	2008
Great Plains Energy	(millions)
Fuel expense	$	(2.3	)
Interest expense		2.8
Income tax expense		(0.2	)
Income (loss) from discontinued operations
Purchased power expense		(106.1	)
Income taxes		43.8
OCI	$	(62.0	)
KCP&L
Fuel expense	$	(2.3	)
Interest expense		2.5
OCI	$	0.2

FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Fair Value Measurements

20.	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 and certain debt securities within KCP&L’s decommissioning trust fund 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, 2010 and 2009.


							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	$	-


							Fair Value Measurements Using
Description	December 31 2009			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)		$	0.2	$	(0.2	)	$	0.2	$	0.2	$	-
Nuclear decommissioning trust (b)
Equity securities			44.5		-			44.5		-		-
Debt securities
U.S. Treasury			11.2		-			11.2		-		-
U.S. Agency			3.5		-			-		3.5		-
State and local obligations			3.1		-			-		2.9		0.2
Corporate bonds			18.9		-			-		18.9		-
Foreign governments			0.7		-			-		0.7		-
Other			1.2		-			-		1.2		-
Total nuclear decommissioning trust			83.1		-			55.7		27.2		0.2
Total			83.3		(0.2	)		55.9		27.4		0.2
Liabilities
Derivative instruments (a)			-		(0.2	)		-		0.2		-
Total		$	-	$	(0.2	)	$	-	$	0.2	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)		$	9.2	$	(0.7	)	$	0.7	$	5.1	$	4.1
SERP rabbi trust (c)
Equity securities			0.2		-			0.2		-		-
Debt securities			6.9		-			-		6.9		-
Total SERP rabbi trust			7.1		-			0.2		6.9		-
Total			16.3		(0.7	)		0.9		12.0		4.1
Liabilities
Derivative instruments (a)			0.8		(1.6	)		1.6		0.8		-
Total		$	0.8	$	(1.6	)	$	1.6	$	0.8	$	-
Great Plains Energy
Assets
Derivative instruments (a)		$	9.4	$	(0.9	)	$	0.9	$	5.3	$	4.1
Nuclear decommissioning trust (b)			83.1		-			55.7		27.2		0.2
SERP rabbi trust (c)			7.1		-			0.2		6.9		-
Total			99.6		(0.9	)		56.8		39.4		4.3
Liabilities
Derivative instruments (a)			0.8		(1.8	)		1.6		1.0		-
Total		$	0.8	$	(1.8	)	$	1.6	$	1.0	$	-

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

(b)	Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $2.7 million and $29.4 million at December 31, 2010 and 2009, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(c)	Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $14.6 million and $16.2 million at December 31, 2010 and 2009, 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, 2010 and 2009, Great Plains Energy netted $2.5 million and $0.9 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 2010 and 2009.


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
					Other
					Great			Great
					Plains			Plains
		KCP&L			Energy			Energy
	State & Local				Derivative
		Obligations			Instruments			Total
		(millions)
Balance January 1, 2010		$	0.2		$	4.1		$	4.3
Total realized/unrealized gains or (losses)
Included in non-operating income			-			(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 and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at December 31, 2010		$	-		$	0.1		$	0.1


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
													Other
													Great			Great
													Plains			Plains
	KCP&L												Energy			Energy
							Mortgage
	U.S.			State & Local			Backed						Derivative
Description	Agency				Obligations		Securities			Total			Instruments			Total
	(millions)
Balance January 1, 2009	$	3.9			$	-	$	2.9		$	6.8		$	3.8		$	10.6
Total realized/unrealized gains or (losses)
Included in regulatory liability		-				-		1.1			1.1			-			1.1
Included in non-operating income		-				-		-			-			1.2			1.2
Purchase, issuances, and settlements		(3.9	)			-		(4.0	)		(7.9	)		(0.9	)		(8.8	)
Transfers in and/or out of Level 3		-				0.2		-			0.2			-			0.2
Balance December 31, 2009	$	-			$	0.2	$	-		$	0.2		$	4.1		$	4.3

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at December 31, 2009	$	-			$	-	$	-		$	-		$	0.8		$	0.8

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 is derived from tax credits and potential cash distributions from the partnerships upon sales of the underlying properties. All of the tax credits have been received and management does not anticipate receiving any cash distributions from the partnership; therefore, management concluded that the investments were impaired and that the impairment was other than temporary since the partnerships are in the process of liquidating over the next 2 – 3 years. As a result of the evaluation, management concluded that the cost method investments have 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.

- Definition

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

+ References+ Details

TAXES

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Taxes

21.

TAXES

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


Great Plains Energy	2010			2009			2008
Current income taxes	(millions)
Federal	$	(7.4	)	$	(11.1	)	$	(21.0	)
State		(4.3	)		(0.9	)		1.1
Foreign		0.1			1.3			-
Total		(11.6	)		(10.7	)		(19.9	)
Deferred income taxes
Federal		99.8			(13.6	)		3.3
State		24.0			10.0			40.8
Total		123.8			(3.6	)		44.1
Noncurrent income taxes
Federal		(4.8	)		8.3			(0.6	)
State		(1.8	)		1.1			(1.0	)
Foreign		0.5			(1.5	)		-
Total		(6.1	)		7.9			(1.6	)
Investment tax credit
Deferral		(4.2	)		37.2			74.2
Amortization		(2.9	)		(2.2	)		(1.8	)
Total		(7.1	)		35.0			72.4
Total income tax expense		99.0			28.6			95.0
Less: taxes on discontinued operations
Current tax expense		-			(1.1	)		25.8
Deferred tax expense		-			0.2			4.5
Noncurrent income tax expense		-			-			0.9
Income tax expense on continuing operations	$	99.0		$	29.5		$	63.8


KCP&L	2010			2009			2008
Current income taxes	(millions)
Federal	$	5.5		$	41.2		$	(8.0	)
State		1.1			4.8			4.5
Total		6.6			46.0			(3.5	)
Deferred income taxes
Federal		69.8			(41.7	)		(38.4	)
State		13.4			3.5			30.9
Total		83.2			(38.2	)		(7.5	)
Noncurrent income taxes
Federal		(1.6	)		3.4			(1.7	)
State		(0.3	)		(0.1	)		(0.3	)
Total		(1.9	)		3.3			(2.0	)
Investment tax credit
Deferral		(4.2	)		37.2			74.2
Amortization		(2.1	)		(1.4	)		(1.4	)
Total		(6.3	)		35.8			72.8
Total	$	81.6		$	46.9		$	59.8

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	2010			2009			2008			2010			2009			2008
	(millions)
Federal statutory income tax	$	108.7		$	63.4		$	64.2			35.0	%		35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		(5.2	)		(9.9	)		(5.4	)		(1.7	)		(5.5	)		(2.9	)
Amortization of investment tax credits		(2.9	)		(2.2	)		(1.8	)		(0.9	)		(1.2	)		(1.0	)
Federal income tax credits		(12.5	)		(8.0	)		(10.2	)		(4.1	)		(4.4	)		(5.6	)
State income taxes		11.4			7.9			3.2			3.7			4.4			1.8
Rate change on deferred taxes		-			-			19.3			-			-			10.5
Medicare Part D subsidy legislation		2.8			-			-			0.9			-			-
Changes in uncertain tax positions, net		0.3			(72.1	)		0.1			0.1			(39.8	)		0.1
GMO transaction costs		-			-			(1.9	)		-			-			(1.0	)
Valuation allowance		(2.7	)		55.8			-			(0.9	)		30.8			-
Other		(0.9	)		(5.4	)		(3.7	)		(0.3	)		(3.0	)		(2.1	)
Total	$	99.0		$	29.5		$	63.8			31.8	%		16.3	%		34.8	%


	Income Tax Expense									Income Tax Rate
KCP&L	2010			2009			2008			2010			2009			2008
	(millions)
Federal statutory income tax	$	85.7		$	61.5		$	64.7			35.0	%		35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		(4.5	)		(7.7	)		(5.2	)		(1.8	)		(4.4	)		(2.8	)
Amortization of investment tax credits		(2.1	)		(1.4	)		(1.4	)		(0.9	)		(0.8	)		(0.8	)
Federal income tax credits		(8.5	)		(7.8	)		(9.8	)		(3.5	)		(4.4	)		(5.3	)
State income taxes		8.9			5.8			3.8			3.6			3.3			2.1
Medicare Part D subsidy legislation		2.8			-			-			1.1			-			-
Changes in uncertain tax positions, net		-			(0.5	)		(0.6	)		-			(0.3	)		(0.3	)
Parent company tax benefits (a)		-			-			(6.7	)		-			-			(3.6	)
Rate change on deferred taxes		-			-			20.3			-			-			11.0
Other		(0.7	)		(3.0	)		(5.3	)		(0.2	)		(1.7	)		(3.0	)
Total	$	81.6		$	46.9		$	59.8			33.3	%		26.7	%		32.3	%
(a) The tax sharing between Great Plains Energy and its subsidiaries was modified on July 14, 2008. As part of the new
agreement, parent company tax benefits are no longer allocated to KCP&L or other subsidiaries.

Great Plains Energy and KCP&L are required to adjust deferred tax assets and liabilities to reflect tax rates that are anticipated to be in effect when timing differences reverse. Due to the 2008 sale of Strategic Energy, L.L.C. (Strategic Energy), the composite tax rate for the companies was expected to increase as a result of the change in composition of states that Great Plains Energy conducts business. Therefore, deferred tax assets and liabilities were adjusted in 2008 to reflect the expected increase in the composite tax rate. The impact of the increase in the composite tax rate on deferred tax assets and liabilities resulted in tax expense for Great Plains Energy and KCP&L of $19.3 million and $20.3 million, respectively, at December 31, 2008.

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	2010			2009			2010			2009
Current deferred income taxes	(millions)
Net operating loss carryforward	$	-		$	30.4		$	-		$	-
Other		14.7			7.8			5.6			0.3
Net current deferred income tax asset before
valuation allowance		14.7			38.2			5.6			0.3
Valuation allowance		(0.4	)		(1.4	)		-			-
Net current deferred income tax asset		14.3			36.8			5.6			0.3
Noncurrent deferred income taxes
Plant related		(975.5	)		(854.7	)		(711.5	)		(631.0	)
Income taxes on future regulatory recoveries		(142.6	)		(104.5	)		(117.2	)		(77.6	)
Derivative instruments		46.0			39.3			34.4			37.4
Pension and postretirement benefits		(16.3	)		(4.5	)		2.0			6.5
SO2 emission allowance sales		30.8			30.3			33.4			34.5
Fuel clause adjustments		(16.6	)		(17.6	)		(3.2	)		0.2
Transition costs		(20.0	)		(19.9	)		(11.4	)		(11.4	)
Tax credit carryforwards		204.3			202.4			101.5			97.6
Long-term debt fair value adjustment		19.2			32.5			-			-
Customer demand programs		(23.3	)		(16.5	)		(17.3	)		(13.8	)
Net operating loss carryforward		409.2			361.3			1.1			0.6
Other		(7.3	)		(1.6	)		(3.8	)		(2.4	)
Net noncurrent deferred tax liability before
valuation allowance		(492.1	)		(353.5	)		(692.0	)		(559.4	)
Valuation allowance		(26.2	)		(28.4	)		-			-
Net noncurrent deferred tax liability		(518.3	)		(381.9	)		(692.0	)		(559.4	)
Net deferred income tax liability	$	(504.0	)	$	(345.1	)	$	(686.4	)	$	(559.1	)


	Great Plains Energy						KCP&L
December 31	2010			2009			2010			2009
	(millions)
Gross deferred income tax assets	$	1,140.7		$	1,126.4		$	602.4		$	597.9
Gross deferred income tax liabilities		(1,644.7	)		(1,471.5	)		(1,288.8	)		(1,157.0	)
Net deferred income tax liability	$	(504.0	)	$	(345.1	)	$	(686.4	)	$	(559.1	)

Tax Credit Carryforwards

At December 31, 2010 and 2009, Great Plains Energy had $102.6 million and $98.7 million, respectively, of federal general business income tax credit carryforwards. At December 31, 2010 and 2009, KCP&L had $101.5 million and $97.6 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 years 2028 to 2030. 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, 2010 and 2009, Great Plains Energy had $90.0 million and $87.6 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, 2010 and 2009, Great Plains Energy had $11.8 million and $16.2 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 years 2011 to 2015. Management expects that a portion of these credits will expire unutilized and has provided a valuation allowance against $0.6 million of the state income tax benefit.

Advanced Coal Credit

In April 2008, KCP&L was notified that its application filed in 2007 for $125.0 million in advanced coal investment tax credits (ITC) was approved by the IRS. The credit is based on the amount of expenses incurred on the construction of Iatan No. 2. Additionally, in order to meet the advanced clean coal standards and avoid forfeiture and/or the recapture of tax credits in the future, KCP&L must meet or exceed certain environmental performance standards for at least five years once the plant is placed in service.

In September 2010, the IRS issued an amended memorandum of understanding to reallocate $17.7 million of the original $125 million of the advanced coal project credits to Empire, meeting the requirements of an arbitration order issued on December 30, 2009. See Note 16 for the related legal proceeding. As a result, Great Plains Energy and KCP&L reduced the amount of advanced coal credit previously recognized. The amount of deferred federal tax expense associated with the reduction in 2010, was $4.2 million. Since the tax laws require KCP&L to reduce income tax expense for ratemaking and financial statement purposes ratably over the life of the plant, Great Plains Energy and KCP&L concurrently recognized a separate deferred advanced coal ITC benefit to offset the current and deferred federal tax expense. Great Plains Energy and KCP&L recognized $0.7 million of ITC in 2010 after the plant was placed in service and will continue to recognize the tax benefits over the life of the plant. At December 31, 2010, Great Plains Energy and KCP&L had $106.6 million of deferred advanced coal ITC.

Net Operating Loss Carryforwards

At December 31, 2010 and 2009, Great Plains Energy had $353.0 million and $337.5 million, respectively, of tax benefits related to federal net operating loss (NOL) carryforwards. Approximately $317.5 million and $320.5 million, at December 31, 2010 and 2009, respectively, are tax benefits related to NOLs that were acquired in the GMO acquisition. The tax benefits for NOLs originating in 2003 are $34.4 million, $152.4 million originating in 2004, $74.1 million originating in 2005, $53.3 million originating in 2006, $1.3 million originating in 2007, $2.5 million originating in 2008, $26.9 million originating in 2009 and $8.1 million originating in 2010. The federal NOL carryforwards expire in years 2023 to 2030.

In addition, Great Plains Energy also had deferred tax benefits of $56.2 million and $54.2 million related to state NOLs as of December 31, 2010 and 2009, respectively. Approximately $49.4 million and $49.9 million at December 31, 2010 and 2009, respectively, were acquired in the GMO acquisition. Management does not expect to utilize $25.7 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 $25.7 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 2010 and 2009, $3.2 million of tax benefit and $6.5 million of tax expense, respectively, on continuing operations was recorded and primarily relates to a portion of the valuation allowance against federal and state NOL carryforwards. The remaining valuation allowances against federal and state NOL carryforwards and tax credit carryforwards were acquired in the GMO acquisition and were recorded as a part of the purchase accounting entries impacting goodwill.

Uncertain Tax Positions

At December 31, 2010 and 2009, Great Plains Energy had $42.0 million and $51.4 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $17.3 million at December 31, 2010 and 2009, is expected to impact the effective tax rate if recognized. The $9.4 million decrease in unrecognized tax benefits is 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, 2008, Great Plains Energy had $97.3 million of liabilities related to unrecognized tax benefits of which $80.2 million is expected to impact the effective rate if recognized. The $45.9 million decrease in unrecognized tax benefits in 2009 was primarily due to a decrease of unrecognized tax benefits of $74.5 million related to the Joint Committee on Taxation approval of the IRS audit for GMO’s 2003-2004 tax years, offset by an increase of $11.3 million of unrecognized tax benefits related to prior year tax positions taken on GMO tax returns, and a $20.5 million increase of unrecognized tax benefits related to Great Plains Energy consolidated 2008 and 2009 tax years. The tax benefits recognized related to the 2003-2004 IRS audit were also offset by an increase in valuation allowance for federal and state net operating losses of $56.0 million and a reduction in deferred income tax assets of $2.5 million, which resulted in an increase to net income of $16.0 million in 2009 related to the 2003-2004 IRS audit.

At December 31, 2010 and 2009, KCP&L had $19.1 and $20.9 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $0.3 million at December 31, 2010, and $0.4 million at December 31, 2009, are expected to impact the effective tax rate if recognized. The $1.8 million decrease in unrecognized tax benefits is primarily due to a $2.6 million decrease as a result of the settlements of the IRS audit for the Great Plains Energy consolidated 2005 tax year. At December 31, 2008, KCP&L had $17.6 million of liabilities related to unrecognized tax benefits of which $1.1 million is 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
		2010			2009			2008			2010			2009			2008
		(millions)
Balance at January 1		$	51.4		$	97.3		$	21.9		$	20.9		$	17.6		$	19.6
Additions for current year tax positions			2.7			13.2			5.3			1.3			3.9			3.8
Additions for prior year tax positions			2.1			8.2			2.6			1.5			3.0			2.6
Additions for GMO prior year tax positions			-			11.6			77.0			-			-			-
Reductions for prior year tax positions			(10.6	)		(1.3	)		(0.8	)		(1.6	)		(0.8	)		(0.7	)
Settlements			(3.8	)		(76.7	)		(8.5	)		(2.9	)		(2.2	)		(7.5	)
Statute expirations			(0.3	)		(0.7	)		(0.2	)		(0.1	)		(0.6	)		(0.2	)
Foreign currency translation adjustments			0.5			(0.2	)		-			-			-			-
Balance at December 31		$	42.0		$	51.4		$	97.3		$	19.1		$	20.9		$	17.6

Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses. At December 31, 2010, 2009 and 2008, accrued interest related to unrecognized tax benefits for Great Plains Energy was $6.7 million, $5.9 million and $2.6 million, respectively. Amounts accrued for penalties with respect to unrecognized tax benefits was $1.1 million at December 31, 2010 and 2009. In 2010 and 2009, Great Plains Energy recognized an increase of $0.5 million and $1.4 million, respectively, of interest expense related to unrecognized tax benefits. The remaining increase in accrued interest and the penalties of $1.1 million were primarily associated with prior year GMO tax return positions identified and recorded to goodwill. In 2008, Great Plains Energy recognized a reduction in interest expense of $6.6 million.

KCP&L had accrued interest related to unrecognized tax benefits of $1.4 million at December 31, 2010 and $1.7 million at December 31, 2009 and 2008. Amounts accrued for penalties with respect to unrecognized tax benefits for KCP&L are insignificant. In 2010, KCP&L recognized a reduction of $0.3 million of interest expense. In 2008, KCP&L recognized a reduction of $1.7 million of interest expense.

The IRS is currently auditing Great Plains Energy and its subsidiaries for the 2006-2008 tax years and the Company is protesting an audit assessment by the Canada Revenue Authority (CRA) against a former GMO subsidiary for the 2002 tax year. The Company estimates that it is reasonably possible that $18.2 million for Great Plains Energy and $12.2 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.

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. The Company also files separate company returns in Canada and certain other states.

SEGMENTS AND RELATED INFORMATION

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Segments and Related Information

22.	SEGMENTS AND RELATED INFORMATION

Great Plains Energy

Great Plains Energy has one reportable segment based on its method of internal reporting, which generally segregates reportable segments based on products and services, management responsibility and regulation. The one reportable business segment is electric utility, consisting of KCP&L and GMO’s regulated utility operations. Other includes GMO activity other than its regulated utility operations, Strategic Energy discontinued 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. For segment reporting, the segment’s income taxes include the effects of allocating holding company tax benefits prior to July 14, 2008. GMO is only included for periods subsequent to the July 14, 2008, date of acquisition. 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
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	)
Loss from equity investments		-			(1.0	)		(1.0	)
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	)
Loss from equity investments		-			(0.4	)		(0.4	)
Discontinued operations		-			(1.5	)		(1.5	)
Net income (loss) attributable to Great Plains Energy		157.8			(7.7	)		150.1


	Electric						Great Plains
2008	Utility			Other			Energy
	(millions)
Operating revenues	$	1,670.1		$	-		$	1,670.1
Depreciation and amortization		(235.0	)		-			(235.0	)
Interest charges		(96.9	)		(14.4	)		(111.3	)
Income tax (expense) benefit		(70.9	)		7.1			(63.8	)
Loss from equity investments		-			(1.3	)		(1.3	)
Discontinued operations		-			35.0			35.0
Net income attributable to Great Plains Energy		143.1			11.4			154.5


	Electric Utility								Great Plains
	Electric Utility		Other		Eliminations				Energy
2010	(millions)
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
2008
Assets	$	8,161.9	$	141.7		$	(434.3	)		$	7,869.3
Capital expenditures (a)		1,023.7		1.2			-				1,024.9

(a) Includes capital expenditures from discontinued operations of $0.8 million.

DISCONTINUED OPERATIONS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Discontinued Operations

23.	DISCONTINUED OPERATIONS

On June 2, 2008, Great Plains Energy completed the sale of Strategic Energy to Direct Energy Services, LLC (Direct Energy), a subsidiary of Centrica plc. Great Plains Energy received gross cash proceeds of $307.7 million, including the base purchase price of $300.0 million, plus a working capital adjustment of $7.7 million. Strategic Energy is reported as discontinued operations for the periods presented.

Under the terms of the purchase agreement with Direct Energy, Great Plains Energy indemnified Direct Energy for various matters, including: breaches of representations, warranties and covenants; funds advanced by Strategic Energy to certain of its channel partners if such funds became uncollectible before December 2, 2009, (approximately $8 million, excluding commission offsets); and losses associated with litigation and other certain claims to the extent such losses exceed $7.5 million in the aggregate. At December 31, 2008, Great Plains Energy had reserved $2.0 million with respect to the indemnification obligations. Great Plains Energy subsequently reversed this reserve. Additionally, during 2009, Great Plains Energy recorded $3.8 million of gross receipts taxes for periods prior to the sale for which Great Plains Energy indemnified Direct Energy. The following table summarizes the income (loss) from Strategic Energy’s discontinued operations.


	2009			2008
	(millions)
Revenues	$	-		$	667.4

Income from operations before income taxes (a)	$	-		$	182.4
Loss on disposal before income taxes		(2.4	)		(116.2	)
Total income (loss) on discontinued operations
before income taxes		(2.4	)		66.2
Income tax benefit (expense)		0.9			(31.2	)
Income (loss) from discontinued operations,
net of income taxes	$	(1.5	)	$	35.0
(a) For 2008, amount includes $189.1 millon of unrealized net gains related to derivative
instruments.

JOINTLY OWNED ELECTRIC UTILITY PLANTS

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Jointly Owned Electric Utility Plants

24.	JOINTLY OWNED ELECTRIC UTILITY PLANTS

Great Plains Energy’s and KCP&L’s share of jointly owned electric utility plants at December 31, 2010, are detailed in the following tables.

Great Plains Energy
	Wolf Creek			LaCygne			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	$	1,423.7		$	410.5		$	638.9		$	1,282.4		$	326.8		$	151.1
Accumulated depreciation		778.2			298.0			239.9			58.9			16.1			74.8
Nuclear fuel, net		79.2			-			-			-			-			-
Construction work in progress		75.3			48.1			23.4			8.0			23.3			6.4
2011 accredited capacity-MWs		560			709			621			618		NA				173

KCP&L
	Wolf Creek			LaCygne			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	$	1,423.7		$	410.5		$	514.1		$	973.0		$	255.0
Accumulated depreciation		778.2			298.0			196.3			56.4			13.9
Nuclear fuel, net		79.2			-			-			-			-
Construction work in progress		75.3			48.1			14.5			7.1			14.4
2011 accredited capacity-MWs		560			709			494			465		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 is included in the appropriate operating expense classifications in Great Plains Energy’s and KCP&L’s financial statements.

- Definition

Describes that the entity has a proportionate interest in a jointly owned utility plant. Should include a table showing separately for each interest the amount of plant in service, the accumulated provision for depreciation (if available), the amount of plant 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). Should include 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. Should state 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 should 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)

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Quarterly Operating Results (Unaudited)

25.	QUARTERLY OPERATING RESULTS (UNAUDITED)


	Quarter
Great Plains Energy	1st		2nd		3rd		4th
2010	(millions, except per share amounts)
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	)
2009
Operating revenue	$	419.2	$	480.5	$	587.7	$	477.6
Operating income		20.9		90.3		151.2		57.7
Income from continuing operations		21.7		36.9		78.4		14.9
Net income		21.7		33.8		79.2		15.7
Net income attributable to Great Plains Energy		21.7		33.7		79.1		15.6
Basic and diluted earnings per common share from
continuing operations		0.18		0.28		0.57		0.10
Basic and diluted earnings per common share		0.18		0.26		0.58		0.11


	Quarter
KCP&L	1st		2nd		3rd		4th
2010	(millions)
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
2009
Operating revenue	$	277.5	$	324.8	$	395.5	$	320.4
Operating income		14.9		68.2		105.9		43.2
Net income		8.4		34.9		65.6		20.0

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. See Note 6 for additional information. 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. See Note 20 for additional information.

- Definition

This element can be used to disclose the entire quarterly financial data disclosure in the annual financial statements as a single block of text. The disclosure includes a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income (loss) before extraordinary items and cumulative effect of a change in accounting principle 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. Alternatively, the details of this disclosure can be reported using the elements in this group, or by using other taxonomy elements and applying the appropriate quarterly date and period contexts when creating an instance document. For example, the element for "Interest and Dividend Income, Operating" may be used by financial institutions from the Statement of Income, applying the appropriate quarterly date and period context when creating an instance document.

+ References+ Details

SCHEDULE I - PARENT COMPANY FINANCIAL STATEMENTS

12 Months Ended

Dec. 31, 2010

Schedule To Financial Statements [Abstract]

Schedule I - Parent Company Financial Statements

Schedule I – Parent Company Financial Statements

GREAT PLAINS ENERGY INCORPORATED
Income Statements of Parent Company


Year Ended December 31	2010			2009			2008
Operating Expenses	(millions, except per share amounts)
Selling, general and administrative	$	1.2		$	8.8		$	9.3
Maintenance		-			0.2			1.0
General taxes		0.9			1.1			0.8
Total		2.1			10.1			11.1
Operating loss		(2.1	)		(10.1	)		(11.1	)
Equity in earnings from subsidiaries		239.3			174.7			144.8
Non-operating income		3.4			-			0.6
Interest charges		(44.7	)		(28.2	)		(19.2	)
Income from continuing operations before income taxes		195.9			136.4			115.1
Income taxes		15.8			15.2			4.4
Income from continuing operations		211.7			151.6			119.5
Equity in earnings (loss) from discontinued subsidiary		-			(1.5	)		35.0
Net income		211.7			150.1			154.5
Preferred stock dividend requirements		1.6			1.6			1.6
Earnings available for common shareholders	$	210.1		$	148.5		$	152.9

Average number of basic common shares outstanding		135.1			129.3			101.1
Average number of diluted common shares outstanding		136.9			129.8			101.2

Basic earnings (loss) per common share
Continuing operations	$	1.55		$	1.16		$	1.16
Discontinued operations		-			(0.01	)		0.35
Basic earnings per common share	$	1.55		$	1.15		$	1.51

Diluted earnings (loss) per common share
Continuing operations	$	1.53		$	1.15		$	1.16
Discontinued operations		-			(0.01	)		0.35
Diluted earnings per common share	$	1.53		$	1.14		$	1.51

Cash dividends per common share	$	0.83		$	0.83		$	1.66

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	2010			2009
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	0.3		$	6.1
Accounts receivable from subsidiaries		-			0.2
Notes receivable from subsidiaries		249.4			0.6
Money pool receivable		2.0			0.9
Taxes receivable		7.2			7.2
Other		0.7			0.1
Total		259.6			15.1
Investments and Other Assets
Investment in KCP&L		2,005.0			1,931.7
Investments in other subsidiaries		1,360.2			1,328.3
Deferred income taxes		7.2			8.3
Other		6.2			5.6
Total		3,378.6			3,273.9
Total	$	3,638.2		$	3,289.0

LIABILITIES AND CAPITALIZATION
Current Liabilities
Notes payable	$	9.5		$	20.0
Accounts payable to subsidiaries		31.1			28.9
Accounts payable		-			0.1
Accrued interest		6.4			3.6
Derivative instruments		20.8			0.2
Other		7.1			5.4
Total		74.9			58.2
Deferred Credits and Other Liabilities
Derivative instruments		-			0.5
Other		1.4			11.7
Total		1.4			12.2
Capitalization
Common shareholders' equity
Common stock-250,000,000 shares authorized without par value
136,113,954 and 135,636,538 shares issued, stated value		2,324.4			2,313.7
Retained earnings		626.5			529.2
Treasury stock-400,889 and 213,423 shares, at cost		(8.9	)		(5.5	)
Accumulated other comprehensive loss		(56.1	)		(44.9	)
Total		2,885.9			2,792.5
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		637.0			387.1
Total		3,561.9			3,218.6
Commitments and Contingencies
Total	$	3,638.2		$	3,289.0

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	2010			2009			2008
Cash Flows from Operating Activities	(millions)
Net income	$	211.7		$	150.1		$	154.5
Adjustments to reconcile income to net cash from operating activities:
Amortization		3.9			1.9			0.9
Deferred income taxes, net		13.9			(6.1	)		3.3
Equity in earnings from subsidiaries		(239.3	)		(174.7	)		(144.8	)
Equity in (earnings) loss from discontinued subsidiary		-			1.5			(35.0	)
Cash flows affected by changes in:
Accounts receivable from subsidiaries		(2.6	)		3.7			(26.3	)
Taxes receivable		-			4.8			(8.7	)
Accounts payable to subsidiaries		2.2			0.2			17.7
Other accounts payable		(0.1	)		0.1			0.2
Accrued interest		2.7			1.4			-
Cash dividends from subsidiaries		138.6			94.0			416.7
Other		(7.8	)		8.8			2.7
Net cash from operating activities		123.2			85.7			381.2
Cash Flows from Investing Activities
Equity contributions to subsidiaries		-			(455.0	)		(200.0	)
Intercompany lending		(248.8	)		-			-
Net money pool lending		(1.1	)		(0.9	)		-
GMO acquisition		-			-			(5.0	)
Purchases of nonutility property		-			-			(0.3	)
Net cash from investing activities		(249.9	)		(455.9	)		(205.3	)
Cash Flows from Financing Activities
Issuance of common stock		6.2			219.9			15.3
Issuance of long-term debt		249.9			287.5			-
Issuance fees		(3.2	)		(18.8	)		(1.0	)
Net change in short-term borrowings		(10.5	)		(10.0	)		(12.0	)
Dividends paid		(114.2	)		(110.5	)		(172.0	)
Other financing activities		(7.3	)		(3.8	)		(0.8	)
Net cash from financing activities		120.9			364.3			(170.5	)
Net Change in Cash and Cash Equivalents		(5.8	)		(5.9	)		5.4
Cash and Cash Equivalents at Beginning of Year		6.1			12.0			6.6
Cash and Cash Equivalents at End of Year	$	0.3		$	6.1		$	12.0

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.

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.

- Definition

This element can be used to encapsulate the entire condensed financial information disclosure, 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, 2010

Schedule To Financial Statements [Abstract]

Schedule II - Valuation and Qualifying Accounts

Great Plains Energy Incorporated
Valuation and Qualifying Accounts
Years Ended December 31, 2010, 2009 and 2008

				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, 2010		(millions)
	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
Year Ended December 31, 2008
	Allowance for uncollectible accounts	$	4.3		$	7.6	$	6.8	(a)	$	11.9	(b)	$	6.8
	Legal reserves		2.2			8.3		9.5	(e)		9.8	(c)		10.2
	Environmental reserves		0.3			-		0.2	(e)		-			0.5
	Tax valuation allowance		-			0.9		74.9	(e)		-			75.8
(a)	Recoveries. Charged to other accounts for the year ended December 31, 2008, includes the establishment of an allowance
	of $1.1 million and a $1.4 million increase due to the acquisition of GMO.
(b)	Uncollectible accounts charged off.
(c)	Payment of claims.
(d)	Reversal of tax valuation allowance.
(e)	Acquisition of GMO.

Kansas City Power & Light Company
Valuation and Qualifying Accounts
Years Ended December 31, 2010, 2009 and 2008

				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, 2010		(millions)
	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
Year Ended December 31, 2008
	Allowance for uncollectible accounts	$	4.3	$	5.9	$	3.3	(a)	$	12.3	(b)	$	1.2
	Legal reserves		2.2		3.2		-			3.0	(c)		2.4
	Environmental reserves		0.3		-		-			-			0.3
(a)	Recoveries.
(b)	Uncollectible accounts charged off.
(c)	Payment of claims.

Document Information	12 Months Ended
Document Information	Dec. 31, 2010
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2010

Entity Information (USD $)	12 Months Ended
Entity Information (USD $)	Dec. 31, 2010	Feb. 22, 2011	Jun. 30, 2010
Entity Registrant Name	Great Plains Energy Incorporated
Entity Central Index Key	0001143068
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,307,217,754
Entity Common Stock, Shares Outstanding		135,690,276
Document Fiscal Year Focus	2010
Document Fiscal Period Focus	FY