10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

or

[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from _______to_______

	Exact name of registrant as specified in charter,
Commission	state of incorporation, address of principal	I.R.S. Employer
File Number	executive offices and telephone number	Identification Number
001-32206	GREAT PLAINS ENERGY INCORPORATED	43-1916803
	(A Missouri Corporation)
	1200 Main Street
	Kansas City, Missouri  64105
	(816) 556-2200
000-51873	KANSAS CITY POWER & LIGHT COMPANY	44-0308720
	(A Missouri Corporation)
	1200 Main Street
	Kansas City, Missouri  64105
	(816) 556-2200

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange

Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been

subject to such filing requirements for the past 90 days.

Great Plains Energy Incorporated

Yes

X

No

_

Kansas City Power & Light Company

Yes

X

No

_

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive

Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12

months (or for such shorter period that the registrant was required to submit and post such files).

Great Plains Energy Incorporated

Yes

X

No

_

Kansas City Power & Light Company

Yes

X

No

_

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting

company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the

Exchange Act.

Great Plains Energy Incorporated

Large accelerated filer

X

Accelerated filer

_

Non-accelerated filer

_

Smaller reporting company

_

Kansas City Power & Light Company

Large accelerated filer

_

Accelerated filer

_

Non-accelerated filer

X

Smaller reporting company

_

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Great Plains Energy Incorporated

Yes

_

No

X

Kansas City Power & Light Company

Yes

_

No

X

On October 31, 2011, Great Plains Energy Incorporated had 136,087,321 shares of common stock outstanding.  On October 31, 2011,

Kansas City Power & Light Company had one share of common stock outstanding and held by Great Plains Energy Incorporated.

Kansas City Power & Light Company meets the conditions set forth in General Instruction (H)(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

This combined Quarterly Report on Form 10-Q is being filed by Great Plains Energy Incorporated (Great Plains Energy) and Kansas City Power & Light Company (KCP&L).  KCP&L is a wholly owned subsidiary of Great Plains Energy and represents a significant portion of its assets, liabilities, revenues, expenses and operations.  Thus, all information contained in this report relates to, and is filed by, Great Plains Energy.  Information that is specifically identified in this report as relating solely to Great Plains Energy, such as its financial statements and all information relating to Great Plains Energy’s other operations, businesses and subsidiaries, including KCP&L Greater Missouri Operations Company (GMO), does not relate to, and is not filed by, KCP&L.  KCP&L makes no representation as to that information.  Neither Great Plains Energy nor its other subsidiaries have any obligation in respect of KCP&L’s debt securities and holders of such securities should not consider Great Plains Energy’s or its other subsidiaries’ financial resources or results of operations in making a decision with respect to KCP&L’s debt securities.  Similarly, KCP&L has no obligation in respect of securities of Great Plains Energy or its other subsidiaries.

This report should be read in its entirety.  No one section of the report deals with all aspects of the subject matter.  It should be read in conjunction with the consolidated financial statements and related notes and with the management’s discussion and analysis included in the 2010 Form 10-K for each of Great Plains Energy and KCP&L.

CAUTIONARY STATEMENTS REGARDING CERTAIN FORWARD-LOOKING INFORMATION

Statements made in this report that are not based on historical facts are forward-looking, may involve risks and uncertainties, and are intended to be as of the date when made.  Forward-looking statements include, but are not limited to, the outcome of regulatory proceedings, cost estimates of capital projects and other matters affecting future operations.  In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, Great Plains Energy and KCP&L are providing a number of important factors that could cause actual results to differ materially from the provided forward-looking information.  These important factors include: future economic conditions in regional, national and international markets and their effects on sales, prices and costs, including but not limited to possible further deterioration in economic conditions and the timing and extent of economic recovery; prices and availability of electricity in regional and national wholesale markets; market perception of the energy industry, Great Plains Energy and KCP&L; changes in business strategy, operations or development plans; effects of current or proposed state and federal legislative and regulatory actions or developments, including, but not limited to, deregulation, re-regulation and restructuring of the electric utility industry; decisions of regulators regarding rates the Companies can charge for electricity; adverse changes in applicable laws, regulations, rules, principles or practices governing tax, accounting and environmental matters including, but not limited to, air and water quality; financial market conditions and performance including, but not limited to, changes in interest rates and credit spreads and in availability and cost of capital and the effects on nuclear decommissioning trust and pension plan assets and costs; impairments of long-lived assets or goodwill; credit ratings; inflation rates; effectiveness of risk management policies and procedures and the ability of counterparties to satisfy their contractual commitments; impact of terrorist acts, including, but not limited to, cyber-terrorism; ability to carry out marketing and sales plans; weather conditions including, but not limited to, weather-related damage and their effects on sales, prices and costs; cost, availability, quality and deliverability of fuel; the inherent uncertainties in estimating the effects of weather, economic conditions and other factors on customer consumption and financial results; ability to achieve generation goals and the occurrence and duration of planned and unplanned generation outages; delays in the anticipated in-service dates and cost increases of generation, transmission, distribution or other projects; the inherent risks associated with the ownership and operation of a nuclear facility including, but not limited to, environmental, health, safety, regulatory and financial risks; workforce risks, including, but not limited to, increased costs of retirement, health care and other benefits; and other risks and uncertainties.

This list of factors is not all-inclusive because it is not possible to predict all factors.  Part II Item 1A Risk Factors included in this report, together with the risk factors included in the 2010 Form 10-K for each of Great Plains Energy and KCP&L under Part I Item 1A, should be carefully read for further understanding of potential risks for each of Great Plains Energy and KCP&L.  Other sections of this report and other periodic reports filed by each of Great Plains Energy and KCP&L with the Securities and Exchange Commission (SEC) should also be read for more information regarding risk factors.  Each forward-looking statement speaks only as of the date of the

2

particular statement.  Great Plains Energy and KCP&L undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.

Abbreviation or Acronym	Definition
AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
BART	Best available retrofit technology
Board	Great Plains Energy Board of Directors
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
Clean Air Act	Clean Air Act Amendments of 1990
CO2	Carbon dioxide
Collaboration Agreement	Agreement among KCP&L, the Sierra Club and the Concerned    Citizens of Platte County
Company	Great Plains Energy Incorporated and its consolidated subsidiaries
Companies	Great Plains Energy Incorporated and its consolidated subsidiaries and    KCP&L and its consolidated subsidiaries
CSAPR	Cross-State Air Pollution Rule
DOE	Department of Energy
ECA	Energy Cost Adjustment
EIRR	Environmental Improvement Revenue Refunding
EPA	Environmental Protection Agency
EPS	Earnings per common share
ERISA	Employee Retirement Income Security Act of 1974, as amended
FAC	Fuel Adjustment Clause
FASB	Financial Accounting Standards Board
FERC	The Federal Energy Regulatory Commission
FGIC	Financial Guaranty Insurance Company
FSS	Forward Starting Swaps
GAAP	Generally Accepted Accounting Principles
GMO	KCP&L Greater Missouri Operations Company, a wholly owned subsidiary of    Great Plains Energy as of July 14, 2008
Great Plains Energy	Great Plains Energy Incorporated and its consolidated subsidiaries
ISO	Independent System Operator
KCC	The State Corporation Commission of the State of Kansas
KCP&L	Kansas City Power & Light Company, a wholly owned subsidiary    of Great Plains Energy
KDHE	Kansas Department of Health and Environment
KLT Inc.	KLT Inc., a wholly owned subsidiary of Great Plains Energy
KW	Kilowatt
kWh	Kilowatt hour
L&P	St. Joseph Light & Power, a division of GMO
MACT	Maximum achievable control technology
MD&A	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations
MDNR	Missouri Department of Natural Resources
MGP	Manufactured gas plant
MPS Merchant	MPS Merchant Services, Inc., a wholly owned subsidiary of GMO
MPSC	Public Service Commission of the State of Missouri
MW	Megawatt

3

Abbreviation or Acronym	Definition
MWh	Megawatt hour
NERC	North American Electric Reliability Corporation
NEIL	Nuclear Electric Insurance Limited
NOx	Nitrogen oxide
NPNS	Normal purchases and normal sales
NRC	Nuclear Regulatory Commission
OCI	Other Comprehensive Income
PCB	Polychlorinated biphenyls
PRB	Powder River Basin
QCA	Quarterly Cost Adjustment
Receivables Company	Kansas City Power & Light Receivables Company, a wholly owned    subsidiary of KCP&L
RTO	Regional Transmission Organization
SCR	Selective catalytic reduction
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
Services	Great Plains Energy Services Incorporated, a wholly owned subsidiary of    Great Plains Energy
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Syncora	Syncora Guarantee Inc.
WCNOC	Wolf Creek Nuclear Operating Corporation
Westar	Westar Energy, Inc., a Kansas utility company
Wolf Creek	Wolf Creek Generating Station

4

PART 1 - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Great Plains Energy Incorporated
Unaudited Consolidated Balance Sheets
Unaudited Consolidated Statements of Income
Unaudited Consolidated Statements of Cash Flows
Unaudited Consolidated Statements of Common Shareholders’ Equity and Noncontrolling Interest
Unaudited Consolidated Statements of Comprehensive Income
Kansas City Power & Light Company
Unaudited Consolidated Balance Sheets
Unaudited Consolidated Statements of Income
Unaudited Consolidated Statements of Cash Flows
Unaudited Consolidated Statements of Common Shareholder’s Equity
Unaudited Consolidated Statements of Comprehensive Income
Combined Notes to Unaudited Consolidated Financial Statements for Great Plains Energy Incorporated and
Kansas City Power & Light Company
	Note 1:	Summary of Significant Accounting Policies
	Note 2:	Supplemental Cash Flow Information
	Note 3:	Receivables
	Note 4:	Nuclear Plant
	Note 5:	Regulatory Matters
	Note 6:	Pension Plans, Other Employee Benefits and Voluntary Separation Program
	Note 7:	Equity Compensation
	Note 8:	Short-Term Borrowings and Short-Term Bank Lines of Credit
	Note 9:	Long-Term Debt
	Note 10:	Commitments and Contingencies
	Note 11:	Legal Proceedings
	Note 12:	Related Party Transactions and Relationships
	Note 13:	Derivative Instruments
	Note 14:	Fair Value Measurements
	Note 15:	Taxes
	Note 16:	Segments and Related Information
	Note 17:	Goodwill

5

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets
(Unaudited)
	September 30		December 31
	2011		2010
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	8.9	$	10.8
Funds on deposit		1.4		5.2
Receivables, net		275.6		241.7
Accounts receivable pledged as collateral		95.0		95.0
Fuel inventories, at average cost		72.2		85.1
Materials and supplies, at average cost		137.6		132.8
Deferred refueling outage costs		33.4		9.6
Refundable income taxes		15.4		2.1
Deferred income taxes		6.7		14.3
Derivative instruments		1.2		1.1
Prepaid expenses and other assets		17.2		13.9
Total		664.6		611.6
Utility Plant, at Original Cost
Electric		10,821.5		10,536.9
Less-accumulated depreciation		4,184.4		4,031.3
Net utility plant in service		6,637.1		6,505.6
Construction work in progress		260.3		307.5
Nuclear fuel, net of amortization of $124.8 and $131.1		77.3		79.2
Total		6,974.7		6,892.3
Investments and Other Assets
Nuclear decommissioning trust fund		125.5		129.2
Regulatory assets		977.2		924.0
Goodwill		169.0		169.0
Derivative instruments		8.1		7.8
Other		86.0		84.3
Total		1,365.8		1,314.3
Total	$	9,005.1	$	8,818.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

6

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets
(Unaudited)
	September 30			December 31
	2011			2010
LIABILITIES AND CAPITALIZATION	(millions, except share amounts)
Current Liabilities
Notes payable	$	28.0		$	9.5
Collateralized note payable		95.0			95.0
Commercial paper		10.5			263.5
Current maturities of long-term debt		951.4			485.7
Accounts payable		193.7			276.3
Accrued taxes		91.9			26.6
Accrued interest		69.3			75.4
Accrued compensation and benefits		38.2			46.8
Pension and post-retirement liability		4.1			4.1
Derivative instruments		-			20.8
Other		29.0			35.6
Total		1,511.1			1,339.3
Deferred Credits and Other Liabilities
Deferred income taxes		638.9			518.3
Deferred tax credits		131.9			133.4
Asset retirement obligations		147.2			143.3
Pension and post-retirement liability		446.0			427.5
Regulatory liabilities		257.8			258.2
Other		99.1			129.4
Total		1,720.9			1,610.1
Capitalization
Great Plains Energy common shareholders' equity
Common stock - 250,000,000 shares authorized without par value
136,340,645 and 136,113,954 shares issued, stated value		2,328.5			2,324.4
Retained earnings		711.9			626.5
Treasury stock - 266,889 and 400,889 shares, at cost		(5.6	)		(8.9	)
Accumulated other comprehensive loss		(52.0	)		(56.1	)
Total		2,982.8			2,885.9
Noncontrolling interest		1.2			1.2
Cumulative preferred stock $100 par value
3.80% - 100,000 shares issued		10.0			10.0
4.50% - 100,000 shares issued		10.0			10.0
4.20% - 70,000 shares issued		7.0			7.0
4.35% - 120,000 shares issued		12.0			12.0
Total		39.0			39.0
Long-term debt (Note 9)		2,750.1			2,942.7
Total		5,773.1			5,868.8
Commitments and Contingencies (Note 10)
Total	$	9,005.1		$	8,818.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

7

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Income
(Unaudited)
	Three Months Ended						Year to Date
	September 30						September 30
	2011			2010			2011			2010
Operating Revenues	(millions, except per share amounts)
Electric revenues	$	773.7		$	728.8		$	1,831.7		$	1,787.7
Operating Expenses
Fuel		146.5			127.3			365.8			333.2
Purchased power		68.1			68.0			178.4			171.4
Transmission of electricity by others		8.6			8.1			23.1			20.9
Utility operating and maintenance expenses		169.1			147.7			487.7			447.3
Voluntary separation program		-			-			12.7			-
Depreciation and amortization		65.9			85.3			205.9			248.5
General taxes		52.3			43.6			134.6			119.2
Other		0.5			5.0			4.0			6.5
Total		511.0			485.0			1,412.2			1,347.0
Operating income		262.7			243.8			419.5			440.7
Non-operating income		1.4			7.5			5.8			34.8
Non-operating expenses		(1.3	)		(3.4	)		(6.3	)		(7.1	)
Interest charges		(60.8	)		(45.5	)		(156.0	)		(138.7	)
Income before income tax expense and loss from
equity investments		202.0			202.4			263.0			329.7
Income tax expense		(75.4	)		(70.4	)		(90.6	)		(112.1	)
Loss from equity investments, net of income taxes		-			-			(0.1	)		(0.9	)
Net income		126.6			132.0			172.3			216.7
Less: Net income attributable to noncontrolling interest		(0.1	)		-			-			(0.1	)
Net income attributable to Great Plains Energy		126.5			132.0			172.3			216.6
Preferred stock dividend requirements		0.4			0.4			1.2			1.2
Earnings available for common shareholders	$	126.1		$	131.6		$	171.1		$	215.4
Average number of basic common shares outstanding		135.7			135.2			135.6			135.1
Average number of diluted common shares outstanding		138.3			136.9			138.5			136.8
Basic earnings per common share	$	0.93		$	0.97		$	1.26		$	1.59
Diluted earnings per common share	$	0.91		$	0.96		$	1.24		$	1.57
Cash dividends per common share	$	0.2075		$	0.2075		$	0.6225		$	0.6225
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

8

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Cash Flows
(Unaudited)
Year to Date September 30	2011			2010
Cash Flows from Operating Activities	(millions)
Net income	$	172.3		$	216.7
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		205.9			248.5
Amortization of:
Nuclear fuel		13.5			19.7
Other		7.5			(4.1	)
Deferred income taxes, net		124.0			127.0
Investment tax credit amortization		(1.5	)		(1.8	)
Loss from equity investments, net of income taxes		0.1			0.9
Other operating activities (Note 2)		(154.3	)		(199.2	)
Net cash from operating activities		367.5			407.7
Cash Flows from Investing Activities
Utility capital expenditures		(317.8	)		(465.2	)
Allowance for borrowed funds used during construction		(3.1	)		(26.9	)
Purchases of nuclear decommissioning trust investments		(15.5	)		(78.3	)
Proceeds from nuclear decommissioning trust investments		13.0			75.6
Other investing activities		(17.4	)		(9.1	)
Net cash from investing activities		(340.8	)		(503.9	)
Cash Flows from Financing Activities
Issuance of common stock		4.5			4.7
Issuance of long-term debt		747.1			249.9
Issuance fees		(6.2	)		(11.7	)
Repayment of long-term debt		(448.5	)		(1.3	)
Net change in short-term borrowings		(234.5	)		(207.1	)
Net change in collateralized short-term borrowings		-			95.0
Dividends paid		(85.9	)		(85.6	)
Other financing activities		(5.1	)		(6.0	)
Net cash from financing activities		(28.6	)		37.9
Net Change in Cash and Cash Equivalents		(1.9	)		(58.3	)
Cash and Cash Equivalents at Beginning of Year		10.8			65.9
Cash and Cash Equivalents at End of Period	$	8.9		$	7.6
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

9

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest
(Unaudited)
Year to Date September 30	2011						2010
	Shares			Amount			Shares			Amount
Common Stock	(millions, except share amounts)
Beginning balance		136,113,954		$	2,324.4			135,636,538		$	2,313.7
Issuance of common stock		226,691			4.5			269,855			5.1
Issuance of restricted common stock		-			-			130,137			2.3
Equity compensation expense, net of forfeitures					0.2						1.1
Unearned Compensation
Issuance of restricted common stock					(3.5	)					(2.3	)
Forfeiture of restricted common stock					0.9						0.6
Compensation expense recognized					1.7						1.9
Other					0.3						0.1
Ending balance		136,340,645			2,328.5			136,036,530			2,322.5
Retained Earnings
Beginning balance					626.5						529.2
Net income attributable to Great Plains Energy					172.3						216.6
Loss on reissuance of treasury stock					(0.7	)					-
Dividends:
Common stock					(84.7	)					(84.4	)
Preferred stock - at required rates					(1.2	)					(1.2	)
Performance shares					(0.3	)					(0.2	)
Ending balance					711.9						660.0
Treasury Stock
Beginning balance		(400,889	)		(8.9	)		(213,423	)		(5.5	)
Treasury shares acquired		(125,024	)		(2.3	)		(172,913	)		(3.1	)
Treasury shares reissued		259,024			5.6			917			-
Ending balance		(266,889	)		(5.6	)		(385,419	)		(8.6	)
Accumulated Other Comprehensive Income (Loss)
Beginning balance					(56.1	)					(44.9	)
Derivative hedging activity, net of tax					4.0						(15.0	)
Change in unrecognized pension expense, net of tax					0.1						0.1
Ending balance					(52.0	)					(59.8	)
Total Great Plains Energy Common Shareholders' Equity				$	2,982.8					$	2,914.1
Noncontrolling Interest
Beginning balance				$	1.2					$	1.2
Net income attributable to noncontrolling interest					-						0.1
Distribution					-						(0.1	)
Ending balance				$	1.2					$	1.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

10

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Comprehensive Income
(Unaudited)
	Three Months Ended						Year to Date
	September 30						September 30
	2011			2010			2011			2010
	(millions)
Net income	$	126.6		$	132.0		$	172.3		$	216.7
Other comprehensive income (loss)
Loss on derivative hedging instruments		(0.1	)		(10.3	)		(5.5	)		(32.4	)
Income tax benefit		0.1			4.0			2.2			12.6
Net loss on derivative hedging instruments		-			(6.3	)		(3.3	)		(19.8	)
Reclassification to expenses, net of tax		3.1			2.0			7.3			4.8
Derivative hedging activity, net of tax		3.1			(4.3	)		4.0			(15.0	)
Defined benefit pension plans
Amortization of net gains included in net periodic benefit costs		-			-			0.2			0.2
Income tax expense		-			-			(0.1	)		(0.1	)
Net change in unrecognized pension expense		-			-			0.1			0.1
Comprehensive income		129.7			127.7			176.4			201.8
Less:  comprehensive income attributable to noncontrolling interest		(0.1	)		-			-			(0.1	)
Comprehensive income attributable to Great Plains Energy	$	129.6		$	127.7		$	176.4		$	201.7
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

11

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
(Unaudited)
	September 30		December 31
	2011		2010
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	3.2	$	3.6
Funds on deposit		0.2		0.4
Receivables, net		223.1		169.4
Accounts receivable pledged as collateral		95.0		95.0
Fuel inventories, at average cost		42.0		44.9
Materials and supplies, at average cost		98.7		94.4
Deferred refueling outage costs		33.4		9.6
Refundable income taxes		13.9		9.0
Deferred income taxes		-		5.6
Prepaid expenses and other assets		15.2		10.0
Total		524.7		441.9
Utility Plant, at Original Cost
Electric		7,762.6		7,540.9
Less-accumulated depreciation		3,209.0		3,104.4
Net utility plant in service		4,553.6		4,436.5
Construction work in progress		181.9		227.6
Nuclear fuel, net of amortization of $124.8 and $131.1		77.3		79.2
Total		4,812.8		4,743.3
Investments and Other Assets
Nuclear decommissioning trust fund		125.5		129.2
Regulatory assets		700.6		679.6
Other		35.8		32.3
Total		861.9		841.1
Total	$	6,199.4	$	6,026.3
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

12

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
(Unaudited)
	September 30			December 31
	2011			2010
LIABILITIES AND CAPITALIZATION	(millions, except share amounts)
Current Liabilities
Collateralized note payable	$	95.0		$	95.0
Commercial paper		10.5			263.5
Current maturities of long-term debt		162.7			150.3
Accounts payable		151.2			201.7
Accrued taxes		66.1			21.3
Accrued interest		34.1			26.2
Accrued compensation and benefits		38.2			46.8
Pension and post-retirement liability		2.6			2.6
Deferred income taxes		1.4			-
Other		15.1			7.8
Total		576.9			815.2
Deferred Credits and Other Liabilities
Deferred income taxes		776.6			692.0
Deferred tax credits		128.4			129.4
Asset retirement obligations		132.2			129.7
Pension and post-retirement liability		426.1			407.3
Regulatory liabilities		135.6			141.3
Other		65.1			76.7
Total		1,664.0			1,576.4
Capitalization
Common shareholder's equity
Common stock - 1,000 shares authorized without par value
1 share issued, stated value		1,563.1			1,563.1
Retained earnings		526.1			478.3
Accumulated other comprehensive loss		(32.5	)		(36.4	)
Total		2,056.7			2,005.0
Long-term debt (Note 9)		1,901.8			1,629.7
Total		3,958.5			3,634.7
Commitments and Contingencies (Note 10)
Total	$	6,199.4		$	6,026.3
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

13

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Income
(Unaudited)
	Three Months Ended						Year to Date
	September 30						September 30
	2011			2010			2011			2010
Operating Revenues	(millions)
Electric revenues	$	506.3		$	486.5		$	1,220.5		$	1,194.7
Operating Expenses
Fuel		99.3			83.8			249.0			213.2
Purchased power		24.9			25.0			66.7			63.2
Transmission of electricity by others		5.7			4.4			14.2			11.3
Operating and maintenance expenses		120.2			102.9			350.7			323.5
Voluntary separation program		-			-			9.2			-
Depreciation and amortization		45.4			66.4			147.0			192.2
General taxes		41.6			37.2			108.9			99.3
Other		-			3.2			1.3			3.2
Total		337.1			322.9			947.0			905.9
Operating income		169.2			163.6			273.5			288.8
Non-operating income		0.8			6.1			1.8			23.3
Non-operating expenses		(1.0	)		(2.5	)		(3.4	)		(4.7	)
Interest charges		(30.8	)		(20.1	)		(81.2	)		(63.8	)
Income before income tax expense		138.2			147.1			190.7			243.6
Income tax expense		(52.8	)		(54.5	)		(67.9	)		(83.6	)
Net income	$	85.4		$	92.6		$	122.8		$	160.0
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.

14

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Cash Flows
(Unaudited)
Year to Date September 30	2011			2010
Cash Flows from Operating Activities	(millions)
Net income	$	122.8		$	160.0
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		147.0			192.2
Amortization of:
Nuclear fuel		13.5			19.7
Other		22.3			18.1
Deferred income taxes, net		87.2			63.5
Investment tax credit amortization		(1.0	)		(1.2	)
Other operating activities (Note 2)		(74.3	)		(171.1	)
Net cash from operating activities		317.5			281.2
Cash Flows from Investing Activities
Utility capital expenditures		(236.7	)		(349.1	)
Allowance for borrowed funds used during construction		(1.6	)		(21.3	)
Purchases of nuclear decommissioning trust investments		(15.5	)		(78.3	)
Proceeds from nuclear decommissioning trust investments		13.0			75.6
Net money pool lending		(18.8	)		6.0
Other investing activities		(9.3	)		(6.0	)
Net cash from investing activities		(268.9	)		(373.1	)
Cash Flows from Financing Activities
Issuance of long-term debt		397.4			-
Issuance fees		(3.7	)		(5.0	)
Repayment of long-term debt		(113.1	)		(0.2	)
Net change in short-term borrowings		(253.0	)		22.9
Net change in collateralized short-term borrowings		-			95.0
Net money pool borrowings		(1.6	)		34.8
Dividends paid to Great Plains Energy		(75.0	)		(70.0	)
Net cash from financing activities		(49.0	)		77.5
Net Change in Cash and Cash Equivalents		(0.4	)		(14.4	)
Cash and Cash Equivalents at Beginning of Year		3.6			17.4
Cash and Cash Equivalents at End of Period	$	3.2		$	3.0
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial
Statements are an integral part of these statements.

15

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Common Shareholder's Equity
(Unaudited)
Year to Date September 30	2011					2010
	Shares		Amount			Shares		Amount
	(millions, except share amounts)
Common Stock		1	$	1,563.1			1	$	1,563.1
Retained Earnings
Beginning balance				478.3					410.1
Net income				122.8					160.0
Dividends:
Common stock held by Great Plains Energy				(75.0	)				(70.0	)
Ending balance				526.1					500.1
Accumulated Other Comprehensive Income (Loss)
Beginning balance				(36.4	)				(41.5	)
Derivative hedging activity, net of tax				3.9					3.7
Ending balance				(32.5	)				(37.8	)
Total Common Shareholder's Equity			$	2,056.7				$	2,025.4
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.

16

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Comprehensive Income
(Unaudited)
	Three Months Ended						Year to Date
	September 30						September 30
	2011			2010			2011			2010
	(millions)
Net income	$	85.4		$	92.6		$	122.8		$	160.0
Other comprehensive income (loss)
Loss on derivative hedging instruments		(0.1	)		(0.4	)		(0.2	)		(1.0	)
Income tax benefit		0.1			0.2			0.1			0.4
Net loss on derivative hedging instruments		-			(0.2	)		(0.1	)		(0.6	)
Reclassification to expenses, net of tax		1.3			1.6			4.0			4.3
Derivative hedging activity, net of tax		1.3			1.4			3.9			3.7
Comprehensive income	$	86.7		$	94.0		$	126.7		$	163.7
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.

17

GREAT PLAINS ENERGY INCORPORATED

KANSAS CITY POWER & LIGHT COMPANY

Notes to Unaudited Consolidated Financial Statements

The notes to unaudited consolidated financial statements that follow are a combined presentation for Great Plains Energy Incorporated and Kansas City Power & Light Company, both registrants under this filing.  The terms “Great Plains Energy,” “Company,” “KCP&L,” and “Companies” are used throughout this report.  “Great Plains Energy” and the “Company” refer to Great Plains Energy Incorporated and its consolidated subsidiaries, unless otherwise indicated.  “KCP&L” refers to Kansas City Power & Light Company and its consolidated subsidiaries.  “Companies” refers to Great Plains Energy Incorporated and its consolidated subsidiaries and KCP&L and its consolidated subsidiaries.  The Companies’ interim financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in the opinion of management, for a fair presentation of the results for the interim periods presented.

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

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

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

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

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

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

Basic and Diluted Earnings per Common Share Calculation

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

18

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

	Three Months Ended				Year to Date
	September 30				September 30
	2011		2010		2011		2010
Income	(millions, except per share amounts)
Net income	$	126.6	$	132.0	$	172.3	$	216.7
Less: net income attributable to noncontrolling interest		0.1		-		-		0.1
Less: preferred stock dividend requirements		0.4		0.4		1.2		1.2
Earnings available for common shareholders	$	126.1	$	131.6	$	171.1	$	215.4
Common Shares Outstanding
Average number of common shares outstanding		135.7		135.2		135.6		135.1
Add: effect of dilutive securities		2.6		1.7		2.9		1.7
Diluted average number of common shares outstanding		138.3		136.9		138.5		136.8
Basic EPS	$	0.93	$	0.97	$	1.26	$	1.59
Diluted EPS	$	0.91	$	0.96	$	1.24	$	1.57

The computation of diluted EPS for the three months ended September 30, 2011, excludes anti-dilutive shares consisting of 102,032 performance shares, 22,818 restricted stock shares and 80,140 stock options.

The computation of diluted EPS year to date September 30, 2011, excludes anti-dilutive shares consisting of 102,032 performance shares, 45,648 restricted stock shares and 80,140 stock options.

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.

Dividends Declared

In November 2011, Great Plains Energy’s Board of Directors (Board) declared a quarterly dividend of $0.2125 per share on Great Plains Energy’s common stock.  The common dividend is payable December 20, 2011, to shareholders of record as of November 29, 2011.  The Board also declared regular dividends on Great Plains Energy’s preferred stock, payable March 1, 2012, to shareholders of record as of February 7, 2012.

In November 2011, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $25 million payable on December 19, 2011.

19

2.   SUPPLEMENTAL CASH FLOW INFORMATION

Great Plains Energy Other Operating Activities
Year to Date September 30	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(41.2	)	$	(45.9	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		12.9			4.9
Materials and supplies		(4.8	)		(10.0	)
Accounts payable		(71.5	)		(79.1	)
Accrued taxes		52.5			54.6
Accrued interest		(6.1	)		(2.0	)
Deferred refueling outage costs		(23.8	)		8.0
Fuel adjustment clauses		(27.3	)		(2.3	)
Pension and post-retirement benefit obligations		22.0			15.5
Allowance for equity funds used during construction		(0.3	)		(25.5	)
Interest rate hedge settlements		(26.1	)		(6.9	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		2.3			4.0
Uncertain tax positions		(20.2	)		(1.4	)
Other		(22.7	)		(18.1	)
Total other operating activities	$	(154.3	)	$	(199.2	)
Cash paid during the period:
Interest	$	195.1		$	175.4
Income taxes	$	2.4		$	0.4
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	34.8		$	36.4
KCP&L Other Operating Activities
Year to Date September 30	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(39.5	)	$	(0.1	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		2.9			0.1
Materials and supplies		(4.3	)		(7.2	)
Accounts payable		(43.2	)		(87.2	)
Accrued taxes		40.3			(6.3	)
Accrued interest		7.9			10.3
Deferred refueling outage costs		(23.8	)		8.0
Pension and post-retirement benefit obligations		32.1			31.1
Allowance for equity funds used during construction		-			(21.7	)
Kansas Energy Cost Adjustment		(22.0	)		(5.4	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		1.5			3.0
Uncertain tax positions		(10.1	)		(1.6	)
Other		(16.1	)		0.9
Total other operating activities	$	(74.3	)	$	(171.1	)
Cash paid during the period:
Interest	$	74.6		$	60.3
Income taxes	$	0.1		$	71.6
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	30.7		$	31.6

20

Significant Non-Cash Items

On January 1, 2010, Great Plains Energy and KCP&L adopted new accounting guidance for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivable pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s and KCP&L’s balance sheets.  As a result, cash flows from operating activities were reduced by $95.0 million and cash flows from financing activities were raised by $95.0 million with no impact to the net change in cash year to date September 30, 2010.

3.   RECEIVABLES

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

	September 30			December 31
	2011			2010
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	122.3		$	62.0
Customer accounts receivable - unbilled		74.3			82.3
Allowance for doubtful accounts		(3.8	)		(2.7	)
Other receivables		82.8			100.1
Total	$	275.6		$	241.7
KCP&L
Customer accounts receivable - billed	$	43.5		$	6.5
Customer accounts receivable - unbilled		45.8			50.1
Allowance for doubtful accounts		(2.5	)		(1.5	)
Intercompany receivables		68.2			43.2
Other receivables		68.1			71.1
Total	$	223.1		$	169.4

Great Plains Energy’s and KCP&L’s other receivables at September 30, 2011, and December 31, 2010, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables.

Sale of Accounts Receivable – KCP&L

KCP&L sells all of its retail electric accounts receivable to its wholly owned subsidiary, Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor.  Receivables Company’s sale of the undivided percentage ownership interest in accounts receivable to Victory Receivables Corporation is accounted for as a secured borrowing with $95.0 million of accounts receivables pledged as collateral and a corresponding short-term collateralized note payable recognized on Great Plains Energy’s and KCP&L’s balance sheets at September 30, 2011, and December 31, 2010.

KCP&L sells its receivables at a fixed price based upon the expected cost of funds and charge-offs.  These costs comprise KCP&L’s loss on the sale of accounts receivable.  KCP&L services the receivables and receives an annual servicing fee of 1.5% 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 September 2011, the agreement was extended to September 2014 and amended to allow for $110 million in aggregate outstanding principal amount at any time.

21

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

22

					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	)		-
(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.

 

4.   NUCLEAR PLANT

KCP&L owns 47% of Wolf Creek Generating Station (Wolf Creek), its only nuclear generating unit.  Wolf Creek is located in Coffey County, Kansas, just northeast of Burlington, Kansas.  Wolf Creek’s operating license expires in 2045.  Wolf Creek is regulated by the Nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety-related requirements.Wolf Creek is operating in the category of nuclear plants receiving the lowest level of NRC oversight.

In March 2011, the NRC established a task force to conduct a 90-day review and a longer-term review of U.S. nuclear power plant safety in the aftermath of a March 11, 2011, earthquake and tsunami that eventually resulted in station blackout and a level 7 event on the International Nuclear and Radiological Event Scale (the highest level event on the scale) at Japan’s Fukushima Daiichi nuclear power plant.  On July 12, 2011, the task force issued an extensive report on the ramifications of the Fukushima earthquake/tsunami for nuclear power plant regulation in the U.S.  In October 2011, the NRC received recommendations from the NRC staff on how to proceed with the task force report.  The recommendations break down the task force report into three tiers of actions.  The first tier of recommendations includes actions that the nuclear industry has already taken or believes need near-term attention.  The second tier recommendations require further study before action can be taken and the third tier recommendations require NRC rulemaking, additional study and stakeholder involvement to finalize the specific details.  The timing and effects of any NRC action cannot be determined at this time.

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 July 2010.  In September 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of September 2011 due to a lack of funding.  Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025, and believes it will be able to expand on-site storage as needed past 2025.  Management cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.  See Note 11 for a related legal proceeding.

23

Low-Level Radioactive Waste

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

Nuclear Plant Decommissioning Costs

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

		Total			KCP&L's
		Station			47% Share
		(millions)
Current cost of decommissioning (in 2011 dollars)		$	630		$	296
Future cost of decommissioning (in 2045-2053 dollars) (a)			2,455			1,154
Annual escalation factor			3.73	%
Annual return on trust assets (b)			6.89	%
(a)	Total future cost over an eight year decommissioning period.
(b)	The 6.89% rate of return is through 2025. The rate then systematically decreases
	through 2053 to 1.81% based on the assumption that the fund's investment mix
	will become increasingly more conservative as the decommissioning period
	approaches.

Nuclear Decommissioning Trust Fund

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

	September 30			December 31
	2011			2010
Decommissioning Trust	(millions)
Beginning balance January 1	$	129.2		$	112.5
Contributions		2.5			3.7
Earned income, net of fees		4.0			2.0
Net realized gains		0.3			6.7
Net unrealized gains (losses)		(10.5	)		4.3
Ending balance	$	125.5		$	129.2

24

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

	September 30									December 31
	2011									2010
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	75.3	$	6.5	$	(6.6	)	$	75.2	$	73.4	$	13.1	$	(1.0	)	$	85.5
Debt securities		42.7		4.4		(0.2	)		46.9		38.1		2.6		(0.1	)		40.6
Other		3.4		-		-			3.4		3.1		-		-			3.1
Total	$	121.4	$	10.9	$	(6.8	)	$	125.5	$	114.6	$	15.7	$	(1.1	)	$	129.2

The weighted average maturity of debt securities held by the trust at September 30, 2011, was approximately 7 years.  The costs of securities sold are determined on the basis of specific identification.  The following table summarizes the realized gains and losses from the sale of securities in the nuclear decommissioning trust fund.

	Three Months Ended					Year to Date
	September 30					September 30
	2011		2010			2011			2010
	(millions)
Realized gains	$	0.2	$	0.2		$	1.0		$	7.2
Realized losses		-		(0.1	)		(0.7	)		(0.6	)

5.   REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

In November 2010, KCC issued an order, effective December 1, 2010, for KCP&L, authorizing an increase in annual revenues of $21.8 million, a return on equity of 10.0%, an equity ratio of approximately 49.7% and a Kansas jurisdictional rate base of $1.781 billion.  The annual revenue increase was subsequently adjusted by KCC in a January 2011 reconsideration order to $22.0 million.  In February 2011, KCC issued an order granting KCP&L and another party to the case their respective petitions for reconsideration regarding rate case expenses and therefore, approximately $1.4 million of the annual revenue increase is considered as interim subject to refund or true-up pending the outcome of the reconsideration proceedings regarding rate case expenses.  A hearing was held in September 2011 with a decision expected in the fourth quarter of 2011.  The rates authorized by KCC are effective unless and until modified by KCC or stayed by a court.

KCP&L Missouri Rate Case Proceedings

On June 4, 2010, KCP&L filed a request with the MPSC to increase its Missouri retail electric annual revenues by $92.1 million.  The request was ultimately adjusted during the rate case proceedings by KCP&L to $66.5 million as the net result of lower fuel and purchased power costs and other updates to the case.  KCP&L’s initial and updated requests reflected, among other things, a proposed annual offset to its revenue requirement for the Missouri jurisdictional portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset); the final update included a proposed wholesale margin offset of approximately $29.4 million.  On April 12, 2011, the MPSC issued its order and on April 14, 2011, the MPSC Staff filed a report which quantified the authorized revenue increase as approximately $34.8 million on an annual basis, which reflects a wholesale margin offset of approximately $45.9 million and authorizes a return on equity of 10.0%, an equity ratio of approximately 46.3% and a Missouri jurisdictional rate base of approximately $2.0 billion.  If the actual Missouri jurisdiction wholesale margin amount exceeds the $45.9 million level reflected in the MPSC order, the difference will be recorded as a regulatory liability and will be returned, with interest, to KCP&L Missouri customers in a future rate case.  The MPSC order provides the opportunity for KCP&L to retain a larger amount of non-firm wholesale

25

electric sales margin than KCP&L proposed; however, there are no assurances that KCP&L will achieve the $45.9 million wholesale margin offset amount and there are no means for KCP&L to recover any shortfall through its retail rates.  The rates established by the MPSC order took effect on May 4, 2011.

As a result of disallowances in the MPSC order, KCP&L recognized losses of $1.5 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project year to date September 30, 2011.  KCP&L also recorded a $2.4 million loss for other disallowed costs in the MPSC order.

In a related order, the MPSC required KCP&L and GMO to apply to the Internal Revenue Service (IRS) to reallocate approximately $26.5 million of Iatan No. 2 qualifying advance coal project tax credits from KCP&L to GMO.  KCP&L and GMO did apply to the IRS but in September 2011, the IRS denied KCP&L’s and GMO’s request.  The MPSC has indicated it will consider the ratemaking treatment of the tax credits in a future rate case.  Certain ratemaking treatments that may be pursued by the MPSC could trigger the loss or repayment to the IRS of a portion of unamortized deferred investment tax credits.  At September 30, 2011, KCP&L and GMO had $128.4 million and $3.5 million, respectively, of unamortized deferred investment tax credits.

GMO Missouri Rate Case Proceedings

On June 4, 2010, GMO filed requests with the MPSC to increase its Missouri retail electric annual revenues by $75.8 million for its Missouri Public Service division, and $22.1 million for its St. Joseph Light & Power (L&P) division.  GMO subsequently adjusted its requests during the rate case proceedings to $65.9 million and $23.2 million, respectively, as the net result of updates to the cases.  On May 4, 2011, the MPSC issued its order and on May 10, 2011, the MPSC Staff filed a report which quantified the authorized revenue increases on an annual basis as $30.1 million for GMO’s Missouri Public Service division and $29.3 million for GMO’s L&P division.  The MPSC order authorized a return on equity of 10.0%, an equity ratio of approximately 46.6% and a Missouri jurisdictional rate base of $1.76 billion.  In response to applications for clarification and rehearing of the MPSC order, the MPSC, on May 27, 2011, issued an order of clarification and modification.  The modified MPSC order revised the authorized annual revenue increase to approximately $35.7 million for GMO’s Missouri Public Service division and approximately $29.8 million for GMO’s L&P division, resulting primarily from a clarification of the amount of fuel costs shifted from GMO’s fuel adjustment clause to base rates.  However, because the MPSC authorized an annual revenue increase that was greater than the amount originally requested by GMO and communicated to GMO’s customers, the modified MPSC order deferred approximately $7.7 million of the L&P division increase, which is the amount over GMO’s requested $22.1 million increase for that division, and will phase in the deferred revenue amount in equal parts over a two-year period, plus carrying costs.

As a result of disallowances in the MPSC order, GMO recognized losses of $0.8 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project year to date September 30, 2011.  GMO also recorded a $1.5 million loss for other disallowed costs in the MPSC order.

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

26

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

SPP and NERC Inquiries

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

MPSC Regulatory Approval of the GMO Acquisition

Appeals of the MPSC order approving the GMO acquisition were filed with the Cole County, Missouri, Circuit Court, which affirmed the order in June 2009.  That decision was appealed and the Missouri Court of Appeals, Western District, upheld the MPSC order in August 2010.  The case was transferred to the Missouri Supreme Court in December 2010.  On July 19, 2011, the Missouri Supreme Court affirmed the Circuit Court’s ruling that affirmed the MPSC order approving the GMO acquisition.

27

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, 2011	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	119.0		$	24.9		$	143.9
Loss on reacquired debt		6.5	(a)		0.6	(a)		7.1
Cost of removal		7.0			-			7.0
Asset retirement obligations		30.4			13.6			44.0
Pension and post-retirement costs		373.2	(b)		120.4	(b)		493.6
Deferred customer programs		48.2	(c)		19.5			67.7
Rate case expenses		9.9	(d)		4.5	(d)		14.4
Skill set realignment costs		3.7	(e)		-			3.7
Fuel adjustment clauses		30.1	(d)		42.5	(d)		72.6
Acquisition transition costs		26.2	(f)		21.3	(f)		47.5
St. Joseph Light & Power acquisition		-			2.2	(g)		2.2
Storm damage		-			2.0	(h)		2.0
Derivative instruments		-			3.1	(i)		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		16.5			6.1			22.6
Iatan No. 2 construction accounting costs		27.6			15.5			43.1
Other		2.3	(j)		0.4	(j)		2.7
Total	$	700.6		$	276.6		$	977.2
Regulatory Liabilities
Emission allowances	$	83.0		$	0.3		$	83.3
Asset retirement obligations		40.9			-			40.9
Pension		0.5			39.9			40.4
Cost of removal		-			62.5	(k)		62.5
Other		11.2			19.5			30.7
Total	$	135.6		$	122.2		$	257.8

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

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

(c)   $11.3 million not included in rate base and amortized over various periods.

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

(e)   $2.5 million not included in rate base and amortized through 2017.

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

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

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

(i)   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).

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

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

28

					Great
December 31, 2010	KCP&L		GMO		Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	117.2	$	25.3	$	142.5
Loss on reacquired debt		5.0		0.7		5.7
Cost of removal		8.5		-		8.5
Asset retirement obligations		27.5		12.8		40.3
Pension and post-retirement costs		386.1		106.7		492.8
Deferred customer programs		44.7		15.6		60.3
Rate case expenses		12.3		3.3		15.6
Skill set realignment costs		4.8		-		4.8
Fuel adjustment clauses		8.4		37.1		45.5
Acquisition transition costs		29.3		22.5		51.8
St. Joseph Light & Power acquisition		-		2.6		2.6
Storm damage		-		3.2		3.2
Derivative instruments		-		3.1		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		15.1		4.3		19.4
Iatan No. 2 construction accounting costs		17.2		6.5		23.7
Other		3.5		0.7		4.2
Total	$	679.6	$	244.4	$	924.0
Regulatory Liabilities
Emission allowances	$	85.9	$	0.5	$	86.4
Asset retirement obligations		44.9		-		44.9
Pension		-		37.1		37.1
Cost of removal		-		62.8		62.8
Other		10.5		16.5		27.0
Total	$	141.3	$	116.9	$	258.2

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

Great Plains Energy maintains defined benefit pension plans for substantially all active and inactive employees, including officers, and also provides certain post-retirement health care and life insurance benefits for substantially all retired employees of KCP&L, GMO, and Wolf Creek Nuclear Operating Corporation (WCNOC).

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.  The current rate orders allow similar regulatory treatment for post-retirement benefits.  The differences between the financial and regulatory accounting methods are due to timing and will be eliminated over the life of the pension and post-retirement plans.

29

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	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	7.8		$	7.6		$	0.7		$	1.0
Interest cost		12.4			12.3			2.0			2.2
Expected return on plan assets		(9.5	)		(9.2	)		(0.4	)		(0.5	)
Prior service cost		1.1			1.1			1.8			1.8
Recognized net actuarial loss (gain)		9.7			9.4			(0.1	)		(0.1	)
Transition obligation		-			-			0.3			0.3
Settlement charge		10.0			-			-			-
Net periodic benefit costs before
regulatory adjustment		31.5			21.2			4.3			4.7
Regulatory adjustment		(12.8	)		(8.1	)		0.4			-
Net periodic benefit costs	$	18.7		$	13.1		$	4.7		$	4.7
	Pension Benefits						Other Benefits
Year to Date September 30	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	23.4		$	22.8		$	2.3		$	2.8
Interest cost		37.5			36.9			5.9			6.6
Expected return on plan assets		(28.8	)		(27.5	)		(1.3	)		(1.6	)
Prior service cost		3.4			3.5			5.4			5.4
Recognized net actuarial loss (gain)		28.9			28.1			(0.4	)		(0.1	)
Transition obligation		-			-			1.0			1.0
Settlement charge		10.2			-			-			-
Net periodic benefit costs before
regulatory adjustment		74.6			63.8			12.9			14.1
Regulatory adjustment		(25.1	)		(24.6	)		0.7			-
Net periodic benefit costs	$	49.5		$	39.2		$	13.6		$	14.1

Year to date September 30, 2011, Great Plains Energy contributed $42.0 million to the pension plans and expects to contribute an additional $80.2 million in 2011 to satisfy the funding requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA), and the MPSC and KCC rate orders, the majority of which is expected to be paid by KCP&L.  Also in 2011, Great Plains Energy expects to contribute $17.1 million to the post-retirement benefit plans, of which the majority will be funded by KCP&L.

Voluntary Separation Program

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

30

related payroll taxes to employees who elected to voluntarily separate.  KCP&L recorded $9.2 million year to date September 30, 2011, related to this voluntary separation program.

Great Plains Energy recorded a $10.0 million pension settlement charge during the third quarter of 2011 from the voluntary separation program as a result of accelerated pension distributions.  The Companies deferred substantially all of the charge as a regulatory asset and expect to recover it over future periods pursuant to regulatory agreements.  The amount of accelerated pension distributions resulting from the voluntary separation program resulted in increased pension funding requirements in 2011 under ERISA.

7.   EQUITY COMPENSATION

Great Plains Energy’s Long-Term Incentive Plan is an equity compensation plan approved by Great Plains Energy’s shareholders.  The Long-Term Incentive Plan permits the grant of restricted stock, 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
	2011		2010		2011		2010
Great Plains Energy	(millions)
Compensation expense	$	1.2	$	0.8	$	4.5	$	3.4
Income tax benefits		0.4		0.2		1.8		0.8
KCP&L
Compensation expense		0.8		0.6		3.1		2.4
Income tax benefits		0.2		0.2		1.2		0.4

Performance Shares

Performance share activity year to date September 30, 2011, is summarized in the following table.

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

At September 30, 2011, the remaining weighted-average contractual term was 1.2 years.  The weighted-average grant-date fair value of shares granted was $26.30 and $26.15 for the three months ended and year to date September 30, 2011, respectively.  There were no shares granted for the three months ended September 30, 2010.  The weighted-average grant-date fair value of shares granted year to date September 30, 2010, was $23.37.  At September 30, 2011, there was $4.0 million of total unrecognized compensation expense, net of forfeiture rates, related to performance shares granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term.  The total fair value of performance shares earned and paid year to date September 30, 2011 and 2010, was $0.8 million and insignificant, respectively.

31

The fair value of performance share awards is estimated using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of expected volatilities, dividend yield and risk-free rates.  Expected volatility is based on daily stock price change during a historical period commensurate with the remaining term of the performance period of the grant.  The risk-free rate is based upon the rate at the time of the evaluation for zero-coupon government bonds with a maturity consistent with the remaining performance period of the grant.  The dividend yield is based on the most recent dividends paid and the actual closing stock price on the valuation date.  For shares granted in 2011, inputs for expected volatility, dividend yield and risk-free rates ranged from 28%-30%, 3.98%-4.35%, and 0.61%-1.15%, respectively.

Restricted Stock

Restricted stock activity year to date September 30, 2011, is summarized in the following table.

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

At September 30, 2011, the remaining weighted-average contractual term was 1.6 years.  The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2011, was $17.89 and $19.03, respectively.  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.  At September 30, 2011, 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.  There were no shares vested for the three months ended September 30, 2011.  The total fair value of shares vested year to date September 30, 2011, was $2.6 million.  The 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.

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

Great Plains Energy’s $200 Million Revolving Credit Facility

Great Plains Energy’s $200 million revolving credit facility with a group of banks expires in August 2013.  The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time.  A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At September 30, 2011, Great Plains Energy was in compliance with this covenant.  At September 30, 2011, Great Plains Energy had $28.0 million of outstanding cash borrowings with a weighted-average interest rate of 3.00% and had issued letters of credit totaling $11.6 million under the credit facility.  At December 31, 2010, Great Plains Energy had $9.5 million of outstanding cash borrowings with a weighted-average interest rate of 3.06% and had issued letters of credit totaling $15.8 million under the credit facility.

32

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

KCP&L’s $600 million revolving credit facility with a group of banks to provide support for its issuance of commercial paper and other general corporate purposes expires in August 2013.  Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities.  A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At September 30, 2011, KCP&L was in compliance with this covenant.  At September 30, 2011, KCP&L had $10.5 million of commercial paper outstanding, at a weighted-average interest rate of 0.35%, $31.5 million of letters of credit outstanding and no outstanding cash borrowings under the facility.  At December 31, 2010, KCP&L had $263.5 million of commercial paper outstanding, at a weighted-average interest rate of 0.41%, $24.4 million of letters of credit outstanding and no outstanding cash borrowings under the facility.

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

GMO’s $450 million revolving credit facility with a group of banks expires in August 2013.  Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities.  A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At September 30, 2011, GMO was in compliance with this covenant.  At September 30, 2011, and December 31, 2010, GMO had $13.2 million of letters of credit outstanding and no outstanding cash borrowings under the facility.  In October 2011, GMO established a $450 million commercial paper program, which is unconditionally guaranteed by Great Plains Energy.  At November 3, 2011, there was no outstanding commercial paper under the program.

33

9.   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	2011			2010
KCP&L		(millions)
General Mortgage Bonds
4.87% EIRR bonds (a)(b)	2012-2035	$	119.3		$	158.8
7.15% Series 2009A (8.59% rate)(c)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
EIRR Series 2007A-1(d)	2035		-			63.3
EIRR Series 2007A-2(d)	2035		-			10.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
6.50% Series	2011		150.0			150.0
5.85% Series (5.72% rate)(c)	2017		250.0			250.0
6.375% Series (7.49% rate)(c)	2018		350.0			350.0
6.05% Series (5.78% rate)(c)	2035		250.0			250.0
5.30% Series	2041		400.0			-
EIRR bonds
4.90% Series 2008	2038		23.4			23.4
Other	2012-2018		2.9			3.3
Current maturities			(162.7	)		(150.3	)
Unamortized discount			(4.3	)		(2.0	)
Total KCP&L			1,901.8			1,629.7
Other Great Plains Energy
GMO First Mortgage Bonds
9.44% Series	2012-2021		11.2			12.4
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.214% Wamego Series 1996 (e)	2026		7.3			7.3
0.263% State Environmental 1993 (e)	2028		5.0			5.0
GMO Senior Notes
7.95% Series			-			137.3
7.75% Series			-			197.0
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			24.2			49.9
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(c)	2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(c)	2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes	2012		287.5			287.5
Great Plains Energy 4.85% Senior Notes (7.34% rate)(c)	2021		350.0			-
Current maturities			(788.7	)		(335.4	)
Unamortized discount			(0.7	)		(0.5	)
Total Great Plains Energy excluding current maturities		$	2,750.1		$	2,942.7
(a)  Weighted-average interest rates at September 30, 2011
(b) September 30, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by
KCP&L
(c) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(d) September 30, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the
bonds have been repurchased and are held by KCP&L
(e)  Variable rate

34

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, 2011, and December 31, 2010, the book value of Great Plains Energy’s long-term debt, including current maturities, was $3.7 billion and $3.4 billion, respectively.  At September 30, 2011, and December 31, 2010, the fair value of Great Plains Energy’s long-term debt, including current maturities, was $4.1 billion and $3.7 billion, respectively.  At September 30, 2011, and December 31, 2010, the book value of KCP&L’s long-term debt, including current maturities, was $2.1 billion and $1.8 billion, respectively.  At September 30, 2011, and December 31, 2010, the fair value of KCP&L’s long-term debt, including current maturities, was $2.3 billion and $1.9 billion, respectively.

KCP&L General Mortgage Bonds and EIRR Bonds

In April 2011, KCP&L purchased in lieu of redemption its $63.3 million EIRR Series 2007A-1, $10.0 million EIRR Series 2007A-2 and $39.5 million EIRR Series 1993B bonds.  KCP&L opted to purchase rather than remarket the bonds given the poor conditions in the tax-exempt market.  KCP&L issued commercial paper to fund the purchase of the bonds.As of September 30, 2011, the bonds were still outstanding, but were not reported as a liability on the balance sheet since they are being held by KCP&L.  KCP&L has the ability to remarket these bonds to third parties whenever it determines market conditions are sufficiently attractive to do so.

KCP&L Senior Notes

In September 2011, KCP&L issued $400.0 million of 5.30% unsecured Senior Notes, maturing in 2041.

GMO Senior Notes

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

Great Plains Energy Senior Notes

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

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

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

Great Plains Energy must attempt to remarket the subordinated notes, in whole but not in part, between December 15, 2011, and June 12, 2012.  The proceeds from a successful remarketing will be used to satisfy the holders’ obligation under the purchase contract.  If the notes have not been successfully remarketed by June 12, 2012, the holders of all notes will have the right to put their notes to Great Plains Energy on June 15, 2012, in satisfaction of the holders’ obligation under the purchase contracts, and Great Plains Energy will issue to the holders newly issued shares of the Company’s common stock equal to the settlement rate.  The settlement rate will vary according to the applicable market value of the Company’s common stock at the settlement date.

35

10.   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’s and KCP&L’s results of operations, financial position and cash flows.

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

Air and Climate Change Overview

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

Great Plains Energy’s and KCP&L’s current estimate of capital expenditures (exclusive of AFUDC and property taxes) to comply with the currently-effective Clean Air Interstate Rule (CAIR), the replacement to CAIR or the Cross-State Air Pollution Rule (CSAPR), the best available retrofit technology (BART) rule, the SO2 national ambient air quality standard (NAAQS), the industrial boiler rule and proposed maximum achievable control technology (MACT) standards for mercury and other hazardous air pollutant emissions (all of which are discussed below) is approximately $1 billion.  The actual cost of compliance with any existing, proposed or future rules may be significantly different from the cost estimate provided.

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

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

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

·   KCP&L’s Montrose No. 3 full AQCS installed by approximately 2016; and

·   GMO’s Sibley No. 3 scrubber and baghouse installed by approximately 2016.

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

The estimate does not reflect the non-capital costs the Companies incur on an ongoing basis to comply with environmental laws, which may increase in the future due to the Companies’ ongoing compliance with current or future environmental laws.  The Companies expect to seek recovery of the costs associated with environmental requirements through rate increases; however, there can be no assurance that such rate increases would be granted.  The Companies may be subject to materially adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies’ environmental reputation.

36

Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule (CSAPR)

The CAIR requires reductions in SO2 and NOx emissions in 28 states, including Missouri.  The reductions in SO2 and NOx emissions are accomplished through statewide caps for NOx and SO2.  Great Plains Energy’s and KCP&L’s fossil fuel-fired plants located in Missouri are subject to CAIR, while their fossil fuel-fired plants in Kansas are not.

On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety and remanded the matter to the EPA to promulgate a new rule consistent with its opinion.  On December 23, 2008, the Court issued an order remanding CAIR to the EPA to revise the rule consistent with its July 2008 order.  The CAIR remains in effect through 2011.

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, 2011, KCP&L had accumulated unused SO2 emission allowances sufficient to support over 150,000 tons of SO2 emissions (enough to support expected requirements under the CAIR and the Acid Rain Program for the foreseeable future) under the provisions of the Acid Rain program, which are recorded in inventory at zero cost.  At September 30, 2011, GMO had accumulated unused SO2 emission allowances sufficient to support just over 9,000 tons of SO2 emissions (enough to support expected requirements under the CAIR and Acid Rain Program through 2011), which it has received under the Acid Rain Program or purchased, and are recorded in inventory at average cost.  KCP&L and GMO purchase NOx allowances as needed.

In July 2011, the EPA finalized the CSAPR to replace the currently-effective CAIR.  The CSAPR, 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 CSAPR is broader than CAIR, and includes Kansas in addition to Missouri and other states.  Kansas and Missouri are only included for fine particulate matter control in the final CSAPR, but the EPA concurrently proposed a supplemental notice of proposed rulemaking to include both states for ozone season control which the EPA intends to finalize in November 2011.  The CSAPR would also impose more stringent emissions limitations than CAIR and, unlike CAIR, would not utilize Acid Rain Program allowances for compliance.  In the CSAPR, the EPA set an emissions budget for each of the affected states.  The CSAPR allows limited interstate emissions allowance trading among power plants; however, it does not permit trading of SO2 allowances between the Companies’ Kansas and Missouri power plants.  Compliance with the CSAPR begins in 2012.  There would be additional reductions in SO2 allowances allocable to the Companies’ Missouri power plants taking effect in 2014.  There is no such 2014 additional reduction in SO2 allowances allocable to the Companies’ Kansas power plants.  In October 2011, the EPA proposed technical adjustments to the final CSAPR.  The proposed rule amends the assurance penalty provisions to start in 2014, instead of 2012.  The EPA proposed to revise certain unit-level allocations in six states, including Kansas, affected by federally enforceable consent agreements.  This would allocate additional allowances to KCP&L’s LaCygne Station to assist in compliance with CSAPR.

The finalized CSAPR is complex and Great Plains Energy and KCP&L are evaluating its impacts.  The Companies project that they may not be allocated sufficient SO2 or NOX emissions allowances to cover their currently expected operations starting in 2012.  Any shortfall in allocated allowances is anticipated to be addressed through a combination of permissible allowance trading, installing additional emission control equipment, changes in plant processes, or purchasing additional power in the wholesale market.  Multiple states, utilities and other parties, including KCP&L, have filed reconsideration requests and stays with the EPA and/or the D.C. Circuit Court.

37

Best Available Retrofit Technology (BART) Rule

The EPA BART rule directs state air quality agencies to identify whether visibility-reducing emissions from sources subject to BART are below limits set by the state or whether retrofit measures are needed to reduce emissions.  BART applies to specific eligible facilities including KCP&L’s LaCygne Nos. 1 and 2 in Kansas, KCP&L’s Iatan No. 1, in which GMO has an 18% interest, KCP&L’s Montrose No. 3 in Missouri, GMO’s Sibley Unit No. 3 and Lake Road Unit No. 6 in Missouri and Westar Energy, Inc.’s (Westar) Jeffrey Unit Nos. 1 and 2 in Kansas, in which GMO has an 8% interest.  Both Missouri and Kansas have submitted BART plans to the EPA but neither Missouri nor Kansas has received EPA approval for their BART plans.  In August 2011, the EPA proposed to approve the Kansas BART plan.

Mercury and Other Hazardous Air Pollutant Emissions

In January 2009, the EPA issued a memorandum stating that new electric steam generating units (EGUs) that began construction while the Clean Air Mercury Rule (CAMR) was effective are subject to a new source 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.  In May 2011, KCP&L received a letter from the Missouri Department of Natural Resources (MDNR) stating the MACT determination was not required for Hawthorn No. 5.  It is not currently known how MACT determinations and schedules of compliance will impact the permitting or operating requirements for Iatan No. 2, but it is possible a MACT determination may ultimately require additional emission control equipment and permit limits.

In 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 and is expected to issue final standards by December 2011.  In March 2011, the EPA issued a proposed rule that would reduce emissions of hazardous air pollutants from new and existing coal-fired EGUs with a capacity of 25MW or greater.  The proposed rule would establish numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrogen chloride (a surrogate for acid gases).  The proposed rule would establish work practices, instead of numerical emission limits, for organic hazardous air pollutants, including dioxin/furan.  Compliance with the rule would need to be addressed by installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market or a combination of these and other alternatives.  Any final rule could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Industrial Boiler Rule

In February 2011, the EPA issued a final rule that would reduce emissions of hazardous air pollutants from new and existing industrial boilers.  The final rule establishes numeric emission limits for mercury, dioxin, particulate matter (as a surrogate for non-mercury metals), hydrogen chloride (as a surrogate for acid gases), and carbon monoxide (as a surrogate for non-dioxin organic hazardous air pollutants).  The final rule establishes emission limits for KCP&L’s and GMO’s new and existing units that produce steam other than for the generation of electricity.  The final rule does not apply to KCP&L’s and GMO’s electricity generating boilers, but would apply to most of GMO’s Lake Road boilers, which also serve steam customers, and to auxiliary boilers at other generating facilities.  In May 2011, the EPA announced it would stay the effective date of the final rule during reconsideration.  The EPA indicated it will propose a revised rule in November 2011 and issue another final rule by the end of April 2012.

38

New Source Review

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

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

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

Collaboration Agreement

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

In 2006, KCP&L installed 100MW of wind generation at its Spearville wind site.  KCP&L agreed in the Collaboration Agreement to pursue increasing its wind generation capacity to 500MW in total by the end of 2012 with 100MW to be added by the end of 2010 and the remainder added by the end of 2012, subject to regulatory approval.  In 2010, KCP&L completed a 48MW wind project adjacent to its existing Spearville wind site with wind turbines it already owned and also secured 52MW of renewable energy credits.  During 2011, KCP&L entered into a 20-year power purchase agreement for approximately 131MW of wind generation beginning in 2012.  The Companies are evaluating options to add up to 200MW of new wind capacity through a combination of ownership and power purchase agreements.

KCP&L has a consent agreement with the KDHE incorporating limits for stack particulate matter emissions, as well as limits for NOx and SO2 emissions, at its LaCygne Station that, consistent with the Collaboration Agreement, will be below the presumptive limits under BART.  KCP&L further agreed to use its best efforts to install emission control technologies to reduce those emissions from the LaCygne

39

Station prior to the required compliance date under BART, but in no event later than June 1, 2015.  In February 2011, KCP&L filed a request with KCC for predetermination of the ratemaking treatment that would apply to the recovery of costs for its 50% share of the environmental equipment required to comply with BART at the LaCygne Station.  The request for predetermination included an estimated total project cost of $1.23 billion (excluding AFUDC and property tax).  KCP&L’s 50% share of the estimated cost is $615 million.  In August 2011, KCC issued its order on the predetermination request.  In the order, KCC stated that KCP&L’s decision to retrofit LaCygne was reasonable, reliable, efficient and prudent and the $1.23 billion cost estimate is reasonable.  If the cost for the project is at or below the $1.23 billion estimate, absent a showing of fraud or other intentional imprudence, KCC stated that it will not re-evaluate the prudency of the cost of the project.  If the cost of the project exceeds the $1.23 billion estimate and KCP&L seeks to recover amounts exceeding the estimate, KCP&L will bear the burden of proving that any additional costs were prudently incurred.  KCP&L began the project in September 2011.

In a related proceeding, in January 2011, KCC opened a general investigation docket regarding KCP&L and Westar environmental retrofits upon the recommendation of the KCC Staff and the Citizens Utility Ratepayers Board.  The Companies cannot predict the outcome or timing of this matter but the outcome could have the potential to impact the Companies’ resource planning in the future.

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, are subject to certain greenhouse gas permitting requirements starting in 2011.  Management believes it is possible that additional federal or relevant state or local laws or regulations could be enacted to address global climate change.  At the international level, while the United States is not a current party to the Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions.  International agreements legally binding on the United States may be reached in the future.  Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels.  The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 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 clean or renewable energy standards are also possible.  While management believes additional requirements addressing these matters will probably be enacted, the timing, provisions and impact of such requirements, including the cost to obtain and install new equipment to achieve compliance, cannot be reasonably estimated at this time.  In addition, certain federal courts have held that state and local governments and private parties have standing to bring climate change tort suits seeking company-specific emission reductions and monetary or other damages.  While the Companies are not a party to any climate change tort suit, there is no assurance that such suits may not be filed in the future or as to the outcome if such suits are filed.  Such requirements or litigation outcomes could have the potential for a significant financial and operational impact on Great Plains Energy and KCP&L.  The Companies would likely seek recovery of capital costs and expenses for compliance through rate increases; however, there can be no assurance that such rate increases would be granted.

40

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

In May 2010, the EPA issued a final rule addressing greenhouse gas emissions from stationary sources under the Clean Air Act permitting programs.  This final rule sets thresholds for greenhouse gas emissions that define when permits under the Prevention of Significant Deterioration (PSD) and Title V Operating Permit programs are required for new and existing industrial facilities.  The EPA phased in the Clean Air Act permitting requirements for greenhouse gas emissions in two initial steps.  In step 1, which started January 2, 2011, only sources currently subject to the PSD permitting program (i.e., those that are newly-constructed or modified in a way that significantly increases emissions of a pollutant other than greenhouse gas) are subject to Title V or PSD permitting requirements, respectively, for their greenhouse gas emissions.  For these projects, only projects with new or increases of greenhouse gas emissions of 75,000 tons per year or more of total greenhouse gases, on a CO2 equivalent basis, need to determine the best available control technology for their greenhouse gas emissions.  In addition, sources subject to the Title V Operating Permit Program need to address greenhouse gas emissions as those permits are applied for or renewed.  In step 2, which started July 1, 2011, Title V and PSD permitting requirements now 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 are 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 are subject to this rule.

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

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

KCP&L and GMO project that their existing renewable resources (including accumulated renewable energy credits) will be sufficient for compliance with the Missouri requirements, exclusive of the solar requirement, through 2021 and 2016, respectively.  KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri solar requirements for the foreseeable future.

KCP&L also projects that its existing renewable resources (including both accumulated renewable energy credits and purchased renewable energy credits) will be sufficient for compliance with the 2011 Kansas requirements.  During 2011, KCP&L entered into a 20-year power purchase agreement for approximately 131MW of wind generation beginning in 2012.  With the addition of this power purchase agreement along with its existing renewable resources, KCP&L anticipates its renewable resources will be sufficient

41

for compliance with the Kansas requirements through 2012.  The Companies are evaluating options to add up to 200MW of new wind capacity through a combination of ownership and power purchase agreements.

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 and/or regulations are issued.  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 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 CSAPR and BART.  The EPA has various options over and above the implementation of the maintenance plans for control of ozone to address the violation but has not yet acted.  At this time, management is unable to predict how the EPA will respond or how that response will impact Great Plains Energy’s and KCP&L’s operations.  However, the EPA’s response could have a significant effect on Great Plains Energy's and KCP&L's results of operations, financial position and cash flows.

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

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

In January 2010, the EPA proposed to reconsider and further strengthen the 2008 NAAQS for ground-level ozone.  The EPA proposed to strengthen the primary eight-hour ozone standard to a level within the range of 0.060-0.070 ppm.  The EPA also proposed to establish a distinct cumulative, seasonal secondary standard, designed to protect sensitive vegetation and ecosystems, to within the range of 7-15 ppm-hours.  In September 2011, President Obama requested that the EPA withdraw the proposed rule reconsidering the 2008 NAAQS and the EPA announced it will proceed with implementation of the 2008 primary eight-hour ozone standard of 0.075 ppm.  The EPA indicated, based on the available ozone air quality data, that the Kansas City area would meet the standard.

42

SO2 NAAQS

In June 2010, the EPA strengthened the primary NAAQS for SO2.  The EPA revised the primary SO2 standard by establishing a new 1-hour standard at a level of 0.075 ppm.  The EPA revoked the two existing primary standards of 0.140 ppm evaluated over 24 hours and 0.030 ppm evaluated over an entire year.  In July 2011, the MDNR recommended to the EPA that part of Jackson County, Missouri, which is in the Companies' service territory, be designated a nonattainment area for the new 1-hour SO2 standard.  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 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.

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 not have a significant impact on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Water

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

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

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

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

43

Solid Waste

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

Remediation

Certain federal and state laws, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) hold current and previous owners or operators of real property, and any person who arranges for the disposal or treatment of hazardous substances at a property, liable on a joint and several basis for the costs of cleaning up contamination at or migrating from such real property, even if they did not know of and were not responsible for such contamination.  CERCLA and other laws also authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment.  GMO is named as a potentially responsible party at two disposal sites for polychlorinated 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, 2011, and December 31, 2010, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site.  At September 30, 2011, and December 31, 2010, Great Plains Energy had $0.4 million accrued for environmental remediation expenses, which includes the $0.3 million at KCP&L, and additional potential remediation and ground water monitoring costs relating to two GMO sites.  The amounts accrued were established on an undiscounted basis and Great Plains Energy and KCP&L do not currently have an estimated time frame over which the accrued amounts may be paid.

In addition to the $0.4 million accrual above, at September 30, 2011, and December 31, 2010, Great Plains Energy had $2.1 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB sites and retained liabilities.  This estimate was based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary.  This estimate could change materially after further investigation, and could also be affected by the actions of environmental agencies and the financial viability of other potentially responsible parties.

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

44

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

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

Contractual Commitments

At September 30, 2011, Great Plains Energy’s and KCP&L’s contractual commitments for KCP&L’s environmental retrofits at its LaCygne station are $123.3 million, $385.7 million, $286.6 million, $130.1 million and $6.3 million for the years 2011 though 2015, respectively.  KCP&L owns 50% of the LaCygne station. KCP&L expects to be reimbursed by the other owner for its 50% share of the costs.  Great Plains Energy’s and KCP&L’s other contractual commitments have not significantly changed at September 30, 2011, compared to December 31, 2010.

11.   LEGAL PROCEEDINGS

KCP&L Spent Nuclear Fuel and Radioactive Waste

In January 2004, KCP&L and the other two Wolf Creek owners filed a lawsuit against the United States in the U.S. Court of Federal Claims seeking $14.1 million of damages resulting from the government’s failure to begin accepting spent nuclear fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982.  The Wolf Creek case was tried before a U.S. Court of Federal Claims judge in June 2010, and a decision was issued in November 2010, granting KCP&L and the other two Wolf Creek owners $10.6 million ($5.0 million KCP&L share) in damages.  In January 2011, KCP&L and the other two Wolf Creek owners as well as the United States filed appeals of the decision to the U.S. Court of Appeals for the Federal Circuit.  The court has set a briefing schedule.  Briefing likely will conclude in the fourth quarter of 2011, and the parties will present their oral arguments to the court sometime thereafter.

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.  Written discovery and depositions are underway and this matter is set for trial in May 2012.  Management cannot predict the outcome of this matter.

GMO Price Reporting Litigation

In response to complaints of manipulation of the California energy market, in July 2001, FERC issued an order requiring net sellers of power in the California markets from October 2, 2000, through June 20, 2001, at prices above a FERC determined competitive market clearing price to make refunds to net purchasers of power in the California market during that time period.  Because MPS Merchant was a net purchaser of power during the refund period, it has received approximately $8 million in refunds through settlements with certain sellers of power.  MPS Merchant estimates that it is entitled to approximately $12 million in additional refunds under the standards FERC has used in this case.  FERC has stated that interest will be applied to the refunds but the amount of interest has not yet been determined.  However, in December 2001, various parties appealed the FERC order to the United States Court of Appeals for the Ninth Circuit seeking review of a number of issues, including changing

45

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

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

12.   RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO’s business and operate its facilities at cost.  These costs totaled $25.0 million and $82.2 million, respectively, for the three months ended and year to date September 30, 2011, respectively.  These costs totaled $26.3 million and $73.5 million, respectively, for the same periods in 2010.  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
	2011		2010
	(millions)
Net receivable from GMO	$	45.7	$	29.6
Net receivable from Great Plains Energy		14.0		13.3
Receivable from MPS Merchant		8.6		0.3

13.   DERIVATIVE INSTRUMENTS

Great Plains Energy and KCP&L are exposed to a variety of market risks including interest rates and commodity prices.  Management has established risk management policies and strategies to reduce the potentially adverse effects that the volatility of the markets may have on Great Plains Energy’s and KCP&L’s operating results.  Commodity risk management activities, including the use of certain derivative instruments, are subject to the management, direction and control of an internal 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

46

asset or liability.  Changes in the fair value of derivative instruments are recognized currently in net income unless specific hedge accounting criteria are met, except GMO utility operations hedges that are recorded to a regulatory asset or liability consistent with MPSC regulatory orders, as discussed below.

Great Plains Energy and KCP&L have posted collateral, in the ordinary course of business, for the aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a liability position.  At September 30, 2011, Great Plains Energy and KCP&L have posted collateral in excess of the aggregate fair value of their derivative instruments; therefore, if the credit risk-related contingent features underlying these agreements were triggered, Great Plains Energy and KCP&L would not be required to post additional collateral to its counterparties.

The Dodd-Frank Wall Street Reform and Consumer Protection Act 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 will 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 May 2011, Great Plains Energy issued $350.0 million of long-term debt and settled six forward starting swaps (FSS) simultaneously with the issuance of this long-term fixed rate debt.  Great Plains Energy had entered into the six FSS with notional amounts totaling $350.0 million to hedge against interest rate variability on the debt issuance.  The six FSS were treated as cash flow hedges with no ineffectiveness recorded for the three months ended and year to date September 30, 2011 and 2010.  A pre-tax loss of $26.1 million was recorded to OCI and is being reclassified to interest expense over the first three years of the ten-year debt.  For the three months ended and year to date September 30, 2011, a $2.2 million and $3.3 million loss, respectively, has been reclassified from OCI to interest expense.

Commodity Risk Management

KCP&L’s risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales.  At September 30, 2011, KCP&L had fully hedged 2012 and had hedged 91% of 2013 projected natural gas usage for retail load and firm MWh sales, primarily by utilizing futures contracts and financial instruments.  KCP&L has designated the natural gas hedges as cash flow hedges.  The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge.  To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense.  KCP&L has not recorded any ineffectiveness on natural gas hedges for the three months ended and year to date September 30, 2011 and 2010.

GMO’s risk management policy is to use derivative instruments to mitigate price exposure to natural gas price volatility in the market.  The fair value of the portfolio relates to financial contracts that will settle against actual purchases of natural gas and purchased power.  At September 30, 2011, GMO had financial contracts in place to hedge approximately 68%, 70% and 50% of the expected on-peak natural gas and natural gas equivalent purchased power price exposure for 2011, 2012 and 2013, respectively.  GMO has designated its natural gas hedges as economic hedges (non-hedging derivatives).  In connection with GMO’s 2005 Missouri electric rate case, it was agreed that the settlement costs of these contracts would be recognized in fuel expense.  The settlement cost is included in GMO’s FAC.  A regulatory asset has been recordedto reflect the change in the timing of recognition authorized by the MPSC.  To the extent recovery of actual costs incurred is allowed, amounts will not impact earnings, but will impact cash flows due to the timing of the recovery mechanism.

47

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

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

	September 30					December 31
	2011					2010
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	2.6	$	(0.2	)	$	4.0	$	-
Non-hedging derivatives		20.2		(2.0	)		59.5		(2.5	)
Forward contracts
Non-hedging derivatives		135.4		9.3			202.8		8.9
Option contracts
Non-hedging derivatives		0.4		-			0.2		-
Anticipated debt issuance				-
Forward starting swaps		-		-			350.0		(20.8	)
KCP&L
Futures contracts
Cash flow hedges		2.6		(0.2	)		4.0		-

48

The fair values of Great Plains Energy’s and KCP&L’s open derivative positions are summarized in the following tables.  The tables contain both derivative instruments designated as hedging instruments as well as non-hedging derivatives under GAAP.  The fair values below are gross values before netting agreements and netting of cash collateral.

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.3		2.0
Total Derivatives		$	9.3	$	2.2
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9
KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

49

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, 2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(5.1	)
Commodity contracts		(0.1	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		2.1
Total	$	-		Total	$	(3.1	)
Year to Date September 30, 2011
Interest rate contracts	$	(5.3	)	Interest charges	$	(11.9	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		2.2		Income tax benefit (expense)		4.7
Total	$	(3.3	)	Total	$	(7.3	)
Three Months Ended September 30, 2010
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	)

50

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, 2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(2.1	)
Commodity contracts		(0.1	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		0.9
Total	$	-		Total	$	(1.3	)
Year to Date September 30, 2011
Interest rate contracts	$	-		Interest charges	$	(6.5	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		2.6
Total	$	(0.1	)	Total	$	(4.0	)
Three Months Ended September 30, 2010
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	)

51

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, 2011	(millions)				(millions)
Commodity contracts	$	(2.2	)	Fuel	$	(0.6	)
Total	$	(2.2	)	Total	$	(0.6	)
Year to Date September 30, 2011
Commodity contracts	$	(3.5	)	Fuel	$	(3.5	)
Total	$	(3.5	)	Total	$	(3.5	)
Three Months Ended September 30, 2010
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	)

Great Plains Energy’s income statement reflects gains (losses) for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $(0.6) million and $0.4 million, respectively, for the three months ended and year to date September 30, 2011, and $(1.6) million and an insignificant amount, respectively, for the same periods in 2010.

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
	2011			2010			2011			2010
	(millions)
Current assets	$	11.5		$	12.0		$	11.5		$	12.0
Current liabilities		(94.5	)		(101.5	)		(64.7	)		(71.6	)
Deferred income taxes		32.3			34.8			20.7			23.2
Total	$	(50.7	)	$	(54.7	)	$	(32.5	)	$	(36.4	)

Great Plains Energy’s accumulated OCI in the table above at September 30, 2011, includes $20.3 million that is expected to be reclassified to expenses over the next twelve months.  KCP&L’s accumulated OCI includes $8.9 million that is expected to be reclassified to expense over the next twelve months.

52

14.   FAIR VALUE MEASUREMENTS

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  GAAP establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad categories, giving the highest priority to quoted prices in active markets for identical assets or liabilities and lowest priority to unobservable inputs.  A definition of the various levels, as well as discussion of the various measurements within the levels, is as follows:

Level 1 – Unadjusted quoted prices for identical assets or liabilities in active markets that Great Plains Energy and KCP&L have access to at the measurement date.  Assets categorized within this level consist of Great Plains Energy’s and KCP&L’s various exchange traded derivative instruments and equity and U.S. Treasury securities that are actively traded within KCP&L’s decommissioning trust fund and GMO’s SERP rabbi trust fund.

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

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

53

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, 2011, and December 31, 2010.

						Fair Value Measurements Using
Description	September 30 2011		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Derivative instruments (a)	$	-	$	-		$	-	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		75.2		-			75.2		-		-
Debt securities
U.S. Treasury		14.7		-			14.7		-		-
U.S. Agency		3.6		-			-		3.6		-
State and local obligations		2.6		-			-		2.6		-
Corporate bonds		25.3		-			-		25.3		-
Foreign governments		0.7		-			-		0.7		-
Other		0.3		-			-		0.3		-
Total nuclear decommissioning trust		122.4		-			89.9		32.5		-
Total		122.4		-			89.9		32.5		-
Liabilities
Derivative instruments (a)		-		(0.2	)		0.2		-		-
Total	$	-	$	(0.2	)	$	0.2	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	9.3	$	-		$	-	$	4.8	$	4.5
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		0.2		-			-		0.2		-
Total SERP rabbi trust		0.4		-			0.2		0.2		-
Total		9.7		-			0.2		5.0		4.5
Liabilities
Derivative instruments (a)		-		(2.0	)		2.0		-		-
Total	$	-	$	(2.0	)	$	2.0	$	-	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	9.3	$	-		$	-	$	4.8	$	4.5
Nuclear decommissioning trust (b)		122.4		-			89.9		32.5		-
SERP rabbi trust (c)		0.4		-			0.2		0.2		-
Total		132.1		-			90.1		37.5		4.5
Liabilities
Derivative instruments (a)		-		(2.2	)		2.2		-		-
Total	$	-	$	(2.2	)	$	2.2	$	-	$	-

54

						Fair Value Measurements Using
Description	December 31 2010		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Derivative instruments (a)	$	-	$	(0.1	)	$	0.1	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		85.5		-			85.5		-		-
Debt securities
U.S. Treasury		8.9		-			8.9		-		-
U.S. Agency		4.8		-			-		4.8		-
State and local obligations		2.5		-			-		2.5		-
Corporate bonds		23.7		-			-		23.7		-
Foreign governments		0.7		-			-		0.7		-
Other		0.4		-			-		0.4		-
Total nuclear decommissioning trust		126.5		-			94.4		32.1		-
Total		126.5		(0.1	)		94.5		32.1		-
Liabilities
Derivative instruments (a)		-		(0.1	)		0.1		-		-
Total	$	-	$	(0.1	)	$	0.1	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.5	)	$	0.5	$	5.2	$	3.7
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		7.0		-			-		7.0		-
Total SERP rabbi trust		7.2		-			0.2		7.0		-
Total		16.1		(0.5	)		0.7		12.2		3.7
Liabilities
Derivative instruments (a)		20.8		(3.0	)		3.0		20.8		-
Total	$	20.8	$	(3.0	)	$	3.0	$	20.8	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.6	)	$	0.6	$	5.2	$	3.7
Nuclear decommissioning trust (b)		126.5		-			94.4		32.1		-
SERP rabbi trust (c)		7.2		-			0.2		7.0		-
Total		142.6		(0.6	)		95.2		44.3		3.7
Liabilities
Derivative instruments (a)		20.8		(3.1	)		3.1		20.8		-
Total	$	20.8	$	(3.1	)	$	3.1	$	20.8	$	-

55

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

(b)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $3.1 million and $2.7 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(c)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $20.4 million and $14.6 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)   Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty.  At September 30, 2011, and December 31, 2010, Great Plains Energy netted $2.2 million and $2.5 million, respectively, of cash collateral posted with counterparties.

The following tables reconcile the beginning and ending balances for all level 3 assets and liabilities, net measured at fair value on a recurring basis for the three months ended and year to date September 30, 2011 and 2010.

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

56

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other Great
	Plains Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains or (losses)
Included in non-operating income		11.1
Settlements		(10.3	)
Balance September 30, 2011	$	4.5
Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at September 30, 2011	$	1.2

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	)

57

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other Great			Great Plains
	KCP&L			Plains 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	$	-		$	-		$	-

15.   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	2011			2010			2011			2010
Current income taxes	(millions)
Federal	$	(10.2	)	$	(7.2	)	$	(6.4	)	$	(8.1	)
State		(0.8	)		(2.0	)		(4.8	)		0.3
Foreign		-			(0.2	)		(0.4	)		0.2
Total		(11.0	)		(9.4	)		(11.6	)		(7.6	)
Deferred income taxes
Federal		74.7			73.5			103.6			108.2
State		13.0			14.6			20.4			18.8
Total		87.7			88.1			124.0			127.0
Noncurrent income taxes
Federal		-			(6.8	)		(18.0	)		(1.3	)
State		-			(1.0	)		(1.9	)		(0.3	)
Foreign		(0.6	)		0.2			(0.4	)		0.2
Total		(0.6	)		(7.6	)		(20.3	)		(1.4	)
Investment tax credit
Deferral		-			-			-			(4.1	)
Amortization		(0.7	)		(0.7	)		(1.5	)		(1.8	)
Total		(0.7	)		(0.7	)		(1.5	)		(5.9	)
Income tax expense	$	75.4		$	70.4		$	90.6		$	112.1

58

	Three Months Ended						Year to Date
	September 30						September 30
KCP&L	2011			2010			2011			2010
Current income taxes	(millions)
Federal	$	(10.2	)	$	(15.3	)	$	(7.8	)	$	22.5
State		(0.9	)		(2.6	)		(0.4	)		4.6
Total		(11.1	)		(17.9	)		(8.2	)		27.1
Deferred income taxes
Federal		53.5			63.9			73.4			53.9
State		9.3			11.7			13.8			9.5
Total		62.8			75.6			87.2			63.4
Noncurrent income taxes
Federal		1.5			(2.4	)		(9.1	)		(1.5	)
State		0.1			(0.3	)		(1.0	)		(0.1	)
Total		1.6			(2.7	)		(10.1	)		(1.6	)
Investment tax credit
Deferral		-			-			-			(4.1	)
Amortization		(0.5	)		(0.5	)		(1.0	)		(1.2	)
Total		(0.5	)		(0.5	)		(1.0	)		(5.3	)
Income tax expense	$	52.8		$	54.5		$	67.9		$	83.6

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	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	70.6		$	70.8			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.8			(0.9	)		0.9			(0.4	)
Amortization of investment tax credits		(0.7	)		(0.7	)		(0.3	)		(0.4	)
Federal income tax credits		(2.9	)		(2.0	)		(1.4	)		(0.9	)
State income taxes		8.1			7.5			4.0			3.7
Changes in uncertain tax positions, net		(2.7	)		0.3			(1.3	)		0.2
Valuation allowance		-			(2.9	)		-			(1.4	)
Other		1.2			(1.7	)		0.4			(1.0	)
Total	$	75.4		$	70.4			37.3	%		34.8	%

59

Great Plains Energy	Income Tax Expense						Income Tax Rate
Year to Date September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	92.0		$	115.0			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		3.7			(6.0	)		1.4			(1.8	)
Amortization of investment tax credits		(1.5	)		(1.8	)		(0.6	)		(0.5	)
Federal income tax credits		(9.7	)		(6.1	)		(3.7	)		(1.8	)
State income taxes		11.1			12.0			4.2			3.7
Medicare Part D subsidy legislation		-			2.8			-			0.8
Changes in uncertain tax positions, net		(4.0	)		0.3			(1.5	)		0.1
Valuation allowance		(2.2	)		(2.9	)		(0.8	)		(0.9	)
Other		1.2			(1.2	)		0.5			(0.5	)
Total	$	90.6		$	112.1			34.5	%		34.1	%

KCP&L	Income Tax Expense						Income Tax Rate
Three Months Ended September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	48.3		$	51.5			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.7			(1.1	)		1.2			(0.8	)
Amortization of investment tax credits		(0.5	)		(0.5	)		(0.4	)		(0.4	)
Federal income tax credits		(2.9	)		(1.9	)		(2.1	)		(1.3	)
State income taxes		5.7			5.7			4.1			3.9
Changes in uncertain tax positions		-			0.1			-			0.1
Other		0.5			0.7			0.4			0.6
Total	$	52.8		$	54.5			38.2	%		37.1	%

KCP&L	Income Tax Expense						Income Tax Rate
Year to Date September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	66.7		$	85.3			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		3.3			(5.2	)		1.7			(2.2	)
Amortization of investment tax credits		(1.0	)		(1.2	)		(0.5	)		(0.5	)
Federal income tax credits		(9.6	)		(6.0	)		(5.1	)		(2.5	)
State income taxes		7.7			8.8			4.0			3.6
Medicare Part D subsidy legislation		-			2.8			-			1.2
Changes in uncertain tax positions		0.4			0.1			0.2			0.1
Other		0.4			(1.0	)		0.3			(0.4	)
Total	$	67.9		$	83.6			35.6	%		34.3	%

60

Uncertain Tax Positions

At September 30, 2011, and December 31, 2010, Great Plains Energy had $24.4 million and $42.0 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $12.4 million and $17.3 million, respectively, at September 30, 2011, and December 31, 2010, is expected to impact the effective tax rate if recognized.  The $17.6 million decrease in unrecognized tax benefits is primarily due to a decrease of $18.4 million related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years.  The $18.4 million tax benefit recognized related to the 2006-2008 IRS audit was offset by an increase of $16.4 million in deferred income tax liabilities since a significant portion of the unrecognized tax benefits were related to temporary tax differences, which resulted in an increase to net income of $2.0 million.

At September 30, 2011, and December 31, 2010, KCP&L had $9.0 million and $19.1 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $0.3 million at September 30, 2011, and December 31, 2010, is expected to impact the effective tax rate if recognized.  The $10.1 million decrease in unrecognized tax benefits is primarily due to a decrease of $12.1 million related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years.  The tax benefit recognized related to the 2006-2008 IRS audit was mostly offset by an increase in deferred income tax liabilities, which resulted in an insignificant impact to net income.

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

	Great Plains Energy						KCP&L
	September 30			December 31			September 30			December 31
	2011			2010			2011			2010
	(millions)
Beginning balance	$	42.0		$	51.4		$	19.1		$	20.9
Additions for current year tax positions		1.1			2.7			-			1.3
Additions for prior year tax positions		2.5			2.1			2.3			1.5
Reductions for prior year tax positions		(20.8	)		(10.6	)		(12.4	)		(1.6	)
Settlements		-			(3.8	)		-			(2.9	)
Statute expirations		-			(0.3	)		-			(0.1	)
Foreign currency translation adjustments		(0.4	)		0.5			-			-
Ending balance	$	24.4		$	42.0		$	9.0		$	19.1

Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.  At September 30, 2011, and December 31, 2010, accrued interest related to unrecognized tax benefits for Great Plains Energy was $5.9 million and $6.7 million, respectively.  Amounts accrued for penalties with respect to unrecognized tax benefits was $1.1 million at September 30, 2011, and December 31, 2010.  KCP&L had accrued interest related to unrecognized tax benefits of $0.3 million and $1.4 million at September 30, 2011, and December 31, 2010, respectively.  Amounts accrued for penalties with respect to unrecognized tax benefits for KCP&L are insignificant.

The Companies are unable to estimate the amount of unrecognized tax benefits that may be recognized in the next twelve months.  

61

16.   SEGMENTS AND RELATED INFORMATION

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, 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						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	773.7		$	-		$	773.7
Depreciation and amortization		(65.9	)		-			(65.9	)
Interest charges		(50.2	)		(10.6	)		(60.8	)
Income tax (expense) benefit		(82.9	)		7.5			(75.4	)
Net income (loss) attributable to Great Plains Energy		133.9			(7.4	)		126.5
Year to Date	Electric						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	1,831.7		$	-		$	1,831.7
Depreciation and amortization		(205.9	)		-			(205.9	)
Interest charges		(124.8	)		(31.2	)		(156.0	)
Income tax (expense) benefit		(109.8	)		19.2			(90.6	)
Net income (loss) attributable to Great Plains Energy		189.9			(17.6	)		172.3
Three Months Ended	Electric						Great Plains
September 30, 2010	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						Great Plains
September 30, 2010	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	)
Net income (loss) attributable to Great Plains Energy		232.8			(16.2	)		216.6

62

	Electric							Great Plains
	Utility		Other		Eliminations			Energy
September 30, 2011	(millions)
Assets	$	9,365.0	$	72.1	$	(432.0	)	$	9,005.1
Capital expenditures (a)		317.8		-		-			317.8
December 31, 2010
Assets	$	9,152.7	$	66.3	$	(400.8	)	$	8,818.2
Capital expenditures (a)		618.1		-		-			618.1
(a) Capital expenditures reflect year to date amounts for the periods presented.

17.   GOODWILL

Accounting rules require goodwill to be tested for impairment annually and when an event occurs indicating the possibility that an impairment exists.  The annual impairment test for the $169.0 million of GMO acquisition goodwill was conducted on September 1, 2011.  The goodwill impairment test is a two step process.  The first step compares the fair value of a reporting unit to its carrying amount, including goodwill, to identify potential impairment.  If the carrying amount exceeds the fair value of the reporting unit, the second step of the test is performed, consisting of assignment of the reporting unit’s fair value to its assets and liabilities to determine an implied fair value of goodwill which is compared to the carrying amount of goodwill to determine the impairment loss, if any, to be recognized in the financial statements.  Great Plains Energy’s regulated electric utility operations are considered one reporting unit for assessment of impairment, as they are included within the same operating segment and have similar economic characteristics.  The determination of fair value of the reporting unit consisted of two valuation techniques: an income approach consisting of a discounted cash flow analysis and a market approach consisting of a determination of reporting unit invested capital using market multiples derived from the historical revenue, EBITDA and net utility asset values and market prices of stock of electric and gas company regulated peers.  The results of the two techniques were evaluated and weighted to determine a point within the range that management considered representative of fair value for the reporting unit.  Fair value of the reporting unit exceeded the carrying amount, including goodwill; therefore, there was no impairment of goodwill.

63

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GREAT PLAINS ENERGY INCORPORATED

EXECUTIVE SUMMARY

Description of Business

Great Plains Energy 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 direct subsidiaries with operations or active subsidiaries are KCP&L and GMO.  Great Plains Energy’s sole reportable business segment is electric utility for the periods presented.

Electric utility consists of KCP&L, a regulated utility, and GMO’s regulated utility operations, which include its Missouri Public Service and St. Joseph Light & Power divisions.  Electric utility has over 6,600 MWs of generating capacity and engages in the generation, transmission, distribution and sale of electricity to approximately 825,000 customers in the states of Missouri and Kansas.  Electric utility’s retail electricity rates are below the national average of investor-owned utilities.

Earnings Overview

Great Plains Energy’s earnings available for common shareholders for the three months ended September 30, 2011, decreased to $126.1 million or $0.91 per share from $131.6 million or $0.96 per share for the same period in 2010.  Several of KCP&L’s coal-fired power plants were impacted by flooding along the Missouri River in 2011, which decreased gross margin by an estimated $16 million due to coal conservation and increased other operating expenses $3.4 million.  Also contributing to the decrease in earnings were unfavorable weather and a $5.8 million increase in electric utility’s general taxes driven by higher property taxes.  Partially offsetting these decreases were new retail rates in Kansas effective December 1, 2010, and Missouri effective May 4, 2011, for KCP&L, and June 25, 2011, for GMO, and an increase in weather-normalized retail demand.  Gross margin is a financial measure that is not calculated in accordance with GAAP.  See the explanation of gross margin and the reconciliation to GAAP operating revenues under Great Plains Energy’s Results of Operations below for further information.

Great Plains Energy’s earnings available for common shareholders year to date September 30, 2011, decreased to $171.1 million or $1.24 per share from $215.4 million or $1.57 per share for the same period in 2010.  Flooding along the Missouri River in 2011 decreased gross margin by an estimated $16 million due to coal conservation and increased other operating expenses $3.4 million.  Also in 2011, Great Plains Energy recognized $12.7 million of expense related to a voluntary separation program; a decrease in gross margin due to unfavorable weather, an estimated $11 million from the impact of an extended refueling outage at Wolf Creek, and $7.5 million from increased coal transportation costs not recovered in KCP&L’s Missouri retail rates; and a $12.7 million increase in electric utility’s general taxes driven by higher property taxes.  Partially offsetting these decreases were new retail rates in Kansas effective December 1, 2010, and Missouri effective May 4, 2011, for KCP&L, and June 25, 2011, for GMO.

KCP&L Kansas Rate Case Proceedings

In November 2010, KCC issued an order, effective December 1, 2010, for KCP&L, authorizing an increase in annual revenues of $21.8 million, a return on equity of 10.0%, an equity ratio of approximately 49.7% and a Kansas jurisdictional rate base of $1.781 billion.  The annual revenue increase was subsequently adjusted by KCC in a January 2011 reconsideration order to $22.0 million.  In February 2011, KCC issued an order granting KCP&L and another party to the case their respective petitions for reconsideration regarding rate case expenses and therefore, approximately $1.4 million of the annual revenue increase is considered as interim subject to refund or true-up pending the outcome of the reconsideration proceedings regarding rate case expenses.  A hearing was

64

held in September 2011 with a decision expected in the fourth quarter of 2011.  The rates authorized by KCC are effective unless and until modified by KCC or stayed by a court.

KCP&L Missouri Rate Case Proceedings

On June 4, 2010, KCP&L filed a request with the MPSC to increase its Missouri retail electric annual revenues by $92.1 million.  The request was ultimately adjusted during the rate case proceedings by KCP&L to $66.5 million as the net result of lower fuel and purchased power costs and other updates to the case.  KCP&L’s initial and updated requests reflected, among other things, a proposed annual offset to its revenue requirement for the Missouri jurisdictional portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset); the final update included a proposed wholesale margin offset of approximately $29.4 million.  On April 12, 2011, the MPSC issued its order and on April 14, 2011, the MPSC Staff filed a report which quantified the authorized revenue increase as approximately $34.8 million on an annual basis, which reflects a wholesale margin offset of approximately $45.9 million and authorizes a return on equity of 10.0%, an equity ratio of approximately 46.3% and a Missouri jurisdictional rate base of approximately $2.0 billion.  If the actual Missouri jurisdiction wholesale margin amount exceeds the $45.9 million level reflected in the MPSC order, the difference will be recorded as a regulatory liability and will be returned, with interest, to KCP&L Missouri customers in a future rate case.  The MPSC order provides the opportunity for KCP&L to retain a larger amount of non-firm wholesale electric sales margin than KCP&L proposed; however, there are no assurances that KCP&L will achieve the $45.9 million wholesale margin offset amount and there are no means for KCP&L to recover any shortfall through its retail rates.  The rates established by the MPSC order took effect on May 4, 2011.

As a result of disallowances in the MPSC order, KCP&L recognized losses of $1.5 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project year to date September 30, 2011.  KCP&L also recorded a $2.4 million loss for other disallowed costs in the MPSC order.

In a related order, the MPSC required KCP&L and GMO to apply to the Internal Revenue Service (IRS) to reallocate approximately $26.5 million of Iatan No. 2 qualifying advance coal project tax credits from KCP&L to GMO.  KCP&L and GMO did apply to the IRS but in September 2011, the IRS denied KCP&L’s and GMO’s request.  The MPSC has indicated it will consider the ratemaking treatment of the tax credits in a future rate case.  Certain ratemaking treatments that may be pursued by the MPSC could trigger the loss or repayment to the IRS of a portion of unamortized deferred investment tax credits.  At September 30, 2011, KCP&L and GMO had $128.4 million and $3.5 million, respectively, of unamortized deferred investment tax credits.

GMO Missouri Rate Case Proceedings

On June 4, 2010, GMO filed requests with the MPSC to increase its Missouri retail electric annual revenues by $75.8 million for its Missouri Public Service division, and $22.1 million for its L&P division.  GMO subsequently adjusted its requests during the rate case proceedings to $65.9 million and $23.2 million, respectively, as the net result of updates to the cases.  On May 4, 2011, the MPSC issued its order and on May 10, 2011, the MPSC Staff filed a report which quantified the authorized revenue increases on an annual basis as $30.1 million for GMO’s Missouri Public Service division and $29.3 million for GMO’s L&P division.  The MPSC order authorized a return on equity of 10.0%, an equity ratio of approximately 46.6% and a Missouri jurisdictional rate base of $1.76 billion.  In response to applications for clarification and rehearing of the MPSC order, the MPSC on May 27, 2011, issued an order of clarification and modification.  The modified MPSC order revised the authorized annual revenue increase to approximately $35.7 million for GMO’s Missouri Public Service division and approximately $29.8 million for GMO’s L&P division, resulting primarily from a clarification of the amount of fuel costs shifted from GMO’s fuel adjustment clause to base rates.  However, because the MPSC authorized an annual revenue increase that was greater than the amount originally requested by GMO and communicated to GMO’s customers, the modified MPSC order deferred approximately $7.7 million of the L&P division increase, which is the amount over GMO’s requested $22.1 million increase for that division, and will phase in the deferred revenue amount in equal parts over a two-year period, plus carrying costs.

65

As a result of disallowances in the MPSC order, GMO recognized losses of $0.8 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project year to date September 30, 2011.  GMO also recorded a $1.5 million loss for other disallowed costs in the MPSC order.

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

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

Coal Conservation and Flood-Related Expenses

Several of KCP&L’s coal-fired power plants were impacted by flooding along the Missouri River during 2011.  Iatan Nos. 1 and 2, Hawthorn No. 5 and LaCygne Nos. 1 and 2 experienced longer rail delivery cycle times, which resulted in delays in coal delivery.  During July 2011, coal deliveries at Iatan Nos. 1 and 2 were suspended.  In an effort to conserve coal and meet customer demand, KCP&L operated the affected plants at reduced loads until mid-October.

The impact of coal conservation at Great Plains Energy resulting from increased fuel and purchased power expense and reduced wholesale sales was approximately $30 million for the three months ended and year to date September 30, 2011, and is expected to be insignificant in the fourth quarter of 2011.  KCP&L’s retail rates in Kansas and GMO’s retail rates contain fuel recovery mechanisms that include the cost of fuel and purchased power, offset by wholesale sales margin.  KCP&L’s Missouri retail rates do not contain a fuel recovery mechanism.  As a result, coal conservation reduced Great Plains Energy’s and KCP&L’s third quarter net income by approximately $10 million.  Additionally, Great Plains Energy’s and KCP&L’s net income was reduced by approximately $2 million for other flood-related expenses.

ENVIRONMENTAL MATTERS

See Note 10 to the consolidated financial statements for information regarding environmental matters.

RELATED PARTY TRANSACTIONS

See Note 12 to the consolidated financial statements for information regarding related party transactions.

66

GREAT PLAINS ENERGY RESULTS OF OPERATIONS

The following table summarizes Great Plains Energy’s comparative results of operations.

	Three Months Ended						Year to Date
	September 30						September 30
	2011			2010			2011			2010
	(millions)
Operating revenues	$	773.7		$	728.8		$	1,831.7		$	1,787.7
Fuel		(146.5	)		(127.3	)		(365.8	)		(333.2	)
Purchased power		(68.1	)		(68.0	)		(178.4	)		(171.4	)
Transmission of electricity by others		(8.6	)		(8.1	)		(23.1	)		(20.9	)
Gross margin (a)		550.5			525.4			1,264.4			1,262.2
Other operating expenses		(221.9	)		(196.3	)		(626.3	)		(573.0	)
Voluntary separation program		-			-			(12.7	)		-
Depreciation and amortization		(65.9	)		(85.3	)		(205.9	)		(248.5	)
Operating income		262.7			243.8			419.5			440.7
Non-operating income and expenses		0.1			4.1			(0.5	)		27.7
Interest charges		(60.8	)		(45.5	)		(156.0	)		(138.7	)
Income tax expense		(75.4	)		(70.4	)		(90.6	)		(112.1	)
Loss from equity investments		-			-			(0.1	)		(0.9	)
Net income		126.6			132.0			172.3			216.7
Less: Net income attributable to noncontrolling interest		(0.1	)		-			-			(0.1	)
Net income attributable to Great Plains Energy		126.5			132.0			172.3			216.6
Preferred dividends		(0.4	)		(0.4	)		(1.2	)		(1.2	)
Earnings available for common shareholders	$	126.1		$	131.6		$	171.1		$	215.4
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin below.

Three Months Ended September 30, 2011 Compared to September 30, 2010

Great Plains Energy’s earnings available for common shareholders for the three months ended September 30, 2011, decreased to $126.1 million, or $0.91 per share, from $131.6 million, or $0.96 per share, for the same period in 2010.

Electric utility’s net income decreased $2.3 million for the three months ended September 30, 2011, compared to the same period in 2010.  Flooding along the Missouri River in 2011 decreased gross margin by an estimated $16 million due to coal conservation and increased other operating expenses $3.4 million.  Also contributing to the decrease in earnings were unfavorable weather and a $5.8 million increase in electric utility’s general taxes driven by higher property taxes.  Partially offsetting these decreases were new retail rates in Kansas effective December 1, 2010, and Missouri effective May 4, 2011, for KCP&L, and June 25, 2011, for GMO and an increase in weather-normalized retail demand.

Great Plains Energy’s corporate and other activities loss increased $3.2 million for the three months ended September 30, 2011, compared to the same period in 2010 due to the resolution of certain general tax related matters in 2011.

Year to Date September 30, 2011 Compared to September 30, 2010

Great Plains Energy’s earnings available for common shareholders year to date September 30, 2011, decreased to $171.1 million, or $1.24 per share, from $215.4 million, or $1.57 per share, for the same period in 2010.

Electric utility’s net income decreased $42.9 million year to date September 30, 2011, compared to the same period in 2010.  Flooding along the Missouri River in 2011 decreased gross margin by an estimated $16 million

67

due to coal conservation and increased other operating expenses $3.4 million.  Also in 2011, electric utility recognized $12.7 million of expense related to a voluntary separation program; a decrease in gross margin due to unfavorable weather, an estimated $11 million from the impact of an extended refueling outage at Wolf Creek, and $7.5 million from increased coal transportation costs not recovered in KCP&L’s Missouri retail rates; and a $12.7 million increase in electric utility’s general taxes driven by higher property taxes.  Partially offsetting these decreases were new retail rates in Kansas effective December 1, 2010, and Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO.

Great Plains Energy’s corporate and other activities loss increased $1.4 million year to date September 30, 2011, compared to the same period in 2010.

Gross Margin

Gross margin is a financial measure that is not calculated in accordance with GAAP.  Gross margin, as used by Great Plains Energy and KCP&L, is defined as operating revenues less fuel, purchased power and transmission of electricity by others.  Expenses for fuel, purchased power and transmission of electricity by others, offset by wholesale sales margin, are subject to recovery through cost adjustment mechanisms, except for KCP&L’s Missouri retail operations.  As a result, operating revenues increase or decrease in relation to a significant portion of these expenses.  Management believes that gross margin provides a more meaningful basis for evaluating electric utility’s operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses.  Gross margin is used internally to measure performance against budget and in reports for management and the Board.  The Companies’ definition of gross margin may differ from similar terms used by other companies.

ELECTRIC UTILITY RESULTS OF OPERATIONS

The following table summarizes the electric utility segment results of operations.

	Three Months Ended						Year to Date
	September 30						September 30
	2011			2010			2011			2010
	(millions)
Operating revenues	$	773.7		$	728.8		$	1,831.7		$	1,787.7
Fuel		(146.5	)		(127.3	)		(365.8	)		(333.2	)
Purchased power		(68.1	)		(68.0	)		(178.4	)		(171.4	)
Transmission of electricity by others		(8.6	)		(8.1	)		(23.1	)		(20.9	)
Gross margin (a)		550.5			525.4			1,264.4			1,262.2
Other operating expenses		(218.2	)		(195.3	)		(620.8	)		(570.0	)
Voluntary separation program		-			-			(12.7	)		-
Depreciation and amortization		(65.9	)		(85.3	)		(205.9	)		(248.5	)
Operating income		266.4			244.8			425.0			443.7
Non-operating income and expenses		0.6			3.2			(0.5	)		21.9
Interest charges		(50.2	)		(34.8	)		(124.8	)		(107.4	)
Income tax expense		(82.9	)		(77.0	)		(109.8	)		(125.4	)
Net income	$	133.9		$	136.2		$	189.9		$	232.8
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's
Results of Operations.

68

Electric Utility Gross Margin and MWh Sales

The following tables summarize electric utility’s gross margin and MWhs sold.

	Revenues and Costs						%			MWhs Sold				%
Three Months Ended September 30	2011			2010			Change			2011		2010		Change
Retail revenues	(millions)									(thousands)
Residential	$	354.3		$	331.9			7			3,018		3,010		-
Commercial		271.2			255.5			6			2,990		2,986		-
Industrial		57.9			54.6			6			828		847		(2	)
Other retail revenues		5.1			3.9			20			29		26		11
Provision for rate refund (excess Missouri
wholesale margin)		-			(2.2	)	NM			NA		NA		NA
Fuel recovery mechanism under recovery		32.2			17.5			85		NA		NA		NA
Total retail		720.7			661.2			9			6,865		6,869		-
Wholesale revenues		41.9			55.0			(24	)		1,206		1,756		(31	)
Other revenues		11.1			12.6			(12	)	NA		NA		NA
Operating revenues		773.7			728.8			6			8,071		8,625		(6	)
Fuel		(146.5	)		(127.3	)		15
Purchased power		(68.1	)		(68.0	)		-
Transmission of electricity by others		(8.6	)		(8.1	)		5
Gross margin (a)	$	550.5		$	525.4			5
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's Results
of Operations.

	Revenues and Costs						%			MWhs Sold				%
Year to Date September 30	2011			2010			Change			2011		2010		Change
Retail revenues	(millions)									(thousands)
Residential	$	773.0		$	748.5			3			7,431		7,532		(1	)
Commercial		676.4			655.9			3			8,209		8,334		(1	)
Industrial		149.6			148.4			1			2,422		2,473		(2	)
Other retail revenues		14.4			12.9			9			88		84		6
Provision for rate refund (excess Missouri
wholesale margin)		-			(3.7	)	NM			NA		NA		NA
Fuel recovery mechanism under recovery		63.8			38.3			67		NA		NA		NA
Total retail		1,677.2			1,600.3			5			18,150		18,423		(1	)
Wholesale revenues		121.0			151.7			(20	)		3,595		4,658		(23	)
Other revenues		33.5			35.7			(6	)	NA		NA		NA
Operating revenues		1,831.7			1,787.7			2			21,745		23,081		(6	)
Fuel		(365.8	)		(333.2	)		10
Purchased power		(178.4	)		(171.4	)		4
Transmission of electricity by others		(23.1	)		(20.9	)		10
Gross margin (a)	$	1,264.4		$	1,262.2			-
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's Results
of Operations.

69

Electric utility’s gross margin increased $25.1 million for the three months ended September 30, 2011, compared to the same period in 2010 primarily due to:

·   new retail rates effective December 1, 2010, and May 4, 2011, for KCP&L in Kansas and Missouri, respectively, and June 25, 2011, for GMO and

·   an increase in weather-normalized retail demand.

These increases were partially offset by:

·   unfavorable weather, with a 7% decrease in cooling degree days, and

·   an estimated $16 million impact of coal conservation due to flooding resulting in increased fuel expenses and purchased power expenses and reduced wholesale sales.

Electric utility’s gross margin increased $2.2 million year to date September 30, 2011, compared to the same period in 2010 primarily due to new retail rates effective December 1, 2010, and May 4, 2011, for KCP&L in Kansas and Missouri, respectively, and June 25, 2011, for GMO.  This increase was mostly offset by:

·   unfavorable weather, with an 8% decrease in cooling degree days;

·   a $7.5 million increase in coal transportation costs not recovered in KCP&L’s Missouri retail rates where there is no fuel recovery mechanism, prior to new rates effective May 4, 2011;

·   an estimated $16 million impact of coal conservation due to flooding resulting in increased fuel expenses and purchased power expenses and reduced wholesale sales; and

·   an estimated $11 million impact from an extended refueling outage at Wolf Creek, which resulted in less generation available for wholesale sales, increased fuel expense due to the use of more coal in the fuel mix, which has a higher cost compared to nuclear fuel, and increased purchased power expense due to an increase in MWhs purchased.  Wolf Creek’s latest refueling outage began on March 19, 2011, and included several increases in work scope that extended the outage.  Primary components of the increased work scope were related to inspection and repair of essential service water system piping, testing and replacement of underground high voltage cables, and a repair of a ground on the main generator rotor.  During the last week of June 2011 before the unit returned to full capacity, Wolf Creek had an unplanned outage related to one of two main feed pumps.  Wolf Creek returned to 100% capacity in early July 2011.

Electric Utility Other Operating Expenses (including utility operating and maintenance expenses, general taxes and other)

Electric utility’s other operating expenses increased $22.9 million for the three months ended September 30, 2011, compared to the same period in 2010 primarily due to:

·   a $6.9 million increase in plant operating and maintenance expenses primarily due to Iatan No. 2 expenses being recognized with Kansas and Missouri rates effective December 1, 2010, and May 4, 2011, respectively, for KCP&L and Missouri rates effective June 25, 2011, for GMO;

·   a $5.8 million increase in general taxes driven by increased property taxes;

·   $3.4 million of expenses related to the impact of flooding; and

·   a $3.9 million increase in pension expense recognized pursuant to higher rates authorized in the MPSC and KCC rate orders.

Additionally, KCP&L and GMO recorded a $4.0 million loss in 2010 related to a recommended disallowance of their combined share of Iatan No. 2 construction costs.

70

Electric utility’s other operating expenses increased $50.8 million year to date September 30, 2011, compared to the same period in 2010 primarily due to:

·   a $12.1 million increase in plant operating and maintenance expenses primarily due to Iatan No. 2 expenses being recognized with Kansas and Missouri rates effective December 1, 2010, and May 4, 2011, respectively, for KCP&L and Missouri rates effective June 25, 2011, for GMO;

·   a $12.7 million increase in general taxes driven by increased property taxes;

·   a $9.4 million increase in pension expense recognized pursuant to higher rates authorized in the MPSC and KCC rate orders;

·   $3.4 million of expenses related to the impact of flooding; and

·   as a result of disallowances in the MPSC rate orders, KCP&L and GMO recognized combined losses of $2.3 million for construction costs related to Iatan No. 2 and to the Iatan No. 1 environmental project in 2011.  KCP&L and GMO also recognized a $3.9 million loss for other disallowed costs in the MPSC rate orders.  KCP&L and GMO recorded a $4.0 million loss in 2010 related to a recommended disallowance of their combined share of Iatan No. 2 construction costs.

Electric Utility Voluntary Separation Program

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

Great Plains Energy recorded a $10.0 million pension settlement charge during the third quarter of 2011 from the voluntary separation program as a result of accelerated pension distributions.  The Companies deferred substantially all of the charge as a regulatory asset and expect to recover it over future periods pursuant to regulatory agreements.  The amount of accelerated pension distributions resulting from the voluntary separation program resulted in increased pension funding requirements in 2011 under ERISA.

Electric Utility Depreciation and Amortization

Electric utility’s depreciation and amortization costs decreased $19.4 million for the three months ended September 30, 2011, compared to the same period in 2010 due to a $9.4 million decrease attributable to lower depreciation rates for KCP&L effective December 1, 2010, for Kansas and May 4, 2011, for Missouri and an $18.8 million decrease in regulatory amortization for KCP&L in Kansas and Missouri.  The regulatory amortization was in effect during KCP&L’s Comprehensive Energy Plan but concluded following the December 2010 and May 2011 effective dates of new retail rates for KCP&L in Kansas and Missouri, respectively.  These decreases were partially offset by $4.3 million of depreciation for Iatan No. 2, as well as increased depreciation expense for other capital additions.

Electric utility’s depreciation and amortization costs decreased $42.6 million year to date September 30, 2011, compared to the same period in 2010 due to a $25.1 million decrease attributable to lower depreciation rates for KCP&L and a $42.4 million decrease in regulatory amortization for KCP&L in Kansas and Missouri.  These decreases were partially offset by $10.5 million of depreciation for Iatan No. 2, as well as increased depreciation expense for other capital additions.

71

Electric Utility Non-Operating Income and Expenses

Electric utility’s non-operating income and expenses decreased $2.6 million and $22.4 million for the three months ended and year to date September 30, 2011, respectively, compared to the same periods in 2010 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010.

Electric Utility Interest Charges

Electric utility’s interest charges increased $15.4 million for the three months ended September 30, 2011, compared to the same period in 2010 primarily due to:

·   a $6.5 million decrease in the debt component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010;

·   $7.5 million of interest on intercompany notes from Great Plains Energy to GMO issued in August 2010 and May 2011; and

·   a $7.1 million decrease in construction accounting carrying costs for Iatan Nos. 1 and 2 and common facilities, which was in effect until new rates were effective in Missouri for KCP&L on May 4, 2011, and for GMO on June 25, 2011.

These items were partially offset by the maturity of GMO’s 7.95% Senior Notes and 7.75% Senior Notes in February 2011 and June 2011, respectively.

Electric utility’s interest charges increased $17.4 million year to date September 30, 2011, compared to the same period in 2010 primarily due to:

·   a $23.8 million decrease in the debt component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010 and

·   $15.5 million of interest on intercompany notes from Great Plains Energy to GMO issued in August 2010 and May 2011.

These items were partially offset by:

·   a $10.7 million increase in the deferral to a regulatory asset of construction accounting carrying costs for Iatan Nos. 1 and 2 and common facilities and

·   the maturity of GMO’s 7.95% Senior Notes and 7.75% Senior Notes in February 2011 and June 2011, respectively.

Electric Utility Income Tax Expense

Electric utility’s income tax expense increased $5.9 million for the three months ended September 30, 2011, compared to the same period in 2010 due to increased pre-tax income and $3.0 million of income tax true-ups.

Electric utility’s income tax expense decreased $15.6 million year to date September 30, 2011, compared to the same period in 2010 due to decreased pre-tax income.

GREAT PLAINS ENERGY SIGNIFICANT BALANCE SHEET CHANGES (September 30, 2011 compared to December 31, 2010)

·   Great Plains Energy’s receivables, net increased $33.9 million primarily due to a $52.3 million increase in customer accounts receivable resulting from seasonal increases.

·   Great Plains Energy’s fuel inventories, at average cost decreased $12.9 million primarily due to lower coal inventories driven by Missouri River flooding during 2011, partially offset by increased coal and coal transportation costs.

72

·   Great Plains Energy’s deferred refueling outage costs increased $23.8 million due to the deferral of costs for the Wolf Creek refueling outage that began on March 19, 2011, and included several increases in work scope that extended the outage.  These deferred costs will be amortized over the months prior to the next refueling outage currently scheduled for the fall of 2012.

·   Great Plains Energy’s refundable income taxes increased $13.3 million primarily due to refunds expected from utilizing a carryback of credits and net operating losses (NOLs) to previous tax years.

·   Great Plains Energy’s deferred income taxes – current assets decreased $7.6 million primarily due to increased temporary differences resulting from increased deferred refueling outage costs.

·   Great Plains Energy’s notes payable increased $18.5 million due to increased borrowings due to the timing of cash payments.

·   Great Plains Energy’s commercial paper decreased $253.0 million due to repayment with proceeds from KCP&L’s issuance of $400.0 million of 5.30% Senior Notes.

·   Great Plains Energy’s current maturities of long-term debt increased $465.7 million due to reclassification of $287.5 million of Great Plains Energy’s 10.00% Equity Units Subordinated Notes and $500.0 million of GMO’s 11.875% Senior Notes from long-term debt, partially offset by the repayment of $137.3 million and $197.0 million at maturity of GMO’s 7.95% and 7.75% Senior Notes, respectively.

·   Great Plains Energy’s accounts payable decreased $82.6 million due to the timing of cash payments.

·   Great Plains Energy’s accrued taxes increased $65.3 million primarily due to the timing of property tax payments.

·   Great Plains Energy’s derivative instruments – current liabilities decreased $20.8 million due to the settlement of FSS upon the issuance of Great Plains Energy’s $350.0 million of 4.85% Senior Notes.

·   Great Plains Energy’s deferred income taxes – deferred credits and other liabilities increased $120.6 million primarily due to a $183.3 million increase in temporary differences mostly as a result of bonus depreciation, partially offset by NOLs created.

·   Great Plains Energy’s other deferred credits and other liabilities decreased $30.3 million primarily due to a decrease in unrecognized tax benefits related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years.

·   Great Plains Energy’s long-term debt decreased $192.6 million primarily due to reclassification of $287.5 million of Great Plains Energy’s 10.00% Equity Units Subordinated Notes and $500.0 million of GMO’s 11.875% Senior Notes to current maturities and the purchase in lieu of redemption of $112.8 million of KCP&L’s EIRR bonds, offset by Great Plains Energy’s issuance of $350.0 million of 4.85% Senior Notes in May 2011 and KCP&L’s issuance of $400.0 million of 5.30% Senior Notes in September 2011.

CAPITAL REQUIREMENTS AND LIQUIDITY

Great Plains Energy operates through its subsidiaries and has no material assets other than the stock of its subsidiaries.  Great Plains Energy’s ability to make payments on its debt securities and its ability to pay dividends is dependent on its receipt of dividends or other distributions from its subsidiaries, proceeds from the issuance of its securities and borrowing under its revolving credit facility.

Great Plains Energy’s capital requirements are principally comprised of debt maturities and electric utility’s construction and other capital expenditures.  These items as well as additional cash and capital requirements are discussed below.

Great Plains Energy's liquid resources at September 30, 2011, consisted of $8.9 million of cash and cash equivalents on hand and $1.155 billion of unused bank lines of credit.  The unused lines consisted of $160.4 million from Great Plains Energy's revolving credit facility, $558.0 million from KCP&L's credit facilities and $436.8 million from GMO’s revolving credit facility.  See Note 8 to the consolidated financial statements for

73

more information on these credit facilities.  Generally, Great Plains Energy uses these liquid resources to meet its day-to-day cash flow requirements, and from time to time issues equity and/or long-term debt to repay short-term debt or increase cash balances.

Great Plains Energy intends to meet day-to-day cash flow requirements including interest payments, retirement of maturing debt, construction requirements, dividends and pension benefit plan funding requirements with a combination of internally generated funds and proceeds from the issuance of equity securities, equity-linked securities and/or short-term and long-term debt.  Great Plains Energy’s intention to meet a portion of these requirements with internally generated funds may be impacted by the effect of inflation on operating expenses, the level of retail MWh sales, regulatory actions, compliance with environmental regulations and the availability of generating units.  In addition, Great Plains Energy may issue equity, equity-linked securities and/or debt to finance growth.

At September 30, 2011, Great Plains Energy’s current maturities of long-term debt were $951.4 million.  KCP&L’s $150.0 million of 6.50% Senior Notes mature in November 2011 and are expected to be repaid with a portion of the proceeds from its $400.0 million of 5.30% Senior Notes that were issued in September 2011.  Great Plains Energy’s $287.5 million of Equity Units Subordinated Notes mature in 2042 but must be remarketed by June 12, 2012.  GMO’s $500.0 million of 11.875% Senior Notes mature in July 2012.  Great Plains Energy is evaluating alternatives to refinance this long-term debt, including issuing new long-term debt.  Based on current market conditions and Great Plains Energy’s unused bank lines of credit, Great Plains Energy expects to have the ability to access the markets to complete the necessary refinancing.

Cash Flows from Operating Activities

The decrease in cash flows from operating activities for Great Plains Energy year to date September 30, 2011, compared to the same period in 2010 is primarily due to a reduction in net income, the payment of $26.1 million for the settlement of FSS upon the issuance of $350.0 million of 4.85% Senior Notes in May 2011 and an increase in deferred refueling outage costs, partially offset by the adoption of new accounting rules in 2010.  On January 1, 2010, Great Plains Energy adopted new accounting rules for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivable pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s balance sheet at December 31, 2010.  See Note 3 for additional information.  As a result, cash flows from operating activities were reduced by $95.0 million and cash flows from financing activities were raised by $95.0 million with no impact to the net change in cash in 2010.  Other changes in working capital are detailed in Note 2 to the consolidated financial statements.  The individual components of working capital vary with normal business cycles and operations.

Cash Flows from Investing Activities

Great Plains Energy’s cash used for investing activities varies with the timing of utility capital expenditures and purchases of investments and nonutility property.  Investing activities are offset by the proceeds from the sale of properties and insurance recoveries.

Great Plains Energy’s utility capital expenditures decreased $147.4 million year to date September 30, 2011, compared to the same period in 2010 due to a decrease in cash utility capital expenditures primarily related to Iatan No. 2.

Great Plains Energy’s projected utility capital expenditures, excluding AFUDC to finance construction, for 2011 are expected to be approximately $50 million less than the $503.3 million disclosed in the 2010 Form 10-K.  This decrease is driven primarily by an approximate $17 million decrease related to environmental and an approximate $25 million decrease related to construction of Iatan No. 2.

74

Cash Flows from Financing Activities

Great Plains Energy’s cash flows from financing activities in 2011 reflect the issuance, at a discount, of $350.0 million of 4.85% Senior Notes that mature in 2021.  Great Plains Energy used the proceeds to make a ten-year intercompany loan to GMO with GMO using the proceeds to repay $137.3 million of 7.95% Senior Notes and $197.0 million of 7.75% Senior Notes at maturity.  Also reflected is KCP&L’s issuance, at a discount, of $400.0 million of 5.30% Senior Notes that mature in 2041.  KCP&L used a portion of the proceeds to repay short-term borrowings.

Great Plains Energy’s cash flows from financing activities year to date September 30, 2010, reflect the issuance, at a discount, of $250.0 million of 2.75% Senior Notes that mature in 2013.  Great Plains Energy used the proceedings to make a three-year intercompany loan to GMO with GMO using the proceeds to repay short-term borrowings.  Also reflected is the $95.0 million impact of the short-term collateralized note payable described above under cash flows from operating activities.

Financing Authorization

Under stipulations with the MPSC and KCC, Great Plains Energy and KCP&L maintain common equity at not less than 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress).  KCP&L’s long-term financing activities are subject to the authorization of the MPSC.  In March 2010, the MPSC authorized KCP&L to issue up to $450.0 million of long-term debt and to enter into interest rate hedging instruments in connection with such debt through December 31, 2011.  KCP&L utilized $400.0 million of this amount with the issuance in September 2011 of 5.30% unsecured Senior Notes maturing in 2041.

In December 2010, FERC authorized KCP&L to have outstanding at any time up to a total of $1.0 billion in short-term debt instruments through December 2012 conditioned on KCP&L’s borrowing costs not exceeding the greater of: (i) 4.25% over LIBOR; (ii) the greater of 2.25% over the prime rate, 2.75% over the federal funds rate, and 3.25% over LIBOR; or (iii) 4.25% over the A2/P-2 nonfinancial commercial paper rate most recently published by the Federal Reserve at the time of the borrowing.  The authorization is subject to four restrictions: (i) proceeds of debt backed by utility assets must be used for utility purposes; (ii) if any utility assets that secure authorized debt are divested or spun off, the debt must follow the assets and also be divested or spun off; (iii) if any proceeds of the authorized debt are used for non-utility purposes, the debt must follow the non-utility assets (specifically, if the non-utility assets are divested or spun off, then a proportionate share of the debt must follow the divested or spun off non-utility assets); and (iv) if utility assets financed by the authorized short-term debt are divested or spun off to another entity, a proportionate share of the debt must also be divested or spun off.  At September 30, 2011, there was $989.5 million available under this authorization.

In March 2010, and modified in April 2010, FERC authorized GMO to have outstanding at any time up to a total of $500.0 million of short-term debt through March 2012, conditioned on GMO’s borrowing costs not exceeding 4.3% over LIBOR, the prime rate or federal funds rate, as applicable, and subject to the same four restrictions as the KCP&L FERC short-term authorization discussed in the preceding paragraph.  At September 30, 2011, there was $500.0 million available under this authorization.  In July 2010, FERC authorized GMO to issue up to a total of $850.0 million of long-term debt, including intercompany debt, through July 2012 and subject to the same four restrictions as the KCP&L FERC short-term authorization discussed in the preceding paragraph.  At September 30, 2011, there was $253.9 million available under this authorization.  In October 2011, GMO filed a request with FERC for authorization to issue up to $850.0 million of long-term debt beginning January 2012 for a two-year period that would supersede its current authorization.

KCP&L and GMO are also authorized by FERC 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.  At September 30, 2011, KCP&L had an outstanding payable under the money pool of $0.4 million to Great Plains Energy and GMO had an outstanding payable of $30.9 million to KCP&L.

75

Debt Agreements

See Note 8 to the consolidated financial statements for discussion of revolving credit facilities.

Pensions

The Company maintains defined benefit plans for substantially all active and inactive employees of KCP&L, GMO and WCNOC and incurs significant costs in providing the plans.  Funding of the plans follows legal and regulatory requirements with funding equaling or exceeding the minimum requirements of ERISA.  Year to date September 30, 2011, the Company contributed $42.0 million to the pension plans and expects to contribute an additional $80.2 million in 2011 to satisfy the ERISA funding requirements and the MPSC and KCC rate orders, with the majority expected to be paid by KCP&L.

Additionally, the Company provides post-retirement health and life insurance benefits for certain retired employees and expects to make benefit contributions of $17.1 million under the provisions of these plans in 2011, with the majority paid by KCP&L.

Management believes the Company has adequate access to capital resources through cash flows from operations or through existing lines of credit to support these funding requirements.

Supplemental Capital Requirements and Liquidity Information

At September 30, 2011, Great Plains Energy’s and KCP&L’s contractual commitments for KCP&L’s environmental retrofits at its LaCygne station are $123.3 million, $385.7 million, $286.6 million, $130.1 million and $6.3 million for the years 2011 though 2015, respectively.  KCP&L owns 50% of the LaCygne station. KCP&L expects to be reimbursed by the other owner for its 50% share of the costs.  Great Plains Energy’s and KCP&L’s other contractual commitments have not significantly changed at September 30, 2011, compared to December 31, 2010.

76

KANSAS CITY POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

The following table summarizes KCP&L's consolidated comparative results of operations.

	Three Months Ended						Year to Date
	September 30						September 30
	2011			2010			2011			2010
	(millions)
Operating revenues	$	506.3		$	486.5		$	1,220.5		$	1,194.7
Fuel		(99.3	)		(83.8	)		(249.0	)		(213.2	)
Purchased power		(24.9	)		(25.0	)		(66.7	)		(63.2	)
Transmission of electricity by others		(5.7	)		(4.4	)		(14.2	)		(11.3	)
Gross margin (a)		376.4			373.3			890.6			907.0
Other operating expenses		(161.8	)		(143.3	)		(460.9	)		(426.0	)
Voluntary separation program		-			-			(9.2	)		-
Depreciation and amortization		(45.4	)		(66.4	)		(147.0	)		(192.2	)
Operating income		169.2			163.6			273.5			288.8
Non-operating income and expenses		(0.2	)		3.6			(1.6	)		18.6
Interest charges		(30.8	)		(20.1	)		(81.2	)		(63.8	)
Income tax expense		(52.8	)		(54.5	)		(67.9	)		(83.6	)
Net income	$	85.4		$	92.6		$	122.8		$	160.0
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's
Results of Operations.

77

KCP&L Gross Margin and MWh Sales

The following tables summarize KCP&L’s gross margin and MWhs sold.

	Revenues and Costs						%			MWhs Sold				%
Three Months September 30	2011			2010			Change			2011		2010		Change
Retail revenues	(millions)									(thousands)
Residential	$	222.5		$	209.8			6			1,884		1,872		1
Commercial		191.8			183.0			5			2,113		2,107		-
Industrial		34.4			34.0			1			488		508		(4	)
Other retail revenues		3.2			2.9			7			22		22		2
Provision for rate refund (excess
Missouri wholesale margin)		-			(2.2	)	NM			NA		NA		NA
Kansas ECA (over) under recovery		13.8			2.6		NM			NA		NA		NA
Total retail		465.7			430.1			8			4,507		4,509		-
Wholesale revenues		35.5			50.2			(29	)		1,081		1,615		(33	)
Other revenues		5.1			6.2			(17	)	NA		NA		NA
Operating revenues		506.3			486.5			4			5,588		6,124		(9	)
Fuel		(99.3	)		(83.8	)		18
Purchased power		(24.9	)		(25.0	)		-
Transmission of electricity by others		(5.7	)		(4.4	)		28
Gross margin (a)	$	376.4		$	373.3			1
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's
Results of Operations.

	Revenues and Costs						%			MWhs Sold				%
Year to Date September 30	2011			2010			Change			2011		2010		Change
Retail revenues	(millions)									(thousands)
Residential	$	481.3		$	464.4			4			4,517		4,573		(1	)
Commercial		488.1			472.2			3			5,802		5,875		(1	)
Industrial		92.1			93.5			(1	)		1,428		1,481		(4	)
Other retail revenues		9.3			8.8			4			65		65		1
Provision for rate refund (excess
Missouri wholesale margin)		-			(3.7	)	NM			NA		NA		NA
Kansas ECA under recovery		26.0			5.5		NM			NA		NA		NA
Total retail		1,096.8			1,040.7			5			11,812		11,994		(2	)
Wholesale revenues		109.5			138.0			(21	)		3,317		4,288		(23	)
Other revenues		14.2			16.0			(11	)	NA		NA		NA
Operating revenues		1,220.5			1,194.7			2			15,129		16,282		(7	)
Fuel		(249.0	)		(213.2	)		17
Purchased power		(66.7	)		(63.2	)		6
Transmission of electricity by others		(14.2	)		(11.3	)		25
Gross margin (a)	$	890.6		$	907.0			(2	)
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's
Results of Operations.

78

KCP&L’s gross margin increased $3.1 million for the three months ended September 30, 2011, compared to the same period in 2010 primarily due to:

·   new retail rates effective December 1, 2010, and May 4, 2011, for KCP&L in Kansas and Missouri, respectively, and

·   an increase in weather-normalized retail demand.

These increases were mostly offset by:

·   unfavorable weather, with a 7% decrease in cooling degree days, and

·   an estimated $16 million impact of coal conservation due to flooding resulting in increased fuel expenses and purchased power expenses and reduced wholesale sales.

KCP&L’s gross margin decreased $16.4 million year to date September 30, 2011, compared to the same period in 2010 primarily due to:

·   unfavorable weather, with an 8% decrease in cooling degree days;

·   a $7.5 million increase in coal transportation costs not recovered in KCP&L’s Missouri retail rates where there is no fuel recovery mechanism, prior to new rates effective May 4, 2011;

·   an estimated $16 million impact of coal conservation due to flooding resulting in increased fuel expenses and purchased power expenses and reduced wholesale sales; and

·   an estimated $11 million impact from an extended refueling outage at Wolf Creek, which resulted in less generation available for wholesale sales, increased fuel expense due to the use of more coal in the fuel mix, which has a higher cost compared to nuclear fuel, and increased purchased power expense due to an increase in MWhs purchased.  Wolf Creek’s latest refueling outage began on March 19, 2011, and included several increases in work scope that extended the outage.  Primary components of the increased work scope were related to inspection and repair of essential service water system piping, testing and replacement of underground high voltage cables, and a repair of a ground on the main generator rotor.  During the last week of June 2011 before the unit returned to full capacity, Wolf Creek had an unplanned outage related to one of two main feed pumps.  Wolf Creek returned to 100% capacity in early July 2011.

These decreases were partially offset by new retail rates effective December 1, 2010, and May 4, 2011, for KCP&L in Kansas and Missouri, respectively.

KCP&L Other Operating Expenses (including operating and maintenance expenses, general taxes and other)

KCP&L’s other operating expenses increased $18.5 million for the three months ended September 30, 2011, compared to the same period in 2010 primarily due to:

·   a $4.4 million increase in plant operating and maintenance expenses primarily due to Iatan No. 2 expenses being recognized with Kansas and Missouri rates effective December 1, 2010, and May 4, 2011, respectively;

·   a $4.4 million increase in general taxes driven by increased property taxes; and

·   $3.2 million of expenses related to the impact of flooding.

Additionally, KCP&L recognized a $3.0 million loss in 2010 related to a recommended disallowance of Iatan 2 construction costs.

79

KCP&L’s other operating expenses increased $34.9 million year to date September 30, 2011, compared to the same period in 2010 primarily due to:

·   a $7.4 million increase in plant operating and maintenance expenses primarily due to Iatan No. 2 expenses being recognized with Kansas and Missouri rates effective December 1, 2010, and May 4, 2011, respectively;

·   a $9.6 million increase in general taxes driven by increased property taxes;

·   $3.2 million of expenses related to the impact of flooding; and

·   as a result of disallowances in the MPSC rate order, KCP&L recognized losses of $1.5 million for construction costs related to Iatan No. 2 and to the Iatan No. 1 environmental project in 2011.  KCP&L also recognized a $2.4 million loss for other disallowed costs in the MPSC rate order. KCP&L recorded a $3.0 million loss in 2010 related to a recommended disallowance of Iatan 2 construction costs in the Kansas rate case.

KCP&L Voluntary Separation Program

KCP&L recorded expense of $9.2 million year to date September 30, 2011, related to the voluntary separation program reflecting severance and related payroll taxes provided by KCP&L to employees who elected to voluntarily separate from KCP&L.

KCP&L recorded a $7.0 million pension settlement charge during the third quarter of 2011 from the voluntary separation program as a result of accelerated pension distributions.  KCP&L deferred substantially all of the charge as a regulatory asset and expects to recover it over future periods pursuant to regulatory agreements.  The amount of accelerated pension distributions resulting from the voluntary separation program resulted in increased pension funding requirements in 2011 under ERISA.

KCP&L Depreciation and Amortization

KCP&L’s depreciation and amortization costs decreased $21.0 million for the three months ended September 30, 2011, compared to the same period in 2010 due to a $9.4 million decrease attributable to lower depreciation rates for KCP&L effective December 1, 2010, for Kansas and May 4, 2011, for Missouri and an $18.8 million decrease in regulatory amortization for KCP&L in Kansas and Missouri.  The regulatory amortization was in effect during KCP&L’s Comprehensive Energy Plan but concluded following the December 2010 and May 2011 effective dates of new retail rates for KCP&L in Kansas and Missouri, respectively.  These decreases were partially offset by $2.4 million of depreciation for Iatan No. 2, as well as increased depreciation expense for other capital additions.

KCP&L’s depreciation and amortization costs decreased $45.2 million year to date September 30, 2011, compared to the same period in 2010 due to a $25.1 million decrease attributable to lower depreciation rates for KCP&L and a $42.4 million decrease in regulatory amortization for KCP&L in Kansas and Missouri.  These decreases were partially offset by $8.6 million of depreciation for Iatan No. 2, as well as increased depreciation expense for other capital additions.

KCP&L Non-operating Income and Expenses

KCP&L’s non-operating income and expenses decreased $3.8 million and $20.2 million for the three months ended and year to date September 30, 2011, respectively, compared to the same periods in 2010 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010.

80

KCP&L Interest Charges

KCP&L’s interest charges increased $10.7 million for the three months ended September 30, 2011, compared to the same period in 2010 primarily due to a decrease of $5.4 million in the debt component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010 and the deferral to a regulatory asset of construction accounting carrying costs for Iatan No. 1, Iatan No.2 and common facilities in 2010.

KCP&L’s interest charges increased $17.4 million year to date September 30, 2011, compared to the same period in 2010.  A decrease of $19.7 million in the debt component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010 was partially offset by the deferral to regulatory asset of construction accounting carrying costs for Iatan No. 1, Iatan No.2 and common facilities.

KCP&L Income Tax Expense

KCP&L’s income tax expense decreased $1.7 million and $15.7 million for the three months ended and year to date September 30, 2011, respectively, compared to the same periods in 2010 primarily due to decreased pre-tax income.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Great Plains Energy and KCP&L are exposed to market risks associated with commodity price and supply, interest rates and equity prices.  Market risks are handled in accordance with established policies, which may include entering into various derivative transactions.  In the normal course of business, Great Plains Energy and KCP&L also face risks that are either non-financial or non-quantifiable.  Such risks principally include business, legal, regulatory, operational and credit risks and are discussed elsewhere in this document as well as in the 2010 Form 10-K and therefore are not represented here.

Great Plains Energy and KCP&L interim period disclosures about market risk included in quarterly reports on Form 10-Q address material changes, if any, from the most recently filed annual report on Form 10-K.  Therefore, these interim period disclosures should be read in connection with Item 7A. Quantitative and Qualitative Disclosures About Market Risk, included in the 2010 Form 10-K of each of Great Plains Energy and KCP&L, incorporated herein by reference.

MPS Merchant is exposed to credit risk.  Credit risk is measured by the loss that would be recorded if counterparties failed to perform pursuant to the terms of the contractual obligations less the value of any collateral held.  MPS Merchant’s counterparties are not externally rated.  Credit exposure to counterparties at September 30, 2011 was $17.8 million.

ITEM 4. CONTROLS AND PROCEDURES

GREAT PLAINS ENERGY

Disclosure Controls and Procedures

Great Plains Energy carried out an evaluation of its disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)).  This evaluation was conducted under the supervision, and with the participation, of Great Plains Energy’s management, including the chief executive officer and chief financial officer, and Great Plains Energy’s disclosure committee.  Based upon this evaluation, the chief executive officer and chief financial officer of Great Plains Energy have concluded as of the end of the period covered by this report that the disclosure controls and procedures of Great Plains Energy were effective at a reasonable assurance level.

81

Changes in Internal Control Over Financial Reporting

There has been no change in Great Plains Energy’s internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act) that occurred during the quarterly period ended September 30, 2011, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

KCP&L

Disclosure Controls and Procedures

KCP&L carried out an evaluation of its disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act).  This evaluation was conducted under the supervision, and with the participation, of KCP&L’s management, including the chief executive officer and chief financial officer, and KCP&L’s disclosure committee.  Based upon this evaluation, the chief executive officer and chief financial officer of KCP&L have concluded as of the end of the period covered by this report that the disclosure controls and procedures of KCP&L were effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There has been no change in KCP&L’s internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act) that occurred during the quarterly period ended September 30, 2011, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Other Proceedings

The Companies are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses.  For information regarding material lawsuits and proceedings, see Notes 5, 10 and 11 to the consolidated financial statements.  Such information is incorporated herein by reference.

ITEM 1A.  RISK FACTORS

Actual results in future periods for Great Plains Energy and KCP&L could differ materially from historical results and the forward-looking statements contained in this report.  The Companies’ business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control.  Additional risks and uncertainties not presently known or that the Companies’ management currently believes to be immaterial may also adversely affect the Companies.  Factors that might cause or contribute to such differences include, but are not limited to, those discussed in Item 1A. Risk Factors included in the 2010 Form 10-K for each of Great Plains Energy and KCP&L.  There have been no material changes with regard to those risk factors.  This information, as well as the other information included in this report and in the other documents filed with the SEC, should be carefully considered before making an investment in the securities of Great Plains Energy or KCP&L.  Risk factors of KCP&L are also risk factors of Great Plains Energy.

82

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table provides information regarding purchases by Great Plains Energy of its equity securities during the three months ended September 30, 2011.

Issuer Purchases of Equity Securities
									Maximum Number
							Total Number of		(or Approximate
							Shares (or Units)		Dollar Value) of
		Total					Purchased as		Shares (or Units)
		Number of			Average		Part of Publicly		that May Yet Be
		Shares			Price Paid		Announced		Purchased Under
		(or Units)			per Share		Plans or		the Plans or
Month		Purchased			(or Unit)		Programs		Programs
July 1 - 31			-		$	-		-		N/A
August 1 - 31			199	(1)		20.87		-		N/A
September 1 - 30			8,477	(1)		16.69		-		N/A
Total			8,676		$	16.79		-		N/A
(1)	Represents common shares surrendered to the Company following the resignation of a certain officer.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.  (REMOVED AND RESERVED)

ITEM 5.  OTHER INFORMATION

None.

ITEM 6.  EXHIBITS

Exhibit Number		Description of Document	Registrant
4.1	*	Supplemental Indenture No. 3 dated as of September 15, 2011 between Kansas City Power & Light Company and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on September 20, 2011).	Great Plains Energy KCP&L
10.1	*	Amendment dated as of September 9, 2011 to Receivables Sale Agreement dated as of July 1, 2005, among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation (Exhibit 10.1 to Form 8-K filed on September 13, 2011).	Great Plains Energy KCP&L

83

12.1		Computation of Ratio of Earnings to Fixed Charges.	Great Plains Energy
12.2		Computation of Ratio of Earnings to Fixed Charges.	KCP&L
31.1		Rule 13a-14(a)/15d-14(a) Certification of Michael J. Chesser.	Great Plains Energy
31.2		Rule 13a-14(a)/15d-14(a) Certification of James C. Shay.	Great Plains Energy
31.3		Rule 13a-14(a)/15d-14(a) Certification of Michael J. Chesser.	KCP&L
31.4		Rule 13a-14(a)/15d-14(a) Certification of James C. Shay.	KCP&L
32.1	**	Section 1350 Certifications.	Great Plains Energy
32.2	**	Section 1350 Certifications.	KCP&L
101.INS	**	XBRL Instance Document.	Great Plains Energy KCP&L
101.SCH	**	XBRL Taxonomy Extension Schema Document.	Great Plains Energy KCP&L
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase Document.	Great Plains Energy KCP&L
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase Document.	Great Plains Energy KCP&L
101.LAB	**	XBRL Taxonomy Extension Labels Linkbase Document.	Great Plains Energy KCP&L
101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase Document.	Great Plains Energy KCP&L

*Filed with the SEC as an exhibit to prior SEC filings and is incorporated herein by reference and made a part hereof.  The SEC filing and the exhibit number of the document so filed, and incorporated herein by reference, is stated in parenthesis in the description of such exhibit.

** Furnished and shall not be deemed filed for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended (the Exchange Act).  Such document shall not be incorporated by reference into any registration statement or other document pursuant to the Exchange Act or the Securities Act of 1933, as amended, unless otherwise indicated in such registration statement or other document.

Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from Great Plains Energy or KCP&L, as applicable, upon written request.

The registrants agree to furnish to the SEC upon request any instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of total assets of such registrant and its subsidiaries on a consolidated basis.

84

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, Great Plains Energy Incorporated and Kansas City Power & Light Company have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

	GREAT PLAINS ENERGY INCORPORATED
Dated:  November 3, 2011	By:  /s/ Michael J. Chesser
	(Michael J. Chesser)
	(Chief Executive Officer)
Dated:  November 3, 2011	By:  /s/ Lori A. Wright
	(Lori A. Wright)
	(Principal Accounting Officer)

	KANSAS CITY POWER & LIGHT COMPANY
Dated:  November 3, 2011	By:  /s/ Michael J. Chesser
	(Michael J. Chesser)
	(Chief Executive Officer)
Dated:  November 3, 2011	By:  /s/ Lori A. Wright
	(Lori A. Wright)
	(Principal Accounting Officer)

85

EX-12.1

Exhibit 12.1
GREAT PLAINS ENERGY INCORPORATED
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
		Year to Date
		September 30
		2011		2010		2009		2008			2007		2006
		(millions)
Income from continuing operations		$	172.3	$	211.9	$	151.9	$	119.7		$	120.9	$	136.7
Add
Equity investment loss			0.1		1.0		0.4		1.3			2.0		1.9
	Income subtotal		172.4		212.9		152.3		121.0			122.9		138.6
Add
Taxes on income			90.6		99.0		29.5		63.8			44.9		60.3
Kansas City earnings tax			-		0.1		0.4		0.3			0.5		0.5
	Total taxes on income		90.6		99.1		29.9		64.1			45.4		60.8
Interest on value of leased property			4.4		6.2		6.5		3.6			3.9		4.1
Interest on long-term debt			163.9		218.9		203.6		126.2			74.1		62.6
Interest on short-term debt			9.7		9.7		10.3		18.2			26.4		9.2
Other interest expense and amortization (a)			7.7		9.7		4.7		(1.4	)		5.8		3.9
	Total fixed charges		185.7		244.5		225.1		146.6			110.2		79.8
Earnings before taxes on
	income and fixed charges	$	448.7	$	556.5	$	407.3	$	331.7		$	278.5	$	279.2
Ratio of earnings to fixed charges			2.42		2.28		1.81		2.26			2.53		3.50
(a)	On January 1, 2007, Great Plains Energy elected to make an accounting policy change to recognize interest
	related to uncertain tax positions in interest expense.

EX-12.2

Exhibit 12.2
KANSAS CITY POWER & LIGHT COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
		Year to Date
		September 30
		2011		2010		2009		2008		2007		2006
		(millions)
Income from continuing operations		$	122.8	$	163.2	$	128.9	$	125.2	$	156.7	$	149.3
Add
Taxes on income			67.9		81.6		46.9		59.8		59.3		70.3
Kansas City earnings tax			-		0.1		0.2		0.5		0.5		0.5
	Total taxes on income		67.9		81.7		47.1		60.3		59.8		70.8
Interest on value of leased property			4.0		5.7		6.0		3.3		3.9		4.1
Interest on long-term debt			86.3		117.9		110.4		79.3		54.5		55.4
Interest on short-term debt			4.1		3.9		5.3		15.2		20.3		8.0
Other interest expense and amortization (a)			3.2		4.2		0.3		1.4		6.8		3.2
	Total fixed charges		97.6		131.7		122.0		99.2		85.5		70.7
Earnings before taxes on
	income and fixed charges	$	288.3	$	376.6	$	298.0	$	284.7	$	302.0	$	290.8
Ratio of earnings to fixed charges			2.95		2.86		2.44		2.87		3.53		4.11
(a)	On January 1, 2007, Kansas City Power & Light Company elected to make an accounting policy change to
	recognize interest related to uncertain tax positions in interest expense.

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Michael J. Chesser, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Great Plains Energy Incorporated;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 3, 2011	/s/ Michael J. Chesser
		Michael J. Chesser Chairman of the Board and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, James C. Shay, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Great Plains Energy Incorporated;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 3, 2011	/s/ James C. Shay
		James C. Shay Senior Vice President – Finance and Strategic Development and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, Michael J. Chesser, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Kansas City Power & Light Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 3, 2011	/s/ Michael J. Chesser
		Michael J. Chesser Chairman of the Board and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, James C. Shay, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Kansas City Power & Light Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 3, 2011	/s/ James C. Shay
		James C. Shay Senior Vice President – Finance and Strategic Development and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification of CEO and CFO Pursuant to

18 U.S.C. Section 1350,

as Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report on Form 10-Q of Great Plains Energy Incorporated (the "Company") for the quarterly period ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Michael J. Chesser, as Chairman of the Board and Chief Executive Officer of the Company, and James C. Shay, as Senior Vice President - Finance and Strategic Development and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

       (1)       The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

       (2)       The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Michael J. Chesser
Name: Title:	Michael J. Chesser Chairman of the Board and Chief Executive Officer
Date:	November 3, 2011
	/s/ James C. Shay
Name: Title:	James C. Shay Senior Vice President – Finance and Strategic Development and Chief Financial Officer
Date:	November 3, 2011

EX-32.2

Exhibit 32.2

Certification of CEO and CFO Pursuant to

18 U.S.C. Section 1350,

as Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report on Form 10-Q of Kansas City Power & Light Company (the "Company") for the quarterly period ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Michael J. Chesser, as Chairman of the Board and Chief Executive Officer of the Company, and James C. Shay, as Senior Vice President – Finance and Strategic Development and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

       (1)       The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

       (2)       The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Michael J. Chesser
Name: Title:	Michael J. Chesser Chairman of the Board and Chief Executive Officer
Date:	November 3, 2011
	/s/ James C. Shay
Name: Title:	James C. Shay Senior Vice President - Finance and Strategic Development and Chief Financial Officer
Date:	November 3, 2011

XML

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Kansas City Power and Light Company [Member] KCPL Greater Missouri Operations Company [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] KCPL Greater Missouri Operations Company [Member]	Sep. 30, 2011 Kansas City Power and Light Company [Member] Great Plains Energy Incorporated [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Great Plains Energy Incorporated [Member]	Sep. 30, 2011 Kansas City Power and Light Company [Member] MPS Merchant Services, Inc. [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] MPS Merchant Services, Inc. [Member]
Notes to Financial Statements [Abstract]
KCPL employees to manage GMO's business and operate its facilities at cost	$ 25.0	$ 26.3	$ 82.2	$ 73.5
Kansas City Power and Light Company's related party receivables and payables [Line Items]
Receivable from related party					$ 45.7	$ 29.6	$ 14.0	$ 13.3	$ 8.6	$ 0.3

XML

Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) In Millions, except Share data	Sep. 30, 2011	Dec. 31, 2010
Utility Plant, at Original Cost
Nuclear fuel, amortization	$ 124.8	$ 131.1
Common shareholder's equity
Common stock- shares authorized (in shares)	250,000,000	250,000,000
Common stock-shares issued (in shares)	136,340,645	136,113,954
Treasury stock- shares (in shares)	266,889	400,889
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100	$ 100
3.80% - shares issued (in share)	100,000	100,000
4.50% - shares issued (in shares)	100,000	100,000
4.20% - shares issued (in shares)	70,000	70,000
4.35% - shares issued (in shares)	120,000	120,000
KANSAS CITY POWER AND LIGHT CO [Member]
Utility Plant, at Original Cost
Nuclear fuel, amortization	$ 124.8	$ 131.1
Common shareholder's equity
Common stock- shares authorized (in shares)	1,000	1,000
Common stock-shares issued (in shares)	1	1

XML

Consolidated Statements of Income (Unaudited) (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Operating Revenues
Electric revenues	$ 773.7	$ 728.8	$ 1,831.7	$ 1,787.7
Operating Expenses
Fuel	146.5	127.3	365.8	333.2
Purchased power	68.1	68.0	178.4	171.4
Transmission of electricity by others	8.6	8.1	23.1	20.9
Utility operating and maintenance expenses	169.1	147.7	487.7	447.3
Voluntary separation program	0	0	12.7	0
Depreciation and amortization	65.9	85.3	205.9	248.5
General taxes	52.3	43.6	134.6	119.2
Other	0.5	5.0	4.0	6.5
Total	511.0	485.0	1,412.2	1,347.0
Operating income	262.7	243.8	419.5	440.7
Non-operating income	1.4	7.5	5.8	34.8
Non-operating expenses	(1.3)	(3.4)	(6.3)	(7.1)
Interest charges	(60.8)	(45.5)	(156.0)	(138.7)
Income before income tax expense and loss from equity investments	202.0	202.4	263.0	329.7
Income tax expense	(75.4)	(70.4)	(90.6)	(112.1)
Loss from equity investments, net of income taxes	0	0	(0.1)	(0.9)
Income from continuing operations	126.6	132.0	172.3	216.7
Net income	126.6	132.0	172.3	216.7
Less: Net income attributable to noncontrolling interest	(0.1)	0	0	(0.1)
Net income attributable to Great Plains Energy	126.5	132.0	172.3	216.6
Preferred stock dividend requirements	0.4	0.4	1.2	1.2
Earnings available for common shareholders	126.1	131.6	171.1	215.4
Average number of basic common shares outstanding	135.7	135.2	135.6	135.1
Average number of diluted common shares outstanding	138.3	136.9	138.5	136.8
Basic earnings (loss) per common share
Continuing operations	$ 0.93	$ 0.97	$ 1.26	$ 1.59
Basic earnings per common share	$ 0.93	$ 0.97	$ 1.26	$ 1.59
Diluted earnings (loss) per common share
Continuing operations	$ 0.91	$ 0.96	$ 1.24	$ 1.57
Diluted earnings per common share	$ 0.91	$ 0.96	$ 1.24	$ 1.57
Cash dividends per common share	$ 0.2075	$ 0.2075	$ 0.6225	$ 0.6225
KANSAS CITY POWER AND LIGHT CO [Member]
Operating Revenues
Electric revenues	506.3	486.5	1,220.5	1,194.7
Operating Expenses
Fuel	99.3	83.8	249.0	213.2
Purchased power	24.9	25.0	66.7	63.2
Transmission of electricity by others	5.7	4.4	14.2	11.3
Utility operating and maintenance expenses	120.2	102.9	350.7	323.5
Voluntary separation program	0	0	9.2	0
Depreciation and amortization	45.4	66.4	147.0	192.2
General taxes	41.6	37.2	108.9	99.3
Other	0	3.2	1.3	3.2
Total	337.1	322.9	947.0	905.9
Operating income	169.2	163.6	273.5	288.8
Non-operating income	0.8	6.1	1.8	23.3
Non-operating expenses	(1.0)	(2.5)	(3.4)	(4.7)
Interest charges	(30.8)	(20.1)	(81.2)	(63.8)
Income before income tax expense and loss from equity investments	138.2	147.1	190.7	243.6
Income tax expense	(52.8)	(54.5)	(67.9)	(83.6)
Net income	$ 85.4	$ 92.6	$ 122.8	$ 160.0

XML

TAXES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Current income taxes [Abstract]
Federal	$ (10.2)	$ (7.2)	$ (6.4)	$ (8.1)
State	(0.8)	(2.0)	(4.8)	0.3
Foreign	0	(0.2)	(0.4)	0.2
Total	(11.0)	(9.4)	(11.6)	(7.6)
Deferred income taxes [Abstract]
Federal	74.7	73.5	103.6	108.2
State	13.0	14.6	20.4	18.8
Total	87.7	88.1	124.0	127.0
Noncurrent income taxes [Abstract]
Federal	0	(6.8)	(18.0)	(1.3)
State	0	(1.0)	(1.9)	(0.3)
Foreign	(0.6)	0.2	(0.4)	0.2
Total	(0.6)	(7.6)	(20.3)	(1.4)
Investment tax credit [Abstract]
Deferral	0	0	0	(4.1)
Amortization	(0.7)	(0.7)	(1.5)	(1.8)
Total	(0.7)	(0.7)	(1.5)	(5.9)
Total income tax expense (benefit)	75.4	70.4	90.6	112.1
Income tax expense (benefit) on continuing operations	75.4	70.4	90.6	112.1
Income tax expense (benefit), reconciliation [Abstract]
Federal statutory income tax	70.6	70.8	92.0	115.0
Differences between book and tax depreciation not normalized	1.8	(0.9)	3.7	(6.0)
Amortization of investment tax credits	(0.7)	(0.7)	(1.5)	(1.8)
Federal income tax credits	(2.9)	(2.0)	(9.7)	(6.1)
State income taxes	8.1	7.5	11.1	12.0
Medicare Part D Subsidy Legislation			0	2.8
Changes in uncertain tax positions, net	(2.7)	0.3	(4.0)	0.3
Valuation allowance	0	(2.9)	(2.2)	(2.9)
Other	1.2	(1.7)	1.2	(1.2)
Total	75.4	70.4	90.6	112.1
Income tax rate, reconciliation [Abstract]
Federal statutory income tax (in hundredths)	35.00%	35.00%	35.00%	35.00%
Differences between book and tax depreciation not normalized (in hundredths)	0.90%	(0.40%)	1.40%	(1.80%)
Amortization of investment tax credits (in hundredths)	(0.30%)	(0.40%)	(0.60%)	(0.50%)
Federal income tax credits (in hundredths)	(1.40%)	(0.90%)	(3.70%)	(1.80%)
State income taxes (in hundredths)	4.00%	3.70%	4.20%	3.70%
Medicare Part D Subsidy Legislation (in hundredths)			0.00%	0.80%
Changes in uncertain tax positions, net (in hundredths)	(1.30%)	0.20%	(1.50%)	0.10%
Valuation allowance (in hundredths)	0.00%	(1.40%)	(0.80%)	(0.90%)
Other (in hundredths)	0.40%	(1.00%)	0.50%	(0.50%)
Total (in hundredths)	37.30%	34.80%	34.50%	34.10%
Income Tax Contingency [Line Items]
Amount of unrecognized tax benefit liabilities expected to impact the effect tax rate, if recognized.	12.4		12.4		17.3
Deferred income tax liability impact of audit settlements			16.4
Net income impact of audit settlements			2.0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning balance			42.0	51.4	51.4
Additions for current year tax positions			1.1		2.7
Additions for prior year tax positions			2.5		2.1
Reductions for prior year tax positons			(20.8)		(10.6)
Settlements			0		(3.8)
Statute Expirations			0		(0.3)
Foreign currency translation adjustments			(0.4)		0.5
Ending balance	24.4		24.4		42.0
Accrued interest related to unrecognized tax benefits	5.9		5.9		6.7
Accrued penalities for unrecognized tax benefits	1.1		1.1		1.1
Kansas City Power and Light Company [Member]
Current income taxes [Abstract]
Federal	(10.2)	(15.3)	(7.8)	22.5
State	(0.9)	(2.6)	(0.4)	4.6
Total	(11.1)	(17.9)	(8.2)	27.1
Deferred income taxes [Abstract]
Federal	53.5	63.9	73.4	53.9
State	9.3	11.7	13.8	9.5
Total	62.8	75.6	87.2	63.5
Noncurrent income taxes [Abstract]
Federal	1.5	(2.4)	(9.1)	(1.5)
State	0.1	(0.3)	(1.0)	(0.1)
Total	1.6	(2.7)	(10.1)	(1.6)
Investment tax credit [Abstract]
Deferral	0	0	0	(4.1)
Amortization	(0.5)	(0.5)	(1.0)	(1.2)
Total	(0.5)	(0.5)	(1.0)	(5.3)
Total income tax expense (benefit)	52.8	54.5	67.9	83.6
Income tax expense (benefit) on continuing operations	52.8	54.5	67.9	83.6
Income tax expense (benefit), reconciliation [Abstract]
Federal statutory income tax	48.3	51.5	66.7	85.3
Differences between book and tax depreciation not normalized	1.7	(1.1)	3.3	(5.2)
Amortization of investment tax credits	(0.5)	(0.5)	(1.0)	(1.2)
Federal income tax credits	(2.9)	(1.9)	(9.6)	(6.0)
State income taxes	5.7	5.7	7.7	8.8
Medicare Part D Subsidy Legislation			0	2.8
Changes in uncertain tax positions, net	0	0.1	0.4	0.1
Other	0.5	0.7	0.4	(1.0)
Total	52.8	54.5	67.9	83.6
Income tax rate, reconciliation [Abstract]
Federal statutory income tax (in hundredths)	35.00%	35.00%	35.00%	35.00%
Differences between book and tax depreciation not normalized (in hundredths)	1.20%	(0.80%)	1.70%	(2.20%)
Amortization of investment tax credits (in hundredths)	(0.40%)	(0.40%)	(0.50%)	(0.50%)
Federal income tax credits (in hundredths)	(2.10%)	(1.30%)	(5.10%)	(2.50%)
State income taxes (in hundredths)	4.10%	3.90%	4.00%	3.60%
Medicare Part D Subsidy Legislation (in hundredths)			0.00%	1.20%
Changes in uncertain tax positions, net (in hundredths)	0.00%	0.10%	0.20%	0.10%
Other (in hundredths)	0.40%	0.60%	0.30%	(0.40%)
Total (in hundredths)	38.20%	37.10%	35.60%	34.30%
Income Tax Contingency [Line Items]
Amount of unrecognized tax benefit liabilities expected to impact the effect tax rate, if recognized.	0.3		0.3		0.3
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning balance			19.1	20.9	20.9
Additions for current year tax positions			0		1.3
Additions for prior year tax positions			2.3		1.5
Reductions for prior year tax positons			(12.4)		(1.6)
Settlements			0		(2.9)
Statute Expirations			0		(0.1)
Ending balance	9.0		9.0		19.1
Accrued interest related to unrecognized tax benefits	$ 0.3		$ 0.3		$ 1.4

XML

SEGMENTS AND RELATED INFORMATION

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Segments and Related Information

16.   SEGMENTS AND RELATED INFORMATION

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, 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						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	773.7		$	-		$	773.7
Depreciation and amortization		(65.9	)		-			(65.9	)
Interest charges		(50.2	)		(10.6	)		(60.8	)
Income tax (expense) benefit		(82.9	)		7.5			(75.4	)
Net income (loss) attributable to Great Plains Energy		133.9			(7.4	)		126.5
Year to Date	Electric						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	1,831.7		$	-		$	1,831.7
Depreciation and amortization		(205.9	)		-			(205.9	)
Interest charges		(124.8	)		(31.2	)		(156.0	)
Income tax (expense) benefit		(109.8	)		19.2			(90.6	)
Net income (loss) attributable to Great Plains Energy		189.9			(17.6	)		172.3
Three Months Ended	Electric						Great Plains
September 30, 2010	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						Great Plains
September 30, 2010	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	)
Net income (loss) attributable to Great Plains Energy		232.8			(16.2	)		216.6

	Electric							Great Plains
	Utility		Other		Eliminations			Energy
September 30, 2011	(millions)
Assets	$	9,365.0	$	72.1	$	(432.0	)	$	9,005.1
Capital expenditures (a)		317.8		-		-			317.8
December 31, 2010
Assets	$	9,152.7	$	66.3	$	(400.8	)	$	8,818.2
Capital expenditures (a)		618.1		-		-			618.1
(a) Capital expenditures reflect year to date amounts for the periods presented.

XML

Document And Entity Information (USD $)	9 Months Ended
	Sep. 30, 2011	Oct. 31, 2011	Jun. 30, 2010
Entity Information [Line Items]
Entity Registrant Name	Great Plains Energy Inc
Entity Central Index Key	0001143068
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,307,217,754
Entity Common Stock, Shares Outstanding		136,087,321
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
KANSAS CITY POWER AND LIGHT CO [Member]
Entity Information [Line Items]
Entity Registrant Name	Kansas City Power & Light Co
Entity Central Index Key	0000054476
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		1
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011

XML

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Air and climate change [Abstract]
Current estimate of capital expenditures	$ 1,000,000,000
Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule (CSAPR) [Abstract]
States required to reduce emissions for of SO2 and NOX under the CAIR (in number of states)	28
Mercury and Other Hazardous Air Pollutant Emissions [Abstract]
Capacity of electric steam generating units that fall under MACT standards (in megawatts)	25
Climate Change [Abstract]
CO2 produced per year (in millions of tons)	23
Midwestern states whose governors signed the Midwestern Greenhouse Gas Reduction Accord (in number of states)	6
Initial Midwestern Greenhouse Gas Reduction Accord minimum percentage reduction goal below 2005 levels by 2020 (in hundredths)	15.00%
Initial Midwestern Greenhouse Gas Reduction Accord maximum percentage reduction goal below2005 levels by 2020 (in hundredths)	20.00%
Long-range Midwestern Greenhouse Gas Reduction Accord minimum percentage reduction goal below 2005 levels by 2050 (in hundredths)	60.00%
Long-range Midwestern Greenhouse Gas Reduction Accord maximum percentage reduction goal below 2005 levels by 2050 (in hundredths)	80.00%
Ozone National Ambient Air Quality Standard (NAAQS) [Abstract]
Primary eight-hour ozone standard, as revised March 2008 (in parts per million)	0.075
Secondary eight-hour ozone standard, as revised March 2008 (in parts per million)	0.075
Primary and secondary eight-hour ozone standard, prior to March 2008 (in parts per million)	0.084
Minimum primary eight-hour ozone standard, proposed in January 2010 (in parts per million)	0.060
Maximum primary eight-hour ozone standard, proposed in January 2010 (in parts per million)	0.070
Minimum cumulative, seasonal secondary ozone standard, as proposed in January 2010 (in parts per million)	7
Maximum cumulative, seasonal secondary ozone standard, as proposed in January 2010 (in parts per million)	15
SO2 National Ambient Air Quality Standard (NAAQS) [Abstract]
Primary one-hour sulfur dioxide standard, as revised June 2010 (in parts per million)	0.075
Primary twenty-four hour sulfur dioxide standard, prior to June 2010 (in parts per million)	0.140
Primary one-year sulfur dioxide standard, prior to June 2010 (in parts per million)	0.030
Remediation [Abstract]
Accrued environmental remediation expenses	400,000	400,000
Amount accrued for future investigation remediation and of GMO retained liabilities	2,100,000	2,100,000
The level for excluded PCB products (parts per million)	50
Kansas City Power and Light Company [Member]
Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule (CSAPR) [Abstract]
Sulfur dioxide emissions supported by accumulated unused emission allowances (in tons)	150,000
Climate Change [Abstract]
CO2 produced per year (in millions of tons)	17
Greenhouse gas, on a CO2 equivalent basis, emissions that prompt need for control technology (in tons per year)	75,000
Minimum greenhouse gas emissions by stationary sources to qualify for regulation (in tons per year)	100,000
Minimum additional greenhouse gas emissions by stationary sources after a modification (in tons per year)	75,000
Minimum required renewable energy generation capacity percentage in Kansas by 2011	10.00%
Minimum required renewable energy generation capacity percentage in Kansas by 2016	15.00%
Minimum required renewable energy generation capacity percentage in Kansas by 2020	20.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2011	2.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2014	5.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2018	10.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2021	15.00%
Estimated electricity required to come from solar resources by 2011 (in megawatts)	2
Collaboration Agreement with the Sierra Club and the Concerned Citizens of Platte County [Abstract]
Additional CO2 agreed to be offset (in tons)	711,000
Wind generation capacity installed at Spearville wind site in 2006 (in megawatts)	100
Increased wind generation capacity agreed to pursue in Collaboration Agreement by 2012 - Total (in megawatts)	500
Wind generation capacity being evaluated for acquisition (in megawatts)	200
Wind project completed in 2010 (in megawatts)		48
Renewable energy credits secured (in megawatts)		52
Power purchase agreement (in years)	20
Power purchase agreement (in megawatts)	131
Remediation [Abstract]
Accrued environmental remediation expenses	300,000	300,000
Kansas City Power and Light Company [Member] | LaCygne Station [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	50.00%
Collaboration Agreement with the Sierra Club and the Concerned Citizens of Platte County [Abstract]
Predetermination request for environmental equipment required at LaCygne Station to comply with BART	615,000,000
Westar Energy Inc Member [Member]
New Source Review [Abstract]
Amount of civil penalty settlement payment	3,000,000
Estimated cost to install a selective catalytic reduction system at Jeffrey Energy Center pursuant to a settlement agreement	240,000,000
Westar Energy Inc Member [Member] | Jeffrey Units Nos 1 and 2 [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	92.00%
KCP and L Greater Missouri Operations Company [Member]
Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule (CSAPR) [Abstract]
Sulfur dioxide emissions supported by accumulated unused emission allowances (in tons)	9,000
Climate Change [Abstract]
Minimum required renewable energy generation capacity percentage in Missouri by 2011	2.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2014	5.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2018	10.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2021	15.00%
Estimated electricity required to come from solar resources by 2011 (in megawatts)	2
Remediation [Abstract]
Estimated amount of insurance proceeds available to cover qualified remediation expenses	2,300,000
KCP and L Greater Missouri Operations Company [Member] | Iatan No 1 [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	18.00%
KCP and L Greater Missouri Operations Company [Member] | Jeffrey Units Nos 1 and 2 [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	8.00%
Jeffrey Units Nos 1 and 2 [Member]
New Source Review [Abstract]
Coal fired units at Jeffrey Energy Center, a jointly owned facility (in number of coal fired facilities)	3
LaCygne Station [Member]
Collaboration Agreement with the Sierra Club and the Concerned Citizens of Platte County [Abstract]
Predetermination request for environmental equipment required at LaCygne Station to comply with BART	1,230,000,000
LaCygne Station Environmental Retrofits [Member]
Contractual obligations to construct environmental retrofits [Abstract]
2011	123,300,000
2012	385,700,000
2013	286,600,000
2014	130,100,000
2015	$ 6,300,000

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Reconciliation of Great Plains Energy's basic and diluted earnings per share

	Three Months Ended				Year to Date
	September 30				September 30
	2011		2010		2011		2010
Income	(millions, except per share amounts)
Net income	$	126.6	$	132.0	$	172.3	$	216.7
Less: net income attributable to noncontrolling interest		0.1		-		-		0.1
Less: preferred stock dividend requirements		0.4		0.4		1.2		1.2
Earnings available for common shareholders	$	126.1	$	131.6	$	171.1	$	215.4
Common Shares Outstanding
Average number of common shares outstanding		135.7		135.2		135.6		135.1
Add: effect of dilutive securities		2.6		1.7		2.9		1.7
Diluted average number of common shares outstanding		138.3		136.9		138.5		136.8
Basic EPS	$	0.93	$	0.97	$	1.26	$	1.59
Diluted EPS	$	0.91	$	0.96	$	1.24	$	1.57

XML

LONG-TERM DEBT (Details) (USD $)	9 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Long-term debt [line items]
Current maturities	$ (951,400,000)		$ (485,700,000)
Long-term debt excluding current maturities	2,750,100,000		2,942,700,000
Fair value value of long-term debt, including current maturities	4,100,000,000		3,700,000,000
Kansas City Power and Light Company [Member]
Long-term debt [line items]
Current maturities	(162,700,000)		(150,300,000)
Unamortized discount	(4,300,000)		(2,000,000)
Long-term debt excluding current maturities	1,901,800,000		1,629,700,000
Fair value value of long-term debt, including current maturities	2,300,000,000		1,900,000,000
Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds EIRR due 2012-2035 [Member]
Long-term debt [line items]
Debt Instrument Maturity Date Range Start	2012
Debt Instrument Maturity Date Range End	2035
Principal outstanding	119,300,000	[1]	158,800,000	[1]
Weighted-average interest rate (in hundredths)	4.87%	[2]
Bonds purchased in lieu of redemption	39,500,000
Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds Series 2009 due 2019 [Member]
Long-term debt [line items]
Principal outstanding	400,000,000		400,000,000
Interest rate (in hundredths)	7.15%
Year Due	2019
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	8.59%	[3]
Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds EIRR series 2005 due 2035 [Member]
Long-term debt [line items]
Principal outstanding	50,000,000		50,000,000
Interest rate (in hundredths)	4.65%
Year Due	2035
Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds Series 2007A-1 due 2035 [Member]
Long-term debt [line items]
Principal outstanding	0	[4]	63,300,000
Year Due	2035
Bonds purchased in lieu of redemption	63,300,000
Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds EIRR series 2007A-2 due 2035 [Member]
Long-term debt [line items]
Principal outstanding	0	[4]	10,000,000
Year Due	2035
Bonds purchased in lieu of redemption	10,000,000
Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds EIRR series 2007B due 2035 [Member]
Long-term debt [line items]
Principal outstanding	73,200,000		73,200,000
Interest rate (in hundredths)	5.375%
Year Due	2035
Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior notes due 2011 KCPL [Member]
Long-term debt [line items]
Principal outstanding	150,000,000		150,000,000
Interest rate (in hundredths)	6.50%
Year Due	2011
Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior notes due 2017 KCPL [Member]
Long-term debt [line items]
Principal outstanding	250,000,000		250,000,000
Interest rate (in hundredths)	5.85%
Year Due	2017
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	5.72%	[3]
Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior notes due 2018 KCPL [Member]
Long-term debt [line items]
Principal outstanding	350,000,000		350,000,000
Interest rate (in hundredths)	6.375%
Year Due	2018
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	7.49%	[3]
Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior notes due 2035 KCPL [Member]
Long-term debt [line items]
Principal outstanding	250,000,000		250,000,000
Interest rate (in hundredths)	6.05%
Year Due	2035
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	5.78%	[3]
Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior Notes Due 2041 KCPL [Member]
Long-term debt [line items]
Principal outstanding	400,000,000		0
Interest rate (in hundredths)	5.30%
Year Due	2041
Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | EIRR bonds due 2038 [Member]
Long-term debt [line items]
Principal outstanding	23,400,000		23,400,000
Interest rate (in hundredths)	4.90%
Year Due	2038
Kansas City Power and Light Company [Member] | Other Long-Term Debt [Member] | Other due 2012-2018 [Member]
Long-term debt [line items]
Debt Instrument Maturity Date Range Start	2012
Debt Instrument Maturity Date Range End	2018
Principal outstanding	2,900,000		3,300,000
Other Great Plains Energy [Member]
Long-term debt [line items]
Current maturities	(788,700,000)		(335,400,000)
Unamortized discount	(700,000)		(500,000)
Other Great Plains Energy [Member] | GMO First Mortgage Bonds [Member] | First mortgage bonds due 2012-2021 [Member]
Long-term debt [line items]
Debt Instrument Maturity Date Range Start	2012
Debt Instrument Maturity Date Range End	2021
Principal outstanding	11,200,000		12,400,000
Interest rate (in hundredths)			9.44%
Other Great Plains Energy [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds SJLP due 2013 [Member]
Long-term debt [line items]
Principal outstanding	5,600,000		5,600,000
Interest rate (in hundredths)	5.85%
Year Due	2013
Other Great Plains Energy [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds Wamego Series 1996 due 2026 [Member]
Long-term debt [line items]
Principal outstanding	7,300,000		7,300,000
Year Due	2026
Variable rate (in hundredths)	0.214%	[5]
Other Great Plains Energy [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds state environmental 1993 due 2028 [Member]
Long-term debt [line items]
Principal outstanding	5,000,000		5,000,000
Year Due	2028
Variable rate (in hundredths)	0.263%	[5]
Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Senior notes 7.95 percent series due 2011 [Member]
Long-term debt [line items]
Principal outstanding	0		137,300,000
Interest rate (in hundredths)	7.95%
Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Senior notes 7.75 percent series due 2011 [Member]
Long-term debt [line items]
Principal outstanding	0		197,000,000
Interest rate (in hundredths)	7.75%
Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Senior notes 11.875 percent series due 2012 [Member]
Long-term debt [line items]
Principal outstanding	500,000,000		500,000,000
Interest rate (in hundredths)	11.875%
Year Due	2012
Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Senior notes 8.27 percent series due 2021 [Member]
Long-term debt [line items]
Principal outstanding	80,900,000		80,900,000
Interest rate (in hundredths)	8.27%
Year Due	2021
Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Fair value adjustment [Member]
Long-term debt [line items]
Principal outstanding	24,200,000		49,900,000
Other Great Plains Energy [Member] | Great Plains Energy Senior Notes [Member] | Senior notes due 2013 [Member]
Long-term debt [line items]
Principal outstanding	250,000,000		250,000,000
Interest rate (in hundredths)	2.75%
Year Due	2013
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	3.67%	[3]
Other Great Plains Energy [Member] | Great Plains Energy Senior Notes [Member] | Senior notes due 2017 [Member]
Long-term debt [line items]
Principal outstanding	100,000,000		100,000,000
Interest rate (in hundredths)	6.875%
Year Due	2017
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	7.33%	[3]
Other Great Plains Energy [Member] | Great Plains Energy Senior Notes [Member] | Senior Notes Due2021 Member [Member]
Long-term debt [line items]
Principal outstanding	350,000,000		0
Interest rate (in hundredths)	4.85%
Year Due	2021
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	7.34%	[3]
Other Great Plains Energy [Member] | GMO Medium Term Notes [Member] | Medium term notes notes 7.16 percent series due 2013 [Member]
Long-term debt [line items]
Principal outstanding	6,000,000		6,000,000
Interest rate (in hundredths)	7.16%
Year Due	2013
Other Great Plains Energy [Member] | GMO Medium Term Notes [Member] | Medium term notes notes 7.33 percent series due 2023 [Member]
Long-term debt [line items]
Principal outstanding	3,000,000		3,000,000
Interest rate (in hundredths)	7.33%
Year Due	2023
Other Great Plains Energy [Member] | GMO Medium Term Notes [Member] | Medium term notes notes 7.17 percent series due 2023 [Member]
Long-term debt [line items]
Principal outstanding	7,000,000		7,000,000
Interest rate (in hundredths)	7.17%
Year Due	2023
Other Great Plains Energy [Member] | Great Plains Energy Equity Units Subordinated Notes [Member] | Equity Units subordinated notes due 2042 [Member]
Long-term debt [line items]
Principal outstanding	$ 287,500,000		$ 287,500,000
Interest rate (in hundredths)	10.00%
Year Due	2012

[1] September 30, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by KCP&L

[2] Weighted-average interest rates at September 30, 2011

[3] Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments

[4] September 30, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L

[5] Variable rate

XML

REGULATORY MATTERS

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Regulatory matters

5.   REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

In November 2010, KCC issued an order, effective December 1, 2010, for KCP&L, authorizing an increase in annual revenues of $21.8 million, a return on equity of 10.0%, an equity ratio of approximately 49.7% and a Kansas jurisdictional rate base of $1.781 billion.  The annual revenue increase was subsequently adjusted by KCC in a January 2011 reconsideration order to $22.0 million.  In February 2011, KCC issued an order granting KCP&L and another party to the case their respective petitions for reconsideration regarding rate case expenses and therefore, approximately $1.4 million of the annual revenue increase is considered as interim subject to refund or true-up pending the outcome of the reconsideration proceedings regarding rate case expenses.  A hearing was held in September 2011 with a decision expected in the fourth quarter of 2011.  The rates authorized by KCC are effective unless and until modified by KCC or stayed by a court.

KCP&L Missouri Rate Case Proceedings

On June 4, 2010, KCP&L filed a request with the MPSC to increase its Missouri retail electric annual revenues by $92.1 million.  The request was ultimately adjusted during the rate case proceedings by KCP&L to $66.5 million as the net result of lower fuel and purchased power costs and other updates to the case.  KCP&L’s initial and updated requests reflected, among other things, a proposed annual offset to its revenue requirement for the Missouri jurisdictional portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset); the final update included a proposed wholesale margin offset of approximately $29.4 million.  On April 12, 2011, the MPSC issued its order and on April 14, 2011, the MPSC Staff filed a report which quantified the authorized revenue increase as approximately $34.8 million on an annual basis, which reflects a wholesale margin offset of approximately $45.9 million and authorizes a return on equity of 10.0%, an equity ratio of approximately 46.3% and a Missouri jurisdictional rate base of approximately $2.0 billion.  If the actual Missouri jurisdiction wholesale margin amount exceeds the $45.9 million level reflected in the MPSC order, the difference will be recorded as a regulatory liability and will be returned, with interest, to KCP&L Missouri customers in a future rate case.  The MPSC order provides the opportunity for KCP&L to retain a larger amount of non-firm wholesale electric sales margin than KCP&L proposed; however, there are no assurances that KCP&L will achieve the $45.9 million wholesale margin offset amount and there are no means for KCP&L to recover any shortfall through its retail rates.  The rates established by the MPSC order took effect on May 4, 2011.

As a result of disallowances in the MPSC order, KCP&L recognized losses of $1.5 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project year to date September 30, 2011.  KCP&L also recorded a $2.4 million loss for other disallowed costs in the MPSC order.

In a related order, the MPSC required KCP&L and GMO to apply to the Internal Revenue Service (IRS) to reallocate approximately $26.5 million of Iatan No. 2 qualifying advance coal project tax credits from KCP&L to GMO.  KCP&L and GMO did apply to the IRS but in September 2011, the IRS denied KCP&L’s and GMO’s request.  The MPSC has indicated it will consider the ratemaking treatment of the tax credits in a future rate case.  Certain ratemaking treatments that may be pursued by the MPSC could trigger the loss or repayment to the IRS of a portion of unamortized deferred investment tax credits.  At September 30, 2011, KCP&L and GMO had $128.4 million and $3.5 million, respectively, of unamortized deferred investment tax credits.

GMO Missouri Rate Case Proceedings

On June 4, 2010, GMO filed requests with the MPSC to increase its Missouri retail electric annual revenues by $75.8 million for its Missouri Public Service division, and $22.1 million for its St. Joseph Light & Power (L&P) division.  GMO subsequently adjusted its requests during the rate case proceedings to $65.9 million and $23.2 million, respectively, as the net result of updates to the cases.  On May 4, 2011, the MPSC issued its order and on May 10, 2011, the MPSC Staff filed a report which quantified the authorized revenue increases on an annual basis as $30.1 million for GMO’s Missouri Public Service division and $29.3 million for GMO’s L&P division.  The MPSC order authorized a return on equity of 10.0%, an equity ratio of approximately 46.6% and a Missouri jurisdictional rate base of $1.76 billion.  In response to applications for clarification and rehearing of the MPSC order, the MPSC, on May 27, 2011, issued an order of clarification and modification.  The modified MPSC order revised the authorized annual revenue increase to approximately $35.7 million for GMO’s Missouri Public Service division and approximately $29.8 million for GMO’s L&P division, resulting primarily from a clarification of the amount of fuel costs shifted from GMO’s fuel adjustment clause to base rates.  However, because the MPSC authorized an annual revenue increase that was greater than the amount originally requested by GMO and communicated to GMO’s customers, the modified MPSC order deferred approximately $7.7 million of the L&P division increase, which is the amount over GMO’s requested $22.1 million increase for that division, and will phase in the deferred revenue amount in equal parts over a two-year period, plus carrying costs.

As a result of disallowances in the MPSC order, GMO recognized losses of $0.8 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project year to date September 30, 2011.  GMO also recorded a $1.5 million loss for other disallowed costs in the MPSC order.

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

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

SPP and NERC Inquiries

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

MPSC Regulatory Approval of the GMO Acquisition

Appeals of the MPSC order approving the GMO acquisition were filed with the Cole County, Missouri, Circuit Court, which affirmed the order in June 2009.  That decision was appealed and the Missouri Court of Appeals, Western District, upheld the MPSC order in August 2010.  The case was transferred to the Missouri Supreme Court in December 2010.  On July 19, 2011, the Missouri Supreme Court affirmed the Circuit Court’s ruling that affirmed the MPSC order approving the GMO acquisition.

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, 2011	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	119.0		$	24.9		$	143.9
Loss on reacquired debt		6.5	(a)		0.6	(a)		7.1
Cost of removal		7.0			-			7.0
Asset retirement obligations		30.4			13.6			44.0
Pension and post-retirement costs		373.2	(b)		120.4	(b)		493.6
Deferred customer programs		48.2	(c)		19.5			67.7
Rate case expenses		9.9	(d)		4.5	(d)		14.4
Skill set realignment costs		3.7	(e)		-			3.7
Fuel adjustment clauses		30.1	(d)		42.5	(d)		72.6
Acquisition transition costs		26.2	(f)		21.3	(f)		47.5
St. Joseph Light & Power acquisition		-			2.2	(g)		2.2
Storm damage		-			2.0	(h)		2.0
Derivative instruments		-			3.1	(i)		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		16.5			6.1			22.6
Iatan No. 2 construction accounting costs		27.6			15.5			43.1
Other		2.3	(j)		0.4	(j)		2.7
Total	$	700.6		$	276.6		$	977.2
Regulatory Liabilities
Emission allowances	$	83.0		$	0.3		$	83.3
Asset retirement obligations		40.9			-			40.9
Pension		0.5			39.9			40.4
Cost of removal		-			62.5	(k)		62.5
Other		11.2			19.5			30.7
Total	$	135.6		$	122.2		$	257.8

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

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

(c)   $11.3 million not included in rate base and amortized over various periods.

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

(e)   $2.5 million not included in rate base and amortized through 2017.

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

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

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

(i)   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).

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

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

					Great
December 31, 2010	KCP&L		GMO		Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	117.2	$	25.3	$	142.5
Loss on reacquired debt		5.0		0.7		5.7
Cost of removal		8.5		-		8.5
Asset retirement obligations		27.5		12.8		40.3
Pension and post-retirement costs		386.1		106.7		492.8
Deferred customer programs		44.7		15.6		60.3
Rate case expenses		12.3		3.3		15.6
Skill set realignment costs		4.8		-		4.8
Fuel adjustment clauses		8.4		37.1		45.5
Acquisition transition costs		29.3		22.5		51.8
St. Joseph Light & Power acquisition		-		2.6		2.6
Storm damage		-		3.2		3.2
Derivative instruments		-		3.1		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		15.1		4.3		19.4
Iatan No. 2 construction accounting costs		17.2		6.5		23.7
Other		3.5		0.7		4.2
Total	$	679.6	$	244.4	$	924.0
Regulatory Liabilities
Emission allowances	$	85.9	$	0.5	$	86.4
Asset retirement obligations		44.9		-		44.9
Pension		-		37.1		37.1
Cost of removal		-		62.8		62.8
Other		10.5		16.5		27.0
Total	$	141.3	$	116.9	$	258.2

XML

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Cash Flow, Supplemental Disclosures [Text Block]

Great Plains Energy Other Operating Activities
Year to Date September 30	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(41.2	)	$	(45.9	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		12.9			4.9
Materials and supplies		(4.8	)		(10.0	)
Accounts payable		(71.5	)		(79.1	)
Accrued taxes		52.5			54.6
Accrued interest		(6.1	)		(2.0	)
Deferred refueling outage costs		(23.8	)		8.0
Fuel adjustment clauses		(27.3	)		(2.3	)
Pension and post-retirement benefit obligations		22.0			15.5
Allowance for equity funds used during construction		(0.3	)		(25.5	)
Interest rate hedge settlements		(26.1	)		(6.9	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		2.3			4.0
Uncertain tax positions		(20.2	)		(1.4	)
Other		(22.7	)		(18.1	)
Total other operating activities	$	(154.3	)	$	(199.2	)
Cash paid during the period:
Interest	$	195.1		$	175.4
Income taxes	$	2.4		$	0.4
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	34.8		$	36.4
KCP&L Other Operating Activities
Year to Date September 30	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(39.5	)	$	(0.1	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		2.9			0.1
Materials and supplies		(4.3	)		(7.2	)
Accounts payable		(43.2	)		(87.2	)
Accrued taxes		40.3			(6.3	)
Accrued interest		7.9			10.3
Deferred refueling outage costs		(23.8	)		8.0
Pension and post-retirement benefit obligations		32.1			31.1
Allowance for equity funds used during construction		-			(21.7	)
Kansas Energy Cost Adjustment		(22.0	)		(5.4	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		1.5			3.0
Uncertain tax positions		(10.1	)		(1.6	)
Other		(16.1	)		0.9
Total other operating activities	$	(74.3	)	$	(171.1	)
Cash paid during the period:
Interest	$	74.6		$	60.3
Income taxes	$	0.1		$	71.6
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	30.7		$	31.6

XML

REGULATORY MATTERS (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Regulatory Assets [Line Items]
Non current assets amount	$ 977.2		$ 924.0
Regulatory Liabilities [Line Items]
Non current liabilities	257.8		258.2
Kansas City Power and Light Company [Member] | Rate jurisdiction - Kansas [Member]
Regulatory Proceedings [Line Items]
Return on equity	10.00%
Rate-making equity ratio	49.70%
Effective date	Dec. 01, 2010
Annual revenue increase authorized	21.8
Jurisdictional rate base	1,781
Adjusted annual revenue increased authorized	22.0
Annual revenue increase authorized but considered as interim subject to refund or true-up	1.4
Kansas City Power and Light Company [Member] | Rate jurisdiction - Missouri [Member]
Regulatory Proceedings [Line Items]
File date	Jun. 04, 2010
Annual revenue increase	92.1
Adjusted annual revenue increase	66.5
Return on equity	10.00%
Rate-making equity ratio	46.30%
Effective date	May 04, 2011
Annual revenue increase authorized	34.8
Jurisdictional rate base	2,000
Wholesale margin offset requested	29.4
Wholesale margin offset authorized	45.9
Disallowed construction costs on Iatan Nos 1 and 2	1.5
Other disallowed costs	2.4
Qualifying advance coal project tax credits to be reallocated from KCPL to GMO	26.5
KCPL Greater Missouri Operations Company [Member] | Rate jurisdiction - Missouri [Member]
Regulatory Proceedings [Line Items]
Jurisdictional rate base	1,760
Disallowed construction costs on Iatan Nos 1 and 2	0.8
Other disallowed costs	1.5
KCPL Greater Missouri Operations Company [Member] | Rate jurisdiction - Missouri public service division [Member]
Regulatory Proceedings [Line Items]
File date	Jun. 04, 2010
Annual revenue increase	75.8
Adjusted annual revenue increase	65.9
Return on equity	10.00%
Rate-making equity ratio	46.60%
Effective date	Jun. 25, 2011
Annual revenue increase authorized	30.1
Adjusted annual revenue increased authorized	35.7
Amount of Crossroads disallowed from rate base	50.0
Amount of Crossroads transmission expense disallowed	4.9
Amount of Crossroads accumulated deferred taxes offset against rate base	15.0
Amount of Crossroads requested in rate base	104.0
KCPL Greater Missouri Operations Company [Member] | Rate jurisdiction - St. Joseph Light and Power division [Member]
Regulatory Proceedings [Line Items]
File date	Jun. 04, 2010
Annual revenue increase	22.1
Adjusted annual revenue increase	23.2
Return on equity	10.00%
Rate-making equity ratio	46.60%
Effective date	Jun. 25, 2011
Annual revenue increase authorized	29.3
Adjusted annual revenue increased authorized	29.8
Deferred annual revenue increase	7.7
Kansas City Power and Light Company [Member]
Regulatory Proceedings [Line Items]
Deferred tax credits (note)	128.4
Regulatory Assets [Line Items]
Non current assets amount	700.6		679.6
Regulatory Liabilities [Line Items]
Non current liabilities	135.6		141.3
Kansas City Power and Light Company [Member] | Taxes recoverable through future rates [Member]
Regulatory Assets [Line Items]
Non current assets amount	119.0		117.2
Kansas City Power and Light Company [Member] | Loss on reacquired debt [Member]
Regulatory Assets [Line Items]
Non current assets amount	6.5	[1]	5.0
Kansas City Power and Light Company [Member] | Cost of removal, asset [Member]
Regulatory Assets [Line Items]
Non current assets amount	7.0		8.5
Kansas City Power and Light Company [Member] | Asset retirement obligations [Member]
Regulatory Assets [Line Items]
Non current assets amount	30.4		27.5
Kansas City Power and Light Company [Member] | Pension and post-retirement costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	373.2	[2]	386.1
Kansas City Power and Light Company [Member] | Deferred customer programs [Member]
Regulatory Assets [Line Items]
Non current assets amount	48.2	[3]	44.7
Amount not included in rate base	11.3
Regulatory amortization period	various
Kansas City Power and Light Company [Member] | Rate case expenses [Member]
Regulatory Assets [Line Items]
Non current assets amount	9.9	[4]	12.3
Regulatory amortization period	various
Kansas City Power and Light Company [Member] | Skill set realignment costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	3.7	[5]	4.8
Amount not included in rate base	2.5
Regulatory amortization period	2017
Kansas City Power and Light Company [Member] | Fuel adjustment clauses [Member]
Regulatory Assets [Line Items]
Non current assets amount	30.1	[4]	8.4
Kansas City Power and Light Company [Member] | Acquisition transition costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	26.2	[6]	29.3
Regulatory amortization period	2016
Kansas City Power and Light Company [Member] | St. Joseph Light and Power acquisition [Member]
Regulatory Assets [Line Items]
Non current assets amount	0		0
Kansas City Power and Light Company [Member] | Storm damage [Member]
Regulatory Assets [Line Items]
Non current assets amount	0		0
Kansas City Power and Light Company [Member] | Derivative instruments [Member]
Regulatory Assets [Line Items]
Non current assets amount	0		0
Kansas City Power and Light Company [Member] | Iatan No. 1 and Common facilities depreciation and carrying costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	16.5		15.1
Kansas City Power and Light Company [Member] | Iatan No. 2 construction accounting costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	27.6		17.2
Kansas City Power and Light Company [Member] | Other [Member]
Regulatory Assets [Line Items]
Non current assets amount	2.3	[7]	3.5
Regulatory amortization period	various
Kansas City Power and Light Company [Member] | Emission allowances [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	83.0		85.9
Kansas City Power and Light Company [Member] | Asset retirement obligations [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	40.9		44.9
Kansas City Power and Light Company [Member] | Pension [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	0.5		0
Kansas City Power and Light Company [Member] | Cost of removal, liability [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	0		0
Kansas City Power and Light Company [Member] | Other [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	11.2		10.5
KCPL Greater Missouri Operations Company [Member]
Regulatory Proceedings [Line Items]
Deferred tax credits (note)	3.5
Regulatory Assets [Line Items]
Non current assets amount	276.6		244.4
Regulatory Liabilities [Line Items]
Non current liabilities	122.2		116.9
KCPL Greater Missouri Operations Company [Member] | Taxes recoverable through future rates [Member]
Regulatory Assets [Line Items]
Non current assets amount	24.9		25.3
KCPL Greater Missouri Operations Company [Member] | Loss on reacquired debt [Member]
Regulatory Assets [Line Items]
Non current assets amount	0.6	[1]	0.7
KCPL Greater Missouri Operations Company [Member] | Cost of removal, asset [Member]
Regulatory Assets [Line Items]
Non current assets amount	0		0
KCPL Greater Missouri Operations Company [Member] | Asset retirement obligations [Member]
Regulatory Assets [Line Items]
Non current assets amount	13.6		12.8
KCPL Greater Missouri Operations Company [Member] | Pension and post-retirement costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	120.4	[2]	106.7
KCPL Greater Missouri Operations Company [Member] | Deferred customer programs [Member]
Regulatory Assets [Line Items]
Non current assets amount	19.5		15.6
KCPL Greater Missouri Operations Company [Member] | Rate case expenses [Member]
Regulatory Assets [Line Items]
Non current assets amount	4.5	[4]	3.3
Regulatory amortization period	various
KCPL Greater Missouri Operations Company [Member] | Skill set realignment costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	0		0
KCPL Greater Missouri Operations Company [Member] | Fuel adjustment clauses [Member]
Regulatory Assets [Line Items]
Non current assets amount	42.5	[4]	37.1
KCPL Greater Missouri Operations Company [Member] | Acquisition transition costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	21.3	[6]	22.5
Regulatory amortization period	2016
KCPL Greater Missouri Operations Company [Member] | St. Joseph Light and Power acquisition [Member]
Regulatory Assets [Line Items]
Non current assets amount	2.2	[8]	2.6
Regulatory amortization period	2015
KCPL Greater Missouri Operations Company [Member] | Storm damage [Member]
Regulatory Assets [Line Items]
Non current assets amount	2.0	[9]	3.2
Regulatory amortization period	2012
KCPL Greater Missouri Operations Company [Member] | Derivative instruments [Member]
Regulatory Assets [Line Items]
Non current assets amount	3.1	[10]	3.1
KCPL Greater Missouri Operations Company [Member] | Iatan No. 1 and Common facilities depreciation and carrying costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	6.1		4.3
KCPL Greater Missouri Operations Company [Member] | Iatan No. 2 construction accounting costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	15.5		6.5
KCPL Greater Missouri Operations Company [Member] | Other [Member]
Regulatory Assets [Line Items]
Non current assets amount	0.4	[7]	0.7
Regulatory amortization period	various
KCPL Greater Missouri Operations Company [Member] | Emission allowances [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	0.3		0.5
KCPL Greater Missouri Operations Company [Member] | Asset retirement obligations [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	0		0
KCPL Greater Missouri Operations Company [Member] | Pension [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	39.9		37.1
KCPL Greater Missouri Operations Company [Member] | Cost of removal, liability [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	62.5	[11]	62.8
KCPL Greater Missouri Operations Company [Member] | Other [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	19.5		16.5
Taxes recoverable through future rates [Member]
Regulatory Assets [Line Items]
Non current assets amount	143.9		142.5
Loss on reacquired debt [Member]
Regulatory Assets [Line Items]
Non current assets amount	7.1		5.7
Cost of removal, asset [Member]
Regulatory Assets [Line Items]
Non current assets amount	7.0		8.5
Asset retirement obligations [Member]
Regulatory Assets [Line Items]
Non current assets amount	44.0		40.3
Asset retirement obligations [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	40.9		44.9
Pension and post-retirement costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	493.6		492.8
Deferred customer programs [Member]
Regulatory Assets [Line Items]
Non current assets amount	67.7		60.3
Rate case expenses [Member]
Regulatory Assets [Line Items]
Non current assets amount	14.4		15.6
Skill set realignment costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	3.7		4.8
Fuel adjustment clauses [Member]
Regulatory Assets [Line Items]
Non current assets amount	72.6		45.5
Acquisition transition costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	47.5		51.8
St. Joseph Light and Power acquisition [Member]
Regulatory Assets [Line Items]
Non current assets amount	2.2		2.6
Storm damage [Member]
Regulatory Assets [Line Items]
Non current assets amount	2.0		3.2
Derivative instruments [Member]
Regulatory Assets [Line Items]
Non current assets amount	3.1		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	22.6		19.4
Iatan No. 2 construction accounting costs [Member]
Regulatory Assets [Line Items]
Non current assets amount	43.1		23.7
Other [Member]
Regulatory Assets [Line Items]
Non current assets amount	2.7		4.2
Emission allowances [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	83.3		86.4
Pension [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	40.4		37.1
Cost of removal, liability [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	62.5		62.8
Other [Member]
Regulatory Liabilities [Line Items]
Non current liabilities	$ 30.7		$ 27.0

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

[2] Represents the funded status of the pension plans more than offset by related liabilities. Also includes pension settlements amortized over various periods and financial and regulatory accounting method differences not included in rate base that will be eliminated over the life of the pension plans.

[3] $11.3 million not included in rate base and amortized over various periods.

[4] Not included in rate base and amortized over various periods.

[5] $2.5 million not included in rate base and amortized through 2017.

[6] Not included in rate base and amortized through 2016.

[7] Certain insignificant items are not included in rate base and amortized over various periods.

[8] Not included in rate base and amortized through 2015.

[9] Not included in rate base and amortized through 2012.

[10] 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).

[11] Estimated cumulative net provision for future removal costs.

XML

SEGMENTS AND RELATED INFORMATION (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Summarized Financial Information based on segments

Three Months Ended	Electric						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	773.7		$	-		$	773.7
Depreciation and amortization		(65.9	)		-			(65.9	)
Interest charges		(50.2	)		(10.6	)		(60.8	)
Income tax (expense) benefit		(82.9	)		7.5			(75.4	)
Net income (loss) attributable to Great Plains Energy		133.9			(7.4	)		126.5
Year to Date	Electric						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	1,831.7		$	-		$	1,831.7
Depreciation and amortization		(205.9	)		-			(205.9	)
Interest charges		(124.8	)		(31.2	)		(156.0	)
Income tax (expense) benefit		(109.8	)		19.2			(90.6	)
Net income (loss) attributable to Great Plains Energy		189.9			(17.6	)		172.3
Three Months Ended	Electric						Great Plains
September 30, 2010	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						Great Plains
September 30, 2010	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	)
Net income (loss) attributable to Great Plains Energy		232.8			(16.2	)		216.6

	Electric							Great Plains
	Utility		Other		Eliminations			Energy
September 30, 2011	(millions)
Assets	$	9,365.0	$	72.1	$	(432.0	)	$	9,005.1
Capital expenditures (a)		317.8		-		-			317.8
December 31, 2010
Assets	$	9,152.7	$	66.3	$	(400.8	)	$	8,818.2
Capital expenditures (a)		618.1		-		-			618.1
(a) Capital expenditures reflect year to date amounts for the periods presented.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Organization

Organization

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

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

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

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

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

Basic and Diluted Earnings per Common Share Calculations

Basic and Diluted Earnings per Common Share Calculation

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

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

	Three Months Ended				Year to Date
	September 30				September 30
	2011		2010		2011		2010
Income	(millions, except per share amounts)
Net income	$	126.6	$	132.0	$	172.3	$	216.7
Less: net income attributable to noncontrolling interest		0.1		-		-		0.1
Less: preferred stock dividend requirements		0.4		0.4		1.2		1.2
Earnings available for common shareholders	$	126.1	$	131.6	$	171.1	$	215.4
Common Shares Outstanding
Average number of common shares outstanding		135.7		135.2		135.6		135.1
Add: effect of dilutive securities		2.6		1.7		2.9		1.7
Diluted average number of common shares outstanding		138.3		136.9		138.5		136.8
Basic EPS	$	0.93	$	0.97	$	1.26	$	1.59
Diluted EPS	$	0.91	$	0.96	$	1.24	$	1.57

The computation of diluted EPS for the three months ended September 30, 2011, excludes anti-dilutive shares consisting of 102,032 performance shares, 22,818 restricted stock shares and 80,140 stock options.

The computation of diluted EPS year to date September 30, 2011, excludes anti-dilutive shares consisting of 102,032 performance shares, 45,648 restricted stock shares and 80,140 stock options.

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.

XML

COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Commitments and contingencies

10.   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’s and KCP&L’s results of operations, financial position and cash flows.

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

Air and Climate Change Overview

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

Great Plains Energy’s and KCP&L’s current estimate of capital expenditures (exclusive of AFUDC and property taxes) to comply with the currently-effective Clean Air Interstate Rule (CAIR), the replacement to CAIR or the Cross-State Air Pollution Rule (CSAPR), the best available retrofit technology (BART) rule, the SO2 national ambient air quality standard (NAAQS), the industrial boiler rule and proposed maximum achievable control technology (MACT) standards for mercury and other hazardous air pollutant emissions (all of which are discussed below) is approximately $1 billion.  The actual cost of compliance with any existing, proposed or future rules may be significantly different from the cost estimate provided.

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

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

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

·   KCP&L’s Montrose No. 3 full AQCS installed by approximately 2016; and

·   GMO’s Sibley No. 3 scrubber and baghouse installed by approximately 2016.

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

The estimate does not reflect the non-capital costs the Companies incur on an ongoing basis to comply with environmental laws, which may increase in the future due to the Companies’ ongoing compliance with current or future environmental laws.  The Companies expect to seek recovery of the costs associated with environmental requirements through rate increases; however, there can be no assurance that such rate increases would be granted.  The Companies may be subject to materially adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies’ environmental reputation.

Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule (CSAPR)

The CAIR requires reductions in SO2 and NOx emissions in 28 states, including Missouri.  The reductions in SO2 and NOx emissions are accomplished through statewide caps for NOx and SO2.  Great Plains Energy’s and KCP&L’s fossil fuel-fired plants located in Missouri are subject to CAIR, while their fossil fuel-fired plants in Kansas are not.

On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety and remanded the matter to the EPA to promulgate a new rule consistent with its opinion.  On December 23, 2008, the Court issued an order remanding CAIR to the EPA to revise the rule consistent with its July 2008 order.  The CAIR remains in effect through 2011.

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, 2011, KCP&L had accumulated unused SO2 emission allowances sufficient to support over 150,000 tons of SO2 emissions (enough to support expected requirements under the CAIR and the Acid Rain Program for the foreseeable future) under the provisions of the Acid Rain program, which are recorded in inventory at zero cost.  At September 30, 2011, GMO had accumulated unused SO2 emission allowances sufficient to support just over 9,000 tons of SO2 emissions (enough to support expected requirements under the CAIR and Acid Rain Program through 2011), which it has received under the Acid Rain Program or purchased, and are recorded in inventory at average cost.  KCP&L and GMO purchase NOx allowances as needed.

In July 2011, the EPA finalized the CSAPR to replace the currently-effective CAIR.  The CSAPR, 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 CSAPR is broader than CAIR, and includes Kansas in addition to Missouri and other states.  Kansas and Missouri are only included for fine particulate matter control in the final CSAPR, but the EPA concurrently proposed a supplemental notice of proposed rulemaking to include both states for ozone season control which the EPA intends to finalize in November 2011.  The CSAPR would also impose more stringent emissions limitations than CAIR and, unlike CAIR, would not utilize Acid Rain Program allowances for compliance.  In the CSAPR, the EPA set an emissions budget for each of the affected states.  The CSAPR allows limited interstate emissions allowance trading among power plants; however, it does not permit trading of SO2 allowances between the Companies’ Kansas and Missouri power plants.  Compliance with the CSAPR begins in 2012.  There would be additional reductions in SO2 allowances allocable to the Companies’ Missouri power plants taking effect in 2014.  There is no such 2014 additional reduction in SO2 allowances allocable to the Companies’ Kansas power plants.  In October 2011, the EPA proposed technical adjustments to the final CSAPR.  The proposed rule amends the assurance penalty provisions to start in 2014, instead of 2012.  The EPA proposed to revise certain unit-level allocations in six states, including Kansas, affected by federally enforceable consent agreements.  This would allocate additional allowances to KCP&L’s LaCygne Station to assist in compliance with CSAPR.

The finalized CSAPR is complex and Great Plains Energy and KCP&L are evaluating its impacts.  The Companies project that they may not be allocated sufficient SO2 or NOX emissions allowances to cover their currently expected operations starting in 2012.  Any shortfall in allocated allowances is anticipated to be addressed through a combination of permissible allowance trading, installing additional emission control equipment, changes in plant processes, or purchasing additional power in the wholesale market.  Multiple states, utilities and other parties, including KCP&L, have filed reconsideration requests and stays with the EPA and/or the D.C. Circuit Court.

Best Available Retrofit Technology (BART) Rule

The EPA BART rule directs state air quality agencies to identify whether visibility-reducing emissions from sources subject to BART are below limits set by the state or whether retrofit measures are needed to reduce emissions.  BART applies to specific eligible facilities including KCP&L’s LaCygne Nos. 1 and 2 in Kansas, KCP&L’s Iatan No. 1, in which GMO has an 18% interest, KCP&L’s Montrose No. 3 in Missouri, GMO’s Sibley Unit No. 3 and Lake Road Unit No. 6 in Missouri and Westar Energy, Inc.’s (Westar) Jeffrey Unit Nos. 1 and 2 in Kansas, in which GMO has an 8% interest.  Both Missouri and Kansas have submitted BART plans to the EPA but neither Missouri nor Kansas has received EPA approval for their BART plans.  In August 2011, the EPA proposed to approve the Kansas BART plan.

Mercury and Other Hazardous Air Pollutant Emissions

In January 2009, the EPA issued a memorandum stating that new electric steam generating units (EGUs) that began construction while the Clean Air Mercury Rule (CAMR) was effective are subject to a new source 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.  In May 2011, KCP&L received a letter from the Missouri Department of Natural Resources (MDNR) stating the MACT determination was not required for Hawthorn No. 5.  It is not currently known how MACT determinations and schedules of compliance will impact the permitting or operating requirements for Iatan No. 2, but it is possible a MACT determination may ultimately require additional emission control equipment and permit limits.

In 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 and is expected to issue final standards by December 2011.  In March 2011, the EPA issued a proposed rule that would reduce emissions of hazardous air pollutants from new and existing coal-fired EGUs with a capacity of 25MW or greater.  The proposed rule would establish numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrogen chloride (a surrogate for acid gases).  The proposed rule would establish work practices, instead of numerical emission limits, for organic hazardous air pollutants, including dioxin/furan.  Compliance with the rule would need to be addressed by installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market or a combination of these and other alternatives.  Any final rule could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Industrial Boiler Rule

In February 2011, the EPA issued a final rule that would reduce emissions of hazardous air pollutants from new and existing industrial boilers.  The final rule establishes numeric emission limits for mercury, dioxin, particulate matter (as a surrogate for non-mercury metals), hydrogen chloride (as a surrogate for acid gases), and carbon monoxide (as a surrogate for non-dioxin organic hazardous air pollutants).  The final rule establishes emission limits for KCP&L’s and GMO’s new and existing units that produce steam other than for the generation of electricity.  The final rule does not apply to KCP&L’s and GMO’s electricity generating boilers, but would apply to most of GMO’s Lake Road boilers, which also serve steam customers, and to auxiliary boilers at other generating facilities.  In May 2011, the EPA announced it would stay the effective date of the final rule during reconsideration.  The EPA indicated it will propose a revised rule in November 2011 and issue another final rule by the end of April 2012.

New Source Review

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

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

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

Collaboration Agreement

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

In 2006, KCP&L installed 100MW of wind generation at its Spearville wind site.  KCP&L agreed in the Collaboration Agreement to pursue increasing its wind generation capacity to 500MW in total by the end of 2012 with 100MW to be added by the end of 2010 and the remainder added by the end of 2012, subject to regulatory approval.  In 2010, KCP&L completed a 48MW wind project adjacent to its existing Spearville wind site with wind turbines it already owned and also secured 52MW of renewable energy credits.  During 2011, KCP&L entered into a 20-year power purchase agreement for approximately 131MW of wind generation beginning in 2012.  The Companies are evaluating options to add up to 200MW of new wind capacity through a combination of ownership and power purchase agreements.

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

In a related proceeding, in January 2011, KCC opened a general investigation docket regarding KCP&L and Westar environmental retrofits upon the recommendation of the KCC Staff and the Citizens Utility Ratepayers Board.  The Companies cannot predict the outcome or timing of this matter but the outcome could have the potential to impact the Companies’ resource planning in the future.

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, are subject to certain greenhouse gas permitting requirements starting in 2011.  Management believes it is possible that additional federal or relevant state or local laws or regulations could be enacted to address global climate change.  At the international level, while the United States is not a current party to the Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions.  International agreements legally binding on the United States may be reached in the future.  Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels.  The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 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 clean or renewable energy standards are also possible.  While management believes additional requirements addressing these matters will probably be enacted, the timing, provisions and impact of such requirements, including the cost to obtain and install new equipment to achieve compliance, cannot be reasonably estimated at this time.  In addition, certain federal courts have held that state and local governments and private parties have standing to bring climate change tort suits seeking company-specific emission reductions and monetary or other damages.  While the Companies are not a party to any climate change tort suit, there is no assurance that such suits may not be filed in the future or as to the outcome if such suits are filed.  Such requirements or litigation outcomes could have the potential for a significant financial and operational impact on Great Plains Energy and KCP&L.  The Companies would likely seek recovery of capital costs and expenses for compliance through rate increases; however, there can be no assurance that such rate increases would be granted.

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

In May 2010, the EPA issued a final rule addressing greenhouse gas emissions from stationary sources under the Clean Air Act permitting programs.  This final rule sets thresholds for greenhouse gas emissions that define when permits under the Prevention of Significant Deterioration (PSD) and Title V Operating Permit programs are required for new and existing industrial facilities.  The EPA phased in the Clean Air Act permitting requirements for greenhouse gas emissions in two initial steps.  In step 1, which started January 2, 2011, only sources currently subject to the PSD permitting program (i.e., those that are newly-constructed or modified in a way that significantly increases emissions of a pollutant other than greenhouse gas) are subject to Title V or PSD permitting requirements, respectively, for their greenhouse gas emissions.  For these projects, only projects with new or increases of greenhouse gas emissions of 75,000 tons per year or more of total greenhouse gases, on a CO2 equivalent basis, need to determine the best available control technology for their greenhouse gas emissions.  In addition, sources subject to the Title V Operating Permit Program need to address greenhouse gas emissions as those permits are applied for or renewed.  In step 2, which started July 1, 2011, Title V and PSD permitting requirements now 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 are 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 are subject to this rule.

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

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

KCP&L and GMO project that their existing renewable resources (including accumulated renewable energy credits) will be sufficient for compliance with the Missouri requirements, exclusive of the solar requirement, through 2021 and 2016, respectively.  KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri solar requirements for the foreseeable future.

KCP&L also projects that its existing renewable resources (including both accumulated renewable energy credits and purchased renewable energy credits) will be sufficient for compliance with the 2011 Kansas requirements.  During 2011, KCP&L entered into a 20-year power purchase agreement for approximately 131MW of wind generation beginning in 2012.  With the addition of this power purchase agreement along with its existing renewable resources, KCP&L anticipates its renewable resources will be sufficient

for compliance with the Kansas requirements through 2012.  The Companies are evaluating options to add up to 200MW of new wind capacity through a combination of ownership and power purchase agreements.

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 and/or regulations are issued.  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 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 CSAPR and BART.  The EPA has various options over and above the implementation of the maintenance plans for control of ozone to address the violation but has not yet acted.  At this time, management is unable to predict how the EPA will respond or how that response will impact Great Plains Energy’s and KCP&L’s operations.  However, the EPA’s response could have a significant effect on Great Plains Energy's and KCP&L's results of operations, financial position and cash flows.

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

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

In January 2010, the EPA proposed to reconsider and further strengthen the 2008 NAAQS for ground-level ozone.  The EPA proposed to strengthen the primary eight-hour ozone standard to a level within the range of 0.060-0.070 ppm.  The EPA also proposed to establish a distinct cumulative, seasonal secondary standard, designed to protect sensitive vegetation and ecosystems, to within the range of 7-15 ppm-hours.  In September 2011, President Obama requested that the EPA withdraw the proposed rule reconsidering the 2008 NAAQS and the EPA announced it will proceed with implementation of the 2008 primary eight-hour ozone standard of 0.075 ppm.  The EPA indicated, based on the available ozone air quality data, that the Kansas City area would meet the standard.

SO2 NAAQS

In June 2010, the EPA strengthened the primary NAAQS for SO2.  The EPA revised the primary SO2 standard by establishing a new 1-hour standard at a level of 0.075 ppm.  The EPA revoked the two existing primary standards of 0.140 ppm evaluated over 24 hours and 0.030 ppm evaluated over an entire year.  In July 2011, the MDNR recommended to the EPA that part of Jackson County, Missouri, which is in the Companies' service territory, be designated a nonattainment area for the new 1-hour SO2 standard.  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 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.

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 not have a significant impact on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Water

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

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

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

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

Solid Waste

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

Remediation

Certain federal and state laws, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) hold current and previous owners or operators of real property, and any person who arranges for the disposal or treatment of hazardous substances at a property, liable on a joint and several basis for the costs of cleaning up contamination at or migrating from such real property, even if they did not know of and were not responsible for such contamination.  CERCLA and other laws also authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment.  GMO is named as a potentially responsible party at two disposal sites for polychlorinated 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, 2011, and December 31, 2010, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site.  At September 30, 2011, and December 31, 2010, Great Plains Energy had $0.4 million accrued for environmental remediation expenses, which includes the $0.3 million at KCP&L, and additional potential remediation and ground water monitoring costs relating to two GMO sites.  The amounts accrued were established on an undiscounted basis and Great Plains Energy and KCP&L do not currently have an estimated time frame over which the accrued amounts may be paid.

In addition to the $0.4 million accrual above, at September 30, 2011, and December 31, 2010, Great Plains Energy had $2.1 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB sites and retained liabilities.  This estimate was based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary.  This estimate could change materially after further investigation, and could also be affected by the actions of environmental agencies and the financial viability of other potentially responsible parties.

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

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

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

Contractual Commitments

At September 30, 2011, Great Plains Energy’s and KCP&L’s contractual commitments for KCP&L’s environmental retrofits at its LaCygne station are $123.3 million, $385.7 million, $286.6 million, $130.1 million and $6.3 million for the years 2011 though 2015, respectively.  KCP&L owns 50% of the LaCygne station. KCP&L expects to be reimbursed by the other owner for its 50% share of the costs.  Great Plains Energy’s and KCP&L’s other contractual commitments have not significantly changed at September 30, 2011, compared to December 31, 2010.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Significant Accounting Policies

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

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

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

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

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

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

Basic and Diluted Earnings per Common Share Calculation

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

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

	Three Months Ended				Year to Date
	September 30				September 30
	2011		2010		2011		2010
Income	(millions, except per share amounts)
Net income	$	126.6	$	132.0	$	172.3	$	216.7
Less: net income attributable to noncontrolling interest		0.1		-		-		0.1
Less: preferred stock dividend requirements		0.4		0.4		1.2		1.2
Earnings available for common shareholders	$	126.1	$	131.6	$	171.1	$	215.4
Common Shares Outstanding
Average number of common shares outstanding		135.7		135.2		135.6		135.1
Add: effect of dilutive securities		2.6		1.7		2.9		1.7
Diluted average number of common shares outstanding		138.3		136.9		138.5		136.8
Basic EPS	$	0.93	$	0.97	$	1.26	$	1.59
Diluted EPS	$	0.91	$	0.96	$	1.24	$	1.57

The computation of diluted EPS for the three months ended September 30, 2011, excludes anti-dilutive shares consisting of 102,032 performance shares, 22,818 restricted stock shares and 80,140 stock options.

The computation of diluted EPS year to date September 30, 2011, excludes anti-dilutive shares consisting of 102,032 performance shares, 45,648 restricted stock shares and 80,140 stock options.

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.

Dividends Declared

In November 2011, Great Plains Energy’s Board of Directors (Board) declared a quarterly dividend of $0.2125 per share on Great Plains Energy’s common stock.  The common dividend is payable December 20, 2011, to shareholders of record as of November 29, 2011.  The Board also declared regular dividends on Great Plains Energy’s preferred stock, payable March 1, 2012, to shareholders of record as of February 7, 2012.

In November 2011, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $25 million payable on December 19, 2011.

XML

DERIVATIVE INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Values of open positions for derivative instruments

	September 30					December 31
	2011					2010
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	2.6	$	(0.2	)	$	4.0	$	-
Non-hedging derivatives		20.2		(2.0	)		59.5		(2.5	)
Forward contracts
Non-hedging derivatives		135.4		9.3			202.8		8.9
Option contracts
Non-hedging derivatives		0.4		-			0.2		-
Anticipated debt issuance				-
Forward starting swaps		-		-			350.0		(20.8	)
KCP&L
Futures contracts
Cash flow hedges		2.6		(0.2	)		4.0		-

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

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.3		2.0
Total Derivatives		$	9.3	$	2.2
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9
KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

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

Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
Three Months Ended September 30, 2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(5.1	)
Commodity contracts		(0.1	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		2.1
Total	$	-		Total	$	(3.1	)
Year to Date September 30, 2011
Interest rate contracts	$	(5.3	)	Interest charges	$	(11.9	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		2.2		Income tax benefit (expense)		4.7
Total	$	(3.3	)	Total	$	(7.3	)
Three Months Ended September 30, 2010
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	)

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, 2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(2.1	)
Commodity contracts		(0.1	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		0.9
Total	$	-		Total	$	(1.3	)
Year to Date September 30, 2011
Interest rate contracts	$	-		Interest charges	$	(6.5	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		2.6
Total	$	(0.1	)	Total	$	(4.0	)
Three Months Ended September 30, 2010
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	)

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, 2011	(millions)				(millions)
Commodity contracts	$	(2.2	)	Fuel	$	(0.6	)
Total	$	(2.2	)	Total	$	(0.6	)
Year to Date September 30, 2011
Commodity contracts	$	(3.5	)	Fuel	$	(3.5	)
Total	$	(3.5	)	Total	$	(3.5	)
Three Months Ended September 30, 2010
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	)

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

Great Plains Energy
Derivatives in Regulatory Account Relationship
				Gain (Loss) Reclassified from
				Regulatory Account
	Amount of Gain (Loss)
	Recognized on Regulatory
	Account on Derivatives			Income Statement
	(Effective Portion)			Classification	Amount
Three Months Ended September 30, 2011	(millions)				(millions)
Commodity contracts	$	(2.2	)	Fuel	$	(0.6	)
Total	$	(2.2	)	Total	$	(0.6	)
Year to Date September 30, 2011
Commodity contracts	$	(3.5	)	Fuel	$	(3.5	)
Total	$	(3.5	)	Total	$	(3.5	)
Three Months Ended September 30, 2010
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	)

Accumulated other comprehensive income related to cash flow hedges

	Great Plains Energy						KCP&L
	September 30			December 31			September 30			December 31
	2011			2010			2011			2010
	(millions)
Current assets	$	11.5		$	12.0		$	11.5		$	12.0
Current liabilities		(94.5	)		(101.5	)		(64.7	)		(71.6	)
Deferred income taxes		32.3			34.8			20.7			23.2
Total	$	(50.7	)	$	(54.7	)	$	(32.5	)	$	(36.4	)

XML

EQUITY COMPENSATION

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Equity Compensation

7.   EQUITY COMPENSATION

Great Plains Energy’s Long-Term Incentive Plan is an equity compensation plan approved by Great Plains Energy’s shareholders.  The Long-Term Incentive Plan permits the grant of restricted stock, 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
	2011		2010		2011		2010
Great Plains Energy	(millions)
Compensation expense	$	1.2	$	0.8	$	4.5	$	3.4
Income tax benefits		0.4		0.2		1.8		0.8
KCP&L
Compensation expense		0.8		0.6		3.1		2.4
Income tax benefits		0.2		0.2		1.2		0.4

Performance Shares

Performance share activity year to date September 30, 2011, is summarized in the following table.

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

At September 30, 2011, the remaining weighted-average contractual term was 1.2 years.  The weighted-average grant-date fair value of shares granted was $26.30 and $26.15 for the three months ended and year to date September 30, 2011, respectively.  There were no shares granted for the three months ended September 30, 2010.  The weighted-average grant-date fair value of shares granted year to date September 30, 2010, was $23.37.  At September 30, 2011, there was $4.0 million of total unrecognized compensation expense, net of forfeiture rates, related to performance shares granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term.  The total fair value of performance shares earned and paid year to date September 30, 2011 and 2010, was $0.8 million and insignificant, respectively.

The fair value of performance share awards is estimated using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of expected volatilities, dividend yield and risk-free rates.  Expected volatility is based on daily stock price change during a historical period commensurate with the remaining term of the performance period of the grant.  The risk-free rate is based upon the rate at the time of the evaluation for zero-coupon government bonds with a maturity consistent with the remaining performance period of the grant.  The dividend yield is based on the most recent dividends paid and the actual closing stock price on the valuation date.  For shares granted in 2011, inputs for expected volatility, dividend yield and risk-free rates ranged from 28%-30%, 3.98%-4.35%, and 0.61%-1.15%, respectively.

Restricted Stock

Restricted stock activity year to date September 30, 2011, is summarized in the following table.

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

At September 30, 2011, the remaining weighted-average contractual term was 1.6 years.  The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2011, was $17.89 and $19.03, respectively.  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.  At September 30, 2011, 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.  There were no shares vested for the three months ended September 30, 2011.  The total fair value of shares vested year to date September 30, 2011, was $2.6 million.  The 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.

XML

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Related party transactions and relationships

12.   RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO’s business and operate its facilities at cost.  These costs totaled $25.0 million and $82.2 million, respectively, for the three months ended and year to date September 30, 2011, respectively.  These costs totaled $26.3 million and $73.5 million, respectively, for the same periods in 2010.  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
	2011		2010
	(millions)
Net receivable from GMO	$	45.7	$	29.6
Net receivable from Great Plains Energy		14.0		13.3
Receivable from MPS Merchant		8.6		0.3

XML

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

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Short-term debt

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

Great Plains Energy’s $200 Million Revolving Credit Facility

Great Plains Energy’s $200 million revolving credit facility with a group of banks expires in August 2013.  The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time.  A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At September 30, 2011, Great Plains Energy was in compliance with this covenant.  At September 30, 2011, Great Plains Energy had $28.0 million of outstanding cash borrowings with a weighted-average interest rate of 3.00% and had issued letters of credit totaling $11.6 million under the credit facility.  At December 31, 2010, Great Plains Energy had $9.5 million of outstanding cash borrowings with a weighted-average interest rate of 3.06% and had issued letters of credit totaling $15.8 million under the credit facility.

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

KCP&L’s $600 million revolving credit facility with a group of banks to provide support for its issuance of commercial paper and other general corporate purposes expires in August 2013.  Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities.  A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At September 30, 2011, KCP&L was in compliance with this covenant.  At September 30, 2011, KCP&L had $10.5 million of commercial paper outstanding, at a weighted-average interest rate of 0.35%, $31.5 million of letters of credit outstanding and no outstanding cash borrowings under the facility.  At December 31, 2010, KCP&L had $263.5 million of commercial paper outstanding, at a weighted-average interest rate of 0.41%, $24.4 million of letters of credit outstanding and no outstanding cash borrowings under the facility.

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

GMO’s $450 million revolving credit facility with a group of banks expires in August 2013.  Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities.  A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At September 30, 2011, GMO was in compliance with this covenant.  At September 30, 2011, and December 31, 2010, GMO had $13.2 million of letters of credit outstanding and no outstanding cash borrowings under the facility.  In October 2011, GMO established a $450 million commercial paper program, which is unconditionally guaranteed by Great Plains Energy.  At November 3, 2011, there was no outstanding commercial paper under the program.

XML

EQUITY COMPENSATION (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Equity compensation expense and associated income tax benefits

	Three Months Ended				Year to Date
	September 30				September 30
	2011		2010		2011		2010
Great Plains Energy	(millions)
Compensation expense	$	1.2	$	0.8	$	4.5	$	3.4
Income tax benefits		0.4		0.2		1.8		0.8
KCP&L
Compensation expense		0.8		0.6		3.1		2.4
Income tax benefits		0.2		0.2		1.2		0.4

Performance share activity

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

Restricted stock activity

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

XML

PENSION PLANS AND OTHER EMPLOYEE BENEFITS

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Pension Plans, Other Employee Benefits and Voluntary Separation Program

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

Great Plains Energy maintains defined benefit pension plans for substantially all active and inactive employees, including officers, and also provides certain post-retirement health care and life insurance benefits for substantially all retired employees of KCP&L, GMO, and Wolf Creek Nuclear Operating Corporation (WCNOC).

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.  The current rate orders allow similar regulatory treatment for post-retirement benefits.  The differences between the financial and regulatory accounting methods are due to timing and will be eliminated over the life of the pension and post-retirement plans.

The following tables provide Great Plains Energy’s components of net periodic benefit costs prior to the effects of capitalization and sharing with joint-owners of power plants.

	Pension Benefits						Other Benefits
Three Months Ended September 30	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	7.8		$	7.6		$	0.7		$	1.0
Interest cost		12.4			12.3			2.0			2.2
Expected return on plan assets		(9.5	)		(9.2	)		(0.4	)		(0.5	)
Prior service cost		1.1			1.1			1.8			1.8
Recognized net actuarial loss (gain)		9.7			9.4			(0.1	)		(0.1	)
Transition obligation		-			-			0.3			0.3
Settlement charge		10.0			-			-			-
Net periodic benefit costs before
regulatory adjustment		31.5			21.2			4.3			4.7
Regulatory adjustment		(12.8	)		(8.1	)		0.4			-
Net periodic benefit costs	$	18.7		$	13.1		$	4.7		$	4.7
	Pension Benefits						Other Benefits
Year to Date September 30	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	23.4		$	22.8		$	2.3		$	2.8
Interest cost		37.5			36.9			5.9			6.6
Expected return on plan assets		(28.8	)		(27.5	)		(1.3	)		(1.6	)
Prior service cost		3.4			3.5			5.4			5.4
Recognized net actuarial loss (gain)		28.9			28.1			(0.4	)		(0.1	)
Transition obligation		-			-			1.0			1.0
Settlement charge		10.2			-			-			-
Net periodic benefit costs before
regulatory adjustment		74.6			63.8			12.9			14.1
Regulatory adjustment		(25.1	)		(24.6	)		0.7			-
Net periodic benefit costs	$	49.5		$	39.2		$	13.6		$	14.1

Year to date September 30, 2011, Great Plains Energy contributed $42.0 million to the pension plans and expects to contribute an additional $80.2 million in 2011 to satisfy the funding requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA), and the MPSC and KCC rate orders, the majority of which is expected to be paid by KCP&L.  Also in 2011, Great Plains Energy expects to contribute $17.1 million to the post-retirement benefit plans, of which the majority will be funded by KCP&L.

Voluntary Separation Program

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

Great Plains Energy recorded a $10.0 million pension settlement charge during the third quarter of 2011 from the voluntary separation program as a result of accelerated pension distributions.  The Companies deferred substantially all of the charge as a regulatory asset and expect to recover it over future periods pursuant to regulatory agreements.  The amount of accelerated pension distributions resulting from the voluntary separation program resulted in increased pension funding requirements in 2011 under ERISA.

XML

FAIR VALUE MEASUREMENTS (Details) (USD $) In Millions	9 Months Ended																							9 Months Ended																					3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Kansas City Power and Light Company [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Sep. 30, 2011 Kansas City Power and Light Company [Member] Fair Value, Netting [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Fair Value, Netting [Member]		Sep. 30, 2011 Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 1 [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 1 [Member]		Sep. 30, 2011 Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 2 [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 2 [Member]		Sep. 30, 2011 Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 3 [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 3 [Member]		Sep. 30, 2010 Kansas City Power and Light Company [Member] State and local obligations [Member]	Sep. 30, 2011 Other Great Plains Energy [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Dec. 31, 2010 Other Great Plains Energy [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Sep. 30, 2011 Other Great Plains Energy [Member] Fair Value, Netting [Member]		Dec. 31, 2010 Other Great Plains Energy [Member] Fair Value, Netting [Member]		Sep. 30, 2011 Other Great Plains Energy [Member] Fair Value, Inputs, Level 1 [Member]		Dec. 31, 2010 Other Great Plains Energy [Member] Fair Value, Inputs, Level 1 [Member]		Sep. 30, 2011 Other Great Plains Energy [Member] Fair Value, Inputs, Level 2 [Member]		Dec. 31, 2010 Other Great Plains Energy [Member] Fair Value, Inputs, Level 2 [Member]		Sep. 30, 2011 Other Great Plains Energy [Member] Fair Value, Inputs, Level 3 [Member]		Dec. 31, 2010 Other Great Plains Energy [Member] Fair Value, Inputs, Level 3 [Member]		Sep. 30, 2011 Other Great Plains Energy [Member] Derivative Instruments [Member]	Sep. 30, 2010 Other Great Plains Energy [Member] Derivative Instruments [Member]	Sep. 30, 2011 Other Great Plains Energy [Member] Derivative Instruments [Member]	Sep. 30, 2010 Other Great Plains Energy [Member] Derivative Instruments [Member]	Sep. 30, 2011 Estimate of Fair Value, Fair Value Disclosure [Member]		Dec. 31, 2010 Estimate of Fair Value, Fair Value Disclosure [Member]		Sep. 30, 2011 Fair Value, Netting [Member]		Dec. 31, 2010 Fair Value, Netting [Member]		Sep. 30, 2011 Fair Value, Inputs, Level 1 [Member]		Dec. 31, 2010 Fair Value, Inputs, Level 1 [Member]		Sep. 30, 2011 Fair Value, Inputs, Level 2 [Member]		Dec. 31, 2010 Fair Value, Inputs, Level 2 [Member]		Sep. 30, 2011 Fair Value, Inputs, Level 3 [Member]		Dec. 31, 2010 Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Derivative instruments, assets				$ 0	[1]	$ 0	[1]	$ 0	[1],[2]	$ (0.1)	[1],[2]	$ 0	[1]	$ 0.1	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]		$ 9.3	[1]	$ 8.9	[1]	$ 0	[1],[2]	$ (0.5)	[1],[2]	$ 0	[1]	$ 0.5	[1]	$ 4.8	[1]	$ 5.2	[1]	$ 4.5	[1]	$ 3.7	[1]					$ 9.3	[1]	$ 8.9	[1]	$ 0	[1],[2]	$ (0.6)	[1],[2]	$ 0	[1]	$ 0.6	[1]	$ 4.8	[1]	$ 5.2	[1]	$ 4.5	[1]	$ 3.7	[1]
Nuclear decommissioning trust [Abstract]
Equity securities related to nuclear decommissioning trust				75.2	[3]	85.5	[3]	0	[2],[3]	0	[2],[3]	75.2	[3]	85.5	[3]	0	[3]	0	[3]	0	[3]	0	[3]
Debt securities related to nuclear decommissioning trust [Abstract]
U.S. Treasury				14.7	[3]	8.9	[3]	0	[2],[3]	0	[2],[3]	14.7	[3]	8.9	[3]	0	[3]	0	[3]	0	[3]	0	[3]
U.S. Agency				3.6	[3]	4.8	[3]	0	[2],[3]	0	[2],[3]	0	[3]	0	[3]	3.6	[3]	4.8	[3]	0	[3]	0	[3]
State and local obligations				2.6	[3]	2.5	[3]	0	[2],[3]	0	[2],[3]	0	[3]	0	[3]	2.6	[3]	2.5	[3]	0	[3]	0	[3]
Corporate bonds				25.3	[3]	23.7	[3]	0	[2],[3]	0	[2],[3]	0	[3]	0	[3]	25.3	[3]	23.7	[3]	0	[3]	0	[3]
Foreign governments				0.7	[3]	0.7	[3]	0	[2],[3]	0	[2],[3]	0	[3]	0	[3]	0.7	[3]	0.7	[3]	0	[3]	0	[3]
Other				0.3	[3]	0.4	[3]	0	[2],[3]	0	[2],[3]	0	[3]	0	[3]	0.3	[3]	0.4	[3]	0	[3]	0	[3]
Total nuclear decommissioning trust				122.4	[3]	126.5	[3]	0	[2],[3]	0	[2],[3]	89.9	[3]	94.4	[3]	32.5	[3]	32.1	[3]	0	[3]	0	[3]																										122.4	[3]	126.5	[3]	0	[2],[3]	0	[2],[3]	89.9	[3]	94.4	[3]	32.5	[3]	32.1	[3]	0	[3]	0	[3]
SERP rabbi trust [Abstract]
Equity securities related to SERP rabbi trust																									0.2	[4]	0.2	[4]	0	[2],[4]	0	[2],[4]	0.2	[4]	0.2	[4]	0	[4]	0	[4]	0	[4]	0	[4]
Debt securities related to SERP rabbi trust																									0.2	[4]	7.0	[4]	0	[2],[4]	0	[2],[4]	0	[4]	0	[4]	0.2	[4]	7.0	[4]	0	[4]	0	[4]
Total SERP rabbi trust																									0.4	[4]	7.2	[4]	0	[2],[4]	0	[2],[4]	0.2	[4]	0.2	[4]	0.2	[4]	7.0	[4]	0	[4]	0	[4]					0.4	[4]	7.2	[4]	0	[2],[4]	0	[2],[4]	0.2	[4]	0.2	[4]	0.2	[4]	7.0	[4]	0	[4]	0	[4]
Total assets				122.4		126.5		0	[2]	(0.1)	[2]	89.9		94.5		32.5		32.1		0		0			9.7		16.1		0	[2]	(0.5)	[2]	0.2		0.7		5.0		12.2		4.5		3.7						132.1		142.6		0	[2]	(0.6)	[2]	90.1		95.2		37.5		44.3		4.5		3.7
Liabilities [Abstract]
Derivative instruments, liabilities				0	[1]	0	[1]	(0.2)	[1],[2]	(0.1)	[1],[2]	0.2	[1]	0.1	[1]	0	[1]	0	[1]	0	[1]	0	[1]		0	[1]	20.8	[1]	(2.0)	[1],[2]	(3.0)	[1],[2]	2.0	[1]	3.0	[1]	0	[1]	20.8	[1]	0	[1]	0	[1]					0	[1]	20.8	[1]	(2.2)	[1],[2]	(3.1)	[1],[2]	2.2	[1]	3.1	[1]	0	[1]	20.8	[1]	0	[1]	0	[1]
Total liabilities				0		0		(0.2)	[2]	(0.1)	[2]	0.2		0.1		0		0		0		0			0		20.8		(2.0)	[2]	(3.0)	[2]	2.0		3.0		0		20.8		0		0						0		20.8		(2.2)	[2]	(3.1)	[2]	2.2		3.1		0		20.8		0		0
Cash and cash equivalents from nuclear decommissioning trust excluded from fair value disclosure		3.1	2.7
Cash and cash equivalents from SERP rabbi trust excluded from fair value disclosure		20.4	14.6
Cash collateral posted with third parties as part of netting agreements		2.2	2.5
Fair value measurement using significant unobservable input (level 3) reconciliation [Roll Forward]
Beginning balance	4.3																							0.2																					4.9	5.2	3.7	4.1
Total realized/unrealized gains or (losses) [Abstract]
Included in non-operating income	(9.5)																							0																					4.0	(3.6)	11.1	(9.5)
Purchase, issuances, and settlements	8.9																							(0.2)																					(4.4)	2.1	(10.3)	9.1
Ending balance	3.7																							0																					4.5	3.7	4.5	3.7
Total unrealized gains and (losses) included in non-operating income relating to assets and liabilities still on the consolidated balance sheet	$ 0																							$ 0																					$ (0.3)	$ (1.3)	$ 1.2	$ 0

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

[2] 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, 2011, and December 31, 2010, Great Plains Energy netted $2.2 million and $2.5 million, respectively, of cash collateral posted with counterparties.

[3] Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $3.1 million and $2.7 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

[4] Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include $20.4 million and $14.6 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

XML

Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest (Unaudited) (USD $) In Millions, except Share data	Total	KANSAS CITY POWER AND LIGHT CO [Member]	Common Stock [Member]	Common Stock [Member] KANSAS CITY POWER AND LIGHT CO [Member]	Retained Earnings [Member]	Retained Earnings [Member] KANSAS CITY POWER AND LIGHT CO [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Other Comprehensive Income (Loss) [Member] KANSAS CITY POWER AND LIGHT CO [Member]	Total Common Shareholders' Equity [Member]	Total Common Shareholders' Equity [Member] KANSAS CITY POWER AND LIGHT CO [Member]	Noncontrolling Interest [Member]
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
Net income attributable to Great Plains Energy	216.6				216.6	160.0
Issuance of common stock			5.1
Issuance of common stock (in shares)			269,855
Issuance of restricted common stock			2.3
Issuance of restricted common stock (in shares)			130,137
Equity compensation expense, net of forfeitures	3.4	2.4	1.1
Unearned Compensation
Issuance of restricted common stock, unearned compensation			(2.3)
Forfeiture of restricted common stock			0.6
Compensation expense recognized			1.9
Other			0.1
Loss on reissuance of treasury stock					0
Dividends:
Common stock					(84.4)	(70.0)
Preferred stock - at required rates					(1.2)
Performance shares					(0.2)
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)
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)	2,914.1	2,025.4	1.2
Beginning balance at Jun. 30, 2010
Net income attributable to Great Plains Energy	132.0
Equity compensation expense, net of forfeitures	0.8	0.6
Dividends:
Derivative hedging activity, net of tax	(4.3)	1.4
Change in unrecognized pension expense, net of tax	0
Ending balance (in shares) at Sep. 30, 2010				1
Ending balance at Sep. 30, 2010				1,563.1						2,914.1	2,025.4
Beginning balance (in shares) at Dec. 31, 2010			136,113,954	1			(400,889)
Beginning balance at Dec. 31, 2010			2,324.4	1,563.1	626.5	478.3	(8.9)	(56.1)	(36.4)			1.2
Net income attributable to Great Plains Energy	172.3				172.3	122.8
Issuance of common stock			4.5
Issuance of common stock (in shares)			226,691
Issuance of restricted common stock			0
Issuance of restricted common stock (in shares)			0
Equity compensation expense, net of forfeitures	4.5	3.1	0.2
Unearned Compensation
Issuance of restricted common stock, unearned compensation			(3.5)
Forfeiture of restricted common stock			0.9
Compensation expense recognized			1.7
Other			0.3
Loss on reissuance of treasury stock					(0.7)
Dividends:
Common stock					(84.7)	(75.0)
Preferred stock - at required rates					(1.2)
Performance shares					(0.3)
Treasury shares acquired							(2.3)
Treasury shares acquired (in shares)							(125,024)
Treasury shares reissued							5.6
Treasury shares reissued (in shares)							259,024
Derivative hedging activity, net of tax	4.0	3.9						4.0	3.9
Change in unrecognized pension expense, net of tax	0.1							0.1
Net income attributable to noncontrolling interest												0
Distribution												0
Ending balance (in shares) at Sep. 30, 2011			136,340,645	1			(266,889)
Ending balance at Sep. 30, 2011			2,328.5	1,563.1	711.9	526.1	(5.6)	(52.0)	(32.5)	2,982.8	2,056.7	1.2
Beginning balance at Jun. 30, 2011
Net income attributable to Great Plains Energy	126.5
Equity compensation expense, net of forfeitures	1.2	0.8
Dividends:
Derivative hedging activity, net of tax	3.1	1.3
Change in unrecognized pension expense, net of tax	0
Ending balance (in shares) at Sep. 30, 2011				1
Ending balance at Sep. 30, 2011				$ 1,563.1						$ 2,982.8	$ 2,056.7

XML

SUPPLEMENTAL CASH FLOW INFORMATION

9 Months Ended

Sep. 30, 2011

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	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(41.2	)	$	(45.9	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		12.9			4.9
Materials and supplies		(4.8	)		(10.0	)
Accounts payable		(71.5	)		(79.1	)
Accrued taxes		52.5			54.6
Accrued interest		(6.1	)		(2.0	)
Deferred refueling outage costs		(23.8	)		8.0
Fuel adjustment clauses		(27.3	)		(2.3	)
Pension and post-retirement benefit obligations		22.0			15.5
Allowance for equity funds used during construction		(0.3	)		(25.5	)
Interest rate hedge settlements		(26.1	)		(6.9	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		2.3			4.0
Uncertain tax positions		(20.2	)		(1.4	)
Other		(22.7	)		(18.1	)
Total other operating activities	$	(154.3	)	$	(199.2	)
Cash paid during the period:
Interest	$	195.1		$	175.4
Income taxes	$	2.4		$	0.4
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	34.8		$	36.4
KCP&L Other Operating Activities
Year to Date September 30	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(39.5	)	$	(0.1	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		2.9			0.1
Materials and supplies		(4.3	)		(7.2	)
Accounts payable		(43.2	)		(87.2	)
Accrued taxes		40.3			(6.3	)
Accrued interest		7.9			10.3
Deferred refueling outage costs		(23.8	)		8.0
Pension and post-retirement benefit obligations		32.1			31.1
Allowance for equity funds used during construction		-			(21.7	)
Kansas Energy Cost Adjustment		(22.0	)		(5.4	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		1.5			3.0
Uncertain tax positions		(10.1	)		(1.6	)
Other		(16.1	)		0.9
Total other operating activities	$	(74.3	)	$	(171.1	)
Cash paid during the period:
Interest	$	74.6		$	60.3
Income taxes	$	0.1		$	71.6
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	30.7		$	31.6

Significant Non-Cash Items

On January 1, 2010, Great Plains Energy and KCP&L adopted new accounting guidance for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivable pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s and KCP&L’s balance sheets.  As a result, cash flows from operating activities were reduced by $95.0 million and cash flows from financing activities were raised by $95.0 million with no impact to the net change in cash year to date September 30, 2010.

XML

SUPPLEMENTAL CASH FLOW INFORMATION (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Cash flows affected by changes in: [Abstract]
Receivables	$ (41.2)	$ (45.9)
Accounts receivable pledged as collateral	0	(95.0)
Fuel inventories	12.9	4.9
Materials and supplies	(4.8)	(10.0)
Accounts payable	(71.5)	(79.1)
Accrued taxes	52.5	54.6
Accrued interest	(6.1)	(2.0)
Deferred refueling outage costs	(23.8)	8.0
Fuel adjustment clauses	(27.3)	(2.3)
Pension and post-retirement benefit obligation	22.0	15.5
Allowance for equity funds used during construction	(0.3)	(25.5)
Forward starting swaps settlement	(26.1)	(6.9)
Iatan Nos. 1 and 2 impact of disallowed construction costs	2.3	4.0
Uncertain tax positions (cash flow)	(20.2)	(1.4)
Other	(22.7)	(18.1)
Total other operating activities	(154.3)	(199.2)
Cash paid during the period [Abstract]
Interest	195.1	175.4
Income taxes	2.4	0.4
Noncash investing activities [Abstract]
Liabilities assumed for capital expenditures	34.8	36.4
Transfers of financial assets [Abstract]
Accounts receivable pledged as collateral	95.0		95.0
Collateralized note payable	95.0		95.0
Increase (decrease) in operating activities due to change in accounts receivable pledged as collateral	0	(95.0)
Increase (decrease) in financing activities due to change in collateralized short-term debt	0	95.0
Kansas City Power and Light Company [Member]
Cash flows affected by changes in: [Abstract]
Receivables	(39.5)	(0.1)
Accounts receivable pledged as collateral	0	(95.0)
Fuel inventories	2.9	0.1
Materials and supplies	(4.3)	(7.2)
Accounts payable	(43.2)	(87.2)
Accrued taxes	40.3	(6.3)
Accrued interest	7.9	10.3
Deferred refueling outage costs	(23.8)	8.0
Pension and post-retirement benefit obligation	32.1	31.1
Allowance for equity funds used during construction	0	(21.7)
Kansas Energy Cost Adjustment	(22.0)	(5.4)
Iatan Nos. 1 and 2 impact of disallowed construction costs	1.5	3.0
Uncertain tax positions (cash flow)	(10.1)	(1.6)
Other	(16.1)	0.9
Total other operating activities	(74.3)	(171.1)
Cash paid during the period [Abstract]
Interest	74.6	60.3
Income taxes	0.1	71.6
Noncash investing activities [Abstract]
Liabilities assumed for capital expenditures	30.7	31.6
Transfers of financial assets [Abstract]
Accounts receivable pledged as collateral	95.0		95.0
Collateralized note payable	95.0		95.0
Increase (decrease) in operating activities due to change in accounts receivable pledged as collateral	0	(95.0)
Increase (decrease) in financing activities due to change in collateralized short-term debt	$ 0	$ 95.0

XML

PENSION PLANS AND OTHER EMPLOYEE BENEFITS (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Components of Net Periodic Benefit Costs

	Pension Benefits						Other Benefits
Three Months Ended September 30	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	7.8		$	7.6		$	0.7		$	1.0
Interest cost		12.4			12.3			2.0			2.2
Expected return on plan assets		(9.5	)		(9.2	)		(0.4	)		(0.5	)
Prior service cost		1.1			1.1			1.8			1.8
Recognized net actuarial loss (gain)		9.7			9.4			(0.1	)		(0.1	)
Transition obligation		-			-			0.3			0.3
Settlement charge		10.0			-			-			-
Net periodic benefit costs before
regulatory adjustment		31.5			21.2			4.3			4.7
Regulatory adjustment		(12.8	)		(8.1	)		0.4			-
Net periodic benefit costs	$	18.7		$	13.1		$	4.7		$	4.7
	Pension Benefits						Other Benefits
Year to Date September 30	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	23.4		$	22.8		$	2.3		$	2.8
Interest cost		37.5			36.9			5.9			6.6
Expected return on plan assets		(28.8	)		(27.5	)		(1.3	)		(1.6	)
Prior service cost		3.4			3.5			5.4			5.4
Recognized net actuarial loss (gain)		28.9			28.1			(0.4	)		(0.1	)
Transition obligation		-			-			1.0			1.0
Settlement charge		10.2			-			-			-
Net periodic benefit costs before
regulatory adjustment		74.6			63.8			12.9			14.1
Regulatory adjustment		(25.1	)		(24.6	)		0.7			-
Net periodic benefit costs	$	49.5		$	39.2		$	13.6		$	14.1

XML

DERIVATIVE INSTRUMENTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended	12 Months Ended			3 Months Ended		9 Months Ended				9 Months Ended								3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended				3 Months Ended		9 Months Ended													9 Months Ended								3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended				3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2011 Kansas City Power & Light Company [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Futures contracts [Member] Cash flow hedges [Member]	Dec. 31, 2010 Kansas City Power & Light Company [Member] Futures contracts [Member] Cash flow hedges [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Cash flow hedges [Member]	Dec. 31, 2010 Kansas City Power & Light Company [Member] Cash flow hedges [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Cash flow hedges [Member] Assets, current [Member]	Dec. 31, 2010 Kansas City Power & Light Company [Member] Cash flow hedges [Member] Assets, current [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Cash flow hedges [Member] Liabilities, current [Member]	Dec. 31, 2010 Kansas City Power & Light Company [Member] Cash flow hedges [Member] Liabilities, current [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Cash flow hedges [Member] Deferred income taxes [Member]	Dec. 31, 2010 Kansas City Power & Light Company [Member] Cash flow hedges [Member] Deferred income taxes [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Interest Rate Contract [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Interest Rate Contract [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Interest Rate Contract [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Interest Rate Contract [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Interest Rate Contract [Member] Interest charges [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Interest Rate Contract [Member] Interest charges [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Interest Rate Contract [Member] Interest charges [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Interest Rate Contract [Member] Interest charges [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Commodity Contract [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Commodity Contract [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Commodity Contract [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Commodity Contract [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Commodity Contract [Member] Fuel [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Commodity Contract [Member] Fuel [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Commodity Contract [Member] Fuel [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Commodity Contract [Member] Fuel [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Income Tax Benefit Expense [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Income Tax Benefit Expense [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Income Tax Benefit Expense [Member]	Sep. 30, 2010 Kansas City Power & Light Company [Member] Income Tax Benefit Expense [Member]	Sep. 30, 2011 Kansas City Power & Light Company [Member] Commodity Contract [Member] Derivative Instrument, Current and Noncurrent [Member]	Dec. 31, 2010 Kansas City Power & Light Company [Member] Commodity Contract [Member] Derivative Instrument, Current and Noncurrent [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member]	Dec. 31, 2010 Total (Great Plains Energy) [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Futures contracts [Member] Cash flow hedges [Member]	Dec. 31, 2010 Total (Great Plains Energy) [Member] Futures contracts [Member] Cash flow hedges [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Futures contracts [Member] Non-hedging derivatives	Dec. 31, 2010 Total (Great Plains Energy) [Member] Futures contracts [Member] Non-hedging derivatives	Sep. 30, 2011 Total (Great Plains Energy) [Member] Option contracts [Member] Non-hedging derivatives	Dec. 31, 2010 Total (Great Plains Energy) [Member] Option contracts [Member] Non-hedging derivatives	Sep. 30, 2011 Total (Great Plains Energy) [Member] Forward contracts [Member] Non-hedging derivatives	Dec. 31, 2010 Total (Great Plains Energy) [Member] Forward contracts [Member] Non-hedging derivatives	Sep. 30, 2011 Total (Great Plains Energy) [Member] Anticipated debt issuance [Member] Forward Starting Swaps [Member]	Dec. 31, 2010 Total (Great Plains Energy) [Member] Anticipated debt issuance [Member] Forward Starting Swaps [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Cash flow hedges [Member]	Dec. 31, 2010 Total (Great Plains Energy) [Member] Cash flow hedges [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Cash flow hedges [Member] Assets, current [Member]	Dec. 31, 2010 Total (Great Plains Energy) [Member] Cash flow hedges [Member] Assets, current [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Cash flow hedges [Member] Liabilities, current [Member]	Dec. 31, 2010 Total (Great Plains Energy) [Member] Cash flow hedges [Member] Liabilities, current [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Cash flow hedges [Member] Deferred income taxes [Member]	Dec. 31, 2010 Total (Great Plains Energy) [Member] Cash flow hedges [Member] Deferred income taxes [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Interest Rate Contract [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Interest Rate Contract [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Interest Rate Contract [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Interest Rate Contract [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Interest Rate Contract [Member] Interest charges [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Interest Rate Contract [Member] Interest charges [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Interest Rate Contract [Member] Interest charges [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Interest Rate Contract [Member] Interest charges [Member]	Dec. 31, 2010 Total (Great Plains Energy) [Member] Interest Rate Contract [Member] Derivative Instrument, Current and Noncurrent [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Commodity Contract [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Commodity Contract [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Commodity Contract [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Commodity Contract [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Commodity Contract [Member] Fuel [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Commodity Contract [Member] Fuel [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Commodity Contract [Member] Fuel [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Commodity Contract [Member] Fuel [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Income Tax Benefit Expense [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Income Tax Benefit Expense [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Income Tax Benefit Expense [Member]	Sep. 30, 2010 Total (Great Plains Energy) [Member] Income Tax Benefit Expense [Member]	Sep. 30, 2011 Total (Great Plains Energy) [Member] Commodity Contract [Member] Derivative Instrument, Current and Noncurrent [Member]	Dec. 31, 2010 Total (Great Plains Energy) [Member] Commodity Contract [Member] Derivative Instrument, Current and Noncurrent [Member]	Sep. 30, 2011 Commodity contract derivatives not designated as hedging instruments [Member]	Sep. 30, 2010 Commodity contract derivatives not designated as hedging instruments [Member]	Sep. 30, 2011 Commodity contract derivatives not designated as hedging instruments [Member]
Interest rate risk management [Line Items]
Amount of long term debt issued		$ 350.0
Number of Forward Starting Swaps settled with debt issued (in number of forward starting swaps)	6	6
Loss recorded in other comprehensive income on Forward Starting Swaps settled with debt issued		26.1
Reclassification period for loss recorded in other comprehensive income (years)	3	3
Amount of loss reclassified from other comprehensive income to interest expense	2.2	3.3
Commodity risk management [Abstract]
Percentage of projected natural gas usage hedged at KCPL (in hundredths)			91.00%	100.00%
Percentage of expected on-peak natural gas and natural gas equivalent purchased power price exposure that is hedged at GMO			50.00%	70.00%	68.00%
Derivative [Line Items]
Notional Contract Amount										2.6	4.0																																				2.6	4.0	20.2	59.5	0.4	0.2	135.4	202.8	0	350.0
Fair Value										(0.2)	0																																				(0.2)	0	(2.0)	(2.5)	0	0	9.3	8.9	0	(20.8)
Derivative Asset, Fair Value [Abstract]
Derivative Asset Designated as Hedging Instrument, Fair Value																																								0	0.1																																0													0	0.1
Derivative Asset Not Designated as Hedging Instrument, Fair Value																																																																																						9.3	9.4
Derivative Asset, Fair Value, Total																																										9.3		9.3		9.5
Derivative Liability, Fair Value [Abstract]
Derivative Liability Designated as Hedging Instrument, Fair Value																																								0.2	0.1																																20.8													0.2	0.1
Derivative Liability Not Designated as Hedging Instrument, Fair Value																																																																																						2.0	3.0
Derivative Liability, Fair Value, Total																																										2.2		2.2		23.9
Derivative Instruments, Gain (Loss) [Line Items]
Gain(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)						(1.3)	(1.6)	(4.0)	(4.3)															(2.1)	(2.2)	(6.5)	(6.6)					(0.1)	(0.5)	(0.1)	(0.5)	0.9	1.1	2.6	2.8			(3.1)	(2.0)	(7.3)	(4.8)																								(5.1)	(2.6)	(11.9)	(7.2)						(0.1)	(0.5)	(0.1)	(0.5)	2.1	1.1	4.7	2.9
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)						0	(0.2)	(0.1)	(0.6)											0	0	0	0					(0.1)	(0.4)	(0.2)	(1.0)					0.1	0.2	0.1	0.4			0	(6.3)	(3.3)	(19.8)																				0	(9.9)	(5.3)	(31.4)						(0.1)	(0.4)	(0.2)	(1.0)					0.1	4.0	2.2	12.6
Gain(Loss) Reclassified from Regulatory Account into Income (Effective Portion)																																										(0.6)	(1.6)	(3.5)	(5.9)																																	(0.6)	(1.6)	(3.5)	(5.9)
Amount of Gain (Loss) Recognized on Regulatory Account on Derivatives (Effective Portion)																																										(2.2)	(2.8)	(3.5)	(8.7)																													(2.2)	(2.8)	(3.5)	(8.7)
Derivatives included in accumulated other comprehensive income recorded value [Line Items]
Recorded amount included in accumulated other comprehensive income												(32.5)	(36.4)	11.5	12.0	(64.7)	(71.6)	20.7	23.2																																						(50.7)	(54.7)	11.5	12.0	(94.5)	(101.5)	32.3	34.8
Accumulated other comprehensive income that is expected to be reclassified in the next twelve months												8.9																																													20.3
Trading Activity, Gains and Losses, Net [Line Items]
Gains (losses) reflected in the income statement for changes in fair value of commodity contracts not designated as hedging																																																																																								$ (0.6)	$ (1.6)	$ 0.4

XML

RECEIVABLES

9 Months Ended

Sep. 30, 2011

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
	2011			2010
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	122.3		$	62.0
Customer accounts receivable - unbilled		74.3			82.3
Allowance for doubtful accounts		(3.8	)		(2.7	)
Other receivables		82.8			100.1
Total	$	275.6		$	241.7
KCP&L
Customer accounts receivable - billed	$	43.5		$	6.5
Customer accounts receivable - unbilled		45.8			50.1
Allowance for doubtful accounts		(2.5	)		(1.5	)
Intercompany receivables		68.2			43.2
Other receivables		68.1			71.1
Total	$	223.1		$	169.4

Great Plains Energy’s and KCP&L’s other receivables at September 30, 2011, and December 31, 2010, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables.

Sale of Accounts Receivable – KCP&L

KCP&L sells all of its retail electric accounts receivable to its wholly owned subsidiary, Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor.  Receivables Company’s sale of the undivided percentage ownership interest in accounts receivable to Victory Receivables Corporation is accounted for as a secured borrowing with $95.0 million of accounts receivables pledged as collateral and a corresponding short-term collateralized note payable recognized on Great Plains Energy’s and KCP&L’s balance sheets at September 30, 2011, and December 31, 2010.

KCP&L sells its receivables at a fixed price based upon the expected cost of funds and charge-offs.  These costs comprise KCP&L’s loss on the sale of accounts receivable.  KCP&L services the receivables and receives an annual servicing fee of 1.5% 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 September 2011, the agreement was extended to September 2014 and amended to allow for $110 million in aggregate outstanding principal amount at any time.

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

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

XML

NUCLEAR PLANT (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended			12 Months Ended
	Sep. 30, 2011		Sep. 30, 2010	Sep. 30, 2011		Sep. 30, 2010	Dec. 31, 2010
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund beginning balance				$ 129.2		$ 112.5	$ 112.5
Contributions to nuclear decommissioning trust fund				2.5			3.7
Nuclear decommissioning trust fund earned income, net of fees				4.0			2.0
Net realized gains/(losses)on nuclear decommissioning trust fund				0.3			6.7
Net unrealized gains/(losses) on nuclear decommissioning trust fund				(10.5)			4.3
Ending balance of nuclear decommissioning trust fund	125.5			125.5			129.2
Investments in decommissioning trust fund [Line Items]
Cost basis	121.4			121.4			114.6
Gross unrealized gains				10.9			15.7
Gross unrealized losses				(6.8)			(1.1)
Fair value	125.5			125.5			129.2
Weighted average maturity of debt securities	7.0			7.0
Realized Gains on investments in decommissioning trust fund	0.2		0.2	1.0		7.2
Realized Losses on investments in decommissioning trust fund	0		(0.1)	(0.7)		(0.6)
Nuclear Plant Decommissioning Costs [Line Items]
Annual escalation factor	3.73%			3.73%
Annual return on trust assets through 2025	6.89%	[1]		6.89%	[1]
Annual return on trust assets beginning in 2053	1.81%			1.81%
Kansas City Power and Light Company [Member]
Nuclear decommissioning trust fund [Abstract]
Ending balance of nuclear decommissioning trust fund	125.5			125.5			129.2
Investments in decommissioning trust fund [Line Items]
Fair value	125.5			125.5			129.2
Nuclear Plant Decommissioning Costs [Line Items]
Current cost of decommissioning (in 2011 dollars)	296.0			296.0
Future cost of decommissioning (in 2045-2053 dollars)	1,154.0	[2]		1,154.0	[2]
Total Wolf Creek [Member]
Nuclear Plant Decommissioning Costs [Line Items]
Current cost of decommissioning (in 2011 dollars)	630.0			630.0
Future cost of decommissioning (in 2045-2053 dollars)	2,455.0	[2]		2,455.0	[2]
Equity securities [Member]
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund beginning balance				85.5
Ending balance of nuclear decommissioning trust fund	75.2			75.2			85.5
Investments in decommissioning trust fund [Line Items]
Cost basis	75.3			75.3			73.4
Gross unrealized gains				6.5			13.1
Gross unrealized losses				(6.6)			(1.0)
Fair value	75.2			75.2			85.5
Debt securities [Member]
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund beginning balance				40.6
Ending balance of nuclear decommissioning trust fund	46.9			46.9			40.6
Investments in decommissioning trust fund [Line Items]
Cost basis	42.7			42.7			38.1
Gross unrealized gains				4.4			2.6
Gross unrealized losses				(0.2)			(0.1)
Fair value	46.9			46.9			40.6
Other [Member]
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund beginning balance				3.1
Ending balance of nuclear decommissioning trust fund	3.4			3.4			3.1
Investments in decommissioning trust fund [Line Items]
Cost basis	3.4			3.4			3.1
Gross unrealized gains				0			0
Gross unrealized losses				0			0
Fair value	$ 3.4			$ 3.4			$ 3.1

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

[2] Total future cost over an eight year decommissioning period.

XML

RECEIVABLES (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Schedule of accounts receivable

	September 30			December 31
	2011			2010
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	122.3		$	62.0
Customer accounts receivable - unbilled		74.3			82.3
Allowance for doubtful accounts		(3.8	)		(2.7	)
Other receivables		82.8			100.1
Total	$	275.6		$	241.7
KCP&L
Customer accounts receivable - billed	$	43.5		$	6.5
Customer accounts receivable - unbilled		45.8			50.1
Allowance for doubtful accounts		(2.5	)		(1.5	)
Intercompany receivables		68.2			43.2
Other receivables		68.1			71.1
Total	$	223.1		$	169.4

Schedule of accounts receivable sold

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

XML

LONG-TERM DEBT (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Long-term debt

		September 30			December 31
	Year Due	2011			2010
KCP&L		(millions)
General Mortgage Bonds
4.87% EIRR bonds (a)(b)	2012-2035	$	119.3		$	158.8
7.15% Series 2009A (8.59% rate)(c)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
EIRR Series 2007A-1(d)	2035		-			63.3
EIRR Series 2007A-2(d)	2035		-			10.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
6.50% Series	2011		150.0			150.0
5.85% Series (5.72% rate)(c)	2017		250.0			250.0
6.375% Series (7.49% rate)(c)	2018		350.0			350.0
6.05% Series (5.78% rate)(c)	2035		250.0			250.0
5.30% Series	2041		400.0			-
EIRR bonds
4.90% Series 2008	2038		23.4			23.4
Other	2012-2018		2.9			3.3
Current maturities			(162.7	)		(150.3	)
Unamortized discount			(4.3	)		(2.0	)
Total KCP&L			1,901.8			1,629.7
Other Great Plains Energy
GMO First Mortgage Bonds
9.44% Series	2012-2021		11.2			12.4
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.214% Wamego Series 1996 (e)	2026		7.3			7.3
0.263% State Environmental 1993 (e)	2028		5.0			5.0
GMO Senior Notes
7.95% Series			-			137.3
7.75% Series			-			197.0
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			24.2			49.9
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(c)	2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(c)	2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes	2012		287.5			287.5
Great Plains Energy 4.85% Senior Notes (7.34% rate)(c)	2021		350.0			-
Current maturities			(788.7	)		(335.4	)
Unamortized discount			(0.7	)		(0.5	)
Total Great Plains Energy excluding current maturities		$	2,750.1		$	2,942.7
(a)  Weighted-average interest rates at September 30, 2011
(b) September 30, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by
KCP&L
(c) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(d) September 30, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the
bonds have been repurchased and are held by KCP&L
(e)  Variable rate

XML

RECEIVABLES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010		Dec. 31, 2010
Accounts Receivable, Net, Current [Abstract]
Allowance for doubtful accounts	$ (3.8)				$ (3.8)				$ (2.7)
Receivables, net	275.6				275.6				241.7
Accounts receivable sold [Line Items]
Accounts receivable pledged as collateral	95.0				95.0				95.0
Collateralized note payable	95.0				95.0				95.0
Maximum percentage servicing fee received on receivables sold (in hundredths)					1.50%
Cash flow during the period [Abstract]
Maximum Amount Of Outstanding Principal Under Receivables Agreement	110.0				110.0
Great Plains Energy Incorporated [Member] | Billed Revenues [Member]
Accounts Receivable, Net, Current [Abstract]
Accounts Receivable, Gross, Current	122.3				122.3				62.0
Great Plains Energy Incorporated [Member] | Unbilled Revenues [Member]
Accounts Receivable, Net, Current [Abstract]
Accounts Receivable, Gross, Current	74.3				74.3				82.3
Great Plains Energy Incorporated [Member] | Other Receivables [Member}
Accounts Receivable, Net, Current [Abstract]
Accounts Receivable, Gross, Current	82.8				82.8				100.1
Kansas City Power and Light Company [Member]
Accounts Receivable, Net, Current [Abstract]
Allowance for doubtful accounts	(2.5)				(2.5)				(1.5)
Receivables, net	223.1				223.1				169.4
Accounts receivable sold [Line Items]
Accounts receivable pledged as collateral	95.0				95.0				95.0
Collateralized note payable	95.0				95.0				95.0
Accounts receivable (sold) purchased [Abstract]
Receivables (sold) purchased	0		0		0		0
Gain (loss) on sale of accounts receivables	(0.1)	[1]	(0.2)	[1]	(0.4)	[1]	(0.6)	[1]
Servicing fees	0		0		0		0
Fees to outside investor	(0.3)		(0.3)		(0.9)		(0.9)
Cash flow during the period [Abstract]
Cash from customers transferred to receivables company	0		0		0		0
Cash paid to KCPL for receivables purchased	0		0		0		0
Interest on intercompany note	0		0		0		0
Kansas City Power and Light Company [Member] | Billed Revenues [Member]
Accounts Receivable, Net, Current [Abstract]
Accounts Receivable, Gross, Current	43.5				43.5				6.5
Kansas City Power and Light Company [Member] | Unbilled Revenues [Member]
Accounts Receivable, Net, Current [Abstract]
Accounts Receivable, Gross, Current	45.8				45.8				50.1
Kansas City Power and Light Company [Member] | Intercompany Receivables [Member]
Accounts Receivable, Net, Current [Abstract]
Accounts Receivable, Gross, Current	68.2				68.2				43.2
Kansas City Power and Light Company [Member] | Other Receivables [Member}
Accounts Receivable, Net, Current [Abstract]
Accounts Receivable, Gross, Current	68.1				68.1				71.1
Kansas City Power and Light Company [Member]
Accounts receivable (sold) purchased [Abstract]
Receivables (sold) purchased	(468.8)		(442.0)		(1,108.4)		(1,067.7)
Gain (loss) on sale of accounts receivables	(5.9)	[1]	(5.6)	[1]	(14.0)	[1]	(13.5)	[1]
Servicing fees	0.9		0.8		2.0		1.9
Fees to outside investor	0		0		0		0
Cash flow during the period [Abstract]
Cash from customers transferred to receivables company	(463.4)		(430.9)		(1,081.6)		(1,029.8)
Cash paid to KCPL for receivables purchased	457.6		425.5		1,068.0		1,016.9
Interest on intercompany note	0.2		0.2		0.4		0.4
Receivables Company [Member]
Accounts receivable (sold) purchased [Abstract]
Receivables (sold) purchased	468.8		442.0		1,108.4		1,067.7
Gain (loss) on sale of accounts receivables	5.8	[1]	5.4	[1]	13.6	[1]	12.9	[1]
Servicing fees	(0.9)		(0.8)		(2.0)		(1.9)
Fees to outside investor	(0.3)		(0.3)		(0.9)		(0.9)
Cash flow during the period [Abstract]
Cash from customers transferred to receivables company	463.4		430.9		1,081.6		1,029.8
Cash paid to KCPL for receivables purchased	(457.6)		(425.5)		(1,068.0)		(1,016.9)
Interest on intercompany note	$ (0.2)		$ (0.2)		$ (0.4)		$ (0.4)

[1] Any net gain (loss) is the result of the timing difference inherent in collecting receivables and over the life of the agreement will net to zero.

XML

REGULATORY MATTERS (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2011

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Regulatory assets

							Great
September 30, 2011	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	119.0		$	24.9		$	143.9
Loss on reacquired debt		6.5	(a)		0.6	(a)		7.1
Cost of removal		7.0			-			7.0
Asset retirement obligations		30.4			13.6			44.0
Pension and post-retirement costs		373.2	(b)		120.4	(b)		493.6
Deferred customer programs		48.2	(c)		19.5			67.7
Rate case expenses		9.9	(d)		4.5	(d)		14.4
Skill set realignment costs		3.7	(e)		-			3.7
Fuel adjustment clauses		30.1	(d)		42.5	(d)		72.6
Acquisition transition costs		26.2	(f)		21.3	(f)		47.5
St. Joseph Light & Power acquisition		-			2.2	(g)		2.2
Storm damage		-			2.0	(h)		2.0
Derivative instruments		-			3.1	(i)		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		16.5			6.1			22.6
Iatan No. 2 construction accounting costs		27.6			15.5			43.1
Other		2.3	(j)		0.4	(j)		2.7
Total	$	700.6		$	276.6		$	977.2

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

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

(c)   $11.3 million not included in rate base and amortized over various periods.

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

(e)   $2.5 million not included in rate base and amortized through 2017.

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

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

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

(i)   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).

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

					Great
December 31, 2010	KCP&L		GMO		Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	117.2	$	25.3	$	142.5
Loss on reacquired debt		5.0		0.7		5.7
Cost of removal		8.5		-		8.5
Asset retirement obligations		27.5		12.8		40.3
Pension and post-retirement costs		386.1		106.7		492.8
Deferred customer programs		44.7		15.6		60.3
Rate case expenses		12.3		3.3		15.6
Skill set realignment costs		4.8		-		4.8
Fuel adjustment clauses		8.4		37.1		45.5
Acquisition transition costs		29.3		22.5		51.8
St. Joseph Light & Power acquisition		-		2.6		2.6
Storm damage		-		3.2		3.2
Derivative instruments		-		3.1		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		15.1		4.3		19.4
Iatan No. 2 construction accounting costs		17.2		6.5		23.7
Other		3.5		0.7		4.2
Total	$	679.6	$	244.4	$	924.0

Regulatory liabilities

						Great
September 30, 2011	KCP&L		GMO			Plains Energy
Regulatory Liabilities	(millions)
Emission allowances	$	83.0	$	0.3		$	83.3
Asset retirement obligations		40.9		-			40.9
Pension		0.5		39.9			40.4
Cost of removal		-		62.5	(k)		62.5
Other		11.2		19.5			30.7
Total	$	135.6	$	122.2		$	257.8

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

					Great
December 31, 2010	KCP&L		GMO		Plains Energy
Regulatory Liabilities	(millions)
Emission allowances	$	85.9	$	0.5	$	86.4
Asset retirement obligations		44.9		-		44.9
Pension		-		37.1		37.1
Cost of removal		-		62.8		62.8
Other		10.5		16.5		27.0
Total	$	141.3	$	116.9	$	258.2

XML

LEGAL PROCEEDINGS

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Legal proceedings

11.   LEGAL PROCEEDINGS

KCP&L Spent Nuclear Fuel and Radioactive Waste

In January 2004, KCP&L and the other two Wolf Creek owners filed a lawsuit against the United States in the U.S. Court of Federal Claims seeking $14.1 million of damages resulting from the government’s failure to begin accepting spent nuclear fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982.  The Wolf Creek case was tried before a U.S. Court of Federal Claims judge in June 2010, and a decision was issued in November 2010, granting KCP&L and the other two Wolf Creek owners $10.6 million ($5.0 million KCP&L share) in damages.  In January 2011, KCP&L and the other two Wolf Creek owners as well as the United States filed appeals of the decision to the U.S. Court of Appeals for the Federal Circuit.  The court has set a briefing schedule.  Briefing likely will conclude in the fourth quarter of 2011, and the parties will present their oral arguments to the court sometime thereafter.

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.  Written discovery and depositions are underway and this matter is set for trial in May 2012.  Management cannot predict the outcome of this matter.

GMO Price Reporting Litigation

In response to complaints of manipulation of the California energy market, in July 2001, FERC issued an order requiring net sellers of power in the California markets from October 2, 2000, through June 20, 2001, at prices above a FERC determined competitive market clearing price to make refunds to net purchasers of power in the California market during that time period.  Because MPS Merchant was a net purchaser of power during the refund period, it has received approximately $8 million in refunds through settlements with certain sellers of power.  MPS Merchant estimates that it is entitled to approximately $12 million in additional refunds under the standards FERC has used in this case.  FERC has stated that interest will be applied to the refunds but the amount of interest has not yet been determined.  However, in December 2001, various parties appealed the FERC order to the United States Court of Appeals for the Ninth Circuit seeking review of a number of issues, including changing the refund period to include periods prior to October 2, 2000.  MPS Merchant was a net seller of power during the period prior to October 2, 2000.  On August 2, 2006, the U.S. Court of Appeals for the Ninth Circuit issued an order finding, among other things, that FERC did not provide a sufficient justification for refusing to exercise its remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the period prior to October 2, 2000, and imposing a remedy for any such violations.  The court remanded the matter to FERC for further consideration.  In May 2011, FERC issued an order which clarified the scope of the hearing in the refund proceeding and ruled on requests for rehearing and motions to dismiss.  A hearing is set for March 2012.  If FERC ultimately includes the period prior to October 2, 2000, MPS Merchant could be found to owe refunds.

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

XML

NUCLEAR PLANT

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Nuclear plant

4.   NUCLEAR PLANT

KCP&L owns 47% of Wolf Creek Generating Station (Wolf Creek), its only nuclear generating unit.  Wolf Creek is located in Coffey County, Kansas, just northeast of Burlington, Kansas.  Wolf Creek’s operating license expires in 2045.  Wolf Creek is regulated by the Nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety-related requirements.Wolf Creek is operating in the category of nuclear plants receiving the lowest level of NRC oversight.

In March 2011, the NRC established a task force to conduct a 90-day review and a longer-term review of U.S. nuclear power plant safety in the aftermath of a March 11, 2011, earthquake and tsunami that eventually resulted in station blackout and a level 7 event on the International Nuclear and Radiological Event Scale (the highest level event on the scale) at Japan’s Fukushima Daiichi nuclear power plant.  On July 12, 2011, the task force issued an extensive report on the ramifications of the Fukushima earthquake/tsunami for nuclear power plant regulation in the U.S.  In October 2011, the NRC received recommendations from the NRC staff on how to proceed with the task force report.  The recommendations break down the task force report into three tiers of actions.  The first tier of recommendations includes actions that the nuclear industry has already taken or believes need near-term attention.  The second tier recommendations require further study before action can be taken and the third tier recommendations require NRC rulemaking, additional study and stakeholder involvement to finalize the specific details.  The timing and effects of any NRC action cannot be determined at this time.

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 July 2010.  In September 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of September 2011 due to a lack of funding.  Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025, and believes it will be able to expand on-site storage as needed past 2025.  Management cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.  See Note 11 for a related legal proceeding.

Low-Level Radioactive Waste

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

Nuclear Plant Decommissioning Costs

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

		Total			KCP&L's
		Station			47% Share
		(millions)
Current cost of decommissioning (in 2011 dollars)		$	630		$	296
Future cost of decommissioning (in 2045-2053 dollars) (a)			2,455			1,154
Annual escalation factor			3.73	%
Annual return on trust assets (b)			6.89	%
(a)	Total future cost over an eight year decommissioning period.
(b)	The 6.89% rate of return is through 2025. The rate then systematically decreases
	through 2053 to 1.81% based on the assumption that the fund's investment mix
	will become increasingly more conservative as the decommissioning period
	approaches.

Nuclear Decommissioning Trust Fund

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

	September 30			December 31
	2011			2010
Decommissioning Trust	(millions)
Beginning balance January 1	$	129.2		$	112.5
Contributions		2.5			3.7
Earned income, net of fees		4.0			2.0
Net realized gains		0.3			6.7
Net unrealized gains (losses)		(10.5	)		4.3
Ending balance	$	125.5		$	129.2

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

	September 30									December 31
	2011									2010
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	75.3	$	6.5	$	(6.6	)	$	75.2	$	73.4	$	13.1	$	(1.0	)	$	85.5
Debt securities		42.7		4.4		(0.2	)		46.9		38.1		2.6		(0.1	)		40.6
Other		3.4		-		-			3.4		3.1		-		-			3.1
Total	$	121.4	$	10.9	$	(6.8	)	$	125.5	$	114.6	$	15.7	$	(1.1	)	$	129.2

The weighted average maturity of debt securities held by the trust at September 30, 2011, was approximately 7 years.  The costs of securities sold are determined on the basis of specific identification.  The following table summarizes the realized gains and losses from the sale of securities in the nuclear decommissioning trust fund.

	Three Months Ended					Year to Date
	September 30					September 30
	2011		2010			2011			2010
	(millions)
Realized gains	$	0.2	$	0.2		$	1.0		$	7.2
Realized losses		-		(0.1	)		(0.7	)		(0.6	)

XML

FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Fair value measurements

14.   FAIR VALUE MEASUREMENTS

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  GAAP establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad categories, giving the highest priority to quoted prices in active markets for identical assets or liabilities and lowest priority to unobservable inputs.  A definition of the various levels, as well as discussion of the various measurements within the levels, is as follows:

Level 1 – Unadjusted quoted prices for identical assets or liabilities in active markets that Great Plains Energy and KCP&L have access to at the measurement date.  Assets categorized within this level consist of Great Plains Energy’s and KCP&L’s various exchange traded derivative instruments and equity and U.S. Treasury securities that are actively traded within KCP&L’s decommissioning trust fund and GMO’s SERP rabbi trust fund.

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

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

The following tables include Great Plains Energy’s and KCP&L’s balances of financial assets and liabilities measured at fair value on a recurring basis at September 30, 2011, and December 31, 2010.

						Fair Value Measurements Using
Description	September 30 2011		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Derivative instruments (a)	$	-	$	-		$	-	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		75.2		-			75.2		-		-
Debt securities
U.S. Treasury		14.7		-			14.7		-		-
U.S. Agency		3.6		-			-		3.6		-
State and local obligations		2.6		-			-		2.6		-
Corporate bonds		25.3		-			-		25.3		-
Foreign governments		0.7		-			-		0.7		-
Other		0.3		-			-		0.3		-
Total nuclear decommissioning trust		122.4		-			89.9		32.5		-
Total		122.4		-			89.9		32.5		-
Liabilities
Derivative instruments (a)		-		(0.2	)		0.2		-		-
Total	$	-	$	(0.2	)	$	0.2	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	9.3	$	-		$	-	$	4.8	$	4.5
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		0.2		-			-		0.2		-
Total SERP rabbi trust		0.4		-			0.2		0.2		-
Total		9.7		-			0.2		5.0		4.5
Liabilities
Derivative instruments (a)		-		(2.0	)		2.0		-		-
Total	$	-	$	(2.0	)	$	2.0	$	-	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	9.3	$	-		$	-	$	4.8	$	4.5
Nuclear decommissioning trust (b)		122.4		-			89.9		32.5		-
SERP rabbi trust (c)		0.4		-			0.2		0.2		-
Total		132.1		-			90.1		37.5		4.5
Liabilities
Derivative instruments (a)		-		(2.2	)		2.2		-		-
Total	$	-	$	(2.2	)	$	2.2	$	-	$	-

						Fair Value Measurements Using
Description	December 31 2010		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Derivative instruments (a)	$	-	$	(0.1	)	$	0.1	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		85.5		-			85.5		-		-
Debt securities
U.S. Treasury		8.9		-			8.9		-		-
U.S. Agency		4.8		-			-		4.8		-
State and local obligations		2.5		-			-		2.5		-
Corporate bonds		23.7		-			-		23.7		-
Foreign governments		0.7		-			-		0.7		-
Other		0.4		-			-		0.4		-
Total nuclear decommissioning trust		126.5		-			94.4		32.1		-
Total		126.5		(0.1	)		94.5		32.1		-
Liabilities
Derivative instruments (a)		-		(0.1	)		0.1		-		-
Total	$	-	$	(0.1	)	$	0.1	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.5	)	$	0.5	$	5.2	$	3.7
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		7.0		-			-		7.0		-
Total SERP rabbi trust		7.2		-			0.2		7.0		-
Total		16.1		(0.5	)		0.7		12.2		3.7
Liabilities
Derivative instruments (a)		20.8		(3.0	)		3.0		20.8		-
Total	$	20.8	$	(3.0	)	$	3.0	$	20.8	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.6	)	$	0.6	$	5.2	$	3.7
Nuclear decommissioning trust (b)		126.5		-			94.4		32.1		-
SERP rabbi trust (c)		7.2		-			0.2		7.0		-
Total		142.6		(0.6	)		95.2		44.3		3.7
Liabilities
Derivative instruments (a)		20.8		(3.1	)		3.1		20.8		-
Total	$	20.8	$	(3.1	)	$	3.1	$	20.8	$	-

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

(b)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $3.1 million and $2.7 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(c)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $20.4 million and $14.6 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)   Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty.  At September 30, 2011, and December 31, 2010, Great Plains Energy netted $2.2 million and $2.5 million, respectively, of cash collateral posted with counterparties.

The following tables reconcile the beginning and ending balances for all level 3 assets and liabilities, net measured at fair value on a recurring basis for the three months ended and year to date September 30, 2011 and 2010.

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

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other Great
	Plains Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains or (losses)
Included in non-operating income		11.1
Settlements		(10.3	)
Balance September 30, 2011	$	4.5
Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at September 30, 2011	$	1.2

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
	KCP&L			Plains 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	$	-		$	-		$	-

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income [Abstract]
Income from continuing operations	$ 126,600,000	$ 132,000,000	$ 172,300,000	$ 216,700,000
Less: Net income attributable to noncontrolling interest	100,000	0	0	100,000
Less: preferred stock dividend requirements	400,000	400,000	1,200,000	1,200,000
Income from continuing operations available for common shareholders	126,100,000	131,600,000	171,100,000	215,400,000
Common Shares Outstanding [Abstract]
Average number of common shares outstanding	135,700,000	135,200,000	135,600,000	135,100,000
Add: effect of dilutive securities	2,600,000	1,700,000	2,900,000	1,700,000
Diluted average number of common shares outstanding	138,300,000	136,900,000	138,500,000	136,800,000
Basic EPS from continuing operations	$ 0.93	$ 0.97	$ 1.26	$ 1.59
Diluted EPS from continuing operations	$ 0.91	$ 0.96	$ 1.24	$ 1.57
Performance shares [Member]
Great Plains Energy anti-dilutive shares [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	102,032	107,958	102,032	116,388
Restricted Stock [Member]
Great Plains Energy anti-dilutive shares [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	22,818	103,114	45,648	278,452
Stock options [Member]
Great Plains Energy anti-dilutive shares [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	80,140	203,879	80,140	209,837
Great Plains Energy Incorporated [Member]
Dividends Declared [Line Iems]
Subsequent Event Date	Nov. 01, 2011		Nov. 01, 2011
Subsequent Event Description			Great Plains Energys Board of Directors declared a quarterly dividend and also declared regular dividends on Great Plains Energys preferred stock.
Subsequent Event Amount			0.2125
Kansas City Power and Light Company [Member]
Dividends Declared [Line Iems]
Subsequent Event Date	Nov. 01, 2011		Nov. 01, 2011
Subsequent Event Description			KCP&Ls Board of Directors declared a cash dividend payable to Great Plains Energy
Subsequent Event Amount			$ 25,000,000

XML

NUCLEAR PLANT (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Changes in nuclear decommissioning trust fund

	September 30			December 31
	2011			2010
Decommissioning Trust	(millions)
Beginning balance January 1	$	129.2		$	112.5
Contributions		2.5			3.7
Earned income, net of fees		4.0			2.0
Net realized gains		0.3			6.7
Net unrealized gains (losses)		(10.5	)		4.3
Ending balance	$	125.5		$	129.2

Detail of assets held in nuclear decommissioning trust fund

	September 30									December 31
	2011									2010
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	75.3	$	6.5	$	(6.6	)	$	75.2	$	73.4	$	13.1	$	(1.0	)	$	85.5
Debt securities		42.7		4.4		(0.2	)		46.9		38.1		2.6		(0.1	)		40.6
Other		3.4		-		-			3.4		3.1		-		-			3.1
Total	$	121.4	$	10.9	$	(6.8	)	$	125.5	$	114.6	$	15.7	$	(1.1	)	$	129.2

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

	Three Months Ended					Year to Date
	September 30					September 30
	2011		2010			2011			2010
	(millions)
Realized gains	$	0.2	$	0.2		$	1.0		$	7.2
Realized losses		-		(0.1	)		(0.7	)		(0.6	)

Nuclear Plant Decommissioning Costs

		Total			KCP&L's
		Station			47% Share
		(millions)
Current cost of decommissioning (in 2011 dollars)		$	630		$	296
Future cost of decommissioning (in 2045-2053 dollars) (a)			2,455			1,154
Annual escalation factor			3.73	%
Annual return on trust assets (b)			6.89	%
(a)	Total future cost over an eight year decommissioning period.
(b)	The 6.89% rate of return is through 2025. The rate then systematically decreases
	through 2053 to 1.81% based on the assumption that the fund's investment mix
	will become increasingly more conservative as the decommissioning period
	approaches.

XML

Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash Flows from Operating Activities
Net income	$ 172.3	$ 216.7
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	205.9	248.5
Amortization of:
Nuclear fuel	13.5	19.7
Other	7.5	(4.1)
Deferred income taxes, net	124.0	127.0
Investment tax credit amortization	(1.5)	(1.8)
Loss from equity investments, net of income taxes	0.1	0.9
Other operating activities	(154.3)	(199.2)
Net cash from operating activities	367.5	407.7
Cash Flows from Investing Activities
Utility capital expenditures	(317.8)	(465.2)
Allowance for borrowed funds used during construction	(3.1)	(26.9)
Purchases of nuclear decommissioning trust investments	(15.5)	(78.3)
Proceeds from nuclear decommissioning trust investments	13.0	75.6
Other investing activities	(17.4)	(9.1)
Net cash from investing activities	(340.8)	(503.9)
Cash Flows from Financing Activities
Issuance of common stock	4.5	4.7
Issuance of long-term debt	747.1	249.9
Issuance fees	(6.2)	(11.7)
Repayment of long-term debt	(448.5)	(1.3)
Net change in short-term borrowings	(234.5)	(207.1)
Net change in collateralized short-term borrowings	0	95.0
Dividends paid	(85.9)	(85.6)
Other financing activities	(5.1)	(6.0)
Net cash from financing activities	(28.6)	37.9
Net Change in Cash and Cash Equivalents	(1.9)	(58.3)
Cash and Cash Equivalents at Beginning of Year	10.8	65.9
Cash and Cash Equivalents at End of Period	8.9	7.6
KANSAS CITY POWER AND LIGHT CO [Member]
Cash Flows from Operating Activities
Net income	122.8	160.0
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	147.0	192.2
Amortization of:
Nuclear fuel	13.5	19.7
Other	22.3	18.1
Deferred income taxes, net	87.2	63.5
Investment tax credit amortization	(1.0)	(1.2)
Other operating activities	(74.3)	(171.1)
Net cash from operating activities	317.5	281.2
Cash Flows from Investing Activities
Utility capital expenditures	(236.7)	(349.1)
Allowance for borrowed funds used during construction	(1.6)	(21.3)
Purchases of nuclear decommissioning trust investments	(15.5)	(78.3)
Proceeds from nuclear decommissioning trust investments	13.0	75.6
Net money pool lending	(18.8)	6.0
Other investing activities	(9.3)	(6.0)
Net cash from investing activities	(268.9)	(373.1)
Cash Flows from Financing Activities
Issuance of common stock	397.4	0
Issuance fees	(3.7)	(5.0)
Repayment of long-term debt	(113.1)	(0.2)
Net change in short-term borrowings	(253.0)	22.9
Net change in collateralized short-term borrowings	0	95.0
Net money pool borrowings	(1.6)	34.8
Dividends paid	(75.0)	(70.0)
Net cash from financing activities	(49.0)	77.5
Net Change in Cash and Cash Equivalents	(0.4)	(14.4)
Cash and Cash Equivalents at Beginning of Year	3.6	17.4
Cash and Cash Equivalents at End of Period	$ 3.2	$ 3.0

XML

TAXES

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Taxes

15.   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	2011			2010			2011			2010
Current income taxes	(millions)
Federal	$	(10.2	)	$	(7.2	)	$	(6.4	)	$	(8.1	)
State		(0.8	)		(2.0	)		(4.8	)		0.3
Foreign		-			(0.2	)		(0.4	)		0.2
Total		(11.0	)		(9.4	)		(11.6	)		(7.6	)
Deferred income taxes
Federal		74.7			73.5			103.6			108.2
State		13.0			14.6			20.4			18.8
Total		87.7			88.1			124.0			127.0
Noncurrent income taxes
Federal		-			(6.8	)		(18.0	)		(1.3	)
State		-			(1.0	)		(1.9	)		(0.3	)
Foreign		(0.6	)		0.2			(0.4	)		0.2
Total		(0.6	)		(7.6	)		(20.3	)		(1.4	)
Investment tax credit
Deferral		-			-			-			(4.1	)
Amortization		(0.7	)		(0.7	)		(1.5	)		(1.8	)
Total		(0.7	)		(0.7	)		(1.5	)		(5.9	)
Income tax expense	$	75.4		$	70.4		$	90.6		$	112.1

	Three Months Ended						Year to Date
	September 30						September 30
KCP&L	2011			2010			2011			2010
Current income taxes	(millions)
Federal	$	(10.2	)	$	(15.3	)	$	(7.8	)	$	22.5
State		(0.9	)		(2.6	)		(0.4	)		4.6
Total		(11.1	)		(17.9	)		(8.2	)		27.1
Deferred income taxes
Federal		53.5			63.9			73.4			53.9
State		9.3			11.7			13.8			9.5
Total		62.8			75.6			87.2			63.4
Noncurrent income taxes
Federal		1.5			(2.4	)		(9.1	)		(1.5	)
State		0.1			(0.3	)		(1.0	)		(0.1	)
Total		1.6			(2.7	)		(10.1	)		(1.6	)
Investment tax credit
Deferral		-			-			-			(4.1	)
Amortization		(0.5	)		(0.5	)		(1.0	)		(1.2	)
Total		(0.5	)		(0.5	)		(1.0	)		(5.3	)
Income tax expense	$	52.8		$	54.5		$	67.9		$	83.6

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	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	70.6		$	70.8			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.8			(0.9	)		0.9			(0.4	)
Amortization of investment tax credits		(0.7	)		(0.7	)		(0.3	)		(0.4	)
Federal income tax credits		(2.9	)		(2.0	)		(1.4	)		(0.9	)
State income taxes		8.1			7.5			4.0			3.7
Changes in uncertain tax positions, net		(2.7	)		0.3			(1.3	)		0.2
Valuation allowance		-			(2.9	)		-			(1.4	)
Other		1.2			(1.7	)		0.4			(1.0	)
Total	$	75.4		$	70.4			37.3	%		34.8	%

Great Plains Energy	Income Tax Expense						Income Tax Rate
Year to Date September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	92.0		$	115.0			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		3.7			(6.0	)		1.4			(1.8	)
Amortization of investment tax credits		(1.5	)		(1.8	)		(0.6	)		(0.5	)
Federal income tax credits		(9.7	)		(6.1	)		(3.7	)		(1.8	)
State income taxes		11.1			12.0			4.2			3.7
Medicare Part D subsidy legislation		-			2.8			-			0.8
Changes in uncertain tax positions, net		(4.0	)		0.3			(1.5	)		0.1
Valuation allowance		(2.2	)		(2.9	)		(0.8	)		(0.9	)
Other		1.2			(1.2	)		0.5			(0.5	)
Total	$	90.6		$	112.1			34.5	%		34.1	%

KCP&L	Income Tax Expense						Income Tax Rate
Three Months Ended September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	48.3		$	51.5			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.7			(1.1	)		1.2			(0.8	)
Amortization of investment tax credits		(0.5	)		(0.5	)		(0.4	)		(0.4	)
Federal income tax credits		(2.9	)		(1.9	)		(2.1	)		(1.3	)
State income taxes		5.7			5.7			4.1			3.9
Changes in uncertain tax positions		-			0.1			-			0.1
Other		0.5			0.7			0.4			0.6
Total	$	52.8		$	54.5			38.2	%		37.1	%

KCP&L	Income Tax Expense						Income Tax Rate
Year to Date September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	66.7		$	85.3			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		3.3			(5.2	)		1.7			(2.2	)
Amortization of investment tax credits		(1.0	)		(1.2	)		(0.5	)		(0.5	)
Federal income tax credits		(9.6	)		(6.0	)		(5.1	)		(2.5	)
State income taxes		7.7			8.8			4.0			3.6
Medicare Part D subsidy legislation		-			2.8			-			1.2
Changes in uncertain tax positions		0.4			0.1			0.2			0.1
Other		0.4			(1.0	)		0.3			(0.4	)
Total	$	67.9		$	83.6			35.6	%		34.3	%

Uncertain Tax Positions

At September 30, 2011, and December 31, 2010, Great Plains Energy had $24.4 million and $42.0 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $12.4 million and $17.3 million, respectively, at September 30, 2011, and December 31, 2010, is expected to impact the effective tax rate if recognized.  The $17.6 million decrease in unrecognized tax benefits is primarily due to a decrease of $18.4 million related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years.  The $18.4 million tax benefit recognized related to the 2006-2008 IRS audit was offset by an increase of $16.4 million in deferred income tax liabilities since a significant portion of the unrecognized tax benefits were related to temporary tax differences, which resulted in an increase to net income of $2.0 million.

At September 30, 2011, and December 31, 2010, KCP&L had $9.0 million and $19.1 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $0.3 million at September 30, 2011, and December 31, 2010, is expected to impact the effective tax rate if recognized.  The $10.1 million decrease in unrecognized tax benefits is primarily due to a decrease of $12.1 million related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years.  The tax benefit recognized related to the 2006-2008 IRS audit was mostly offset by an increase in deferred income tax liabilities, which resulted in an insignificant impact to net income.

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

	Great Plains Energy						KCP&L
	September 30			December 31			September 30			December 31
	2011			2010			2011			2010
	(millions)
Beginning balance	$	42.0		$	51.4		$	19.1		$	20.9
Additions for current year tax positions		1.1			2.7			-			1.3
Additions for prior year tax positions		2.5			2.1			2.3			1.5
Reductions for prior year tax positions		(20.8	)		(10.6	)		(12.4	)		(1.6	)
Settlements		-			(3.8	)		-			(2.9	)
Statute expirations		-			(0.3	)		-			(0.1	)
Foreign currency translation adjustments		(0.4	)		0.5			-			-
Ending balance	$	24.4		$	42.0		$	9.0		$	19.1

Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.  At September 30, 2011, and December 31, 2010, accrued interest related to unrecognized tax benefits for Great Plains Energy was $5.9 million and $6.7 million, respectively.  Amounts accrued for penalties with respect to unrecognized tax benefits was $1.1 million at September 30, 2011, and December 31, 2010.  KCP&L had accrued interest related to unrecognized tax benefits of $0.3 million and $1.4 million at September 30, 2011, and December 31, 2010, respectively.  Amounts accrued for penalties with respect to unrecognized tax benefits for KCP&L are insignificant.

The Companies are unable to estimate the amount of unrecognized tax benefits that may be recognized in the next twelve months.  

XML

PENSION PLANS AND OTHER EMPLOYEE BENEFITS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Components of net periodic benefit costs [Abstract]
Contributions made by the Company			$ 42.0
Voluntary Separation Program [Line Items]
Annual Savings In Labor Costs Expected From Voluntary Savings Program	15.0		15.0
Voluntary separation program	0	0	12.7	0
Employees who elected to voluntarily separate (in employees)	140		140
Date of employee separation	Apr. 30, 2011		Apr. 30, 2011
Pension Benefits [Member]
Components of net periodic benefit costs [Abstract]
Service cost	7.8	7.6	23.4	22.8
Interest cost	12.4	12.3	37.5	36.9
Expected return on plan assets	(9.5)	(9.2)	(28.8)	(27.5)
Prior service cost	1.1	1.1	3.4	3.5
Recognized net actuarial loss (gain)	9.7	9.4	28.9	28.1
Transition obligation	0	0	0	0
Settlement charge	10.0	0	10.2	0
Net periodic benefit costs before regulatory adjustment	31.5	21.2	74.6	63.8
Regulatory adjustment	(12.8)	(8.1)	(25.1)	(24.6)
Net periodic benefit costs	18.7	13.1	49.5	39.2
Additional contribution expected in the year	80.2		80.2
Other Benefits [Member]
Components of net periodic benefit costs [Abstract]
Service cost	0.7	1.0	2.3	2.8
Interest cost	2.0	2.2	5.9	6.6
Expected return on plan assets	(0.4)	(0.5)	(1.3)	(1.6)
Prior service cost	1.8	1.8	5.4	5.4
Recognized net actuarial loss (gain)	(0.1)	(0.1)	(0.4)	(0.1)
Transition obligation	0.3	0.3	1.0	1.0
Settlement charge	0	0	0	0
Net periodic benefit costs before regulatory adjustment	4.3	4.7	12.9	14.1
Regulatory adjustment	0.4	0	0.7	0
Net periodic benefit costs	4.7	4.7	13.6	14.1
Additional contribution expected in the year	$ 17.1		$ 17.1

XML

GOODWILL

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Goodwill

17.   GOODWILL

Accounting rules require goodwill to be tested for impairment annually and when an event occurs indicating the possibility that an impairment exists.  The annual impairment test for the $169.0 million of GMO acquisition goodwill was conducted on September 1, 2011.  The goodwill impairment test is a two step process.  The first step compares the fair value of a reporting unit to its carrying amount, including goodwill, to identify potential impairment.  If the carrying amount exceeds the fair value of the reporting unit, the second step of the test is performed, consisting of assignment of the reporting unit’s fair value to its assets and liabilities to determine an implied fair value of goodwill which is compared to the carrying amount of goodwill to determine the impairment loss, if any, to be recognized in the financial statements.  Great Plains Energy’s regulated electric utility operations are considered one reporting unit for assessment of impairment, as they are included within the same operating segment and have similar economic characteristics.  The determination of fair value of the reporting unit consisted of two valuation techniques: an income approach consisting of a discounted cash flow analysis and a market approach consisting of a determination of reporting unit invested capital using market multiples derived from the historical revenue, EBITDA and net utility asset values and market prices of stock of electric and gas company regulated peers.  The results of the two techniques were evaluated and weighted to determine a point within the range that management considered representative of fair value for the reporting unit.  Fair value of the reporting unit exceeded the carrying amount, including goodwill; therefore, there was no impairment of goodwill.

XML

Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Net income	$ 126.6	$ 132.0	$ 172.3	$ 216.7
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	(0.1)	(10.3)	(5.5)	(32.4)
Income tax benefit	0.1	4.0	2.2	12.6
Net gain (loss) on derivative hedging instruments	0	(6.3)	(3.3)	(19.8)
Reclassification to expenses, net of tax	3.1	2.0	7.3	4.8
Derivative hedging activity, net of tax	3.1	(4.3)	4.0	(15.0)
Defined benefit pension plans
Amortization of net gains included in net periodic benefit costs	0	0	0.2	0.2
Income tax expense	0	0	(0.1)	(0.1)
Net change in unrecognized pension expense	0	0	0.1	0.1
Comprehensive income	129.7	127.7	176.4	201.8
Less: comprehensive income attributable to noncontrolling interest	(0.1)	0	0	(0.1)
Comprehensive income attributable to Great Plains Energy	129.6	127.7	176.4	201.7
KANSAS CITY POWER AND LIGHT CO [Member]
Net income	85.4	92.6	122.8	160.0
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments	(0.1)	(0.4)	(0.2)	(1.0)
Income tax benefit	0.1	0.2	0.1	0.4
Net gain (loss) on derivative hedging instruments	0	(0.2)	(0.1)	(0.6)
Reclassification to expenses, net of tax	1.3	1.6	4.0	4.3
Derivative hedging activity, net of tax	1.3	1.4	3.9	3.7
Defined benefit pension plans
Comprehensive income	$ 86.7	$ 94.0	$ 126.7	$ 163.7

XML

LONG-TERM DEBT

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Long-term debt

9.   LONG-TERM DEBT

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

		September 30			December 31
	Year Due	2011			2010
KCP&L		(millions)
General Mortgage Bonds
4.87% EIRR bonds (a)(b)	2012-2035	$	119.3		$	158.8
7.15% Series 2009A (8.59% rate)(c)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
EIRR Series 2007A-1(d)	2035		-			63.3
EIRR Series 2007A-2(d)	2035		-			10.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
6.50% Series	2011		150.0			150.0
5.85% Series (5.72% rate)(c)	2017		250.0			250.0
6.375% Series (7.49% rate)(c)	2018		350.0			350.0
6.05% Series (5.78% rate)(c)	2035		250.0			250.0
5.30% Series	2041		400.0			-
EIRR bonds
4.90% Series 2008	2038		23.4			23.4
Other	2012-2018		2.9			3.3
Current maturities			(162.7	)		(150.3	)
Unamortized discount			(4.3	)		(2.0	)
Total KCP&L			1,901.8			1,629.7
Other Great Plains Energy
GMO First Mortgage Bonds
9.44% Series	2012-2021		11.2			12.4
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.214% Wamego Series 1996 (e)	2026		7.3			7.3
0.263% State Environmental 1993 (e)	2028		5.0			5.0
GMO Senior Notes
7.95% Series			-			137.3
7.75% Series			-			197.0
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			24.2			49.9
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(c)	2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(c)	2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes	2012		287.5			287.5
Great Plains Energy 4.85% Senior Notes (7.34% rate)(c)	2021		350.0			-
Current maturities			(788.7	)		(335.4	)
Unamortized discount			(0.7	)		(0.5	)
Total Great Plains Energy excluding current maturities		$	2,750.1		$	2,942.7
(a)  Weighted-average interest rates at September 30, 2011
(b) September 30, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by
KCP&L
(c) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(d) September 30, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the
bonds have been repurchased and are held by KCP&L
(e)  Variable rate

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, 2011, and December 31, 2010, the book value of Great Plains Energy’s long-term debt, including current maturities, was $3.7 billion and $3.4 billion, respectively.  At September 30, 2011, and December 31, 2010, the fair value of Great Plains Energy’s long-term debt, including current maturities, was $4.1 billion and $3.7 billion, respectively.  At September 30, 2011, and December 31, 2010, the book value of KCP&L’s long-term debt, including current maturities, was $2.1 billion and $1.8 billion, respectively.  At September 30, 2011, and December 31, 2010, the fair value of KCP&L’s long-term debt, including current maturities, was $2.3 billion and $1.9 billion, respectively.

KCP&L General Mortgage Bonds and EIRR Bonds

In April 2011, KCP&L purchased in lieu of redemption its $63.3 million EIRR Series 2007A-1, $10.0 million EIRR Series 2007A-2 and $39.5 million EIRR Series 1993B bonds.  KCP&L opted to purchase rather than remarket the bonds given the poor conditions in the tax-exempt market.  KCP&L issued commercial paper to fund the purchase of the bonds.As of September 30, 2011, the bonds were still outstanding, but were not reported as a liability on the balance sheet since they are being held by KCP&L.  KCP&L has the ability to remarket these bonds to third parties whenever it determines market conditions are sufficiently attractive to do so.

KCP&L Senior Notes

In September 2011, KCP&L issued $400.0 million of 5.30% unsecured Senior Notes, maturing in 2041.

GMO Senior Notes

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

Great Plains Energy Senior Notes

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

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

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

Great Plains Energy must attempt to remarket the subordinated notes, in whole but not in part, between December 15, 2011, and June 12, 2012.  The proceeds from a successful remarketing will be used to satisfy the holders’ obligation under the purchase contract.  If the notes have not been successfully remarketed by June 12, 2012, the holders of all notes will have the right to put their notes to Great Plains Energy on June 15, 2012, in satisfaction of the holders’ obligation under the purchase contracts, and Great Plains Energy will issue to the holders newly issued shares of the Company’s common stock equal to the settlement rate.  The settlement rate will vary according to the applicable market value of the Company’s common stock at the settlement date.

XML

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Kansas City Power and Light Company's related party receivables and payables

	September 30		December 31
	2011		2010
	(millions)
Net receivable from GMO	$	45.7	$	29.6
Net receivable from Great Plains Energy		14.0		13.3
Receivable from MPS Merchant		8.6		0.3

XML

DERIVATIVE INSTRUMENTS

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Derivative Instruments

13.   DERIVATIVE INSTRUMENTS

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

Great Plains Energy and KCP&L have posted collateral, in the ordinary course of business, for the aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a liability position.  At September 30, 2011, Great Plains Energy and KCP&L have posted collateral in excess of the aggregate fair value of their derivative instruments; therefore, if the credit risk-related contingent features underlying these agreements were triggered, Great Plains Energy and KCP&L would not be required to post additional collateral to its counterparties.

The Dodd-Frank Wall Street Reform and Consumer Protection Act 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 will 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 May 2011, Great Plains Energy issued $350.0 million of long-term debt and settled six forward starting swaps (FSS) simultaneously with the issuance of this long-term fixed rate debt.  Great Plains Energy had entered into the six FSS with notional amounts totaling $350.0 million to hedge against interest rate variability on the debt issuance.  The six FSS were treated as cash flow hedges with no ineffectiveness recorded for the three months ended and year to date September 30, 2011 and 2010.  A pre-tax loss of $26.1 million was recorded to OCI and is being reclassified to interest expense over the first three years of the ten-year debt.  For the three months ended and year to date September 30, 2011, a $2.2 million and $3.3 million loss, respectively, has been reclassified from OCI to interest expense.

Commodity Risk Management

KCP&L’s risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales.  At September 30, 2011, KCP&L had fully hedged 2012 and had hedged 91% of 2013 projected natural gas usage for retail load and firm MWh sales, primarily by utilizing futures contracts and financial instruments.  KCP&L has designated the natural gas hedges as cash flow hedges.  The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge.  To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense.  KCP&L has not recorded any ineffectiveness on natural gas hedges for the three months ended and year to date September 30, 2011 and 2010.

GMO’s risk management policy is to use derivative instruments to mitigate price exposure to natural gas price volatility in the market.  The fair value of the portfolio relates to financial contracts that will settle against actual purchases of natural gas and purchased power.  At September 30, 2011, GMO had financial contracts in place to hedge approximately 68%, 70% and 50% of the expected on-peak natural gas and natural gas equivalent purchased power price exposure for 2011, 2012 and 2013, respectively.  GMO has designated its natural gas hedges as economic hedges (non-hedging derivatives).  In connection with GMO’s 2005 Missouri electric rate case, it was agreed that the settlement costs of these contracts would be recognized in fuel expense.  The settlement cost is included in GMO’s FAC.  A regulatory asset has been recordedto reflect the change in the timing of recognition authorized by the MPSC.  To the extent recovery of actual costs incurred is allowed, amounts will not impact earnings, but will impact cash flows due to the timing of the recovery mechanism.

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

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

	September 30					December 31
	2011					2010
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	2.6	$	(0.2	)	$	4.0	$	-
Non-hedging derivatives		20.2		(2.0	)		59.5		(2.5	)
Forward contracts
Non-hedging derivatives		135.4		9.3			202.8		8.9
Option contracts
Non-hedging derivatives		0.4		-			0.2		-
Anticipated debt issuance				-
Forward starting swaps		-		-			350.0		(20.8	)
KCP&L
Futures contracts
Cash flow hedges		2.6		(0.2	)		4.0		-

The fair values of Great Plains Energy’s and KCP&L’s open derivative positions are summarized in the following tables.  The tables contain both derivative instruments designated as hedging instruments as well as non-hedging derivatives under GAAP.  The fair values below are gross values before netting agreements and netting of cash collateral.

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.3		2.0
Total Derivatives		$	9.3	$	2.2
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9
KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

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

Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
Three Months Ended September 30, 2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(5.1	)
Commodity contracts		(0.1	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		2.1
Total	$	-		Total	$	(3.1	)
Year to Date September 30, 2011
Interest rate contracts	$	(5.3	)	Interest charges	$	(11.9	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		2.2		Income tax benefit (expense)		4.7
Total	$	(3.3	)	Total	$	(7.3	)
Three Months Ended September 30, 2010
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	)

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, 2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(2.1	)
Commodity contracts		(0.1	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		0.9
Total	$	-		Total	$	(1.3	)
Year to Date September 30, 2011
Interest rate contracts	$	-		Interest charges	$	(6.5	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		2.6
Total	$	(0.1	)	Total	$	(4.0	)
Three Months Ended September 30, 2010
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	)

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, 2011	(millions)				(millions)
Commodity contracts	$	(2.2	)	Fuel	$	(0.6	)
Total	$	(2.2	)	Total	$	(0.6	)
Year to Date September 30, 2011
Commodity contracts	$	(3.5	)	Fuel	$	(3.5	)
Total	$	(3.5	)	Total	$	(3.5	)
Three Months Ended September 30, 2010
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	)

Great Plains Energy’s income statement reflects gains (losses) for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $(0.6) million and $0.4 million, respectively, for the three months ended and year to date September 30, 2011, and $(1.6) million and an insignificant amount, respectively, for the same periods in 2010.

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
	2011			2010			2011			2010
	(millions)
Current assets	$	11.5		$	12.0		$	11.5		$	12.0
Current liabilities		(94.5	)		(101.5	)		(64.7	)		(71.6	)
Deferred income taxes		32.3			34.8			20.7			23.2
Total	$	(50.7	)	$	(54.7	)	$	(32.5	)	$	(36.4	)

Great Plains Energy’s accumulated OCI in the table above at September 30, 2011, includes $20.3 million that is expected to be reclassified to expenses over the next twelve months.  KCP&L’s accumulated OCI includes $8.9 million that is expected to be reclassified to expense over the next twelve months.

XML

Consolidated Balance Sheets (Unaudited) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 8.9	$ 10.8
Funds on deposit	1.4	5.2
Receivables, net	275.6	241.7
Accounts receivable pledged as collateral	95.0	95.0
Fuel inventories, at average cost	72.2	85.1
Materials and supplies, at average cost	137.6	132.8
Deferred refueling outage costs	33.4	9.6
Refundable income taxes	15.4	2.1
Deferred income taxes	6.7	14.3
Derivative instruments	1.2	1.1
Prepaid expenses and other assets	17.2	13.9
Total	664.6	611.6
Utility Plant, at Original Cost
Electric	10,821.5	10,536.9
Less-accumulated depreciation	4,184.4	4,031.3
Net utility plant in service	6,637.1	6,505.6
Construction work in progress	260.3	307.5
Nuclear fuel, net of amortization	77.3	79.2
Total	6,974.7	6,892.3
Investments and Other Assets
Nuclear decommissioning trust fund	125.5	129.2
Regulatory assets	977.2	924.0
Goodwill	169.0	169.0
Derivative instruments	8.1	7.8
Other	86.0	84.3
Total	1,365.8	1,314.3
Total	9,005.1	8,818.2
Current Liabilities
Notes payable	28.0	9.5
Collateralized note payable	95.0	95.0
Commercial paper	10.5	263.5
Current maturities of long-term debt	951.4	485.7
Accounts payable	193.7	276.3
Accrued taxes	91.9	26.6
Accrued interest	69.3	75.4
Accrued compensation and benefits	38.2	46.8
Pension and post-retirement liability	4.1	4.1
Derivative instruments	0	20.8
Other	29.0	35.6
Total	1,511.1	1,339.3
Deferred Credits and Other Liabilities
Deferred income taxes	638.9	518.3
Deferred tax credits	131.9	133.4
Asset retirement obligations	147.2	143.3
Pension and post-retirement liability	446.0	427.5
Regulatory liabilities	257.8	258.2
Other	99.1	129.4
Total	1,720.9	1,610.1
Common shareholders' equity
Common Stock	2,328.5	2,324.4
Retained earnings	711.9	626.5
Treasury stock	(5.6)	(8.9)
Accumulated other comprehensive gain (loss)	(52.0)	(56.1)
Total	2,982.8	2,885.9
Noncontrolling interest	1.2	1.2
Cumulative preferred stock
3.80% - 100,000 shares issued	10.0	10.0
4.50% - 100,000 shares issued	10.0	10.0
4.20% - 70,000 shares issued	7.0	7.0
4.35% - 120,000 shares issued	12.0	12.0
Total	39.0	39.0
Long-term debt	2,750.1	2,942.7
Total	5,773.1	5,868.8
Commitments and Contingencies
Total	9,005.1	8,818.2
KANSAS CITY POWER AND LIGHT CO [Member]
Current Assets
Cash and cash equivalents	3.2	3.6
Funds on deposit	0.2	0.4
Receivables, net	223.1	169.4
Accounts receivable pledged as collateral	95.0	95.0
Fuel inventories, at average cost	42.0	44.9
Materials and supplies, at average cost	98.7	94.4
Deferred refueling outage costs	33.4	9.6
Refundable income taxes	13.9	9.0
Deferred income taxes	0	5.6
Prepaid expenses and other assets	15.2	10.0
Total	524.7	441.9
Utility Plant, at Original Cost
Electric	7,762.6	7,540.9
Less-accumulated depreciation	3,209.0	3,104.4
Net utility plant in service	4,553.6	4,436.5
Construction work in progress	181.9	227.6
Nuclear fuel, net of amortization	77.3	79.2
Total	4,812.8	4,743.3
Investments and Other Assets
Nuclear decommissioning trust fund	125.5	129.2
Regulatory assets	700.6	679.6
Other	35.8	32.3
Total	861.9	841.1
Total	6,199.4	6,026.3
Current Liabilities
Notes payable	0	0
Collateralized note payable	95.0	95.0
Commercial paper	10.5	263.5
Current maturities of long-term debt	162.7	150.3
Accounts payable	151.2	201.7
Accrued taxes	66.1	21.3
Accrued interest	34.1	26.2
Accrued compensation and benefits	38.2	46.8
Pension and post-retirement liability	2.6	2.6
Deferred incomes taxes	1.4	0
Other	15.1	7.8
Total	576.9	815.2
Deferred Credits and Other Liabilities
Deferred income taxes	776.6	692.0
Deferred tax credits	128.4	129.4
Asset retirement obligations	132.2	129.7
Pension and post-retirement liability	426.1	407.3
Regulatory liabilities	135.6	141.3
Other	65.1	76.7
Total	1,664.0	1,576.4
Common shareholders' equity
Common Stock	1,563.1	1,563.1
Retained earnings	526.1	478.3
Accumulated other comprehensive gain (loss)	(32.5)	(36.4)
Total	2,056.7	2,005.0
Cumulative preferred stock
Long-term debt	1,901.8	1,629.7
Total	3,958.5	3,634.7
Commitments and Contingencies
Total	$ 6,199.4	$ 6,026.3

XML

FAIR VALUE MEASUREMENTS (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2011

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Balances of financial assets measured at fair value

					Fair Value Measurements Using
Description	September 30 2011		Netting(d)		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Derivative instruments (a)	$	-	$	-	$	-	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		75.2		-		75.2		-		-
Debt securities
U.S. Treasury		14.7		-		14.7		-		-
U.S. Agency		3.6		-		-		3.6		-
State and local obligations		2.6		-		-		2.6		-
Corporate bonds		25.3		-		-		25.3		-
Foreign governments		0.7		-		-		0.7		-
Other		0.3		-		-		0.3		-
Total nuclear decommissioning trust		122.4		-		89.9		32.5		-
Total		122.4		-		89.9		32.5		-

Other Great Plains Energy
Assets
Derivative instruments (a)	$	9.3	$	-	$	-	$	4.8	$	4.5
SERP rabbi trust (c)
Equity securities		0.2		-		0.2		-		-
Debt securities		0.2		-		-		0.2		-
Total SERP rabbi trust		0.4		-		0.2		0.2		-
Total		9.7		-		0.2		5.0		4.5

Great Plains Energy
Assets
Derivative instruments (a)	$	9.3	$	-	$	-	$	4.8	$	4.5
Nuclear decommissioning trust (b)		122.4		-		89.9		32.5		-
SERP rabbi trust (c)		0.4		-		0.2		0.2		-
Total		132.1		-		90.1		37.5		4.5

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

(b)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $3.1 million and $2.7 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(c)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $20.4 million and $14.6 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)   Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty.  At September 30, 2011, and December 31, 2010, Great Plains Energy netted $2.2 million and $2.5 million, respectively, of cash collateral posted with counterparties.

						Fair Value Measurements Using
Description	December 31 2010		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Derivative instruments (a)	$	-	$	(0.1	)	$	0.1	$	-	$	-
Nuclear decommissioning trust (b)
Equity securities		85.5		-			85.5		-		-
Debt securities
U.S. Treasury		8.9		-			8.9		-		-
U.S. Agency		4.8		-			-		4.8		-
State and local obligations		2.5		-			-		2.5		-
Corporate bonds		23.7		-			-		23.7		-
Foreign governments		0.7		-			-		0.7		-
Other		0.4		-			-		0.4		-
Total nuclear decommissioning trust		126.5		-			94.4		32.1		-
Total		126.5		(0.1	)		94.5		32.1		-

Other Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.5	)	$	0.5	$	5.2	$	3.7
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		7.0		-			-		7.0		-
Total SERP rabbi trust		7.2		-			0.2		7.0		-
Total		16.1		(0.5	)		0.7		12.2		3.7

Great Plains Energy
Assets
Derivative instruments (a)	$	8.9	$	(0.6	)	$	0.6	$	5.2	$	3.7
Nuclear decommissioning trust (b)		126.5		-			94.4		32.1		-
SERP rabbi trust (c)		7.2		-			0.2		7.0		-
Total		142.6		(0.6	)		95.2		44.3		3.7

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

(b)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $3.1 million and $2.7 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(c)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $20.4 million and $14.6 million at September 30, 2011, and December 31, 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)   Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty.  At September 30, 2011, and December 31, 2010, Great Plains Energy netted $2.2 million and $2.5 million, respectively, of cash collateral posted with counterparties.

Balances of financial liabilities measured at fair value

			Fair Value Measurements Using
Description	September 30 2011	Netting(d)	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
KCP&L	(millions)

Liabilities
Derivative instruments (a)		-		(0.2	)		0.2		-		-
Total	$	-	$	(0.2	)	$	0.2	$	-	$	-
Other Great Plains Energy
Liabilities
Derivative instruments (a)		-		(2.0	)		2.0		-		-
Total	$	-	$	(2.0	)	$	2.0	$	-	$	-
Great Plains Energy
Liabilities
Derivative instruments (a)		-		(2.2	)		2.2		-		-
Total	$	-	$	(2.2	)	$	2.2	$	-	$	-

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

(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, 2011, and December 31, 2010, Great Plains Energy netted $2.2 million and $2.5 million, respectively, of cash collateral posted with counterparties.

			Fair Value Measurements Using
Description	December 31 2010	Netting(d)	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
KCP&L	(millions)

Liabilities
Derivative instruments (a)		-		(0.1	)		0.1		-		-
Total	$	-	$	(0.1	)	$	0.1	$	-	$	-
Other Great Plains Energy
Liabilities
Derivative instruments (a)		20.8		(3.0	)		3.0		20.8		-
Total	$	20.8	$	(3.0	)	$	3.0	$	20.8	$	-
Great Plains Energy
Liabilities
Derivative instruments (a)		20.8		(3.1	)		3.1		20.8		-
Total	$	20.8	$	(3.1	)	$	3.1	$	20.8	$	-

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

(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, 2011, and December 31, 2010, Great Plains Energy netted $2.2 million and $2.5 million, respectively, of cash collateral posted with counterparties.

Reconciled balances for Level 3 assets, net measured at fair value

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

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other Great
	Plains Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains or (losses)
Included in non-operating income		11.1
Settlements		(10.3	)
Balance September 30, 2011	$	4.5
Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at September 30, 2011	$	1.2

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
	KCP&L			Plains 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	$	-		$	-		$	-

XML

LEGAL PROCEEDINGS (Details) (USD $) In Millions	Sep. 30, 2011
Kansas City Power and Light Company [Member] | Spent Nuclear Fuel and Radioactive Waste [Member]
Loss Contingencies [Line Items]
Amount of pending claims against the United States in the U.S. Court	$ 14.1
Amount awarded but subject to appeal	5.0
KCPL Greater Missouri Operations Company [Member] | Price Reporting Litigation [Member]
Loss Contingencies [Line Items]
Approximate amount of refunds received as a net purchaser of power through settlements with sellers of power	8.0
Estimated additional refunds entitled to receive	12.0
Amount of claims addressed under refund proceedings	5.1
Total Wolf Creek including KCPL [Member] | Pending or Threatened Litigation [Member]
Loss Contingencies [Line Items]
Amount awarded but subject to appeal	$ 10.6

XML

EQUITY COMPENSATION (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010	Sep. 30, 2011		Sep. 30, 2010
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
Compensation expense	$ 1.2		$ 0.8	$ 4.5		$ 3.4
Income tax benefits	0.4		0.2	1.8		0.8
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Expected volatility, minimum (in hundredths)				28.00%
Expected volatility, maximum (in hundredths)				30.00%
Expected dividend yields, minimum (in hundredths)				3.98%
Expected dividend yields, maximum (in hundredths)				4.35%
Risk-free interest rates, minimum (in hundredths)				0.61%
Risk-free interest rates, maximum (in hundredths)				1.15%
Kansas City Power and Light Company [Member]
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
Compensation expense	0.8		0.6	3.1		2.4
Income tax benefits	0.2		0.2	1.2		0.4
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Balance at beginning of period (in number of shares)				431,784
Granted and issued (in number of shares)				140,128
Earned (in number of shares)				(68,258)
Forfeited (in number of shares)				(61,612)
Balance at end of period (in number of shares)	442,042			442,042
Weighted-average grant date fair value per share price, beginning of period (in dollars per shares)				$ 18.01	[1]
Granted and issued (in dollars per shares)	$ 26.30		$ 0.00	$ 26.15	[1]	$ 23.37
Earned (in dollars per shares)				$ 11.04	[1]
Forfeited (in dollars per shares)	$ 22.38	[1]		$ 22.38	[1]
Weighted-average grant date fair value per share price, end of period (in dollars per shares)	$ 21.06	[1]		$ 21.06	[1]
Remaining weighted-average contractual term (in years)				1.2
Total unrecognized compensation expense, net of forfeiture rates	4.0			4.0
Total fair value of shares vested				0.8
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Balance at beginning of period (in number of shares)				406,657
Granted and issued (in number of shares)				182,385
Vested (in number of shares)				(149,688)
Forfeited (in number of shares)				(53,171)
Balance at end of period (in number of shares)	386,183			386,183
Weighted-average grant date fair value per share price, beginning of period (in dollars per shares)				$ 16.23	[1]
Granted and issued (in dollars per shares)	$ 17.89		$ 18.32	$ 19.03	[1]	$ 17.80
Vested (in dollars per shares)				$ 17.29	[1]
Forfeited (in dollars per shares)	$ 17.25	[1]		$ 17.25	[1]
Weighted-average grant date fair value per share price, end of period (in dollars per shares)	$ 17.06	[1]		$ 17.06	[1]
Remaining weighted-average contractual term (in years)				1.6
Total unrecognized compensation expense, net of forfeiture rates	3.4			3.4
Total fair value of shares vested	$ 0		$ 0.9	$ 2.6		$ 7.3

[1] weighted-average

XML

SHORT-TERM BORROWINGS AND SHORT-TERM BANK LINES OF CREDIT (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Line of Credit Facility [Line Items]
Amount of outstanding cash borrowings	$ 28.0	$ 9.5
Amount of outstanding commercial paper borrowings	10.5	263.5
Kansas City Power and Light Company [Member]
Line of Credit Facility [Line Items]
Amount of revolving credit facility	600.0
Revolving credit facility expiration date	August 2013
Covenant term - amount considered as default	50.0
Amount of outstanding cash borrowings	0	0
Amount of outstanding commercial paper borrowings	10.5	263.5
Weighted average interest rate from outstanding borrowings	0.35%	0.41%
Line of Credit Facility, Covenant Compliance	in compliance
Amount of letters of credit outstanding	31.5	24.4
Covenant Term Ratio Of Consolidated Indebtedness To Consolidated Capitalization Ratio, Maximum	0.65
KCPL Greater Missouri Operations Company [Member]
Line of Credit Facility [Line Items]
Amount of revolving credit facility	450.0
Revolving credit facility expiration date	August 2013
Covenant term - amount considered as default	50.0
Amount of outstanding cash borrowings	0	0
Line of Credit Facility, Covenant Compliance	in compliance
Amount of letters of credit outstanding	13.2	13.2
Covenant Term Ratio Of Consolidated Indebtedness To Consolidated Capitalization Ratio, Maximum	0.65
Line of credit facility with group of banks [Member]
Line of Credit Facility [Line Items]
Amount of revolving credit facility	200.0
Revolving credit facility expiration date	August 2013
Covenant term - amount considered as default	50.0
Weighted average interest rate from outstanding borrowings	3.00%	3.06%
Line of Credit Facility, Covenant Compliance	in compliance
Amount of letters of credit outstanding	$ 11.6	$ 15.8
Covenant Term Ratio Of Consolidated Indebtedness To Consolidated Capitalization Ratio, Maximum	0.65

XML

SEGMENTS AND RELATED INFORMATION (Details) (USD $) In Millions	3 Months Ended		9 Months Ended			12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011		Sep. 30, 2010	Dec. 31, 2010
Segment Reporting Information [Line Items]
Operating revenues	$ 773.7	$ 728.8	$ 1,831.7		$ 1,787.7
Depreciation and amortization	(65.9)	(85.3)	(205.9)		(248.5)
Interest charges	(60.8)	(45.5)	(156.0)		(138.7)
Income tax expense	(75.4)	(70.4)	(90.6)		(112.1)
Loss from equity investments	0	0	(0.1)		(0.9)
Net income	126.6	132.0	172.3		216.7
Net income attributable to Great Plains Energy	126.5	132.0	172.3		216.6
Assets	9,005.1		9,005.1			8,818.2
Capital expenditures			317.8	[1]		618.1	[1]
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	773.7	728.8	1,831.7		1,787.7
Depreciation and amortization	(65.9)	(85.3)	(205.9)		(248.5)
Interest charges	50.2	34.8	124.8		107.4
Income tax expense	82.9	77.0	109.8		125.4
Net income attributable to Great Plains Energy	133.9	136.2	189.9		232.8
Assets	9,365.0		9,365.0			9,152.7
Capital expenditures			317.8	[1]		618.1	[1]
Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0		0
Depreciation and amortization	0	0	0		0
Interest charges	10.6	10.7	31.2		31.3
Income tax expense	(7.5)	(6.6)	(19.2)		(13.3)
Net income attributable to Great Plains Energy	(7.4)	(4.2)	(17.6)		(16.2)
Assets	72.1		72.1			66.3
Capital expenditures			0	[1]		0	[1]
Eliminations Member [Member]
Segment Reporting Information [Line Items]
Assets	(432.0)		(432.0)			(400.8)
Capital expenditures			$ 0	[1]		$ 0	[1]

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

XML

TAXES (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Components of income tax expense (benefit)

	Three Months Ended						Year to Date
	September 30						September 30
Great Plains Energy	2011			2010			2011			2010
Current income taxes	(millions)
Federal	$	(10.2	)	$	(7.2	)	$	(6.4	)	$	(8.1	)
State		(0.8	)		(2.0	)		(4.8	)		0.3
Foreign		-			(0.2	)		(0.4	)		0.2
Total		(11.0	)		(9.4	)		(11.6	)		(7.6	)
Deferred income taxes
Federal		74.7			73.5			103.6			108.2
State		13.0			14.6			20.4			18.8
Total		87.7			88.1			124.0			127.0
Noncurrent income taxes
Federal		-			(6.8	)		(18.0	)		(1.3	)
State		-			(1.0	)		(1.9	)		(0.3	)
Foreign		(0.6	)		0.2			(0.4	)		0.2
Total		(0.6	)		(7.6	)		(20.3	)		(1.4	)
Investment tax credit
Deferral		-			-			-			(4.1	)
Amortization		(0.7	)		(0.7	)		(1.5	)		(1.8	)
Total		(0.7	)		(0.7	)		(1.5	)		(5.9	)
Income tax expense	$	75.4		$	70.4		$	90.6		$	112.1

	Three Months Ended						Year to Date
	September 30						September 30
KCP&L	2011			2010			2011			2010
Current income taxes	(millions)
Federal	$	(10.2	)	$	(15.3	)	$	(7.8	)	$	22.5
State		(0.9	)		(2.6	)		(0.4	)		4.6
Total		(11.1	)		(17.9	)		(8.2	)		27.1
Deferred income taxes
Federal		53.5			63.9			73.4			53.9
State		9.3			11.7			13.8			9.5
Total		62.8			75.6			87.2			63.4
Noncurrent income taxes
Federal		1.5			(2.4	)		(9.1	)		(1.5	)
State		0.1			(0.3	)		(1.0	)		(0.1	)
Total		1.6			(2.7	)		(10.1	)		(1.6	)
Investment tax credit
Deferral		-			-			-			(4.1	)
Amortization		(0.5	)		(0.5	)		(1.0	)		(1.2	)
Total		(0.5	)		(0.5	)		(1.0	)		(5.3	)
Income tax expense	$	52.8		$	54.5		$	67.9		$	83.6

Income tax expense (benefit) and effective income tax rates

Great Plains Energy	Income Tax Expense						Income Tax Rate
Three Months Ended September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	70.6		$	70.8			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.8			(0.9	)		0.9			(0.4	)
Amortization of investment tax credits		(0.7	)		(0.7	)		(0.3	)		(0.4	)
Federal income tax credits		(2.9	)		(2.0	)		(1.4	)		(0.9	)
State income taxes		8.1			7.5			4.0			3.7
Changes in uncertain tax positions, net		(2.7	)		0.3			(1.3	)		0.2
Valuation allowance		-			(2.9	)		-			(1.4	)
Other		1.2			(1.7	)		0.4			(1.0	)
Total	$	75.4		$	70.4			37.3	%		34.8	%

Great Plains Energy	Income Tax Expense						Income Tax Rate
Year to Date September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	92.0		$	115.0			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		3.7			(6.0	)		1.4			(1.8	)
Amortization of investment tax credits		(1.5	)		(1.8	)		(0.6	)		(0.5	)
Federal income tax credits		(9.7	)		(6.1	)		(3.7	)		(1.8	)
State income taxes		11.1			12.0			4.2			3.7
Medicare Part D subsidy legislation		-			2.8			-			0.8
Changes in uncertain tax positions, net		(4.0	)		0.3			(1.5	)		0.1
Valuation allowance		(2.2	)		(2.9	)		(0.8	)		(0.9	)
Other		1.2			(1.2	)		0.5			(0.5	)
Total	$	90.6		$	112.1			34.5	%		34.1	%

KCP&L	Income Tax Expense						Income Tax Rate
Three Months Ended September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	48.3		$	51.5			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.7			(1.1	)		1.2			(0.8	)
Amortization of investment tax credits		(0.5	)		(0.5	)		(0.4	)		(0.4	)
Federal income tax credits		(2.9	)		(1.9	)		(2.1	)		(1.3	)
State income taxes		5.7			5.7			4.1			3.9
Changes in uncertain tax positions		-			0.1			-			0.1
Other		0.5			0.7			0.4			0.6
Total	$	52.8		$	54.5			38.2	%		37.1	%

KCP&L	Income Tax Expense						Income Tax Rate
Year to Date September 30	2011			2010			2011			2010
	(millions)
Federal statutory income tax	$	66.7		$	85.3			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		3.3			(5.2	)		1.7			(2.2	)
Amortization of investment tax credits		(1.0	)		(1.2	)		(0.5	)		(0.5	)
Federal income tax credits		(9.6	)		(6.0	)		(5.1	)		(2.5	)
State income taxes		7.7			8.8			4.0			3.6
Medicare Part D subsidy legislation		-			2.8			-			1.2
Changes in uncertain tax positions		0.4			0.1			0.2			0.1
Other		0.4			(1.0	)		0.3			(0.4	)
Total	$	67.9		$	83.6			35.6	%		34.3	%

Liability for unrecognized tax benefits

	Great Plains Energy						KCP&L
	September 30			December 31			September 30			December 31
	2011			2010			2011			2010
	(millions)
Beginning balance	$	42.0		$	51.4		$	19.1		$	20.9
Additions for current year tax positions		1.1			2.7			-			1.3
Additions for prior year tax positions		2.5			2.1			2.3			1.5
Reductions for prior year tax positions		(20.8	)		(10.6	)		(12.4	)		(1.6	)
Settlements		-			(3.8	)		-			(2.9	)
Statute expirations		-			(0.3	)		-			(0.1	)
Foreign currency translation adjustments		(0.4	)		0.5			-			-
Ending balance	$	24.4		$	42.0		$	9.0		$	19.1