Consolidated Balance Sheets (Unaudited) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2010	Dec. 31, 2009
GREAT PLAINS ENERGY INCORPORATED
Current Assets
Cash and cash equivalents	$ 7.6	$ 65.9
Funds on deposit	4.4	4.4
Receivables, net	274.6	230.5
Accounts receivable pledged as collateral	95.0	0
Fuel inventories, at average cost	80.1	85.0
Materials and supplies, at average cost	131.3	121.3
Deferred refueling outage costs	11.5	19.5
Refundable income taxes	15.3	13.5
Deferred income taxes	42.9	36.8
Assets held for sale	18.8	19.4
Derivative instruments	1.1	1.5
Prepaid expenses and other assets	10.7	14.7
Total	693.3	612.5
Utility Plant, at Original Cost
Electric	10,352.8	8,849.0
Less-accumulated depreciation	3,959.2	3,774.5
Net utility plant in service	6,393.6	5,074.5
Construction work in progress	350.9	1,508.4
Nuclear fuel, net of amortization	80.2	68.2
Total	6,824.7	6,651.1
Investments and Other Assets
Affordable housing limited partnerships	11.5	13.2
Nuclear decommissioning trust fund	120.7	112.5
Regulatory assets	888.8	822.2
GOODWILL	169.0	169.0
Derivative instruments	8.1	7.9
Other	83.0	94.4
Total	1,281.1	1,219.2
Total	8,799.1	8,482.8
Current Liabilities
Notes payable	22.0	252.0
Collateralized note payable	95.0	0
Commercial paper	209.5	186.6
Current maturities of long-term debt	335.7	1.3
Accounts payable	172.4	315.0
Accrued taxes	86.8	27.9
Accrued interest	70.5	72.5
Accrued compensation and benefits	44.1	45.1
Pension and post-retirement liability	4.7	4.6
Derivative instruments	25.1	0.3
Other	35.4	53.0
Total	1,101.2	958.3
Deferred Credits and Other Liabilities
Deferred income taxes	544.3	381.9
Deferred tax credits	134.5	140.5
Asset retirement obligations	139.1	132.6
Pension and post-retirement liability	439.6	440.4
Regulatory liabilities	249.5	237.8
Derivative instruments	0	0.5
Other	135.3	145.1
Total	1,642.3	1,478.8
Common shareholders' equity
Common Stock	2,322.5	2,313.7
Retained earnings	660.0	529.2
Treasury stock	(8.6)	(5.5)
Accumulated other comprehensive gain (loss)	(59.8)	(44.9)
Total	2,914.1	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	3,101.3	3,213.0
Total	6,055.6	6,045.7
Commitments and Contingencies
Total	8,799.1	8,482.8
KANSAS CITY POWER AND LIGHT COMPANY
Current Assets
Cash and cash equivalents	3.0	17.4
Funds on deposit	0.2	0.1
Receivables, net	153.2	161.7
Accounts receivable pledged as collateral	95.0	0
Fuel inventories, at average cost	45.5	45.6
Materials and supplies, at average cost	92.0	84.8
Deferred refueling outage costs	11.5	19.5
Refundable income taxes	41.8	0
Deferred income taxes	4.9	0.3
Derivative instruments	0	0.2
Prepaid expenses and other assets	9.1	11.0
Total	456.2	340.6
Utility Plant, at Original Cost
Electric	7,376.8	6,258.5
Less-accumulated depreciation	3,046.9	2,899.0
Net utility plant in service	4,329.9	3,359.5
Construction work in progress	288.2	1,144.1
Nuclear fuel, net of amortization	80.2	68.2
Total	4,698.3	4,571.8
Investments and Other Assets
Nuclear decommissioning trust fund	120.7	112.5
Regulatory assets	645.6	612.1
Other	38.8	65.3
Total	805.1	789.9
Total	5,959.6	5,702.3
Current Liabilities
Collateralized note payable	95.0	0
Commercial paper	209.5	186.6
Current maturities of long-term debt	0.3	0.2
Accounts payable	141.5	237.9
Accrued taxes	62.9	23.7
Accrued interest	37.0	26.7
Accrued compensation and benefits	44.1	45.1
Pension and post-retirement liability	3.2	3.2
Other	7.7	26.1
Total	601.2	549.5
Deferred Credits and Other Liabilities
Deferred income taxes	666.2	559.4
Deferred tax credits	130.3	135.7
Asset retirement obligations	125.7	119.8
Pension and post-retirement liability	420.7	421.2
Regulatory liabilities	133.2	126.9
Other	77.2	78.2
Total	1,553.3	1,441.2
Common shareholders' equity
Common Stock	1,563.1	1,563.1
Retained earnings	500.1	410.1
Accumulated other comprehensive gain (loss)	(37.8)	(41.5)
Total	2,025.4	1,931.7
Cumulative preferred stock
Long-term debt	1,779.7	1,779.9
Total	3,805.1	3,711.6
Commitments and Contingencies
Total	$ 5,959.6	$ 5,702.3

Parenthetical Data to the Consolidated Balance Sheets (Unaudited) (USD $) In Millions, except Share data, unless otherwise specified	Sep. 30, 2010	Dec. 31, 2009
GREAT PLAINS ENERGY INCORPORATED
Current Assets
Nuclear fuel accumulated amortization	$ 125.7	$ 106.0
Capitalization
Common Stock, Shares, Authorized	250,000,000	250,000,000
Common Stock, Shares, Issued	136,036,530	135,636,538
Treasury Stock, Shares	385,419	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
Current Assets
Nuclear fuel accumulated amortization	$ 125.7	$ 106.0
Capitalization
Common Stock, Shares, Authorized	1,000	1,000
Common Stock, Shares, Issued	1	1

Consolidated Statements of Income (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
GREAT PLAINS ENERGY INCORPORATED
Operating Revenues
Electric revenues	$ 728.8	$ 587.7	$ 1,787.7	$ 1,487.4
Operating Expenses
Fuel	127.3	118.1	333.2	302.5
Purchased power	68.0	46.1	171.4	140.9
Transmission of electricity by others	8.1	7.9	20.9	21.2
Utility operating and maintenance expenses	147.7	145.2	447.3	423.1
Depreciation and amortization	85.3	77.9	248.5	220.3
General taxes	43.6	38.4	119.2	106.8
Other	5.0	2.9	6.5	10.2
Total	485.0	436.5	1,347.0	1,225.0
Operating income (loss)	243.8	151.2	440.7	262.4
Non-operating income	7.5	12.7	34.8	37.4
Non-operating expenses	(3.4)	(0.7)	(7.1)	(2.9)
Interest charges	(45.5)	(49.0)	(138.7)	(133.2)
Income (loss) before income tax (expense) benefit and loss from equity investments	202.4	114.2	329.7	163.7
Income tax (expense) benefit	(70.4)	(35.6)	(112.1)	(26.3)
Loss from equity investments, net of income taxes	0	(0.2)	(0.9)	(0.4)
Income (loss) from continuing operations	132.0	78.4	216.7	137.0
Income (loss) from discontinued operations, net of income taxes	0	0.8	0	(2.3)
Net income (loss)	132.0	79.2	216.7	134.7
Less: Net income attributable to noncontrolling interest	0	(0.1)	(0.1)	(0.2)
Net income (loss) attributable to parent	132.0	79.1	216.6	134.5
Preferred stock dividend requirements	0.4	0.4	1.2	1.2
Earnings available for common shareholders	131.6	78.7	215.4	133.3
Average number of basic common shares outstanding	135.2	134.6	135.1	127.5
Average number of diluted common shares outstanding	136.9	134.9	136.8	127.6
Basic and diluted earnings (loss) per common share
Basic earnings per common share - continuing operations	$ 0.97	$ 0.57	$ 1.59	$ 1.07
Basic earnings (loss) per common share - discontinued operations	$ 0	$ 0.01	$ 0	$ (0.02)
Basic earnings per common share	$ 0.97	$ 0.58	$ 1.59	$ 1.05
Diluted earnings per common share - continuing operations	$ 0.96	$ 0.57	$ 1.57	$ 1.06
Diluted earnings (loss) per common share - discontinued operations	$ 0	$ 0.01	$ 0	$ (0.02)
Diluted earnings per common share	$ 0.96	$ 0.58	$ 1.57	$ 1.04
Cash dividends per common share	$ 0.2075	$ 0.2075	$ 0.6225	$ 0.6225
KANSAS CITY POWER AND LIGHT COMPANY
Operating Revenues
Electric revenues	486.5	395.5	1,194.7	997.8
Operating Expenses
Fuel	83.8	70.5	213.2	183.3
Purchased power	25.0	19.8	63.2	58.6
Transmission of electricity by others	4.4	3.2	11.3	9.1
Utility operating and maintenance expenses	102.9	104.2	323.5	301.6
Depreciation and amortization	66.4	59.3	192.2	166.1
General taxes	37.2	32.6	99.3	90.2
Other	3.2	0	3.2	(0.1)
Total	322.9	289.6	905.9	808.8
Operating income (loss)	163.6	105.9	288.8	189.0
Non-operating income	6.1	8.6	23.3	24.7
Non-operating expenses	(2.5)	(0.2)	(4.7)	(2.3)
Interest charges	(20.1)	(22.3)	(63.8)	(62.7)
Income (loss) before income tax (expense) benefit and loss from equity investments	147.1	92.0	243.6	148.7
Income tax (expense) benefit	(54.5)	(26.4)	(83.6)	(39.8)
Net income (loss)	$ 92.6	$ 65.6	$ 160.0	$ 108.9

Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
GREAT PLAINS ENERGY INCORPORATED
Cash Flows from Operating Activities
Net income (loss)	$ 216.7	$ 134.7
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	248.5	220.3
Amortization of:
Nuclear fuel	19.7	12.8
Other	(4.1)	(8.0)
Deferred income taxes, net	127.0	(4.8)
Investment tax credit amortization	(1.8)	(1.7)
Loss from equity investments, net of income taxes	0.9	0.4
Other operating activities	(199.2)	(91.9)
Net cash from operating activities	407.7	261.8
Cash Flows from Investing Activities
Utility capital expenditures	(465.2)	(683.6)
Allowance for borrowed funds used during construction	(26.9)	(28.4)
Payment to Black Hills for asset sale working capital adjustment	0	(7.7)
Purchases of nuclear decommissioning trust investments	(78.3)	(36.1)
Proceeds from nuclear decommissioning trust investments	75.6	33.4
Other investing activities	(9.1)	(2.5)
Net cash from investing activities	(503.9)	(724.9)
Cash Flows from Financing Activities
Issuance of common stock	4.7	217.9
Issuance of long-term debt	249.9	700.5
Issuance fees	(11.7)	(22.7)
Repayment of long-term debt	(1.3)	(2.0)
Net change in short-term borrowings	(207.1)	(390.2)
Net change in collateralized short-term borrowings	95.0	0
Dividends paid	(85.6)	(82.0)
Other financing activities	(6.0)	(3.0)
Net cash from financing activities	37.9	418.5
Net Change in Cash and Cash Equivalents	(58.3)	(44.6)
Cash and Cash Equivalents at Beginning of Year	65.9	61.1
Cash and Cash Equivalents at End of Period	7.6	16.5
KANSAS CITY POWER AND LIGHT COMPANY
Cash Flows from Operating Activities
Net income (loss)	160.0	108.9
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	192.2	166.1
Amortization of:
Nuclear fuel	19.7	12.8
Other	18.1	13.9
Deferred income taxes, net	63.5	(49.6)
Investment tax credit amortization	(1.2)	(1.1)
Other operating activities	(171.1)	32.9
Net cash from operating activities	281.2	283.9
Cash Flows from Investing Activities
Utility capital expenditures	(349.1)	(520.6)
Allowance for borrowed funds used during construction	(21.3)	(23.6)
Purchases of nuclear decommissioning trust investments	(78.3)	(36.1)
Proceeds from nuclear decommissioning trust investments	75.6	33.4
Net money pool lending	6.0	0
Other investing activities	(6.0)	1.5
Net cash from investing activities	(373.1)	(545.4)
Cash Flows from Financing Activities
Issuance of long-term debt	0	413.0
Issuance fees	(5.0)	(4.0)
Repayment of long-term debt	(0.2)	0
Net change in short-term borrowings	22.9	(342.2)
Net change in collateralized short-term borrowings	95.0	0
Net money pool borrowings	34.8	0
Dividends paid	(70.0)	(54.0)
Equity contribution from Great Plains Energy	0	247.5
Net cash from financing activities	77.5	260.3
Net Change in Cash and Cash Equivalents	(14.4)	(1.2)
Cash and Cash Equivalents at Beginning of Year	17.4	5.4
Cash and Cash Equivalents at End of Period	$ 3.0	$ 4.2

Consolidated Statements of Common Shareholders' Equity (Unaudited) (USD $) In Millions, except Share data, unless otherwise specified	GREAT PLAINS ENERGY INCORPORATED	KANSAS CITY POWER AND LIGHT COMPANY	Common Stock GREAT PLAINS ENERGY INCORPORATED	Common Stock KANSAS CITY POWER AND LIGHT COMPANY	Retained Earnings GREAT PLAINS ENERGY INCORPORATED	Retained Earnings KANSAS CITY POWER AND LIGHT COMPANY	Treasury Stock GREAT PLAINS ENERGY INCORPORATED	Accumulated Other Comprehensive Income (Loss) GREAT PLAINS ENERGY INCORPORATED	Accumulated Other Comprehensive Income (Loss) KANSAS CITY POWER AND LIGHT COMPANY	Noncontrolling Interest GREAT PLAINS ENERGY INCORPORATED
Beginning balance (in shares) at Dec. 31, 2008			119,375,923	1			(120,677)
Beginning balance at Dec. 31, 2008			$ 2,118.4	$ 1,315.6	$ 489.3	$ 353.2	$ (3.6)	$ (53.5)	$ (46.9)	$ 1.0
Equity contribution from Great Plains Energy		247.5		247.5
Issuance of common stock			218.2
Issuance of common stock (in shares)			15,781,851
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			0.9
Unearned Compensation
Issuance of restricted common stock			(5.4)
Forfeiture of restricted common stock			1.0
Compensation expense recognized			2.7
Equity Units allocated fees and expenses and the present value of contract adjustment payments			(22.5)
Other			(0.5)
Net income (loss) attributable to Great Plains Energy	134.5				134.5	108.9
Dividends:
Common stock					(80.8)	(54.0)
Preferred stock - at required rates					(1.2)
Performance shares					(0.1)
Performance shares amendment					0.4
Treasury shares acquired							(2.8)
Treasury shares acquired (in shares)							(125,488)
Treasury shares reissued							0.1
Treasury shares reissued (in shares)							2,758
Derivative hedging activity, net of tax	4.2	4.0						4.2	4.0
Change in unrecognized pension expense, net of tax	0.2							0.2
Net income attributable to noncontrolling interest										0.2
Distribution										0
Ending balance (in shares) at Sep. 30, 2009			135,534,441	1			(243,407)
Ending balance at Sep. 30, 2009	2,914.1	1,928.3	2,311.2	1,563.1	542.1	408.1	(6.3)	(49.1)	(42.9)	1.2
Beginning balance at Jun. 30, 2009
Unearned Compensation
Net income (loss) attributable to Great Plains Energy	79.1
Dividends:
Derivative hedging activity, net of tax	1.7	1.6
Change in unrecognized pension expense, net of tax	0.1
Ending balance at Sep. 30, 2009	2,914.1	1,928.3
Beginning balance (in shares) at Dec. 31, 2009			135,636,538	1			(213,423)
Beginning balance at Dec. 31, 2009			2,313.7	1,563.1	529.2	410.1	(5.5)	(44.9)	(41.5)	1.2
Equity contribution from Great Plains Energy		0		0
Issuance of common stock			5.1
Issuance of common stock (in shares)			269,855
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			1.1
Unearned Compensation
Issuance of restricted common stock			(2.3)
Forfeiture of restricted common stock			0.6
Compensation expense recognized			1.9
Equity Units allocated fees and expenses and the present value of contract adjustment payments			0
Other			0.1
Net income (loss) attributable to Great Plains Energy	216.6				216.6	160.0
Dividends:
Common stock					(84.4)	(70.0)
Preferred stock - at required rates					(1.2)
Performance shares					(0.2)
Performance shares amendment					0
Treasury shares acquired							(3.1)
Treasury shares acquired (in shares)							(172,913)
Treasury shares reissued							0
Treasury shares reissued (in shares)							917
Derivative hedging activity, net of tax	(15.0)	3.7						(15.0)	3.7
Change in unrecognized pension expense, net of tax	0.1							0.1
Net income attributable to noncontrolling interest										0.1
Distribution										(0.1)
Common Stockholders' Equity attributable to Parent	2,914.1	2,025.4
Ending balance (in shares) at Sep. 30, 2010			136,036,530	1			(385,419)
Ending balance at Sep. 30, 2010			$ 2,322.5	$ 1,563.1	$ 660.0	$ 500.1	$ (8.6)	$ (59.8)	$ (37.8)	$ 1.2

Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
GREAT PLAINS ENERGY INCORPORATED
Net income (loss)	$ 132.0	$ 79.2	$ 216.7	$ 134.7
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	(10.3)	(0.6)	(32.4)	0.1
Income tax (expense) benefit	4.0	0.2	12.6	0
Net gain (loss) on derivative hedging instruments	(6.3)	(0.4)	(19.8)	0.1
Reclassification to expenses, net of tax	2.0	2.1	4.8	4.1
Derivative hedging activity, net of tax	(4.3)	1.7	(15.0)	4.2
Defined benefit pension plans
Amortization of net gain included in net periodic benefit costs	0	0.1	0.2	0.3
Income tax expense	0	0	(0.1)	(0.1)
Net change in unrecognized pension expense	0	0.1	0.1	0.2
Comprehensive income (loss)	127.7	81.0	201.8	139.1
Less: comprehensive income attributable to noncontrolling interest	0	(0.1)	(0.1)	(0.2)
Comprehensive income (loss) attributable to Great Plains Energy	127.7	80.9	201.7	138.9
KANSAS CITY POWER AND LIGHT COMPANY
Net income (loss)	92.6	65.6	160.0	108.9
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	(0.4)	(0.6)	(1.0)	0.1
Income tax (expense) benefit	0.2	0.2	0.4	0
Net gain (loss) on derivative hedging instruments	(0.2)	(0.4)	(0.6)	0.1
Reclassification to expenses, net of tax	1.6	2.0	4.3	3.9
Derivative hedging activity, net of tax	1.4	1.6	3.7	4.0
Defined benefit pension plans
Comprehensive income (loss)	$ 94.0	$ 67.2	$ 163.7	$ 112.9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 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.

·	Great Plains Energy Services Incorporated (Services) obtains certain goods and third-party services for its affiliated companies.

·	KLT Inc. is an intermediate holding company that primarily holds investments in affordable housing limited partnerships.

Great Plains Energy’s sole reportable business segment is electric utility. See Note 17 for additional information.

Basic and Diluted Earnings per Common Share Calculation

To determine basic EPS, preferred stock dividend requirements and net income attributable to noncontrolling interest are deducted from 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.


	Three Months Ended				Year to Date
	September 30				September 30
	2010		2009		2010		2009
Income	(millions, except per share amounts)
Income from continuing operations	$	132.0	$	78.4	$	216.7	$	137.0
Less: net income attributable to noncontrolling interest		-		0.1		0.1		0.2
Less: preferred stock dividend requirements		0.4		0.4		1.2		1.2
Income from continuing operations available for common shareholders	$	131.6	$	77.9	$	215.4	$	135.6
Common Shares Outstanding
Average number of common shares outstanding		135.2		134.6		135.1		127.5
Add: effect of dilutive securities		1.7		0.3		1.7		0.1
Diluted average number of common shares outstanding		136.9		134.9		136.8		127.6
Basic EPS from continuing operations	$	0.97	$	0.57	$	1.59	$	1.07
Diluted EPS from continuing operations	$	0.96	$	0.57	$	1.57	$	1.06

The computation of diluted EPS for the three months ended September 30, 2010, excludes anti-dilutive shares consisting of 107,958 performance shares, 103,114 restricted stock shares and 203,879 stock options. The computation of diluted EPS year to date September 30, 2010, excludes anti-dilutive shares consisting of 116,388 performance shares, 278,452 restricted stock shares and 209,837 stock options.

The computation of diluted EPS for the three months ended September 30, 2009, excludes anti-dilutive shares consisting of 68,310 performance shares, 267,685 restricted stock shares and 247,383 stock options. The computation of diluted EPS year to date September 30, 2009, excludes anti-dilutive shares consisting of 68,310 performance shares, 439,585 restricted stock shares, 247,383 stock options and 5.8 million Equity Units.

Dividends Declared

In October 2010, 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 on December 20, 2010, to shareholders of record as of November 29, 2010. The Board also declared regular dividends on Great Plains Energy’s preferred stock, payable on March 1, 2011, to shareholders of record as of February 7, 2011.

In October 2010, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $25 million payable on December 17, 2010.

SUPPLEMENTAL CASH FLOW INFORMATION

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Supplemental Cash Flow Information

2.	SUPPLEMENTAL CASH FLOW INFORMATION

Great Plains Energy Other Operating Activities
Year to Date September 30	2010			2009
Cash flows affected by changes in:	(millions)
Receivables	$	(45.9	)	$	7.9
Accounts receivable pledged as collateral		(95.0	)		-
Fuel inventories		4.9			(3.1	)
Materials and supplies		(10.0	)		(16.1	)
Accounts payable		(79.1	)		(122.2	)
Accrued taxes		54.6			85.7
Accrued interest		(2.0	)		1.9
Deferred refueling outage costs		8.0			4.3
Accrued plant maintenance costs		1.9			2.2
Fuel adjustment clauses		(2.3	)		3.1
Pension and post-retirement benefit obligations		15.5			43.0
Allowance for equity funds used during construction		(25.5	)		(29.6	)
Forward Starting Swaps settlement		(6.9	)		(79.1	)
Other		(17.4	)		10.1
Total other operating activities	$	(199.2	)	$	(91.9	)
Cash paid during the period:
Interest	$	175.4		$	162.8
Income taxes	$	0.4		$	4.7
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	36.4		$	56.8

KCP&L Other Operating Activities
Year to Date September 30	2010			2009
Cash flows affected by changes in:	(millions)
Receivables	$	(0.1	)	$	6.7
Accounts receivable pledged as collateral		(95.0	)		-
Fuel inventories		0.1			0.6
Materials and supplies		(7.2	)		(11.4	)
Accounts payable		(87.2	)		(49.3	)
Accrued taxes		(6.3	)		96.4
Accrued interest		10.3			18.9
Deferred refueling outage costs		8.0			4.3
Pension and post-retirement benefit obligations		31.1			51.5
Allowance for equity funds used during construction		(21.7	)		(22.6	)
Kansas Energy Cost Adjustment		(5.4	)		(0.2	)
Forward Starting Swaps settlement		-			(79.1	)
Other		2.3			17.1
Total other operating activities	$	(171.1	)	$	32.9
Cash paid during the period:
Interest	$	60.3		$	44.0
Income taxes	$	71.6		$	-
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	31.6		$	55.2

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 September 30, 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 year to date September 30, 2010.

RECEIVABLES

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Receivables

3.	RECEIVABLES

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


	September 30			December 31
	2010			2009
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	118.3		$	47.3
Customer accounts receivable - unbilled		80.3			77.9
Allowance for doubtful accounts		(5.0	)		(2.8	)
Other receivables		81.0			108.1
Total	$	274.6		$	230.5
KCP&L
Customer accounts receivable - billed	$	38.2		$	-
Customer accounts receivable - unbilled		52.0			44.6
Allowance for doubtful accounts		(2.6	)		(1.7	)
Intercompany receivables		12.7			42.4
Other receivables		52.9			76.4
Total	$	153.2		$	161.7

Great Plains Energy’s and KCP&L’s other receivables at September 30, 2010, and December 31, 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 September 30, 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 May 2010, the term of the agreement was extended to May 2011.

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


				Receivables			Consolidated
Three Months Ended September 30, 2010	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(442.0	)	$	442.0		$	-
Gain (loss) on sale of accounts receivable (a)		(5.6	)		5.4			(0.2	)
Servicing fees		0.8			(0.8	)		-
Fees to outside investor		-			(0.3	)		(0.3	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(430.9	)		430.9			-
Cash paid to KCP&L for receivables purchased		425.5			(425.5	)		-
Servicing fees		0.8			(0.8	)		-
Interest on intercompany note		0.2			(0.2	)		-


				Receivables			Consolidated
Year to Date September 30, 2010	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,067.7	)	$	1,067.7		$	-
Gain (loss) on sale of accounts receivable (a)		(13.5	)		12.9			(0.6	)
Servicing fees		1.9			(1.9	)		-
Fees to outside investor		-			(0.9	)		(0.9	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(1,029.8	)		1,029.8			-
Cash paid to KCP&L for receivables purchased		1,016.9			(1,016.9	)		-
Servicing fees		1.9			(1.9	)		-
Interest on intercompany note		0.4			(0.4	)		-


				Receivables			Consolidated
Three Months Ended September 30, 2009	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(354.2	)	$	354.2		$	-
Gain (loss) on sale of accounts receivable (a)		(4.5	)		4.4			(0.1	)
Servicing fees		0.9			(0.9	)		-
Fees to outside investor		-			(0.4	)		(0.4	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(352.5	)		352.5			-
Cash paid to KCP&L for receivables purchased		348.1			(348.1	)		-
Servicing fees		0.9			(0.9	)		-
Interest on intercompany note		0.1			(0.1	)		-


				Receivables			Consolidated
Year to Date September 30, 2009	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(892.0	)	$	892.0		$	-
Gain (loss) on sale of accounts receivable (a)		(11.3	)		11.0			(0.3	)
Servicing fees		2.4			(2.4	)		-
Fees to outside investor		-			(0.9	)		(0.9	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(880.3	)		880.3			-
Cash paid to KCP&L for receivables purchased		869.3			(869.3	)		-
Servicing fees		2.4			(2.4	)		-
Interest on intercompany note		0.3			(0.3	)		-
(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

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Assets Held for Sale

4.	ASSETS HELD FOR SALE

Great Plains Energy has several real estate properties that will not be used. As a result, these real estate properties are available for immediate sale in their present condition and management is actively marketing these properties. The carrying amounts for these assets are presented at fair value less estimated selling cost and are included in assets held for sale on Great Plains Energy’s balance sheets. 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. Of the $18.8 million of assets held for sale at September 30, 2010, $14.4 million is included in the electric utility segment and the remaining $4.4 million is included in the other category. 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.

NUCLEAR PLANT

9 Months Ended

Sep. 30, 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 DOE’s legal authority to withdraw its license application also is pending in multiple lawsuits filed with a federal appellate court. However, that court has put those cases on hold pending a final decision from the NRC. 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 12 for a related legal proceeding.

Low-Level Radioactive Waste

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

Nuclear Decommissioning Trust Fund

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


	September 30				December 31
	2010				2009
Decommissioning Trust		(millions)
Beginning balance January 1		$	112.5		$	96.9
Contributions			2.7			3.7
Earned income, net of fees			1.2			2.8
Net realized gains/(losses)			6.6			(5.5	)
Net unrealized gains/(losses)			(2.3	)		14.6
Ending balance		$	120.7		$	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.


	September 30				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	$ 72.4	$ 6.4	$ (2.2)	$ 76.6	$ 36.3	$ 8.9	$ (0.7)	$ 44.5
Debt securities	37.8	3.8	-	41.6	35.3	2.1	-	37.4
Other	2.5	-	-	2.5	30.6	-	-	30.6
Total	$ 112.7	$ 10.2	$ (2.2)	$ 120.7	$ 102.2	$ 11.0	$ (0.7)	$ 112.5

The weighted average maturity of debt securities held by the trust at September 30, 2010, was approximately 7.7 years. The costs of securities sold are determined on the basis of specific identification. The following table summarizes the realized gains and losses from the sale of securities by the nuclear decommissioning trust fund.


	Three Months Ended						Year to Date
	September 30						September 30
	2010			2009			2010			2009
	(millions)
Realized gains	$	0.2		$	0.5		$	7.2		$	1.2
Realized losses		(0.1	)		(0.9	)		(0.6	)		(7.6	)

REGULATORY MATTERS

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Regulatory Matters

6.	REGULATORY MATTERS

Regulatory Proceedings

The following table summarizes the initial filing information in currently pending requests for retail rate increases with The State Corporation Commission of the State of Kansas (KCC) and the Public Service Commission of the State of Missouri (MPSC).


			Annual
			Revenue		Return on		Rate-Making
Rate Jurisdiction		File Date	Increase		Equity		Equity Ratio
			(millions)
KCP&L - Kansas (a)		12/17/2009	$ 55.2	(b)	11.25%	(b)	46.17%
KCP&L - Missouri (c)		6/4/2010	92.1		11.00%		46.16%
GMO - Missouri Public Service division (c)		6/4/2010	75.8		11.00%		46.16%
GMO - St. Joseph Light & Power division (c)		6/4/2010	22.1		11.00%		46.16%

(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. Any authorized changes to retail rates
	are expected to be effective in December 2010.
(b)	The requested increase was adjusted by KCP&L during the hearing process to $50.9 million as the net result of updates
	to the case, most notably a reduction in the requested return on equity. The requested return on equity was adjusted
	by KCP&L to 10.75% with the potential for a 0.25% adder (to 11.00%) if KCC adopts a particular rate design
	proposal by KCC Staff and other interveners.
(c)	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 expected with 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.

In June 2010, KCC staff and certain interveners filed their direct testimony in KCP&L’s rate case. KCC staff recommended a rate reduction of $9.1 million. The main differences between KCP&L’s and KCC staff’s positions are the staff’s proposals for a return on equity of 9.70%, disallowance of $231 million of the total project cost of Iatan No. 2 ($58 million for KCP&L’s Kansas jurisdictional portion of the plant) and depreciation rate differences. KCP&L supported a recommended disallowance of certain Iatan No. 2 construction costs in its post-hearing brief filed in September 2010. Great Plains Energy recorded a $4.0 million pre-tax loss in the third quarter of 2010 for KCP&L’s and GMO’s combined share of these Iatan No. 2 construction costs. Management does not believe a further write-down of the Iatan No. 2 plant is appropriate under regulatory prudence standards. In the event of a further disallowance of certain Iatan No. 2 costs, KCP&L would recognize a loss with a corresponding write-down of utility plant for the amount of disallowance. The outcome of the KCP&L Kansas case will likely be different from either of the positions of KCP&L or KCC staff, though the decision of KCC cannot be predicted. Evidentiary hearings in the case were held August 16, 2010, through September 2, 2010. The case has been fully briefed and a KCC order is expected in November 2010 with new rates expected to be effective in December 2010.

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) 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. The next major milestone in the MPSC cases is November 2010, when the MPSC staff will file its Iatan No. 2 prudence report and the MPSC Staff and other interveners will file direct testimony. Hearings are scheduled for late January 2011 for KCP&L and early February 2011 for GMO. New rates are proposed to go into effect in May 2011 for KCP&L and June 2011 for GMO.

KCP&L’s Comprehensive Energy Plan – Iatan No. 2

In April 2010, Great Plains Energy and KCP&L announced the results of a cost and schedule reforecast for Iatan No. 2. The current and previous cost estimate ranges are shown in the following table. The cost estimate ranges do not include allowance for funds used during construction 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.


	Current Estimate			Previous Estimate
	Range			Range			Change
	(millions)
Great Plains Energy's 73% share of Iatan No. 2	$ 1,222	-	$ 1,251	$ 1,153	-	$ 1,201	$ 69	-	$ 50
KCP&L's 55% share of Iatan No. 2	919	-	941	868	-	904	51	-	37

The increase in the cost estimate ranges was primarily due to a shift in the expected in-service date, the impact of lower wholesale prices on expected test power revenues that offset construction cost, and a level of contingency management considered appropriate in light of recent start-up events encountered at other coal plants under construction. 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 rate cases. The Companies estimate that the final cost will be within the current estimate range.

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 have received the final audit report alleging violation of certain standards, which could result in penalties. The timing and amount of such penalties that may be proposed are unknown at this time. 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 may also investigate the circumstances surrounding this transmission system outage. The outcome of the outage inquiries cannot be predicted at this time.

Energy Efficiency

Great Plains Energy and KCP&L have implemented various energy efficiency programs, and are evaluating expanded and new energy efficiency programs as one of the elements to meet future customer energy needs. 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. While there is an ongoing rulemaking proceeding in Missouri, and a pending KCC case filed by KCP&L to address recovery of and earnings on investments in energy efficiency programs, until these rules are set and programs are approved, the effects on Great Plains Energy’s and KCP&L’s plans and future results cannot be reasonably estimated.

MPSC Regulatory Approval of the GMO Acquisition

The MPSC order approving the GMO acquisition was received on July 1, 2008. Certain parties filed appeals and a motion to stay the order with the Cole County, Missouri, Circuit Court, which affirmed the order in June 2009. That decision was appealed and in August 2010, the Missouri Court of Appeals, Western District, upheld the MPSC order. In September 2010, certain parties filed motions for rehearing by the Missouri Court of Appeals and applications for transfer to the Missouri Supreme Court.

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. The order remains in effect unless reversed by the courts.

Regulatory Assets and Liabilities

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


							Great
September 30, 2010	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	112.6		$	26.4		$	139.0
Loss on reacquired debt		5.1	(a)		0.8	(a)		5.9
Cost of removal		7.5			-			7.5
Asset retirement obligations		26.6			12.6			39.2
Pension settlements		10.1	(b)		-			10.1
Pension and post-retirement costs		366.9	(c)		103.0	(c)		469.9
Deferred customer programs		42.5	(d)		13.2			55.7
Rate case expenses		10.9	(e)		2.3	(e)		13.2
Skill set realignment costs		5.1	(f)		-			5.1
Fuel adjustment clauses		5.2	(e)		45.1	(e)		50.3
Acquisition transition costs		29.5	(g)		22.5	(g)		52.0
St. Joseph Light & Power acquisition		-			2.7	(h)		2.7
Storm damage		-			3.6	(i)		3.6
Derivative instruments		-			4.8	(j)		4.8
Iatan No. 1 and Common facilities depreciation and carrying costs		13.3	(k)		3.5	(k)		16.8
Iatan No. 2 construction accounting costs		6.4	(k)		2.2	(k)		8.6
Other		3.9	(l)		0.5	(l)		4.4
Total	$	645.6		$	243.2		$	888.8
Regulatory Liabilities
Emission allowances	$	86.1		$	0.6		$	86.7
Asset retirement obligations		37.8			-			37.8
Pension		-			36.3			36.3
Cost of removal		-			63.2	(m)		63.2
Other		9.3			16.2			25.5
Total	$	133.2		$	116.3		$	249.5

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

(b)	$5.6 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)	$2.9 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 expected to be 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)	Not included in rate base.

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

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


					Great
December 31, 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

PENSION PLANS AND OTHER EMPLOYEE BENEFITS

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Pension Plans and Other Employee Benefits

7.	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 generally accepted accounting principles (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 tables provide Great Plains Energy’s components of net periodic benefit costs prior to the effects of capitalization and sharing with joint-owners of power plants.


	Pension Benefits						Other Benefits
Three Months Ended September 30	2010			2009			2010			2009
Components of net periodic benefit costs	(millions)
Service cost	$	7.6		$	7.3		$	1.0		$	1.1
Interest cost		12.3			11.8			2.2			2.0
Expected return on plan assets		(9.2	)		(8.1	)		(0.5	)		(0.4	)
Prior service cost		1.1			1.0			1.8			1.9
Recognized net actuarial loss (gain)		9.4			9.1			(0.1	)		(0.1	)
Transition obligation		-			-			0.3			0.3
Net periodic benefit costs before
regulatory adjustment		21.2			21.1			4.7			4.8
Regulatory adjustment		(8.1	)		(7.2	)		-			-
Net periodic benefit costs	$	13.1		$	13.9		$	4.7		$	4.8


	Pension Benefits						Other Benefits
Year to Date September 30	2010			2009			2010			2009
Components of net periodic benefit costs	(millions)
Service cost	$	22.8		$	21.8		$	2.8		$	3.1
Interest cost		36.9			35.4			6.6			6.2
Expected return on plan assets		(27.5	)		(24.1	)		(1.6	)		(1.2	)
Prior service cost		3.5			3.0			5.4			5.2
Recognized net actuarial loss (gain)		28.1			27.3			(0.1	)		(0.3	)
Transition obligation		-			-			1.0			1.0
Settlement charge		-			0.1			-			-
Net periodic benefit costs before
regulatory adjustment		63.8			63.5			14.1			14.0
Regulatory adjustment		(24.6	)		(20.3	)		-			(0.2	)
Net periodic benefit costs	$	39.2		$	43.2		$	14.1		$	13.8

Year to date September 30, 2010, the Company contributed $38.5 million to the pension plans and expects to contribute an additional $29.8 million in 2010 to satisfy the ERISA minimum funding requirements and the MPSC and KCC rate orders, the majority of which is expected to be paid by KCP&L.

On March 23, 2010, the Patient Protection and Affordable Care Act, a comprehensive health care reform bill took effect. Management expects a minimal impact as a result of this new legislation in the short-term but will continue to monitor for any long-term impacts. Year to date September 30, 2010, Great Plains Energy and KCP&L recorded a $2.8 million increase in income tax expense for the cumulative change in tax treatment of the Medicare Part D subsidy under this new legislation.

- 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

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Equity Compensation

8.	EQUITY COMPENSATION

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

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


	Three Months Ended				Year to Date
	September 30				September 30
	2010		2009		2010		2009
Great Plains Energy	(millions)
Compensation expense	$	0.8	$	1.7	$	3.4	$	4.2
Income tax benefits		0.2		0.5		0.8		1.0
KCP&L
Compensation expense		0.6		1.2		2.4		2.8
Income tax benefits		0.2		0.4		0.4		0.5

Performance Shares

Performance share activity year to date September 30, 2010, is summarized in the following table.


	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	(44,168)	21.33
Ending balance	451,964	18.05
* weighted-average

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, based on internal and external measures, over stated performance periods.

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 commensurate with the remaining life of the performance period of the grant based on the zero-coupon government bonds in effect at the time of the valuation. The dividend yield is based on the most recent dividends paid and the actual closing stock price on the valuation date. For shares granted year to date September 30, 2010, inputs for expected volatility, dividend yield and risk-free rates were 31%, 4.65%, and 1.2%, respectively.

At September 30, 2010, the remaining weighted-average contractual term was 1.6 years. There were no performance shares granted for the three months ended September 30, 2010 and 2009. The weighted-average grant-date fair value of shares granted year to date September 30, 2010, was $23.37. The weighted-average grant-date fair value of shares granted year to date September 30, 2009, was $14.35. At September 30, 2010, there was $3.7 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 year to date September 30, 2010, was insignificant. There were no performance shares earned and paid for the three months ended and year to date September 30, 2009.

Restricted Stock

Restricted stock activity year to date September 30, 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	(29,760)	19.05
Ending balance	421,177	16.21
* weighted-average

At September 30, 2010, the remaining weighted-average contractual term was 1.5 years. The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2010, was $18.32 and $17.80, respectively. The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2009, was $18.03 and $14.50, respectively. At September 30, 2010, there was $3.4 million of total unrecognized compensation expense, net of forfeiture rates, related to nonvested restricted stock granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term. The total fair value of shares vested for the three months ended and year to date September 30, 2010, was $0.9 million and $7.3 million, respectively. The total fair value of shares vested for the three months ended and year to date September 30, 2009, was insignificant and $5.4 million, respectively.

Stock Options

Stock options were granted under the Long-Term Incentive Plan during 2001-2003 and GMO stock options outstanding on the July 14, 2008, acquisition date were converted to Great Plains Energy stock options. All stock options are fully vested at September 30, 2010. Stock option activity under all plans year to date September 30, 2010, is summarized in the following table.


		Exercise
Stock Options	Shares	Price*
Beginning balance	244,610	$ 36.73
Exercised	(917)	9.21
Forfeited or expired	(29,681)	62.17
Outstanding and exercisable at September 30, 2010	214,012	33.32
* weighted-average

There were no stock options exercised during the three months ended September 30, 2010. The weighted-average grant-date fair value of options exercised year to date September 30, 2010, was $9.21. The weighted-average grant-date fair value of options exercised for the three months ended and year to date September 30, 2009, was $10.65 and $10.94 per share, respectively. The aggregate intrinsic value and cash received for options exercised for the three months ended and year to date September 30, 2010 and 2009, was insignificant. At September 30, 2010, there were no in-the-money outstanding and exercisable options.

The following table summarizes all outstanding and exercisable stock options as of September 30, 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	203,656	1.2	$ 24.51
$181.11	3,998	0.3	181.11
$221.82 - $251.86	6,358	0.6	222.33
Total	214,012	1.1	33.32

SHORT TERM BORROWINGS AND SHORT TERM BANK LINES OF CREDIT

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

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

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

Great Plains Energy’s $200 Million Revolving Credit Facility

In August 2010, Great Plains Energy entered into a new $200 million revolving credit facility with a group of banks that expires in August 2013. The facility replaced a $400 million revolving credit facility with a group of banks that would have expired in May 2011 and was sized based on expected short-term debt requirements over the facility’s term. The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time. A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At September 30, 2010, Great Plains Energy was in compliance with this covenant. At September 30, 2010, Great Plains Energy had $22.0 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

In August 2010, KCP&L entered into a new $600 million revolving credit facility with a group of banks to provide support for its issuance of commercial paper and other general corporate purposes that expires in August 2013. The facility replaced a $600 million facility with a group of banks that would have expired in May 2011. Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities. A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At September 30, 2010, KCP&L was in compliance with this covenant. At September 30, 2010, KCP&L had $209.5 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

In August 2010, GMO entered into a new $450 million revolving credit facility with a group of banks that expires in August 2013. The facility replaced a $400 million revolving credit facility with a group of banks that would have expired in September 2011 and was sized based on expected short-term debt requirements over the facility’s term. Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities. A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At September 30, 2010, GMO was in compliance with this covenant. At September 30, 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

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Long-Term Debt

10.	LONG-TERM DEBT

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


		September 30			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			(0.3	)		(0.2	)
Unamortized discount			(2.0	)		(2.1	)
Total KCP&L			1,779.7			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
0.289%*** Wamego Series 1996	2026		7.3			7.3
0.937%*** 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			58.6			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			(0.6	)		(0.4	)
Total Great Plains Energy excluding current maturities		$	3,101.3		$	3,213.0
* Weighted-average interest rates at September 30, 2010
** Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
*** Variable rate

Fair Value of Long-Term Debt

Fair value of long-term debt is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices were not available. At September 30, 2010, and December 31, 2009, the book value of Great Plains Energy’s long-term debt, including current maturities, was $3.4 billion and $3.2 billion, respectively. At September 30, 2010, and December 31, 2009, the fair value of Great Plains Energy’s long-term debt, including current maturities, was $3.8 billion and $3.4 billion, respectively. At September 30, 2010, and December 31, 2009, the book value of KCP&L’s long-term debt, including current maturities, was $1.8 billion. At September 30, 2010, and December 31, 2009, the fair value of KCP&L’s long-term debt, including current maturities, was $2.0 billion and $1.9 billion, respectively.

Amortization of Debt Expense

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


	Three Months Ended				Year to Date
	September 30				September 30
	2010		2009		2010		2009
	(millions)
KCP&L	$	0.7	$	0.5	$	1.8	$	1.5
Other Great Plains Energy		1.2		0.8		2.5		1.7
Total Great Plains Energy	$	1.9	$	1.3	$	4.3	$	3.2

KCP&L EIRR Bonds

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.

Great Plains Energy 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%.

COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Commitments and Contingencies

11.	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 regulations 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. 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 set to be accomplished through establishment of permanent statewide caps for NOx effective January 1, 2009, and SO2 effective January 1, 2010. 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 September 30, 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. KCP&L is permitted to sell excess SO2 emission allowances in accordance with KCP&L’s Comprehensive Energy Plan as approved by the MPSC and KCC. At September 30, 2010, GMO had accumulated unused SO2 emission allowances sufficient to support just over 18,000 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, which are recorded in inventory at average cost. KCP&L and GMO purchase NOx allowances as needed.

In 2009, KCP&L completed environmental upgrades at Iatan No. 1 for compliance with the current CAIR rule as part of its Comprehensive Energy Plan. 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, with 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 September and October 2010, the EPA supplemented the record supporting the proposed Transport Rule. The EPA made available additional information relevant to the rulemaking, including, among other things, an updated version of the power sector modeling that the EPA proposes to use to support the final rule.

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 will attempt to address 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 Rule (BART)

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. Neither Missouri nor Kansas has received EPA approval for their BART plans.

Mercury 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. Until a rule is finalized, the financial and operational impacts to Great Plains Energy and KCP&L cannot be determined.

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. 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 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. 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 $200 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 requires 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. KCP&L is constructing a 48MW wind project adjacent to its existing Spearville wind site with wind turbines it currently owns, which is expected to be completed in December 2010. KCP&L also intends to secure 52MW of renewable energy credits. 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. Also as provided for in the Collaboration Agreement, KCP&L issued, in 2008, requests for proposals for equipment required to comply with BART at the LaCygne Station. KCP&L is continuing to evaluate compliance options in light of developing potential legislative and regulatory environmental requirements.

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, including the establishment of a goal to reduce greenhouse gas emissions. International agreements legally binding on the United States may be reached in the future. Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels. The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 23 million tons and 17 million tons per year for Great Plains Energy and KCP&L, respectively.

Laws have recently been passed in Missouri and Kansas, the states in which the Companies’ retail electric businesses are operated, setting renewable energy standards, and management believes that national 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. 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. In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (House Bill), which would establish a renewable electricity standard and a greenhouse gas cap and trade program that would require Great Plains Energy, KCP&L and other affected entities to surrender allowances or offsets for each ton of greenhouse gas emitted, and that would reduce the available quantity of emission allowances over time. The U.S. Senate has not yet enacted companion legislation. Legislation proposed or enacted in the future, however, may include greenhouse gas reduction measures, including those contained in the House Bill. 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 April 2010, the EPA finalized greenhouse gas emission standards for light-duty vehicles. These are the first-ever national greenhouse gas emission standards under the 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 GHG emissions that define when permits under the PSD and Title V Operating Permit programs are required for new and existing industrial facilities. The EPA will phase in the Clean Air Act permitting requirements for greenhouse gas emissions in two initial steps. In step 1, starting 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) would be 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, would need to determine the best available control technology for their greenhouse gas emissions. In addition, sources subject to the Title V Operating Permit Program would 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.

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. Regulations implementing these laws are being drafted by the MPSC and KCC, and the ultimate impacts on the Companies cannot be reasonably estimated at this time. Subject to the terms of the final MPSC regulations, KCP&L and GMO project that their current renewable resources (including accumulated renewable energy credits), combined with an expected purchase of solar renewable energy credits, will be sufficient for compliance with the Missouri requirements through 2013. KCP&L also projects, subject to the terms of the final KCC regulations, 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.

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 are 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.

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. 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, among other things, to 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. 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, 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. The Companies principally use coal in generating electricity and dispose of the combustion products 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 September 30, 2010, and December 31, 2009, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site. At September 30, 2010, and December 31, 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 September 30, 2010, Great Plains Energy had $2.0 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 $2.2 million in insurance proceeds less an annual deductible is available to GMO to recover qualified MGP remediation expenses. GMO would seek recovery of additional remediation costs and expenses through rate increases; however, there can be no assurance that such rate increases would be granted.

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

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

LEGAL PROCEEDINGS

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Legal Proceedings

12.	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.

KCP&L Spent Nuclear Fuel and Radioactive Waste

KCP&L and the other two Wolf Creek owners have a lawsuit pending 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. Approximately seventy other similar cases were filed with that court, a few of which have settled. To date, the court has rendered final decisions in several of the cases, most of which are on appeal now. Another Federal appellate court has already determined that the government breached its obligation to begin accepting spent fuel for disposal. The questions now before the court in the pending cases are whether and to what extent the utilities are entitled to monetary damages for that breach. The Wolf Creek case was tried before a Court of Federal Claims judge in June 2010 and the parties expect a decision in late 2010.

KCP&L Advanced Coal Credit Arbitration

In 2009, KCP&L was served a notice to arbitrate by 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. 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. Management cannot predict the outcome of this matter.

GMO Price Reporting Litigation

In response to complaints of manipulation of the California energy market, in 2002 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, 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. The MPSC has appealed the dismissal to the Missouri Court of Appeals for the Western District of Missouri. In December 2009, the court affirmed the dismissal and the MPSC filed a request for rehearing or, in the alternative, transfer to the Missouri Supreme Court. The Supreme Court accepted the transfer in April 2010, but in September 2010, transferred the case back to the Court of Appeals.

The ultimate outcome of these matters cannot be predicted.

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

13.	RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO’s business and operate its facilities at cost. These costs totaled $26.3 million and $73.5 million, respectively, for the three months ended and year to date September 30, 2010. These costs totaled $24.6 million and $75.2 million, respectively, for the same periods in 2009. Additionally, KCP&L and GMO engage in wholesale electricity transactions with each other. KCP&L and GMO are also authorized to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO. The following table summarizes KCP&L’s related party receivables and payables.


	September 30			December 31
	2010			2009
	(millions)
Receivable (payable) from/to GMO	$	(19.0	)		$	26.4
Payable to Services		-				(0.2	)
Receivable from Great Plains Energy		12.7				15.1
Receivable from MPS Merchant		-				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

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Derivative Instruments

14.	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 post collateral, in the normal course of business, for the aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a liability position. If the credit risk-related contingent features underlying these agreements were triggered, Great Plains Energy and KCP&L would be required to post an insignificant amount of collateral to its counterparties.

The 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 Forward Starting Swaps (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 September 30, 2010, $0.3 million of the loss has been reclassified from OCI to interest expense.

Since December 2009, Great Plains Energy has 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 for the three months ended and year to date September 30, 2010. At September 30, 2010, a $25.1 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 September 30, 2010, KCP&L has hedged 7% of the 2011 projected natural gas usage for retail load and firm MWh sales, primarily by utilizing futures contracts and financial instruments. The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense. KCP&L has not recorded any ineffectiveness on natural gas hedges for the three months ended and year to date September 30, 2010 and 2009.

GMO’s risk management policy is to use derivative instruments to mitigate exposure to natural gas price volatility in the market. The fair value of the portfolio relates to financial contracts that will settle against actual purchases of natural gas and purchased power. At September 30, 2010, GMO had financial contracts in place to hedge all for the remainder of 2010, 44% for 2011 and 7% for 2012 of the expected on-peak natural gas and natural gas equivalent purchased power price exposure. 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 costs are 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 that 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 trading energy contracts, both physical and financial, as derivative assets or liabilities with an offsetting entry to Great Plains Energy’s consolidated statements of income.

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


	September 30					December 31
	2010					2009
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	0.3	$	(0.1	)	$	3.2	$	-
Non-hedging derivatives		17.9		(4.2	)		29.8		(0.9	)
Forward contracts
Non-hedging derivatives		206.5		9.1			234.4		9.1
Option contracts
Cash flow hedges		-		-			2.3		0.2
Non-hedging derivatives		0.5		0.1			-		-
Anticipated debt issuance
Forward starting swaps		350.0		(25.1	)		362.5		(0.7	)
KCP&L
Future contracts
Cash flow hedges		0.3		(0.1	)		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
September 30, 2010	Classification	Fair Value	Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$ -	$ 0.1
Interest rate contracts	Derivative instruments	-	25.1
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments	9.2	4.2
Total Derivatives		$ 9.2	$ 29.4

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
September 30, 2010	Classification	Fair Value	Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$ -	$ 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
Three Months Ended September 30, 2010	(millions)			(millions)
Interest rate contracts		$ (9.9)	Interest charges	$ (2.6)
Commodity contracts		(0.4)	Fuel	(0.5)
Income tax benefit (expense)		4.0	Income tax benefit (expense)	1.1
Total		$ (6.3)	Total	$ (2.0)

Year to Date September 30, 2010
Interest rate contracts		$ (31.4)	Interest charges	$ (7.2)
Commodity contracts		(1.0)	Fuel	(0.5)
Income tax benefit (expense)		12.6	Income tax benefit (expense)	2.9
Total		$ (19.8)	Total	$ (4.8)

Three Months Ended September 30, 2009
Interest rate contracts		$ -	Interest charges	$ (2.1)
Commodity contracts		(0.6)	Fuel	(1.1)
Income tax benefit (expense)		0.2	Income tax benefit (expense)	1.1
Total		$ (0.4)	Total	$ (2.1)

Year to Date September 30, 2009
Interest rate contracts		$ 1.0	Interest charges	$ (5.6)
Commodity contracts		(0.9)	Fuel	(1.1)
Income tax benefit (expense)		-	Income tax benefit (expense)	2.6
Total		$ 0.1	Total	$ (4.1)

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
Three Months Ended September 30, 2010	(millions)			(millions)
Interest rate contracts		$ -	Interest charges	$ (2.2)
Commodity contracts		(0.4)	Fuel	(0.5)
Income tax benefit (expense)		0.2	Income tax benefit (expense)	1.1
Total		$ (0.2)	Total	$ (1.6)

Year to Date September 30, 2010
Interest rate contracts		$ -	Interest charges	$ (6.6)
Commodity contracts		(1.0)	Fuel	(0.5)
Income tax benefit (expense)		0.4	Income tax benefit (expense)	2.8
Total		$ (0.6)	Total	$ (4.3)

Three Months Ended September 30, 2009
Interest rate contracts		$ -	Interest charges	$ (2.2)
Commodity contracts		(0.6)	Fuel	(1.1)
Income tax benefit (expense)		0.2	Income tax benefit (expense)	1.3
Total		$ (0.4)	Total	$ (2.0)

Year to Date September 30, 2009
Interest rate contracts		$ 1.0	Interest charges	$ (5.3)
Commodity contracts		(0.9)	Fuel	(1.1)
Income tax benefit (expense)		-	Income tax benefit (expense)	2.5
Total		$ 0.1	Total	$ (3.9)

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
Three Months Ended September 30, 2010	(millions)		(millions)
Commodity contracts	$ (2.8)	Fuel	$ (1.6)
Total	$ (2.8)	Total	$ (1.6)

Year to Date September 30, 2010
Commodity contracts	$ (8.7)	Fuel	$ (5.9)
Total	$ (8.7)	Total	$ (5.9)

Three Months Ended September 30, 2009
Commodity contracts	$ (0.2)	Fuel	$ (10.9)
Total	$ (0.2)	Total	$ (10.9)

Year to Date September 30, 2009
Commodity contracts	$ (11.1)	Fuel	$ (17.0)
Total	$ (11.1)	Total	$ (17.0)

Great Plains Energy’s income statement reflects gains (losses) for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $(1.6) million and an insignificant amount for the three months ended and year to date September 30, 2010, respectively, and $1.4 million and $2.0 million, respectively, for the three months ended and year to date September 30, 2009.

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


	Great Plains Energy						KCP&L
	September 30			December 31			September 30			December 31
	2010			2009			2010			2009
	(millions)
Current assets	$	12.2		$	13.3		$	12.2		$	13.3
Current liabilities		(109.0	)		(84.9	)		(74.1	)		(81.2	)
Noncurrent liabilities		-			(0.5	)		-			-
Deferred income taxes		37.7			28.0			24.1			26.4
Total	$	(59.1	)	$	(44.1	)	$	(37.8	)	$	(41.5	)

Great Plains Energy’s accumulated OCI in the table above at September 30, 2010, includes $14.4 million that is expected to be reclassified to expense over the next twelve months. KCP&L’s accumulated OCI includes $8.8 million that is expected to be reclassified to expense over the next twelve months.

FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Fair Value Measurements

15.	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 September 30, 2010, and December 31, 2009.


							Fair Value Measurements Using
Description	September 30 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)	$	-		$	-		$	-	$	-		$	-
Nuclear decommissioning trust (b)
Equity securities		76.6			-			76.6		-			-
Debt securities
U.S. Treasury		8.4			-			8.4		-			-
U.S. Agency		5.3			-			-		5.3			-
State and local obligations		2.4			-			-		2.4			-
Corporate bonds		24.8			-			-		24.8			-
Foreign governments		0.7			-			-		0.7			-
Other		(0.3	)		-			-		(0.3	)		-
Total nuclear decommissioning trust		117.9			-			85.0		32.9			-
Total		117.9			-			85.0		32.9			-
Liabilities
Derivative instruments (a)		-			(0.1	)		0.1		-			-
Total	$	-		$	(0.1	)	$	0.1	$	-		$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	9.2		$	-		$	0.1	$	5.4		$	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		16.4			-			0.3		12.4			3.7
Liabilities
Derivative instruments (a)		25.1			(4.2	)		4.2		25.1			-
Total	$	25.1		$	(4.2	)	$	4.2	$	25.1		$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	9.2		$	-		$	0.1	$	5.4		$	3.7
Nuclear decommissioning trust (b)		117.9			-			85.0		32.9			-
SERP rabbi trust (c)		7.2			-			0.2		7.0			-
Total		134.3			-			85.3		45.3			3.7
Liabilities
Derivative instruments (a)		25.1			(4.3	)		4.3		25.1			-
Total	$	25.1		$	(4.3	)	$	4.3	$	25.1		$	-


						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 priced 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 $2.8 million and $29.4 million at September 30, 2010, and December 31, 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 $15.0 million and $16.2 million at September 30, 2010, and December 31, 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 September 30, 2010, and December 31, 2009, Great Plains Energy netted $4.3 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 the three months ended and year to date September 30, 2010 and 2009.


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other
	Great
	Plains
	Energy
	Derivative
	Instruments
	(millions)
Balance July 1, 2010	$	5.2
Total realized/unrealized gains or (losses)
Included in non-operating income		(3.6	)
Settlements		2.1
Balance September 30, 2010	$	3.7

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at September 30, 2010	$	(1.3	)


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		-			(9.5	)		(9.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			9.1			9.1
Balance September 30, 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 September 30, 2010	$	-		$	-		$	-


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 July 1, 2009	$ 2.9		$ 0.5	$ 3.5	$ 6.9	$ 3.4	$ 10.3
Total realized/unrealized gains or (losses)
Included in regulatory liability	(0.1)		-	0.6	0.5	-	0.5
Included in non-operating income	-		-	-	-	1.0	1.0
Purchase, issuances, and settlements	-		-	1.3	1.3	(0.1)	1.2
Transfers in and/or out of Level 3	-		(0.1)	-	(0.1)	-	(0.1)
Balance September 30, 2009	$ 2.8		$ 0.4	$ 5.4	$ 8.6	$ 4.3	$ 12.9

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at September 30, 2009	$ -		$ -	$ -	$ -	$ 1.1	$ 1.1


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		0.1				-		0.8		0.9		-		0.9
Included in non-operating income		-				-		-		-		1.2		1.2
Purchase, issuances, and settlements		(1.2	)			-		1.7		0.5		(0.7)		(0.2	)
Transfers in and/or out of Level 3		-				0.4		-		0.4		-		0.4
Balance September 30, 2009	$	2.8			$	0.4	$	5.4	$	8.6	$	4.3	$	12.9

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at September 30, 2009	$	-			$	-	$	-	$	-	$	0.9	$	0.9

- 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

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Taxes

16.

TAXES

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


	Three Months Ended						Year to Date
	September 30						September 30
Great Plains Energy	2010			2009			2010			2009
Current income taxes	(millions)
Federal	$	(7.2	)	$	16.1		$	(8.1	)	$	(1.3	)
State		(2.0	)		1.1			0.3			(2.6	)
Foreign		(0.2	)		-			0.2			1.2
Total		(9.4	)		17.2			(7.6	)		(2.7	)
Deferred income taxes
Federal		73.5			(5.8	)		108.2			(13.6	)
State		14.6			4.0			18.8			8.8
Total		88.1			(1.8	)		127.0			(4.8	)
Noncurrent income taxes
Federal		(6.8	)		7.7			(1.3	)		6.8
State		(1.0	)		0.9			(0.3	)		0.8
Foreign		0.2			0.6			0.2			(1.9	)
Total		(7.6	)		9.2			(1.4	)		5.7
Investment tax credit
Deferral		-			12.2			(4.1	)		28.4
Amortization		(0.7	)		(0.6	)		(1.8	)		(1.7	)
Total		(0.7	)		11.6			(5.9	)		26.7
Total income tax expense		70.4			36.2			112.1			24.9
Less: taxes on discontinued operations
Deferred tax expense (benefit)		-			0.6			-			(1.4	)
Income tax expense on continuing operations	$	70.4		$	35.6		$	112.1		$	26.3


	Three Months Ended						Year to Date
	September 30						September 30
KCP&L	2010			2009			2010			2009
Current income taxes	(millions)
Federal	$	(15.3	)	$	41.4		$	22.5		$	51.9
State		(2.6	)		5.0			4.6			6.9
Total		(17.9	)		46.4			27.1			58.8
Deferred income taxes
Federal		63.9			(34.8	)		53.9			(49.6	)
State		11.7			(1.0	)		9.5			-
Total		75.6			(35.8	)		63.4			(49.6	)
Noncurrent income taxes
Federal		(2.4	)		3.6			(1.5	)		2.9
State		(0.3	)		0.4			(0.1	)		0.4
Total		(2.7	)		4.0			(1.6	)		3.3
Investment tax credit
Deferral		-			12.2			(4.1	)		28.4
Amortization		(0.5	)		(0.4	)		(1.2	)		(1.1	)
Total		(0.5	)		11.8			(5.3	)		27.3
Total	$	54.5		$	26.4		$	83.6		$	39.8

Great Plains Energy’s income tax expense increased $34.8 million and $85.8 million for the three months ended and year to date September 30, 2010, respectively, compared to the same periods in 2009 due to increased pre-tax income. Year to date September 30, 2009, reflects a $16.0 million tax benefit due to the settlement of GMO’s 2003-2004 tax audit. A significant portion of total income tax expense in 2010 is reflected as deferred income tax expense due to the utilization of net operating losses and accelerated tax deductions, including bonus depreciation, which reduce the current tax liability of Great Plains Energy.

KCP&L’s income tax expense increased $28.1 million and $43.8 million for the three months ended and year to date September 30, 2010, respectively, compared to the same periods in 2009 due to increased pre-tax income. A significant portion of total income tax expense in 2010 is reflected as deferred income tax expense due to accelerated tax deductions, including bonus depreciation, which reduce the current tax liability of KCP&L.

Income Tax Expense and Effective Income Tax Rates

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


Great Plains Energy	Income Tax Expense						Income Tax Rate
Three Months Ended September 30	2010			2009			2010			2009
	(millions)
Federal statutory income tax	$	70.8		$	39.9			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		(0.9	)		(2.4	)		(0.4	)		(2.1	)
Amortization of investment tax credits		(0.7	)		(0.6	)		(0.4	)		(0.5	)
Federal income tax credits		(2.0	)		(1.9	)		(0.9	)		(1.7	)
State income taxes		7.5			4.0			3.7			3.5
Changes in uncertain tax positions, net		0.3			0.8			0.2			0.6
Valuation allowance		(2.9	)		-			(1.4	)		-
Other		(1.7	)		(4.2	)		(1.0	)		(3.5	)
Total	$	70.4		$	35.6			34.8	%		31.3	%


Great Plains Energy	Income Tax Expense						Income Tax Rate
Year to Date September 30	2010			2009			2010			2009
	(millions)
Federal statutory income tax	$	115.0		$	57.1			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		(6.0	)		(8.6	)		(1.8	)		(5.3	)
Amortization of investment tax credits		(1.8	)		(1.7	)		(0.5	)		(1.0	)
Federal income tax credits		(6.1	)		(6.5	)		(1.8	)		(4.0	)
State income taxes		12.0			5.4			3.7			3.3
Medicare Part D subsidy legislation		2.8			-			0.8			-
Changes in uncertain tax positions, net		0.3			(72.5	)		0.1			(44.5	)
Valuation allowance		(2.9	)		56.5			(0.9	)		34.6
Other		(1.2	)		(3.4	)		(0.5	)		(2.0	)
Total	$	112.1		$	26.3			34.1	%		16.1	%


KCP&L	Income Tax Expense						Income Tax Rate
Three Months Ended September 30	2010			2009			2010			2009
	(millions)
Federal statutory income tax	$	51.5		$	32.2			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		(1.1	)		(3.0	)		(0.8	)		(3.2	)
Amortization of investment tax credits		(0.5	)		(0.4	)		(0.4	)		(0.4	)
Federal income tax credits		(1.9	)		(1.6	)		(1.3	)		(1.8	)
State income taxes		5.7			3.0			3.9			3.2
Changes in uncertain tax positions, net		0.1			(0.1	)		0.1			(0.1	)
Other		0.7			(3.7	)		0.6			(4.0	)
Total	$	54.5		$	26.4			37.1	%		28.7	%


KCP&L	Income Tax Expense						Income Tax Rate
Year to Date September 30	2010			2009			2010			2009
	(millions)
Federal statutory income tax	$	85.3		$	52.0			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		(5.2	)		(6.8	)		(2.2	)		(4.6	)
Amortization of investment tax credits		(1.2	)		(1.1	)		(0.5	)		(0.7	)
Federal income tax credits		(6.0	)		(5.8	)		(2.5	)		(3.9	)
State income taxes		8.8			4.8			3.6			3.2
Medicare Part D subsidy legislation		2.8			-			1.2			-
Changes in uncertain tax positions, net		0.1			-			0.1			-
Other		(1.0	)		(3.3	)		(0.4	)		(2.2	)
Total	$	83.6		$	39.8			34.3	%		26.8	%

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 12 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 year to date September 30, 2010, was $4.1 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 an insignificant amount of tax benefits of the ITC in the third quarter of 2010 when the plant was placed in service and will continue to recognize the tax benefits over the life of the plant. At September 30, 2010, Great Plains Energy and KCP&L had $107.1 million of deferred advanced coal ITC.

Uncertain Tax Positions

At September 30, 2010, and December 31, 2009, Great Plains Energy had $52.4 million and $51.4 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $17.5 million and $17.3 million, respectively, at September 30, 2010 and December 31, 2009, are expected to impact the effective tax rate, if recognized.

At September 30, 2010, and December 31, 2009, KCP&L had $19.3 million and $20.9 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $0.4 million at September 30, 2010, and December 31, 2009, are expected to impact the effective tax rate, if recognized.

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


	Great Plains Energy							KCP&L
		September 30			December 31			September 30			December 31
		2010			2009			2010			2009
	(millions)
Beginning balance		$	51.4		$	97.3		$	20.9		$	17.6
Additions for current year tax positions			2.0			13.2			1.0			3.9
Additions for prior year tax positions			3.5			8.2			1.6			3.0
Additions for GMO prior year tax positions			-			11.6			-			-
Reductions for prior year tax positions			(1.8	)		(1.3	)		(1.3	)		(0.8	)
Settlements			(2.9	)		(76.7	)		(2.9	)		(2.2	)
Statute expirations			-			(0.7	)		-			(0.6	)
Foreign currency translation adjustments			0.2			(0.2	)		-			-
Ending balance		$	52.4		$	51.4		$	19.3		$	20.9

Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and recognize penalties related to unrecognized tax benefits in non-operating expenses. At September 30, 2010, and December 31, 2009, accrued interest related to unrecognized tax benefits for Great Plains Energy was $6.5 million and $5.9 million, respectively. Amounts accrued for penalties related to unrecognized tax benefits for Great Plains Energy were $1.1 million at September 30, 2010, and December 31, 2009. KCP&L had accrued interest related to unrecognized tax benefits of $1.5 million and $1.7 million at September 30, 2010, and December 31, 2009, respectively. Amounts accrued for penalties related to unrecognized tax benefits for KCP&L are insignificant.

In July 2010, the Joint Committee on Taxation approved the settlement of the IRS audit of Great Plains Energy’s 2005 tax year. Great Plains Energy and KCP&L recognized $2.9 million of unrecognized tax benefits in the third quarter of 2010 associated with this settlement. 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 is unable to estimate the amount of unrecognized tax benefits that may be recognized in the next twelve months.

SEGMENTS AND RELATED INFORMATION

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Segments and Related Information

17.	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, Services, KLT Inc., unallocated corporate charges, consolidating entries and intercompany eliminations. Intercompany eliminations include insignificant amounts of intercompany financing-related activities. The summary of significant accounting policies applies to the reportable segment. Segment performance is evaluated based on net income attributable to Great Plains Energy.

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


Three Months Ended	Electric Utility						Great Plains
September 30, 2010	Electric Utility			Other			Energy
	(millions)
Operating revenues	$	728.8		$	-		$	728.8
Depreciation and amortization		(85.3	)		-			(85.3	)
Interest charges		(34.8	)		(10.7	)		(45.5	)
Income tax (expense) benefit		(77.0	)		6.6			(70.4	)
Net income (loss) attributable to Great Plains Energy		136.2			(4.2	)		132.0


Year to Date	Electric Utility						Great Plains
September 30, 2010	Electric Utility			Other			Energy
	(millions)
Operating revenues	$	1,787.7		$	-		$	1,787.7
Depreciation and amortization		(248.5	)		-			(248.5	)
Interest charges		(107.4	)		(31.3	)		(138.7	)
Income tax (expense) benefit		(125.4	)		13.3			(112.1	)
Loss from equity investments		-			(0.9	)		(0.9	)
Net income (loss) attributable to Great Plains Energy		232.8			(16.2	)		216.6


Three Months Ended	Electric Utility						Great Plains
September 30, 2009	Electric Utility			Other			Energy
	(millions)
Operating revenues	$	587.7		$	-		$	587.7
Depreciation and amortization		(77.9	)		-			(77.9	)
Interest charges		(38.6	)		(10.4	)		(49.0	)
Income tax (expense) benefit		(42.2	)		6.6			(35.6	)
Loss from equity investments		-			(0.2	)		(0.2	)
Discontinued operations		-			0.8			0.8
Net income (loss) attributable to Great Plains Energy		83.9			(4.8	)		79.1


Year to Date	Electric Utility						Great Plains
September 30, 2009	Electric Utility			Other			Energy
	(millions)
Operating revenues	$	1,487.4		$	-		$	1,487.4
Depreciation and amortization		(220.3	)		-			(220.3	)
Interest charges		(113.6	)		(19.6	)		(133.2	)
Income tax (expense) benefit		(55.5	)		29.2			(26.3	)
Loss from equity investments		-			(0.4	)		(0.4	)
Discontinued operations		-			(2.3	)		(2.3	)
Net income attributable to Great Plains Energy		134.1			0.4			134.5


	Electric Utility		Other		Eliminations				Great Plains Energy
September 30, 2010	(millions)
Assets	$	9,115.2	$	97.1		$	(413.2	)		$	8,799.1
Capital expenditures (a)		465.3		-			-				465.3
December 31, 2009
Assets	$	8,765.3	$	152.5		$	(435.0	)		$	8,482.8
Capital expenditures (a)		841.3		-			-				841.3
(a) Capital expenditures reflect year to date amounts for the periods presented.

DISCONTINUED OPERATIONS

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Discontinued Operations

18.	DISCONTINUED OPERATIONS

In 2008, Great Plains Energy sold Strategic Energy, L.L.C. to Direct Energy Services, LLC (Direct Energy), a subsidiary of Centrica. In the second quarter of 2009, Great Plains Energy recorded $5.1 million of gross receipts taxes for periods prior to the sale for which Great Plains Energy indemnified Direct Energy. In the third quarter of 2009, Great Plains Energy reduced its previously recorded reserve of $2.0 million related to indemnification obligations by $1.4 million. Corresponding income tax expense of $0.6 million and a $1.4 million tax benefit for the three months ended and year to date September 30, 2009, respectively, resulted in $0.8 million income and $2.3 million loss from discontinued operations, net of income taxes for the three months ended and year to date September 30, 2009, respectively.

GOODWILL

9 Months Ended

Sep. 30, 2010

Notes to Financial Statements [Abstract]

Goodwill

19.

GOODWILL

Goodwill is required to be tested for impairment at least annually and more frequently when indicators of impairment exist. The annual impairment test for the GMO acquisition goodwill was conducted on September 1, 2010. The goodwill impairment test is a two step process, the first step of which is the comparison of 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.

- 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

Document Information	9 Months Ended
Document Information	Sep. 30, 2010
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2010

Entity Information (USD $)	9 Months Ended
Entity Information (USD $)	Sep. 30, 2010	Jun. 30, 2009
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	No
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 2,101,763,626
Entity Common Stock, Shares Outstanding	136,036,530
Document Fiscal Year Focus	2010
Document Fiscal Period Focus	Q3