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 June 30, 2012

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 its 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 August 6, 2012, Great Plains Energy Incorporated had 153,430,889 shares of common stock outstanding.  On August 6, 2012,

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 2011 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 2011 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

2

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 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 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
EBITDA	Earnings before interest, income taxes, depreciation and amortization
ECA	Energy Cost Adjustment
EGU	Electric steam generating unit
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
FERC	The Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GMO	KCP&L Greater Missouri Operations Company, a wholly owned subsidiary of    Great Plains Energy
Great Plains Energy	Great Plains Energy Incorporated and its subsidiaries
IRS	Internal Revenue Service
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
KCP&L Receivables   Company	Kansas City Power & Light Receivables Company, a wholly owned    subsidiary of KCP&L
KDHE	Kansas Department of Health and Environment
kV	Kilovolt
KW	Kilowatt
kWh	Kilowatt hour
L&P	St. Joseph Light & Power, a division of GMO
MACT	Maximum achievable control technology

3

Abbreviation or Acronym	Definition
MAP-21	Moving Ahead for Progress in the 21st Century Act
MATS	Mercury and Air Toxics Standards
MD&A	Management’s Discussion and Analysis of Financial Condition and    Results of Operations
MDNR	Missouri Department of Natural Resources
MEEIA	Missouri Energy Efficiency Investment Act
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
MWh	Megawatt hour
NAAQS	National Ambient Air Quality Standard
NERC	North American Electric Reliability Corporation
NEIL	Nuclear Electric Insurance Limited
NOL	Net operating loss
NOx	Nitrogen oxide
NPNS	Normal purchases and normal sales
NRC	Nuclear Regulatory Commission
OCI	Other Comprehensive Income
PCB	Polychlorinated biphenyls
Ppm	Parts per million
PRB	Powder River Basin
QCA	Quarterly Cost Adjustment
RTO	Regional Transmission Organization
SCR	Selective catalytic reduction
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Syncora	Syncora Guarantee Inc.
Transource	Transource Energy, LLC
WCNOC	Wolf Creek Nuclear Operating Corporation
Westar	Westar Energy, Inc., a Kansas utility company
Wolf Creek	Wolf Creek Generating Station

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PART 1 - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Great Plains Energy Incorporated
Unaudited Consolidated Balance Sheets
Unaudited Consolidated Statements of Income and Comprehensive Income
Unaudited Consolidated Statements of Cash Flows
Unaudited Consolidated Statements of Common Shareholders’ Equity and Noncontrolling Interest
Kansas City Power & Light Company
Unaudited Consolidated Balance Sheets
Unaudited Consolidated Statements of Income and Comprehensive Income
Unaudited Consolidated Statements of Cash Flows
Unaudited Consolidated Statements of Common Shareholder’s Equity
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 and Other Employee Benefits
	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

5

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets
(Unaudited)
	June 30		December 31
	2012		2011
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	6.9	$	6.2
Funds on deposit		1.5		1.4
Receivables, net		206.1		231.2
Accounts receivable pledged as collateral		162.0		95.0
Fuel inventories, at average cost		102.7		89.0
Materials and supplies, at average cost		146.0		140.3
Deferred refueling outage costs		18.5		27.5
Refundable income taxes		5.4		0.3
Deferred income taxes		28.5		7.5
Derivative instruments		0.9		1.0
Prepaid expenses and other assets		27.2		19.7
Total		705.7		619.1
Utility Plant, at Original Cost
Electric		11,039.5		10,924.8
Less - accumulated depreciation		4,343.3		4,235.8
Net utility plant in service		6,696.2		6,689.0
Construction work in progress		406.2		287.9
Nuclear fuel, net of amortization of $141.8 and $132.7		87.8		76.6
Total		7,190.2		7,053.5
Investments and Other Assets
Nuclear decommissioning trust fund		144.9		135.3
Regulatory assets		1,029.5		1,058.2
Goodwill		169.0		169.0
Derivative instruments		5.8		6.8
Other		67.8		76.1
Total		1,417.0		1,445.4
Total	$	9,312.9	$	9,118.0
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

6

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets
(Unaudited)
	June 30			December 31
	2012			2011
LIABILITIES AND CAPITALIZATION	(millions, except share amounts)
Current Liabilities
Notes payable	$	31.0		$	22.0
Collateralized note payable		162.0			95.0
Commercial paper		91.0			267.0
Current maturities of long-term debt		507.1			801.4
Accounts payable		222.5			275.6
Accrued taxes		64.4			25.8
Accrued interest		73.1			76.9
Accrued compensation and benefits		39.4			40.8
Pension and post-retirement liability		4.4			4.4
Other		24.9			26.0
Total		1,219.8			1,634.9
Deferred Credits and Other Liabilities
Deferred income taxes		678.3			628.6
Deferred tax credits		130.0			131.2
Asset retirement obligations		154.3			149.6
Pension and post-retirement liability		452.3			461.9
Regulatory liabilities		276.3			268.5
Other		102.3			101.1
Total		1,793.5			1,740.9
Capitalization
Great Plains Energy common shareholders' equity
Common stock - 250,000,000 shares authorized without par value
153,655,260 and 136,406,306 shares issued, stated value		2,620.9			2,330.6
Retained earnings		674.7			684.7
Treasury stock - 240,468 and 264,567 shares, at cost		(5.0	)		(5.6	)
Accumulated other comprehensive loss		(43.6	)		(49.8	)
Total		3,247.0			2,959.9
Noncontrolling interest		0.2			1.0
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)		3,013.4			2,742.3
Total		6,299.6			5,742.2
Commitments and Contingencies (Note 10)
Total	$	9,312.9		$	9,118.0
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Income and Comprehensive Income
(Unaudited)
	Three Months Ended						Year to Date
	June 30						June 30
	2012			2011			2012			2011
Operating Revenues	(millions, except per share amounts)
Electric revenues	$	603.6		$	565.1		$	1,083.3		$	1,058.0
Operating Expenses
Fuel		138.1			114.4			257.4			219.3
Purchased power		26.9			55.4			51.6			110.3
Transmission of electricity by others		8.8			7.0			16.1			14.5
Utility operating and maintenance expenses		164.1			161.1			327.2			318.6
Voluntary separation program		-			3.0			-			12.7
Depreciation and amortization		67.9			67.6			135.3			140.0
General taxes		45.0			40.3			89.5			82.3
Other		2.8			0.7			7.2			3.5
Total		453.6			449.5			884.3			901.2
Operating income		150.0			115.6			199.0			156.8
Non-operating income		1.6			0.8			2.5			4.4
Non-operating expenses		(5.8	)		(2.8	)		(7.6	)		(5.0	)
Interest charges		(55.8	)		(50.3	)		(122.7	)		(95.2	)
Income before income tax expense and loss from equity
investments		90.0			63.3			71.2			61.0
Income tax expense		(31.8	)		(19.8	)		(22.3	)		(15.2	)
Loss from equity investments, net of income taxes		(0.1	)		(0.1	)		(0.1	)		(0.1	)
Net income		58.1			43.4			48.8			45.7
Less: Net loss attributable to noncontrolling interest		-			-			0.2			0.1
Net income attributable to Great Plains Energy		58.1			43.4			49.0			45.8
Preferred stock dividend requirements		0.4			0.4			0.8			0.8
Earnings available for common shareholders	$	57.7		$	43.0		$	48.2		$	45.0
Average number of basic common shares outstanding		139.6			135.6			137.7			135.5
Average number of diluted common shares outstanding		142.0			138.9			140.6			138.6
Basic earnings per common share	$	0.41		$	0.32		$	0.35		$	0.33
Diluted earnings per common share	$	0.41		$	0.31		$	0.34		$	0.32
Cash dividends per common share	$	0.2125		$	0.2075		$	0.425		$	0.415
Comprehensive Income
Net income	$	58.1		$	43.4		$	48.8		$	45.7
Other comprehensive income
Derivative hedging activity
Gain (loss) on derivative hedging instruments		0.1			(5.9	)		(0.2	)		(5.4	)
Income tax benefit		-			2.2			0.1			2.1
Net gain (loss) on derivative hedging instruments		0.1			(3.7	)		(0.1	)		(3.3	)
Reclassification to expenses, net of tax		3.1			2.5			6.2			4.2
Derivative hedging activity, net of tax		3.2			(1.2	)		6.1			0.9
Defined benefit pension plans
Amortization of net gains included in net periodic
benefit costs		0.1			0.2			0.2			0.2
Income tax expense		(0.1	)		(0.1	)		(0.1	)		(0.1	)
Change in unrecognized pension expense, net of tax		-			0.1			0.1			0.1
Total other comprehensive income (loss)		3.2			(1.1	)		6.2			1.0
Comprehensive income		61.3			42.3			55.0			46.7
Less:  comprehensive loss attributable to
noncontrolling interest		-			-			0.2			0.1
Comprehensive income attributable to Great Plains Energy	$	61.3		$	42.3		$	55.2		$	46.8
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 June 30	2012			2011
Cash Flows from Operating Activities	(millions)
Net income	$	48.8		$	45.7
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		135.3			140.0
Amortization of:
Nuclear fuel		9.1			5.9
Other		9.2			1.3
Deferred income taxes, net		26.8			36.3
Investment tax credit amortization		(1.2	)		(0.8	)
Loss from equity investments, net of income taxes		0.1			0.1
Other operating activities (Note 2)		(62.8	)		(157.4	)
Net cash from operating activities		165.3			71.1
Cash Flows from Investing Activities
Utility capital expenditures		(263.4	)		(193.2	)
Allowance for borrowed funds used during construction		(2.7	)		(2.1	)
Purchases of nuclear decommissioning trust investments		(11.7	)		(11.2	)
Proceeds from nuclear decommissioning trust investments		10.0			9.4
Other investing activities		(7.5	)		(13.6	)
Net cash from investing activities		(275.3	)		(210.7	)
Cash Flows from Financing Activities
Issuance of common stock		290.3			3.0
Issuance of long-term debt		-			349.7
Issuance fees		(2.6	)		(2.5	)
Repayment of long-term debt		(13.4	)		(448.3	)
Net change in short-term borrowings		(167.0	)		295.7
Net change in collateralized short-term borrowings		67.0			-
Dividends paid		(58.7	)		(57.2	)
Other financing activities		(4.9	)		(3.8	)
Net cash from financing activities		110.7			136.6
Net Change in Cash and Cash Equivalents		0.7			(3.0	)
Cash and Cash Equivalents at Beginning of Year		6.2			10.8
Cash and Cash Equivalents at End of Period	$	6.9		$	7.8
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 June 30	2012						2011
	Shares			Amount			Shares			Amount
Common Stock	(millions, except share amounts)
Beginning balance		136,406,306		$	2,330.6			136,113,954		$	2,324.4
Issuance of common stock		17,248,954			290.3			155,345			3.1
Equity compensation expense, net of forfeitures					0.1						0.1
Unearned Compensation
Issuance of restricted common stock					(3.2	)					(2.9	)
Forfeiture of restricted common stock					1.0						0.8
Compensation expense recognized					1.6						1.2
Other					0.5						0.1
Ending balance		153,655,260			2,620.9			136,269,299			2,326.8
Retained Earnings
Beginning balance					684.7						626.5
Net income attributable to Great Plains Energy					49.0						45.8
Loss on reissuance of treasury stock					(0.3	)					(0.5	)
Dividends:
Common stock					(57.9	)					(56.4	)
Preferred stock - at required rates					(0.8	)					(0.8	)
Performance shares					-						(0.3	)
Ending balance					674.7						614.3
Treasury Stock
Beginning balance		(264,567	)		(5.6	)		(400,889	)		(8.9	)
Treasury shares acquired		(145,701	)		(2.9	)		(88,400	)		(2.2	)
Treasury shares reissued		169,800			3.5			221,296			4.8
Ending balance		(240,468	)		(5.0	)		(267,993	)		(6.3	)
Accumulated Other Comprehensive Income (Loss)
Beginning balance					(49.8	)					(56.1	)
Derivative hedging activity, net of tax					6.1						0.9
Change in unrecognized pension expense, net of tax					0.1						0.1
Ending balance					(43.6	)					(55.1	)
Total Great Plains Energy Common Shareholders' Equity				$	3,247.0					$	2,879.7
Noncontrolling Interest
Beginning balance				$	1.0					$	1.2
Net loss attributable to noncontrolling interest					(0.2	)					(0.1	)
Distribution					(0.6	)					-
Ending balance				$	0.2					$	1.1
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

10

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
(Unaudited)
	June 30		December 31
	2012		2011
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	2.4	$	1.9
Funds on deposit		0.1		0.1
Receivables, net		160.8		172.9
Accounts receivable pledged as collateral		106.0		95.0
Fuel inventories, at average cost		71.7		59.0
Materials and supplies, at average cost		105.6		101.1
Deferred refueling outage costs		18.5		27.5
Refundable income taxes		3.8		5.7
Deferred income taxes		4.8		-
Prepaid expenses and other assets		23.6		16.0
Total		497.3		479.2
Utility Plant, at Original Cost
Electric		7,906.2		7,829.3
Less - accumulated depreciation		3,314.0		3,243.0
Net utility plant in service		4,592.2		4,586.3
Construction work in progress		311.3		203.5
Nuclear fuel, net of amortization of $141.8 and $132.7		87.8		76.6
Total		4,991.3		4,866.4
Investments and Other Assets
Nuclear decommissioning trust fund		144.9		135.3
Regulatory assets		760.8		780.7
Other		23.5		30.6
Total		929.2		946.6
Total	$	6,417.8	$	6,292.2
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

11

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
(Unaudited)
	June 30			December 31
	2012			2011
LIABILITIES AND CAPITALIZATION	(millions, except share amounts)
Current Liabilities
Collateralized note payable	$	106.0		$	95.0
Commercial paper		91.0			227.0
Current maturities of long-term debt		0.4			12.7
Accounts payable		183.2			209.7
Affiliated payables		251.2			5.1
Accrued taxes		43.7			20.6
Accrued interest		26.5			30.0
Accrued compensation and benefits		39.4			40.8
Pension and post-retirement liability		3.0			3.0
Other		13.0			13.7
Total		757.4			657.6
Deferred Credits and Other Liabilities
Deferred income taxes		797.7			772.7
Deferred tax credits		127.0			127.9
Asset retirement obligations		138.6			134.3
Pension and post-retirement liability		431.5			440.9
Regulatory liabilities		146.9			142.8
Other		72.6			68.6
Total		1,714.3			1,687.2
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		509.8			513.8
Accumulated other comprehensive loss		(28.8	)		(31.4	)
Total		2,044.1			2,045.5
Long-term debt (Note 9)		1,902.0			1,901.9
Total		3,946.1			3,947.4
Commitments and Contingencies (Note 10)
Total	$	6,417.8		$	6,292.2
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 Statements of Income and Comprehensive Income
(Unaudited)
	Three Months Ended						Year to Date
	June 30						June 30
	2012			2011			2012			2011
Operating Revenues	(millions)
Electric revenues	$	409.1		$	383.4		$	736.1		$	714.2
Operating Expenses
Fuel		98.7			81.5			183.3			149.7
Purchased power		6.6			20.4			13.6			41.8
Transmission of electricity by others		6.1			4.2			11.1			8.5
Operating and maintenance expenses		115.9			115.6			233.8			230.5
Voluntary separation program		-			2.4			-			9.2
Depreciation and amortization		46.0			48.2			91.7			101.6
General taxes		35.9			33.4			71.1			67.3
Other		-			(0.1	)		-			1.3
Total		309.2			305.6			604.6			609.9
Operating income		99.9			77.8			131.5			104.3
Non-operating income		0.8			0.5			1.3			1.0
Non-operating expenses		(2.7	)		(1.4	)		(3.4	)		(2.4	)
Interest charges		(31.3	)		(27.3	)		(63.7	)		(50.4	)
Income before income tax expense		66.7			49.6			65.7			52.5
Income tax expense		(23.0	)		(16.2	)		(19.7	)		(15.1	)
Net income	$	43.7		$	33.4		$	46.0		$	37.4
Comprehensive Income
Net income	$	43.7		$	33.4		$	46.0		$	37.4
Other comprehensive income
Derivative hedging activity
Gain (loss) on derivative hedging instruments		0.1			(0.1	)		(0.2	)		(0.1	)
Income tax benefit		-			-			0.1			-
Net gain (loss) on derivative hedging instruments		0.1			(0.1	)		(0.1	)		(0.1	)
Reclassification to expenses, net of tax		1.3			1.4			2.7			2.7
Derivative hedging activity, net of tax		1.4			1.3			2.6			2.6
Total other comprehensive income		1.4			1.3			2.6			2.6
Comprehensive income	$	45.1		$	34.7		$	48.6		$	40.0
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 Cash Flows
(Unaudited)
Year to Date June 30	2012			2011
Cash Flows from Operating Activities	(millions)
Net income	$	46.0		$	37.4
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		91.7			101.6
Amortization of:
Nuclear fuel		9.1			5.9
Other		14.9			14.1
Deferred income taxes, net		20.2			24.4
Investment tax credit amortization		(0.9	)		(0.5	)
Other operating activities (Note 2)		(26.1	)		(95.1	)
Net cash from operating activities		154.9			87.8
Cash Flows from Investing Activities
Utility capital expenditures		(208.6	)		(143.0	)
Allowance for borrowed funds used during construction		(1.4	)		(1.2	)
Purchases of nuclear decommissioning trust investments		(11.7	)		(11.2	)
Proceeds from nuclear decommissioning trust investments		10.0			9.4
Net money pool lending		-			12.1
Other investing activities		(6.3	)		(7.8	)
Net cash from investing activities		(218.0	)		(141.7	)
Cash Flows from Financing Activities
Repayment of long-term debt		(12.3	)		(112.8	)
Net change in short-term borrowings		(136.0	)		213.2
Net change in collateralized short-term borrowings		11.0			-
Net money pool borrowings		250.9			2.5
Dividends paid to Great Plains Energy		(50.0	)		(50.0	)
Other		-			(0.1	)
Net cash from financing activities		63.6			52.8
Net Change in Cash and Cash Equivalents		0.5			(1.1	)
Cash and Cash Equivalents at Beginning of Year		1.9			3.6
Cash and Cash Equivalents at End of Period	$	2.4		$	2.5
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 Common Shareholder's Equity
(Unaudited)
Year to Date June 30	2012					2011
	Shares		Amount			Shares		Amount
Common Stock	(millions, except share amounts)
Ending balance		1	$	1,563.1			1	$	1,563.1
Retained Earnings
Beginning balance				513.8					478.3
Net income				46.0					37.4
Dividends:
Common stock held by Great Plains Energy				(50.0	)				(50.0	)
Ending balance				509.8					465.7
Accumulated Other Comprehensive Income (Loss)
Beginning balance				(31.4	)				(36.4	)
Derivative hedging activity, net of tax				2.6					2.6
Ending balance				(28.8	)				(33.8	)
Total Common Shareholder's Equity			$	2,044.1				$	1,995.0
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

15

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 (KCP&L Receivables Company).

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

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

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

Basic and Diluted Earnings per Common Share Calculation

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

16

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

	Three Months Ended				Year to Date
	June 30				June 30
	2012		2011		2012			2011
Income	(millions, except per share amounts)
Net income	$	58.1	$	43.4	$	48.8		$	45.7
Less: net loss attributable to noncontrolling interest		-		-		(0.2	)		(0.1	)
Less: preferred stock dividend requirements		0.4		0.4		0.8			0.8
Earnings available for common shareholders	$	57.7	$	43.0	$	48.2		$	45.0
Common Shares Outstanding
Average number of common shares outstanding		139.6		135.6		137.7			135.5
Add: effect of dilutive securities		2.4		3.3		2.9			3.1
Diluted average number of common shares outstanding		142.0		138.9		140.6			138.6
Basic EPS	$	0.41	$	0.32	$	0.35		$	0.33
Diluted EPS	$	0.41	$	0.31	$	0.34		$	0.32

The computation of diluted EPS for the three months ended and year to date June 30, 2012, excludes anti-dilutive shares consisting of 10,617 restricted stock shares.

The computation of diluted EPS for the three months ended June 30, 2011, excludes anti-dilutive shares consisting of 201,571 performance shares, 12,115 restricted stock shares and 154,096 stock options.

The computation of diluted EPS year to date June 30, 2011, excludes anti-dilutive shares consisting of 201,571 performance shares, 43,641 restricted stock shares and 154,096 stock options.

Dividends Declared

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

In August 2012, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $23 million payable on September 19, 2012.

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2.   SUPPLEMENTAL CASH FLOW INFORMATION

Great Plains Energy Other Operating Activities
Year to Date June 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	27.3		$	(14.1	)
Accounts receivable pledged as collateral		(67.0	)		-
Fuel inventories		(13.7	)		3.2
Materials and supplies		(5.7	)		(3.1	)
Accounts payable		(53.7	)		(67.2	)
Accrued taxes		33.8			33.6
Accrued interest		(3.6	)		(4.5	)
Deferred refueling outage costs		9.0			(31.0	)
Fuel adjustment clauses		10.5			(11.0	)
Pension and post-retirement benefit obligations		13.5			7.2
Allowance for equity funds used during construction		(0.1	)		(0.3	)
Interest rate hedge settlements		-			(26.1	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		-			2.3
Uncertain tax positions		(0.3	)		(19.6	)
Other		(12.8	)		(26.8	)
Total other operating activities	$	(62.8	)	$	(157.4	)
Cash paid during the period:
Interest	$	130.5		$	138.4
Income taxes	$	3.3		$	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	48.9		$	31.5

KCP&L Other Operating Activities
Year to Date June 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	13.8		$	(9.7	)
Accounts receivable pledged as collateral		(11.0	)		-
Fuel inventories		(12.7	)		(4.1	)
Materials and supplies		(4.5	)		(3.3	)
Accounts payable		(36.5	)		(47.1	)
Accrued taxes		25.2			30.6
Accrued interest		(3.5	)		(3.0	)
Deferred refueling outage costs		9.0			(31.0	)
Pension and post-retirement benefit obligations		14.9			14.1
Kansas Energy Cost Adjustment		(4.4	)		(10.8	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		-			1.5
Uncertain tax positions		0.1			(11.8	)
Other		(16.5	)		(20.5	)
Total other operating activities	$	(26.1	)	$	(95.1	)
Cash paid during the period:
Interest	$	61.3		$	62.2
Income taxes	$	-		$	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	44.3		$	22.4

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3.   RECEIVABLES

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

	June 30			December 31
	2012			2011
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	4.2		$	69.8
Customer accounts receivable - unbilled		120.1			82.4
Allowance for doubtful accounts		(3.5	)		(2.5	)
Other receivables		85.3			81.5
Total	$	206.1		$	231.2
KCP&L
Customer accounts receivable - billed	$	-		$	16.4
Customer accounts receivable - unbilled		74.6			50.0
Allowance for doubtful accounts		(2.0	)		(1.4	)
Intercompany receivables		13.4			38.7
Other receivables		74.8			69.2
Total	$	160.8		$	172.9

Great Plains Energy’s and KCP&L’s other receivables at June 30, 2012, and December 31, 2011, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables.

Sale of Accounts Receivable – KCP&L and GMO

KCP&L sells all of its retail electric accounts receivable to its wholly owned subsidiary, KCP&L Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor.  On May 31, 2012, GMO entered into an agreement to sell all of its retail electric and steam service accounts receivable to its wholly owned subsidiary, GMO Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation.

Each of KCP&L Receivables Company’s and GMO Receivables Company’s sale of the undivided percentage ownership interest in accounts receivable to Victory Receivables Corporation is accounted for as a secured borrowing with accounts receivable pledged as collateral and a corresponding short-term collateralized note payable recognized on the balance sheets.  At June 30, 2012, and December 31, 2011, Great Plains Energy’s accounts receivable pledged as collateral and the corresponding short-term collateralized note payable was $162.0 million and $95.0 million, respectively.  At June 30, 2012, and December 31, 2011, KCP&L’s accounts receivable pledged as collateral and the corresponding short-term collateralized note payable was $106.0 million and $95.0 million, respectively.

KCP&L and GMO each sell their receivables at a fixed price based upon the expected cost of funds and charge-offs.  These costs comprise KCP&L’s and GMO’s loss on the sale of accounts receivable.  KCP&L and GMO service the receivables and receive annual servicing fees of 1.5% and 1.25%, respectively, of the outstanding principal amount of the receivables sold to KCP&L Receivables Company and GMO Receivables Company.  KCP&L and GMO do not recognize a servicing asset or liability because management determined the collection agent fees earned by KCP&L and GMO approximate market value.  KCP&L’s agreement expires in September 2014 and allows for $110 million in aggregate outstanding principal amount at any time.  GMO’s agreement expires in September 2014 and allows for $80 million in aggregate outstanding principal during the period of June 1 through October 31 and $65 million in aggregate outstanding principal during the period of November 1 through May 31 of each year.

19

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

				KCP&L									GMO			Consolidated
				Receivables			Consolidated						Receivables			Great Plains
Three Months Ended June 30, 2012	KCP&L			Company			KCP&L			GMO			Company			Energy
	(millions)
Receivables (sold) purchased	$	(368.6	)	$	368.6		$	-		$	(91.7	)	$	91.7		$	-
Gain (loss) on sale of accounts receivable (a)		(4.7	)		4.0			(0.7	)		(1.2	)		0.8			(1.1	)
Servicing fees received (paid)		0.6			(0.6	)		-			0.1			(0.1	)		-
Fees paid to outside investor		-			(0.3	)		(0.3	)		-			(0.1	)		(0.4	)
Cash from customers (transferred) received		(319.4	)		319.4			-			(64.7	)		64.7			-
Cash received from (paid for) receivables
purchased		315.3			(315.3	)		-			63.9			(63.9	)		-

				KCP&L									GMO			Consolidated
				Receivables			Consolidated						Receivables			Great Plains
Year to Date June 30, 2012	KCP&L			Company			KCP&L			GMO			Company			Energy
	(millions)
Receivables (sold) purchased	$	(662.1	)	$	662.1		$	-		$	(91.7	)	$	91.7		$	-
Gain (loss) on sale of accounts receivable (a)		(8.4	)		8.1			(0.3	)		(1.2	)		0.8			(0.7	)
Servicing fees received (paid)		1.1			(1.1	)		-			0.1			(0.1	)		-
Fees paid to outside investor		-			(0.6	)		(0.6	)		-			(0.1	)		(0.7	)
Cash from customers (transferred) received		(646.6	)		646.6			-			(64.7	)		64.7			-
Cash received from (paid for) receivables
purchased		638.4			(638.4	)		-			63.9			(63.9	)		-
Interest on intercompany note received (paid)		0.1			(0.1	)		-			-			-			-

	Three Months Ended June 30, 2011									Year to Date June 30, 2011
				KCP&L									KCP&L
				Receivables			Consolidated						Receivables			Consolidated
	KCP&L			Company			KCP&L			KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(347.7	)	$	347.7		$	-		$	(639.6	)	$	639.6		$	-
Gain (loss) on sale of accounts receivable (a)		(4.4	)		3.9			(0.5	)		(8.1	)		7.8			(0.3	)
Servicing fees received (paid)		0.5			(0.5	)		-			1.1			(1.1	)		-
Fees paid to outside investor		-			(0.3	)		(0.3	)		-			(0.6	)		(0.6	)
Cash from customers (transferred) received		(309.9	)		309.9			-			(618.2	)		618.2			-
Cash received from (paid for) receivables
purchased		306.0			(306.0	)		-			610.4			(610.4	)		-
Interest on intercompany note received (paid)		0.1			(0.1	)		-			0.2			(0.2	)		-
(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.

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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.

Spent Nuclear Fuel and High-Level Radioactive Waste

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel.  KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kWh of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel.  These disposal costs are charged to fuel expense.  In 2010, the DOE filed a motion with the NRC to withdraw its then pending application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada.  An NRC board denied the DOE’s motion to withdraw its application, and the DOE appealed that decision to the full NRC.  In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of September 2011 due to a lack of funding.  These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application.  The court has not yet issued a final decision in the case, but in August 2012, the court ordered the parties to report to it, no later than December 14, 2012, on whether Congress by then had provided funding for the NRC to proceed on the license application.  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 Decommissioning Trust Fund

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

	June 30		December 31
	2012		2011
Decommissioning Trust	(millions)
Beginning balance January 1	$	135.3	$	129.2
Contributions		1.7		3.4
Earned income, net of fees		1.4		4.8
Net realized gains		0.5		0.3
Net unrealized gains (losses)		6.0		(2.4	)
Ending balance	$	144.9	$	135.3

21

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

	June 30									December 31
	2012									2011
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	77.9	$	17.2	$	(3.8	)	$	91.3	$	76.5	$	12.3	$	(4.5	)	$	84.3
Debt securities		46.0		4.9		(0.1	)		50.8		44.2		4.5		(0.1	)		48.6
Other		2.8		-		-			2.8		2.4		-		-			2.4
Total	$	126.7	$	22.1	$	(3.9	)	$	144.9	$	123.1	$	16.8	$	(4.6	)	$	135.3

The weighted average maturity of debt securities held by the trust at June 30, 2012, was approximately 7 years.  The costs of securities sold are determined on the basis of specific identification.  The following table summarizes the realized gains and losses from the sale of securities in the nuclear decommissioning trust fund.

	Three Months Ended						Year to Date
	June 30						June 30
	2012			2011			2012			2011
	(millions)
Realized gains	$	0.2		$	0.7		$	0.7		$	0.8
Realized losses		(0.1	)		(0.7	)		(0.2	)		(0.7	)

5.   REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

On April 20, 2012, KCP&L filed an application with The State Corporation Commission of the State of Kansas (KCC) to request an increase to its retail revenues of $63.6 million, with a return on equity of 10.4% and a rate-making equity ratio of 51.8%.  The request includes recovery of costs related to significant upgrades at its generating facilities, including environmental upgrades at the La Cygne Station; investments in additional wind generation; and increased investments in electrical infrastructure.  KCP&L is also requesting that KCC approve a change to depreciation rates to reflect the increase in plant in service as well as a change to the current method of allocating costs between its Kansas and Missouri jurisdictions to better reflect KCP&L’s summer peaking business.  Testimony from KCC staff and other parties regarding the case is expected in late August 2012, with an evidentiary hearing to occur in October 2012.  The increase to retail revenues is anticipated to be effective in January 2013.

KCP&L Missouri Rate Case Proceedings

On February 27, 2012, KCP&L filed an application with the Public Service Commission of the State of Missouri (MPSC) to request an increase to its retail revenues of $105.7 million, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%.  The request includes recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service and also includes a lower annual offset to the revenue requirement for the Missouri jurisdictional portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset).  KCP&L currently expects that it will not be able to achieve the $45.9 million wholesale margin offset currently reflected in its retail rates due to a decline in wholesale power prices, which is being driven by low natural gas prices.  Testimony from MPSC staff and other parties regarding the case was filed on August 2, 2012.  The MPSC staff’s testimony recommended a return on equity range of 8.0% to 9.0% and a revenue increase range of approximately $16.5 million to $33.7 million.  The outcome of the KCP&L Missouri rate case will likely be different from either of the positions of KCP&L or MPSC staff, though the

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decision of the MPSC cannot be predicted.  An evidentiary hearing is scheduled to occur in October 2012.  The increase to retail revenues is anticipated to be effective in January 2013.

In a March 2011 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 June 30, 2012, KCP&L and GMO had $127.0 million and $3.0 million, respectively, of unamortized deferred investment tax credits.

GMO Missouri Rate Case Proceedings

On February 27, 2012, GMO filed an application with the MPSC to request an increase to its retail revenues of $58.3 million for its Missouri Public Service division and $25.2 million for its St. Joseph Light & Power (L&P) division, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%.  The requests include recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service, costs related to energy efficiency and demand side management programs, and increased fuel costs.  Testimony from MPSC staff and other parties regarding the case is expected in mid-August 2012, with an evidentiary hearing to occur in October 2012.  The increase to retail revenues is anticipated to be effective in January 2013.

In December 2011, GMO filed a request with the MPSC seeking to recover costs for new and enhanced energy efficiency and demand side management programs under the Missouri Energy Efficiency Investment Act (MEEIA).  A decision on the MEEIA request is anticipated in the third quarter of 2012.

GMO Fuel Adjustment Clause (FAC) Prudence Review

GMO’s electric retail rates contain an FAC tariff under which 95% of the difference between actual fuel cost, purchased power costs and off-system sales margin and the amount provided in base rates for these costs is passed along to GMO’s customers.  The MPSC requires prudence reviews of the FAC no less frequently than at 18-month intervals.  On November 28, 2011, the MPSC staff filed its prudence review report for the 18-month prudence review period covering June 1, 2009 through November 30, 2010.  The MPSC staff recommended to the MPSC to order GMO to refund approximately $19 million, plus interest, to customers through an adjustment to its FAC because the MPSC staff asserts that GMO was imprudent in its use of natural gas hedges to mitigate risk associated with its future purchases in the spot power market.  In May 2012, the MPSC staff revised their recommended refund amount to $14.9 million, plus interest.  GMO is disputing the MPSC staff’s claim of imprudence and filed its testimony on February 22, 2012.  An evidentiary hearing was held June 5-6, 2012, and an order is expected in the third quarter of 2012.

SPP and NERC Inquiries

The Southwest Power Pool, Inc. (SPP) conducted a compliance inquiry regarding a transmission system outage that occurred in the St. Joseph, Missouri area in the summer of 2009.  The North American Electric Reliability Corporation (NERC) also investigated the circumstances surrounding this transmission system outage.  GMO was assessed an immaterial penalty in 2012 resolving this matter.

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6.   PENSION PLANS AND OTHER EMPLOYEE BENEFITS

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

KCP&L and GMO record pension and post-retirement expense in accordance with rate orders from the MPSC and KCC that allow the difference between pension and post-retirement costs under Generally Accepted Accounting Principles (GAAP) and costs for ratemaking to be recognized as a regulatory asset or liability.  This difference between financial and regulatory accounting methods is due to timing and will be eliminated over the life of the plans.

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 June 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	8.8		$	7.8		$	0.8		$	0.8
Interest cost		12.3			12.6			2.0			1.9
Expected return on plan assets		(10.7	)		(9.7	)		(0.4	)		(0.5	)
Prior service cost		1.1			1.2			1.8			1.8
Recognized net actuarial (gain) loss		11.2			9.5			-			(0.2	)
Transition obligation		-			-			0.2			0.4
Settlement charge		-			0.2			-			-
Net periodic benefit costs before
regulatory adjustment		22.7			21.6			4.4			4.2
Regulatory adjustment		(3.8	)		(5.9	)		0.3			0.1
Net periodic benefit costs	$	18.9		$	15.7		$	4.7		$	4.3

	Pension Benefits						Other Benefits
Year to Date June 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	17.7		$	15.6		$	1.6		$	1.6
Interest cost		24.5			25.1			3.9			3.9
Expected return on plan assets		(21.4	)		(19.3	)		(0.9	)		(0.9	)
Prior service cost		2.2			2.3			3.6			3.6
Recognized net actuarial (gain) loss		22.3			19.2			-			(0.3	)
Transition obligation		-			-			0.5			0.7
Settlement charge		-			0.2			-			-
Net periodic benefit costs before
regulatory adjustment		45.3			43.1			8.7			8.6
Regulatory adjustment		(7.7	)		(12.3	)		0.7			0.3
Net periodic benefit costs	$	37.6		$	30.8		$	9.4		$	8.9

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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, restricted stock units, bonus shares, stock options, stock appreciation rights, limited stock appreciation rights, director shares, director deferred share units and performance shares to directors, officers and other employees of Great Plains Energy and KCP&L.  Forfeiture rates are based on historical forfeitures and future expectations and are reevaluated annually.

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

	Three Months Ended				Year to Date
	June 30				June 30
	2012		2011		2012		2011
Great Plains Energy	(millions)
Compensation expense	$	1.8	$	1.7	$	2.8	$	3.3
Income tax benefit		0.7		0.8		1.3		1.4
KCP&L
Compensation expense	$	1.4	$	1.2	$	2.1	$	2.3
Income tax benefit		0.5		0.6		1.0		1.0

Performance Shares

Performance share activity year to date June 30, 2012, is summarized in the following table.  Performance adjustment represents the number of shares of common stock related to performance shares ultimately issued that can vary from the number of performance shares initially granted depending on Great Plains Energy’s performance over a stated period of time.

	Performance			Grant Date
	Shares			Fair Value*
Beginning balance		442,042		$	21.06
Granted		161,627			19.01
Forfeited		(50,685	)		18.71
Performance adjustment		(160,717	)
Ending balance		392,267			22.98
* weighted-average

At June 30, 2012, the remaining weighted-average contractual term was 1.4 years.  The weighted-average grant-date fair value of shares granted was $20.99 and $19.01 for the three months ended and year to date June 30, 2012, respectively.  The weighted-average grant-date fair value of shares granted was $26.28 and $22.48 for the three months ended and year to date June 30, 2011, respectively.  At June 30, 2012, there was $3.8 million of total unrecognized compensation expense, net of forfeiture rates, related to performance shares granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term.  There were no performance shares earned and paid year to date June 30, 2012.  The total fair value of performance shares earned and paid year to date June 30, 2011, was $0.8 million.

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The fair value of performance share awards is estimated using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of expected volatilities, dividend yield and risk-free rates.  Expected volatility is based on daily stock price change during a historical period commensurate with the remaining term of the performance period of the grant.  The risk-free rate is based upon the rate at the time of the evaluation for zero-coupon government bonds with a maturity consistent with the remaining performance period of the grant.  The dividend yield is based on the most recent dividends paid and the actual closing stock price on the valuation date.  For shares granted in 2012, inputs for expected volatility, dividend yield and risk-free rates were 21%, 4.32% and 0.40%, respectively.

Restricted Stock

Restricted stock activity year to date June 30, 2012, is summarized in the following table.

	Nonvested			Grant Date
	Restricted Stock			Fair Value*
Beginning balance		386,183		$	17.06
Granted and issued		162,129			19.69
Vested		(204,838	)		15.76
Forfeited		(50,685	)		19.66
Ending balance		292,789			18.97
* weighted-average

At June 30, 2012, the remaining weighted-average contractual term was 2.0 years.  The weighted-average grant-date fair value of shares granted for the three months ended and year to date June 30, 2012, was $19.89 and $19.69, respectively.  The weighted-average grant-date fair value of shares granted for the three months ended and year to date June 30, 2011, was $20.26 and $19.26, respectively.  At June 30, 2012, there was $3.4 million of total unrecognized compensation expense, net of forfeiture rates, related to nonvested restricted stock granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term.  The total fair value of shares vested for the three months ended and year to date June 30, 2012, was $1.3 million and $3.2 million, respectively.  The total fair value of shares vested for the three months ended and year to date June 30, 2011, was $0.6 million and $2.6 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 December 2016.  The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time.  A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At June 30, 2012, Great Plains Energy was in compliance with this covenant.  At June 30, 2012, Great Plains Energy had $31.0 million of outstanding cash borrowings at a weighted-average interest rate of 2.0% and had issued letters of credit totaling $4.8 million under the credit facility.  At December 31, 2011, Great Plains Energy had $22.0 million of outstanding cash borrowings at a weighted-average interest rate of 2.06% and had issued letters of credit totaling $11.6 million under the credit facility.

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

KCP&L’s $600 million revolving credit facility with a group of banks provides support for its issuance of commercial paper and other general corporate purposes and expires in December 2016.  Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities.  A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At June 30, 2012, KCP&L was in compliance with this covenant.  At June 30, 2012, KCP&L had $91.0 million of commercial paper outstanding at a weighted-average interest rate of 0.46%, had issued letters of credit totaling $18.2 million and had no outstanding cash borrowings under the credit facility.  At December 31, 2011, KCP&L had $227.0 million of commercial paper outstanding at a weighted-average interest rate of 0.50%, had issued letters of credit totaling $21.5 million and had no outstanding cash borrowings under the credit facility.

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

GMO’s $450 million revolving credit facility with a group of banks provides support for its issuance of commercial paper and other general corporate purposes and expires in December 2016.  Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities.  A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At June 30, 2012, GMO was in compliance with this covenant.  At June 30, 2012, GMO had issued letters of credit totaling $13.2 million and had no outstanding commercial paper or cash borrowings under the credit facility.  At December 31, 2011, GMO had $40.0 million of commercial paper outstanding at a weighted-average interest rate of 0.88%, had issued letters of credit totaling $13.2 million and had no outstanding cash borrowings under the credit facility.

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9.   LONG-TERM DEBT

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

		June 30			December 31
	Year Due	2012			2011
KCP&L		(millions)
General Mortgage Bonds
4.97% EIRR bonds(a)	2015-2035	$	106.9		$	119.3
7.15% Series 2009A (8.59% rate)(b)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
5.85% Series (5.72% rate)(b)	2017		250.0			250.0
6.375% Series (7.49% rate)(b)	2018		350.0			350.0
6.05% Series (5.78% rate)(b)	2035		250.0			250.0
5.30% Series	2041		400.0			400.0
EIRR bonds 4.90% Series 2008	2038		23.4			23.4
Other	2012-2018		2.9			2.9
Current maturities			(0.4	)		(12.7	)
Unamortized discount			(4.0	)		(4.2	)
Total KCP&L excluding current maturities(c)			1,902.0			1,901.9
Other Great Plains Energy
GMO First Mortgage Bonds 9.44% Series	2013-2021		10.1			11.2
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.341% Wamego Series 1996(d)	2026		7.3			7.3
0.341% State Environmental 1993(d)	2028		5.0			5.0
GMO Senior Notes
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			-			16.3
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(b)	2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(b)	2017		100.0			100.0
Great Plains Energy 4.85% Senior Notes (7.34% rate)(b)	2021		350.0			350.0
Great Plains Energy 5.292% Senior Notes	2022		287.5			-
Great Plains Energy 10.00% Equity Units Subordinated Notes			-			287.5
Current maturities			(506.7	)		(788.7	)
Unamortized discount and premium, net			5.7			(0.7	)
Total Great Plains Energy excluding current maturities(c)		$	3,013.4		$	2,742.3
(a) Weighted-average interest rates at June 30, 2012
(b) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(c) Does not include $39.5 million EIRR Series 1993B, $63.3 million EIRR Series 2007 A-1 and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L
(d) Variable rate

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Fair Value of Long-Term Debt

The fair value of long-term debt is categorized as a Level 2 liability within the fair value hierarchy as it is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices are not available.  At June 30, 2012, and December 31, 2011, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.5 billion and $3.9 billion, respectively.  At June 30, 2012, and December 31, 2011, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.9 billion and $2.2 billion, respectively.

GMO Senior Notes

GMO repaid its $500 million 11.875% Senior Notes that matured in July 2012.

Great Plains Energy Equity Units

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

In March 2012, Great Plains Energy remarketed $287.4 million of its 10% subordinated notes that were originally issued as components of the Equity Units as senior notes at a new interest rate of 5.292%.  The 5.292% Senior Notes mature in June 2022.

Great Plains Energy did not receive any proceeds from the remarketing.  Proceeds from the remarketing were used to purchase a portfolio of U.S. Treasury securities that were pledged as collateral to secure the Equity Unit holders’ obligation under the purchase contract.  There were also $0.1 million of purchase contracts that settled early and did not participate in the remarketing.

In June 2012, Great Plains Energy settled the obligations under the purchase contracts underlying its 5.7 million outstanding Equity Units by issuing approximately 17.1 million shares of its common stock in exchange for $287.4 million, which had been raised through the remarketing completed in March 2012.  The settlement rate of 2.9762 was determined according to the applicable market value of the Company’s common stock at the settlement date.  The applicable market value of $20.05 was measured by the average of the closing price per share of the Company’s common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding June 15, 2012.

10.   COMMITMENTS AND CONTINGENCIES

Environmental Matters

Great Plains Energy and KCP&L are subject to extensive federal, state and local environmental laws, regulations and permit requirements relating to air and water quality, waste management and disposal, natural resources and health and safety.  In addition to imposing continuing compliance obligations and remediation costs, these laws, regulations and permits authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions.  The cost of complying with current and future environmental requirements is expected to be material to Great Plains Energy and KCP&L.  Failure to comply with environmental requirements or to timely recover environmental costs through rates could have a material effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

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

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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 Allowance for Funds Used During Construction (AFUDC) and property taxes) to comply with the currently-effective Clean Air Interstate Rule (CAIR), the replacement to CAIR or the Cross-State Air Pollution Rule (CSAPR), the best available retrofit technology (BART) rule, the SO2 National Ambient Air Quality Standard (NAAQS), the industrial boiler rule and the Mercury and Air Toxics Standards (MATS) rule that would reduce emissions of toxic air pollutants, (all of which are discussed below) is approximately $1 billion.  The actual cost of compliance with any existing, proposed or future rules may be significantly different from the cost estimate provided.

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

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

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

·   KCP&L’s Montrose No. 3 full AQCS installed by approximately 2020; and

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

In September 2011, KCP&L commenced construction of the La Cygne project.  Other capital projects at KCP&L’s Montrose Nos. 1 and 2 and GMO’s Sibley Nos. 1 and 2 and Lake Road No. 4/6 are possible but are currently considered less likely.  In connection with KCP&L’s and GMO’s Integrated Resource Plan (IRP) filings with the MPSC in April 2012, the economics around Montrose No. 2 and Lake Road No. 4/6 have improved.  Pending further evaluation, these projects may move from less likely to more likely but it is not expected to materially impact the overall $1 billion current estimate of capital expenditures.  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 $1 billion current estimate of capital expenditures does not reflect the non-capital costs the Companies incur on an ongoing basis to comply with environmental laws, which may increase in the future due to current or future environmental laws.  The Companies expect to seek recovery of the costs associated with environmental requirements through rate increases; however, there can be no assurance that such rate increases would be granted.  The Companies may be subject to materially adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies’ environmental reputation.

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

The CAIR requires reductions in SO2 and 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.

In July 2008, the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit Court) vacated CAIR in its entirety and remanded the matter to the EPA to promulgate a new rule consistent with its opinion.  In December 2008, the court issued an order reinstating CAIR pending EPA’s development of a replacement regulation on remand.

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

Compliance with the CSAPR was scheduled to begin in 2012.  Multiple states, utilities and other parties, including KCP&L, filed requests for reconsideration and stays with the EPA and/or the D.C. Circuit Court.  In December 2011, the D.C. Circuit Court issued an order staying the CSAPR pending the Court's resolution of the petitions for review of the rule.  The order requires the EPA to continue administering the CAIR while the CSAPR is stayed.

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

Best Available Retrofit Technology (BART) Rule

The EPA BART rule directs state air quality agencies to identify whether visibility-reducing emissions from sources subject to BART are below limits set by the state or whether retrofit measures are needed to reduce emissions.  BART applies to specific eligible facilities including KCP&L’s La Cygne Nos. 1 and 2 in Kansas, KCP&L’s Iatan No. 1, in which GMO has an 18% interest, and KCP&L’s Montrose No. 3 in Missouri, GMO’s Sibley Unit No. 3 and Lake Road Unit No. 6 in Missouri and Westar Energy, Inc.’s (Westar) Jeffrey Unit Nos. 1 and 2 in Kansas, in which GMO has an 8% interest.  Both Missouri and Kansas have submitted BART plans to the EPA.  In December 2011, the EPA approved the Kansas BART plan.

In May 2012, the EPA finalized a rule that approves the CSAPR as an alternative to BART.  As a result, states in the CSAPR will be able to substitute participation in the CSAPR for source-specific BART.  In addition, the EPA finalized a limited disapproval of the BART plan that had been submitted by Missouri because it relied on requirements of the CAIR to satisfy certain regional haze requirements.  To address deficiencies in a CAIR-dependent BART plan, the EPA promulgated a Federal Implementation Plan (FIP) to replace reliance on CAIR with reliance on the CSAPR in the BART plan for Missouri.  In June 2012, the EPA finalized a limited approval of the Missouri BART plan that does not include the FIP-approved component of the BART plan.

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Mercury and Air Toxics Standards (MATS) Rule

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

In December 2011, the EPA finalized theMATS Rule that will reduce emissions of toxic air pollutants, also known as hazardous air pollutants, from new and existing coal- and oil-fired EGUs with a capacity of greater than 25 MWs.  The rule establishes numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrochloric acid (a surrogate for acid gases).  The rule establishes work practices, instead of numerical emission limits, for organic air toxics, including dioxin/furan.  Compliance with the rule would need to be achieved by installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market or a combination of these and other alternatives.  The rule allows three years for compliance with authority for state permitting authorities to grant an additional year as needed for technology installation.  The EPA indicated that it expects this option to be broadly available.  The Missouri Department of Natural Resources (MDNR) has granted an extension at KCP&L’s Montrose Station and at GMO’s Lake Road and Sibley Stations.  The Kansas Department of Health and Environment (KDHE) has granted an extension at KCP&L’s La Cygne Station.

Industrial Boiler Rule

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

New Source Review

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

In 2010, Westar settled a lawsuit filed by the Department of Justice on behalf of the EPA.  The lawsuit asserted that certain projects completed at the Jeffrey Energy Center violated certain requirements of the New Source Review program.  The Jeffrey Energy Center is 92% owned by Westar and operated exclusively by Westar.  GMO has an 8% interest in the Jeffrey Energy Center and is generally responsible for its 8% share of the facility’s operating costs and capital expenditures.  The settlement agreement required, among other things, the installation of a selective catalytic reduction (SCR) system at one of the three Jeffrey Energy Center units by the end of 2014.  Westar has estimated the cost of this SCR at

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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.  GMO expects to seek recovery of its share of these costs through rate increases; however, there can be no assurance that such rate increases would be granted.

KCP&L had received requests for information from the KDHE pertaining to a past La Cygne No. 1 scrubber project.  In April 2012, KCP&L and KDHE agreed to resolve this matter with KCP&L completing supplemental environmental projects in the amount of $800,000 and paying a penalty in the amount of $350,000.

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 designed to offset CO2 emissions.

KCP&L agreed in the Collaboration Agreement to pursue increasing its wind generation capacity by 400 MWs by the end of 2012.  KCP&L and GMO have added 379 MWs of wind generation and have also added the equivalent CO2 offset of 21 MWs of wind through solar, landfill gas and other projects that were not required under the Collaboration Agreement.

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

Also in the Collaboration Agreement, KCP&L agreed to offset an additional 711,000 tons of CO2 by the end of 2012, which it has done.

Climate Change

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

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produce about one ton of CO2 per MWh, or approximately 25 million tons and 18 million tons per year for Great Plains Energy and KCP&L, respectively.

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

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

In March 2012, the EPA proposed new source performance standards for emissions of CO2 for new affected fossil-fuel-fired electric utility generating units.  This action pursuant to the Clean Air Act would, for the first time, set national limits on the amount of CO2 that power plants built in the future can emit.  The proposal would not apply to Great Plains Energy’s and KCP&L’s existing units including modifications to those units.

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

KCP&L and GMO project that they will be compliant with the Missouri renewable requirements, exclusive of the solar requirement, through 2023 for KCP&L and 2018 for GMO.  KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri solar requirements for the foreseeable future.  KCP&L also projects that it will be compliant with the Kansas renewable requirements through 2015.

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

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SO2 NAAQS

In June 2010, the EPA strengthened the primary NAAQS for SO2 by establishing a new 1-hour standard at a level of 0.075 ppm and revoking the two existing primary standards of 0.140 ppm evaluated over 24 hours and 0.030 ppm evaluated over an entire year.  In July 2011, the MDNR recommended to the EPA that part of Jackson County, Missouri, which is in the Companies’ service territory, be designated a nonattainment area for the new 1-hour SO2 standard.  In April 2012, the EPA announced it is seeking additional input from states, tribes, and other interested parties to refine the agency's approach for implementing the SO2 standard.

Particulate Matter (PM)NAAQS

In June 2012, the EPA proposed to strengthen the NAAQS for fine particulate matter (PM2.5).  The proposal strengthens the annual primary standard and seeks comment on alternative levels of the annual primary standard.  The proposal retains the existing 24‐hour PM2.5 primary standard, coarse particle matter (PM10) primary standard, and secondary standards for PM2.5 and PM10 identical to the primary standards.  The proposal also includes a separate PM2.5 standard to improve visibility.  The EPA is proposing two visibility options for this 24‐hour standard and is seeking comment on alternative levels. The EPA agreed to finalize the rule by December 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.

Water

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

In March 2011, the EPA proposed regulations pursuant to Section 316(b) of the Clean Water Act regarding cooling water intake structures pursuant to a court approved settlement.  KCP&L generation facilities with cooling water intake structures would be subject to a limit on how many fish can be killed by being pinned against intake screens (impingement) and would be required to conduct studies to determine whether and what site-specific controls, if any, would be required to reduce the number of aquatic organisms drawn into cooling water systems (entrainment).  The EPA agreed to finalize the rule by June 2013.  Although the impact on Great Plains Energy’s and KCP&L’s operations will not be known until after the rule is finalized, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

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

Additionally, the EPA plans to revise the existing standards for water discharges from coal-fired power plants with a proposed rule in November 2012 and final action in April 2014.  Until a rule is proposed and finalized, the financial and operational impacts to Great Plains Energy and KCP&L cannot be determined.

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Solid Waste

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

Remediation

Certain federal and state laws, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), hold current and previous owners or operators of contaminated facilities and persons who arranged for the disposal or treatment of hazardous substances liable for the cost of investigation and cleanup.  CERCLA and other laws also authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment.  GMO is named as a potentially responsible party at two disposal sites for polychlorinated biphenyl (PCB) contamination, and retains some environmental liability for several operations and investments it no longer owns.  In addition, GMO also owns, or has acquired liabilities from companies that once owned or operated, former manufactured gas plant (MGP) sites, which are subject to the supervision of the EPA and various state environmental agencies.

At June 30, 2012, and December 31, 2011, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site.  At June 30, 2012, and December 31, 2011, 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 June 30, 2012, and December 31, 2011, Great Plains Energy had $2.1 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB contaminated sites and retained liabilities.  This estimate was based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary.  This estimate could change materially after further investigation, and could also be affected by the actions of environmental agencies and the financial viability of other potentially responsible parties; however, given the uncertainty of these items the possible loss or range of loss in excess of the amount accrued is not estimable.

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

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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.  On July 12, 2012, a three-judge panel of the Court of Appeals issued a decision reversing in part the trial court’s decision and directing that the original award be increased by $2.1 million ($1.0 million KCP&L share).  The parties have until late August 2012 to request a rehearing of that decision.

GMO Western Energy Crisis

In response to complaints of manipulation of the California energy market, The Federal Energy Regulatory Commission (FERC) issued an order in July 2001 requiring net sellers of power in the California markets from October 2, 2000, through June 20, 2001, at prices above a FERC-determined competitive market clearing price, to make refunds to net purchasers of power in the California market during that time period.  Because MPS Merchant was a net purchaser of power during the refund period, it has received approximately $8 million in refunds through settlements with certain sellers of power.  MPS Merchant estimates that it is entitled to approximately $12 million in additional refunds under the standards FERC has used in this case.  FERC has stated that interest will be applied to the refunds but the amount of interest has not yet been determined.

In December 2001, various parties appealed the July 2001 FERC order to the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) seeking review of a number of issues, including expansion of the refund period to include periods prior to October 2, 2000 (the Summer Period).  MPS Merchant was a net seller of power during the Summer Period.  On August 2, 2006, the Ninth Circuit issued an order finding, among other things, that FERC did not provide a sufficient justification for refusing to exercise its remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the Summer Period.  The court remanded the matter to FERC for further consideration.  In May 2011, FERC issued an order which clarified the scope of the hearing regarding spot-market transactions during the Summer Period and ruled on requests for rehearing and motions to dismiss.  An evidentiary hearing before a FERC administrative law judge concluded on July 19, 2012.  An initial decision by the FERC administrative law judge is due February 2013.  If FERC determines that MPS Merchant violated then-existing tariffs or laws during the Summer Period and that such violations affected market clearing prices in California, MPS Merchant could be found to owe refunds.

A separate proceeding was also initiated, generally referred to as the Pacific Northwest refund proceeding, to determine if any refunds were warranted in the Pacific Northwest between December 25, 2000, and June 20, 2001.  Refund claims brought against MPS Merchant were $5.1 million.  FERC initially rejected the refund requests, but its decision was remanded by the Ninth Circuit for FERC to consider whether any specific acts of market manipulation support the imposition of refunds for particular bilateral contracts.  Formal claims against MPS Merchant must be identified by August 17, 2012, and an evidentiary hearing on transactions in the Pacific Northwest has been scheduled to begin April 15, 2013.

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12.   RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO’s business and operate its facilities at cost.  These costs totaled $26.7 million and $52.9 million, respectively, for the three months ended and year to date June 30, 2012.  These costs totaled $27.7 million and $57.2 million, respectively, for the same periods in 2011.  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.  At June 30, 2012, KCP&L had a $256.9 million money pool payable to GMO, which it repaid in July 2012.  The following table summarizes KCP&L’s related party receivables and payables.

	June 30			December 31
	2012			2011
	(millions)
Net receivable from (payable to) GMO	$	(246.6	)	$	24.1
Net receivable from Great Plains Energy		8.8			9.5

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 purchases and normal sales (NPNS) election, which are accounted for by accrual accounting, are recorded on the balance sheet at fair value as an asset or liability.  Changes in the fair value of derivative instruments are recognized currently in net income unless specific hedge accounting criteria are met, except GMO utility operations hedges that are recorded to a regulatory asset or liability consistent with MPSC regulatory orders, as discussed below.

Great Plains Energy and KCP&L have posted collateral, in the ordinary course of business, for the aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a liability position.  At June 30, 2012, Great Plains Energy and KCP&L have posted collateral in excess of the aggregate fair value of its derivative instruments; therefore, if the credit risk-related contingent features underlying these agreements were triggered, Great Plains Energy and KCP&L would not be required to post additional collateral to its counterparties.

Commodity Risk Management

KCP&L’s risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales.  At June 30, 2012, KCP&L had fully hedged 2012 and had hedged 38% and 6%, respectively, of the 2013 and 2014 projected natural gas usage for retail load and firm MWh sales by utilizing futures contracts.  KCP&L has designated the natural gas hedges as cash flow hedges.  The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge.  To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be

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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 June 30, 2012 and 2011.

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 June 30, 2012, GMO had financial contracts in place to hedge approximately 99%, 59% and 8%, respectively, of the expected on-peak natural gas generation and natural gas equivalent purchased power price exposure for 2012, 2013 and 2014.  GMO has designated its natural gas hedges as economic hedges (non-hedging derivatives).  In connection with GMO’s 2005 Missouri electric rate case, it was agreed that the settlement costs of these contracts would be recognized in fuel expense.  The settlement cost is included in GMO’s FAC.  A regulatory asset has been 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, which has certain long-term natural gas contracts remaining from its former non-regulated trading operations, manages the daily delivery of its remaining contractual commitments with economic hedges (non-hedging derivatives) to reduce its exposure to changes in market prices.  Within the trading portfolio, MPS Merchant takes certain positions to hedge physical sale or purchase contracts.  MPS Merchant records the fair value of physical trading energy contracts as derivative assets or liabilities with an offsetting entry to the consolidated statements of income.

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

	June 30					December 31
	2012					2011
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	1.6	$	(0.5	)	$	2.0	$	(0.5	)
Non-hedging derivatives		16.2		(3.0	)		23.6		(5.0	)
Forward contracts
Non-hedging derivatives		69.5		6.7			97.3		7.8
Option contracts
Non-hedging derivatives		-		-			0.4		-
KCP&L
Futures contracts
Cash flow hedges	$	1.6	$	(0.5	)	$	2.0	$	(0.5	)

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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
June 30, 2012	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		6.7		3.0
Total Derivatives		$	6.7	$	3.5
December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.8		5.0
Total Derivatives		$	7.8	$	5.5

KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
June 30, 2012	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	-	$	0.5

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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 June 30, 2012	(millions)					(millions)
Interest rate contracts		$	-		Interest charges	$	(5.0	)
Commodity contracts			0.1		Fuel		-
Income tax benefit			-		Income tax benefit		1.9
Total		$	0.1		Total	$	(3.1	)
Year to Date June 30, 2012
Interest rate contracts		$	-		Interest charges	$	(10.1	)
Commodity contracts			(0.2	)	Fuel		-
Income tax benefit			0.1		Income tax benefit		3.9
Total		$	(0.1	)	Total	$	(6.2	)
Three Months Ended June 30, 2011
Interest rate contracts		$	(5.8	)	Interest charges	$	(3.9	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			2.2		Income tax benefit		1.4
Total		$	(3.7	)	Total	$	(2.5	)
Year to Date June 30, 2011
Interest rate contracts		$	(5.3	)	Interest charges	$	(6.8	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			2.1		Income tax benefit		2.6
Total		$	(3.3	)	Total	$	(4.2	)

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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 June 30, 2012	(millions)					(millions)
Interest rate contracts		$	-		Interest charges	$	(2.2	)
Commodity contracts			0.1		Fuel		-
Income tax benefit			-		Income tax benefit		0.9
Total		$	0.1		Total	$	(1.3	)
Year to Date June 30, 2012
Interest rate contracts		$	-		Interest charges	$	(4.4	)
Commodity contracts			(0.2	)	Fuel		-
Income tax benefit			0.1		Income tax benefit		1.7
Total		$	(0.1	)	Total	$	(2.7	)
Three Months Ended June 30, 2011
Interest rate contracts		$	-		Interest charges	$	(2.2	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			-		Income tax benefit		0.8
Total		$	(0.1	)	Total	$	(1.4	)
Year to Date June 30, 2011
Interest rate contracts		$	-		Interest charges	$	(4.4	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			-		Income tax benefit		1.7
Total		$	(0.1	)	Total	$	(2.7	)

42

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				Income Statement
	Account on Derivatives				Classification	Amount
Three Months Ended June 30, 2012		(millions)				(millions)
Commodity contracts		$	0.3		Fuel	$	(2.0	)
Total		$	0.3		Total	$	(2.0	)
Year to Date June 30, 2012
Commodity contracts		$	(2.7	)	Fuel	$	(2.7	)
Total		$	(2.7	)	Total	$	(2.7	)
Three Months Ended June 30, 2011
Commodity contracts		$	(1.0	)	Fuel	$	(1.0	)
Total		$	(1.0	)	Total	$	(1.0	)
Year to Date June 30, 2011
Commodity contracts		$	(1.3	)	Fuel	$	(2.9	)
Total		$	(1.3	)	Total	$	(2.9	)

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 $(0.3) million and $(1.1) million, respectively, for the three months ended and year to date June 30, 2012, and $(0.9) million and $1.0 million, respectively, for the same periods in 2011.

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

	Great Plains Energy						KCP&L
	June 30			December 31			June 30			December 31
	2012			2011			2012			2011
	(millions)
Current assets	$	10.9		$	11.3		$	10.9		$	11.3
Current liabilities		(79.1	)		(89.5	)		(57.8	)		(62.5	)
Noncurrent liabilities		(0.3	)		(0.2	)		(0.3	)		(0.2	)
Deferred income taxes		26.7			30.5			18.4			20.0
Total	$	(41.8	)	$	(47.9	)	$	(28.8	)	$	(31.4	)

Great Plains Energy’s accumulated OCI in the table above at June 30, 2012, includes $20.6 million that is expected to be reclassified to expenses over the next twelve months.  KCP&L’s accumulated OCI in the table above at June 30, 2012, includes $9.1 million that is expected to be reclassified to expense over the next twelve months.

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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 and liabilities categorized within this level consist of Great Plains Energy’s and KCP&L’s various exchange traded derivative instruments and equity and U.S. Treasury securities that are actively traded within KCP&L’s decommissioning trust fund and GMO’s Supplemental Executive Retirement Plan (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 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.

44

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 June 30, 2012, and December 31, 2011.

						Fair Value Measurements Using
Description	June 30 2012		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Nuclear decommissioning trust (b)
Equity securities	$	91.3	$	-		$	91.3	$	-	$	-
Debt securities
U.S. Treasury		16.2		-			16.2		-		-
U.S. Agency		4.3		-			-		4.3		-
State and local obligations		2.7		-			-		2.7		-
Corporate bonds		26.9		-			-		26.9		-
Foreign governments		0.7		-			-		0.7		-
Other		0.5		-			-		0.5		-
Total nuclear decommissioning trust		142.6		-			107.5		35.1		-
Total		142.6		-			107.5		35.1		-
Liabilities
Derivative instruments (a)		-		(0.5	)		0.5		-		-
Total	$	-	$	(0.5	)	$	0.5	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	6.7	$	-		$	-	$	4.5	$	2.2
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		0.1		-			-		0.1		-
Total SERP rabbi trust		0.3		-			0.2		0.1		-
Total		7.0		-			0.2		4.6		2.2
Liabilities
Derivative instruments (a)		-		(3.0	)		3.0		-		-
Total	$	-	$	(3.0	)	$	3.0	$	-	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	6.7	$	-		$	-	$	4.5	$	2.2
Nuclear decommissioning trust (b)		142.6		-			107.5		35.1		-
SERP rabbi trust (c)		0.3		-			0.2		0.1		-
Total		149.6		-			107.7		39.7		2.2
Liabilities
Derivative instruments (a)		-		(3.5	)		3.5		-		-
Total	$	-	$	(3.5	)	$	3.5	$	-	$	-

45

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

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

(b)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $2.3 million and $3.0 million at June 30, 2012, and December 31, 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

46

(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 $20.2 million and $20.3 million at June 30, 2012, and December 31, 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)   Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty.  At June 30, 2012, and December 31, 2011, Great Plains Energy netted $3.4 million and $5.5 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 June 30, 2012 and 2011.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative
	Instruments
	(millions)
Balance at April 1	$	2.4		$	5.7
Total realized/unrealized gains
included in non-operating income		0.9			2.1
Settlements		(1.1	)		(2.9	)
Balance at June 30	$	2.2		$	4.9
Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at June 30	$	(0.1	)	$	(0.6	)

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative
	Instruments
	(millions)
Balance at January 1	$	3.1		$	3.7
Total realized/unrealized gains
included in non-operating income		1.1			7.1
Settlements		(2.0	)		(5.9	)
Balance at June 30	$	2.2		$	4.9
Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at June 30	$	(0.7	)	$	1.5

47

15.   TAXES

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

	Three Months Ended						Year to Date
	June 30						June 30
Great Plains Energy	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	(3.3	)	$	2.7		$	(3.3	)	$	3.8
State		0.4			(4.7	)		0.3			(4.0	)
Foreign		-			(0.1	)		-			(0.4	)
Total		(2.9	)		(2.1	)		(3.0	)		(0.6	)
Deferred income taxes
Federal		30.8			32.3			22.5			28.9
State		5.1			11.4			4.3			7.4
Total		35.9			43.7			26.8			36.3
Noncurrent income taxes
Federal		(0.2	)		(19.0	)		(0.2	)		(18.0	)
State		-			(2.0	)		-			(1.9	)
Foreign		(0.4	)		(0.1	)		(0.1	)		0.2
Total		(0.6	)		(21.1	)		(0.3	)		(19.7	)
Investment tax credit amortization		(0.6	)		(0.7	)		(1.2	)		(0.8	)
Income tax expense	$	31.8		$	19.8		$	22.3		$	15.2

	Three Months Ended						Year to Date
	June 30						June 30
KCP&L	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	0.1		$	1.3		$	0.2		$	2.4
State		0.1			0.2			0.1			0.5
Total		0.2			1.5			0.3			2.9
Deferred income taxes
Federal		19.4			23.2			16.1			19.9
State		4.2			4.7			4.1			4.5
Total		23.6			27.9			20.2			24.4
Noncurrent income taxes
Federal		(0.3	)		(11.5	)		0.1			(10.6	)
State		(0.1	)		(1.2	)		-			(1.1	)
Total		(0.4	)		(12.7	)		0.1			(11.7	)
Investment tax credit amortization		(0.4	)		(0.5	)		(0.9	)		(0.5	)
Income tax expense	$	23.0		$	16.2		$	19.7		$	15.1

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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 June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	31.5		$	22.1			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.0			1.1			1.2			1.6
Amortization of investment tax credits		(0.6	)		(0.7	)		(0.7	)		(1.1	)
Federal income tax credits		(3.3	)		(3.8	)		(3.6	)		(6.0	)
State income taxes		3.5			2.6			3.9			4.1
Changes in uncertain tax positions, net		(0.3	)		(1.6	)		(0.4	)		(2.5	)
Valuation allowance		0.1			0.2			0.1			0.3
Other		(0.1	)		(0.1	)		-			-
Total	$	31.8		$	19.8			35.5	%		31.4	%

Great Plains Energy	Income Tax Expense						Income Tax Rate
Year to Date June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	25.0		$	21.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		2.1			1.9			3.0			3.0
Amortization of investment tax credits		(1.2	)		(0.8	)		(1.8	)		(1.4	)
Federal income tax credits		(6.1	)		(6.8	)		(8.6	)		(11.1	)
State income taxes		2.9			3.0			4.1			4.9
Changes in uncertain tax positions, net		(0.1	)		(1.3	)		(0.1	)		(2.2	)
Valuation allowance		0.1			(2.2	)		0.1			(3.6	)
Other		(0.4	)		-			(0.4	)		0.4
Total	$	22.3		$	15.2			31.3	%		25.0	%

KCP&L	Income Tax Expense						Income Tax Rate
Three Months Ended June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	23.4		$	17.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		0.9			0.8			1.3			1.6
Amortization of investment tax credits		(0.4	)		(0.5	)		(0.7	)		(1.0	)
Federal income tax credits		(3.3	)		(3.7	)		(4.9	)		(7.6	)
State income taxes		2.6			1.8			4.0			3.8
Changes in uncertain tax positions, net		-			0.4			-			0.9
Other		(0.2	)		-			(0.2	)		(0.2	)
Total	$	23.0		$	16.2			34.5	%		32.5	%

49

KCP&L	Income Tax Expense						Income Tax Rate
Year to Date June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	23.0		$	18.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.8			1.6			2.7			3.0
Amortization of investment tax credits		(0.9	)		(0.5	)		(1.4	)		(0.9	)
Federal income tax credits		(6.1	)		(6.7	)		(9.3	)		(12.9	)
State income taxes		2.6			2.0			4.1			3.9
Changes in uncertain tax positions, net		-			0.4			-			0.8
Other		(0.7	)		(0.1	)		(1.1	)		(0.3	)
Total	$	19.7		$	15.1			30.0	%		28.6	%

Uncertain Tax Positions

At June 30, 2012, and December 31, 2011, Great Plains Energy had $24.0 million of liabilities related to unrecognized tax benefits.  Of these amounts, $11.7 million and $11.8 million at June 30, 2012, and December 31, 2011, respectively, are expected to impact the effective tax rate if recognized.  

At June 30, 2012, and December 31, 2011, KCP&L had $8.8 million and $8.7 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $0.2 million at June 30, 2012, and December 31, 2011, is expected to impact the effective tax rate if recognized. 

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

	Great Plains Energy						KCP&L
	June 30			December 31			June 30			December 31
	2012			2011			2012			2011
	(millions)
Beginning balance January 1	$	24.0		$	42.0		$	8.7		$	19.1
Additions for current year tax positions		1.5			1.4			1.4			-
Additions for prior year tax positions		-			2.4			-			2.3
Reductions for prior year tax positions		(1.4	)		(20.9	)		(1.3	)		(12.6	)
Statute expirations		-			(0.7	)		-			(0.1	)
Foreign currency translation adjustments		(0.1	)		(0.2	)		-			-
Ending balance	$	24.0		$	24.0		$	8.8		$	8.7

Great Plains Energy and KCP&L recognize interest related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.  At June 30, 2012, and December 31, 2011, accrued interest related to unrecognized tax benefits for Great Plains Energy was $6.1 million and $5.7 million, respectively.  Amounts accrued for penalties with respect to unrecognized tax benefits was $1.1 million at June 30, 2012, and December 31, 2011.  Amounts accrued for interest and penalties with respect to unrecognized tax benefits for KCP&L are insignificant.  

The IRS is currently auditing Great Plains Energy and its subsidiaries for the 2009-2010 tax years.  The Company estimates that it is reasonably possible that $9.3 million for Great Plains Energy and $4.1 million for KCP&L of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities.

50

16.   SEGMENTS AND RELATED INFORMATION

Great Plains Energy has one reportable segment based on its method of internal reporting, which segregates reportable segments based on products and services, management responsibility and regulation.  The one reportable business segment is electric utility, consisting of KCP&L, GMO’s regulated utility operations and GMO Receivables Company.  Other includes GMO activity other than its regulated utility operations, 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
June 30, 2012	Utility			Other			Energy
	(millions)
Operating revenues	$	603.6		$	-		$	603.6
Depreciation and amortization		(67.9	)		-			(67.9	)
Interest charges		(50.4	)		(5.4	)		(55.8	)
Income tax (expense) benefit		(35.9	)		4.1			(31.8	)
Net income (loss) attributable to Great Plains Energy		63.8			(5.7	)		58.1

Year to Date	Electric						Great Plains
June 30, 2012	Utility			Other			Energy
	(millions)
Operating revenues	$	1,083.3		$	-		$	1,083.3
Depreciation and amortization		(135.3	)		-			(135.3	)
Interest charges		(101.1	)		(21.6	)		(122.7	)
Income tax (expense) benefit		(34.1	)		11.8			(22.3	)
Net income (loss) attributable to Great Plains Energy		68.3			(19.3	)		49.0

Three Months Ended	Electric						Great Plains
June 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	565.1		$	-		$	565.1
Depreciation and amortization		(67.6	)		-			(67.6	)
Interest charges		(40.3	)		(10.0	)		(50.3	)
Income tax (expense) benefit		(26.0	)		6.2			(19.8	)
Net income (loss) attributable to Great Plains Energy		49.0			(5.6	)		43.4

Year to Date	Electric						Great Plains
June 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	1,058.0		$	-		$	1,058.0
Depreciation and amortization		(140.0	)		-			(140.0	)
Interest charges		(74.6	)		(20.6	)		(95.2	)
Income tax (expense) benefit		(26.9	)		11.7			(15.2	)
Net income (loss) attributable to Great Plains Energy		56.0			(10.2	)		45.8

51

	Electric							Great Plains
	Utility		Other		Eliminations			Energy
June 30, 2012	(millions)
Assets	$	9,907.8	$	66.1	$	(661.0	)	$	9,312.9
Capital expenditures (a)		263.4		-		-			263.4
December 31, 2011
Assets	$	9,483.4	$	51.9	$	(417.3	)	$	9,118.0
Capital expenditures (a)		456.6		-		-			456.6
(a) Capital expenditures reflect year to date amounts for the periods presented.

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, GMO’s regulated utility operations, which include its Missouri Public Service and St. Joseph Light & Power divisions and GMO Receivables Company.  Electric utility has over 6,600 MWs of generating capacity and engages in the generation, transmission, distribution and sale of electricity to approximately 826,100 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 June 30, 2012, increased to $57.7 million or $0.41 per share from $43.0 million or $0.31 per share for the same period in 2011 driven by:

·   favorable weather with a 30% increase in cooling degree days;

·   new retail rates in Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO; and

·   the three months ended June 30, 2011, included $3.0 million of expense relating to a voluntary separation program and an estimated $11 million impact from an extended refueling outage at Wolf Creek.

These increases were partially offset by:

·   a $6.8 million increase in operating and maintenance expenses at Wolf Creek; and

·   a $5.5 million increase in interest expense primarily due to deferral to a regulatory asset of Iatan Nos. 1, 2 and common facilities construction accounting carrying costs during the three months ended June 30, 2011.

Great Plains Energy’s earnings available for common shareholders year to date June 30, 2012, increased to $48.2 million or $0.34 per share from $45.0 million or $0.32 per share for the same period in 2011 driven by:

·   new retail rates in Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO; and

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·   year to date June 30, 2011 included $12.7 million of expense relating to a voluntary separation program, a $2.3 million loss relating to the impact of disallowed construction costs for the Iatan No. 1 environmental project and Iatan No. 2, $3.9 million of expenses related to other accounting effects of the KCP&L and GMO 2011 MPSC rate orders and an estimated $11 million impact from an extended refueling outage at Wolf Creek.

These increases were partially offset by:

·   unfavorable weather, with a 34% decrease or 1,214 fewer heating degree days during the first quarter of 2012 more than offsetting the impact of a 30% increase or 184 more cooling degree days during the second quarter of 2012;

·   a decrease in weather-normalized retail demand;

·   an estimated $21 million impact from an unplanned outage at Wolf Creek in the first quarter of 2012 and increased amortization from the 2011 extended refueling outage; and

·   a $27.5 million increase in interest expense primarily due to deferral to a regulatory asset of $22.1 million of Iatan Nos. 1, 2 and common facilities construction accounting carrying costs year to date June 30, 2011, and $2.7 million of additional interest expense resulting from the early remarketing in March 2012 of subordinated notes underlying Great Plains Energy’s $287.5 million Equity Units.

Wolf Creek Regulation and Operating Costs

On January 13, 2012, Wolf Creek experienced a loss of off-site power resulting in an unplanned shutdown of the unit.  Wolf Creek returned to service on March 27, 2012.  The NRC conducted an investigation and increased its oversight of Wolf Creek following the loss of off-site power.  Operating costs at Wolf Creek increased year to date June 30, 2012, due to the unplanned outage.  Further increases in the NRC's oversight and involvement in Wolf Creek's operations are expected to occur in the future.  Great Plains Energy is planning to expend more resources at Wolf Creek that will result in future increases in operating costs due to increased NRC oversight and efforts to comply with new industry-wide regulations adopted by the NRC earlier this year after a review of U.S. nuclear power plant safety prompted by Japan's Fukushima Daiichi nuclear power plant event in 2011.

As a result of the 2012 unplanned outage and the extended refueling outage that occurred in 2011, Wolf Creek’s next refueling outage is being delayed from the third quarter of 2012 to the first quarter of 2013.

KCP&L Kansas Rate Case Proceedings

On April 20, 2012, KCP&L filed an application with KCC to request an increase to its retail revenues of $63.6 million, with a return on equity of 10.4% and a rate-making equity ratio of 51.8%.  The request includes recovery of costs related to significant upgrades at its generating facilities, including environmental upgrades at the La Cygne Station; investments in additional wind generation; and increased investments in electrical infrastructure.  KCP&L is also requesting that KCC approve a change to depreciation rates to reflect the increase in plant in service as well as a change to the current method of allocating costs between its Kansas and Missouri jurisdictions to better reflect KCP&L’s summer peaking business.  Testimony from KCC staff and other parties regarding the case is expected in late August 2012, with an evidentiary hearing to occur in October 2012.  The increase to retail revenues is anticipated to be effective in January 2013.

KCP&L Missouri Rate Case Proceedings

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

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its retail rates due to a decline in wholesale power prices, which is being driven by low natural gas prices.  Testimony from MPSC staff and other parties regarding the case was filed on August 2, 2012.  The MPSC staff’s testimony recommended a return on equity range of 8.0% to 9.0% and a revenue increase range of approximately $16.5 million to $33.7 million.  The outcome of the KCP&L Missouri rate case will likely be different from either of the positions of KCP&L or MPSC staff, though the decision of the MPSC cannot be predicted.  An evidentiary hearing is scheduled to occur in October 2012.  The increase to retail revenues is anticipated to be effective in January 2013.

In a March 2011 order, the MPSC required KCP&L and GMO to apply to the 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 June 30, 2012, KCP&L and GMO had $127.0 million and $3.0 million, respectively, of unamortized deferred investment tax credits.

GMO Missouri Rate Case Proceedings

On February 27, 2012, GMO filed an application with the MPSC to request an increase to its retail revenues of $58.3 million for its Missouri Public Service division and $25.2 million for its L&P division, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%.  The requests include recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service, costs related to energy efficiency and demand side management programs, and increased fuel costs.  Testimony from MPSC staff and other parties regarding the case is expected in mid-August 2012, with an evidentiary hearing to occur in October 2012.  The increase to retail revenues is anticipated to be effective in January 2013.

In December 2011, GMO filed a request with the MPSC seeking to recover costs for new and enhanced energy efficiency and demand side management programs under the Missouri Energy Efficiency Investment Act (MEEIA).  A decision on the MEEIA request is anticipated in the third quarter of 2012.

Transmission Investment Opportunities

In April 2012, Great Plains Energy announced that GPE Transmission Holding Company LLC (GPETHC), a newly-formed wholly-owned subsidiary of Great Plains Energy, and AEP Transmission Holding Company, LLC (AEPTHC) have formed a new company to exclusively pursue, develop, construct, own and operate competitive electric transmission projects.  The new company, Transource Energy, LLC (Transource), is 86.5% owned by AEPTHC, a subsidiary of American Electric Power Company, Inc., and 13.5% owned by GPETHC.  Transource plans to initially pursue competitive regional transmission projects in the PJM Interconnection, SPP and Midwest Independent Transmission System Operator transmission regions with plans to pursue competitive electric transmission projects in additional regions as they mature.

GMO has an SPP-approved regional transmission project for the Missouri portion of an approximately 175-mile, 345kV transmission line from Sibley, Missouri to Nebraska City, Nebraska with an estimated cost of $380 million for GMO’s portion of the line and an expected 2017 in-service date.  KCP&L and GMO jointly have an SPP-approved regional transmission project for an approximately 30-mile, 345kV transmission line, with estimated construction costs of $65 million and an expected 2015 in-service date, from KCP&L’s and GMO’s Iatan generating station to KCP&L’s Nashua substation.  KCP&L and GMO plan to seek regulatory approvals to novate these two projects to Transource.  Additionally, KCP&L and GMO will seek to transfer certain development costs and assets acquired to build the transmission lines and be reimbursed by Transource for the costs of such assets and work performed prior to novation.

ENVIRONMENTAL MATTERS

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

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RELATED PARTY TRANSACTIONS

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

GREAT PLAINS ENERGY RESULTS OF OPERATIONS

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

	Three Months Ended						Year to Date
	June 30						June 30
	2012			2011			2012			2011
	(millions)
Operating revenues	$	603.6		$	565.1		$	1,083.3		$	1,058.0
Fuel		(138.1	)		(114.4	)		(257.4	)		(219.3	)
Purchased power		(26.9	)		(55.4	)		(51.6	)		(110.3	)
Transmission of electricity by others		(8.8	)		(7.0	)		(16.1	)		(14.5	)
Gross margin (a)		429.8			388.3			758.2			713.9
Other operating expenses		(211.9	)		(202.1	)		(423.9	)		(404.4	)
Voluntary separation program		-			(3.0	)		-			(12.7	)
Depreciation and amortization		(67.9	)		(67.6	)		(135.3	)		(140.0	)
Operating income		150.0			115.6			199.0			156.8
Non-operating income and expenses		(4.2	)		(2.0	)		(5.1	)		(0.6	)
Interest charges		(55.8	)		(50.3	)		(122.7	)		(95.2	)
Income tax expense		(31.8	)		(19.8	)		(22.3	)		(15.2	)
Loss from equity investments		(0.1	)		(0.1	)		(0.1	)		(0.1	)
Net income		58.1			43.4			48.8			45.7
Less: Net loss attributable to noncontrolling interest		-			-			0.2			0.1
Net income attributable to Great Plains Energy		58.1			43.4			49.0			45.8
Preferred dividends		(0.4	)		(0.4	)		(0.8	)		(0.8	)
Earnings available for common shareholders	$	57.7		$	43.0		$	48.2		$	45.0
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin below.

Three Months Ended June 30, 2012 Compared to June 30, 2011

Great Plains Energy’s earnings available for common shareholders for the three months ended June 30, 2012, increased to $57.7 million or $0.41 per share from $43.0 million or $0.31 per share for the same period in 2011.

Electric utility’s net income increased $14.8 million for the three months ended June 30, 2012, compared to the same period in 2011 driven by:

·   favorable weather with a 30% increase in cooling degree days;

·   new retail rates in Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO; and

·   the three months ended June 30, 2011, included $3.0 million of expense relating to a voluntary separation program and an estimated $11 million impact from an extended refueling outage at Wolf Creek.

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These increases were partially offset by:

·   a $10.1 million increase in interest expense primarily due to deferral to a regulatory asset of $7.8 million of Iatan Nos. 1, 2 and common facilities construction accounting carrying costs during the three months ended June 30, 2011; and

·   a $6.8 million increase in operating and maintenance expenses at Wolf Creek.

Year to Date June 30, 2012 Compared to June 30, 2011

Great Plains Energy’s earnings available for common shareholders year to date June 30, 2012, increased to $48.2 million or $0.34 per share from $45.0 million or $0.32 per share for the same period in 2011.

Electric utility’s net income increased $12.3 million year to date June 30, 2012, compared to the same period in 2011 driven by:

·   new retail rates in Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO; and

·   year to date June 30, 2011, included $12.7 million of expense relating to a voluntary separation program, a $2.3 million loss relating to the impact of disallowed construction costs for the Iatan No. 1 environmental project and Iatan No. 2, $3.9 million of expenses related to other accounting effects of the KCP&L and GMO 2011 MPSC rate orders and an estimated $11 million impact from an extended refueling outage at Wolf Creek.

These increases were partially offset by:

·   unfavorable weather, with a 34% decrease or 1,214 fewer heating degree days during the first quarter of 2012 more than offsetting the impact of a 30% increase or 184 more cooling degree days during the second quarter of 2012;

·   a decrease in weather-normalized retail demand;

·   an estimated $21 million impact from an unplanned outage at Wolf Creek in the first quarter of 2012 and increased amortization from the 2011 extended refueling outage; and

·   a $26.5 million increase in interest expense driven by deferral to a regulatory asset of $22.1 million of Iatan Nos. 1, 2 and common facilities construction carrying costs year to date June 30, 2011.

Great Plains Energy’s corporate and other activities loss increased $9.1 million year to date June 30, 2012, compared to the same period in 2011 primarily due to:

·   a $1.8 million after-tax loss on the sale of real estate property;

·   an additional $1.6 million of after-tax interest expense resulting from the early remarketing in March 2012 of subordinated notes underlying Great Plains Energy’s $287.5 million Equity Units; and

·   year to date June 30, 2011 included a $2.2 million tax benefit from the reversal of tax valuation allowances and a $2.0 million tax benefit recognized on the settlement of the Company’s 2006-2008 federal tax audit.

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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
	June 30						June 30
	2012			2011			2012			2011
	(millions)
Operating revenues	$	603.6		$	565.1		$	1,083.3		$	1,058.0
Fuel		(138.1	)		(114.4	)		(257.4	)		(219.3	)
Purchased power		(26.9	)		(55.4	)		(51.6	)		(110.3	)
Transmission of electricity by others		(8.8	)		(7.0	)		(16.1	)		(14.5	)
Gross margin (a)		429.8			388.3			758.2			713.9
Other operating expenses		(208.8	)		(201.2	)		(416.2	)		(402.6	)
Voluntary separation program		-			(3.0	)		-			(12.7	)
Depreciation and amortization		(67.9	)		(67.6	)		(135.3	)		(140.0	)
Operating income		153.1			116.5			206.7			158.6
Non-operating income and expenses		(3.0	)		(1.2	)		(3.2	)		(1.1	)
Interest charges		(50.4	)		(40.3	)		(101.1	)		(74.6	)
Income tax expense		(35.9	)		(26.0	)		(34.1	)		(26.9	)
Net income	$	63.8		$	49.0		$	68.3		$	56.0
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's Results of Operations.

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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 June 30	2012			2011			Change			2012		2011		Change
Retail revenues	(millions)									(thousands)
Residential	$	236.7		$	217.2			9			2,060		1,976		4
Commercial		242.5			222.9			9			2,790		2,630		6
Industrial		55.4			53.2			4			853		848		1
Other retail revenues		4.9			4.8			5			29		28		2
Kansas property tax surcharge		1.4			-			N/A			N/A		N/A		N/A
Provision for rate refund		-			0.1			N/M			N/A		N/A		N/A
Fuel recovery mechanism		3.8			18.8			N/M			N/A		N/A		N/A
Total retail		544.7			517.0			5			5,732		5,482		5
Wholesale revenues		48.6			37.8			29			2,146		1,132		90
Other revenues		10.3			10.3			-			N/A		N/A		N/A
Operating revenues		603.6			565.1			7			7,878		6,614		19
Fuel		(138.1	)		(114.4	)		21
Purchased power		(26.9	)		(55.4	)		(51	)
Transmission of electricity by others		(8.8	)		(7.0	)		27
Gross margin (a)	$	429.8		$	388.3			11
(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 June 30	2012			2011			Change			2012		2011		Change
Retail revenues	(millions)									(thousands)
Residential	$	426.8		$	418.7			2			4,116		4,413		(7	)
Commercial		431.3			405.2			6			5,253		5,219		1
Industrial		98.2			91.7			7			1,610		1,594		1
Other retail revenues		9.9			9.3			5			60		59		1
Kansas property tax surcharge		2.9			-			N/A			N/A		N/A		N/A
Fuel recovery mechanism		10.2			31.6			N/M			N/A		N/A		N/A
Total retail		979.3			956.5			2			11,039		11,285		(2	)
Wholesale revenues		82.2			79.1			4			3,279		2,389		37
Other revenues		21.8			22.4			(3	)		N/A		N/A		N/A
Operating revenues		1,083.3			1,058.0			2			14,318		13,674		5
Fuel		(257.4	)		(219.3	)		17
Purchased power		(51.6	)		(110.3	)		(53	)
Transmission of electricity by others		(16.1	)		(14.5	)		11
Gross margin (a)	$	758.2		$	713.9			6
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's Results of Operations.

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Electric utility’s gross margin increased $41.5 million for the three months ended June 30, 2012, compared to the same period in 2011 primarily due to:

·   favorable weather with a 30% increase in cooling degree days;

·   new retail rates in Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO; and

·   the three months ended June 30, 2011, included an estimated $11 million impact from an extended refueling outage at Wolf Creek.

Electric utility’s gross margin increased $44.3 million year to date June 30, 2012, compared to the same period in 2011 primarily due to:

·   new retail rates in Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO; and

·   year to date June 30, 2011, included an estimated $11 million impact from an extended refueling outage at Wolf Creek.

These increases were partially offset by:

·   unfavorable weather, with a 34% decrease or 1,214 fewer heating degree days during the first quarter of 2012 more than offsetting the impact of a 30% increase or 184 more cooling degree days during the second quarter of 2012;

·   a decrease in weather-normalized retail demand; and

·   an estimated $4 million impact from an unplanned outage at Wolf Creek in the first quarter of 2012.

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

Electric utility’s other operating expenses increased $7.6 million for the three months ended June 30, 2012, compared to the same period in 2011 primarily due to:

·   a $6.8 million increase in operating and maintenance expenses at Wolf Creek driven by $3.7 million of additional amortization from the 2011 extended refueling outage, along with other increased operating and maintenance expenses; and

·   a $4.7 million increase in general taxes driven by higher property taxes.

These increases were partially offset by a $3.8 million decrease in plant operating and maintenance expenses primarily due to planned plant outages, other than at Wolf Creek, in 2011 with longer durations than in 2012.

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Electric utility’s other operating expenses increased $13.6 million year to date June 30, 2012, compared to the same period in 2011 primarily due to:

·   a $17.0 million increase in operating and maintenance expenses at Wolf Creek driven by $6.8 million of additional amortization from the 2011 extended refueling outage, along with other increased operating and maintenance expenses including an unplanned outage in the first quarter of 2012;

·   a $7.2 million increase in general taxes driven by higher property taxes; and

·   a $4.0 million increase in pension expense resulting from the resetting of pension trackers with the effective dates of new retail rates at KCP&L and GMO in 2011.

These increases were partially offset by:

·   a $7.2 million decrease in plant operating and maintenance expenses primarily due to planned plant outages, other than at Wolf Creek, in 2011 with longer durations than in 2012;

·   deferral to a regulatory asset of $3.0 million relating to solar rebates provided to customers for recovery in future rates; and

·   year to date June 30, 2011, included a $2.3 million loss related to the impact of disallowed construction costs for the Iatan No. 1 environmental project and Iatan No. 2 and $3.9 million of expenses related to other accounting effects of the KCP&L and GMO 2011 MPSC rate orders.

Electric Utility Voluntary Separation Program

In 2011, Great Plains Energy executed an organizational realignment and voluntary separation program to assist in the management of overall costs within the level reflected in the Company’s retail electric rates and to enhance organizational efficiency.  Electric utility recorded expense of $3.0 million and $12.7 million for the three months ended and year to date June 30, 2011, respectively, 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.

Electric Utility Depreciation and Amortization

Electric utility’s depreciation and amortization costs decreased $4.7 million year to date June 30, 2012, compared to the same period in 2011 due to $14.1 million of lower regulatory amortization for KCP&L in Missouri, which was in effect during KCP&L’s Comprehensive Energy Plan but concluded following the May 2011 effective date of new retail rates for KCP&L in Missouri, and a $5.4 million decrease attributable to lower depreciation rates for KCP&L Missouri effective May 4, 2011.  These decreases were partially offset by $6.3 million of depreciation for Iatan No. 2 (Missouri jurisdiction only) and increased depreciation expense for other capital additions.

Electric Utility Interest Charges

Electric utility’s interest charges increased $10.1 million and $26.5 million for the three months ended and year to date June 30, 2012, respectively, compared to the same periods in 2011 primarily due to deferral to a regulatory asset of $7.8 million and $22.1 million of construction accounting carrying costs for Iatan Nos. 1, 2 and common facilities for the three months ended and year to date June 30, 2011, respectively.

Electric Utility Income Tax Expense

Electric utility’s income tax expense increased $9.9 million and $7.2 million for the three months ended and year to date June 30, 2012, respectively, compared to the same periods in 2011 primarily due to increased pre-tax income.

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GREAT PLAINS ENERGY SIGNIFICANT BALANCE SHEET CHANGES

(June 30, 2012 compared to December 31, 2011)

·   Great Plains Energy’s receivables, net decreased $25.1 million due to an $11 million increase in KCP&L’s sale of accounts receivable and GMO’s $56 million sale of accounts receivable, partially offset by seasonal increases in customer accounts receivable.

·   Great Plains Energy’s accounts receivable pledged as collateral and collateralized note payable increased $67.0 million due to an $11 million increase in KCP&L’s sale of accounts receivable and GMO’s $56 million sale of accounts receivable, which are accounted for as secured borrowings.

·   Great Plains Energy’s deferred income taxes – current assets increased $21.0 million primarily due to the reclassification from deferred income taxes – deferred credits and other liabilities of $15.6 million of net operating losses driven by the expected timing of their utilization.

·   Great Plains Energy’s construction work in progress increased $118.3 million primarily due to environmental upgrades at KCP&L’s La Cygne Station.

·   Great Plains Energy’s commercial paper decreased $176.0 million due to the repayment of commercial paper with proceeds from settlement of Great Plains Energy’s Equity Units purchase contracts.

·   Great Plains Energy’s current maturities of long-term debt decreased $294.3 million and long-term debt increased $271.1 million due to the March 2012 remarketing of subordinated notes underlying Great Plains Energy’s $287.5 million Equity Units, which resulted in reclassification from current maturities to long-term debt.

·   Great Plains Energy’s accounts payable decreased $53.1 million primarily due to the timing of cash payments.

·   Great Plains Energy’s accrued taxes increased $38.6 million primarily due to the timing of property tax payments.

·   Great Plains Energy’s deferred income taxes – deferred credits and other liabilities increased $49.7 million due to an increase in temporary differences mostly as a result of bonus depreciation partially offset by the reclassification of net operating losses to deferred income taxes – current assets.

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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 are 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 June 30, 2012, consisted of $6.9 million of cash and cash equivalents on hand and $1.1 billion of unused bank lines of credit.  The unused lines consisted of $164.2 million from Great Plains Energy's revolving credit facility, $494.8 million from KCP&L's credit facilities and $460.8 million from GMO’s credit facilities.  At July 31, 2012, Great Plains Energy’s unused bank lines of credit decreased $497.3 million from the amount at June 30, 2012, due to a $251.3 million decrease from KCP&L's credit facilities and a $246.0 million decrease from GMO’s credit facilities.  See Cash Flows from Financing Activities below for more information.  See Note 8 to the consolidated financial statements for 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 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.

Cash Flows from Operating Activities

The $94.2 million increase in cash flows from operating activities for Great Plains Energy year to date June 30, 2012, compared to the same period in 2011 is primarily due to the payment in 2011 of $26.1 million for the settlement of forward starting swaps upon the issuance of $350.0 million of 4.85% Senior Notes in May 2011 and a decrease in deferred refueling outage costs.  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 proceeds from the sale of properties and insurance recoveries.

Great Plains Energy’s utility capital expenditures increased $70.2 million year to date June 30, 2012, compared to the same period in 2011 due to an increase in cash utility capital expenditures primarily related to environmental upgrades at KCP&L’s La Cygne Station.

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Cash Flows from Financing Activities

In June 2012, Great Plains Energy settled the obligations under the purchase contracts underlying its 5.7 million outstanding Equity Units by issuing approximately 17.1 million shares of its common stock in exchange for $287.4 million in cash proceeds which Great Plains Energy used to make an intercompany loan to GMO.  GMO used the proceeds to make an intercompany loan to KCP&L under the Great Plains Energy money pool, which KCP&L used to repay short-term borrowings.  In July 2012, KCP&L repaid its $256.9 million money pool payable to GMO with increased short-term borrowings.  GMO used the proceeds from the money pool repayment along with increased short-term borrowings to repay its $500 million 11.875% Senior Notes at maturity in July 2012.

Great Plains Energy’s cash flows from financing activities year to date June 30, 2012 also reflect repayment of KCP&L’s $12.4 million of 4.00% EIRR bonds at maturity in January 2012.

Great Plains Energy’s cash flows from financing activities year to date June 30, 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.  Short-term borrowings increased with the proceeds used for KCP&L’s purchase in lieu of redemption of its EIRR Series 1993B bonds totaling $39.5 million and EIRR Series 2007A-1 and 2007A-2 totaling $73.3 million.  Additional short-term borrowings were used to support interest and dividend payments.

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 February 2012, the MPSC authorized KCP&L to issue up to $300.0 million of long-term debt and to enter into interest rate hedging instruments in connection with such debt through December 31, 2013.  KCP&L has not utilized any of this authorization.

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 June 30, 2012, there was $909.0 million available under this authorization.

In January 2012, FERC authorized GMO to have outstanding at any time up to a total of $750.0 million in short-term debt instruments through March 2014, conditioned on GMO’s borrowing costs not exceeding the greater of 2.25% over LIBOR or 1.75% over 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 June 30, 2012, there was $750.0 million available under this authorization.

In November 2011, FERC authorized GMO to issue up to a total of $850.0 million of long-term debt through December 2013.  At June 30, 2012, there was $562.5 million available under this authorization.

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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 June 30, 2012, KCP&L had an outstanding payable under the money pool of $2.5 million to Great Plains Energy and $256.9 million to GMO.  In July 2012, KCP&L repaid the $256.9 million money pool payable to GMO.

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 the Employee Retirement Income Security Act of 1974, as amended (ERISA).

On July 6, 2012, the Moving Ahead for Progress in the 21st Century Act (MAP-21) was signed into federal law.  The new law contains provisions offering funding relief for defined benefit plans by stabilizing interest rates used in determining required ERISA contributions.  The new law should stabilize the fluctuation of interest rates from year to year and is expected to lower the 2012 funding requirements from the amount disclosed in the 2011 Form 10-K.  Year to date June 30, 2012, Great Plains Energy contributed $32.3 million to the pension plans.  Great Plains Energy’s estimate of additional contributions in 2012 is approximately $46.7 million under the new law to satisfy ERISA funding requirements and the MPSC and KCC rate orders, the majority of which is 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 $17.3 million under the provisions of these plans in 2012, 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.

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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
	June 30						June 30
	2012			2011			2012			2011
	(millions)
Operating revenues	$	409.1		$	383.4		$	736.1		$	714.2
Fuel		(98.7	)		(81.5	)		(183.3	)		(149.7	)
Purchased power		(6.6	)		(20.4	)		(13.6	)		(41.8	)
Transmission of electricity by others		(6.1	)		(4.2	)		(11.1	)		(8.5	)
Gross margin (a)		297.7			277.3			528.1			514.2
Other operating expenses		(151.8	)		(148.9	)		(304.9	)		(299.1	)
Voluntary separation program		-			(2.4	)		-			(9.2	)
Depreciation and amortization		(46.0	)		(48.2	)		(91.7	)		(101.6	)
Operating income		99.9			77.8			131.5			104.3
Non-operating income and expenses		(1.9	)		(0.9	)		(2.1	)		(1.4	)
Interest charges		(31.3	)		(27.3	)		(63.7	)		(50.4	)
Income tax expense		(23.0	)		(16.2	)		(19.7	)		(15.1	)
Net income	$	43.7		$	33.4		$	46.0		$	37.4
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's Results of Operations.

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 Ended June 30	2012			2011			Change			2012		2011		Change
Retail revenues	(millions)									(thousands)
Residential	$	147.7		$	138.1			7			1,288		1,231		5
Commercial		172.6			161.9			7			1,949		1,855		5
Industrial		32.5			33.6			(3	)		483		499		(3	)
Other retail revenues		3.1			3.0			2			21		20		2
Kansas property tax surcharge		1.4			-			N/A			N/A		N/A		N/A
Provision for rate refund		-			0.1			N/M			N/A		N/A		N/A
Fuel recovery mechanism		1.3			7.6			N/M			N/A		N/A		N/A
Total retail		358.6			344.3			4			3,741		3,605		4
Wholesale revenues		46.4			35.1			32			2,056		1,046		96
Other revenues		4.1			4.0			2			N/A		N/A		N/A
Operating revenues		409.1			383.4			7			5,797		4,651		25
Fuel		(98.7	)		(81.5	)		21
Purchased power		(6.6	)		(20.4	)		(68	)
Transmission of electricity by others		(6.1	)		(4.2	)		43
Gross margin (a)	$	297.7		$	277.3			7
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's Results of Operations.

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	Revenues and Costs						%			MWhs Sold				%
Year to Date June 30	2012			2011			Change			2012		2011		Change
Retail revenues	(millions)									(thousands)
Residential	$	260.3		$	258.8			1			2,488		2,633		(5	)
Commercial		310.7			296.3			5			3,691		3,689		-
Industrial		59.4			57.7			3			933		940		(1	)
Other retail revenues		6.3			6.1			3			44		43		2
Kansas property tax surcharge		2.9			-			N/A			N/A		N/A		N/A
Fuel recovery mechanism		9.0			12.2			N/M			N/A		N/A		N/A
Total retail		648.6			631.1			3			7,156		7,305		(2	)
Wholesale revenues		78.7			74.0			6			3,145		2,236		41
Other revenues		8.8			9.1			(2	)		N/A		N/A		N/A
Operating revenues		736.1			714.2			3			10,301		9,541		8
Fuel		(183.3	)		(149.7	)		22
Purchased power		(13.6	)		(41.8	)		(67	)
Transmission of electricity by others		(11.1	)		(8.5	)		30
Gross margin (a)	$	528.1		$	514.2			3
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's Results of Operations.

KCP&L’s gross margin increased $20.4 million for the three months ended June 30, 2012, compared to the same period in 2011 primarily due to:

·   favorable weather with a 30% increase in cooling degree days;

·   new retail rates in Missouri effective May 4, 2011; and

·   the three months ended June 30, 2011, included an estimated $11 million impact from an extended refueling outage at Wolf Creek.

KCP&L’s gross margin increased $13.9 million year to date June 30, 2012, compared to the same period in 2011 primarily due to:

·   new retail rates in Missouri effective May 4, 2011; and

·   year to date June 30, 2011, included an estimated $11 million impact from an extended refueling outage at Wolf Creek.

These increases were partially offset by:

·   unfavorable weather, with a 34% decrease or 1,214 fewer heating degree days during the first quarter of 2012 more than offsetting the impact of a 30% increase or 184 more cooling degree days during the second quarter of 2012;

·   a decrease in weather-normalized retail demand; and

·   an estimated $4 million impact from an unplanned outage at Wolf Creek in the first quarter of 2012.

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

KCP&L’s other operating expenses increased $2.9 million for the three months ended June 30, 2012, compared to the same period in 2011 primarily due to a $6.8 million increase in operating and maintenance expenses at Wolf Creek driven by $3.7 million of additional amortization from the 2011 extended refueling outage, along with other increased operating and maintenance expenses.  This increase was partially offset by a $2.3 million decrease in plant operating and maintenance expenses primarily due to planned plant outages, other than at Wolf Creek, in 2011 with longer durations than in 2012.

KCP&L’s other operating expenses increased $5.8 million year to date June 30, 2012, compared to the same period in 2011 primarily due to a $17.0 million increase in operating and maintenance expenses at Wolf Creek driven by $6.8 million of additional amortization from the 2011 extended refueling outage, along with increased other operating and maintenance expenses including an unplanned outage in the first quarter of 2012.  This increase was partially offset by a $6.9 million decrease in plant operating and maintenance expenses primarily due to planned plant outages, other than at Wolf Creek, in 2011 with longer durations than in 2012 and deferral to a regulatory asset of $1.6 million relating to solar rebates provided to customers for recovery in future rates.  Additionally, year to date June 30, 2011, included $1.5 million of losses related to the impact of disallowed construction costs for the Iatan No. 1 environmental project and Iatan No. 2 and $2.4 million of expenses related to other accounting effects of the KCP&L 2011 MPSC rate order.

KCP&L Voluntary Separation Program

KCP&L recorded expense of $2.4 million and $9.2 million for the three months ended and year to date June 30, 2011, respectively, 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 Depreciation and Amortization

KCP&L’s depreciation and amortization costs decreased $9.9 million year to date June 30, 2012, compared to the same period in 2011 due to $14.1 million of lower regulatory amortization for KCP&L in Missouri, which was in effect during KCP&L’s Comprehensive Energy Plan but concluded following the May 2011 effective date of new retail rates for KCP&L in Missouri, and a $5.4 million decrease attributable to lower depreciation rates for KCP&L Missouri effective May 4, 2011.  These decreases were partially offset by $2.9 million of depreciation for Iatan No. 2 (Missouri jurisdiction only) and increased depreciation expense for other capital additions.

KCP&L Interest Charges

KCP&L’s interest charges increased $4.0 million and $13.3 million for the three months ended and year to date June 30, 2012, respectively, compared to the same periods in 2011 primarily due to deferral to a regulatory asset of $2.3 million and $10.7 million of construction accounting carrying costs for Iatan Nos. 1, 2 and common facilities for the three months ended and year to date June 30, 2011, respectively.

KCP&L Income Tax Expense

KCP&L’s income tax expense increased $6.8 million and $4.6 million for the three months ended and year to date June 30, 2012, respectively, compared to the same periods in 2011 primarily due to increased pre-tax income.

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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 2011 Form 10-K and therefore are not represented here.

Great Plains Energy’s and KCP&L’s 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 2011 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 June 30, 2012 was $19.3 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.

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 June 30, 2012, 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 June 30, 2012, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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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 2011 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.

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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 June 30, 2012.

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
April 1 - 30		-		$	-		-		N/A
May 1 - 31		82,043	(1)(2)		19.78		-		N/A
June 1- 30		513	(2)		21.00		-		N/A
Total		82,556		$	19.79		-		N/A
(1) Represents common shares surrendered to the Company to pay taxes related to the vesting of restricted common shares.
(2) Represents common shares surrendered to the Company following the resignation of a certain officer.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

None.

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ITEM 6.  EXHIBITS

Exhibit Number		Description of Document	Registrant
10.1	+	Retirement Agreement dated May 22, 2012, among Great Plains Energy Incorporated, Kansas City Power & Light Company, KCP&L Greater Missouri Operations Company and Michael J. Chesser.	Great Plains Energy KCP&L
10.2		Purchase and Sale Agreement dated as of May 31, 2012, between KCP&L Greater Missouri Operations Company, as Originator, and GMO Receivables Company, as Buyer.	Great Plains Energy
10.3		Receivables Sale Agreement dated as of May 31, 2012, among GMO Receivables Company, as the Seller, KCP&L Greater Missouri Operations Company, as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi, Ltd., New York Branch, as the Agent, and Victory Receivables Corporation.	Great Plains Energy
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 Terry Bassham.	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 Terry Bassham.	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

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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

+ Indicates management contract or compensatory plan or arrangement.

* 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.

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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:  August 8, 2012	By:  /s/ Terry Bassham
	(Terry Bassham)
	(Chief Executive Officer)
Dated:  August 8, 2012	By:  /s/ Lori A. Wright
	(Lori A. Wright)
	(Principal Accounting Officer)

	KANSAS CITY POWER & LIGHT COMPANY
Dated:  August 8, 2012	By:  /s/ Terry Bassham
	(Terry Bassham)
	(Chief Executive Officer)
Dated:  August 8, 2012	By:  /s/ Lori A. Wright
	(Lori A. Wright)
	(Principal Accounting Officer)

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EX-10.1

Exhibit 10.1 

RETIREMENT AGREEMENT

This Retirement Agreement (this “Agreement”) is entered into by and between Great Plains Energy Incorporated, Kansas City Power & Light Company (“KCP&L”) and KCP&L Greater Missouri Operations Company (“GMO”) (collectively, the “Company”), and Michael J. Chesser (the “Executive”) as of May 22, 2012 (the “Effective Date”).  Each of the Company and the Executive is a “Party”, and collectively they are the “Parties”.

WHEREAS, the Executive currently serves as Chief Executive Officer and Chairman of the Board of Directors (the "Board") of the Company;

WHEREAS, the Parties have agreed that the Executive will retire and resign from his position as Chief Executive Officer of the Company and its subsidiaries effective at the close of business on May 31, 2012 (the “Retirement Date”); and

WHEREAS, the Parties wish to enter into this Agreement to set forth the terms and conditions related to the Executive’s retirement.

NOW, THEREFORE, in consideration of the foregoing and the mutual promises contained herein and for other good and valuable consideration, the receipt, adequacy and sufficiency of which is hereby acknowledged, the Parties hereto hereby agree as follows:

1.  Executive’s Retirement.  The Executive shall retire and resign from his position as Chief Executive Officer of the Company and its subsidiaries effective at the close of business on the Retirement Date, without any further action required by the Executive or the Company.  Notwithstanding the foregoing, the Executive shall continue to serve as Chairman of the Board for a period of time (the “Transition Period”) as determined by the Board.  In addition to the compensation set forth in Section 2 of this Agreement, the Executive will be paid his normal salary and benefits through the Retirement Date, less deductions for applicable withholding and payroll taxes (collectively, "Withholding") and, within thirty (30) days following the Retirement Date, will be paid all earned and unpaid salary and any accrued but unused vacation days earned through the Retirement Date, less Withholding.  The Executive also shall receive such benefits to which he is otherwise entitled to receive under the Company's employee benefit plans and programs in accordance with the terms of such plans and programs and this Agreement.  Such benefits shall include, but not necessarily be limited to, vested retirement benefits under the Company's management pension plan, 401(k) plan, supplemental executive retirement plan, and nonqualified deferred compensation plan and the letter agreements between the Company and the Executive dated as of September 10, 2003 and September 16, 2003.

2.      Outstanding Equity and Incentive Compensation Awards; Bonus; Ayco Services;

Reimbursement.

(a)  Notwithstanding anything to the contrary in the Company’s Annual Incentive Plan (the “AIP”), the Executive shall be entitled to a payment due pursuant to the Executive’s 2012 AIP award in accordance with the terms and conditions of such award. For purposes of such AIP award, (i) the Executive’s employment with the Company shall be deemed to have not

1 

terminated prior to the payment of such award, (ii) the Company shall be deemed to have achieved the target level of the financial and key business objectives performance components of the award, and (iii) the Executive shall be deemed to have achieved the target level of the individual performance component of the award.  The payment made pursuant to this Section 2(a) shall be made, no later than March 15, 2013.

(b)  The Executive has received awards of restricted stock (“Restricted Stock Awards”) and performance shares (“Performance Share Awards”) under the Company’s Long-Term Incentive Plan (the “LTIP”) that have not vested or been paid.  These outstanding Restricted Stock Awards and Performance Share Awards shall be treated as follows:

(i)  All Restricted Stock Awards and Performance Share Awards granted to Executive in 2012 shall be forfeited by Executive on the Retirement Date.

(ii)  All Restricted Stock Awards subject to a time-based vesting schedule (i.e., a vesting schedule based solely on the continued employment of the Executive after the grant date) and granted before 2012 will become fully vested upon the Retirement Date.

(iii)  All Performance Share Awards subject to a performance-based vesting schedule (i.e., a vesting schedule based on the achievement of certain established performance goals) and granted to the Executive before 2012 shall not be forfeited, but shall continue in full force and effect without proration as if the Executive’s employment had not terminated prior to the applicable payment, if at all, of the Performance Share Awards.

(iv)  Except as described above, the Executive’s AIP award, Restricted Stock Awards and Performance Share Awards shall be subject to the terms and conditions of the agreements evidencing such awards as well as the AIP and LTIP, as applicable.

(c)  The Executive shall be paid a bonus of $480,000 within fifteen days of his Retirement Date in recognition of the Executive's significant contributions to the Company and as consideration for the Executive's agreement to the releases given in Section 3 of this Agreement.

(d)  The Parties acknowledge that services will be rendered by The Ayco Company, L.P. (“Ayco”) to the Executive and paid by the Company, pursuant to the terms of the agreement dated as of February 16, 2006 between Ayco and the Company, for a period of one year from his Retirement Date.  The Executive acknowledges that the value of such services shall continue to be imputed as income to the Executive.

(e)  In addition, the Executive shall be reimbursed for all reasonable incidental expenses incurred through the Transition Period related to his membership and positions with the various clubs and industry and community organizations (e.g., Greater Kansas City Chamber of Commerce).

(f)  The Executive agrees that except as otherwise provided herein, any and all Company property in his possession shall be returned on his Retirement Date, except that during the

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Transition Period, the Executive shall retain and have the use of the Company-provided cell phone, iPad, and any other similar electronic equipment at the Company’s expense.  Following the Transition Period, the Executive may retain his Company-provided cell phone, iPad and all other similar electronic equipment at no charge, and the Executive shall be solely responsible for any and all expenses related to such devices.  In addition, following the Transition Period and after the Company has removed from the Executive’s Company-provided home computer all Company confidential information, the Executive may retain his Company-provided home computer at no charge.  However, after the end of the Transition Period, the Executive shall be responsible at his own expense for obtaining any necessary licenses for software remaining on said computer.

3.  Releases

(a)  In consideration for the payments and other benefits received under this Agreement, the Executive voluntarily releases and discharges the Company, all of its affiliates, or all of its subsidiaries and each of their agents, officers, directors, employees, and former employees (the "Released Parties"), of and from any and all claims, demands, counterclaims, liabilities, obligations, suits, or causes of action of any kind or nature whatsoever whether in their personal or representative capacities, which the Executive may have had, may now have or may have in the future, arising from or in any way connected with the Executive's employment by Company and his retirement from Company's employment, or relating to matters occurring on or before the date hereof. Without limiting in any way the foregoing, the Executive specifically releases the Released Parties from any and all claims, demands, counterclaims, liabilities, and obligations, causes of action or suits arising:

i. Out of or in any manner related to the employment or retirement of the Executive, including but not limited to the Executive’s employment offer letter dated April 7, 2005; or

ii. Under Title VII of the Civil Rights Act of 1964, as amended, 42 U.S.C. § 2000e-5; or

iii. Under the Age Discrimination in Employment Act ("ADEA"), as amended, 29 U.S.C. § 621, et seq., including the provisions of the Older Workers Benefits Protection Act amendments to the ADEA; or

iv. Under the Americans With Disabilities Act of 1990, 42 U.S.C. § 12101, et seq.; or

v. Under any and all federal, state or local discrimination statutes, laws, ordinances, regulations or Executive Orders including but not limited to the Missouri Human Rights Act, or other applicable state discrimination act; or

vi. Under Family and Medical Leave Act ("FMLA"), or any comparable state statute; or

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vii. Under any exception to the employment-at-will doctrine, including any common-law theory sounding in tort, contract, or public policy; or

viii.           Under the provisions of any state or local wage and hour law or ordinance; or

ix. Under the National Labor Relations Act, as amended, 29 U.S.C. Subsection 141, et seq.; or

x. Under any state "service letter" statute, including but not limited to Missouri's Service Letter Statute, R.S.Mo. 290.140; or

xi.           Under the Equal Pay Act of 1963, as amended; or

xii. Under the Employee Retirement Income Security Act of 1974 ("ERISA"), as amended, except this Section 2 shall not be construed as limiting the Executive's rights of election or claim for payment of benefits under the Management Pension Plan or the Employee Savings Plus Plan; or

xiii. Under Section 806 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. § 1514A; or

xiv. Under the Change In Control Severance Agreement dated as of September 1, 2006.

(b)  Company hereby releases and forever discharges the Executive from any and all liability, claims, and charges, arising from or in any way connected to his employment. In addition, this Agreement will not cause the termination of, or extinguish the Executive's rights under, the Indemnification Agreement dated as of December 2, 2008, between the Executive and the Company.

4.  Tax Matters.  To the extent any payments hereunder are subject to Section 409A of the Internal Revenue Code ("Section 409A"), such payments will be paid in a manner that will meet the requirements of such section, including regulations or other guidance issued with respect thereto, such that the payment will not be subject to the excise tax applicable under such section. Except as otherwise expressly provided herein, to the extent any expense reimbursement or the provision of any in-kind benefit under this Agreement is determined to be subject to Section 409A, the amount of any such expenses eligible for reimbursement, or the provision of any in-kind benefit, in one calendar year shall not affect the expenses eligible for reimbursement in any other calendar year (except for any life-time or other aggregate limitation applicable to medical expenses), in no event shall any expenses be reimbursed after the last day of the calendar year following the calendar year in which Employee incurred such expenses, and in no event shall any right to reimbursement or the provision of any in-kind benefit be subject to liquidation or exchange for another benefit. The Executive acknowledges and agrees that he is responsible for all federal, state, and local income or earnings taxes and the Executive's portion of any employment taxes due on payments made under this Agreement and arising under each of the Company's plans and programs.  The Company has no duty to defend the Executive in any tax-related proceeding brought against, or any inquiry raised with, the Executive.

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5.  Confidentiality.  The Executive covenants and agrees that all prior agreements relating to confidentiality of proprietary Company information ("Confidential Information") and trade secrets of which the Executive has gained knowledge through his employment shall remain in effect and survive this Agreement. The terms Confidential Information and "trade secrets" shall not be deemed to include information that is accessible to or otherwise known by the public.

6.  No Disparagement.  The Parties agree and covenant that they will not disparage one another for any reason, or make any comments that might be harmful to the other Party's reputation.

7.  Other Provisions.

(a)  The Company has advised the Executive to consult with counsel prior to the execution of this Agreement, and the Executive and the Company acknowledge that they have fully read and considered the contents of this Agreement, and that they have had the opportunity to consult with and receive independent legal advice from counsel of their choice regarding the advisability hereof. The Company and the Executive fully, completely, and totally comprehend the provisions hereof and are in full agreement with each and every one of its terms, conditions, and provisions.

(b)  This Agreement shall be construed in accordance with the laws of the State of Missouri. Any dispute relating to this Agreement shall be brought in an appropriate Circuit Court of Missouri or the U.S. District Court for the Western District of Missouri.

(c)  This Agreement contains the entire agreement between the Executive and the Company concerning the foregoing matters and no change, modification, or waiver of any provision hereof will be valid unless in writing and signed by the Parties to be bound.

(d)  The provisions of this Agreement are severable, and if any paragraph or part of any paragraph is found to be unenforceable or inoperable, then other paragraphs or the remainder of the particular paragraph, whichever applies, shall remain fully valid and enforceable.

(e)  Unless otherwise covered by a specific beneficiary designation, in the event of the Executive’s death, the unpaid balance of the amounts due to the Executive under this Agreement shall be paid to the Executive’s estate.

8.  The Executive acknowledges that he received this document on May 1, 2012, and that he is legally entitled to consider this Agreement for twenty-one (21) days before executing this Agreement.  The Executive acknowledges that he may revoke (cancel) this Agreement within seven (7) days after executing it, by delivering written notice to Robert H. West, Lead Director of the Board. Unless revoked by the Executive within seven (7) days after execution, this Agreement will be final and binding on the eighth (8th) day following the Executive's execution of this Agreement.

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THE EXECUTIVE ACKNOWLEDGES THAT HE HAS CAREFULLY READ THIS AGREEMENT, THAT HE KNOWS AND UNDERSTANDS THE CONTENTS THEREOF AND THAT HE EXECUTES THE SAME AS HIS OWN FREE ACT AND DEED.

In witness whereof, the Company and the Executive have signed this Agreement as of the date first above written.

Great Plains Energy Incorporated	Executive
Kansas City Power & Light Company
KCP&L Greater Missouri Operations Company
By: /s/ Terry Bassham	/s/ Michael J. Chesser
Terry Bassham        President and Chief Operating Officer	Michael J. Chesser

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EX-10.2

Exhibit 10.2

==========================================================================================

Purchase and Sale Agreement

Dated as of May 31, 2012

between

KCP&L Greater Missouri Operations Company,

as Originator,

and

GMO Receivables Company,

as Buyer

==========================================================================================

Table of Contents

Section	Heading	Page
Section 1.	Definitions and Related Matters	1
Section 1.1.	Defined Terms	1
Section 1.2.	Other Interpretive Matters	2
Section 2.	Agreement to Contribute, Purchase and Sell	2
Section 2.1.	Purchase and Sale	2
Section 2.2.	Timing of Contribution, Purchases	2
Section 2.3.	Purchase Price	3
Section 2.4.	No Recourse or Assumption of Obligations	3
Section 3.	Administration and Collection	4
Section 3.1.	Originator to Act as Collection Agent	4
Section 3.2.	Deemed Collections	4
Section 3.3.	Application of Collections	5
Section 3.4.	Responsibilities of Originator	5
Section 4.	Representations and Warranties	5
Section 4.1.	Mutual Representations and Warranties	5
Section 4.2.	Additional Representations by Originator	6
Section 5.	General Covenants	8
Section 5.1.	Covenants	8
Section 5.2.	Organizational Separateness	12
Section 6.	Termination of Contributions and Purchases	12
Section 6.1.	Voluntary Termination	12
Section 6.2.	Automatic Termination	12
Section 7.	Indemnification	12
Section 7.1.	Originator’s Indemnity	12
Section 7.2.	Indemnification Due to Failure to Consummate Purchase	14
Section 7.3.	Other Costs	15
Section 8.	Miscellaneous	15
Section 8.1.	Amendments, Waivers, etc	15
Section 8.2.	Assignment of Purchase and Sale Agreement	15
Section 8.3.	Binding Effect; Assignment	16
Section 8.4.	Survival	16

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Section 8.5.	Costs, Expenses and Taxes	16
Section 8.6.	Execution in Counterparts; Integration	16
Section 8.7.	Governing Law; Submission to Jurisdiction	16
Section 8.8.	No Proceedings	16
Section 8.9.	Loans by Buyer to Originator	16
Section 8.10.	Notice	17
Section 8.11.	Entire Agreement	17
Section 8.12.	Confidentiality	17
Section 8.13.	Waiver of Trial by Jury	17
Signature		18

Exhibit A Purchase Price

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This Purchase and Sale Agreement dated as of May 31, 2012 (this “Agreement”) is between KCP&L Greater Missouri Operations Company, a Delaware corporation (“Originator”), and GMO Receivables Company, a Delaware corporation (“Buyer”).  The parties agree as follows:

Section 1.  Definitions and Related Matters.

Section 1.1.Defined Terms.  In this Agreement, unless otherwise specified or defined herein: (a) capitalized terms are used as defined in Schedule I to the Receivables Sale Agreement dated as of the date hereof (as amended or modified from time to time, the “Second Tier Agreement”) among Buyer, Originator, as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as the Agent, and Victory Receivables Corporation, as such agreement may be amended or modified from time to time; and (b) terms defined in Article 9 of the UCC and not otherwise defined herein are used as defined in such Article 9.

In addition, the following terms will have the meanings specified below:

“Available Funds” is defined in Section 2.3(b) hereof.

 “Closing Date” means the date on which this Agreement and the Second Tier Agreement become effective in accordance with their terms.

“Collection Agent Fee“ is defined in Section 3.6 of the Second Tier Agreement.

“Contributed Receivables” is defined in Section 2.2 hereof.

“Credit Agreement” means the Credit Agreement, dated as of August 9, 2010, among Originator, Great Plains Energy Incorporated, certain lenders party thereto, Bank of America, N.A., as Administrative Agent, and Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, The Royal Bank of Scotland PLC and BNP Paribas, as Documentation Agents, Banc of America Securities LLC, Union Bank, N.A. and Wells Fargo Securities, LLC as Joint Lead Arrangers and Joint Book Managers, as amended by the First Amendment to Credit Agreement dated as of December 9, 2011 among Originator, Great Plains Energy Incorporated, certain lenders party thereto, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, Bank of America, N.A., as Administrative Agent, The Royal Bank of Scotland PLC and BNP Paribas, as Documentation Agents, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Union Bank, N.A. and Wells Fargo Securities, LLC as Joint Lead Arrangers and Joint Book Managers.

“Excluded Losses” is defined in Section 7.1 hereof.

“Initial Funding Date” means June 1, 2012, which is the date of the first purchase by Buyer from Originator, and the first contribution by Originator to Buyer under this Agreement.

“Settlement Date” means, with respect to each calendar month, the second Business Day after the Monthly Report Date for such calendar month; provided, however, that upon the occurrence and during the continuation of a Termination Event, the Settlement Date shall be a Business Day each calendar month as designated by the Agent.

“Settlement Period” means with respect to each Settlement Date, the calendar month preceding such Settlement Date (or, in the case of the first Settlement Period, the period from the Initial Funding Date to the end of the calendar month in which the Initial Funding Date occurs); provided, however, that upon the occurrence and during the continuation of a Termination Event, the Agent upon prior written notice to Originator and Buyer, may change the Settlement Period to be the period from a specified day during one calendar month to the same specified day during the following calendar month (e.g., a Settlement Period running from the 10th calendar day of one month to the 10th calendar day of the following month).

“Total Capitalization” shall have the meaning set forth in the Credit Agreement as of the date hereof.

“Total Indebtedness” shall have the meaning set forth in the Credit Agreement as of the date hereof.

Section 1.2.Other Interpretive Matters.  In this Agreement, unless otherwise specified:  (a) references to any Section or Annex refer to such Section of, or Annex to, this Agreement, and references in any Section or definition to any subsection or clause refer to such subsection or clause of such Section or definition; (b) “herein”, “hereof”, “hereto”, “hereunder” and similar terms refer to this Agreement as a whole and not to any particular provision of this Agreement; (c) “including” means including without limitation, and other forms of the verb “to include” have correlative meanings; (d) the word “or” is not exclusive; and (e) captions are solely for convenience of reference and shall not affect the meaning of this Agreement.

Section 2.  Agreement to Contribute, Purchase and Sell.

Section 2.1.Purchase and Sale.  On the terms and subject to the conditions set forth in this Agreement, Originator hereby sells and contributes to Buyer, and Buyer hereby purchases and accepts each such contribution from Originator, all of Originator’s right, title and interest in, to and under the Receivables, all Related Security and all proceeds thereof (including all Collections with respect thereto), in each case whether now existing or hereafter arising or acquired.  The proceeds with respect to each Receivable (including all Collections with respect thereto) are sold or contributed by Originator to Buyer together with such Receivable, whether such proceeds (or Collections) exist at such time or arise or are acquired thereafter.

Section 2.2.Timing of Contribution, Purchases.  Originator hereby, pursuant to the terms hereof and the terms of the Stockholder and Subscription Agreement between Originator and Buyer dated as of May 31, 2012, has agreed to contribute $1,800,000 in cash as an initial capital contribution to Buyer, it being understood that in lieu of a payment of such capital contribution in cash, Originator hereby agrees that Buyer may net from the purchase price

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payable to the Originator on the Initial Funding Date the amount of such capital contribution and pay to the Originator the excess of such purchase price over such capital contribution.  After the Initial Funding Date, upon the creation of each Receivable, it shall immediately, and without further action by any Person, be sold to Buyer pursuant to Section 2.3 or contributed by Originator to Buyer (each a “Contributed Receivable”).  

Section 2.3.Purchase Price.  (a) The aggregate purchase price for the portion of the Receivables sold on the Initial Funding Date shall be such amount as agreed upon prior to the Initial Funding Date between Originator and Buyer, which shall be the fair market value of such Receivables on such date, and which shall equal the excess of the (i) estimated aggregate outstanding balance of such Receivables over (ii) the sum of (x) the bad debt reserves maintained by the Originator and (y) a discount agreed upon by Buyer and Originator representing the uncertainty of payment and cost of purchase of such Receivables.  The purchase price for Receivables subsequently sold by Originator to Buyer shall be calculated in accordance with the provisions set forth in Exhibit A hereto.

(b)On the Initial Funding Date, Buyer shall pay Originator the purchase price for the portion of the Receivables sold on that date, which shall be the fair market value of such Receivables on such date, as follows:  First, the Buyer shall pay to the Originator cash in the amount of the net proceeds received from the sale of the Purchase Interest under the Second Tier Agreement and Second, the remainder shall be paid by the Buyer borrowing an initial advance under the promissory note (as amended or modified from time to time, the “Subordinated Note”) executed and delivered by Buyer to the order of Originator as of the Initial Funding Date.  On each Business Day after the Initial Funding Date on which Originator sells any Receivables to Buyer pursuant to the terms of Section 2.1, until the termination of the purchase and sale of Receivables under Section 6 hereof, Buyer shall pay to Originator the purchase price of such Receivables (i) by depositing into such account as Originator shall specify immediately available funds from monies then held by or on behalf of Buyer (solely to the extent that such monies do not constitute Collections that are required to be identified or are deemed to be held by the Collection Agent pursuant to the Second Tier Agreement for the benefit of, or required to be distributed to, the Agent or the Buyer or required to be paid to the Collection Agent as the Collection Agent Fee, or otherwise necessary to pay current expenses of Buyer (in its reasonable discretion)) (such available monies, the “Available Funds”) and provided that Originator has paid all amounts then due by Originator hereunder or (ii) by increasing the principal amount owed to Originator under the Subordinated Note.  Any Receivables that are not paid for by either of these methods shall constitute Contributed Receivables.  The outstanding principal amount owed to Originator under the Subordinated Note may be reduced from time to time as provided in Section 3.2 hereof or by payments made by Buyer to Originator from Available Funds, provided that Originator has paid all amounts then due by Originator hereunder.  Originator shall make all appropriate record keeping entries with respect to amounts due to Originator under the Subordinated Note to reflect payments by Buyer thereon and increases of the principal amount thereof, and Originator’s books and records shall constitute rebuttable presumptive evidence of the principal amount of and accrued interest owed to Originator under the Subordinated Note.

Section 2.4.No Recourse or Assumption of Obligations.  Except to the limited extent specifically provided in this Agreement, the contribution, purchase and sale of Receivables under

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this Agreement shall be without recourse to Originator.  Originator and Buyer intend the transactions hereunder to constitute absolute, irrevocable and unconditional true sales, transfers and/or capital contributions, as applicable, of Receivables by Originator to Buyer, providing Buyer with the full risks and benefits of ownership of the Receivables (such that the Receivables would not be property of Originator’s estate in the event of Originator’s bankruptcy).  If, however, despite the intention of the parties, the conveyances provided for in this Agreement are determined not to be true sales, absolute transfers and/or capital contributions, as applicable, of Receivables from Originator to Buyer, then this Agreement shall also be deemed to be a “security agreement” within the meaning of Article 9 of the UCC and Originator hereby grants to Buyer a “security interest” within the meaning of Article 1 of the UCC in all of Originator’s right, title and interest in and to such Receivables (including the proceeds thereof), now existing and thereafter created, to secure a non-recourse loan in an amount equal to the aggregate purchase prices therefor and each of Originator’s other payment obligations (including the obligation to remit to Buyer all Collections of all Receivables) under this Agreement.

Buyer shall not have any obligation or liability with respect to any Receivable, nor shall Buyer have any obligation or liability to any Obligor or other customer or client of Originator (including any obligation to perform any of the obligations of Originator under any Receivable).

Section 3.  Administration and Collection.

Section 3.1.Originator to Act as Collection Agent.  Notwithstanding the sale or contribution of Receivables pursuant to this Agreement, Originator shall be retained under the Second Tier Agreement to serve as Collection Agent with respect to the Receivables.  In its capacity as Collection Agent, Originator will continue to be responsible for the servicing, administration and collection of the Receivables, all on the terms set out in (and subject to any rights to terminate Originator as Collection Agent pursuant to) the Second Tier Agreement.

Section 3.2.Deemed Collections.  If on any day the outstanding balance of a Receivable sold hereunder is reduced or cancelled as a result of any defective or rejected goods or services, any cash discount or adjustment (including as a result of the application of any special refund or other discounts or any reconciliation), any setoff, credit or bona fide dispute (whether such claim or credit, bona fide dispute arises out of the same, a related, or an unrelated transaction); provided, however, that such reductions or cancellations shall not include any amounts arising from the credit risk of the related Obligor, or the refusal or the financial inability of the related Obligor, to pay undisputed indebtedness, (i) Originator shall be deemed to have received on such day a Collection on such Receivable in the amount of such reduction or cancellation and (ii) such Receivable shall thereupon be, or be deemed to be reconveyed to Originator.  If on any day any representation, warranty, covenant or other agreement of Originator related to a Receivable is discovered to have been untrue or not satisfied in any material respect as of the date such Receivable was sold or contributed hereunder, (i) Originator shall be deemed to have received on such day a Collection in the amount of the outstanding balance of such Receivable and (ii) such Receivable shall thereupon be, or be deemed to be reconveyed to Originator.  After Originator is deemed pursuant to this Section 3.2 to have received any Collections, Originator shall transfer to Buyer, in immediately available funds, the amount of such Deemed Collections on the date that is the later to occur of (i) the Settlement Date following such deemed receipt and (ii) the second

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Business Day following such deemed receipt; provided, however, that if no such application is required under the Second Tier Agreement, Buyer and Originator may agree to reduce the outstanding principal amount of the Subordinated Note in lieu of all or part of such transfer.  To the extent that Buyer subsequently collects any payment with respect to any such Receivable that was previously reconveyed to Originator, Buyer shall pay Originator an amount equal to the amount so collected, such amount to be payable on the date that is the later to occur of (i) the Settlement Date following receipt of such amount and (ii) the second Business Day following such receipt of such amount.

Section 3.3.Application of Collections.  Any payment by an Obligor in respect of any indebtedness owed by it with respect to any Receivable or otherwise owed by it to Originator shall, except as otherwise specified by such Obligor (including by reference to a particular invoice), or required by the related contracts or law, be applied, first, as a Collection of any Receivable or Receivables then outstanding of such Obligor in the order of the age of such Receivables, starting with the oldest of such Receivables, and, second, to any other indebtedness of such Obligor to Originator.

Section 3.4.Responsibilities of Originator.  Originator shall pay when due all Taxes payable in connection with the Receivables or their creation or satisfaction.  Originator shall perform all of its obligations under agreements related to the Receivables to the same extent as if interests in the Receivables had not been transferred hereunder.  The Agent’s or the Buyer’s exercise of any rights hereunder or under the Second Tier Agreement shall not relieve Originator from such obligations.  Neither the Agent nor the Buyer shall have any obligation to perform any obligation of Originator or any other obligation (other than the obligation to act in good faith and with commercial reasonableness) or liability in connection with the Receivables.

Section 4.  Representations and Warranties.

Section 4.1.Mutual Representations and Warranties.  Each of Originator and Buyer represents and warrants to the other with respect to itself as follows:

(a)Existence and Power.  It is a corporation, duly organized, validly existing and in good standing under the laws of its state of incorporation and has all corporate power and authority and all governmental licenses, authorizations, consents and approvals required to carry on its business in each jurisdiction in which its business is now conducted, except where failure to obtain such license, authorization, consent or approval could not reasonably be expected to have a material adverse effect on (i) its ability to perform its obligations under, or the enforceability of, any Transaction Document to which it is a party, (ii) its business or financial condition, (iii) the interests of Buyer under any Transaction Document or (iv) the enforceability or collectibility of the Receivables (“Material Adverse Effect”).

(b)Authorization and No Contravention.  Its execution, delivery and performance of each Transaction Document to which it is a party (i) are within its corporate powers, (ii) have been duly authorized by all necessary corporate action, (iii) do not contravene or constitute a default under:  (A) any applicable law, rule or

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regulation binding an Originator or Buyer in any material respect, (B) its charter or by-laws or (C) any agreement, order or other instrument to which it is a party or its property is subject except to the extent such contravention or default would not have a Material Adverse Effect and (iv) will not result in any Adverse Claim on any Receivable or Collection or give cause for the acceleration of any of its indebtedness.

(c)No Consent Required.  Other than the filing of financing statements and the items set forth in the next sentence, no approval, authorization or other action by, or filings with, any Governmental Authority or other Person is required (other than any already given or obtained) in connection with the execution, delivery and performance by it of any Transaction Document to which it is a party or any transaction contemplated thereby.  The Transaction Documents and the transactions contemplated thereby are subject to filing requirements or reporting requirements, or both, under the Securities Exchange Act of 1934, as amended, and Chapters 386 and 393 of the Missouri revised statutes, as amended, and the rules and regulations promulgated thereunder.

(d)Binding Effect.  Each Transaction Document to which it is a party constitutes the legal, valid and binding obligation of such Person enforceable against such Person in accordance with its terms, except as limited by bankruptcy, insolvency, or other similar laws of general application relating to or affecting the enforcement of creditors’ rights generally and subject to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 4.2.Additional Representations by Originator.  Originator further represents and warrants to Buyer as follows:

(a)Perfection of Ownership Interest.  Immediately preceding its sale or contribution of Receivables to Buyer, Originator was the owner of, and effectively sold or contributed, such Receivables to Buyer, free and clear of any Adverse Claim, except for the interests of the Secured Parties therein that are created by the Second Tier Agreement.  Other than the ownership interest granted to Buyer pursuant to this Agreement, Originator has not pledged, assigned, sold or granted a security interest in, or otherwise conveyed, the Receivables or the Collections, other than any such pledge, assignment or grant that has been terminated in full prior to the sale or contribution hereunder.  Originator has not authorized the filing of and is not aware of any financing statements against Originator that include a description of collateral covering the Receivables or the Collections other than any financing statement relating to the security interest granted to Buyer hereunder or the Secured Parties under the Second Tier Agreement or that has been terminated in full prior to the sale or contribution hereunder.  Originator has caused or will have caused, within ten days after the date hereof, the filing of all appropriate financing statements in the proper filing office in the appropriate jurisdictions under the applicable law in order to perfect the conveyance of Receivables and Collections by Originator hereunder.

(b)Accuracy of Information.  All written information furnished by Originator in connection with any Transaction Document, or any transaction contemplated thereby,

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is true and accurate in all material respects as of the date it was dated (and, when considered together with all current reports filed by Originator or Parent with the SEC under the Securities Exchange Act of 1934,as amended, was not incomplete by omitting to state a material fact necessary to make such information not materially misleading in light of the circumstances when made).

(c)No Actions, Suits. Except as disclosed by Parent in its current reports filed with the SEC under the Securities Exchange Act of 1934, as amended, there are no actions, suits or other proceedings (including matters relating to environmental liability) pending or threatened against or affecting Originator or any of its properties, that (i) is reasonably likely to have a material adverse effect on the financial condition of the Originator or on the collectibility of the Receivables or (ii) seeks to challenge the validity of Originator’s obligations under any Transaction Document to which it is a party or any transaction contemplated thereby.  Originator is not in default of any contractual obligation or in violation of any order, rule or regulation of any Governmental Authority, which default or violation could reasonably be expected to have a material adverse effect upon (i) the financial condition or the Originator or (ii) the collectibility of the Receivables.

(d)No Material Adverse Change.  Since March 31, 2012 and except as disclosed by Parent in its current reports filed with the SEC under the Securities Exchange Act of 1934, as amended, there has been no material adverse change in (i) the collectibility of the Receivables or (ii) the Originator’s financial condition, business or results of operations or its ability to perform its obligations under any Transaction Document.

(e)Accuracy of Exhibits. All information on Exhibits D and E of the Second Tier Agreement (to the extent describing Originator) is true and complete, subject to any changes permitted by, and notified to the Agent in accordance with the Second Tier Agreement.

(f)Sales by Originator.  Each sale by Originator to Buyer of an interest in Receivables has been made for “reasonably equivalent value” (as such term is used in Section 548 of the Bankruptcy Code) and not for or on account of “antecedent debt” (as such term is used in Section 547 of the Bankruptcy Code) owed by Originator to Buyer.

(g)Use of Proceeds.  No proceeds of any purchase will be used (i) for the purpose which violates, or would be inconsistent with, Regulation T, U or X promulgated by the Board of Governors of the Federal Reserve System from  time to time or (ii) to acquire any security in any transaction which is subject to Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended.

(h)Lock-Box Accounts.  The names and address of all the Collection Banks and addresses of the Lock-Boxes, are specified in Exhibit F.

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(i)Nature of Pool Receivables.  All Receivables originated by Originator (i) were originated by Originator in the ordinary course of its business, (ii) represent all, or a portion of the purchase price of goods, insurance or services within the meaning of Section 3(c)(5)(A) of the Investment Company Act, 1940.

(j)Credit and Collection Policies.  Originator has complied with the Credit and Collection Policies in all material respects, and such policies have not changed in any material respect (except to the extent required by law, rule or regulation) since the date hereof unless Agent has consented in writing to such change.

(k)Eligible Receivables.  Each Receivable shall be an Eligible Receivable on the date of any purchase or contribution hereunder, unless otherwise specified in the first Periodic Report that includes such Receivable.

Section 5.  General Covenants.

Section 5.1.Covenants.  Originator hereby covenants and agrees to comply with the following covenants and agreements, unless Buyer (with the consent of the Agent) shall otherwise consent:

(a)Financial Reporting. Originator shall, and shall cause the Parent, to maintain a system of accounting established and administered in accordance with GAAP and shall furnish to Buyer:

(i)Within 90 days after each fiscal year of the Parent, (a) copies of the Parent’s annual audited financial statements (including a consolidated balance sheet, consolidated statement of income and retained earnings and statement of cash flows, with related footnotes) certified by an independent registered public accounting firm which is generally recognized as being among the “big four” and prepared on a consolidated basis in conformity with GAAP, and (b) an unaudited consolidating balance sheet for the Parent and its consolidated Subsidiaries as of the end of such period and related consolidating income statements, certified by a  Designated Financial Officer of the Parent;

(ii)Within 45 days after the close of the first three (3) quarterly periods of each of the Parent’s fiscal years, (a) for the Parent and its consolidated Subsidiaries, either (I) consolidated unaudited balance sheets as at the close of each such period and consolidated and consolidating profit and loss and reconciliation of surplus statements and a statement of cash flows for the period from the beginning of such fiscal year to the end of such quarter, all certified by a Designated Financial Officer of the Parent or (II) if the Parent is then a “registrant” within the meaning of Rule 1-01 of Regulation S-X of the SEC and required to report on Form 10-Q with the SEC, a copy of the Parent’s report on Form 10-Q for such quarterly period and (b) either (I) consolidating unaudited balance sheets and related consolidating income statements for the Parent and its consolidated Subsidiaries as at the close of each such period, all certified by a

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Designated Financial Officer of the Parent or (II) if the Parent is then a “registrant” within the meaning of Rule 1-01 of Regulation S-X of the SEC and required to report on Form 10-Q with the SEC, a copy of the Parent’s report on Form 10-Q for such quarterly period;

(iii)Promptly upon becoming available, a copy of each report or proxy statement filed by the Parent with the Securities and Exchange Commission or any securities exchange;

(iv)Promptly after the filing or receiving thereof, copies of all reports and notices with respect to any “Reportable Event” defined in Article IV of ERISA that could reasonably be expected to result in a liability in an aggregate amount in excess of$50,000,000 which Parent files under ERISA with the Internal Revenue Service, the Pension Benefit Guaranty Corporation or the U.S. Department of Labor or which Parent receives from the Pension Benefit Guaranty Corporation;

(v)[Reserved];

(vi)[Reserved]; and

(vii)With reasonable promptness such other information (including non-financial information) as Buyer may reasonably request.

The statements and reports of the Parent required to be furnished pursuant to clauses (i), (ii) and (iii) above shall be deemed furnished for such purpose upon becoming publicly available on the Securities and Exchange Commission’s EDGAR web page.

(b)Notices.  Promptly and in any event within five Business Days after a Designated Financial Officer of Originator obtains knowledge of any of the following, Originator will notify Buyer and the Agent and provide a description of:

(i)Potential Termination Events.  The occurrence of any Potential Termination Event;

(ii)Representations and Warranties.  The failure of any representations or warranty herein to be true when made in any material respect; or

(iii)Litigation.  The institution of any litigation, arbitration proceeding or governmental proceeding reasonably likely to be material to the collectibility or quality of the Receivables which is not referenced in the Parent’s filings with the SEC.

(c)Conduct of Business.  The Originator will perform all actions necessary to remain duly incorporated, validly existing and in good standing in its jurisdiction of

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incorporation and to maintain all requisite authority to conduct its business in each jurisdiction in which it conducts business except where the failure to do so could not reasonably be expected to have a material adverse effect on the collectibility of the Receivables.  

(d)Compliance with Laws.  The Originator will comply with all laws, regulations, judgments and other directions or orders imposed by any Governmental Authority to which the Originator or any Receivable, any Related Security or Collection may be subject, except where the failure to do so could not reasonably be expected to have a material adverse effect on the collectibility of the Receivables.

(e)Furnishing Information and Inspection of Records.  Originator will furnish to Buyer and the Agent (as assignee of the Buyer) such information concerning the Receivables as Buyer may reasonably request.  With reasonable notice, Originator will permit, at any time during regular business hours, Buyer or the Agent (as assignee of the Buyer) (or), in each case, any representatives thereof) (i) to examine and make copies of all Records, (ii) to visit the offices and properties of Originator for the purpose of examining the Records and (iii) to discuss matters relating hereto with any of Originator’s officers, directors, employees or independent public accountants having knowledge of such matters.  

(f)Keeping Records.  (i) Originator will have and maintain (A) administrative and operating procedures (including an ability to recreate Records if originals are destroyed), (B) adequate facilities, personnel and equipment (which may be arranged through joint operating, service or similar agreements with affiliates) and (C) all Records and other information necessary or advisable for collecting the Receivables (including Records adequate to permit the immediate identification of each new Receivable and all Collections of, and adjustments to, each existing Receivable).  Originator will give Buyer prior notice of any material change in such administrative operating procedures.

(ii)Originator will at all times from and after the date hereof, clearly and conspicuously mark its computer and master data processing books and records with a legend describing Buyer’s ownership of, and in the alternative, security interest in the Receivables and the Collections.

(g)Perfection.  (i) The Originator will at its expense, promptly execute and deliver all instruments and documents and take all action necessary or reasonably requested by the Buyer (including the execution and filing of financing or continuation statements, amendments thereto or assignments thereof) to vest and maintain vested in the Buyer a valid, first priority perfected security interest in the Receivables, the Collections, the Lock-Boxes, the Collection Account and proceeds thereof free and clear of any Adverse Claim (and a perfected ownership interest in the Receivables and Collections to the extent of the Purchase Interest).  To the extent permitted by applicable law, the Buyer will be permitted to sign and file any continuation statements, amendments thereto and assignments thereof without the Originator’s signature.

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(ii)The Originator will not change its name, identity or corporate structure or relocate its jurisdiction of organization or chief executive office or the Records except after fifteen (15) days advance notice to the Buyer and the Agent and the delivery to the Buyer and the Agent of all financing statements, instruments and other documents (including direction letters) requested by the Buyer and the Agent.

(iii)The Originator will at all times maintain its chief executive offices and maintain its jurisdiction of organization within a jurisdiction in the USA in which Article 9 of the UCC is in effect.  If the Originator moves its chief executive office to a location that imposes Taxes, fees or other charges to perfect the Buyer’s interests hereunder, the Originator will pay all such amounts and any other costs and expenses incurred in order to maintain the enforceability of the Transaction Documents, the Purchase Interest and the interests of the Buyer in the Receivables, the Related Security, the Lock-Boxes, the Collection Account and Collections.

(h)Payments on Receivables, Accounts.  The Originator will at all times instruct all Obligors to deliver payments on the Receivables to a Lock-Box, the Collection Account or to a Designated Payee.  The Originator will also instruct each Designated Payee to pay all Collections it receives to a Collection Account.  If any such payments or other Collections are received by the Originator, it shall hold such payments in trust for the benefit of the Buyer and promptly (but in any event within two Business Days after receipt) remit such funds at the direction of the Buyer.  The Originator will cause each Collection Bank to comply with the terms of each applicable Deposit Account Control Agreement.  After the occurrence of a Termination Event, the Originator will not, and will not permit any Collection Agent or other Person to, commingle Collections or other funds to which the Buyer is entitled with any other funds.  The Originator shall only add a Collection Bank or Lock-Box to those listed on Exhibit F of the Second Tier Agreement if the Buyer has received notice of such addition, a copy of any new Lock-Box Agreement, as applicable, and an executed and acknowledged copy of a Deposit Account Control Agreement (with such changes as are acceptable to the Buyer) from any new Collection Bank.  The Originator shall only terminate a Collection Bank or Lock-Box upon 30 days advance notice to the Buyer.  If the long term unsecured indebtedness of the Originator is rated less than BBB- by S&P and Baa3 by Moody’s (or either S&P or Moody’s if the other has withdrawn or suspended such rating), the Originator agrees that the Agent may, in its sole discretion, deliver the Agent’s Notice to the Collection Bank.

(i)Sales and Adverse Claims Relating to Receivables.  Except as otherwise provided herein, the Originator will not (by operation of law or otherwise) dispose of or otherwise transfer, or create or suffer to exist any Adverse Claim upon, any Receivable or any proceeds thereof.

(j)Extension or Amendment of Receivables.  Except as otherwise permitted in the Second Tier Agreement and then subject to Section 1.5 of the Second Tier Agreement, the Originator will not extend, amend, rescind or cancel any Receivable.

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(k)Performance of Duties.  Originator will perform its duties or obligations in accordance with the provisions of each of the Transaction Documents to which it is a party.  Originator (at its expense) will (i) fully and timely perform in all material respects all agreements, if any, required to be observed by it in connection with each Receivable, (ii) comply in all material respects with the Credit and Collection Policy, and (iii) refrain from any action that could reasonably be expected to impair the rights of Buyer in the Receivables or Collections.

(l)Agreed Upon Procedures Report.  Originator shall cooperate with the Collection Agent and the designated accountants for each annual agreed upon procedures report required pursuant to Section 5.1(a)(vi) of the Second Tier Agreement.

(m)Changes to Credit and Collection Policy and Character of Business.  The Originator shall not, except as required by law rule or regulation make any material change to the Credit and Collection Policy without the prior written consent of the Buyer and the Agent.

(n)Total Indebtedness to Total Capitalization.  Originator shall at all times cause the ratio of (i) Total Indebtedness to (ii) Total Capitalization (in each case measured as of the  most  recent fiscal quarter end) to be less than or equal to 0.65 to 1.0.

Section 5.2.Organizational Separateness.  Originator agrees not to take any action that would cause Buyer to violate its certificate of incorporation, by-laws or the covenants in Section 5.1(o) of the Second Tier Agreement.  Buyer agrees to conduct its business in a manner consistent with its certificate of incorporation and by-laws.

Section 6.  Termination of Contributions and Purchases.

Section 6.1.Voluntary Termination.  The contribution, purchase and sale of Receivables pursuant to this Agreement may be terminated by either party, upon at least five Business Days' prior written notice to the other party.

Section 6.2.Automatic Termination.  The contribution, purchase and sale of Receivables pursuant to this Agreement shall automatically terminate upon the occurrence of (i) a Bankruptcy Event with respect to Originator, or (ii) the Termination Date.

Section 7.  Indemnification.

Section 7.1.Originator’s Indemnity.  Without limiting any other rights any Person may have hereunder or under applicable law, Originator hereby indemnifies and holds harmless Buyer and its officers, managers, agents and employees (each an “Indemnified Party”) from and against any and all damages, losses, claims, liabilities, penalties, Taxes, costs and expenses (including reasonable attorneys’ fees and court costs actually incurred) (all of the foregoing collectively, the “Indemnified Losses”) at any time imposed on or incurred by any Indemnified Party arising out of or otherwise relating to any Transaction Document, the transactions contemplated thereby, or any action taken or omitted by any of the Indemnified Parties, whether

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arising by reason of the acts to be performed by Originator hereunder or otherwise, excluding only Indemnified Losses (“Excluded Losses”) to the extent (a) a final judgment of a court of competent jurisdiction holds such Indemnified Losses resulted solely from gross negligence or willful misconduct of the Indemnified Party seeking indemnification, (b) solely due to the credit risk of the Obligor or the refusal or financial inability of the Obligor to pay undisputed indebtedness or for which reimbursement would constitute recourse to Originator or the Collection Agent for uncollectible Receivables or (c) such Indemnified Losses include Taxes on, or measured by, the overall net income of the Buyer or its assigns.  Without limiting the foregoing indemnification, Originator shall indemnify each Indemnified Party for Indemnified Losses (other than Excluded Losses) relating to or resulting from:

(i)any representation or warranty made by or on behalf of Originator under or in connection with this Agreement, any Periodic Report or any other information or report delivered by Originator pursuant to the Transaction Documents, which shall have been false or incorrect in any material respect when made or deemed made;

(ii)the failure by Originator to comply with any applicable law, rule or regulation related to any Receivable, or the nonconformity of any Receivable with any such applicable law, rule or regulation;

(iii)the failure of Originator to vest and maintain vested in Buyer, a perfected ownership or security interest in the Receivables and the other property conveyed pursuant hereto, free and clear of any Adverse Claim;

(iv)any commingling of Collections with any other funds;

(v)any failure of a Collection Bank to comply with the terms of the applicable Lock-Box Agreement;

(vi)any dispute, claim, offset or defense (other than Excluded Losses) of the Obligor to the payment of any Receivable, or any other claim resulting from the rendering of services related to such Receivable or the furnishing or failure to furnish any such services or other similar claim or defense not arising from Excluded Losses;

(vii)any failure of Originator to perform its duties or obligations in accordance with the provisions of this Agreement or any other Transaction Document to which Originator is a party;

(viii)any environmental liability claim, products liability claim or personal injury or property damage suit or other similar or related claim or action of whatever sort, arising out of or in connection with any Receivable or any other suit, claim or action of whatever sort relating to any of Originator’s obligations under the Transaction Documents;

(ix)any tax or governmental fee or charge (but not including taxes upon or measured by net income or otherwise contemplated by the Intended Tax

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Characterization), all interest and penalties thereon or with respect thereto, and all out-of-pocket costs and expenses, including the fees and expenses of counsel in defending against the same, which may rise by reason of the purchase or ownership of any Receivable or Related Security or in any goods which secure any Receivable or Related Security;

(x)the failure to comply with provisions of the Transaction Documents requiring notifications to any Obligor of the assignment pursuant to the terms hereof of any Receivable to Buyer (and subsequently, pursuant to the Second Tier Agreement, to Agent for the benefit of Buyer) or to comply with provisions of the Transaction Documents requiring notifications to require that payments (including any under the related insurance policies) be made directly to Buyer pursuant to the terms hereof (and subsequently, pursuant to the Second Tier Agreement, to Agent for benefit of Buyer);

(xi)any Taxes (other than as contemplated by the Intended Tax Characterization) imposed upon any Indemnified Party or upon or with respect to the Receivables, all interest and penalties thereon or with respect thereto, and all out-of-pocket costs and expenses related thereto or arising therefrom, including the reasonable fees and expenses of counsel in defending against the same, which may arise by reason of the purchase or ownership or sale of any Receivables (or of any interest therein) or Related Security or in any goods which secured any such Receivables or Related Security;

(xii)any loss arising, directly or indirectly, as a result of the imposition of sales or analogous taxes imposed on or collected as part of the Receivables or the failure by the Originator to timely collect and remit to the appropriate authority any such taxes; or

(xiii)any action taken by the Originator or any other Affiliate of the Originator related to any Receivable and the Related Security, or arising out of any alleged failure of compliance of any Receivable or the Related Security with the provisions of any law or regulation.

If for any reason the indemnification provided above in this Section is unavailable to an Indemnified Party or is insufficient to hold an Indemnified Party harmless, then Originator shall contribute to the amount paid or payable by such Indemnified Party as a result of such loss, claim, damage or liability in such proportion as is appropriate to reflect not only the relative benefits received by such Indemnified Party on the one hand and Originator on the other hand but also the relative fault of such Indemnified Party as well as any other relevant equitable considerations; provided, however, that notwithstanding any other provision hereof to the contrary, Originator shall not have any obligations concerning Excluded Losses.

Section 7.2.Indemnification Due to Failure to Consummate Purchase.  Originator will indemnify Buyer on demand and hold it harmless  against all costs (including, without limitation, breakage costs) and expenses incurred by Buyer resulting from any failure by Originator to

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consummate a purchase or contribution after Buyer has requested a transfer of the applicable Receivables to the Buyer under the terms of the Second Tier Agreement.

Section 7.3.Other Costs.  If Buyer becomes obligated to compensate the Purchaser under the Second Tier Agreement or any other Transaction Document for any costs or indemnities pursuant to any provision of the Second Tier Agreement or any other Transaction Document, which obligation is caused by Originator’s failure to perform any obligations hereunder, then Originator shall, on demand, reimburse Buyer for the amount of any compensation.

Section 8.  Miscellaneous.

Section 8.1.Amendments, Waivers, etc.  No amendment of this Agreement or waiver of any provision hereof or consent to any departure by either party therefrom shall be effective without the written consent of the party that is sought to be bound.  Any such waiver or consent shall be effective only in the specific instance given.  No failure or delay on the part of either party to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right.  The remedies herein provided are cumulative and not exclusive of any remedies provided by law.  Originator agrees that the Buyer and the Agent may rely upon the terms of this Agreement, and that the terms of this Agreement may not be amended, nor any material waiver of those terms be granted, without the consent of the Agent; provided that Originator and Buyer may agree to an adjustment of the purchase price for any Receivable without the consent of the Agent provided that any such adjustment shall be prospective only and the purchase price paid for any Receivable shall be an amount not less than adequate consideration that represents fair value for such Receivable.  BTMNY, individually and as Agent, Liquidity Provider and Enhancement Provider is hereby authorized by the parties hereto, at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by BTMNY to or for the credit to the account of Originator, against any obligations of the Originator now or hereafter existing under this Agreement that have been assigned to and are payable to or for the benefit of BTMNY as Agent, Liquidity Provider or Enhancement Provider pursuant to Section 1.8(a) of the Second Tier Agreement.

Section 8.2.Assignment of Purchase and Sale Agreement. Originator hereby acknowledges that on the date hereof Buyer has assigned all of its right, title and interest in, to and under this Agreement to the Agent for the benefit of the Buyer pursuant to the Second Tier Agreement and that the Agent and the Buyer are express third party beneficiaries hereof.  Originator hereby further acknowledges that after the occurrence of the Termination Date all provisions of this Agreement shall inure to the benefit of the Agent and the Buyer, including the enforcement of any provision hereof to the extent set forth in the Second Tier Agreement, but that neither the Agent nor the Buyer shall have any obligations or duties under this Agreement.  Originator hereby further acknowledges that the execution and performance of this Agreement are conditions precedent for the Agent and the Buyer to enter into the Second Tier Agreement and that the agreement of the Agent and Buyer to enter into the Second Tier Agreements will

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directly or indirectly benefit Originator and constitutes good and valuable consideration for the rights and remedies of the Agent and the Buyer with respect hereto.

Section 8.3. Binding Effect.  This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns and shall also, to the extent provided herein, inure to the benefit of the parties to the Second Tier Agreement.

Section 8.4.Survival.  The rights and remedies with respect to any breach of any representation and warranty made by Originator or Buyer pursuant to Section 4 and the indemnification provisions of Section 7 shall survive any termination of this Agreement.

Section 8.5.Costs, Expenses and Taxes.  In addition to the obligations of Originator under Section 7, each party hereto agrees to pay within 30 days of demand all costs and expenses incurred by the other party and its assigns (other than Excluded Losses) in connection with the enforcement of, or any actual or claimed breach of, this Agreement, including the reasonable fees and expenses of counsel to any of such Persons incurred in connection with any of the foregoing or in advising such Persons as to their respective rights and remedies under this Agreement in connection with any of the foregoing. Originator also agrees to pay on demand all stamp and other taxes and fees payable or determined to be payable in connection with the execution, delivery, filing, and recording of this Agreement.

Section 8.6.Execution in Counterparts; Integration.  This Agreement may be executed in any number of counterparts and by the different parties in separate counterparts, each of which when so executed shall be deemed to be an original and all of which when taken together shall constitute one and the same Agreement.

Section 8.7.Governing Law; Submission to Jurisdiction.  This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of New York (including Section 5-1401-1 of the General Obligations Law, but without regard to any other conflict of laws provisions thereof).

Section 8.8.No Proceedings.  Originator agrees, for the benefit of the parties to the Second Tier Agreement, that it will not institute against Buyer, or join any other Person in instituting against Buyer, any proceeding of a type referred to in the definition of Bankruptcy Event until one year and one day after no investment, loan or commitment is outstanding under the Second Tier Agreement. In addition, all amounts payable by Buyer to Originator pursuant to this Agreement shall be payable solely from funds available for that purpose (after Buyer has satisfied all obligations then due and owing under the Second Tier Agreement).

Section 8.9. Loans by Buyer to Originator.  Buyer may make loans to Originator from time to time if so agreed between such parties and to the extent that Buyer has funds available for that purpose after satisfying its obligations under this Agreement and the Second Tier Agreement.  Any such loan shall be payable upon demand (and may be prepaid without penalty or premium) and shall bear interest at such rate as Buyer and Originator shall from time to time agree.

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  Section 8.10.Notices.  Unless otherwise specified, all notices and other communications hereunder shall be in writing (including by telecopier or other facsimile communication), given to the appropriate Person at its address or telecopy number set forth in the Second Tier Agreement or at such other address or telecopy number as such Person may specify, and effective when received at the address specified by such Person.

Section 8.11.Entire Agreement.  This Agreement constitutes the entire understanding of the parties thereto concerning the subject matter thereof.  Any previous or contemporaneous agreements, whether written or oral, concerning such matters are superseded thereby.

Section 8.12.Confidentiality.  Each party hereto agrees to comply with the confidentiality provisions of Section 9.10 of the Second Tier Agreement.

Section 8.13.Waiver of Trial by Jury.  To the extent permitted by applicable law, each party hereto irrevocably waives all right of trial by jury in any action, proceeding or counterclaim arising out of, or in connection with, any transaction document or any matter arising thereunder.

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In Witness Whereof, the parties have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written.

KCP&L Greater Missouri Operations Company, as Originator

By /s/ Kevin E. Bryant

  Name: Kevin E. Bryant

  Title: Vice President-Investor Relations and Treasurer

GMO Receivables Company, as Buyer

By /s/ James P. Gilligan

  Name: James P. Gilligan

  Title: President

Exhibit A

Purchase Price

All capitalized terms used, and not otherwise defined, herein have the meanings set forth for such terms in the Receivables Sale Agreement dated as of May 31, 2012 among GMO Receivables Company (“Seller”), as the Seller, KCP&L Greater Missouri Operations Company (“KCPL”), as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as the Agent, and Victory Receivables Corporation or, if not defined therein, in the Purchase and Sale Agreement dated as of May 31,2012 between KCPL Greater Missouri Operations Company, as the Originator (“Originator”), and Seller, as the Buyer (“Buyer”).

The purchase price applicable to the Receivables purchased on any day after the Initial Funding Date by Buyer from Originator shall be equal to 98.75% times the aggregate outstanding balance of such Receivables.  The foregoing purchase price, which is fair market value for such Receivables, was calculated to yield to the Buyer a reasonable profit return on its equity and was calculated assuming, among other things, that charge-offs of Receivables in any year will average approximately one-half of one percent (0.5%) of the average outstanding balance of the Receivables and that LIBOR (which represents the index for the Buyer’s cost of funds) would average approximately 0.5%.  If the Originator or Buyer determines that charge-offs in any twelve-month period have exceeded one percent (1.0%) of the average outstanding balance of Receivables during such period, or if LIBOR subsequently rises above 1.0%, then the Originator and the Buyer agree to negotiate in good faith to re-set the purchase price percentage so as to reflect in an equitable manner the impact of such revised charge-off ratio or revised cost of funds on the Buyer’s anticipated equity return.  Any such change in the purchase price percentage shall not take effect unless and until both parties agree to such adjustment.  In the event that (i) the purchase price is adjusted due to increased charge-offs and average charge-off experience over a twelve-month period subsequently reduces to one-half of one percent, or (ii) the purchase price is adjusted due to an increase in LIBOR and LIBOR subsequently reduces below 1.0% for a three-month consecutive period then the Originator and Buyer may subsequently agree to readjust the purchase price percentage as set forth above to reflect the equitable impact of such changes.  All purchase price adjustments pursuant to the foregoing provisions shall be prospective only and shall not operate to adjust retroactively the purchase price previously paid for any Receivables.

EX-10.3

Exhibit 10.3

==============================================================================

Receivables Sale Agreement

Dated as of May 31, 2012

among

GMO Receivables Company,

as the Seller,

KCP&L Greater Missouri Operations Company,

as the Initial Collection Agent,

The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch,

as the Agent,

and

Victory Receivables Corporation,

as the Purchaser

==============================================================================

Table of Contents

Page

Article I	Purchases from Seller and Settlements	1
Section 1.1.	Sales	1
Section 1.2.	Interim Liquidations.	2
Section 1.3.	Discount Rates and Tranche Periods.	3
Section 1.4.	Fees and Other Costs and Expenses	3
Section 1.5.	Maintenance of Purchase Interest; Deemed Collection	4
Section 1.6.	Reduction in Purchase Limit	5
Section 1.7.	Optional Repurchases.	5
Section 1.8.	Security Interest	5
Article II	Allocations	6
Section 2.1.	Allocations and Distributions	6
Article III	Administration and Collections	7
Section 3.1.	Appointment of Collection Agent	7
Section 3.2.	Duties of Collection Agent	8
Section 3.3.	Reports	9
Section 3.4.	Lock-Box Arrangements	10
Section 3.5.	Enforcement Rights	10
Section 3.6.	Collection Agent Fee	10
Section 3.7.	Responsibilities of the Seller	11
Section 3.8.	[Reserved].	11
Section 3.9.	Indemnities by the Collection Agent.	11
Article IV	Representations and Warranties	12
Section 4.1.	Representations and Warranties	12
Article V	Covenants	15
Section 5.1.	Covenants of the Seller	15
Article VI	Indemnification	21
Section 6.1.	Indemnities by the Seller	21
Section 6.2.	Increased Cost and Reduced Return	23
Section 6.3.	Other Costs and Expenses	24
Section 6.4.	Withholding Taxes	24
Section 6.5.	Payments and Allocations	25
Article VII	Conditions Precedent	25
Section 7.1.	Conditions to Closing	25

Section 7.2.	Conditions to Each Purchase	26
Article VIII	The Agent	27
Section 8.1.	Appointment and Authorization	27
Section 8.2.	Delegation of Duties	27
Section 8.3.	Exculpatory Provisions	27
Section 8.4.	Reliance by Agent	27
Section 8.5.	Assumed Payments	28
Section 8.6.	Notice of Termination Events	28
Section 8.7.	Non-Reliance on Agent	28
Section 8.8.	Agent and Affiliates.	28
Section 8.9.	[Reserved]	29
Section 8.10.	Successor Agent.	29
Article IX	Miscellaneous	29
Section 9.1.	Termination	29
Section 9.2.	Notices	29
Section 9.3.	Payments and Computations	29
Section 9.4.	[Reserved]	30
Section 9.5.	Right of Setoff	30
Section 9.6.	Amendments	30
Section 9.7.	Waivers	30
Section 9.8.	Successors and Assigns; Participations; Assignments	30
Section 9.9.	Intended Tax Characterization	31
Section 9.10.	Confidentiality	31
Section 9.11.	Agreement Not to Petition.	33
Section 9.12.	Excess Funds	33
Section 9.13.	No Recourse	33
Section 9.14.	Deutsche Bank Trust Company Americas, BTMNY and Affiliates	33
Section 9.15.	Headings; Counterparts.	34
Section 9.16.	Cumulative Rights and Severability.	34
Section 9.17.	Governing Law; Submission to Jurisdiction	34
Section 9.18.	Waiver of Trial by Jury	34
Section 9.19.	Entire Agreement.	34
Section 9.20.	Third Party Beneficiaries	34

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Schedules	Description
Schedule I	Definitions
Schedule 5.1(a)(viii)	Agreed-Upon Procedures Report
Exhibits	Description
Exhibit A	Form of Incremental Purchaser Request
Exhibit B	[Reserved]
Exhibit C	Form of Periodic Report
Exhibit D	Addresses and Names of Seller and Originator
Exhibit E	Significant Subsidiaries
Exhibit F	Lock-Boxes and Collection Banks
Exhibit G	List of Designated Payees
Exhibit H	Compliance Certificate
Exhibit I	Credit and Collection Policy

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Receivables Sale Agreement

Receivables Sale Agreement, dated as of May 31, 2012 (the “Agreement”), among GMO Receivables Company, a Delaware corporation, as Seller (the “Seller”), KCP&L Greater Missouri Operations Company, a Delaware corporation, as initial Collection Agent (the “Initial Collection Agent,” and, together with any successor thereto, the “Collection Agent”), The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as agent for the Purchaser (the “Agent”), and Victory Receivables Corporation, as Purchaser (the “Purchaser”).  Capitalized terms used herein, and certain rules of construction, are defined in Schedule I.

The parties hereto agree as follows:

Article I

Purchases from Seller and Settlements

Section 1.1.Sales.  

(a)The Purchase Interest.  Subject to the terms and conditions hereof, the Purchaser shall, from time to time before the Termination Date, purchase from the Seller an undivided percentage ownership interest in the Receivables, the Related Security and all related Collections.  Any such purchase, including an increase in the Investment and any Reinvestment Purchase (a “Purchase”) shall be made by the Purchaser remitting funds to the Seller, through the Agent, pursuant to Section 1.1(c) or by the Collection Agent remitting Collections to the Seller pursuant to Section 1.1(d).  The aggregate percentage ownership interest so acquired by the Purchaser in the Receivables, the Related Security and related Collections (its “Purchase Interest”) shall equal at any time the percentage equivalent of the following:

     I      ------------ ER +   RP

where:

I	=	the outstanding Investment of the Purchaser at such time;
ER	=	the Eligible Receivables Balance at such time; and
RP	=	the Reserve Percentage at such time;

provided, however, that after the Termination Date, the Purchase Interest shall be deemed to be equal to 100% until all Investment, Discount and all amounts payable to the Agent and the Purchaser under the Transaction Documents have been paid in full and the Purchaser has no further obligation to make Purchases from the Seller, and provided, further however that on and after such date as the Investment, Discount and all amounts payable to the Agent and the

Purchaser under the Transaction Documents have been paid in full and the Purchaser has no

further obligation to make Purchases from the Seller, the “Purchase Interest” shall equal zero.  Except during a Liquidation Period the Purchaser’s Purchase Interest will change whenever its Investment, the Reserve Percentage or the Eligible Receivables Balance changes.  During a Liquidation Period the Purchase Interest shall remain constant until all amounts payable to the Agent and the Purchaser under the Transaction Documents have been paid in full.

(b)The Purchaser’s first Purchase and each additional Purchase by the Purchaser not made from Collections pursuant to Section 1.1(d) that increases the outstanding Investment is referred to herein as an “Incremental Purchase.”  Each Purchase made by the Purchaser with the proceeds of Collections which does not increase the outstanding Investment of the Purchaser, is referred to herein as a “Reinvestment Purchase.”

(c)Incremental Purchases.  The Seller may, at any time prior to the Termination Date, request that the Purchaser make an Incremental Purchase.  In order to request an Incremental Purchase from the Purchaser, the Seller must provide to the Agent an irrevocable written request (including by telecopier or other facsimile communication), substantially in the form of Exhibit A, by 11:00 a.m. (New York City time) three Business Days before the requested date (the “Purchase Date”) of such Purchase, specifying the requested Purchase Date (which must be a Business Day) and the requested amount (the “Purchase Amount”) of such Purchase, which must be in a minimum amount of $1,000,000 and multiples thereof (or, if less, an amount equal to the Maximum Incremental Purchase Amount); provided, however, that notwithstanding the foregoing, solely with respect to the first Purchase made hereunder on June 1, 2012, such written request may be delivered to the Agent on the date hereof.  The Agent shall promptly notify the Purchaser of the contents of any such request.  Subject to Section 7.2 and the other terms and conditions hereof, the Purchaser shall transfer to the Agent’s Account the amount of such Incremental Purchase on the requested Purchase Date.  The Agent shall not later than 3:00 p.m. New York City time on the related Purchase Date initiate a wire transfer to the Seller Account the proceeds of any Incremental Purchase to the Agent’s Account in immediately available funds.  

(d)Reinvestment Purchases.  On each day before the Termination Date that any Collections are received by the Collection Agent and no Interim Liquidation is in effect the Purchase Interest in such Collections shall automatically be used to make a Reinvestment Purchase by the Purchaser.  If there are not sufficient Receivables on such date, then the Collection Agent shall institute an Interim Liquidation in order to apply such excess Collections as a reduction of the Investment.

Section 1.2.Interim Liquidations.  

(a)Optional.  The Seller may at any time direct that Reinvestment Purchases cease and that an Interim Liquidation commence by giving the Agent and the Collection Agent at least three Business Days prior written (including telecopy or other facsimile communication) notice specifying the date on which the Interim Liquidation shall commence and, if desired, when such Interim Liquidation shall cease (identified as a specific date prior to the Termination Date or as when the Investment is reduced to a specified amount).  If the Seller does not so specify the date on which an Interim Liquidation shall cease, it may cause such Interim Liquidation to cease at

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any time before the Termination Date, subject to Section 1.2(b) below, by notifying the Agent and the Collection Agent in writing (including by telecopy or other facsimile communication) at least three Business Days before the date on which it desires such Interim Liquidation to cease.

(b)Mandatory.  If at any time before the Termination Date any condition in Section 7.2 to the making of Reinvestment Purchases is not satisfied, the Seller shall immediately notify the Agent and the Collection Agent, whereupon Reinvestment Purchases shall cease and an Interim Liquidation shall commence, which shall cease only upon the Seller confirming to the Agent that the conditions in Section 7.2 are satisfied.  If on the first day of the Seasonal Period and prior to the Termination Date, outstanding Investment exceeds the Purchase Limit, the Seller shall immediately notify the Agent and the Collection Agent whereupon Reinvestment Purchases shall cease and an Interim Liquidation shall commence (a “Seasonal Interim Liquidation”), which Seasonal Interim Liquidation shall cease only upon the Seller confirming to the Agent that outstanding Investment is less than the Purchase Limit.

Section 1.3.Discount Rates and Tranche Periods.  The Agent shall, from time to time for purposes of computing Discount, divide the Investment into Tranches, and the applicable Discount Rate may be different for each Tranche.  All Investment shall be allocated to Tranches by the Agent to reflect the funding sources for the Investment, so that:

(a)there will be one or more Tranches, selected by the Agent, reflecting the portion of the Investment funded by outstanding Liquidity Advances or by funding under the Enhancement Agreement;

(b)there will be a Tranche, selected by the Agent, equal to the excess of Investment over the aggregate amounts allocated at such time pursuant to clause (a) above, which Tranche shall reflect the portion of the Investment funded by Commercial Paper Notes; and

(c)for purposes of allocating the Investment to Tranches, the Agent shall use reasonable efforts to allocate all of the Investment to Tranches funded with Commercial Paper Notes so long as, in the reasonable determination of the Agent, (i) the sale of Commercial Paper Notes is possible and (ii) such allocation will not adversely affect the rating of the Commercial Paper Notes.

Section 1.4.Fees and Other Costs and Expenses.  (a) The Seller shall pay to the Agent for the benefit of the Purchaser, such amounts as agreed to with the Purchaser and the Agent in the Fee Letter.

(b)If any Affected Party incurs any loss or expense (including any loss or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by such Affected Party), at any time, as a result of (i) any settlement (including any full or partial repayment of Investment) with respect to any Tranche funded by Pooled Commercial Paper, being made on any day other than the applicable Settlement Date, (ii) any settlement (including any full or partial repayment of Investment, with respect to any Tranche, however so funded, other than by Pooled Commercial Paper, being made on any day other than the scheduled last

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day of an applicable Tranche Period with respect thereto, or (iii) any Purchase not being made in accordance with a request therefore under Section 1.1, upon written notice from the Agent to the Seller and the Collection Agent, the Seller shall pay to the Collection Agent, and the Collection Agent shall pay to the Agent for the account of the Affected Parties, on the next Settlement Date the amount of such loss or expense.  Such written notice shall, in the absence of manifest error, be conclusive and binding upon the Seller and the Collection Agent.  If an Affected Party incurs any loss or expense (including any loss or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by such Affected Party), at any time, and is not entitled to reimbursement for such loss or expense in the manner set forth above, such Affected Party shall individually bear such loss or expense without recourse to or payment from any other Affected Party.

(c)Investment and Discount shall not be recourse obligations of the Seller and shall be payable solely from Collections and from amounts payable under Sections 1.5, 1.7 and 6.1 (to the extent amounts paid under Section 6.1 indemnify against reductions in or non-payment of Receivables).  The Seller shall pay, as a full recourse obligation, all other amounts payable hereunder.  Notwithstanding anything in this Agreement to the contrary, in no event will the Discount charged and payable hereunder exceed any maximum interest rate imposed by applicable law or regulations.

Section 1.5.Maintenance of Purchase Interest; Deemed Collection.  

(a)General.  If at any time before the Termination Date the Eligible Receivables Balance is less than the sum of the Investmentplus the Aggregate Reserve, the Seller shall pay to the Agent an amount equal to such deficiency for application to reduce the Investment, applied first to the Tranches with the shortest remaining maturities unless otherwise specified by the Seller.

(b)Deemed Collections.  If on any day the outstanding balance of a Receivable is reduced or cancelled as a result of any defective or rejected goods or services, any cash discount or adjustment (including any adjustment resulting from the application of any special refund or other discounts or any reconciliation), any setoff or credit (whether such claim or credit arises out of the same, a related, or an unrelated transaction) or other similar reason not arising from the financial inability of the Obligor to pay undisputed indebtedness, the Seller shall be deemed to have received on such day a Collection on such Receivable in the amount of such reduction or cancellation; provided, however, that such reductions and cancellations shall not include any amounts arising from the refusal of an Obligor to pay undisputed indebtedness, the credit risk of an Obligor or the financial inability of an Obligor to pay undisputed indebtedness, or for which reimbursement would constitute recourse for any such amounts.  If on any day any representation, warranty, covenant or other agreement of the Seller related to a Receivable is not true or is not satisfied, the Seller shall be deemed to have received on such day a Collection in the amount of the outstanding balance of such Receivable; provided, however, that such deemed Collections shall not include any amounts arising from the refusal of an Obligor to pay undisputed indebtedness, the credit risk of an Obligor or the financial inability of an Obligor to pay undisputed indebtedness, or for which reimbursement would constitute recourse for any such

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amounts.  All such Collections deemed received by the Seller under this Section 1.5(b) shall be remitted by the Seller to the Collection Agent.

(c)Adjustment to Purchase Interest.  At any time before the Termination Date that the Seller is deemed to have received any Collection under Section 1.5(b) (“Deemed Collections”) that derives from a Receivable that is otherwise reported as an Eligible Receivable, so long as no Liquidation Period then exists, the Seller may satisfy its obligation to deliver such amount to the Collection Agent by instead notifying the Agent that the Purchase Interest should be recalculated by decreasing the Eligible Receivables Balance by the amount of such Deemed Collections, so long as such adjustment does not cause the Purchase Interest to exceed 100%.

(d)Payment Assumption.  Unless an Obligor otherwise specifies or another application is required by contract or law, any payment received by the Seller from any Obligor shall be applied as a Collection of Receivables of such Obligor (starting with the oldest such Receivable) and remitted to the Collection Agent as such.

Section 1.6.Reduction in Purchase Limit.  The Seller may, upon thirty days notice to the Agent, (i) upon a Settlement Date, terminate the facility provided for in this Agreement, and (ii) reduce the Purchase Limit in increments of $1,000,000, so long as the Purchase Limit as so reduced equals at least the outstanding Investment.

Section 1.7.Optional Repurchases.  On any Settlement Date, the Seller may, upon thirty days notice to the Agent, repurchase the entire Purchase Interest from the Purchaser at a price equal to the outstanding Matured Investment and all other amounts then owed hereunder.

Section 1.8.Security Interest.  (a) The Seller hereby grants to the Agent, for its own benefit and for the ratable benefit of the Secured Parties, a security interest in all Receivables, Related Security, Collections, the Collection Accounts, and Lock-Boxes and all of the Seller’s right, title, and interest in, to and under the Purchase Agreement to secure the payment of all amounts owing hereunder.  The Seller and Collection Agent shall hold in trust for the benefit of the Persons entitled thereto any Collections received by either of them pending their application pursuant to Article II hereof.  Upon the occurrence and during the continuation of a Termination Event, the Seller and Collection Agent shall not, without the prior written consent of the Agent, distribute any Collections to any Person other than the Agent and the Purchaser (and to the Collection Agent, in payment of the Collection Agent Fee to the extent permitted hereto) until all amounts owed under the Transaction Documents to the Agent and the Purchaser shall have been paid in full.

(b)The Seller shall file and record all financing statements, continuation statements and other documents required to perfect or protect such security interest.  All provisions of the Purchase Agreement shall inure to the benefit of, and may be relied upon by, the Agent and the Secured Parties.  After the occurrence of the Termination Date, the Agent shall have the sole right to enforce the Seller’s rights and remedies under the Purchase Agreement to the same extent as the Seller could absent this assignment, but without any obligation on the part of the Secured Parties to perform any of the obligations of the Seller under the Purchase Agreement (or the promissory note executed thereunder).  All amounts distributed to the Seller under the

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Purchase Agreement from Receivables sold to the Seller thereunder shall constitute Collections hereunder and shall be applied in accordance herewith.  The Seller shall direct any indemnification payments it receives from the Originator pursuant to Section 7 of the Purchase Agreement to the applicable party entitled thereto.

(c)This agreement shall be a security agreement for purposes of the UCC.  After the occurrence of the Termination Date, the Agent shall have all rights and remedies provided under the UCC as in effect in all applicable jurisdictions.

Article II

 Allocations

Section 2.1.Allocations and Distributions.

(a)Settlement Dates.  On the Business Day following each Deposit Date occurring prior to the Termination Date (unless an Interim Liquidation is in effect), the Collection Agent shall set aside from Collections the amounts necessary to make all distributions to the Agent, the Purchaser and the Collection Agent required by this Section 2.1(a) with respect to the next succeeding Settlement Date.  The balance of such Collections shall be released to the Seller on a daily basis.  On each Settlement Date prior to the Termination Date (unless an Interim Liquidation is in effect), all Collections so set aside during the preceding Settlement Period shall be applied where applicable by the Collection Agent (or, if the Agent is then in control of any Collections, by the Agent) in the following order:

(i)to the Agent, all fees and other amounts due and payable to the Agent pursuant to the Transaction Documents;

(ii)to the Purchaser, all Discount due and payable on such date; and

(iii)to the Collection Agent, the Collection Agent Fee and other amounts due and payable to the Collection Agent;

(iv)to the Seller, all remaining funds.

On the last day of each Tranche Period, the Collection Agent (or, if the Agent is then in control of any Collections, the Agent) shall pay Discount due and payable to the Purchaser from amounts set aside for such purpose pursuant to this Section 2.1(a).

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(b)Termination Date and Interim Liquidations.  On each day during any Interim Liquidation and on each day on and after the Termination Date (unless the events giving rise to such Termination Date have been waived), the Collection Agent shall set aside and hold in trust solely for the account of the Agent, for the benefit of the Agent and the Purchaser, (or deliver to the Agent, if so instructed pursuant to Section 3.2(a)) all Collections received on such day and such Collections shall be allocated in the following order:

(i)to the Agent, until all fees and other amounts owed to the Agent pursuant to the Transaction Documents have been paid in full;

(ii)to the Purchaser until all Discount owed to the Purchaser pursuant to the Transaction Documents have been paid in full;

(iii)to the Collection Agent, the Collection Agent Fee due and payable to the Collection Agent;

(iv)to the Purchaser until the Investment and all other amounts owed to the Purchaser pursuant to the Transaction Documents have been paid in full;

(v)to the Collection Agent, any amounts other than the Collection Agent Fee due and payable to the Collection Agent;

(vi)to any other Person (other than the Seller, the Collection Agent or an Originator) to whom any amounts are owed under the Transaction Documents until all such amounts have been paid in full; and

(vii)to the Seller, all remaining funds.

Unless an Interim Liquidation has ended by such date, on the last day of each Tranche Period or if a Tranche Period is one day, on such day (unless otherwise instructed by the Agent pursuant to Section 3.2(a)), the Collection Agent shall deposit into the Agent’s Account (for the benefit of the Agent and the Purchaser), from such set aside Collections, all amounts allocated to such Tranche Period and any amounts that remain unpaid from Tranche Periods that ended before such date.  No distributions shall be made to pay amounts under clauses (iv) and (v) until sufficient Collections have been set aside to pay all amounts described in clauses (i) and (ii) that may become payable for all then-outstanding Tranche Periods.  All distributions by the Agent shall be made ratably within each priority level in accordance with the respective amounts then due each Person included in such level unless otherwise agreed by the Agent and the Purchaser.

Article III

Administration and Collections

Section 3.1.Appointment of Collection Agent. (a) The servicing, administering and collecting of the Receivables shall be conducted by a Person (the “Collection Agent”) designated to so act on behalf of the Purchaser and, to the extent of any retained interest of the Seller, the

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Seller, under this Article III.  As the Initial Collection Agent, the Originator is hereby designated as, and agrees to perform the duties and obligations of, the Collection Agent.  The Originator acknowledges that the Agent and the Purchaser have relied on the Originator’s agreement to act as Collection Agent (and the agreement of any of the sub-collection agents to so act) in making the decision to execute and deliver this Agreement and agrees that it will not voluntarily resign as Collection Agent unless it is not permitted by applicable law to continue.  At any time after the occurrence of a Collection Agent Replacement Event, the Agent may designate a new Collection Agent to succeed the Originator (or any successor Collection Agent) (any such designation, a “Collection Agent Termination”).

(b)The Originator may delegate its duties and obligations as Collection Agent to an Affiliate (acting as a sub-collection agent).  Notwithstanding such delegation, the Originator shall remain primarily liable for the performance of the duties and obligations so delegated, and the Agent and the Purchaser shall have the right to look solely to the Originator for such performance.  The Agent may at any time on or after a Collection Agent Termination remove or replace any sub-collection agent.

(c)If replaced, the replaced Collection Agent agrees it will terminate, and will cause each existing sub-collection agent to terminate, its collection activities in a manner reasonably requested by the Agent to facilitate the transition to a new Collection Agent.  The replaced Collection Agent shall cooperate with and assist any new Collection Agent (including providing access to, and transferring, all Records and allowing (to the extent permitted by applicable law and contract) the new Collection Agent to use all licenses, hardware or software necessary or desirable to collect the Receivables).  The Originator irrevocably agrees to reasonably cooperate with any new Collection Agent in the transfer of, and to provide such new Collection Agent with access to, such information, data, systems and other materials that such new Collection Agent requires in order to perform its duties hereunder (including, without limitation, access to all data, information and all systems which the Originator used to monitor, collect and service the Receivables when it was Collection Agent), until the earlier of (i) the date on which when no Investment is held by the Purchaser and all other amounts payable hereunder have been indefeasibly paid in full and (ii) all of the Receivables have been paid in full or been Charged-Off.

Section 3.2.Duties of Collection Agent. (a) The Collection Agent shall take, or cause to be taken, all reasonable action necessary or advisable to collect each Receivable in accordance with this Agreement, the Credit and Collection Policy and all applicable laws, rules and regulations using the skill and attention the Collection Agent exercises in collecting other receivables or obligations owed solely to it.  If so instructed by the Agent, upon the occurrence and during the continuation of a Collection Agent Replacement Event, the Collection Agent shall transfer to the Agent the amount of Collections to which the Agent and the Purchaser are entitled by the thirdBusiness Day following receipt.  Each party hereto hereby appoints the Collection Agent to enforce such Person’s rights and interests in the Receivables and the Collection Agent may commence or settle any legal action to enforce collection of any Receivable; provided, however, that upon the occurrence and during the continuation of a Collection Agent Replacement Event, such action may only be taken after consultation with the Agent.

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(b)If no Termination Event has occurred and is then continuing and the Collection Agent determines that such action is appropriate in order to maximize the Collections, the Collection Agent may, in accordance with the Credit and Collection Policy, adjust the outstanding balance or extend the maturity of, any Receivable (but no such extension shall be for a period more than thirty (30) days unless otherwise required by applicable law, rules or regulations); provided, however, that notwithstanding the foregoing Receivables constituting not more than 3% of the Eligible Receivables Balance (excluding from such calculation Eligible Receivables the maturity of which was extended as required by applicable law, rules or regulations) on any given date may be extended for a period in excess of thirty (30) days or the outstanding balance of such Receivables may be adjusted.  Any such extension or adjustment shall not alter the status of a Receivable as a Defaulted Receivable or Delinquent Receivable or limit any rights of the Agent or the Purchaser hereunder.  If a Collection Agent Replacement Event exists, the Collection Agent may make such extensions or adjustments only with the prior consent of the Agent.

(c)The Collection Agent shall turn over to the Seller (i) any percentage of Collections in excess of the Purchase Interest, less all reasonable costs and expenses of the Collection Agent for servicing, collecting and administering the Receivables and (ii) subject to Section 1.5(d), the collections and records for any indebtedness owed to the Seller that is not a Receivable.  The Collection Agent shall have no obligation to remit any such funds or records to the Seller until the Collection Agent receives evidence (if requested by the Agent and reasonably satisfactory to the Agent) that the Seller is entitled to such items.  The Collection Agent has no obligations concerning indebtedness that is not a Receivable other than to deliver the collections and records for such indebtedness to the Seller when required by this Section 3.2(c).

(d)The Collection Agent shall take all actions necessary to maintain the perfection and priority of the security interest of the Agent in the Receivables, Related Security, Collections, the Collection Accounts, and Lock-Boxes.

Section 3.3.Reports.  (a) On or before the Monthly Report Date of each month, and, after the occurrence and during the continuation of a Collection Agent Replacement Event, at such other times covering such other periods as is requested by the Agent, the Collection Agent shall deliver to the Agent a report reflecting information as of the close of business of the Collection Agent for the immediately preceding calendar month or such other preceding period as is requested (each a “Periodic Report”), containing the information described on Exhibit C (with such modifications or additional information as reasonably requested by the Agent).

(b)Within 180 days after the end of each year, the Collection Agent will deliver to the Agent an officer’s certificate stating that (i) a review of the activities of the Collection Agent and of its performance under this Agreement during the immediately preceding twelve-month period ending on December 31 of the prior year was made under the supervision of the officer signing such certificate and (ii) to the best of such officer’s knowledge, based on such reviews, the Collection Agent has fully performed all of its obligations under this Agreement throughout such period, or if there has been a default in the performance of any such obligation, specifying each such default known to such officer and the nature and status thereof.

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Section 3.4.Lock-Box Arrangements.  The Agent is hereby authorized to give notice at any time upon the occurrence and during the continuation of a Collection Agent Replacement Event to any or all Collection Banks that the Agent is exercising its rights under the Deposit Account Control Agreements and to take all actions permitted under the Deposit Account Control Agreements.  The Seller agrees to take any reasonable action requested by the Agent to facilitate the foregoing.  After the Agent takes any such action under the Deposit Account Control Agreements, the Seller shall immediately deliver to the Agent any Collections received by the Seller.  

Section 3.5.Enforcement Rights.  (a) The Agent may at any time after the occurrence of a Collection Agent Termination direct the Obligors and the Collection Banks to make all payments on the Receivables directly to the Agent or its designee.  The Agent may, and the Seller shall at the Agent’s request, withhold the identity of the Purchaser from the Obligors and Collection Banks.  Upon the Agent’s request after the occurrence of a Collection Agent Termination, the Seller (at the Seller’s expense) shall (i) give notice to each Obligor of the Agent’s ownership of the Purchase Interest and direct that payments on Receivables be made directly to the Agent or its designee, (ii) assemble for the Agent all Records and collateral security for the Receivables and the Related Security and transfer to the Agent (or its designee), or (to the extent permitted by applicable law and contract) license to the Agent (or its designee) the use of, all software necessary to collect the Receivables and (iii) segregate in a manner acceptable to the Agent all Collections the Seller receives and, promptly upon receipt, remit such Collections in the form received, duly endorsed or with duly executed instruments of transfer, to the Agent or its designee.

(b)After the occurrence of a Collection Agent Termination, the Seller hereby irrevocably appoints the Agent as its attorney-in-fact coupled with an interest, with full power of substitution and with full authority in the place of the Seller, to take any and all steps deemed desirable by the Agent, in the name and on behalf of the Seller to (i) collect any amounts due under any Receivable, including endorsing the name of the Seller on checks and other instruments representing Collections and enforcing such Receivables and the Related Security, and (ii) exercise any and all of the Seller’s rights and remedies under the Purchase Agreement.  The Agent’s powers under this Section 3.5(b) shall not subject the Agent to any liability if any action taken by it proves to be inadequate or invalid, nor shall such powers confer any obligation whatsoever upon the Agent.

(c)Neither the Agent nor the Purchaser shall have any obligation to take or consent to any action to realize upon any Receivable or Related Security or to enforce any rights or remedies related thereto.

Section 3.6.Collection Agent Fee.  On or before the Monthly Report Date in each calendar month, the Seller shall pay to the Collection Agent a fee for the immediately preceding calendar month as compensation for its services (the “Collection Agent Fee”) equal to, subject to applicable law, a reasonable amount agreed upon by the Agent and the Collection Agent on an arm’s-length basis reflecting rates and terms prevailing in the market at such time set forth in the Collection Agent Fee Letter.  The Agent may, with the consent of the Purchaser, pay the

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Collection Agent Fee to the Collection Agent from the Purchase Interest in Collections.  The Seller shall be obligated to reimburse any such payment made by the Agent.

Section 3.7.Responsibilities of the Seller.  The Seller shall, or shall cause the Originator to, pay when due all Taxes payable in connection with the Receivables and the Related Security or their creation or satisfaction.  The Seller shall, or shall cause the Originator to, perform all of its obligations under agreements related to the Receivables and the Related Security to the same extent as if interests in the Receivables and the Related Security had not been transferred hereunder.  The Agent’s or the Purchaser’s exercise of any rights hereunder shall not relieve the Seller from such obligations.  Neither the Agent nor the Purchaser shall have any obligation to perform any obligation of the Seller or any other obligation or liability in connection with the Receivables or the Related Security.

Section 3.8.[Reserved].

Section 3.9.Indemnities by the Collection Agent.  Without limiting any other rights any Person may have hereunder or under applicable law, the Collection Agent hereby indemnifies and holds harmless the Agent and the Purchaser and their respective officers, directors, agents and employees (each an “Indemnified Party”) from and against any and all damages, losses, claims, liabilities, penalties, Taxes, costs and expenses (including attorneys’ fees and court costs) (all of the foregoing collectively, the “Indemnified Losses”) at any time imposed on or incurred by any Indemnified Party arising out of or otherwise relating to:

(i)any representation or warranty made by or on behalf of the Collection Agent in this Agreement, any other Transaction Document, any Periodic Report or any other information or report delivered by the Collection Agent pursuant hereto, which shall have been false or incorrect in any material respect when made;

(ii)the failure by the Collection Agent to comply with any applicable law, rule or regulation related to any Receivable or the Related Security in fulfilling its duties as Collection Agent;

(iii)any loss of a perfected security interest (or in the priority of such security interest) as a result of any commingling by the Collection Agent of funds to which the Agent or the Purchaser is entitled hereunder with any other funds;

(iv)any failure of the Collection Agent to perform its duties or obligations in accordance with the provisions of this Agreement (including, without limitation, compliance with the Credit and Collection Policy) or any other Transaction Document to which the Collection Agent is a party; or

(v)the imposition of any Lien with respect to any Receivable or Related Security as a result of an action taken by the Collection Agent under any Transaction Document;

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whether arising by reason of the acts to be performed by the Collection Agent hereunder or otherwise, excluding only Indemnified Losses (“Collection Agent Excluded Losses”) to the extent (a) a final judgment of a court of competent jurisdiction determined that such Indemnified Losses resulted solely from gross negligence or willful misconduct of the Indemnified Party seeking indemnification, (b) solely due to the credit risk or financial inability to pay of the Obligor or for which reimbursement would constitute recourse to the Collection Agent for uncollectible Receivables, or (c) such Indemnified Losses include Taxes on, or measured by, the overall net income of the Agent or the Purchaser computed in accordance with the Intended Tax Characterization or Taxes pursuant to FATCA; provided, however, that nothing contained in this sentence shall limit the liability of the Collection Agent or limit the recourse of the Agent and the Purchaser to the Collection Agent for any amounts otherwise specifically provided to be paid by the Collection Agent hereunder; provided, further, that notwithstanding any other provision hereof to the contrary, the Collection Agent shall not have any obligations concerning Collection Agent Excluded Losses.

Article IV

Representations and Warranties

Section 4.1.Representations and Warranties.  The Seller represents and warrants to the Agent and the Purchaser that:

(a)Corporate Existence and Power.  The Seller is a corporation duly organized, validly existing and in good standing under the laws of its state of incorporation and has all corporate power and authority and all governmental licenses, authorizations, consents and approvals required to carry on its business in each jurisdiction in which its business is now conducted, except where failure to obtain such license, authorization, consent or approval could not reasonably be expected to have a material adverse effect on (i) its ability to perform its obligations under, or the enforceability of, any Transaction Document, (ii) its business or financial condition, (iii) the interests of the Agent or the Purchaser under any Transaction Document or (iv) the enforceability or collectibility of the Receivables (“Material Adverse Effect”).

(b)Corporate Authorization and No Contravention.  The execution, delivery and performance by the Seller of each Transaction Document to which it is a party (i) are within its corporate powers, (ii) have been duly authorized by all necessary corporate action, (iii) do not contravene or constitute a default under (A) any applicable law, rule or regulation binding on Seller in any material respect, (B) its charter or by-laws or (C) any agreement, order or other instrument to which it is a party or its property is subject except to the extent such contravention or default would not have a Material Adverse Effect, and (iv) will not result in any Adverse Claim on any Receivable, the Related Security or Collection or give cause for the acceleration of any indebtedness of the Seller.

(c)No Consent Required. Other than the filing of financing statements and the items set forth in the next sentence, no approval, authorization or other action by, or filings with, any Governmental Authority or other Person is required (other than any

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already given or obtained) in connection with the execution, delivery and performance by it of any Transaction Document to which it is a party or any transaction contemplated thereby.  The Transaction Documents and the transactions contemplated thereby are subject to filing requirements or reporting requirements, or both, under the Securities Exchange Act of 1934, as amended, and Chapters 386 and 393 of the Missouri revised statutes, as amended, and the rules and regulations promulgated thereunder.

(d)Binding Effect. Each Transaction Document to which the Seller is a party constitutes the legal, valid and binding obligation of the Seller enforceable against the Seller in accordance with its terms, except as limited by bankruptcy, insolvency, or other similar laws of general application relating to or affecting the enforcement of creditors’ rights generally and subject to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law.).

(e)Perfection of Ownership Interest.  Immediately preceding the acquisition of the Receivables by the Purchaser, the Seller has acquired all right, title and interest of the Originator in the Receivables, free and clear of any Adverse Claim.  The Seller owns the Receivables free of any Adverse Claim other than the interests of the Purchaser (through the Agent) therein that are created hereby, and the Purchaser shall at all times have a valid and continuing undivided percentage ownership interest, which shall be a first priority perfected security interest for purposes of Article 9 of the applicable Uniform Commercial Code enforceable as such against creditors of and purchasers from the Seller, in the Receivables and Collections to the extent of the Purchase Interest then in effect.  Other than the ownership or security interest granted to the Agent pursuant to this Agreement, the Seller has not pledged, assigned, sold or granted a security interest in, or otherwise conveyed, the Receivables or the Collections.  The Seller has not authorized the filing of and is not aware of any financing statements against the Seller that include a description of collateral covering the Receivables or the Collections other than any financing statement relating to the security interest granted to the Agent hereunder.  The Seller has caused or will have caused, within ten days after the date hereof, the filing of all appropriate financing statements in the proper filing office in the appropriate jurisdictions under the applicable law in order to perfect the conveyance of Receivables by Seller hereunder.

(f)Accuracy of Information.  All written information furnished by the Seller to the Agent or the Purchaser in connection with any Transaction Document, or any transaction contemplated thereby, is true and accurate in all material respects as of the date it was dated (and is, when considered together with all current reports filed by Originator or Parent with the SEC under the Securities Exchange Act of 1934, as amended, not incomplete by omitting to state a material fact necessary to make such information not materially misleading in light of the circumstances when made).

(g)No Actions, Suits.  Except as disclosed by the Parent in its current reports filed with the SEC under the Securities Exchange Act of 1934, as amended, there are no actions, suits or other proceedings (including matters relating to environmental liability) pending or threatened against or affecting the Seller, or any of its respective properties,

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that (i) is reasonably likely to have a material adverse effect on the financial condition of the Seller or on the collectibility of the Receivables or (ii) seeks to challenge the validity of any Transaction Document or any transaction contemplated thereby.  The Seller is not in default of any contractual obligation or in violation of any order, rule or regulation of any Governmental Authority, which default or violation could reasonably be expected to have a material adverse effect upon (i) the financial condition of the Seller or (ii) the collectibility of the Receivables.

(h)No Material Adverse Change. Except as disclosed by the Parent in its current reports filed with the SEC under the Securities Exchange Act of 1934, as amended, there has been no material adverse change since March 31, 2012 in the collectibility of the Receivables or the Seller’s financial condition, business or results of operations which could reasonably be expected to materially affect its ability to perform its obligations under any Transaction Document.

(i)Accuracy of Exhibits; Lock-Box Arrangements. All information on Exhibits D-F (listing offices and names of the Seller and the Originator and where they maintain Records; the Significant Subsidiaries, Lock-Boxes and the Collection Banks) is true and complete, subject to any changes permitted by, and notified to the Agent in accordance with, Article V.  The Seller has delivered a copy of all Lock-Box Agreements and Deposit Account Control Agreements to the Agent.  The Seller has not granted any interest in any Lock-Box, and Collection Account or any bank account in which Collections are or will be deposited to any Person other than the Agent and, upon delivery to a Collection Bank of an Agent’s Notice, the Collection Banks shall apply Collections received in the Lock-Boxes at the direction of the Agent.

(j)Sales by the Originator.  Each transfer by the Originator to the Seller of an interest in Receivables and their Collections has been made in accordance with the terms of the Purchase Agreement, including the payment by the Seller to the Originator of the purchase price described in the Purchase Agreement.  Each such transfer has been made for “reasonably equivalent value” (as such term is used in Section 548 of the Bankruptcy Code) and not for or on account of “antecedent debt” (as such term is used in Section 547 of the Bankruptcy Code) owed by the Originator to the Seller.

(k)Eligible Receivables.  Each Receivable comprising part of the Eligible Receivables Balance as of the date of any calculation of the Purchase Interest as part of the Eligible Receivables Balance was an Eligible Receivable as of the date of such calculation.

(l)Use of Proceeds.  No proceeds of any Purchase will be used (i) for the purpose which violates, or would be inconsistent with, Regulation T, U or X promulgated by the Board of Governors of the Federal Reserve System from time to time or (ii) to acquire any security in any transaction which is subject to Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended.

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Article V

Covenants

Section 5.1.Covenants of the Seller.  The Seller hereby covenants and agrees to comply with the following covenants and agreements, unless the Agent, with the consent of the Purchaser, shall otherwise consent:

(a)Reporting.  The Seller shall, and shall cause each Seller Entity to maintain a system of accounting established and administered in accordance with GAAP and shall furnish to the Agent and the Purchaser:

(i)Annual Financial Statements. Within 90 days after each fiscal year of (A) the Parent, (I) copies of the Parent’s annual audited financial statements (including a consolidated balance sheet, consolidated statement of income and retained earnings and statement of cash flows, with related footnotes) certified by an independent registered public accounting firm which is generally recognized as being among the “big four” and prepared on a consolidated basis in conformity with GAAP, and (II) an unaudited consolidating balance sheet for the Parent and its consolidated Subsidiaries as of the end of such period and related consolidating income statements, certified by a  Designated Financial Officer of the Parent, and (B) each of the Seller and the Originator, an unaudited annual consolidating balance sheet for such Person and its consolidated Subsidiaries as of the end of such period and related consolidating income statements, certified by a Designated Financial Officer thereof;

(ii)Within 45 days after the close of the first three (3) quarterly periods of each of the Parent’s fiscal years, (A) for the Parent and its consolidated Subsidiaries, either (I) consolidated unaudited balance sheets as at the close of each such period and consolidated and consolidating profit and loss and reconciliation of surplus statements and a statement of cash flows for the period from the beginning of such fiscal year to the end of such quarter, all certified by a Designated Financial Officer of the Parent or (II) if the Parent is then a “registrant” within the meaning of Rule 1-01 of Regulation S-X of the SEC and required to report on Form 10-Q with the SEC, a copy of the Parent’s report on Form 10-Q for such quarterly period and (B) either (I) consolidating unaudited balance sheets and related consolidating income statements for the Parent and its consolidated Subsidiaries as at the close of each such period, all certified by a Designated Financial Officer of the Parent or (II) if the Parent is then a “registrant” within the meaning of Rule 1-01 of Regulation S-X of the SEC and required to report on Form 10-Q with the SEC, a copy of the Parent’s report on Form 10-Q for such quarterly period;

(iii)[Reserved];

(iv)[Reserved];

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(v)Officer’s Certificate. Each time financial statements are furnished pursuant to clause (i) and (ii) of this Section 5.1(a), a compliance certificate (in substantially the form of Exhibit H) signed by a Designated Financial Officer, dated the date of such financial statements;

(vi)Public Reports.  Promptly upon becoming publicly available, a copy of each report or proxy statement filed by the Parent with the SEC or any securities exchange;

(vii)ERISA.  Promptly after the filing or receiving thereof, copies of (i) all reports and notices with respect to any “Reportable Event” defined in Article IV of ERISA which Seller files under ERISA with the Internal Revenue Service, the Pension Benefit Guaranty Corporation or the U.S. Department of Labor or which Seller receives from the Pension Benefit Guaranty Corporation and (ii) all reports and documents which it files under any other applicable pension benefits legislation;

(viii)Receivables Agreed Upon Procedures Report.  As soon as available and in any event by October 31st of each year, (i) a copy of an agreed upon procedures report, prepared by Deloitte & Touche LLP (or another firm of nationally-recognized independent registered public accounting firm that is generally recognized as being among the “big four”), as at the end of the fiscal year of Seller, stating the aggregate unpaid balance of the Receivables, the Eligible Receivables Balance, the unpaid balance of the Delinquent Receivables and Defaulted Receivables and confirming that, based upon its performance of the agreed upon procedures, such accountants found nothing that would indicate that the Periodic Report provided for the Settlement Period ended on or next preceding the last day of such fiscal year of the Seller is not inaccurate or incomplete; and (ii) a copy of an agreed upon procedures report, prepared by the same nationally-recognized independent certified public accountants, or a management report relating to the ability of Originator (if Collection Agent) to perform or observe any term, covenant or condition relating to it hereunder as Collection Agent.  The scope of the above agreed upon procedures shall be as described in Schedule 5.1(a)(viii);

(ix)Agreed Upon Procedures.  In addition, the Seller shall cooperate with the Collection Agent and the designated accountants for each annual agreed upon procedures report required pursuant to Section 5.1(a)(viii); and

(x)Other Information.  With reasonable promptness, such other information (including non-financial information) as may be reasonably requested by the Agent or the Purchaser (with a copy of such request to the Agent).

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The statements and reports required to be furnished by the Parent or the Originator pursuant to clauses (i), (ii) and (vi) above shall be deemed furnished for such purpose upon becoming publicly available on the SEC’s EDGAR web page.

(b)Notices.  Promptly and in any event within five Business Days after a Designated Financial Officer of the Seller obtains knowledge of any of the following the Seller will notify the Agent and provide a description of:

(i)Potential Termination Events.  The occurrence of any Potential Termination Event;

(ii)Representations and Warranties.  The failure of any representation or warranty herein to be true when made in any material respect;

(iii)Downgrading.  The downgrading, withdrawal or suspension of the senior unsecured long term debt rating of any Seller Entity by any Rating Agency; or

(iv)Litigation.  The institution of any litigation, arbitration proceeding or governmental proceeding reasonably likely to be material to the collectibility or quality of the Receivables which is not referenced in the Parent’s filings with the SEC.

If the Agent receives such a notice, the Agent shall promptly give notice thereof to the Purchaser.

(c)Conduct of Business.  The Seller will perform all actions necessary to remain duly incorporated, validly existing and in good standing in its jurisdiction of incorporation and to maintain all requisite authority to conduct its business in each jurisdiction in which it conducts business.

(d)Compliance with Laws.  The Seller will comply with all laws, regulations, judgments and other directions or orders imposed by any Governmental Authority to which the Seller or any Receivable, any Related Security or Collection may be subject except to the extent that failure to so comply could not reasonably be expected to have a Material Adverse Effect.

(e)Furnishing Information and Inspection of Records.  The Seller will furnish to the Agent and the Purchaser such information concerning the Receivables and the Related Security as the Agent or the Purchaser may reasonably request.  With reasonable notice, the Seller will permit, at any time during regular business hours, the Agent or the Purchaser (or any representatives thereof) (i) to examine and make copies of all Records, (ii) to visit the offices and properties of the Seller for the purpose of examining the Records and (iii) to discuss matters relating hereto with any of the Seller officers, directors, employees or independent public accountants having knowledge of such matters; provided, that so long as no Termination Event has occurred and is continuing,

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the Seller shall not be responsible for the costs of more than one such on-site audit per year.  

(f)Keeping Records.  (i) The Seller will have and maintain (A) administrative and operating procedures and resources (including an ability to recreate Records if originals are destroyed), and (B) all Records and other information necessary or advisable for collecting the Receivables (including Records adequate to permit the immediate identification of each new Receivable and all Collections of, and adjustments to, each existing Receivable).  The Seller will give the Agent prior notice of any material change in such administrative and operating procedures.

(ii)The Seller will at all times from and after the date hereof, clearly and conspicuously mark its computer and master data processing books and records with a legend describing the Agent’s and the Purchaser’s interest in the Receivables and the Collections.

(g)Perfection.  (i) The Seller will at its expense, promptly execute and deliver all instruments and documents and take all action necessary or requested by the Agent (including the filing of financing or continuation statements, amendments thereto or assignments thereof) to vest and maintain vested in the Agent a valid, first priority perfected security interest in the Receivables, the Collections, the Related Security, the Purchase Agreement, the Collection Account and the Lock-Boxes and proceeds thereof free and clear of any Adverse Claim (and a perfected ownership interest in the Receivables and Collections to the extent of the Purchase Interest).  To the extent permitted by applicable law, the Agent will be permitted to sign and file any continuation statements, amendments thereto and assignments thereof without the Seller’s signature.

(ii)The Seller will not change its name, identity or corporate structure or relocate its jurisdiction of organization or chief executive office or the Records except after fifteen (15) days advance notice to the Agent and the delivery to the Agent of all financing statements, instruments and other documents (including direction letters) requested by the Agent.

(iii)The Seller will at all times maintain its chief executive offices and maintain its jurisdiction of organization within a jurisdiction in the USA in which Article 9 of the UCC is in effect.  If the Seller or Originator moves its chief executive office to a location that imposes Taxes, fees or other charges to perfect the Agent’s and the Purchaser’s interests hereunder or the Seller’s interests under the Purchase Agreement, the Seller will pay all such amounts and any other costs and expenses incurred in order to maintain the enforceability of the Transaction Documents, the Purchase Interest and the interests of the Agent and the Purchaser in the Receivables, the Related Security, Collections, Purchase Agreement, the Collection Account and the Lock-Boxes.

(h)Performance of Duties.  The Seller will perform, and will cause the Collection Agent (if an Affiliate) to perform, its respective duties or obligations in

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 accordance with the provisions of each of the Transaction Documents.  The Seller (at its expense) will (i) fully and timely perform in all material respects all agreements required to be observed by it in connection with each Receivable, (ii) comply in all material respects with the Credit and Collection Policy, and (iii) refrain from any action that could reasonably be expected to impair the rights of the Agent or the Purchaser in the Receivables, the Related Security, Collections, Purchase Agreement, the Collection Account and the Lock-Boxes.

(i)Payments on Receivables, Accounts.  The Seller will at all times instruct all Obligors to deliver payments on the Receivables to a Lock-Box, the Collection Account or to a Designated Payee.  The Seller will also instruct each Designated Payee to pay all Collections it receives to a Collection Account.  If any such payments or other Collections are received by the Seller, it shall hold such payments in trust for the benefit of the Agent and the Purchaser and promptly (but in any event within two Business Days after receipt) remit such funds at the direction of the Agent.  The Seller will use commercially reasonable efforts to cause each Collection Bank to comply with the terms of each applicable Deposit Account Control Agreement.  Upon the occurrence and during the continuation of a Termination Event, the Seller will not, and will not permit any Collection Agent or other Person to, commingle Collections or other funds to which the Agent or the Purchaser is entitled with any other funds.  The Seller shall only add a Collection Bank or Lock-Box to those listed on Exhibit F if the Agent has received notice of such addition, a copy of any new Lock-Box Agreement, as applicable, and an executed and acknowledged copy of a Deposit Account Control Agreement (with such changes as are acceptable to the Agent) from any new Collection Bank.  The Seller shall only terminate a Collection Bank or Lock-Box upon 30 days advance notice to the Agent.  If the long term unsecured indebtedness of the Originator is less than BBB- by S&P and Baa3 by Moody’s (or either S&P or Moody’s if the other has withdrawn or suspended such rating), the Seller agrees that the Agent may, in its sole discretion, deliver the Agent’s Notice to the Collection Bank.

(j)Sales and Adverse Claims Relating to Receivables.  Except as otherwise provided herein, the Seller will not (by operation of law or otherwise) dispose of or otherwise transfer, or create or suffer to exist any Adverse Claim upon, any Receivable or any proceeds thereof.

(k)Extension or Amendment of Receivables.  Except as otherwise permitted in Section 3.2(b) and then subject to Section 1.5, the Seller will not extend, amend, rescind or cancel any Receivable.

(l)Change in Business or Credit and Collection Policy.  The Seller will not make any material change in the character of its business and will not, and except as required by applicable laws, rules or regulations will not permit the Originator to, make any material change to the Credit and Collection Policy.

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(m)Certain Agreements.  The Seller will not (and will not permit any Originator to) amend, modify, waive, revoke or terminate any Transaction Document to which it is a party or any provision of Seller’s certificate of incorporation or by-laws.

(n)Other Business.  The Seller will not:  (i) engage in any business other than the transactions contemplated by the Transaction Documents, (ii) create, incur or permit to exist any indebtedness of any kind (or cause or permit to be issued for its account any letters of credit or bankers’ acceptances) other than pursuant to this Agreement, or (iii) form any Subsidiary or make any investments in any other Person; provided, however, that the Seller shall be permitted to incur ordinary course obligations to the extent necessary for the day-to-day operations of the Seller (such as expenses for stationery, audits, maintenance of legal status, etc.).

(o)Nonconsolidation.  The Seller will operate in such a manner that the separate corporate existence of (A)  the Seller and (B) the Seller Entities and each Affiliate thereof would not be disregarded in the event of the bankruptcy or insolvency of any Seller Entity or any Affiliate thereof and, without limiting the generality of the foregoing:

(i)the Seller will not engage in any activity other than those activities expressly permitted under the Seller’s organizational documents and the Transaction Documents, nor will the Seller enter into any agreement other than this Agreement, the other Transaction Documents to which it is a party and, with the prior written consent of the Agent, any other agreement necessary to carryout more effectively the provisions and purposes hereof or thereof;

(ii)the Seller will maintain a business office separate from that of each of the Seller Entities and the Affiliates thereof;

(iii)the Seller will cause the financial statements and books and records of the Seller and each Seller Entity and any Affiliate thereof to reflect the separate corporate existence of the Seller;

(iv)except as otherwise expressly permitted hereunder, under the other Transaction Documents and under the Seller’s organizational documents, the Seller will not permit any Seller Entity or Affiliate thereof to (A) pay the Seller’s expenses, (B) guarantee the Seller’s obligations, or (C) advance funds to the Seller for the payment of expenses or otherwise other than as a capital contribution; and

(v)the Seller will not act as agent for any Seller Entity or Affiliate thereof, but instead will present itself to the public as a corporation separate from each such Person and independently engaged in the business of purchasing and financing Receivables.

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(p)Mergers, Consolidations and Acquisitions.  The Seller will not merge into or consolidate with any other Person, or permit any other Person to merge into or consolidate with it, or purchase, lease or otherwise acquire (in one transaction or a series of transactions) all or substantially all of the assets of any other Person (whether directly by purchase, lease or other acquisition of all or substantially all of the assets of such Person or indirectly by purchase or other acquisition of all or substantially all of the capital stock of such other Person) other than the acquisition of the Receivables and Related Security pursuant to the Purchase Agreement.

Article VI

Indemnification

Section 6.1.Indemnities by the Seller.  Without limiting any other rights any Person may have hereunder or under applicable law, the Seller hereby indemnifies and holds harmless the Agent and the Purchaser and their respective officers, directors, agents and employees (each an “Indemnified Party”) from and against any and all damages, losses, claims, liabilities, penalties, Taxes, costs and expenses (including reasonable attorneys’ fees and court costs) (all of the foregoing collectively, the “Indemnified Losses”) at any time imposed on or incurred by any Indemnified Party arising out of or otherwise relating to any Transaction Document, the transactions contemplated thereby or any action taken or omitted by any of the Indemnified Parties (including any action taken by the Agent as attorney-in-fact for the Seller pursuant to Section 3.5(b)), whether arising by reason of the acts to be performed by the Seller hereunder or otherwise, excluding only Indemnified Losses (“Excluded Losses”) to the extent (a) a final judgment of a court of competent jurisdiction holds such Indemnified Losses resulted solely from bad faith, gross negligence or willful misconduct of the Indemnified Party seeking indemnification, (b) solely due to the credit risk or financial inability to pay of the Obligor or for which reimbursement would constitute recourse to the Seller or the Collection Agent for uncollectible Receivables or (c) such Indemnified Losses include Taxes on, or measured by, the overall net income of the Agent or the Purchaser computed in accordance with the Intended Tax Characterization or Taxes pursuant to FATCA.  Without limiting the foregoing indemnification, but subject to the limitations of the Excluded Losses, the Seller shall indemnify each Indemnified Party for Indemnified Losses arising out of  or resulting from:

(i)any representation or warranty made by the Seller or the Collection Agent (to the extent the Collection Agent is an Affiliate of the Seller) (or any employee or agent of the Seller or the Collection Agent (to the extent the Collection Agent is an Affiliate of the Seller)) under or in connection with this Agreement, any Periodic Report or any other information or report delivered by the Seller or the Collection Agent pursuant hereto, which shall have been false or incorrect in any material respect when made or deemed made;

(ii)the failure by the Seller or the Collection Agent (to the extent the Collection Agent is an Affiliate of the Seller) to comply with any applicable law, rule or regulation related to any Receivable, or the nonconformity of any Receivable with any such applicable law, rule or regulation;

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(iii)the failure of the Seller to vest and maintain vested in the Agent, for the benefit of the Purchaser, a perfected ownership or security interest in the Purchase Interest and the property conveyed pursuant to Section 1.1 and Section 1.8, free and clear of any Adverse Claim;

(iv)any commingling of Collections with any other funds;

(v)any failure of a Collection Bank to comply with the terms of the applicable Deposit Account Control Agreement;

(vi)any dispute, claim, offset or defense (other than Excluded Losses) of the Obligor to the payment of any Receivable, or any other claim resulting from the rendering of services related to such Receivable or the furnishing or failure to furnish any such services or other similar claim or defense not arising from Excluded Losses;

(vii)any failure of the Seller to perform its duties or obligations in accordance with the provisions of this Agreement or any other Transaction Document to which such Person is a party;

(viii)any environmental liability claim, products liability claim or personal injury or property damage suit or other similar or related claim or action of whatever sort, arising out of or in connection with any Receivable or any other suit, claim or action of whatever sort relating to any of the Transaction Documents;

(ix)any tax or governmental fee or charge (but not including taxes upon or measured by net income, pursuant to FATCA or otherwise contemplated by the Intended Tax Characterization), all interest and penalties thereon or with respect thereto, and all out-of-pocket costs and expenses, including the fees and expenses of counsel in defending against the same, which may rise by reason of the purchase or ownership of any Receivable or Related Security or in any goods which secure any Receivable or Related Security;

(x)the failure to comply with the provisions of the Transaction Documents regarding notifications to any Obligor of the assignment pursuant to the terms hereof of any Receivable to the Agent for the benefit of the Purchaser or that payments (including any under the related insurance policies) be made directly to the Agent for the benefit of the Purchaser;

(xi)any Taxes (other than as contemplated by the Intended Tax Characterization imposed upon any Indemnified Party or upon or with respect to the Receivables or pursuant to FATCA), all interest and penalties thereon or with respect thereto, and all out-of-pocket costs and expenses related thereto or arising therefrom, including the reasonable fees and expenses or counsel in defending against the same, which may arise by reason of the purchase or ownership or sale of any Receivables (or of any interest therein) or Related Security or in any goods which secured any such Receivables or Related Security;

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(xii)any loss arising, directly or indirectly, as a result of the imposition of sales or analogous taxes imposed on or collected as part of the Receivables or the failure by the Seller, the Originator or the Collection Agent to timely collect and remit to the appropriate authority any such taxes; or

(xiii)any action taken by the Seller, the Originator or any other Affiliate of the Seller or of the Originator (whether acting as Collection Agent or otherwise) related to any Receivable and the Related Security, or arising out of any alleged failure of compliance of any Receivable or the Related Security with the provisions of any law or regulation.

If for any reason the compensation provided above in this Section 6.1 is unavailable to a Person or is insufficient to hold a Person harmless, then the Seller shall contribute to the amount paid or payable by such Person as a result of such loss, claim, damage or liability in such proportion as is appropriate to reflect not only the relative benefits received by such Person on the one hand and the Seller on the other hand but also the relative fault of such Person as well as any other relevant equitable considerations; provided, however, that notwithstanding any other provision hereof to the contrary, the Seller shall not have any obligations concerning Excluded Losses.

Section 6.2.Increased Cost and Reduced Return.  If the adoption after the date hereof of any applicable law, rule of regulation or accounting principle, or any change therein after the date hereof, or any change in the interpretation or administration thereof by any Governmental Authority or Accounting Authority charged with the interpretation or administration thereof, or compliance by any Purchaser Funding Source, the Agent or the Purchaser (collectively, the “Funding Parties”) with any request or directive (whether or not having the force of law) made after the date hereof by any such Governmental Authority or Accounting Authority (a “Regulatory Change”) (a) subjects any Funding Party to any charge or withholding on or in connection with a Funding Agreement or this Agreement (collectively, the “Funding Documents”) or any Receivable (other than Taxes pursuant to FATCA), (b) changes the basis of taxation of payments to any of the Funding Parties of any amounts payable under any of the Funding Documents (except for changes in the rate of Tax on the overall net income of such Funding Party or other tax rates contemplated by the Intended Tax Characterization), (c) imposes, modifies or deems applicable any reserve, assessment, insurance charge, special deposit or similar requirement against assets of, deposits with or for the account of, or any credit extended by, any of the Funding Parties, (d) has the effect of reducing the rate of return on such Funding Party’s capital to a level below that which such Funding Party could have achieved but for such adoption, change or compliance (taking into consideration such Funding Party’s policies concerning capital adequacy) or (e) imposes any other condition, and the result of any of the foregoing is (x) to impose a cost on, or increase the cost to, any Funding Party of its commitment under any Funding Document or of purchasing, maintaining or funding any interest acquired under any Funding Document, (y) to reduce the amount of any sum received or receivable by, or to reduce the rate of return of, any Funding Party under any Funding Document or (z) to require any payment calculated by reference to the amount of interests held or amounts received by it hereunder, then, on the next Settlement Date which is at least ten (10) Business Days following demand by the Agent, the Seller shall pay to the Agent for the account of the Person such

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additional amounts as will compensate the Agent or the Purchaser (or will enable the Purchaser to compensate the Purchaser Funding Source) for such increased cost or reduction.  Notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, regulations, guidelines or directives thereunder or issued in connection therewith shall be deemed to be a “Regulatory Change”, regardless of the date enacted, adopted or issued and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Regulatory Change”, regardless of the date enacted, adopted or issued.

Section 6.3.Other Costs and Expenses.  The Seller shall pay to the Agent within 30 days of demand all reasonable costs and expenses in connection with (a) the preparation, execution, delivery (including amendments of any provision) of the Transaction Documents, (b) the sale of the Purchase Interest, (c) the perfection of the Agent’s rights in the Receivables and Collections, (d) the enforcement by the Agent or the Purchaser of the obligations of the Seller under the Transaction Documents or of any Obligor under a Receivable and (e) the maintenance by the Agent of the Lock-Boxes including reasonable fees, costs and expenses of legal counsel for the Agent and the Purchaser relating to any of the foregoing or to advising the Agent, the Purchaser and any Purchaser Funding Source about its rights and remedies under any Transaction Document or any related Funding Agreement and all costs and expenses (including counsel fees and expenses) of the Agent, the Purchaser and the Purchaser Funding Source in connection with the enforcement of the Transaction Documents or any Funding Agreement and in connection with the administration of the Transaction Documents following the occurrence and during the continuation of a Termination Event.  Subject to Section 5.1(e), the Seller shall reimburse the Agent and the Purchaser for the cost of the Agent’s or the Purchaser’s auditors (which may be employees of such Person) auditing the books, records and procedures of the Seller.  The Seller shall reimburse the Purchaser for any amounts the Purchaser must pay to the Purchaser Funding Source pursuant to any Funding Agreement on account of any Tax (other than taxes upon or measured by net income, pursuant to FATCA or otherwise contemplated by the Intended Tax Characterization).  The Seller shall reimburse the Purchaser within 30 days of demand for all other reasonable costs and expenses (excluding the costs of auditing the Purchaser’s books and the cost of the Ratings) incurred by the Purchaser in connection with the Transaction Documents or the transactions contemplated thereby.

Section 6.4.Withholding Taxes.  All payments made by the Seller to any Affected Party shall be made without withholding for or on account of any present or future taxes (other than overall net income taxes on the recipient or pursuant to FATCA).  If any such withholding is so required, the Seller shall make the withholding, pay the amount withheld to the appropriate authority before penalties attach thereto or interest accrues thereon and pay such additional amount as may be necessary to ensure that the net amount actually received free and clear of such taxes (including such taxes on such additional amount) is equal to the amount that would have been received had such withholding not been made.  If any Affected Party pays any such taxes, penalties or interest the Seller shall reimburse such Affected Party for that payment on demand.  If the Seller pays any such taxes, penalties or interest, it shall deliver official tax receipts evidencing that payment or certified copies thereof to the Affected Party on whose

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account such withholding was made (with a copy to the Agent if not the recipient of the original) on or before the thirtieth day after payment.  Before the first date on which any amount is payable hereunder for the account of the Agent, the Agent shall deliver to the Seller two (2) duly completed copies of United States Internal Revenue Service Form W8-IMY (or any successor applicable form) and all required attachments certifying that such Agent is entitled to receive payments hereunder without deduction or withholding of any United States federal income taxes or any information required to demonstrate that Agent is entitled to receive payments hereunder without deduction or withholding of any Taxes pursuant to FATCA.  The Agent shall replace or update such forms when necessary to maintain any applicable exemption and as requested by the Seller.

Section 6.5.Payments and Allocations.  If any Person seeks compensation pursuant to this Article VI, such Person shall deliver to the Seller and the Agent a certificate setting forth the amount due to such Person, a description of the circumstance giving rise thereto and the basis of the calculations of such amount, which certificate shall be conclusive absent manifest error.  The Seller shall pay to the Agent (for the account of such Person) the amount shown as due on any such certificate within 30 days after receipt of the notice.  

Article VII

Conditions Precedent

Section 7.1.Conditions to Closing.  This Agreement shall become effective on the first date all conditions in this Section 7.1 are satisfied.  On or before such date, the Seller shall deliver to the Agent the following documents in form, substance and quantity acceptable to the Agent:

(a)A certificate of the Secretary of each of the Seller and the Originator certifying (i) the resolutions of the Seller’s and the Originator’s board of directors approving each Transaction Document to which it is a party, (ii) the name, signature, and authority of each officer who executes on the Seller’s or the Originator’s behalf a Transaction Document (on which certificate the Agent and the Purchaser may conclusively rely until a revised certificate is received), (iii) the Seller’s and the Originator’s certificate or articles of incorporation certified by the Secretary of State of its state of incorporation, (iv) a copy of the Seller’s and the Originator’s by-laws and (v) good standing certificates issued by the Secretaries of State of each jurisdiction where the Seller or the Originator has material operations.

(b)All instruments and other documents required by the Agent, to perfect the Agent’s first priority interest in the Receivables, Collections and the Purchase Agreement in all appropriate jurisdictions.

(c)Lien search reports, including state and county UCC, state and federal tax, ERISA liens and judgments from, with respect to the Originator, the Secretary of State of the State of Delaware and Kent County, Delaware, the Secretary of State of the State of

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Missouri and Jackson County, Missouri and, with respect to the Seller, the Secretary of the State of Delaware and Kent County, Delaware.

(d)Executed copies of (i) all consents and authorizations necessary in connection with the Transaction Documents (ii) all Deposit Account Control Agreements, (iii) a compliance certificate in the form of Exhibit H covering the period ending April 30, 2012 (excepting financial statements, which shall be for the period ended March 31, 2012), (iv) a Periodic Report covering the month ended April 30, 2012 and (v) each agreement specifically identified in the definition of Transaction Document.

(e)Favorable opinions of counsel to the Seller and the Originator covering corporate, enforceability, true-sale concerning the transfer of Receivables from Originator to Seller, non-consolidation and UCC matters.

(f)Such other approvals, opinions or documents as the Agent or the Purchaser may reasonably request.

(g)All legal matters related to the Purchase are satisfactory to the Purchaser.

Section 7.2.Conditions to Each Purchase.  The obligation of the Purchaser to make any Purchase, and the right of the Seller to request or accept any Purchase, are subject to the conditions (and each Purchase shall evidence the Seller’s representation and warranty that clauses (a)-(e) of this Section 7.2 have been satisfied) that on the date of such Purchase before and after giving effect to the Purchase:

(a)no Potential Termination Event (or in the case of a Reinvestment Purchase, a Termination Event) shall then exist or shall occur as a result of the Purchase;

(b)the Termination Date has not occurred;

(c)after giving effect to the application of the proceeds of such Purchase, the outstanding Investment would not exceed the Purchase Limit;

(d)the representations and warranties of the Seller, the Originator and the Collection Agent contained herein or in any Transaction Document are true and correct in all material respects on and as of such date (except to the extent such representations and warranties relate solely to an earlier date and then are true and correct as of such earlier date); and

(e)each of the Seller and the Originator is in material compliance with the Transaction Documents (including all covenants and agreements in Article V).

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Article VIII

The Agent

Section 8.1.Appointment and Authorization.  The Purchaser hereby irrevocably designates and appoints The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch as the “Agent” under the Transaction Documents and authorizes the Agent to take such actions and to exercise such powers as are delegated to the Agent thereby and to exercise such other powers as are reasonably incidental thereto.  The Agent shall hold, in its name, for the benefit of the Purchaser, the Purchase Interest.  The Agent shall not have any duties other than those expressly set forth in the Transaction Documents or any fiduciary relationship with the Purchaser, and no implied obligations or liabilities shall be read into any Transaction Document, or otherwise exist, against the Agent.  The Agent does not assume, nor shall it be deemed to have assumed, any obligation to, or relationship of trust or agency with, the Seller.  Notwithstanding any provision of this Agreement or any other Transaction Document, in no event shall the Agent ever be required to take any action which exposes the Agent to personal liability or which is contrary to the provision of any Transaction Document or applicable law.

Section 8.2.Delegation of Duties.  The Agent may execute any of its duties through agents or attorneys-in-fact and shall be entitled to advice of counsel concerning all matters pertaining to such duties.  The Agent shall not be responsible for the negligence or misconduct of any agents or attorneys-in-fact selected by it with reasonable care.

Section 8.3.Exculpatory Provisions.  Neither the Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted (i) with the consent or at the direction of the Purchaser or (ii) in the absence of such Person’s gross negligence or willful misconduct.  The Agent shall not be responsible to the Purchaser or other Person for (i) any recitals, representations, warranties or other statements made by the Seller or the Originator or any of their Affiliates, (ii) the value, validity, effectiveness, genuineness, enforceability or sufficiency of any Transaction Document, (iii) any failure of the Seller or the Originator or any of their Affiliates to perform any obligation or (iv) the satisfaction of any condition specified in Article VII.  The Agent shall not have any obligation to the Purchaser to ascertain or inquire about the observance or performance of any agreement contained in any Transaction Document or to inspect the properties, books or records of the Seller or the Originator or any of their Affiliates.

Section 8.4.Reliance by Agent.  The Agent shall in all cases be entitled to rely, and shall be fully protected in relying, upon any document, other writing or conversation believed by it to be genuine and correct and to have been signed, sent or made by the proper Person and upon advice and statements of legal counsel (including counsel to the Seller), independent accountants and other experts selected by the Agent.  The Agent shall in all cases be fully justified in failing or refusing to take any action under any Transaction Document unless it shall first receive such advice or concurrence of the Purchaser, and assurance of its indemnification, as it deems appropriate.

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Section 8.5.Assumed Payments.  Unless the Agent shall have received notice from the Purchaser before the date of any Incremental Purchase that the Purchaser will not make available to the Agent the amount it is scheduled to remit as part of such Incremental Purchase, the Agent may assume the Purchaser has made such amount available to the Agent when due (an “Assumed Payment”) and, in reliance upon such assumption, the Agent may (but shall have no obligation to) make available such amount to the appropriate Person.  If and to the extent that the Purchaser shall not have made its Assumed Payment available to the Agent, the Purchaser hereby agrees to pay the Agent forthwith on demand such unpaid portion of such Assumed Payment up to the amount of funds actually paid by the Agent, together with interest thereon for each day from the date of such payment by the Agent until the date the requisite amount is repaid to the Agent, at a rate per annum equal to the Federal Funds Rate.

Section 8.6.Notice of Termination Events.  The Agent shall not be deemed to have knowledge or notice of the occurrence of any Potential Termination Event unless the Agent has received notice from the Purchaser or the Seller stating that a Potential Termination Event has occurred hereunder and describing such Potential Termination Event.  The Agent shall take such action concerning a Potential Termination Event as may be directed by the Purchaser, but until the Agent receives such directions, the Agent may (but shall not be obligated to) take such action, or refrain from taking such action, as the Agent deems advisable and in the best interests of the Purchaser.

Section 8.7.Non-Reliance on Agent.  The Purchaser expressly acknowledges that neither the Agent nor any of its officers, directors, employees, agents, attorneys-in-fact or Affiliates has made any representations or warranties to it and that no act by the Agent hereafter taken, including any review of the affairs of the Seller or the Originator, shall be deemed to constitute any representation or warranty by the Agent.  The Purchaser represents and warrants to the Agent that, independently and without reliance upon the Agent and based on such documents and information as it has deemed appropriate, it has made and will continue to make its own appraisal of and investigation into the business, operations, property, prospects, financial and other conditions and creditworthiness of the Seller, the Originator, and the Receivables and its own decision to enter into this Agreement and to take, or omit, action under any Transaction Document.  The Agent shall deliver each month to the Purchaser that so requests a copy of the Periodic Report(s) received covering the preceding calendar month.  Except for items specifically required to be delivered hereunder, the Agent shall not have any duty or responsibility to provide the Purchaser with any information concerning the Seller or the Originator or any of their Affiliates that comes into the possession of the Agent or any of its officers, directors, employees, agents, attorneys-in-fact or Affiliates.

Section 8.8.Agent and Affiliates.  The Agent and its Affiliates may extend credit to, accept deposits from and generally engage in any kind of business with the Seller, the Originator or any of their Affiliates and, in its roles as a Liquidity Provider, BTMNY may exercise or refrain from exercising its rights and powers as if it were not the Agent.  The parties acknowledge that BTMNY acts as agent for the Purchaser and subagent for the Purchaser’s management company in various capacities, as well as providing credit facilities and other support for the Purchaser not contained in the Transaction Documents.

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Section 8.9.[Reserved].  

Section 8.10.Successor Agent.  The Agent may, upon at least thirty (30) days notice to the Seller and the Purchaser, resign as Agent.  Such resignation shall not become effective until a successor agent is appointed by the Purchaser (with the approval of the Seller, which approval may not be unreasonably withheld or delayed) and has accepted such appointment.  Upon such acceptance of its appointment as Agent hereunder by a successor Agent, such successor Agent shall succeed to and become vested with all the rights and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations under the Transaction Documents.  After any retiring Agent’s resignation hereunder, the provisions of Article VI and this Article VIII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was the Agent.

Article IX

Miscellaneous

Section 9.1.Termination.  This Agreement shall terminate following the Termination Date (unless the events giving rise to such Termination Date have been waived) when no Investment is held by the Purchaser and all other amounts payable hereunder have been indefeasibly paid in full, but the rights and remedies of the Agent and the Purchaser under Article VI and the provisions of Sections 9.10 and 9.11 shall survive such termination.

Section 9.2.Notices.  Unless otherwise specified, all notices and other communications hereunder shall be in writing (including by telecopier or other facsimile communication), given to the appropriate Person at its address or telecopy number set forth on the signature pages hereof or at such other address or telecopy number as such Person may specify, and effective when received at the address specified by such Person.  The Agent agrees to notify the Seller and the Originator prior to recording any conversation.  The number of days for any advance notice required hereunder may be waived (orally or in writing) by the Person receiving such notice and, in the case of notices to the Agent, the consent of each Person to which the Agent is required to forward such notice.

Section 9.3.Payments and Computations.  Notwithstanding anything herein to the contrary, any amounts to be paid or transferred by the Seller or the Collection Agent to, or for the benefit of, the Purchaser or any other Person shall be paid or transferred to the Agent (for the benefit of the Purchaser or other Person).  The Agent shall promptly (and, if reasonably practicable, on the day it receives such amounts) forward each such amount to the Person entitled thereto and such Person shall apply the amount in accordance herewith.  All amounts to be paid or deposited hereunder shall be paid or transferred on the day when due in immediately available Dollars (and, if due from the Seller or Collection Agent, by 12:00 noon (New York City time), with amounts received after such time being deemed paid on the Business Day following such receipt).  The Seller shall, to the extent permitted by law, pay to the Agent upon demand, for the account of the applicable Person, interest on all amounts not paid or transferred by the Seller or the Collection Agent when due hereunder at a rate equal to the Prime Rate plus 1%, calculated from the date any such amount became due until the date paid in full.  Any payment or other

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transfer of funds scheduled to be made on a day that is not a Business Day shall be made on the next Business Day, and any Discount Rate or interest rate accruing on such amount to be paid or transferred shall continue to accrue to such next Business Day.  All computations of interest, fees, and Discount shall be calculated for the actual days elapsed based on a 360 day year.

Section 9.4.[Reserved].  

Section 9.5.Right of Setoff.  After the occurrence and during the continuation of a Termination Event, the Purchaser is hereby authorized (in addition to any other rights it may have) to setoff, appropriate and apply (without presentment, demand, protest or other notice which are hereby expressly waived) any deposits and any other indebtedness held or owing by the Purchaser (including by any branches or agencies of the Purchaser) to, or for the account of, the Seller against amounts owing by the Seller hereunder (even if contingent or unmatured).

Section 9.6.Amendments.  Except as otherwise expressly provided herein, no amendment or waiver hereof shall be effective unless signed by the Seller, the Collection Agent and the Purchaser.  

Section 9.7.Waivers.  No failure or delay of the Agent or the Purchaser in exercising any power, right, privilege or remedy hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such power, right, privilege or remedy preclude any other or further exercise thereof or the exercise of any other power, right, privilege or remedy.  Any waiver hereof shall be effective only in the specific instance and for the specific purpose for which such waiver was given.  After any waiver, the Seller, the Purchaser and the Agent shall be restored to their former position and rights and any Potential Termination Event waived shall be deemed to be cured and not continuing, but no such waiver shall extend to (or impair any right consequent upon) any subsequent or other Potential Termination Event.  Any additional Discount that has accrued after a Termination Event before the execution of a waiver thereof, solely as a result of the occurrence of such Termination Event, may be waived by the Agent at the direction of the Purchaser entitled thereto.

Section 9.8.Successors and Assigns; Participations; Assignments.

(a)Successors and Assigns.  This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.  Except as otherwise provided herein, the parties hereto (except to the extent provided in Section 3.1) may not assign or transfer any of their rights or delegate any of their duties without the prior consent of the other parties.

(b)Participations. The Purchaser may sell to one or more Persons (each a “Participant”) participating interests in the interests of the Purchaser hereunder.  The Purchaser shall remain solely responsible for performing its obligations hereunder, and the Seller, the Originator and the Agent shall continue to deal solely and directly with the Purchaser in connection with the Purchaser’s rights and obligations hereunder.  Each Participant shall be entitled to the benefits of Article VI to the extent that the Purchaser would be entitled to such benefits if no such participation had been sold and shall have the right of setoff through its

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participation in amounts owing hereunder to the same extent as if it were a Purchaser hereunder.  The Purchaser shall not agree with a Participant to restrict the Purchaser’s right to agree to any amendment hereto.  Any agreement pursuant to which the Purchaser sells a participation shall provide that the Purchaser shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement.  A participant shall not be entitled to receive any greater payment under Section 6.1, 6.2 or 6.3 hereof than the Purchaser would have been entitled to receive, with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Seller’s prior written consent.

(c)Assignments by Purchaser.  The Purchaser may assign to a Person any portion of (i) its commitment to make a Purchase or (ii) its Purchase Interest pursuant to a supplement hereto.  Prior to the occurrence of a Termination Event, any such assignment of a commitment shall require the prior written consent of the Seller (which shall not be unreasonably withheld) unless the assignee (i) is an entity whose principal business is the purchase of assets similar to the Receivables, (ii) has BTMNY as its administrative agent (iii) issues commercial paper, and (iv) would not cause any additional amounts to be due from the Seller under Section 6.4.  Upon such an assignment of any portion of the Purchase Interest, the assignee shall have all of the rights of the Purchaser hereunder related to such portion of the Purchase Interest.

Section 9.9.Intended Tax Characterization.  It is the intention of the parties hereto that, for the purposes of all Taxes, the transactions contemplated hereby shall be treated as a loan by the Purchaser (through the Agent) to the Seller that is secured by the Receivables (the “Intended Tax Characterization”).  The parties hereto agree to report and otherwise to act for the purposes of all Taxes in a manner consistent with the Intended Tax Characterization.

Section 9.10.Confidentiality.  (a)  The parties hereto agree to hold the Transaction Documents or any other confidential or proprietary information received in connection therewith in confidence and agree not to provide any Person with copies of any Transaction Document or such other confidential or proprietary information other than to (i) any officers, directors, members, managers, employees or outside accountants, auditors or attorneys thereof, (ii) any prospective or actual assignee or participant which (in each case) has signed a confidentiality agreement with terms substantially similar to the terms hereof, (iii) any Rating Agency, (iv) any surety, guarantor or credit or liquidity enhancer to the Agent or the Purchaser which (in each case) has signed a confidentiality agreement with terms substantially similar to the terms hereof, (v) any entity organized to loan, or make loans secured by, financial assets for which BTMNY provides managerial services or acts as an administrative agent which (in each case) has signed a confidentiality agreement with terms substantially similar to the terms hereof, (vi) the Purchaser’s administrator, management company, referral agents, issuing agents or depositaries or commercial paper dealers and (vii) Governmental Authorities with appropriate jurisdiction, including, without limitation, any filings required by the Securities Exchange Act of 1934, as amended, and Chapter 386 and 393 of the Missouri Revised Statutes, as amended, as amended, and the rules and regulations promulgated thereunder.  Notwithstanding the above stated obligations, provided that the other parties hereto are given notice of the intended disclosure or use, the parties hereto will not be liable for disclosure or use of such information which such Person can establish by tangible evidence: (i) was required by law, including pursuant to a valid

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subpoena or other legal process, (ii) was in such Person’s possession or known to such Person prior to receipt or (iii) is or becomes known to the public through disclosure in a printed publication (without breach of any of such Person’s obligations hereunder).

(b)Notwithstanding anything to the contrary contained herein or in any of the other Transaction Documents, each of the parties hereto acknowledges and agrees that the Agent or the Purchaser may, to the extent such  information relates to the business or affairs of Seller, Originator or Parent, post to a secured password-protected internet website maintained by the Agent or the Purchaser and required by any rating agency rating the commercial paper notes of the Purchaser in connection with Rule 17g-5 (as defined below) such information as any such rating agency may request in connection with the confirming its rating of such commercial paper notes or that the Agent or the Purchaser may otherwise determine is necessary or appropriate to post to such website in furtherance of the requirements of Rule 17g-5.  “Rule 17g-5” shall mean Rule 17g-5 under the Securities Exchange Act of 1934 as such may be amended from time to time, and subject to such clarification and interpretation as has been provided by the Securities and Exchange Commission in the adopting release (Amendments to Rules for Nationally Recognized Statistical Rating Organizations, Exchange Act Release No. 34-61050, 74 Fed. Reg. 63,832, 63,865 (Dec. 4, 2009)) and subject to such clarification and interpretation as may be provided by the Securities and Exchange Commission or its staff from time to time.

(c)Notwithstanding anything to contrary herein, the parties (and each employee, representative or other agent of such parties) may disclose to any and all persons, without limitation of any kind, the United States tax treatment and United States tax structure of the transactions contemplated in the Transaction Documents and related materials (including opinions or other tax analyses) that are provided to the parties relating to such tax treatment and tax structure.

(d)The Agent and the Purchaser each agrees and acknowledges, on its own behalf and on behalf of any Program Administrator or Purchaser Funding Source, that as to all NPPI received or obtained by it with respect to any Obligor (“Customer Information”) under any Receivable: (i) such Customer Information is and shall be held by the Agent, Purchaser, Program Administrator or Purchaser Funding Source in accordance with all applicable law, including but not limited to the privacy provisions of the Gramm-Leach-Bliley Act, as it may be amended from time to time (the “GLB Act”); and (ii) the Agent, Purchaser, Program Administrator and Purchaser Funding Source are prohibited from disclosing or using any such Customer Information other than to carry out the express provisions of this Agreement, or as otherwise permitted by applicable law.  The Agent and the Purchaser shall take all reasonable measures to ensure that the Customer Information is not disclosed, published, released, transferred, duplicated or otherwise made available to others in contravention of the provisions of this Agreement or of the GLB Act or the regulations promulgated thereunder.  The Agent and the Purchaser shall implement and maintain “appropriate safeguards,” as that term is used in the GLB Act and § 314.4(d) of the FTC Safeguard Rule, 16 C.F.R. § 314 (the “FTC Rule”), for all “customer information,” as that term is defined in §314.2(b) of the FTC Rule, delivered to Agent and Purchaser pursuant to this Agreement.  The Agent and Purchaser shall each promptly notify the Seller and the Initial Collection Agent of any disclosure of or breach of security related to any Customer Information made in violation of the foregoing and shall take all reasonable

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actions required by the Seller and the Initial Collection Agent in connection with any such violation or security breach.  The provisions of Section shall survive the termination of this Agreement.

Section 9.11.Agreement Not to Petition.  Each party hereto agrees, for the benefit of the holders of the privately or publicly placed indebtedness for borrowed money for the Purchaser, not, prior to the date which is one (1) year and one (1) day after the payment in full of all such indebtedness, to acquiesce, petition or otherwise, directly or indirectly, invoke, or cause the Purchaser to invoke, the process of any Governmental Authority for the purpose of (a) commencing or sustaining a case against the Purchaser under any federal or state bankruptcy, insolvency or similar law (including the Federal Bankruptcy Code), (b) appointing a receiver, liquidator, assignee, trustee, custodian, sequestrator or other similar official for the Purchaser, or any substantial part of its property, or (c) ordering the winding up or liquidation of the affairs of the Purchaser.

      Section 9.12.Excess Funds.  The Purchaser shall be required to make payment of the amounts required to be paid pursuant hereto only if the Purchaser has Excess Funds (as defined below).  If the Purchaser does not have Excess Funds, the excess of the amount due hereunder over the amount paid shall not constitute a “claim” (as defined in Section 101(5) of the Federal Bankruptcy Code) against Victory until such time as the Purchaser has Excess Funds.  If the Purchaser does not have sufficient Excess Funds to make any payment due hereunder, then the Purchaser may pay a lesser amount and make additional payments that in the aggregate equal the amount of deficiency as soon as possible thereafter.  The term “Excess Funds” means the excess of (a) the aggregate projected value of the Purchaser’s assets and other property (including cash and cash equivalents), over (b) the sum of (i) the sum of all scheduled payments of principal, interest and other amounts payable on publicly or privately placed indebtedness of the Purchaser for borrowed money, plus (ii) the sum of all other liabilities, indebtedness and other obligations of the Purchaser for borrowed money or owed to any credit or liquidity provider, together with all unpaid interest then accrued thereon, plus (iii) all taxes payable by the Purchaser to the Internal Revenue Service, plus (iv) all other indebtedness, liabilities and obligations of the Purchaser then due and payable, but the amount of any liability, indebtedness or obligation of the Purchaser shall not exceed the projected value of the assets to which recourse for such liability, indebtedness or obligation is limited.  Excess Funds shall be calculated once each Business Day.

Section 9.13.No Recourse.  No recourse under any obligation, covenant or agreement or agreement of any party contained in this Agreement shall be had against any stockholder, employee, officer, director, incorporator or organizer of such party, provided, however, that nothing in this Section 9.13 shall relieve any of the foregoing Persons from any liability which such Person may otherwise have for its bad faith, gross negligence or willful misconduct.

Section 9.14.Deutsche Bank Trust Company Americas, BTMNY and Affiliates. Deutsche Bank Trust Company Americas, BTMNY and any of their respective Affiliates may generally engage in any kind of business with the Seller, the Collection Agent or any Obligor, any of their respective Affiliates and any Person who may do business with or own securities of the Seller, Originator or any Obligor or any of their respective Affiliates, all as if Deutsche Bank Trust Company Americas were not the Program Administrator and BTMNY were not the Agent,

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respectively, and without any duty to account therefor to the Purchaser or any other holder of an interest in the Receivables.

Section 9.15.Headings; Counterparts.  Article and Section Headings in this Agreement are for reference only and shall not affect the construction of this Agreement.  This Agreement may be executed by different parties on any number of counterparts, each of which shall constitute an original and all of which, taken together, shall constitute one and the same agreement.

Section 9.16.Cumulative Rights and Severability.  All rights and remedies of the Purchaser and Agent hereunder shall be cumulative and non-exclusive of any rights or remedies such Persons have under law or otherwise.  Any provision hereof that is prohibited or unenforceable in any jurisdiction shall, in such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof and without affecting such provision in any other jurisdiction.

Section 9.17.Governing Law; Submission to Jurisdiction.  This Agreement, including the rights and duties of the parties hereto, shall be governed by, and construed in accordance with, the internal laws of the State of New York (including Section 5-1401-1 of the General Obligations Law, but without regard to any other conflict of laws provisions thereof), except to the extent that the perfection of the interests of the Purchaser in the Receivables or related security is governed by the laws of a jurisdiction other than the State of New York.

Section 9.18.Waiver of Trial by Jury.  To the extent permitted by applicable law, each party hereto irrevocably waives all right of trial by jury in any action, proceeding or counterclaim arising out of, or in connection with, any transaction document or any matter arising thereunder.

Section 9.19.Entire Agreement.  The Transaction Documents constitute the entire understanding of the parties thereto concerning the subject matter thereof.  Any previous or contemporaneous agreements, whether written or oral, concerning such matters are superseded thereby.

Section 9.20.Third Party Beneficiaries.  Each Liquidity Provider and each Enhancement Provider are express third party beneficiaries hereof.

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In Witness Whereof, the parties hereto have caused this Agreement to be executed and delivered by their duly authorized officers as of the date hereof.

The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as the Agent

By: /s/ Eric Williams

Title: Director

Address: Securitization Group

1251 Avenue of the Americas

12th Floor

New York, New York 10020

Attention:  Van Dusenbury

Telephone: (212) 782-6964

Telecopy: (212) 782-6448

With a copy to:

Attention: Eric Williams

Phone:  (212) 782-4910

Facsimile: 212-782-6448

Victory Receivables Corporation

By: /s/ David V. DiAngelis

Title: Vice President

Address: 114 W. 47th St.

Suite 2310

New York, New York 10036

Attention: David D. DeAngelis

Telephone: (212) 295-2745

Telecopy:

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GMO Receivables Company, as Seller

By: /s/ James P. Gilligan

Title: President

Address: 2215-B Renaissance Drive

Renaissance Office Park

Las Vegas, Nevada 89119

Attention: Wendy Mavrinac

Telephone: (702) 740-4244

Telecopy: (702) 966-4247

KCP&L Greater Missouri Operations Company, as Initial Collection Agent

By: /s/ Kevin E. Bryant

Title: Vice President-Investor Relations and Treasurer

Address: 1200 Main Street, 28th Floor

Kansas City, Missouri  64105

Attention:  James P. Gilligan

Telephone: (816) 556-2084

Telecopy:  (816) 556-2992

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Schedule I

Definitions

The following terms have the meanings set forth, or referred to, below:

“Accounting Authority” means any accounting board or authority (whether or not part of a government) which is responsible for the establishment or interpretation of national or international accounting principles, in each case whether foreign or domestic.

“Adverse Claim” means, for any asset or property of a Person, a lien, security interest, charge, mortgage, pledge, hypothecation, assignment or encumbrance, or any other right or similar claim, in, of or on such asset or property in favor of any other Person, except those created by the Transaction Documents.

“Affected Party” means the Purchaser, any assignee of the Purchaser permitted by Section 9.8 hereof, the Agent, any successor to the Agent and any sub-agent of Agent or any Affiliate of any of the foregoing; provided that a participant of Purchaser shall also be an Affected Party, and shall be entitled to the benefits or an Affected Party, to the extent that Purchaser would be entitled to such benefits if no such participation had been sold.

“Affiliate” means, for any Person, any other Person which, directly or indirectly, is in control of, is controlled by, or is under common control with such Person.  For purposes of this definition, “control” means the power, directly or indirectly, to either (i) vote ten percent (10%) or more of the securities having ordinary voting power for the election of directors of a Person or (ii) cause the direction of the management and policies of a Person.

“Agent” is defined in the first paragraph hereof.

“Agent’s Account” means the account so designated to the Seller and the Purchaser by the Agent.

“Agent’s Notice” means the “Access Termination Notice”, “Notice” or other similar notice requiring the Collection Bank to comply with instructions delivered by the Agent, as defined in the applicable Deposit Account Control Agreement.

“Aggregate Reserve” means, at any time at which such amount is calculated, the sum of the Loss Reserve, the Dilution Reserve and Discount Reserve.

“Alternate Base Rate” means, on any date, a fluctuating rate of interest per annum equal to the higher of:

(a)the rate of interest most recently announced by The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch in New York, New York as its Prime Rate; or

(b)the Federal Funds Rate most recently determined by Agent, plus 0.50%.

The Alternate Base Rate is not necessarily intended to be the lowest rate of interest determined by Agent in connection with extensions of credit.

“Bank Rate” for any day falling in a particular Tranche Period with respect to any Tranche means an interest rate per annum equal to the BTM LIBO Rate for such Tranche Period.

“Bankruptcy Event” means, for any Person, that (a) (i) such Person makes a general assignment for the benefit of creditors or (ii) any proceeding is instituted by or against such Person seeking to adjudicate it bankrupt or insolvent, or seeking the liquidation, winding up, reorganization, arrangement, adjustment, protection, relief or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee or other similar official for it or any substantial part of its property and, if such proceeding was not voluntarily instituted by such Person, such decree or order remains unstayed and in effect for a period of sixty (60) daysor (b) such Person takes any corporate action to authorize any such action.

“BTM LIBO Rate” means for any Tranche Period either (a) the interest rate per annum for a period of time comparable to such Tranche Period that appears on the Reuters Screen LIBO Page as of 11:00 a.m. (London time) on the second Business Day preceding the first day of such Tranche Period or (b) if a rate cannot be determined under clause (a), an annual rate designated as The Bank of Tokyo-Mitsubishi LIBO Rate equal to the average (rounded upwards if necessary to the nearest 1/100th of 1%) of the rates per annum at which deposits in U.S. Dollars with a duration equal to such Tranche Period in a principal amount substantially equal to the applicable Tranche are offered to the principal London office of The Bank of Tokyo-Mitsubishi UFJ, Ltd. by three London banks, selected by the Agent in good faith, at about 11:00 a.m. London time on the second Business Day preceding the first day of such Tranche Period.

“BTMNY” means The Bank of Tokyo-Mitsubishi UFJ, Ltd. in its individual capacity and not in its capacity as the Agent.

“Business Day” means any day other than (a) a Saturday, Sunday or other day on which banks in New York City, New York, Chicago, Illinois or Kansas City, Missouri are authorized or required to close, (b) a holiday on the Federal Reserve calendar and, (c) solely for matters relating to a Tranche based on BTMNY LIBO Rate, a day on which dealings in Dollars are not carried on in the London interbank market.

“Charge-Off” means any Receivable that has or should have been (in accordance with the Credit and Collection Policy) charged off or written off by the Seller.

“Collection” means any amount paid on a Receivable or any amount paid or deemed paid as a Deemed Collection under Section 1.5(b).

“Collection Account” means account number 9871739643 maintained with UMB Bank, N.A. (“UMB”) in the name of the Agent or any other account so designated by the Seller to the Agent in writing.

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“Collection Agent” is defined in Section 3.1(a).

“Collection Agent Excluded Losses” is defined in Section 3.9.

“Collection Agent Fee” is defined in Section 3.6.

“Collection Agent Fee Letter” means the letter agreement dated as of the date hereof among the Agent, the Seller and the Collection Agent.

“Collection Agent Replacement Event” means the occurrence of any one or more of the following:

(a)the Collection Agent (or any sub-collection agent) fails to observe or perform any material term, covenant or agreement under any Transaction Document and such failure remains unremedied for ten (10) Business Days after the earlier of notice from the Agent or knowledge by a Designated Financial Officer;

(b)any written representation, warranty, certification or statement made by the Collection Agent in, or pursuant to, any Transaction Document proves to have been incorrect in any respect that is materially adverse to the Purchaser when made and remains incorrect or untrue for ten (10) Business Days after the earlier of notice from the Agent or knowledge by a Designated Financial Officer; or

(c)the Collection Agent suffers a Bankruptcy Event.

“Collection Agent Termination” is defined in Section 3.1(a).

“Collection Bank” means each bank listed on Exhibit F, as revised pursuant to Section 5.1(i).

“Commercial Paper Notes” means short-term promissory notes issued or to be issued by the Purchaser to fund its investments in accounts receivable or other financial assets.

“Concentration Limit” means (i) for any Obligor which is a federal government or a governmental subdivision or agency thereof, 3% of the Eligible Receivables Balance, (ii) for any Obligor with long-term unsecured indebtedness rated A- or higher by S&P and A3 or higher by Moody’s, 4% of the Eligible Receivables Balance, and (iii) for any Obligor that has no rated long-term unsecured indebtedness or with long-term unsecured indebtedness rated lower than A- by S&P or lower than A3 by Moody’s (or S&P or Moody’s has withdrawn or suspended such rating), 2% of the Eligible Receivables Balance.  If the Moody’s rating and the S&P rating assigned to the long-term unsecured indebtedness of any Obligor differ, then the Concentration Limit for such Obligor shall be used on the lower of such ratings.

“CP Dealer” means, at any time, each Person the Purchaser then engages as a placement agent or commercial paper dealer.

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“CP Rate” for any period and with respect to the Investment funded by Commercial Paper Notes, means:  (I) unless the Agent has determined that the Pooled CP Rate shall be applicable, the rate per annum calculated by the Agent to reflect the Purchaser’s cost of funding such Investment, taking into account the weighted daily average interest rate payable in respect to such Commercial Paper Notes during such period (determined in the case of discount Commercial Paper Notes by converting the discount to an interest bearing equivalent per annum), applicable placement fees and commissions, and such other costs and expenses as the Agent in good faith deems appropriate; and (II) to the extent the Agent has determined that the Pooled CP Rate shall be applicable, the Pooled CP Rate.  The Agent agrees to provide prompt notice to the Seller of any decision to apply a CP Rate other than the Pooled CP Rate.

“Credit and Collection Policy” means the Seller’s credit and collection policy and practices relating to Receivables based on the Missouri Public Service Commission rules which, as currently in effect, are attached hereto as Exhibit I.

“Customer Deposit” means a deposit or prepayment by an Obligor made in consideration of services not yet rendered by the Originator.

“Customer Deposit Amount” means (a) if the long term unsecured indebtedness of the Originator is rated greater than or equal to BBB- by S&P or Baa3 by Moody’s, the aggregate amount of Customer Deposits in excess of 15% of the Eligible Receivables Balance (calculated without regard to this definition) and (b) if the long term unsecured indebtedness of the Originator is rated less than BBB- by S&P or Baa3 by Moody’s, the aggregate amount of Customer Deposits.

“Customer Information” is defined in Section 9.10(d).

“Deemed Collections” is defined in Section 1.5(c).

“Default Ratio” means the ratio (expressed as a percentage) for any calendar month of (a) the then aggregate outstanding balance of all Receivables that during such month became Defaulted Receivables (minus Charge-Offs) at the end of such calendar month to (b) the then aggregate outstanding balance of all Receivables (minus Charge-Offs) at the end of such calendar month.

“Defaulted Receivable” means any Receivable (a) on which any amount is unpaid more than 90 days past its invoice date or (b) the Obligor on which has suffered a Bankruptcy Event.

“Delinquency Ratio” means, the ratio (expressed as a percentage), for any calendar month of (a) the then aggregate outstanding balance of all Receivables that during such month became Delinquent Receivables as of the end of such calendar month to (b) the then aggregate outstanding balance of all Receivables at the end of such calendar month.

“Delinquent Receivable” means any Receivable (other than a Charge-Off or Defaulted Receivable) on which any amount is unpaid more than 60 days.

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“Deposit Account Control Agreement” means an agreement acceptable to the Agent between the Agent, the Collection Agent and each Collection Bank granting the Agent “control” within the meaning of Section 9-104 of the UCC over a Lock-Box or Collection Account.

“Deposit Date” means each day on which any Collections are transferred to any Lock-Box, deposited directly into the Collection Account by an Obligor or on which the Collection Agent receives Collections.

“Designated Financial Officer” means any officer of the Seller or the Chief Financial Officer, Controller or Treasurer of the Originator.

“Designated Payee” means each Person listed on Exhibit G.

“Dilution Ratio” means, the ratio (expressed as a percentage), for any period, of (a) the aggregate amount of payments owed by the Seller pursuant to the first sentence of Section 1.5(b) for such period to (b) the aggregate amount of Collections received during such period.

“Dilution Reserve” means (i) two (2) times the highest three consecutive month average Dilution Ratio (expressed as a decimal) over the last twelve (12) calendar months multiplied by (ii) the Eligible Receivables Balance.

“Discount” means, for any Tranche Period, (a) the product of (i) the Discount Rate for such Tranche Period, (ii) the total amount of Investment allocated to the Tranche Period, and (iii) the number of days elapsed during the Tranche Period divided by (b) 360 days.

“Discount Rate” means (a) in the case of a Tranche funded by Commercial Paper Notes, the applicable CP Rate; and (b) in the case of a Tranche funded by a Liquidity Advance or by a funding under an Enhancement Agreement, the applicable Bank Rate, plus 2.0% for such Tranche; provided, however, that (i) on any day as to any Tranche which is not funded by Commercial Paper Notes, the Discount Rate shall equal the Alternate Base Rate, plus 2.0% if (A) the Agent does not receive notice or determine, by no later than 12:00 noon (New York City time) on the third Business Day prior to the first day of the related Tranche Period, that such Tranche shall not be funded by Commercial Paper Notes or (B) the Agent determines that (I) funding that Tranche on a basis consistent with pricing based on the Bank Rate would violate any applicable law or (II) that deposits of a type and maturity appropriate to match fund such Tranche are not available; and (ii) on any day when any Termination Event shall have occurred and be continuing, the Discount Rate for each Tranche means a rate per annum equal to the higher of (A) the Alternate Base Rate, plus 2.0% per annum and (B) the rate otherwise applicable to such Tranche during the current Tranche Period or Settlement Period, plus 2.0% per annum.

“Discount Reserve” means, at any time, the product of (a) 1.5 multiplied by (b) the rate announced by BTMNY as its “Prime Rate” (which may not be its best or lowest rate) plus 2.50% multiplied by (c) Investment multiplied by (d) a fraction, the numerator of which is the average Turnover Ratio over the last three calendar months and the denominator of which is 360.

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“Dollar” and “$” means lawful currency of the United States of America.

“Eligible Receivable” means, at any time, any Receivable:

(i)the Obligor of which (a) is a resident of, or organized under the laws of, or with its chief executive office in, the USA; (b) is not an Affiliate of the Seller or the Originator; and (c) is a customer of the Originator in good standing and not the Obligor of any Receivable that became a Charge-Off (unless such Charge-Off has been subsequently paid-in-full by the related Obligor);

(ii)which is stated to be due and payable within 30 days after the invoice therefor;

(iii)which is not a Defaulted Receivable or a Charge-Off;

(iv)which is an “account” within the meaning of Section 9-105 of the UCC of all applicable jurisdictions;

(v)which is denominated and payable only in Dollars in the USA;

(vi)which arises under a contract or a publicly filed tariff that is in full force and effect and constitutes the legal, valid and binding obligation of the related Obligor enforceable against such Obligor in accordance with its terms subject to no offset, counterclaim, defense or other Adverse Claim, and is not an executory contract or unexpired lease within the meaning of Section 365 of the Bankruptcy Code;

(vii)which (a) contains an obligation to pay a sum of money and is subject to no contingencies, (b) does not require the Obligor to consent to the transfer, sale or assignment of the rights and duties of the Originator, (c) does not contain a confidentiality provision that purports to restrict the Purchaser’s exercise of rights under this Agreement, including, without limitation, the right to review any contract related thereto and (d) directs that payment be made to a Lock-Box or the Collection Account;

(viii)which does not, in whole or in part, contravene any material law, rule or regulation applicable thereto (including, without limitation, those relating to usury, truth in lending, fair credit billing, fair credit reporting, equal credit opportunity, fair debt collection practices and privacy);

(ix)which satisfies all applicable requirements of the Credit and Collection Policy and was generated in the ordinary course of the Originator’s business from the sale of goods or provision of services to a related Obligor solely by the Originator;

(x)which relates to the sale by the Originator of steam, electricity, steam-related services and electricity-related services to retail customers within its general service area on the date hereof;

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(xi)the transfer, sale or assignment of which does not contravene any applicable law, rule or regulation; and

    (xii)as to which the Originator has satisfied and fully performed all obligations on its part with respect to such Receivable required to be fulfilled by it, and other than issuing an invoice, no further action is required to be performed by any Person with respect thereto other than payment thereon by the applicable Obligor.

“Eligible Receivable Balance” means, at any time, the aggregate outstanding principal balance of all Eligible Receivables less the sum of (i) the portion of the aggregate outstanding principal balance of Eligible Receivables of any Obligor that exceeds the applicable Concentration Limit or the Special Limit (ii) the Customer Deposit Amount and (iii) the amount, if any, by which the outstanding balance of Eligible Receivables for which the Originator has not yet issued an invoice exceeds 60% of the outstanding balance of all Eligible Receivables.

“Enhancement Agreement” means any agreement between the Purchaser and any other Person(s) entered into to provide credit enhancement to Purchaser’s commercial paper facility.

“Enhancement Provider” means any Person providing credit support to the Purchaser under an Enhancement Agreement.

“ERISA” means the U.S. Employee Retirement Income Security Act of 1974, as amended from time to time.

“Excluded Losses” is defined in Section 6.1.

“FATCA” means Section 1471 through 1474 of the Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with) and any current and future regulations and official interpretations thereof.

“Federal Funds Rate” means, for any period, a fluctuating interest rate per annum equal (for each day during such period) to:

(a)the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York; or

(b)if such rate is not so published for any day which is a Business Day, the average of the quotations for such day on such transactions received by the Liquidity Agent in good faith from three federal funds brokers of recognized standing selected by it.

“Fee Letter” means the letter agreement dated as of the date hereof among the Seller, the Agent and the Purchaser.

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“Fitch” means Fitch, Inc.

“Funding Agreement” means any agreement or instrument executed by the Purchaser and executed by or in favor of any Purchaser Funding Source or executed by any Purchaser Funding Source at the request of the Purchaser (including a Liquidity Agreement executed with respect to the transactions contemplated in the Transaction Documents or an Enhancement Agreement with respect to any portion of the Enhancement Agreement allocated to the transactions contemplated in the Transaction Documents).

“FTC Rule” is defined in Section 9.10(d).

“GAAP” means generally accepted accounting principles in the USA, applied on a consistent basis.

“Governmental Authority” means any (a) Federal, state, municipal or other governmental entity, board, bureau, agency or instrumentality, (b) administrative or regulatory authority (including any central bank or similar authority) or (c) court, judicial authority or arbitrator, in each case, whether foreign or domestic.

“Incremental Purchase” is defined in Section 1.1(b).

“Initial Collection Agent” is defined in the first paragraph hereof.

“Intended Tax Characterization” is defined in Section 9.9.

“Interim Liquidation” means any time before the Termination Date during which no Reinvestment Purchases are made by the Purchaser, as established pursuant to Section 1.2.

“Investment” means, for the Purchaser, (a) the sum of all Incremental Purchases by the Purchaser minus (b) all Collections and other amounts received or exchanged and applied to reduce Investment pursuant to the terms hereof.  Investment shall be restored to the extent any amounts so received or exchanged and applied are rescinded or must be returned for any reason.

“LIBOR” means, as of any date, “London Interbank Offered Rates (Libor) - one month” (or the equivalent term) as most recently published in The Wall Street Journal.

“Liquidation Period” means all times (x) during an Interim Liquidation and (y) on and after the Termination Date (unless the events giving rise to such Termination Date have been waived).

“Liquidity Advance” means a loan, advance, purchase or other similar action made by a Liquidity Provider pursuant to a Liquidity Agreement.

“Liquidity Agent” means BTMNY in its capacity as liquidity agent under the Liquidity Agreement.

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“Liquidity Agreement” means any agreement entered into in connection with this Agreement pursuant to which any Person agrees to make loans or advances to, or purchases from the Purchaser in order to provide liquidity for Purchaser Commercial Paper Notes.

“Liquidity Provider” means BTMNY or any other commercial lending institution that is at any time a lender or purchaser under a Liquidity Agreement.

“Lock-Box” means each post office box or bank box listed on Exhibit F, as revised pursuant to Section 5.1(i).

“Lock-Box Agreement” means each agreement between the Collection Agent and a Collection Bank concerning a Lock-Box.

“Loss Reserve” means, at any time, the product of (i) the greater of (a) 8.0% and (b) 3 times the highest three month rolling average Delinquency Ratio (expressed as a decimal) as of the last day of each of the last 3 calendar months multiplied by (ii) the Eligible Receivables Balance.

“Loss-to-Liquidation Ratio” means, for any calendar month, the ratio (expressed as a percentage) of the outstanding balance of Charge-Offs made during such calendar month to the aggregate amount of Collections during such calendar month.

“Material Adverse Effect” is defined in Section 4.1(a).

“Matured Investment” means, at any time, the Matured Value of the Investment.

“Matured Value” means the sum of the Investment and all unpaid Discount scheduled to become due (whether or not then due) on such Investment during all Tranche Periods to which any portion of such Investment has been allocated.

“Maximum Incremental Purchase Amount” means, at any time, the difference between the Purchase Limit and the Investment then outstanding.

“Monthly Report Date” means with respect to each calendar month, the 15th day of the immediately succeeding calendar month (or if such day is not a Business Day, the immediately succeeding Business Day).

“Moody’s” means Moody’s Investors Service, Inc.

“NPPI” has the meaning ascribed to the term “Nonpublic Personal Information” in 12 U.S.C. §6809(4).

“Obligor” means, for any Receivable, each Person obligated to pay such Receivable and each guarantor of such obligation.

“Originator” means KCP&L Greater Missouri Operations Company.

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“Parent” means Great Plains Energy Incorporated.

“Periodic Report” is defined in Section 3.3.

“Permitted Investments” shall mean (a) evidences of indebtedness, maturing not more than thirty (30) days after the date of purchase thereof, issued by, or the full and timely payment of which is guaranteed by, the full faith and credit of, the federal government of the United States of America, (b) repurchase agreements with banking institutions or broker-dealers that are registered under the Securities Exchange Act of 1934, as amended, fully secured by obligations of the kind specified in clause (a) above, (c) money market funds denominated in Dollars rated not lower than A-1 (and without the “r” symbol attached to any such rating) by S&P and P-1 by Moody’s or otherwise acceptable to the Rating Agencies or (d) commercial paper denominated in Dollars issued by any corporation incorporated under the laws of the United States or any political subdivision thereof, provided that such commercial paper is rated at least A-1 (and without any “r” symbol attached to any such rating) thereof by S&P and at least Prime-1 thereof by Moody’s.

“Person” means an individual, partnership, corporation, association, joint venture, Governmental Authority or other entity of any kind.

“Pooled Commercial Paper” means Commercial Paper Notes of the Purchaser which are subject to any particular pooling arrangement, as determined by the Agent (it being recognized that there may be more than one distinct group of Pooled Commercial Paper at any time).

“Pooled CP Rate” shall means, for each day with respect to the Investment as to which the Pooled CP Rate is applicable, the sum of (i) discount or yield accrued (including, without limitation, any associated with financing the discount or interest component on the roll-over of any Pooled Commercial Paper) on the Purchaser’s Pooled Commercial Paper on such day, plus (ii) any and all accrued commissions in respect of its placement agents and commercial paper dealers, and issuing and paying agent fees incurred, in respect of such Pooled Commercial Paper for such day, plus (iii) other costs (including without limitation those associated with funding small or odd-lot amounts) with respect to all receivable purchase, credit and other investment facilities which are funded by the applicable Pooled Commercial Paper for such day.  The Pooled CP Rate shall be determined for the Purchaser by the Agent, whose determination shall be conclusive.

“Potential Termination Event” means any Termination Event or any event or condition that with the lapse of time or giving of notice, or both, would constitute a Termination Event.

“Program Administration Agreement” means that certain Administration Agreement between Purchaser and Deutsche Bank Trust Company Americas governing certain aspects of the administration of Purchaser’s commercial paper facility.

“Program Administrator” means Deutsche Bank Trust Company Americas and its successors under the Program Administration Agreement.

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“Purchase” is defined in Section 1.1(a).

“Purchase Agreement” means the Purchase and Sale Agreement dated as of the date hereof between the Seller and the Originator.

“Purchase Amount” is defined in Section 1.1(c).

“Purchase Date” is defined in Section 1.1(c).

“Purchase Interest” means the percentage ownership interest in the Receivables and Collections held by the Purchaser, calculated when and as described in Section 1.1(a).

“Purchase Limit” means $80,000,000; provided, however, for each Seasonal Period the Purchase Limit shall equal $65,000,000.

“Purchaser” is defined in the first paragraph hereof.

“Purchaser Funding Source” means any insurance company, bank or other financial institution providing liquidity, back-up purchase or credit support for the Purchaser in connection with the transactions contemplated by this Agreement.

“Rating Agency” means Moody’s, S&P, and Fitch and any other rating agency the Purchaser chooses to rate its commercial paper notes.

“Ratings” means the ratings by the Rating Agencies of the indebtedness for borrowed money of the Purchaser.

“Receivable” means each obligation of an Obligor to pay for the delivery or sale by the Originator of steam, electricity, steam-related services and electricity-related services to retail customers within its general service area (as such area exists on the date hereof) and includes the Originator’s rights to payment of any interest or finance charges and all proceeds of the foregoing.  During any Interim Liquidation and on and after the Termination Date (unless the events giving rise to such Termination Date have been waived), the term “Receivable” shall only include receivables existing on the date such Interim Liquidation commenced or Termination Date occurred, as applicable.  Deemed Collections shall reduce the outstanding balance of Receivables hereunder, so that any Receivable that has its outstanding balance deemed collected shall cease to be a Receivable hereunder to the extent that (x) the Collection Agent receives payment of such Deemed Collections under Section 1.5(b) or (y) if such Deemed Collection is received before the Termination Date, an adjustment to the Purchase Interest permitted by Section 1.5(c) is made.

“Records” means, for any Receivable, all contracts, books, records and other documents or information (including computer programs, tapes, disks, software and related property and rights) relating to such Receivable or the related Obligor.

“Reinvestment Purchase” is defined in Section 1.1(b).

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“Related Security” means all security interests, guaranties and property securing or supporting payment of the Receivables, all Records and all proceeds of the foregoing.

“Reserve Percentage” means, at any time, the quotient obtained by dividing (a) the Aggregate Reserve by (b) the Eligible Receivables Balance.

“Seasonal Interim Liquidation” is defined in Section 1.2(b).

“Seasonal Period” means November 1 of a calendar year to and including May 31 of the succeeding calendar year.

“SEC” means Securities and Exchange Commission.

“Secured Parties” means the Purchaser, the Agent and the Affected Parties.

“Seller” is defined in the first paragraph hereof.

“Seller Entity” means the Originator and the Parent.

“Seller Account” means the Seller’s account designated by the Seller to the Agent in writing.

“Settlement Date” means with respect to each calendar month, the second Business Day after the Monthly Report Date for such calendar month; provided, however, that upon the occurrence and during the continuation of a Termination Event, the Settlement Date shall be a Business Day designated by the Agent.

“Settlement Period” means, with respect to each Settlement Date, the calendar month preceding such Settlement Date (or, in the case of the first Settlement Period, the period from the date of the initial Purchase to the end of the calendar month in which such initial Purchase occurred); provided, however, that upon the occurrence and during the continuation of a Termination Event, the duration of each Settlement Period shall be the number of days designated by the Agent.

“Significant Subsidiary” means, at any time, each Subsidiary of the Originator in which the Originator has, at such time, an investment, either directly or indirectly, of $100,000,000 or more, whether through loans or advances, equity investments, capital contributions, contingent obligations or otherwise, with all such investments determined at the original amount thereof, without giving effect to any writeoffs of any such investment.  The Significant Subsidiaries of the Originator on the date hereof are listed on Exhibit E.

“S&P” means Standard & Poor’s Ratings Group.

“Special Limit” means, with respect to the City of Kansas City, Missouri, 5% of the Eligible Receivables Balance.

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“Subordinated Note” means each revolving promissory note issued by the Seller to the Originator under the Purchase Agreement.

“Subsidiary” of a Person means (i) any corporation more than 50% of the outstanding securities having ordinary voting power of which shall at the time be owned or controlled, directly or indirectly, by such Person or by one or more of its Subsidiaries or by such Person and one or more of its Subsidiaries, (ii) any partnership, limited liability company, association, joint venture or similar business organization more than 50% of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled; or (iii) any other Person the operations and/or financial results of which are required to be consolidated with those of such first Person in accordance with GAAP.

“Taxes” means all taxes, charges, fees, levies or other assessments (including income, gross receipts, profits, withholding, excise, property, sales, use, license, occupation and franchise taxes and including any related interest, penalties or other additions) imposed by any jurisdiction or taxing authority (whether foreign or domestic).

“Termination Date” means the earliest of (a) the date of the occurrence of an Termination Event described in clause (e) of the definition of Termination Event, (b) the date designated by the Agent to the Seller at any time upon the occurrence of any other Termination Event, (c) 20 Business Days following notice of termination delivered from Seller to Agent and (d) September 9, 2014.

“Termination Event” means the occurrence of any one or more of the following:

(a)any representation, warranty, certification or statement made by the Seller or the Originator in, or pursuant to, any Transaction Document proves to have been incorrect in any material respect when made (including pursuant to Section 7.2) and is not cured within 20 Business Days of the date made; or

(b)the Collection Agent, the Originator or the Seller fails to make any payment or other transfer of funds hereunder when due (including any payments under Section 1.5(a)) and such failure continues unremedied for three Business Days following written notice from the Agent; or

(c)the Seller fails to observe or perform any covenant or agreement contained in Sections 3.3, 5.1(b), 5.1(g), 5.1(i) or 5.1(j) of this Agreement or the Originator fails to perform any covenant or agreement in Sections 5.1(b), 5.1(g), 5.1(h) and 5.1(n) of the Purchase Agreement, and any such failure is not cured within 10 Business Days after such failure to observe or perform; or

(d)the Seller or the Collection Agent (or any sub-collection agent) fails to observe or perform any other term, covenant or agreement under any Transaction Document, and such failure remains unremedied for twenty Business Days following the earlier of written notice from the Agent or knowledge by a Designated Financial Officer; or

A-13

 (e)the Originator, the Seller or any Significant Subsidiary of the Originator suffers a Bankruptcy Event; provided that with respect to any procedure that is instituted against such Person seeking to adjudicate it bankrupt or insolvent, or seeking the liquidation, winding up, reorganization, arrangement, adjustment, protection, relief or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee or other similar official for it or any substantial part of its property, such proceeding continues undismissed or unstayed for 30 consecutive days or an order for relief has been entered in such proceeding; or

(f)on the date any Periodic Report is due pursuant to Section 3.3, the average Delinquency Ratio for the three month period ending as of the most recent calendar month end exceeds 6.0%, the average Default Ratio for the three-month period then ending exceeds 6.0% or the average Loss-to Liquidation Ratio for the three-month period ending as of the most recent calendar month end exceeds 1.5%;or

(g)the Seller, the Originator or any Significant Subsidiary, directly or indirectly, disaffirms or contests the validity or enforceability of any Transaction Document or (ii) any Transaction Document fails to be the enforceable obligation of the Seller or any Affiliate party thereto; or

(h)the Originator or any Significant Subsidiary (i) generally does not pay its debts as such debts become due or admits in writing its inability to pay its debts generally or (ii) fails to pay any of its indebtedness (except in aggregate principal amount of less than $50,000,000) or defaults in the performance of any provision of any agreement under which such indebtedness was created or is governed and such default permits such indebtedness to be declared due and payable or to be required to be prepaid before the scheduled maturity thereof; or

(i)the Collection Agent changes the Credit and Collection Policy or scope of its business in a way which would have a material adverse effect on the collectibility of any Receivable without the consent of the Agent; or

(j)a Collection Agent Replacement Event has occurred and is continuing; or

(k)the Parent shall fail to own and control, directly or indirectly, 100% of the outstanding voting stock of the Seller and the Originator; or

(l)the Agent, on behalf of the Purchaser, for any reason, does not have a valid first priority ownership or security interest in the Receivables or the Related Security; or

(m)the Seller shall become an “investment company” within the meaning of the Investment Company Act of 1940, as amended; or

A-14

(n)the Originator or any of its Significant Subsidiaries shall fail within thirty (30) days to pay, bond or otherwise discharge (i) any judgment or order for the payment of money not covered by insurance in excess of $50,000,000 (either singly or in the aggregate with other such judgments) or (ii) any non-monetary final judgment that has, or could reasonably be expected to have, a Material Adverse Effect, in either case which is not stayed on appeal or otherwise being appropriately contested in good faith.

(o) a Seasonal Interim Liquidation is not completed within 2 consecutive Settlement Periods.

Notwithstanding the foregoing, a failure of a representation or warranty or breach of any covenant described in clause (a), (c) or (d) above related to a Receivable shall not constitute a Termination Event if the Seller has been deemed to have collected such Receivable pursuant to Section 1.5(b) or, before the Termination Date, has adjusted the Purchase Interest as provided in Section 1.5(c) so that such Receivable is no longer considered to be outstanding.

“Tranche” means at any time a portion of the Investment selected by the Agent pursuant to Section 1.3.

“Tranche Period” (a) with respect to any Tranche funded by Commercial Paper Notes that are not Pooled Commercial Paper, the period selected by the Agent pursuant to Section 1.3(b), and (b) with respect to any Tranche funded by a Liquidity Advance or under the Enhancement Agreement, means:

(a)the period commencing on the date of the initial Purchase of the Purchase Interest, the making of such Liquidity Advance or funding under the Enhancement Agreement or the creation of such Tranche pursuant to Section 1.3 (whichever is latest) and ending such number of days thereafter as the Agent shall select in consultation with the Seller; and

(b)each period commencing on the last day of the immediately preceding Tranche Period for the related Tranche and ending such number of days thereafter as the Agent shall select in consultation with the Seller; provided, however, that:

(i)any such Tranche Period (other than a Tranche Period consisting of one day) which would otherwise end on a day that is not a Business Day shall be extended to the next succeeding Business Day.

(ii)in the case of Tranche Periods of one day for any Tranche, (A) the initial Tranche Period shall be the date such Tranche Period commences as described in clause (a) above; and (B) any subsequently occurring Tranche Period which is one day shall, if the immediately preceding Tranche Period is more than one day, be the last day of such immediately preceding Tranche Period, and if the immediately preceding Tranche Period is one day, shall be the next day following such immediately preceding Tranche Period; and

A-15

(iii)any Tranche Period for any Tranche which commences before the Termination Date and would otherwise end on a date occurring after such Termination Date, such Tranche Period shall end on such Termination Date and the duration of each such Tranche Period which commences on or after the Termination Date for such Tranche shall be of such duration as shall be selected by the Agent.

“Transaction Documents” means this Agreement, the Fee Letter, the Purchase Agreement, the Subordinated Note and all other documents, instruments and agreements executed or furnished in connection herewith and therewith.

“Turnover Ratio” means an amount, expressed in days, obtained by multiplying (a) a fraction, (i) the numerator of which is equal to the Eligible Receivables Balance as of the last day of the most recent calendar month and (ii) the denominator of which is equal to Collections during such calendar month; times (b) 30.

“UCC” means, for any state, the Uniform Commercial Code as in effect in such state.

“USA” means the United States of America (including all states and political subdivisions thereof).

The foregoing definitions shall be equally applicable to both the singular and plural forms of the defined terms.  Unless otherwise inconsistent with the terms of this Agreement, all accounting terms used herein shall be interpreted, and all accounting determinations hereunder shall be made, in accordance with GAAP.  Unless otherwise specified, amounts to be calculated hereunder shall be continuously recalculated at the time any information relevant to such calculation changes.

A-16

Schedule 5.1(a)(viii)

Agreed-Upon Procedures Report

As soon as available and in any event within 180 days after the end of each year, commencing 2013, the Collection Agent shall cause a firm of nationally-recognized independent certified public accountants (who may also render other services to the Collection Agent or the Seller) to furnish an agreed upon procedures report to Agent to the effect that the independent certified public accountants have performed the agreed upon procedures enumerated below and based on such agreed upon procedures have disclosed any non-compliance.  It is recognized that modifications or clarifications to these procedures, or the descriptions of these procedures, may be necessary or desirable as the independent certified public accountants perform the work.  In the event the accountants seek clarification or interpretation of the procedures to be performed, such requests shall be submitted in writing to the Agent, who shall have sole responsibility and authority to provide clarifications or interpretations.

1.  The Agent shall choose four monthly Periodic Reports as presented by the Collection Agent during the related year.  For each of the monthly Periodic Reports thus chosen, the accountants shall perform the following:

(i) Agree the month-end aggregate outstanding balance of Receivables as reported in such Periodic Report to the applicable accounts receivable sub-ledger.

(ii) Agree the month-end outstanding balance of Receivables which did not constitute Eligible Receivables (by category of ineligibility as set forth in such Periodic Report) during such month as reported in such Periodic Report to applicable accounts receivable sub-ledger.

(iii) Agree the Collections for the related month as reported in such Periodic Report to Collection Agent’s records.

(iv) Agree the month-end outstanding balance of Delinquent Receivables as reported in such Periodic Report to Collection Agent’s records.

(v) Agree the month-end outstanding balance of Defaulted Receivables as reported in such Periodic Report to Collection Agent’s records.

(vi) Agree the month-end outstanding balance of the aggregate amount of Section 1.5(b) payments owed by the Seller as reported in such Periodic Report to Collection Agent’s records.

(vii) Agree the month-end Charge-offs as reported in such Periodic Report to Collection Agent’s records.

(viii) Agree the amount by which the outstanding balance of Receivables related to any single Obligor exceeds the Concentration Limit or its Special Limits reported in such Periodic Report to the applicable accounts receivable sub-ledger.

(ix) Recalculate the amount by which the outstanding balance of Receivables related to any single Obligor agreed in (viii) above exceeds the Concentration Limit or its Special Limit.

(x) Recompute the mathematical calculations of the Eligible Receivable Balance as set forth in such Periodic Report.

2.  The accountants shall judgmentally select twenty (20) Receivables from the accounts receivable sub-ledger maintained by the Collection Agent and agree the activity with respect to such Receivables in the Collection Agent’s records to the information reported for such Receivables in each of the four Periodic Reports selected.

A-2 

Exhibit A

to

Receivables Sale Agreement

Form of Incremental Purchase Request

____________, 201_

[                                                  ]

Re:  Receivables Sale Agreement dated as of May 31, 2012 (the “Sale Agreement”) among GMO Receivables Company, as Seller,

KCP&L Greater Missouri Operations Company, as Initial Collection Agent,

The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Agent,

and the Purchaser thereunder

Ladies and Gentlemen:

The undersigned Seller under the above-referenced Sale Agreement hereby confirms it has requested an Incremental Purchase of $___________ by the Purchaser under the Sale Agreement.

Attached hereto as Schedule I is information relating to the proposed Incremental Purchase required by the Sale Agreement.  If on the date of this Incremental Purchase Request (“Notice”), an Interim Liquidation is in effect, this Notice revokes our request for such Interim Liquidation so that Reinvestment Purchases shall immediately commence in accordance with Section 1.1(d) of the Sale Agreement.

The Seller hereby certifies that both before and after giving effect to the proposed Incremental Purchase contemplated hereby and the use of the proceeds therefrom, all of the requirements of Section 7.2 of the Sale Agreement have been satisfied.  

Very truly yours,

GMO Receivables Company

By

Title

Schedule I

to

Incremental Purchase Requests

Summary of Information Relating to Proposed Sale(s)

1.Dates, Amounts, Purchaser(s), Proposed Tranche Periods

A1 Date of Notice_________

A2 Proposed Purchase Dates____________________________________

(each of which is a

Business Day)

A3 Respective Proposed

Incremental Purchase on

each such Purchase Date

(each Incremental

Purchase must be in a

minimum amount of

$1,000,000 and multiples

thereof, or, if less, an

amount equal to the

Maximum Incremental

Purchase Amount)

Exhibit B

[Reserved]

Exhibit C

Form of Periodic Report

Exhibit D

Addresses and Names of Seller and Originator

1.Locations.  (a) The chief executive office of the Originator is located at the following address:

1200 Main Street

Kansas City, Missouri  64105

(b)The chief executive office of the Seller is:

2215-B Renaissance Drive

Renaissance Office Park

Las Vegas, Nevada 89119

(c)The following are all the locations where the Seller and the Originator directly or through its agents maintain any Records:

Same as (a) and (b) above

2.Names.  The following is a list of all names (including trade names or similar appellations) used by the Seller and the Originator or any of its divisions or other business units that generate Receivables:

KCP&L Greater Missouri Operations Company

KCP&L Greater Missouri Operations Company - L&P

KCP&L Greater Missouri Operations Company - MPS

KCP&L

KCP&L GMO

GMO

GMO Receivables Company

GMOREC

GMORC

Exhibit E

Significant Subsidiaries

MPS Merchant Services, Inc.

Trans MPS, Inc.

Exhibit F

Lock-Boxes and Collection Banks

Collection Bank
Wells Fargo Bank, National Association	420 Montgomery San Francisco, California  94104
UMB Bank, N.A.	1010 Grand Boulevard Kansas City, Missouri  64106

Lock-Boxes

UMB Retail Lockbox, PO Box 219703, Kansas City, MO 64121-9703

Other Accounts where Collections are received or deposited prior to transfer to Collection Account

UMB Bank, N.A.

Acct Name: KCP&L Greater Missouri Operations Company

ABA# 101-000-695

Acct# 98-717-39643

Wells Fargo Bank, National Association

 Acct Name: KCP&L Greater Missouri Operations Company

ABA# 121-000-248

Acct# 2000042932419, and

Acct# 2000041713529

Exhibit G

List of Designated Payees

Designated Payees with respect to Wells Fargo Bank, National Association shall mean:

1.	Global Express
2.	Obligors of Receivables who make payments directly to Wells Fargo Bank, National Association.
3.	Kansas City Power & Light Company

Designated Payees with respect to UMB Bank, N.A. shall mean:

1.	Obligors of Receivables who make payments direct to UMB Bank, N.A.
2.	Kansas City Power & Light Company

Exhibit H

To Receivables Sale Agreement

Compliance Certificate

To:The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Agent, and

the Purchaser

This Compliance Certificate is furnished pursuant to Section 5.1(a)(v) of the Receivables Sale Agreement, dated as of May 31, 2012 (as amended, supplemented or otherwise modified through the date hereof, the “Sale Agreement”), among GMO Receivables Company (the “Seller”), KCP&L Greater Missouri Operations Company (the “Initial Collection Agent”), Victory Receivables Corporation, as purchaser (the “Purchaser”) and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (in such capacity, the “Agent”).  Terms used in this Compliance Certificate and not otherwise defined herein shall have the respective meanings ascribed thereto in the Sale Agreement.

The undersigned hereby represents, warrants, certifies and confirms that:

1.The undersigned is a duly elected Designated Financial Officer of the undersigned.

2.Attached hereto is a copy of the financial statements described in Section 5.1(a)(i) or 5.1(a)(ii) of the Sale Agreement.

3.The undersigned confirms that the representations and warranties contained in Article IV of the Sale Agreement are true and correct as though made on the date hereof, except [those made as of a specific date, which are true and correct as of that date]*

The foregoing certifications and the financial statements delivered with this Compliance Certificate in support hereof, are made and delivered this ____ day of ___________, 20[__].

[Name of Seller or Originator]

By:

Designated Financial Officer

 

* Use for compliance certificates delivered after the Closing Date.

Exhibit I

Credit and Collection Policy

EX-12.1

													Exhibit 12.1
GREAT PLAINS ENERGY INCORPORATED
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
		Year to Date
		June 30
		2012		2011		2010		2009		2008			2007
		(millions)
Income (loss) from continuing operations		$	48.8	$	174.2	$	211.9	$	151.9	$	119.7		$	120.9
Add
Equity investment loss			0.1		0.1		1.0		0.4		1.3			2.0
	Income subtotal		48.9		174.3		212.9		152.3		121.0			122.9
Add
Income tax expense (benefit)			22.3		84.8		99.0		29.5		63.8			44.9
Kansas City earnings tax			-		-		0.1		0.4		0.3			0.5
	Total taxes on income		22.3		84.8		99.1		29.9		64.1			45.4
Interest on value of leased property			2.9		5.9		6.2		6.5		3.6			3.9
Interest on long-term debt			118.2		223.2		218.9		203.6		126.2			74.1
Interest on short-term debt			4.0		11.8		9.7		10.3		18.2			26.4
Other interest expense and amortization (a)			3.4		11.6		9.7		4.7		(1.4	)		5.8
	Total fixed charges		128.5		252.5		244.5		225.1		146.6			110.2
Earnings before taxes on
	income and fixed charges	$	199.7	$	511.6	$	556.5	$	407.3	$	331.7		$	278.5
Ratio of earnings to fixed charges			1.55		2.03		2.28		1.81		2.26			2.53
(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
		June 30
		2012		2011		2010		2009		2008		2007
		(millions)
Income from continuing operations		$	46.0	$	135.5	$	163.2	$	128.9	$	125.2	$	156.7
Add
Income tax expense (benefit)			19.7		69.1		81.6		46.9		59.8		59.3
Kansas City earnings tax			-		-		0.1		0.2		0.5		0.5
	Total taxes on income		19.7		69.1		81.7		47.1		60.3		59.8
Interest on value of leased property			2.7		5.4		5.7		6.0		3.3		3.9
Interest on long-term debt			61.7		118.5		117.9		110.4		79.3		54.5
Interest on short-term debt			2.1		5.1		3.9		5.3		15.2		20.3
Other interest expense and amortization (a)			1.4		5.8		4.2		0.3		1.4		6.8
	Total fixed charges		67.9		134.8		131.7		122.0		99.2		85.5
Earnings before taxes on
	income and fixed charges	$	133.6	$	339.4	$	376.6	$	298.0	$	284.7	$	302.0
Ratio of earnings to fixed charges			1.97		2.52		2.86		2.44		2.87		3.53
(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, Terry Bassham, 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:	August 8, 2012	/s/ Terry Bassham
		Terry Bassham Chief Executive Officer and President

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:	August 8, 2012	/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, Terry Bassham, 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:	August 8, 2012	/s/ Terry Bassham
		Terry Bassham Chief Executive Officer and President

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:	August 8, 2012	/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 June 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Terry Bassham, as Chief Executive Officer and President 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/ Terry Bassham
Name: Title:	Terry Bassham Chief Executive Officer and President
Date:	August 8, 2012
	/s/ James C. Shay
Name: Title:	James C. Shay Senior Vice President – Finance and Strategic Development and Chief Financial Officer
Date:	August 8, 2012

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 June 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Terry Bassham, as Chief Executive Officer and President 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/ Terry Bassham
Name: Title:	Terry Bassham Chief Executive Officer and President
Date:	August 8, 2012
	/s/ James C. Shay
Name: Title:	James C. Shay Senior Vice President - Finance and Strategic Development and Chief Financial Officer
Date:	August 8, 2012

XML

Nuclear Plant (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Investments in decommissioning trust fund [Line Items]
Cost Basis	$ 126.7		$ 126.7		$ 123.1
Gross Unrealized Gains	22.1		22.1		16.8
Gross Unrealized Losses	(3.9)		(3.9)		(4.6)
Fair Value, Nuclear decommissioning trust fund	144.9		144.9		135.3
Realized Gains on investments in decommissioning trust fund	0.2	0.7	0.7	0.8
Realized Losses on investments in decommissioning trust fund	(0.1)	(0.7)	(0.2)	(0.7)
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, beginning balance			135.3	129.2	129.2
Contributions to nuclear decommission trust fund			1.7		3.4
Nuclear decommissioning trust fund earned income, net of fees			1.4		4.8
Net realized gains (losses) on nuclear decommissioning trust fund			0.5		0.3
Net unrealized gains (losses) on nuclear decommissioning trust fund			6.0		(2.4)
Nuclear decommissioning trust fund, ending balance	144.9		144.9		135.3
Equity Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	77.9		77.9		76.5
Gross Unrealized Gains	17.2		17.2		12.3
Gross Unrealized Losses	(3.8)		(3.8)		(4.5)
Fair Value, Nuclear decommissioning trust fund	91.3		91.3		84.3
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, ending balance	91.3		91.3		84.3
Debt Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	46.0		46.0		44.2
Gross Unrealized Gains	4.9		4.9		4.5
Gross Unrealized Losses	(0.1)		(0.1)		(0.1)
Fair Value, Nuclear decommissioning trust fund	50.8		50.8		48.6
Weighted average maturity of debt securities	7		7
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, ending balance	50.8		50.8		48.6
Other Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	2.8		2.8		2.4
Gross Unrealized Gains	0		0		0
Gross Unrealized Losses	0		0		0
Fair Value, Nuclear decommissioning trust fund	2.8		2.8		2.4
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, ending balance	2.8		2.8		2.4
Kansas City Power and Light Company [Member]
Investments in decommissioning trust fund [Line Items]
Fair Value, Nuclear decommissioning trust fund	144.9		144.9		135.3
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, ending balance	$ 144.9		$ 144.9		$ 135.3

XML

Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Futures contracts [Member] | Cash Flow Hedging [Member]
Commodity Risk Management [Abstract]
Notional Contract Amount	$ 1.6	$ 2.0
Fair Value	(0.5)	(0.5)
Futures contracts [Member] | Not Designated as Hedging Instrument [Member]
Commodity Risk Management [Abstract]
Notional Contract Amount	16.2	23.6
Fair Value	(3.0)	(5.0)
Forward Contracts [Member] | Not Designated as Hedging Instrument [Member]
Commodity Risk Management [Abstract]
Notional Contract Amount	69.5	97.3
Fair Value	6.7	7.8
Option contracts [Member] | Not Designated as Hedging Instrument [Member]
Commodity Risk Management [Abstract]
Notional Contract Amount	0	0.4
Fair Value	0	0
Kansas City Power and Light Company [Member]
Commodity Risk Management [Abstract]
Percentage Of Projected Natural Gas Usage Hedged Current	100.00%
Percentage Of Projected Natural Gas Usage Hedged Year One	38.00%
Percentage Of Projected Natural Gas Usage Hedged Year Two	6.00%
Kansas City Power and Light Company [Member] | Futures contracts [Member] | Cash Flow Hedging [Member]
Commodity Risk Management [Abstract]
Notional Contract Amount	1.6	2.0
Fair Value	$ (0.5)	$ (0.5)
Kcpl Greater Missouri Operations Member
Commodity Risk Management [Abstract]
Percentage Of Expected On Peak Natural Gas And Natural Gas Equivalent Purchased Power Price Exposure Hedged Current	99.00%
Percentage Of Expected On Peak Natural Gas And Natural Gas Equivalent Purchased Power Price Exposure Hedged Year One	59.00%
Percentage Of Expected On Peak Natural Gas And Natural Gas Equivalent Purchased Power Price Exposure Hedged Year Two	8.00%

XML

Legal Proceedings (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Total Wolf Creek including KCPL [Member] | Positive Outcome of Litigation [Member] | Spent Nuclear Fuel and Radioactive Waste [Member]
Gain Contingencies [Line Items]
Amount of pending claims against the United States in the U.S. Court	$ 14.1
Amount awarded but subject to appeal	10.6
Additional amount awarded upon appeal	2.1
Kansas City Power and Light Company [Member] | Positive Outcome of Litigation [Member] | Spent Nuclear Fuel and Radioactive Waste [Member]
Gain Contingencies [Line Items]
Amount awarded but subject to appeal	5.0
Additional amount awarded upon appeal	1.0
Pending or Threatened Litigation [Member] | Kcpl Greater Missouri Operations 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

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Measurements [Abstract]

Fair value of assets and liabilities

						Fair Value Measurements Using
Description	June 30 2012		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Nuclear decommissioning trust (b)
Equity securities	$	91.3	$	-		$	91.3	$	-	$	-
Debt securities
U.S. Treasury		16.2		-			16.2		-		-
U.S. Agency		4.3		-			-		4.3		-
State and local obligations		2.7		-			-		2.7		-
Corporate bonds		26.9		-			-		26.9		-
Foreign governments		0.7		-			-		0.7		-
Other		0.5		-			-		0.5		-
Total nuclear decommissioning trust		142.6		-			107.5		35.1		-
Total		142.6		-			107.5		35.1		-
Liabilities
Derivative instruments (a)		-		(0.5	)		0.5		-		-
Total	$	-	$	(0.5	)	$	0.5	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	6.7	$	-		$	-	$	4.5	$	2.2
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		0.1		-			-		0.1		-
Total SERP rabbi trust		0.3		-			0.2		0.1		-
Total		7.0		-			0.2		4.6		2.2
Liabilities
Derivative instruments (a)		-		(3.0	)		3.0		-		-
Total	$	-	$	(3.0	)	$	3.0	$	-	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	6.7	$	-		$	-	$	4.5	$	2.2
Nuclear decommissioning trust (b)		142.6		-			107.5		35.1		-
SERP rabbi trust (c)		0.3		-			0.2		0.1		-
Total		149.6		-			107.7		39.7		2.2
Liabilities
Derivative instruments (a)		-		(3.5	)		3.5		-		-
Total	$	-	$	(3.5	)	$	3.5	$	-	$	-

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

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

(b)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $2.3 million and $3.0 million at June 30, 2012, and December 31, 2011, 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 $20.2 million and $20.3 million at June 30, 2012, and December 31, 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)   Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty.  At June 30, 2012, and December 31, 2011, Great Plains Energy netted $3.4 million and $5.5 million, respectively, of cash collateral posted with counterparties.

Unobservable inputs reconciliation

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative
	Instruments
	(millions)
Balance at April 1	$	2.4		$	5.7
Total realized/unrealized gains
included in non-operating income		0.9			2.1
Settlements		(1.1	)		(2.9	)
Balance at June 30	$	2.2		$	4.9
Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at June 30	$	(0.1	)	$	(0.6	)

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative
	Instruments
	(millions)
Balance at January 1	$	3.1		$	3.7
Total realized/unrealized gains
included in non-operating income		1.1			7.1
Settlements		(2.0	)		(5.9	)
Balance at June 30	$	2.2		$	4.9
Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at June 30	$	(0.7	)	$	1.5

XML

Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2012

Supplemental Cash Flow Elements [Abstract]

Supplemental cash flow information

Great Plains Energy Other Operating Activities
Year to Date June 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	27.3		$	(14.1	)
Accounts receivable pledged as collateral		(67.0	)		-
Fuel inventories		(13.7	)		3.2
Materials and supplies		(5.7	)		(3.1	)
Accounts payable		(53.7	)		(67.2	)
Accrued taxes		33.8			33.6
Accrued interest		(3.6	)		(4.5	)
Deferred refueling outage costs		9.0			(31.0	)
Fuel adjustment clauses		10.5			(11.0	)
Pension and post-retirement benefit obligations		13.5			7.2
Allowance for equity funds used during construction		(0.1	)		(0.3	)
Interest rate hedge settlements		-			(26.1	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		-			2.3
Uncertain tax positions		(0.3	)		(19.6	)
Other		(12.8	)		(26.8	)
Total other operating activities	$	(62.8	)	$	(157.4	)
Cash paid during the period:
Interest	$	130.5		$	138.4
Income taxes	$	3.3		$	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	48.9		$	31.5

KCP&L Other Operating Activities
Year to Date June 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	13.8		$	(9.7	)
Accounts receivable pledged as collateral		(11.0	)		-
Fuel inventories		(12.7	)		(4.1	)
Materials and supplies		(4.5	)		(3.3	)
Accounts payable		(36.5	)		(47.1	)
Accrued taxes		25.2			30.6
Accrued interest		(3.5	)		(3.0	)
Deferred refueling outage costs		9.0			(31.0	)
Pension and post-retirement benefit obligations		14.9			14.1
Kansas Energy Cost Adjustment		(4.4	)		(10.8	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		-			1.5
Uncertain tax positions		0.1			(11.8	)
Other		(16.5	)		(20.5	)
Total other operating activities	$	(26.1	)	$	(95.1	)
Cash paid during the period:
Interest	$	61.3		$	62.2
Income taxes	$	-		$	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	44.3		$	22.4

XML

Derivative Instruments, Group 2 (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012 Kansas City Power and Light Company [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Derivative Instrument, Current and Noncurrent [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Derivative Instrument, Current and Noncurrent [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Derivative Instrument, Current and Noncurrent [Member] Kansas City Power and Light Company [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Derivative Instrument, Current and Noncurrent [Member] Kansas City Power and Light Company [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Current assets [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Current assets [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Current assets [Member] Kansas City Power and Light Company [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Current assets [Member] Kansas City Power and Light Company [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Current liabilities [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Current liabilities [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Current liabilities [Member] Kansas City Power and Light Company [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Current liabilities [Member] Kansas City Power and Light Company [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Noncurrent liabilities [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Noncurrent liabilities [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Noncurrent liabilities [Member] Kansas City Power and Light Company [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Noncurrent liabilities [Member] Kansas City Power and Light Company [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Deferred income taxes [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Deferred income taxes [Member]	Jun. 30, 2012 Cash Flow Hedging [Member] Deferred income taxes [Member] Kansas City Power and Light Company [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Deferred income taxes [Member] Kansas City Power and Light Company [Member]	Jun. 30, 2012 Commodity Contract [Member] Designated as Hedging Instrument [Member] Derivative Instrument, Current and Noncurrent [Member]	Dec. 31, 2011 Commodity Contract [Member] Designated as Hedging Instrument [Member] Derivative Instrument, Current and Noncurrent [Member]	Jun. 30, 2012 Commodity Contract [Member] Designated as Hedging Instrument [Member] Derivative Instrument, Current and Noncurrent [Member] Kansas City Power and Light Company [Member]	Dec. 31, 2011 Commodity Contract [Member] Designated as Hedging Instrument [Member] Derivative Instrument, Current and Noncurrent [Member] Kansas City Power and Light Company [Member]	Jun. 30, 2012 Commodity Contract [Member] Not Designated as Hedging Instrument [Member] Derivative Instrument, Current and Noncurrent [Member]	Dec. 31, 2011 Commodity Contract [Member] Not Designated as Hedging Instrument [Member] Derivative Instrument, Current and Noncurrent [Member]	Jun. 30, 2012 Total Derivatives [Member] Derivative Instrument, Current and Noncurrent [Member]	Dec. 31, 2011 Total Derivatives [Member] Derivative Instrument, Current and Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral																							$ 0	$ 0	$ 0	$ 0	$ 6.7	$ 7.8	$ 6.7	$ 7.8
Derivative liability, fair value, amount not offset against collateral																							0.5	0.5	0.5	0.5	3.0	5.0	3.5	5.5
Recorded amounts included in accumulated other comprehensive income			(41.8)	(47.9)	(28.8)	(31.4)	10.9	11.3	10.9	11.3	(79.1)	(89.5)	(57.8)	(62.5)	(0.3)	(0.2)	(0.3)	(0.2)	26.7	30.5	18.4	20.0
Derivative [Line Items]
Accumulated other comprehensive income that is expected to be reclassified in the next twelve months	$ 20.6	$ 9.1

XML

Equity Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 1.8		$ 1.7		$ 2.8		$ 3.3
Income tax benefits	0.7		0.8		1.3		1.4
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility (in hundredths)					21.00%
Expected dividend yield (in hundredths)					4.32%
Risk-free interest rates (in hundredths)					0.40%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Beginning balance (in shares)					442,042
Performance adjustment (in shares)					(160,717)
Granted (in shares)					161,627
Forfeited (in shares)					(50,685)
Ending balance (in shares)	392,267				392,267
Granted and issued (in shares)					161,627
Weighted average beginning balance (in dollars per share)					$ 21.06	[1]
Weighted average granted (in dollars per share)	$ 20.99	[1]	$ 26.28	[1]	$ 19.01	[1]	$ 22.48	[1]
Weighted average forfeited (in dollars per share)	$ 18.71	[1]			$ 18.71	[1]
Weighted average ending balance (in dollars per share)	$ 22.98	[1]			$ 22.98	[1]
Weighted average granted and issued (in dollars per share)	$ 20.99	[1]	$ 26.28	[1]	$ 19.01	[1]	$ 22.48	[1]
Remaining weighted-average contractual term (in years)					1.4
Weighted-average grant-date fair value of shares granted (in dollars per share)	$ 20.99	[1]	$ 26.28	[1]	$ 19.01	[1]	$ 22.48	[1]
Fair value of performance shares earned and paid							0.8
Total unrecognized compensation expense	3.8				3.8
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Beginning balance (in shares)					386,183
Granted (in shares)					162,129
Forfeited (in shares)					(50,685)
Ending balance (in shares)	292,789				292,789
Granted and issued (in shares)					162,129
Vested (in shares)					(204,838)
Weighted average beginning balance (in dollars per share)					$ 17.06	[1]
Weighted average granted (in dollars per share)	$ 19.89	[1]	$ 20.26	[1]	$ 19.69	[1]	$ 19.26	[1]
Weighted average forfeited (in dollars per share)	$ 19.66	[1]			$ 19.66	[1]
Weighted average ending balance (in dollars per share)	$ 18.97	[1]			$ 18.97	[1]
Total fair value of shares vested	1.3		0.6		3.2		2.6
Weighted average granted and issued (in dollars per share)	$ 19.89	[1]	$ 20.26	[1]	$ 19.69	[1]	$ 19.26	[1]
Remaining weighted-average contractual term (in years)					2.0
Weighted-average grant-date fair value of shares granted (in dollars per share)	$ 19.89	[1]	$ 20.26	[1]	$ 19.69	[1]	$ 19.26	[1]
Weighted average vested (in dollars per share)					$ 15.76	[1]
Total unrecognized compensation expense	3.4				3.4
Kansas City Power and Light Company [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	1.4		1.2		2.1		2.3
Income tax benefits	$ 0.5		$ 0.6		$ 1.0		$ 1.0

[1] weighted-average

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Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Cash flows affected by changes in:
Receivables	$ 27.3	$ (14.1)
Accounts receivable pledged as collateral	(67.0)	0
Fuel inventories	(13.7)	3.2
Materials and supplies	(5.7)	(3.1)
Accounts payable	(53.7)	(67.2)
Accrued taxes	33.8	33.6
Accrued interest	(3.6)	(4.5)
Deferred refueling outage costs	9.0	(31.0)
Fuel adjustment clauses	10.5	(11.0)
Pension and post-retirement benefit obligations	13.5	7.2
Allowance for equity funds used during construction	(0.1)	(0.3)
Forward starting swaps settlement	0	(26.1)
Iatan Nos. 1 and 2 impact of disallowed construction costs	0	2.3
Uncertain tax positions	(0.3)	(19.6)
Other Operating Activities, Cash Flow Statement	(12.8)	(26.8)
Total other operating activities	(62.8)	(157.4)
Cash paid during the period:
Interest Paid, Net	130.5	138.4
Income Taxes Paid	3.3	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	48.9	31.5
Kansas City Power and Light Company [Member]
Cash flows affected by changes in:
Receivables	13.8	(9.7)
Accounts receivable pledged as collateral	(11.0)	0
Fuel inventories	(12.7)	(4.1)
Materials and supplies	(4.5)	(3.3)
Accounts payable	(36.5)	(47.1)
Accrued taxes	25.2	30.6
Accrued interest	(3.5)	(3.0)
Deferred refueling outage costs	9.0	(31.0)
Fuel adjustment clauses	(4.4)	(10.8)
Pension and post-retirement benefit obligations	14.9	14.1
Iatan Nos. 1 and 2 impact of disallowed construction costs	0	1.5
Uncertain tax positions	0.1	(11.8)
Other Operating Activities, Cash Flow Statement	(16.5)	(20.5)
Total other operating activities	(26.1)	(95.1)
Cash paid during the period:
Interest Paid, Net	61.3	62.2
Income Taxes Paid	0	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$ 44.3	$ 22.4

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Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Current income taxes [Abstract]
Federal	$ (3.3)	$ 2.7	$ (3.3)	$ 3.8
State	0.4	(4.7)	0.3	(4.0)
Foreign	0	(0.1)	0	(0.4)
Current Income Tax Expense (Benefit), Total	(2.9)	(2.1)	(3.0)	(0.6)
Deferred income taxes [Abstract]
Federal	30.8	32.3	22.5	28.9
State	5.1	11.4	4.3	7.4
Deferred Income Tax Expense (Benefit), Total	35.9	43.7	26.8	36.3
Noncurrent income taxes [Abstract]
Federal	(0.2)	(19.0)	(0.2)	(18.0)
State	0	(2.0)	0	(1.9)
Foreign	(0.4)	(0.1)	(0.1)	0.2
Noncurrent Income Tax Expense (Benefit), Total	(0.6)	(21.1)	(0.3)	(19.7)
Investment tax credit [Abstract]
Amortization	(0.6)	(0.7)	(1.2)	(0.8)
Total income tax expense	31.8	19.8	22.3	15.2
Reconciliation of income tax expense [Abstract]
Federal statutory income tax	31.5	22.1	25.0	21.4
Differences between book and tax depreciation not normalized	1.0	1.1	2.1	1.9
Amortization of investment tax credits	(0.6)	(0.7)	(1.2)	(0.8)
Federal income tax credits	(3.3)	(3.8)	(6.1)	(6.8)
State income taxes	3.5	2.6	2.9	3.0
Changes in uncertain tax positions, net	(0.3)	(1.6)	(0.1)	(1.3)
Valuation allowance	0.1	0.2	0.1	(2.2)
Income Tax Reconciliation, Other Adjustments	(0.1)	(0.1)	(0.4)	0
Income Tax Expense (Benefit)	31.8	19.8	22.3	15.2
Reconciliation of income tax rate [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%	1.60%	3.00%	3.00%
Amortization of investment tax credits (in hundredths)	(0.70%)	(1.10%)	(1.80%)	(1.40%)
Federal income tax credits (in hundredths)	(3.60%)	(6.00%)	(8.60%)	(11.10%)
State income taxes (in hundredths)	3.90%	4.10%	4.10%	4.90%
Changes in uncertain tax positions, net (in hundredths)	(0.40%)	(2.50%)	(0.10%)	(2.20%)
Valuation allowance (in hundredths)	0.10%	0.30%	0.10%	(3.60%)
Effective Income Tax Rate Reconciliation, Other Adjustments	0.00%	0.00%	(0.40%)	0.40%
Effective Income Tax Rate, Continuing Operations, Total	35.50%	31.40%	31.30%	25.00%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period			24.0	42.0	42.0
Additions for current year tax positions			1.5		1.4
Additions for prior year tax positions			0		2.4
Reductions for prior year tax positions			(1.4)		(20.9)
Statute expirations			0		(0.7)
Foreign currency translation adjustments			(0.1)		(0.2)
Balance at end of period	24.0		24.0		24.0
Uncertain Tax Positions [Abstract]
Amount expected to impact the effective tax rate if recognized	11.7		11.7		11.8
Accrued interest related to unrecognized tax benefits	6.1		6.1		5.7
Accrued penalties with respect to unrecognized tax benefits	1.1		1.1		1.1
Amount of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities	9.3		9.3
Kansas City Power and Light Company [Member]
Current income taxes [Abstract]
Federal	0.1	1.3	0.2	2.4
State	0.1	0.2	0.1	0.5
Current Income Tax Expense (Benefit), Total	0.2	1.5	0.3	2.9
Deferred income taxes [Abstract]
Federal	19.4	23.2	16.1	19.9
State	4.2	4.7	4.1	4.5
Deferred Income Tax Expense (Benefit), Total	23.6	27.9	20.2	24.4
Noncurrent income taxes [Abstract]
Federal	(0.3)	(11.5)	0.1	(10.6)
State	(0.1)	(1.2)	0	(1.1)
Noncurrent Income Tax Expense (Benefit), Total	(0.4)	(12.7)	0.1	(11.7)
Investment tax credit [Abstract]
Amortization	(0.4)	(0.5)	(0.9)	(0.5)
Total income tax expense	23.0	16.2	19.7	15.1
Reconciliation of income tax expense [Abstract]
Federal statutory income tax	23.4	17.4	23.0	18.4
Differences between book and tax depreciation not normalized	0.9	0.8	1.8	1.6
Amortization of investment tax credits	(0.4)	(0.5)	(0.9)	(0.5)
Federal income tax credits	(3.3)	(3.7)	(6.1)	(6.7)
State income taxes	2.6	1.8	2.6	2.0
Changes in uncertain tax positions, net	0	0.4	0	0.4
Income Tax Reconciliation, Other Adjustments	(0.2)	0	(0.7)	(0.1)
Income Tax Expense (Benefit)	23.0	16.2	19.7	15.1
Reconciliation of income tax rate [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)	1.30%	1.60%	2.70%	3.00%
Amortization of investment tax credits (in hundredths)	(0.70%)	(1.00%)	(1.40%)	(0.90%)
Federal income tax credits (in hundredths)	(4.90%)	(7.60%)	(9.30%)	(12.90%)
State income taxes (in hundredths)	4.00%	3.80%	4.10%	3.90%
Changes in uncertain tax positions, net (in hundredths)	0.00%	0.90%	0.00%	0.80%
Effective Income Tax Rate Reconciliation, Other Adjustments	(0.20%)	(0.20%)	(1.10%)	(0.30%)
Effective Income Tax Rate, Continuing Operations, Total	34.50%	32.50%	30.00%	28.60%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period			8.7	19.1	19.1
Additions for current year tax positions			1.4		0
Additions for prior year tax positions			0		2.3
Reductions for prior year tax positions			(1.3)		(12.6)
Statute expirations			0		(0.1)
Foreign currency translation adjustments			0		0
Balance at end of period	8.8		8.8		8.7
Uncertain Tax Positions [Abstract]
Amount expected to impact the effective tax rate if recognized	0.2		0.2		0.2
Amount of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities	$ 4.1		$ 4.1

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Related Party Transactions and Relationships (Details) (Kansas City Power and Light Company [Member], USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 Kcpl Greater Missouri Operations Member	Dec. 31, 2011 Kcpl Greater Missouri Operations Member	Jun. 30, 2012 Great Plains Energy [Member]	Dec. 31, 2011 Great Plains Energy [Member]
Related Party Transaction [Line Items]
Receivable from Related Party						$ 24.1	$ 8.8	$ 9.5
Payable to Related Party					(246.6)
KCP and L employees manage GMO's business and operate its facilities at cost.	26.7	27.7	52.9	57.2
Money Pool Payable					$ 256.9

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Receivables

6 Months Ended

Jun. 30, 2012

Receivables [Abstract]

Receivables

3.   RECEIVABLES

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

	June 30			December 31
	2012			2011
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	4.2		$	69.8
Customer accounts receivable - unbilled		120.1			82.4
Allowance for doubtful accounts		(3.5	)		(2.5	)
Other receivables		85.3			81.5
Total	$	206.1		$	231.2
KCP&L
Customer accounts receivable - billed	$	-		$	16.4
Customer accounts receivable - unbilled		74.6			50.0
Allowance for doubtful accounts		(2.0	)		(1.4	)
Intercompany receivables		13.4			38.7
Other receivables		74.8			69.2
Total	$	160.8		$	172.9

Great Plains Energy’s and KCP&L’s other receivables at June 30, 2012, and December 31, 2011, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables.

Sale of Accounts Receivable – KCP&L and GMO

KCP&L sells all of its retail electric accounts receivable to its wholly owned subsidiary, KCP&L Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor.  On May 31, 2012, GMO entered into an agreement to sell all of its retail electric and steam service accounts receivable to its wholly owned subsidiary, GMO Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation.

Each of KCP&L Receivables Company’s and GMO Receivables Company’s sale of the undivided percentage ownership interest in accounts receivable to Victory Receivables Corporation is accounted for as a secured borrowing with accounts receivable pledged as collateral and a corresponding short-term collateralized note payable recognized on the balance sheets.  At June 30, 2012, and December 31, 2011, Great Plains Energy’s accounts receivable pledged as collateral and the corresponding short-term collateralized note payable was $162.0 million and $95.0 million, respectively.  At June 30, 2012, and December 31, 2011, KCP&L’s accounts receivable pledged as collateral and the corresponding short-term collateralized note payable was $106.0 million and $95.0 million, respectively.

KCP&L and GMO each sell their receivables at a fixed price based upon the expected cost of funds and charge-offs.  These costs comprise KCP&L’s and GMO’s loss on the sale of accounts receivable.  KCP&L and GMO service the receivables and receive annual servicing fees of 1.5% and 1.25%, respectively, of the outstanding principal amount of the receivables sold to KCP&L Receivables Company and GMO Receivables Company.  KCP&L and GMO do not recognize a servicing asset or liability because management determined the collection agent fees earned by KCP&L and GMO approximate market value.  KCP&L’s agreement expires in September 2014 and allows for $110 million in aggregate outstanding principal amount at any time.  GMO’s agreement expires in September 2014 and allows for $80 million in aggregate outstanding principal during the period of June 1 through October 31 and $65 million in aggregate outstanding principal during the period of November 1 through May 31 of each year. 

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

				KCP&L									GMO			Consolidated
				Receivables			Consolidated						Receivables			Great Plains
Three Months Ended June 30, 2012	KCP&L			Company			KCP&L			GMO			Company			Energy
	(millions)
Receivables (sold) purchased	$	(368.6	)	$	368.6		$	-		$	(91.7	)	$	91.7		$	-
Gain (loss) on sale of accounts receivable (a)		(4.7	)		4.0			(0.7	)		(1.2	)		0.8			(1.1	)
Servicing fees received (paid)		0.6			(0.6	)		-			0.1			(0.1	)		-
Fees paid to outside investor		-			(0.3	)		(0.3	)		-			(0.1	)		(0.4	)
Cash from customers (transferred) received		(319.4	)		319.4			-			(64.7	)		64.7			-
Cash received from (paid for) receivables
purchased		315.3			(315.3	)		-			63.9			(63.9	)		-

				KCP&L									GMO			Consolidated
				Receivables			Consolidated						Receivables			Great Plains
Year to Date June 30, 2012	KCP&L			Company			KCP&L			GMO			Company			Energy
	(millions)
Receivables (sold) purchased	$	(662.1	)	$	662.1		$	-		$	(91.7	)	$	91.7		$	-
Gain (loss) on sale of accounts receivable (a)		(8.4	)		8.1			(0.3	)		(1.2	)		0.8			(0.7	)
Servicing fees received (paid)		1.1			(1.1	)		-			0.1			(0.1	)		-
Fees paid to outside investor		-			(0.6	)		(0.6	)		-			(0.1	)		(0.7	)
Cash from customers (transferred) received		(646.6	)		646.6			-			(64.7	)		64.7			-
Cash received from (paid for) receivables
purchased		638.4			(638.4	)		-			63.9			(63.9	)		-
Interest on intercompany note received (paid)		0.1			(0.1	)		-			-			-			-

	Three Months Ended June 30, 2011									Year to Date June 30, 2011
				KCP&L									KCP&L
				Receivables			Consolidated						Receivables			Consolidated
	KCP&L			Company			KCP&L			KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(347.7	)	$	347.7		$	-		$	(639.6	)	$	639.6		$	-
Gain (loss) on sale of accounts receivable (a)		(4.4	)		3.9			(0.5	)		(8.1	)		7.8			(0.3	)
Servicing fees received (paid)		0.5			(0.5	)		-			1.1			(1.1	)		-
Fees paid to outside investor		-			(0.3	)		(0.3	)		-			(0.6	)		(0.6	)
Cash from customers (transferred) received		(309.9	)		309.9			-			(618.2	)		618.2			-
Cash received from (paid for) receivables
purchased		306.0			(306.0	)		-			610.4			(610.4	)		-
Interest on intercompany note received (paid)		0.1			(0.1	)		-			0.2			(0.2	)		-
(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.

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Short-term Borrowings and Short-term Bank Lines of Credit (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Dec. 31, 2011
Short-term Debt [Line Items]
Amount of outstanding cash borrowings	$ 31.0	$ 22.0
Commercial paper outstanding	91.0	267.0
Parent Company [Member]
Short-term Debt [Line Items]
Amount of revolving credit facility	200.0
Revolving credit facility expiration date	2016-12-01
Covenant term - amount considered in default	50.0
Amount of outstanding cash borrowings	31.0	22.0
Weighted-average interest rate from outstanding borrowings	2.00%	2.06%
Amount of letters of credit outstanding	4.8	11.6
Covenant Term Ratio of Consolidated Indebtedness to Consolidated Capitalization Ratio, Maximum	0.65
Line of Credit Facility, Covenant Compliance	in compliance
Kansas City Power and Light Company [Member]
Short-term Debt [Line Items]
Amount of revolving credit facility	600.0
Revolving credit facility expiration date	2016-12-01
Covenant term - amount considered in default	50.0
Amount of outstanding cash borrowings	0	0
Commercial paper outstanding	91.0	227.0
Weighted-average interest rate from outstanding borrowings	0.46%	0.50%
Amount of letters of credit outstanding	18.2	21.5
Covenant Term Ratio of Consolidated Indebtedness to Consolidated Capitalization Ratio, Maximum	0.65
Line of Credit Facility, Covenant Compliance	in compliance
Kcpl Greater Missouri Operations Member
Short-term Debt [Line Items]
Amount of revolving credit facility	450.0
Revolving credit facility expiration date	2016-12-01
Covenant term - amount considered in default	50.0
Amount of outstanding cash borrowings	0	0
Commercial paper outstanding	0	40.0
Weighted-average interest rate from outstanding borrowings		0.88%
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, Covenant Compliance	in compliance

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Equity Compensation (Tables)

6 Months Ended

Jun. 30, 2012

Equity Compensation [Abstract]

Equity compensation expense and associated income tax benefits

	Three Months Ended				Year to Date
	June 30				June 30
	2012		2011		2012		2011
Great Plains Energy	(millions)
Compensation expense	$	1.8	$	1.7	$	2.8	$	3.3
Income tax benefit		0.7		0.8		1.3		1.4
KCP&L
Compensation expense	$	1.4	$	1.2	$	2.1	$	2.3
Income tax benefit		0.5		0.6		1.0		1.0

Performance share activity

	Performance			Grant Date
	Shares			Fair Value*
Beginning balance		442,042		$	21.06
Granted		161,627			19.01
Forfeited		(50,685	)		18.71
Performance adjustment		(160,717	)
Ending balance		392,267			22.98
* weighted-average

Restricted stock activity

	Nonvested			Grant Date
	Restricted Stock			Fair Value*
Beginning balance		386,183		$	17.06
Granted and issued		162,129			19.69
Vested		(204,838	)		15.76
Forfeited		(50,685	)		19.66
Ending balance		292,789			18.97
* weighted-average

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Pension Plans and Other Employee Benefits (Tables)

6 Months Ended

Jun. 30, 2012

Pension Plans and Other Employee Benefits [Abstract]

Components of net periodic benefit costs

	Pension Benefits						Other Benefits
Three Months Ended June 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	8.8		$	7.8		$	0.8		$	0.8
Interest cost		12.3			12.6			2.0			1.9
Expected return on plan assets		(10.7	)		(9.7	)		(0.4	)		(0.5	)
Prior service cost		1.1			1.2			1.8			1.8
Recognized net actuarial (gain) loss		11.2			9.5			-			(0.2	)
Transition obligation		-			-			0.2			0.4
Settlement charge		-			0.2			-			-
Net periodic benefit costs before
regulatory adjustment		22.7			21.6			4.4			4.2
Regulatory adjustment		(3.8	)		(5.9	)		0.3			0.1
Net periodic benefit costs	$	18.9		$	15.7		$	4.7		$	4.3

	Pension Benefits						Other Benefits
Year to Date June 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	17.7		$	15.6		$	1.6		$	1.6
Interest cost		24.5			25.1			3.9			3.9
Expected return on plan assets		(21.4	)		(19.3	)		(0.9	)		(0.9	)
Prior service cost		2.2			2.3			3.6			3.6
Recognized net actuarial (gain) loss		22.3			19.2			-			(0.3	)
Transition obligation		-			-			0.5			0.7
Settlement charge		-			0.2			-			-
Net periodic benefit costs before
regulatory adjustment		45.3			43.1			8.7			8.6
Regulatory adjustment		(7.7	)		(12.3	)		0.7			0.3
Net periodic benefit costs	$	37.6		$	30.8		$	9.4		$	8.9

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Long-Term Debt (Details) (USD $)	6 Months Ended
	Jun. 30, 2012		Dec. 31, 2011
Debt Instrument [Line Items]
Current maturities	$ 507,100,000		$ 801,400,000
Long-term debt excluding current maturities	3,013,400,000	[1]	2,742,300,000	[1]
Long-term debt detail [Abstract]
Subordinated Notes Successfully Remarketed	287,400,000
Purchase Contracts Settled Early	100,000
Number of outstanding Equity Units at settlement (in millions of units)	5,700,000
Number of common shares issued in settlement of purchase contracts (in millions of shares)	17,100,000
Settlement rate (in shares)	2.9762
Applicable market value (in dollars per share)	$ 20.05
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair value of financial instruments [Abstract}
Long-term debt	3,500,000,000		3,500,000,000
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair value of financial instruments [Abstract}
Long-term debt	3,900,000,000		3,900,000,000
Kansas City Power and Light Company [Member]
Debt Instrument [Line Items]
Current maturities	400,000		12,700,000
Unamortized discount	(4,000,000)		(4,200,000)
Long-term debt excluding current maturities	1,902,000,000	[1]	1,901,900,000	[1]
Kansas City Power and Light Company [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair value of financial instruments [Abstract}
Long-term debt	1,900,000,000		1,900,000,000
Kansas City Power and Light Company [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair value of financial instruments [Abstract}
Long-term debt	2,200,000,000		2,200,000,000
Kansas City Power and Light Company [Member] | Corporate Debt Securities [Member] | Senior notes due 2018 KCPL [Member]
Debt Instrument [Line Items]
Principal outstanding	350,000,000		350,000,000
Year due	2018
Interest rates (in hundredths)	6.375%
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	7.49%	[2]
Kansas City Power and Light Company [Member] | Corporate Debt Securities [Member] | Senior notes due 2035 KCPL [Member]
Debt Instrument [Line Items]
Principal outstanding	250,000,000		250,000,000
Year due	2035
Interest rates (in hundredths)	6.05%
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	5.78%	[2]
Kansas City Power and Light Company [Member] | Corporate Debt Securities [Member] | Senior notes due 2017 KCPL [Member]
Debt Instrument [Line Items]
Principal outstanding	250,000,000		250,000,000
Year due	2017
Interest rates (in hundredths)	5.85%
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	5.72%	[2]
Kansas City Power and Light Company [Member] | Corporate Debt Securities [Member] | Senior Notes Due 2041 KCPL [Member]
Debt Instrument [Line Items]
Principal outstanding	400,000,000		400,000,000
Year due	2041
Interest rates (in hundredths)	5.30%
Kansas City Power and Light Company [Member] | Other Long-Term Debt [Member]
Debt Instrument [Line Items]
Principal outstanding	2,900,000		2,900,000
Debt Instrument Maturity Date Range Start	2012
Debt Instrument Maturity Date Range End	2018
Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds EIRR due 2015-2035 [Member]
Debt Instrument [Line Items]
Principal outstanding	106,900,000		119,300,000
Debt Instrument Maturity Date Range Start	2015
Debt Instrument Maturity Date Range End	2035
Weighted-average interest rates (in hundredths)	4.97%	[3]
Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds Series 2009 due 2019 [Member]
Debt Instrument [Line Items]
Principal outstanding	400,000,000		400,000,000
Year due	2019
Interest rates (in hundredths)	7.15%
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	8.59%	[2]
Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds EIRR series 2005 due 2035 [Member]
Debt Instrument [Line Items]
Principal outstanding	50,000,000		50,000,000
Year due	2035
Interest rates (in hundredths)	4.65%
Kansas City Power and Light Company [Member] | Secured Debt [Member] | General Mortgage bonds EIRR series 2007B due 2035 [Member]
Debt Instrument [Line Items]
Principal outstanding	73,200,000		73,200,000
Year due	2035
Interest rates (in hundredths)	5.375%
Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | General Mortgage bonds EIRR series 2007A-2 due 2035 [Member]
Debt Instrument [Line Items]
Bonds purchased in lieu of redemption	10,000,000		10,000,000
Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | General Mortgage bonds Series 2007A-1 due 2035 [Member]
Debt Instrument [Line Items]
Bonds purchased in lieu of redemption	63,300,000		63,300,000
Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | 1993 B EIRR Bonds [Member]
Debt Instrument [Line Items]
Bonds purchased in lieu of redemption	39,500,000		39,500,000
Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | EIRR bonds 4.90 percent Series 2008
Debt Instrument [Line Items]
Principal outstanding	23,400,000		23,400,000
Year due	2038
Interest rates (in hundredths)	4.90%
Other Great Plains [Member]
Debt Instrument [Line Items]
Current maturities	(506,700,000)		(788,700,000)
Unamortized discount	5,700,000		(700,000)
Other Great Plains [Member] | GMO First Mortgage Bonds [Member] | First mortgage bonds due 2013-2021 [Member]
Debt Instrument [Line Items]
Principal outstanding	10,100,000		11,200,000
Debt Instrument Maturity Date Range Start	2013
Debt Instrument Maturity Date Range End	2021
Interest rates (in hundredths)	9.44%
Other Great Plains [Member] | GMO Medium Term Notes [Member] | Medium term notes 7.17 percent series due 2023 [Member]
Debt Instrument [Line Items]
Principal outstanding	7,000,000		7,000,000
Year due	2023
Interest rates (in hundredths)	7.17%
Other Great Plains [Member] | GMO Medium Term Notes [Member] | Medium term notes 7.33 percent series due 2023 [Member]
Debt Instrument [Line Items]
Principal outstanding	3,000,000		3,000,000
Year due	2023
Interest rates (in hundredths)	7.33%
Other Great Plains [Member] | GMO Medium Term Notes [Member] | Medium term notes 7.16 percent series due 2013 [Member]
Debt Instrument [Line Items]
Principal outstanding	6,000,000		6,000,000
Year due	2013
Interest rates (in hundredths)	7.16%
Other Great Plains [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds SJLP due 2013 [Member]
Debt Instrument [Line Items]
Principal outstanding	5,600,000		5,600,000
Year due	2013
Interest rates (in hundredths)	5.85%
Other Great Plains [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds Wamego Series 1996 due 2026 [Member]
Debt Instrument [Line Items]
Principal outstanding	7,300,000		7,300,000
Year due	2026
Variable rate (in hundredths)	0.341%	[4]
Other Great Plains [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds state environmental 1993 due 2028 [Member]
Debt Instrument [Line Items]
Principal outstanding	5,000,000		5,000,000
Year due	2028
Variable rate (in hundredths)	0.341%	[4]
Other Great Plains [Member] | GMO Senior Notes [Member] | Senior notes 11.875 percent series due 2012 [Member]
Debt Instrument [Line Items]
Principal outstanding	500,000,000		500,000,000
Year due	2012
Interest rates (in hundredths)	11.875%
Other Great Plains [Member] | GMO Senior Notes [Member] | Fair value adjustment [Member]
Debt Instrument [Line Items]
Principal outstanding	0		16,300,000
Other Great Plains [Member] | GMO Senior Notes [Member] | Senior notes 8.27 percent series due 2021 [Member]
Debt Instrument [Line Items]
Principal outstanding	80,900,000		80,900,000
Year due	2021
Interest rates (in hundredths)	8.27%
Other Great Plains [Member] | Great Plains Energy Equity Units Subordinated Notes [Member] | Equity Units Subordinated Notes [Member]
Debt Instrument [Line Items]
Principal outstanding	0		287,500,000
Interest rates (in hundredths)	10.00%
Other Great Plains [Member] | Great Plains Energy Senior Notes [Member] | Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Principal outstanding	350,000,000		350,000,000
Year due	2021
Interest rates (in hundredths)	4.85%
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	7.34%	[2]
Other Great Plains [Member] | Great Plains Energy Senior Notes [Member] | Senor notes due 2013 [Member]
Debt Instrument [Line Items]
Principal outstanding	250,000,000		250,000,000
Year due	2013
Interest rates (in hundredths)	2.75%
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	3.67%	[2]
Other Great Plains [Member] | Great Plains Energy Senior Notes [Member] | Senior notes due 2017 [Member]
Debt Instrument [Line Items]
Principal outstanding	100,000,000		100,000,000
Year due	2017
Interest rates (in hundredths)	6.875%
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)	7.33%	[2]
Other Great Plains [Member] | Great Plains Energy Senior Notes [Member] | Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Principal outstanding	$ 287,500,000		$ 0
Year due	2022
Interest rates (in hundredths)	5.292%

[1] Does not include $39.5 million EIRR Series 1993B, $63.3 million EIRR Series 2007 A-1 and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L

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

[3] Weighted-average interest rates at June 30, 2012

[4] Variable rate

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2012

Debt Disclosure [Abstract]

Long-term debt

		June 30			December 31
	Year Due	2012			2011
KCP&L		(millions)
General Mortgage Bonds
4.97% EIRR bonds(a)	2015-2035	$	106.9		$	119.3
7.15% Series 2009A (8.59% rate)(b)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
5.85% Series (5.72% rate)(b)	2017		250.0			250.0
6.375% Series (7.49% rate)(b)	2018		350.0			350.0
6.05% Series (5.78% rate)(b)	2035		250.0			250.0
5.30% Series	2041		400.0			400.0
EIRR bonds 4.90% Series 2008	2038		23.4			23.4
Other	2012-2018		2.9			2.9
Current maturities			(0.4	)		(12.7	)
Unamortized discount			(4.0	)		(4.2	)
Total KCP&L excluding current maturities(c)			1,902.0			1,901.9
Other Great Plains Energy
GMO First Mortgage Bonds 9.44% Series	2013-2021		10.1			11.2
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.341% Wamego Series 1996(d)	2026		7.3			7.3
0.341% State Environmental 1993(d)	2028		5.0			5.0
GMO Senior Notes
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			-			16.3
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(b)	2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(b)	2017		100.0			100.0
Great Plains Energy 4.85% Senior Notes (7.34% rate)(b)	2021		350.0			350.0
Great Plains Energy 5.292% Senior Notes	2022		287.5			-
Great Plains Energy 10.00% Equity Units Subordinated Notes			-			287.5
Current maturities			(506.7	)		(788.7	)
Unamortized discount and premium, net			5.7			(0.7	)
Total Great Plains Energy excluding current maturities(c)		$	3,013.4		$	2,742.3
(a) Weighted-average interest rates at June 30, 2012
(b) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(c) Does not include $39.5 million EIRR Series 1993B, $63.3 million EIRR Series 2007 A-1 and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L
(d) Variable rate

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Related Party Transactions and Relationships (Tables)

6 Months Ended

Jun. 30, 2012

Related Party Transactions and Relationships [Abstract]

Schedule of related party receivables and payables

	June 30			December 31
	2012			2011
	(millions)
Net receivable from (payable to) GMO	$	(246.6	)	$	24.1
Net receivable from Great Plains Energy		8.8			9.5

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2012

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

2.   SUPPLEMENTAL CASH FLOW INFORMATION

Great Plains Energy Other Operating Activities
Year to Date June 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	27.3		$	(14.1	)
Accounts receivable pledged as collateral		(67.0	)		-
Fuel inventories		(13.7	)		3.2
Materials and supplies		(5.7	)		(3.1	)
Accounts payable		(53.7	)		(67.2	)
Accrued taxes		33.8			33.6
Accrued interest		(3.6	)		(4.5	)
Deferred refueling outage costs		9.0			(31.0	)
Fuel adjustment clauses		10.5			(11.0	)
Pension and post-retirement benefit obligations		13.5			7.2
Allowance for equity funds used during construction		(0.1	)		(0.3	)
Interest rate hedge settlements		-			(26.1	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		-			2.3
Uncertain tax positions		(0.3	)		(19.6	)
Other		(12.8	)		(26.8	)
Total other operating activities	$	(62.8	)	$	(157.4	)
Cash paid during the period:
Interest	$	130.5		$	138.4
Income taxes	$	3.3		$	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	48.9		$	31.5

KCP&L Other Operating Activities
Year to Date June 30	2012			2011
Cash flows affected by changes in:	(millions)
Receivables	$	13.8		$	(9.7	)
Accounts receivable pledged as collateral		(11.0	)		-
Fuel inventories		(12.7	)		(4.1	)
Materials and supplies		(4.5	)		(3.3	)
Accounts payable		(36.5	)		(47.1	)
Accrued taxes		25.2			30.6
Accrued interest		(3.5	)		(3.0	)
Deferred refueling outage costs		9.0			(31.0	)
Pension and post-retirement benefit obligations		14.9			14.1
Kansas Energy Cost Adjustment		(4.4	)		(10.8	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		-			1.5
Uncertain tax positions		0.1			(11.8	)
Other		(16.5	)		(20.5	)
Total other operating activities	$	(26.1	)	$	(95.1	)
Cash paid during the period:
Interest	$	61.3		$	62.2
Income taxes	$	-		$	0.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	44.3		$	22.4

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Derivative Instruments [Abstract]

Values of open positions for derivative instruments

	June 30					December 31
	2012					2011
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	1.6	$	(0.5	)	$	2.0	$	(0.5	)
Non-hedging derivatives		16.2		(3.0	)		23.6		(5.0	)
Forward contracts
Non-hedging derivatives		69.5		6.7			97.3		7.8
Option contracts
Non-hedging derivatives		-		-			0.4		-
KCP&L
Futures contracts
Cash flow hedges	$	1.6	$	(0.5	)	$	2.0	$	(0.5	)

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

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
June 30, 2012	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		6.7		3.0
Total Derivatives		$	6.7	$	3.5
December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.8		5.0
Total Derivatives		$	7.8	$	5.5

KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
June 30, 2012	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	-	$	0.5

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

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 June 30, 2012	(millions)					(millions)
Interest rate contracts		$	-		Interest charges	$	(5.0	)
Commodity contracts			0.1		Fuel		-
Income tax benefit			-		Income tax benefit		1.9
Total		$	0.1		Total	$	(3.1	)
Year to Date June 30, 2012
Interest rate contracts		$	-		Interest charges	$	(10.1	)
Commodity contracts			(0.2	)	Fuel		-
Income tax benefit			0.1		Income tax benefit		3.9
Total		$	(0.1	)	Total	$	(6.2	)
Three Months Ended June 30, 2011
Interest rate contracts		$	(5.8	)	Interest charges	$	(3.9	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			2.2		Income tax benefit		1.4
Total		$	(3.7	)	Total	$	(2.5	)
Year to Date June 30, 2011
Interest rate contracts		$	(5.3	)	Interest charges	$	(6.8	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			2.1		Income tax benefit		2.6
Total		$	(3.3	)	Total	$	(4.2	)

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 June 30, 2012	(millions)					(millions)
Interest rate contracts		$	-		Interest charges	$	(2.2	)
Commodity contracts			0.1		Fuel		-
Income tax benefit			-		Income tax benefit		0.9
Total		$	0.1		Total	$	(1.3	)
Year to Date June 30, 2012
Interest rate contracts		$	-		Interest charges	$	(4.4	)
Commodity contracts			(0.2	)	Fuel		-
Income tax benefit			0.1		Income tax benefit		1.7
Total		$	(0.1	)	Total	$	(2.7	)
Three Months Ended June 30, 2011
Interest rate contracts		$	-		Interest charges	$	(2.2	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			-		Income tax benefit		0.8
Total		$	(0.1	)	Total	$	(1.4	)
Year to Date June 30, 2011
Interest rate contracts		$	-		Interest charges	$	(4.4	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			-		Income tax benefit		1.7
Total		$	(0.1	)	Total	$	(2.7	)

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

Great Plains Energy
Derivatives in Regulatory Account Relationship
					Gain (Loss) Reclassified from
					Regulatory Account
	Amount of Gain (Loss)
	Recognized on Regulatory				Income Statement
	Account on Derivatives				Classification	Amount
Three Months Ended June 30, 2012		(millions)				(millions)
Commodity contracts		$	0.3		Fuel	$	(2.0	)
Total		$	0.3		Total	$	(2.0	)
Year to Date June 30, 2012
Commodity contracts		$	(2.7	)	Fuel	$	(2.7	)
Total		$	(2.7	)	Total	$	(2.7	)
Three Months Ended June 30, 2011
Commodity contracts		$	(1.0	)	Fuel	$	(1.0	)
Total		$	(1.0	)	Total	$	(1.0	)
Year to Date June 30, 2011
Commodity contracts		$	(1.3	)	Fuel	$	(2.9	)
Total		$	(1.3	)	Total	$	(2.9	)

Accumulated other comprehensive income related to cash flow hedges

	Great Plains Energy						KCP&L
	June 30			December 31			June 30			December 31
	2012			2011			2012			2011
	(millions)
Current assets	$	10.9		$	11.3		$	10.9		$	11.3
Current liabilities		(79.1	)		(89.5	)		(57.8	)		(62.5	)
Noncurrent liabilities		(0.3	)		(0.2	)		(0.3	)		(0.2	)
Deferred income taxes		26.7			30.5			18.4			20.0
Total	$	(41.8	)	$	(47.9	)	$	(28.8	)	$	(31.4	)

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Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Regulatory Assets [Line Items]
Regulatory Assets	$ 1,029.5	$ 1,058.2
Regulatory Liabilities [Line Items]
Regulatory Liabilities	276.3	268.5
Kansas City Power and Light Company [Member]
Regulatory Proceedings [Line Items]
Qualifying advance coal project tax credits to be reallocated from KCPL to GMO	26.5
Unamortized deferred investment tax credits	127.0
Regulatory Assets [Line Items]
Regulatory Assets	760.8	780.7
Regulatory Liabilities [Line Items]
Regulatory Liabilities	146.9	142.8
Kansas City Power and Light Company [Member] | Rate jurisdiction - Kansas [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase	63.6
Return on equity (in hundredths)	10.40%
Rate-making equity ratio (in hundredths)	51.80%
Kansas City Power and Light Company [Member] | Rate jurisdiction - Missouri [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase	105.7
Return on equity (in hundredths)	10.40%
Rate-making equity ratio (in hundredths)	52.50%
Wholesale Margin Offset	45.9
Annual revenue increase (decrease) recommended by MPSC staff, minimum	16.5
Annual revenue increase (decrease) recommended by MPSC staff, maximum	33.7
Return on equity (in hundredths) recommended by MPSC staff, minimum	8.00%
Return on equity (in hundredths) recommended by MPSC staff, maximum	9.00%
KCPL Greater Missouri Operations [Member]
Regulatory Proceedings [Line Items]
Unamortized deferred investment tax credits	3.0
Amount of FAC refund recommended by MPSC staff	19.0
Revised amount of FAC refund recommended by MPSC staff	14.9
KCPL Greater Missouri Operations [Member] | Rate jurisdiction - Missouri public service division [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase	58.3
Return on equity (in hundredths)	10.40%
Rate-making equity ratio (in hundredths)	52.50%
KCPL Greater Missouri Operations [Member] | Rate jurisdiction - St. Joseph Light and Power division [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase	$ 25.2
Return on equity (in hundredths)	10.40%
Rate-making equity ratio (in hundredths)	52.50%

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Segments and Related Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended			12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012		Jun. 30, 2011	Dec. 31, 2011
Segment Reporting Information [Line Items]
Operating revenues	$ 603.6	$ 565.1	$ 1,083.3		$ 1,058.0
Depreciation and amortization	(67.9)	(67.6)	(135.3)		(140.0)
Interest charges	(55.8)	(50.3)	(122.7)		(95.2)
Income tax (expense) benefit	(31.8)	(19.8)	(22.3)		(15.2)
Net income (loss) attributable to Great Plains Energy	58.1	43.4	49.0		45.8
Assets	9,312.9		9,312.9			9,118.0
Capital expenditures			263.4	[1]		456.6	[1]
All Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0		0
Depreciation and amortization	0	0	0		0
Interest charges	5.4	10.0	21.6		20.6
Income tax (expense) benefit	(4.1)	(6.2)	(11.8)		(11.7)
Net income (loss) attributable to Great Plains Energy	(5.7)	(5.6)	(19.3)		(10.2)
Assets	66.1		66.1			51.9
Capital expenditures			0	[1]		0	[1]
Corporate Elimination [Member]
Segment Reporting Information [Line Items]
Assets	(661.0)		(661.0)			(417.3)
Capital expenditures			0	[1]		0	[1]
Electric Utility Segment [Member]
Segment Reporting Information [Line Items]
Operating revenues	603.6	565.1	1,083.3		1,058.0
Depreciation and amortization	67.9	67.6	135.3		140.0
Interest charges	50.4	40.3	101.1		74.6
Income tax (expense) benefit	35.9	26.0	34.1		26.9
Net income (loss) attributable to Great Plains Energy	63.8	49.0	68.3		56.0
Assets	9,907.8		9,907.8			9,483.4
Capital expenditures			$ 263.4	[1]		$ 456.6	[1]

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

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Consolidated Statements of Income and Comprehensive Income (unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Operating Revenues
Electric revenues	$ 603.6	$ 565.1	$ 1,083.3	$ 1,058.0
Operating Expenses
Fuel	138.1	114.4	257.4	219.3
Purchased power	26.9	55.4	51.6	110.3
Transmission of electricity by others	8.8	7.0	16.1	14.5
Utility operating and maintenance expenses	164.1	161.1	327.2	318.6
Voluntary separation program	0	3.0	0	12.7
Depreciation and amortization	67.9	67.6	135.3	140.0
General taxes	45.0	40.3	89.5	82.3
Other General and Administrative Expense	2.8	0.7	7.2	3.5
Costs and Expenses, Total	453.6	449.5	884.3	901.2
Operating income	150.0	115.6	199.0	156.8
Non-operating income	1.6	0.8	2.5	4.4
Non-operating expenses	(5.8)	(2.8)	(7.6)	(5.0)
Interest charges	(55.8)	(50.3)	(122.7)	(95.2)
Income from continuing operations before income tax	90.0	63.3	71.2	61.0
Income tax (expense) benefit	(31.8)	(19.8)	(22.3)	(15.2)
Loss from equity investments, net of income taxes	(0.1)	(0.1)	(0.1)	(0.1)
Net income	58.1	43.4	48.8	45.7
Less: Net income attributable to noncontrolling interest	0	0	0.2	0.1
Net income (loss) attributable to Great Plains Energy	58.1	43.4	49.0	45.8
Preferred stock dividend requirements	0.4	0.4	0.8	0.8
Earnings available for common shareholders	57.7	43.0	48.2	45.0
Average number of basic common shares outstanding	139.6	135.6	137.7	135.5
Average number of diluted common shares outstanding	142.0	138.9	140.6	138.6
Basic earnings (loss) per common share
Continuing operations	$ 0.41	$ 0.32	$ 0.35	$ 0.33
Basic earnings per common share	$ 0.41	$ 0.32	$ 0.35	$ 0.33
Diluted earnings (loss) per common share
Continuing operations	$ 0.41	$ 0.31	$ 0.34	$ 0.32
Diluted earnings per common share	$ 0.41	$ 0.31	$ 0.34	$ 0.32
Cash dividends per common share	$ 0.2125	$ 0.2075	$ 0.425	$ 0.415
Comprehensive Income
Net income	58.1	43.4	48.8	45.7
Derivative Hedging Activity
Gain (loss) on derivative hedging instruments	0.1	(5.9)	(0.2)	(5.4)
Income tax benefit (expense)	0	2.2	0.1	2.1
Net gain (loss) on derivative hedging instruments	0.1	(3.7)	(0.1)	(3.3)
Reclassification to expenses, net of tax	3.1	2.5	6.2	4.2
Derivative hedging activity, net of tax	3.2	(1.2)	6.1	0.9
Defined benefit pension plans
Amortization of net gains included in net periodic benefit costs	0.1	0.2	0.2	0.2
Income tax benefit (expense)	(0.1)	(0.1)	(0.1)	(0.1)
Net change in unrecognized pension expense	0	0.1	0.1	0.1
Other comprehensive income (loss)	3.2	(1.1)	6.2	1.0
Comprehensive income	61.3	42.3	55.0	46.7
Less: comprehensive income attributable to noncontrolling interest	0	0	0.2	0.1
Comprehensive income attributable to Great Plains Energy	61.3	42.3	55.2	46.8
Kansas City Power and Light Company [Member]
Operating Revenues
Electric revenues	409.1	383.4	736.1	714.2
Operating Expenses
Fuel	98.7	81.5	183.3	149.7
Purchased power	6.6	20.4	13.6	41.8
Transmission of electricity by others	6.1	4.2	11.1	8.5
Utility operating and maintenance expenses	115.9	115.6	233.8	230.5
Voluntary separation program	0	2.4	0	9.2
Depreciation and amortization	46.0	48.2	91.7	101.6
General taxes	35.9	33.4	71.1	67.3
Other General and Administrative Expense	0	(0.1)	0	1.3
Costs and Expenses, Total	309.2	305.6	604.6	609.9
Operating income	99.9	77.8	131.5	104.3
Non-operating income	0.8	0.5	1.3	1.0
Non-operating expenses	(2.7)	(1.4)	(3.4)	(2.4)
Interest charges	(31.3)	(27.3)	(63.7)	(50.4)
Income from continuing operations before income tax	66.7	49.6	65.7	52.5
Income tax (expense) benefit	(23.0)	(16.2)	(19.7)	(15.1)
Net income	43.7	33.4	46.0	37.4
Earnings available for common shareholders	43.7	33.4	46.0	37.4
Comprehensive Income
Net income	43.7	33.4	46.0	37.4
Derivative Hedging Activity
Gain (loss) on derivative hedging instruments	0.1	(0.1)	(0.2)	(0.1)
Income tax benefit (expense)	0	0	0.1	0
Net gain (loss) on derivative hedging instruments	0.1	(0.1)	(0.1)	(0.1)
Reclassification to expenses, net of tax	1.3	1.4	2.7	2.7
Derivative hedging activity, net of tax	1.4	1.3	2.6	2.6
Defined benefit pension plans
Other comprehensive income (loss)	1.4	1.3	2.6	2.6
Comprehensive income attributable to Great Plains Energy	$ 45.1	$ 34.7	$ 48.6	$ 40.0

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Commitments and Contingencies (Details) (USD $)	Jun. 30, 2012 MW T	Dec. 31, 2011
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 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)	25,000,000
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
Estimated amount of insurance proceeds available to cover qualified remediation expenses	2,400,000
LaCygne Station Evironmental Retrofits [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
KCPL share of predetermination request for environmental equipment required at LaCygne Station to comply with BART	615,000,000
Kansas City Power and Light Company [Member]
Climate Change [Abstract]
CO2 produced per year (in millions of tons)	18,000,000
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 (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
Increased wind generation capacity agreed to pursue in Collaboration Agreement by 2012 - Total (in megawatts)	400
Wind generation added under Collaboration Agreement (in megawatts)	379
Remediation [Abstract]
Accrued environmental remediation expenses	300,000	300,000
New Source Review [Abstract]
Cost of Supplemental Environmental Project	800,000
Amount of penalty agreed to in settlement agreement	350,000
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%
Kcpl Greater Missouri Operations Member
Climate Change [Abstract]
Minimum required renewable energy generation capacity percentage in Missouri by 2011	2.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2014	5.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2018	10.00%
Minimum required renewable energy generation capacity percentage in Missouri by 2021	15.00%
Estimated electricity required to come from solar resources (in megawatts)	2
Kcpl Greater Missouri Operations Member | Jeffrey Units Nos 1 and 2 [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	8.00%
Kcpl Greater Missouri Operations Member | Iatan No. 1 [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	18.00%
Westar Energy Inc [Member] | Jeffrey Units Nos 1 and 2 [Member]
Best Available Retrofit Technology Rule (BART) [Abstract]
Entity's ownership percentage in facility (in hundredths)	92.00%
New Source Review [Abstract]
Estimated cost to install a selective catalytic reduction system at jeffrey Energy Center pursuant to a settlement agreement	$ 240,000,000

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Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest (unaudited) (USD $) In Millions, except Share data, unless otherwise specified	Total	Kansas City Power and Light Company [Member]	Common Stock [Member]	Common Stock [Member] Kansas City Power and Light Company [Member]	Retained Earnings [Member]	Retained Earnings [Member] Kansas City Power and Light Company [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Other Comprehensive Income (Loss) [Member] Kansas City Power and Light Company [Member]	Noncontrolling Interest [Member]
Beginning balance at Dec. 31, 2010			$ 2,324.4	$ 1,563.1	$ 626.5	$ 478.3	$ (8.9)	$ (56.1)	$ (36.4)	$ 1.2
Beginning balance (in shares) at Dec. 31, 2010			136,113,954	1			(400,889)
Distribution										0
Total Great Plains Energy Common Shareholders' Equity	2,879.7	1,995.0
Derivative hedging activity, net of tax	0.9	2.6						0.9	2.6
Change in unrecognized pension expense, net of tax	0.1							0.1
Net income (loss) attributable to Great Plains Energy	45.8				45.8	37.4
Loss On Reissuance Of Treasury Stock					(0.5)
Treasury shares acquired							(2.2)
Treasury shares acquired (in shares)							(88,400)
Treasury shares reissued							4.8
Treasury shares reissued (in shares)							221,296
Issuance of common stock			3.1
Issuance of common stock (in shares)			155,345
Equity compensation expense, net of forfeitures			0.1
Unearned Compensation [Abstract]
Issuance of restricted common stock			(2.9)
Forfeiture of restricted common stock			0.8
Compensation expense recognized			1.2
Stockholders' Equity, Other			0.1
Dividends:
Common stock					(56.4)	(50.0)
Preferred stock - at required rates					(0.8)
Performance shares					(0.3)
Net income attributable to noncontrolling interest										(0.1)
Ending balance at Jun. 30, 2011			2,326.8	1,563.1	614.3	465.7	(6.3)	(55.1)	(33.8)	1.1
Ending balance (in shares) at Jun. 30, 2011			136,269,299	1			(267,993)
Beginning balance at Mar. 31, 2011
Total Great Plains Energy Common Shareholders' Equity	2,879.7	1,995.0
Derivative hedging activity, net of tax	(1.2)	1.3
Change in unrecognized pension expense, net of tax	0.1
Net income (loss) attributable to Great Plains Energy	43.4
Ending balance at Jun. 30, 2011				1,563.1
Ending balance (in shares) at Jun. 30, 2011				1
Beginning balance at Dec. 31, 2011			2,330.6	1,563.1	684.7	513.8	(5.6)	(49.8)	(31.4)	1.0
Beginning balance (in shares) at Dec. 31, 2011			136,406,306	1			(264,567)
Distribution										(0.6)
Total Great Plains Energy Common Shareholders' Equity	3,247.0	2,044.1
Derivative hedging activity, net of tax	6.1	2.6						6.1	2.6
Change in unrecognized pension expense, net of tax	0.1							0.1
Net income (loss) attributable to Great Plains Energy	49.0				49.0	46.0
Loss On Reissuance Of Treasury Stock					(0.3)
Treasury shares acquired							(2.9)
Treasury shares acquired (in shares)							(145,701)
Treasury shares reissued							3.5
Treasury shares reissued (in shares)							169,800
Issuance of common stock			290.3
Issuance of common stock (in shares)			17,248,954
Equity compensation expense, net of forfeitures			0.1
Unearned Compensation [Abstract]
Issuance of restricted common stock			(3.2)
Forfeiture of restricted common stock			1.0
Compensation expense recognized			1.6
Stockholders' Equity, Other			0.5
Dividends:
Common stock					(57.9)	(50.0)
Preferred stock - at required rates					(0.8)
Performance shares					0
Net income attributable to noncontrolling interest										(0.2)
Ending balance at Jun. 30, 2012			2,620.9	1,563.1	674.7	509.8	(5.0)	(43.6)	(28.8)	0.2
Ending balance (in shares) at Jun. 30, 2012			153,655,260	1			(240,468)
Beginning balance at Mar. 31, 2012
Total Great Plains Energy Common Shareholders' Equity	3,247.0	2,044.1
Derivative hedging activity, net of tax	3.2	1.4
Change in unrecognized pension expense, net of tax	0
Net income (loss) attributable to Great Plains Energy	58.1
Ending balance at Jun. 30, 2012				$ 1,563.1
Ending balance (in shares) at Jun. 30, 2012				1

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Segments and Related Information (Tables)

6 Months Ended

Jun. 30, 2012

Segments and Related Information [Abstract]

Segment financial information

Three Months Ended	Electric						Great Plains
June 30, 2012	Utility			Other			Energy
	(millions)
Operating revenues	$	603.6		$	-		$	603.6
Depreciation and amortization		(67.9	)		-			(67.9	)
Interest charges		(50.4	)		(5.4	)		(55.8	)
Income tax (expense) benefit		(35.9	)		4.1			(31.8	)
Net income (loss) attributable to Great Plains Energy		63.8			(5.7	)		58.1

Year to Date	Electric						Great Plains
June 30, 2012	Utility			Other			Energy
	(millions)
Operating revenues	$	1,083.3		$	-		$	1,083.3
Depreciation and amortization		(135.3	)		-			(135.3	)
Interest charges		(101.1	)		(21.6	)		(122.7	)
Income tax (expense) benefit		(34.1	)		11.8			(22.3	)
Net income (loss) attributable to Great Plains Energy		68.3			(19.3	)		49.0

Three Months Ended	Electric						Great Plains
June 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	565.1		$	-		$	565.1
Depreciation and amortization		(67.6	)		-			(67.6	)
Interest charges		(40.3	)		(10.0	)		(50.3	)
Income tax (expense) benefit		(26.0	)		6.2			(19.8	)
Net income (loss) attributable to Great Plains Energy		49.0			(5.6	)		43.4

Year to Date	Electric						Great Plains
June 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	1,058.0		$	-		$	1,058.0
Depreciation and amortization		(140.0	)		-			(140.0	)
Interest charges		(74.6	)		(20.6	)		(95.2	)
Income tax (expense) benefit		(26.9	)		11.7			(15.2	)
Net income (loss) attributable to Great Plains Energy		56.0			(10.2	)		45.8

	Electric							Great Plains
	Utility		Other		Eliminations			Energy
June 30, 2012	(millions)
Assets	$	9,907.8	$	66.1	$	(661.0	)	$	9,312.9
Capital expenditures (a)		263.4		-		-			263.4
December 31, 2011
Assets	$	9,483.4	$	51.9	$	(417.3	)	$	9,118.0
Capital expenditures (a)		456.6		-		-			456.6
(a) Capital expenditures reflect year to date amounts for the periods presented.

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Segments and Related Information

6 Months Ended

Jun. 30, 2012

Segments and Related Information [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 segregates reportable segments based on products and services, management responsibility and regulation.  The one reportable business segment is electric utility, consisting of KCP&L, GMO’s regulated utility operations and GMO Receivables Company.  Other includes GMO activity other than its regulated utility operations, 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
June 30, 2012	Utility			Other			Energy
	(millions)
Operating revenues	$	603.6		$	-		$	603.6
Depreciation and amortization		(67.9	)		-			(67.9	)
Interest charges		(50.4	)		(5.4	)		(55.8	)
Income tax (expense) benefit		(35.9	)		4.1			(31.8	)
Net income (loss) attributable to Great Plains Energy		63.8			(5.7	)		58.1

Year to Date	Electric						Great Plains
June 30, 2012	Utility			Other			Energy
	(millions)
Operating revenues	$	1,083.3		$	-		$	1,083.3
Depreciation and amortization		(135.3	)		-			(135.3	)
Interest charges		(101.1	)		(21.6	)		(122.7	)
Income tax (expense) benefit		(34.1	)		11.8			(22.3	)
Net income (loss) attributable to Great Plains Energy		68.3			(19.3	)		49.0

Three Months Ended	Electric						Great Plains
June 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	565.1		$	-		$	565.1
Depreciation and amortization		(67.6	)		-			(67.6	)
Interest charges		(40.3	)		(10.0	)		(50.3	)
Income tax (expense) benefit		(26.0	)		6.2			(19.8	)
Net income (loss) attributable to Great Plains Energy		49.0			(5.6	)		43.4

Year to Date	Electric						Great Plains
June 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	1,058.0		$	-		$	1,058.0
Depreciation and amortization		(140.0	)		-			(140.0	)
Interest charges		(74.6	)		(20.6	)		(95.2	)
Income tax (expense) benefit		(26.9	)		11.7			(15.2	)
Net income (loss) attributable to Great Plains Energy		56.0			(10.2	)		45.8

	Electric							Great Plains
	Utility		Other		Eliminations			Energy
June 30, 2012	(millions)
Assets	$	9,907.8	$	66.1	$	(661.0	)	$	9,312.9
Capital expenditures (a)		263.4		-		-			263.4
December 31, 2011
Assets	$	9,483.4	$	51.9	$	(417.3	)	$	9,118.0
Capital expenditures (a)		456.6		-		-			456.6
(a) Capital expenditures reflect year to date amounts for the periods presented.

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Summary of Significant Accounting Policies (Details) (USD $)	3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 Dividend Declared [Member]	Jun. 30, 2012 Restricted Stock [Member]	Jun. 30, 2011 Restricted Stock [Member]	Jun. 30, 2012 Restricted Stock [Member]	Jun. 30, 2011 Restricted Stock [Member]	Jun. 30, 2012 Stock Options [Member]	Jun. 30, 2011 Stock Options [Member]	Jun. 30, 2012 Stock Options [Member]	Jun. 30, 2011 Stock Options [Member]	Jun. 30, 2012 Performance Shares [Member]	Jun. 30, 2011 Performance Shares [Member]	Jun. 30, 2012 Performance Shares [Member]	Jun. 30, 2011 Performance Shares [Member]	Jun. 30, 2012 Subsidiaries [Member]	Jun. 30, 2011 Subsidiaries [Member]	Jun. 30, 2012 Subsidiaries [Member]	Jun. 30, 2011 Subsidiaries [Member]	Jun. 30, 2012 Subsidiaries [Member] Dividend Declared [Member]	Jun. 30, 2012 Carrying (Reported) Amount, Fair Value Disclosure [Member]	Dec. 31, 2011 Carrying (Reported) Amount, Fair Value Disclosure [Member]	Jun. 30, 2012 Carrying (Reported) Amount, Fair Value Disclosure [Member] Subsidiaries [Member]	Dec. 31, 2011 Carrying (Reported) Amount, Fair Value Disclosure [Member] Subsidiaries [Member]	Jun. 30, 2012 Estimate of Fair Value, Fair Value Disclosure [Member]	Dec. 31, 2011 Estimate of Fair Value, Fair Value Disclosure [Member]	Jun. 30, 2012 Estimate of Fair Value, Fair Value Disclosure [Member] Subsidiaries [Member]	Dec. 31, 2011 Estimate of Fair Value, Fair Value Disclosure [Member] Subsidiaries [Member]
Fair value of financial instruments [Abstract}
Long-term debt																							$ 3,500,000,000	$ 3,500,000,000	$ 1,900,000,000	$ 1,900,000,000	$ 3,900,000,000	$ 3,900,000,000	$ 2,200,000,000	$ 2,200,000,000
Income [Abstract]
Net income	58,100,000	43,400,000	48,800,000	45,700,000														43,700,000	33,400,000	46,000,000	37,400,000
Less: net income attributable to noncontrolling interest	0	0	(200,000)	(100,000)
Less: preferred stock dividend requirements	400,000	400,000	800,000	800,000
Income from continuing operations available for common shareholders	57,700,000	43,000,000	48,200,000	45,000,000
Common Shares Outstanding [Abstract]
Average number of common shares outstanding (in shares)	139,600,000	135,600,000	137,700,000	135,500,000
Add: effect of dilutive securities (in shares)	2,400,000	3,300,000	2,900,000	3,100,000
Diluted average number of common shares outstanding (in shares)	142,000,000	138,900,000	140,600,000	138,600,000
Earnings per share [Abstract]
Basic EPS from continuing operations (in dollars per share)	$ 0.41	$ 0.32	$ 0.35	$ 0.33
Diluted EPS from continuing operations (in dollars per share)	$ 0.41	$ 0.31	$ 0.34	$ 0.32
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares (in shares)						10,617	12,115	10,617	43,641	0	154,096	0	154,096	0	201,571	0	201,571
Dividends Declared [Abstract]
Subsequent event date					Aug. 01, 2012																	Aug. 01, 2012
Subsequent Event Amount																						$ 23,000,000
Subsequent per share amount (in dollars per share)					$ 0.2125
Subsequent Event Description					Great Plains Energys Board of Directors declared a quarterly dividend and also declared regular dividends on Great Plains Energys preferred stock.																	KCP&Ls Board of Directors declared a cash dividend payable to Great Plains Energy.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2012

Summary of Significant Accounting Policies [Abstract]

Basic and diluted earnings per share

	Three Months Ended				Year to Date
	June 30				June 30
	2012		2011		2012			2011
Income	(millions, except per share amounts)
Net income	$	58.1	$	43.4	$	48.8		$	45.7
Less: net loss attributable to noncontrolling interest		-		-		(0.2	)		(0.1	)
Less: preferred stock dividend requirements		0.4		0.4		0.8			0.8
Earnings available for common shareholders	$	57.7	$	43.0	$	48.2		$	45.0
Common Shares Outstanding
Average number of common shares outstanding		139.6		135.6		137.7			135.5
Add: effect of dilutive securities		2.4		3.3		2.9			3.1
Diluted average number of common shares outstanding		142.0		138.9		140.6			138.6
Basic EPS	$	0.41	$	0.32	$	0.35		$	0.33
Diluted EPS	$	0.41	$	0.31	$	0.34		$	0.32

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2012

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

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

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

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

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

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

Basic and Diluted Earnings per Common Share Calculation

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

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

	Three Months Ended				Year to Date
	June 30				June 30
	2012		2011		2012			2011
Income	(millions, except per share amounts)
Net income	$	58.1	$	43.4	$	48.8		$	45.7
Less: net loss attributable to noncontrolling interest		-		-		(0.2	)		(0.1	)
Less: preferred stock dividend requirements		0.4		0.4		0.8			0.8
Earnings available for common shareholders	$	57.7	$	43.0	$	48.2		$	45.0
Common Shares Outstanding
Average number of common shares outstanding		139.6		135.6		137.7			135.5
Add: effect of dilutive securities		2.4		3.3		2.9			3.1
Diluted average number of common shares outstanding		142.0		138.9		140.6			138.6
Basic EPS	$	0.41	$	0.32	$	0.35		$	0.33
Diluted EPS	$	0.41	$	0.31	$	0.34		$	0.32

The computation of diluted EPS for the three months ended and year to date June 30, 2012, excludes anti-dilutive shares consisting of 10,617 restricted stock shares.

The computation of diluted EPS for the three months ended June 30, 2011, excludes anti-dilutive shares consisting of 201,571 performance shares, 12,115 restricted stock shares and 154,096 stock options.

The computation of diluted EPS year to date June 30, 2011, excludes anti-dilutive shares consisting of 201,571 performance shares, 43,641 restricted stock shares and 154,096 stock options.

Dividends Declared

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

In August 2012, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $23 million payable on September 19, 2012.

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Consolidated Balance Sheets (unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 6.9		$ 6.2
Funds on deposit	1.5		1.4
Receivables, net	206.1		231.2
Accounts receivable pledged as collateral	162.0		95.0
Fuel inventories, at average cost	102.7		89.0
Materials and supplies, at average cost	146.0		140.3
Deferred refueling outage costs	18.5		27.5
Refundable income taxes	5.4		0.3
Deferred income taxes	28.5		7.5
Derivative instruments	0.9		1.0
Prepaid expenses and other assets	27.2		19.7
Assets, Current, Total	705.7		619.1
Utility Plant, at Original Cost
Electric	11,039.5		10,924.8
Less-accumulated depreciation	4,343.3		4,235.8
Net utility plant in service	6,696.2		6,689.0
Construction work in progress	406.2		287.9
Nuclear Fuel, Net of Amortization	87.8		76.6
Public Utilities, Property, Plant and Equipment, Net, Total	7,190.2		7,053.5
Investments and Other Assets
Nuclear decommissioning trust fund	144.9		135.3
Regulatory Assets	1,029.5		1,058.2
Goodwill	169.0		169.0
Derivative instruments	5.8		6.8
Other Assets, Noncurrent	67.8		76.1
Investments and Other Assets, Total	1,417.0		1,445.4
Assets, Total	9,312.9		9,118.0
Current Liabilities
Notes payable	31.0		22.0
Collateralized note payable	162.0		95.0
Commercial paper	91.0		267.0
Current maturities of long-term debt	507.1		801.4
Accounts payable	222.5		275.6
Accrued taxes	64.4		25.8
Accrued interest	73.1		76.9
Accrued compensation and benefits	39.4		40.8
Pension and post-retirement liability	4.4		4.4
Other Liabilities, Current	24.9		26.0
Liabilities, Current, Total	1,219.8		1,634.9
Deferred Credits and Other Liabilities
Deferred income taxes	678.3		628.6
Deferred tax credits	130.0		131.2
Asset retirement obligations	154.3		149.6
Pension and post-retirement liability	452.3		461.9
Regulatory Liabilities	276.3		268.5
Other Liabilities, Noncurrent	102.3		101.1
Liabilities, Noncurrent, Total	1,793.5		1,740.9
Common shareholders' equity
Common Stock, Value, Issued	2,620.9		2,330.6
Retained earnings	674.7		684.7
Treasury Stock, Value	(5.0)		(5.6)
Accumulated other comprehensive loss	(43.6)		(49.8)
Common Shareholders' Equity, Total	3,247.0		2,959.9
Noncontrolling interest	0.2		1.0
Cumulative preferred stock $100 par value
3.8% - 100,000 shares issued	10.0		10.0
4.50% - 100,000 shares issued	10.0		10.0
4.20% - 70,000 shares issued	7.0		7.0
4.35% - 120,000 shares issued	12.0		12.0
Preferred Stock, Value, Outstanding	39.0		39.0
Long-term debt	3,013.4	[1]	2,742.3	[1]
Capitalization, Total	6,299.6		5,742.2
Commitments and Contingencies
Liabilities and Equity, Total	9,312.9		9,118.0
Kansas City Power and Light Company [Member]
Current Assets
Cash and cash equivalents	2.4		1.9
Funds on deposit	0.1		0.1
Receivables, net	160.8		172.9
Accounts receivable pledged as collateral	106.0		95.0
Fuel inventories, at average cost	71.7		59.0
Materials and supplies, at average cost	105.6		101.1
Deferred refueling outage costs	18.5		27.5
Refundable income taxes	3.8		5.7
Deferred income taxes	4.8		0
Prepaid expenses and other assets	23.6		16.0
Assets, Current, Total	497.3		479.2
Utility Plant, at Original Cost
Electric	7,906.2		7,829.3
Less-accumulated depreciation	3,314.0		3,243.0
Net utility plant in service	4,592.2		4,586.3
Construction work in progress	311.3		203.5
Nuclear Fuel, Net of Amortization	87.8		76.6
Public Utilities, Property, Plant and Equipment, Net, Total	4,991.3		4,866.4
Investments and Other Assets
Nuclear decommissioning trust fund	144.9		135.3
Regulatory Assets	760.8		780.7
Other Assets, Noncurrent	23.5		30.6
Investments and Other Assets, Total	929.2		946.6
Assets, Total	6,417.8		6,292.2
Current Liabilities
Notes payable	0		0
Collateralized note payable	106.0		95.0
Commercial paper	91.0		227.0
Current maturities of long-term debt	0.4		12.7
Accounts payable	183.2		209.7
Affiliated payables	251.2		5.1
Accrued taxes	43.7		20.6
Accrued interest	26.5		30.0
Accrued compensation and benefits	39.4		40.8
Pension and post-retirement liability	3.0		3.0
Other Liabilities, Current	13.0		13.7
Liabilities, Current, Total	757.4		657.6
Deferred Credits and Other Liabilities
Deferred income taxes	797.7		772.7
Deferred tax credits	127.0		127.9
Asset retirement obligations	138.6		134.3
Pension and post-retirement liability	431.5		440.9
Regulatory Liabilities	146.9		142.8
Other Liabilities, Noncurrent	72.6		68.6
Liabilities, Noncurrent, Total	1,714.3		1,687.2
Common shareholders' equity
Common Stock, Value, Issued	1,563.1		1,563.1
Retained earnings	509.8		513.8
Accumulated other comprehensive loss	(28.8)		(31.4)
Common Shareholders' Equity, Total	2,044.1		2,045.5
Cumulative preferred stock $100 par value
Long-term debt	1,902.0	[1]	1,901.9	[1]
Capitalization, Total	3,946.1		3,947.4
Commitments and Contingencies
Liabilities and Equity, Total	$ 6,417.8		$ 6,292.2

[1] Does not include $39.5 million EIRR Series 1993B, $63.3 million EIRR Series 2007 A-1 and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L

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Legal Proceedings

6 Months Ended

Jun. 30, 2012

Legal Proceedings [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.  On July 12, 2012, a three-judge panel of the Court of Appeals issued a decision reversing in part the trial court’s decision and directing that the original award be increased by $2.1 million ($1.0 million KCP&L share).  The parties have until late August 2012 to request a rehearing of that decision.

GMO Western Energy Crisis

In response to complaints of manipulation of the California energy market, The Federal Energy Regulatory Commission (FERC) issued an order in July 2001 requiring net sellers of power in the California markets from October 2, 2000, through June 20, 2001, at prices above a FERC-determined competitive market clearing price, to make refunds to net purchasers of power in the California market during that time period.  Because MPS Merchant was a net purchaser of power during the refund period, it has received approximately $8 million in refunds through settlements with certain sellers of power.  MPS Merchant estimates that it is entitled to approximately $12 million in additional refunds under the standards FERC has used in this case.  FERC has stated that interest will be applied to the refunds but the amount of interest has not yet been determined.

In December 2001, various parties appealed the July 2001 FERC order to the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) seeking review of a number of issues, including expansion of the refund period to include periods prior to October 2, 2000 (the Summer Period).  MPS Merchant was a net seller of power during the Summer Period.  On August 2, 2006, the Ninth Circuit issued an order finding, among other things, that FERC did not provide a sufficient justification for refusing to exercise its remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the Summer Period.  The court remanded the matter to FERC for further consideration.  In May 2011, FERC issued an order which clarified the scope of the hearing regarding spot-market transactions during the Summer Period and ruled on requests for rehearing and motions to dismiss.  An evidentiary hearing before a FERC administrative law judge concluded on July 19, 2012.  An initial decision by the FERC administrative law judge is due February 2013.  If FERC determines that MPS Merchant violated then-existing tariffs or laws during the Summer Period and that such violations affected market clearing prices in California, MPS Merchant could be found to owe refunds.

A separate proceeding was also initiated, generally referred to as the Pacific Northwest refund proceeding, to determine if any refunds were warranted in the Pacific Northwest between December 25, 2000, and June 20, 2001.  Refund claims brought against MPS Merchant were $5.1 million.  FERC initially rejected the refund requests, but its decision was remanded by the Ninth Circuit for FERC to consider whether any specific acts of market manipulation support the imposition of refunds for particular bilateral contracts.  Formal claims against MPS Merchant must be identified by August 17, 2012, and an evidentiary hearing on transactions in the Pacific Northwest has been scheduled to begin April 15, 2013.

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Document And Entity Information (USD $)	6 Months Ended
	Jun. 30, 2012	Aug. 06, 2012	Jun. 30, 2011
Entity Registrant Name	Great Plains Energy Inc
Entity Central Index Key	0001143068
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,819,307,073
Entity Common Stock, Shares Outstanding		153,430,889
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2012

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Related Party Transactions and Relationships

6 Months Ended

Jun. 30, 2012

Related Party Transactions and Relationships [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 $26.7 million and $52.9 million, respectively, for the three months ended and year to date June 30, 2012.  These costs totaled $27.7 million and $57.2 million, respectively, for the same periods in 2011.  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.  At June 30, 2012, KCP&L had a $256.9 million money pool payable to GMO, which it repaid in July 2012.  The following table summarizes KCP&L’s related party receivables and payables.

	June 30			December 31
	2012			2011
	(millions)
Net receivable from (payable to) GMO	$	(246.6	)	$	24.1
Net receivable from Great Plains Energy		8.8			9.5

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Consolidated Balance Sheets (Parenthetical) (unaudited) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011
Utility Plant, at Original Cost
Nuclear fuel, amortization	$ 141.8	$ 132.7
Common shareholder's equity
Common stock - shares authorized (in shares)	250,000,000	250,000,000
Common stock-shares issued (in shares)	153,655,260	136,406,306
Treasury stock- shares (in shares)	240,468	264,567
Cumulative Preferred Stock [Member] | Preferred Stock 3 Point 80 [Member]
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100.00	$ 100.00
Cumulative preferred stock, Shares issued (in share)	100,000	100,000
Cumulative preferred stock, Dividend rate (in hundredths)	3.80%	3.80%
Cumulative Preferred Stock [Member] | Preferred Stock 4 Point 50 [Member]
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100.00	$ 100.00
Cumulative preferred stock, Shares issued (in share)	100,000	100,000
Cumulative preferred stock, Dividend rate (in hundredths)	4.50%	4.50%
Cumulative Preferred Stock [Member] | Preferred Stock 4 Point 20 [Member]
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100.00	$ 100.00
Cumulative preferred stock, Shares issued (in share)	70,000	70,000
Cumulative preferred stock, Dividend rate (in hundredths)	4.20%	4.20%
Cumulative Preferred Stock [Member] | Preferred Stock 4 Point 35 [Member]
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	$ 100.00	$ 100.00
Cumulative preferred stock, Shares issued (in share)	120,000	120,000
Cumulative preferred stock, Dividend rate (in hundredths)	4.35%	4.35%
Subsidiaries [Member]
Utility Plant, at Original Cost
Nuclear fuel, amortization	$ 141.8	$ 132.7
Common shareholder's equity
Common stock - shares authorized (in shares)	1,000	1,000
Common stock-shares issued (in shares)	1	1

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Pension Plans and Other Employee Benefits

6 Months Ended

Jun. 30, 2012

Pension Plans and Other Employee Benefits [Abstract]

Pension Plans and Other Employee Benefits

6.   PENSION PLANS AND OTHER EMPLOYEE BENEFITS

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

KCP&L and GMO record pension and post-retirement expense in accordance with rate orders from the MPSC and KCC that allow the difference between pension and post-retirement costs under Generally Accepted Accounting Principles (GAAP) and costs for ratemaking to be recognized as a regulatory asset or liability.  This difference between financial and regulatory accounting methods is due to timing and will be eliminated over the life of the plans.

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 June 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	8.8		$	7.8		$	0.8		$	0.8
Interest cost		12.3			12.6			2.0			1.9
Expected return on plan assets		(10.7	)		(9.7	)		(0.4	)		(0.5	)
Prior service cost		1.1			1.2			1.8			1.8
Recognized net actuarial (gain) loss		11.2			9.5			-			(0.2	)
Transition obligation		-			-			0.2			0.4
Settlement charge		-			0.2			-			-
Net periodic benefit costs before
regulatory adjustment		22.7			21.6			4.4			4.2
Regulatory adjustment		(3.8	)		(5.9	)		0.3			0.1
Net periodic benefit costs	$	18.9		$	15.7		$	4.7		$	4.3

	Pension Benefits						Other Benefits
Year to Date June 30	2012			2011			2012			2011
Components of net periodic benefit costs	(millions)
Service cost	$	17.7		$	15.6		$	1.6		$	1.6
Interest cost		24.5			25.1			3.9			3.9
Expected return on plan assets		(21.4	)		(19.3	)		(0.9	)		(0.9	)
Prior service cost		2.2			2.3			3.6			3.6
Recognized net actuarial (gain) loss		22.3			19.2			-			(0.3	)
Transition obligation		-			-			0.5			0.7
Settlement charge		-			0.2			-			-
Net periodic benefit costs before
regulatory adjustment		45.3			43.1			8.7			8.6
Regulatory adjustment		(7.7	)		(12.3	)		0.7			0.3
Net periodic benefit costs	$	37.6		$	30.8		$	9.4		$	8.9

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Regulatory Matters

6 Months Ended

Jun. 30, 2012

Regulatory Matters [Abstract]

Regulatory Matters

5.   REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

On April 20, 2012, KCP&L filed an application with The State Corporation Commission of the State of Kansas (KCC) to request an increase to its retail revenues of $63.6 million, with a return on equity of 10.4% and a rate-making equity ratio of 51.8%.  The request includes recovery of costs related to significant upgrades at its generating facilities, including environmental upgrades at the La Cygne Station; investments in additional wind generation; and increased investments in electrical infrastructure.  KCP&L is also requesting that KCC approve a change to depreciation rates to reflect the increase in plant in service as well as a change to the current method of allocating costs between its Kansas and Missouri jurisdictions to better reflect KCP&L’s summer peaking business.  Testimony from KCC staff and other parties regarding the case is expected in late August 2012, with an evidentiary hearing to occur in October 2012.  The increase to retail revenues is anticipated to be effective in January 2013.

KCP&L Missouri Rate Case Proceedings

On February 27, 2012, KCP&L filed an application with the Public Service Commission of the State of Missouri (MPSC) to request an increase to its retail revenues of $105.7 million, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%.  The request includes recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service and also includes a lower annual offset to the revenue requirement for the Missouri jurisdictional portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset).  KCP&L currently expects that it will not be able to achieve the $45.9 million wholesale margin offset currently reflected in its retail rates due to a decline in wholesale power prices, which is being driven by low natural gas prices.  Testimony from MPSC staff and other parties regarding the case was filed on August 2, 2012.  The MPSC staff’s testimony recommended a return on equity range of 8.0% to 9.0% and a revenue increase range of approximately $16.5 million to $33.7 million.  The outcome of the KCP&L Missouri rate case will likely be different from either of the positions of KCP&L or MPSC staff, though the decision of the MPSC cannot be predicted.  An evidentiary hearing is scheduled to occur in October 2012.  The increase to retail revenues is anticipated to be effective in January 2013.

In a March 2011 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 June 30, 2012, KCP&L and GMO had $127.0 million and $3.0 million, respectively, of unamortized deferred investment tax credits.

GMO Missouri Rate Case Proceedings

On February 27, 2012, GMO filed an application with the MPSC to request an increase to its retail revenues of $58.3 million for its Missouri Public Service division and $25.2 million for its St. Joseph Light & Power (L&P) division, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%.  The requests include recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service, costs related to energy efficiency and demand side management programs, and increased fuel costs.  Testimony from MPSC staff and other parties regarding the case is expected in mid-August 2012, with an evidentiary hearing to occur in October 2012.  The increase to retail revenues is anticipated to be effective in January 2013.

In December 2011, GMO filed a request with the MPSC seeking to recover costs for new and enhanced energy efficiency and demand side management programs under the Missouri Energy Efficiency Investment Act (MEEIA).  A decision on the MEEIA request is anticipated in the third quarter of 2012.

GMO Fuel Adjustment Clause (FAC) Prudence Review

GMO’s electric retail rates contain an FAC tariff under which 95% of the difference between actual fuel cost, purchased power costs and off-system sales margin and the amount provided in base rates for these costs is passed along to GMO’s customers.  The MPSC requires prudence reviews of the FAC no less frequently than at 18-month intervals.  On November 28, 2011, the MPSC staff filed its prudence review report for the 18-month prudence review period covering June 1, 2009 through November 30, 2010.  The MPSC staff recommended to the MPSC to order GMO to refund approximately $19 million, plus interest, to customers through an adjustment to its FAC because the MPSC staff asserts that GMO was imprudent in its use of natural gas hedges to mitigate risk associated with its future purchases in the spot power market.  In May 2012, the MPSC staff revised their recommended refund amount to $14.9 million, plus interest.  GMO is disputing the MPSC staff’s claim of imprudence and filed its testimony on February 22, 2012.  An evidentiary hearing was held June 5-6, 2012, and an order is expected in the third quarter of 2012.

SPP and NERC Inquiries

The Southwest Power Pool, Inc. (SPP) conducted a compliance inquiry regarding a transmission system outage that occurred in the St. Joseph, Missouri area in the summer of 2009.  The North American Electric Reliability Corporation (NERC) also investigated the circumstances surrounding this transmission system outage.  GMO was assessed an immaterial penalty in 2012 resolving this matter.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2012

Summary of Significant Accounting Policies [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 (KCP&L Receivables Company).

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

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

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

Basic and Diluted Earnings per Common Share Calculation

Basic and Diluted Earnings per Common Share Calculation

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

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

	Three Months Ended				Year to Date
	June 30				June 30
	2012		2011		2012			2011
Income	(millions, except per share amounts)
Net income	$	58.1	$	43.4	$	48.8		$	45.7
Less: net loss attributable to noncontrolling interest		-		-		(0.2	)		(0.1	)
Less: preferred stock dividend requirements		0.4		0.4		0.8			0.8
Earnings available for common shareholders	$	57.7	$	43.0	$	48.2		$	45.0
Common Shares Outstanding
Average number of common shares outstanding		139.6		135.6		137.7			135.5
Add: effect of dilutive securities		2.4		3.3		2.9			3.1
Diluted average number of common shares outstanding		142.0		138.9		140.6			138.6
Basic EPS	$	0.41	$	0.32	$	0.35		$	0.33
Diluted EPS	$	0.41	$	0.31	$	0.34		$	0.32

The computation of diluted EPS for the three months ended and year to date June 30, 2012, excludes anti-dilutive shares consisting of 10,617 restricted stock shares.

The computation of diluted EPS for the three months ended June 30, 2011, excludes anti-dilutive shares consisting of 201,571 performance shares, 12,115 restricted stock shares and 154,096 stock options.

The computation of diluted EPS year to date June 30, 2011, excludes anti-dilutive shares consisting of 201,571 performance shares, 43,641 restricted stock shares and 154,096 stock options.

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Derivative Instruments

6 Months Ended

Jun. 30, 2012

Derivative Instruments [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 purchases and normal sales (NPNS) election, which are accounted for by accrual accounting, are recorded on the balance sheet at fair value as an asset or liability.  Changes in the fair value of derivative instruments are recognized currently in net income unless specific hedge accounting criteria are met, except GMO utility operations hedges that are recorded to a regulatory asset or liability consistent with MPSC regulatory orders, as discussed below.

Great Plains Energy and KCP&L have posted collateral, in the ordinary course of business, for the aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a liability position.  At June 30, 2012, Great Plains Energy and KCP&L have posted collateral in excess of the aggregate fair value of its derivative instruments; therefore, if the credit risk-related contingent features underlying these agreements were triggered, Great Plains Energy and KCP&L would not be required to post additional collateral to its counterparties.

Commodity Risk Management

KCP&L’s risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales.  At June 30, 2012, KCP&L had fully hedged 2012 and had hedged 38% and 6%, respectively, of the 2013 and 2014 projected natural gas usage for retail load and firm MWh sales by utilizing futures contracts.  KCP&L has designated the natural gas hedges as cash flow hedges.  The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge.  To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense.  KCP&L has not recorded any ineffectiveness on natural gas hedges for the three months ended and year to date June 30, 2012 and 2011.

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 June 30, 2012, GMO had financial contracts in place to hedge approximately 99%, 59% and 8%, respectively, of the expected on-peak natural gas generation and natural gas equivalent purchased power price exposure for 2012, 2013 and 2014.  GMO has designated its natural gas hedges as economic hedges (non-hedging derivatives).  In connection with GMO’s 2005 Missouri electric rate case, it was agreed that the settlement costs of these contracts would be recognized in fuel expense.  The settlement cost is included in GMO’s FAC.  A regulatory asset has been 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, which has certain long-term natural gas contracts remaining from its former non-regulated trading operations, manages the daily delivery of its remaining contractual commitments with economic hedges (non-hedging derivatives) to reduce its exposure to changes in market prices.  Within the trading portfolio, MPS Merchant takes certain positions to hedge physical sale or purchase contracts.  MPS Merchant records the fair value of physical trading energy contracts as derivative assets or liabilities with an offsetting entry to the consolidated statements of income.

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

	June 30					December 31
	2012					2011
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Futures contracts
Cash flow hedges	$	1.6	$	(0.5	)	$	2.0	$	(0.5	)
Non-hedging derivatives		16.2		(3.0	)		23.6		(5.0	)
Forward contracts
Non-hedging derivatives		69.5		6.7			97.3		7.8
Option contracts
Non-hedging derivatives		-		-			0.4		-
KCP&L
Futures contracts
Cash flow hedges	$	1.6	$	(0.5	)	$	2.0	$	(0.5	)

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

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
June 30, 2012	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		6.7		3.0
Total Derivatives		$	6.7	$	3.5
December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.8		5.0
Total Derivatives		$	7.8	$	5.5

KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
June 30, 2012	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	-	$	0.5

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

Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
					Gain (Loss) Reclassified from
					Accumulated OCI into Income
					(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives				Income Statement
	(Effective Portion)				Classification	Amount
Three Months Ended June 30, 2012	(millions)					(millions)
Interest rate contracts		$	-		Interest charges	$	(5.0	)
Commodity contracts			0.1		Fuel		-
Income tax benefit			-		Income tax benefit		1.9
Total		$	0.1		Total	$	(3.1	)
Year to Date June 30, 2012
Interest rate contracts		$	-		Interest charges	$	(10.1	)
Commodity contracts			(0.2	)	Fuel		-
Income tax benefit			0.1		Income tax benefit		3.9
Total		$	(0.1	)	Total	$	(6.2	)
Three Months Ended June 30, 2011
Interest rate contracts		$	(5.8	)	Interest charges	$	(3.9	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			2.2		Income tax benefit		1.4
Total		$	(3.7	)	Total	$	(2.5	)
Year to Date June 30, 2011
Interest rate contracts		$	(5.3	)	Interest charges	$	(6.8	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			2.1		Income tax benefit		2.6
Total		$	(3.3	)	Total	$	(4.2	)

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 June 30, 2012	(millions)					(millions)
Interest rate contracts		$	-		Interest charges	$	(2.2	)
Commodity contracts			0.1		Fuel		-
Income tax benefit			-		Income tax benefit		0.9
Total		$	0.1		Total	$	(1.3	)
Year to Date June 30, 2012
Interest rate contracts		$	-		Interest charges	$	(4.4	)
Commodity contracts			(0.2	)	Fuel		-
Income tax benefit			0.1		Income tax benefit		1.7
Total		$	(0.1	)	Total	$	(2.7	)
Three Months Ended June 30, 2011
Interest rate contracts		$	-		Interest charges	$	(2.2	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			-		Income tax benefit		0.8
Total		$	(0.1	)	Total	$	(1.4	)
Year to Date June 30, 2011
Interest rate contracts		$	-		Interest charges	$	(4.4	)
Commodity contracts			(0.1	)	Fuel		-
Income tax benefit			-		Income tax benefit		1.7
Total		$	(0.1	)	Total	$	(2.7	)

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

Great Plains Energy
Derivatives in Regulatory Account Relationship
					Gain (Loss) Reclassified from
					Regulatory Account
	Amount of Gain (Loss)
	Recognized on Regulatory				Income Statement
	Account on Derivatives				Classification	Amount
Three Months Ended June 30, 2012		(millions)				(millions)
Commodity contracts		$	0.3		Fuel	$	(2.0	)
Total		$	0.3		Total	$	(2.0	)
Year to Date June 30, 2012
Commodity contracts		$	(2.7	)	Fuel	$	(2.7	)
Total		$	(2.7	)	Total	$	(2.7	)
Three Months Ended June 30, 2011
Commodity contracts		$	(1.0	)	Fuel	$	(1.0	)
Total		$	(1.0	)	Total	$	(1.0	)
Year to Date June 30, 2011
Commodity contracts		$	(1.3	)	Fuel	$	(2.9	)
Total		$	(1.3	)	Total	$	(2.9	)

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 $(0.3) million and $(1.1) million, respectively, for the three months ended and year to date June 30, 2012, and $(0.9) million and $1.0 million, respectively, for the same periods in 2011.

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

	Great Plains Energy						KCP&L
	June 30			December 31			June 30			December 31
	2012			2011			2012			2011
	(millions)
Current assets	$	10.9		$	11.3		$	10.9		$	11.3
Current liabilities		(79.1	)		(89.5	)		(57.8	)		(62.5	)
Noncurrent liabilities		(0.3	)		(0.2	)		(0.3	)		(0.2	)
Deferred income taxes		26.7			30.5			18.4			20.0
Total	$	(41.8	)	$	(47.9	)	$	(28.8	)	$	(31.4	)

Great Plains Energy’s accumulated OCI in the table above at June 30, 2012, includes $20.6 million that is expected to be reclassified to expenses over the next twelve months.  KCP&L’s accumulated OCI in the table above at June 30, 2012, includes $9.1 million that is expected to be reclassified to expense over the next twelve months.

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Long-Term Debt

6 Months Ended

Jun. 30, 2012

Debt Disclosure [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.

		June 30			December 31
	Year Due	2012			2011
KCP&L		(millions)
General Mortgage Bonds
4.97% EIRR bonds(a)	2015-2035	$	106.9		$	119.3
7.15% Series 2009A (8.59% rate)(b)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
5.85% Series (5.72% rate)(b)	2017		250.0			250.0
6.375% Series (7.49% rate)(b)	2018		350.0			350.0
6.05% Series (5.78% rate)(b)	2035		250.0			250.0
5.30% Series	2041		400.0			400.0
EIRR bonds 4.90% Series 2008	2038		23.4			23.4
Other	2012-2018		2.9			2.9
Current maturities			(0.4	)		(12.7	)
Unamortized discount			(4.0	)		(4.2	)
Total KCP&L excluding current maturities(c)			1,902.0			1,901.9
Other Great Plains Energy
GMO First Mortgage Bonds 9.44% Series	2013-2021		10.1			11.2
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.341% Wamego Series 1996(d)	2026		7.3			7.3
0.341% State Environmental 1993(d)	2028		5.0			5.0
GMO Senior Notes
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			-			16.3
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(b)	2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(b)	2017		100.0			100.0
Great Plains Energy 4.85% Senior Notes (7.34% rate)(b)	2021		350.0			350.0
Great Plains Energy 5.292% Senior Notes	2022		287.5			-
Great Plains Energy 10.00% Equity Units Subordinated Notes			-			287.5
Current maturities			(506.7	)		(788.7	)
Unamortized discount and premium, net			5.7			(0.7	)
Total Great Plains Energy excluding current maturities(c)		$	3,013.4		$	2,742.3
(a) Weighted-average interest rates at June 30, 2012
(b) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(c) Does not include $39.5 million EIRR Series 1993B, $63.3 million EIRR Series 2007 A-1 and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L
(d) Variable rate

Fair Value of Long-Term Debt

The fair value of long-term debt is categorized as a Level 2 liability within the fair value hierarchy as it is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices are not available.  At June 30, 2012, and December 31, 2011, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.5 billion and $3.9 billion, respectively.  At June 30, 2012, and December 31, 2011, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.9 billion and $2.2 billion, respectively.

GMO Senior Notes

GMO repaid its $500 million 11.875% Senior Notes that matured in July 2012.

Great Plains Energy Equity Units

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

In March 2012, Great Plains Energy remarketed $287.4 million of its 10% subordinated notes that were originally issued as components of the Equity Units as senior notes at a new interest rate of 5.292%.  The 5.292% Senior Notes mature in June 2022.

Great Plains Energy did not receive any proceeds from the remarketing.  Proceeds from the remarketing were used to purchase a portfolio of U.S. Treasury securities that were pledged as collateral to secure the Equity Unit holders’ obligation under the purchase contract.  There were also $0.1 million of purchase contracts that settled early and did not participate in the remarketing.

In June 2012, Great Plains Energy settled the obligations under the purchase contracts underlying its 5.7 million outstanding Equity Units by issuing approximately 17.1 million shares of its common stock in exchange for $287.4 million, which had been raised through the remarketing completed in March 2012.  The settlement rate of 2.9762 was determined according to the applicable market value of the Company’s common stock at the settlement date.  The applicable market value of $20.05 was measured by the average of the closing price per share of the Company’s common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding June 15, 2012.

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Equity Compensation

6 Months Ended

Jun. 30, 2012

Equity Compensation [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, restricted stock units, bonus shares, stock options, stock appreciation rights, limited stock appreciation rights, director shares, director deferred share units and performance shares to directors, officers and other employees of Great Plains Energy and KCP&L.  Forfeiture rates are based on historical forfeitures and future expectations and are reevaluated annually.

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

	Three Months Ended				Year to Date
	June 30				June 30
	2012		2011		2012		2011
Great Plains Energy	(millions)
Compensation expense	$	1.8	$	1.7	$	2.8	$	3.3
Income tax benefit		0.7		0.8		1.3		1.4
KCP&L
Compensation expense	$	1.4	$	1.2	$	2.1	$	2.3
Income tax benefit		0.5		0.6		1.0		1.0

Performance Shares

Performance share activity year to date June 30, 2012, is summarized in the following table.  Performance adjustment represents the number of shares of common stock related to performance shares ultimately issued that can vary from the number of performance shares initially granted depending on Great Plains Energy’s performance over a stated period of time.

	Performance			Grant Date
	Shares			Fair Value*
Beginning balance		442,042		$	21.06
Granted		161,627			19.01
Forfeited		(50,685	)		18.71
Performance adjustment		(160,717	)
Ending balance		392,267			22.98
* weighted-average

At June 30, 2012, the remaining weighted-average contractual term was 1.4 years.  The weighted-average grant-date fair value of shares granted was $20.99 and $19.01 for the three months ended and year to date June 30, 2012, respectively.  The weighted-average grant-date fair value of shares granted was $26.28 and $22.48 for the three months ended and year to date June 30, 2011, respectively.  At June 30, 2012, there was $3.8 million of total unrecognized compensation expense, net of forfeiture rates, related to performance shares granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term.  There were no performance shares earned and paid year to date June 30, 2012.  The total fair value of performance shares earned and paid year to date June 30, 2011, was $0.8 million.

The fair value of performance share awards is estimated using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of expected volatilities, dividend yield and risk-free rates.  Expected volatility is based on daily stock price change during a historical period commensurate with the remaining term of the performance period of the grant.  The risk-free rate is based upon the rate at the time of the evaluation for zero-coupon government bonds with a maturity consistent with the remaining performance period of the grant.  The dividend yield is based on the most recent dividends paid and the actual closing stock price on the valuation date.  For shares granted in 2012, inputs for expected volatility, dividend yield and risk-free rates were 21%, 4.32% and 0.40%, respectively.

Restricted Stock

Restricted stock activity year to date June 30, 2012, is summarized in the following table.

	Nonvested			Grant Date
	Restricted Stock			Fair Value*
Beginning balance		386,183		$	17.06
Granted and issued		162,129			19.69
Vested		(204,838	)		15.76
Forfeited		(50,685	)		19.66
Ending balance		292,789			18.97
* weighted-average

At June 30, 2012, the remaining weighted-average contractual term was 2.0 years.  The weighted-average grant-date fair value of shares granted for the three months ended and year to date June 30, 2012, was $19.89 and $19.69, respectively.  The weighted-average grant-date fair value of shares granted for the three months ended and year to date June 30, 2011, was $20.26 and $19.26, respectively.  At June 30, 2012, there was $3.4 million of total unrecognized compensation expense, net of forfeiture rates, related to nonvested restricted stock granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term.  The total fair value of shares vested for the three months ended and year to date June 30, 2012, was $1.3 million and $3.2 million, respectively.  The total fair value of shares vested for the three months ended and year to date June 30, 2011, was $0.6 million and $2.6 million, respectively.

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

6 Months Ended

Jun. 30, 2012

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

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

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 December 2016.  The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time.  A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At June 30, 2012, Great Plains Energy was in compliance with this covenant.  At June 30, 2012, Great Plains Energy had $31.0 million of outstanding cash borrowings at a weighted-average interest rate of 2.0% and had issued letters of credit totaling $4.8 million under the credit facility.  At December 31, 2011, Great Plains Energy had $22.0 million of outstanding cash borrowings at a weighted-average interest rate of 2.06% and had issued letters of credit totaling $11.6 million under the credit facility.

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

KCP&L’s $600 million revolving credit facility with a group of banks provides support for its issuance of commercial paper and other general corporate purposes and expires in December 2016.  Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities.  A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At June 30, 2012, KCP&L was in compliance with this covenant.  At June 30, 2012, KCP&L had $91.0 million of commercial paper outstanding at a weighted-average interest rate of 0.46%, had issued letters of credit totaling $18.2 million and had no outstanding cash borrowings under the credit facility.  At December 31, 2011, KCP&L had $227.0 million of commercial paper outstanding at a weighted-average interest rate of 0.50%, had issued letters of credit totaling $21.5 million and had no outstanding cash borrowings under the credit facility.

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

GMO’s $450 million revolving credit facility with a group of banks provides support for its issuance of commercial paper and other general corporate purposes and expires in December 2016.  Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities.  A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At June 30, 2012, GMO was in compliance with this covenant.  At June 30, 2012, GMO had issued letters of credit totaling $13.2 million and had no outstanding commercial paper or cash borrowings under the credit facility.  At December 31, 2011, GMO had $40.0 million of commercial paper outstanding at a weighted-average interest rate of 0.88%, had issued letters of credit totaling $13.2 million and had no outstanding cash borrowings under the credit facility.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

10.   COMMITMENTS AND CONTINGENCIES

Environmental Matters

Great Plains Energy and KCP&L are subject to extensive federal, state and local environmental laws, regulations and permit requirements relating to air and water quality, waste management and disposal, natural resources and health and safety.  In addition to imposing continuing compliance obligations and remediation costs, these laws, regulations and permits authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions.  The cost of complying with current and future environmental requirements is expected to be material to Great Plains Energy and KCP&L.  Failure to comply with environmental requirements or to timely recover environmental costs through rates could have a material effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

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

Air and Climate Change Overview

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

Great Plains Energy’s and KCP&L’s current estimate of capital expenditures (exclusive of Allowance for Funds Used During Construction (AFUDC) and property taxes) to comply with the currently-effective Clean Air Interstate Rule (CAIR), the replacement to CAIR or the Cross-State Air Pollution Rule (CSAPR), the best available retrofit technology (BART) rule, the SO2 National Ambient Air Quality Standard (NAAQS), the industrial boiler rule and the Mercury and Air Toxics Standards (MATS) rule that would reduce emissions of toxic air pollutants, (all of which are discussed below) is approximately $1 billion.  The actual cost of compliance with any existing, proposed or future rules may be significantly different from the cost estimate provided.

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

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

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

·   KCP&L’s Montrose No. 3 full AQCS installed by approximately 2020; and

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

In September 2011, KCP&L commenced construction of the La Cygne project.  Other capital projects at KCP&L’s Montrose Nos. 1 and 2 and GMO’s Sibley Nos. 1 and 2 and Lake Road No. 4/6 are possible but are currently considered less likely.  In connection with KCP&L’s and GMO’s Integrated Resource Plan (IRP) filings with the MPSC in April 2012, the economics around Montrose No. 2 and Lake Road No. 4/6 have improved.  Pending further evaluation, these projects may move from less likely to more likely but it is not expected to materially impact the overall $1 billion current estimate of capital expenditures.  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 $1 billion current estimate of capital expenditures does not reflect the non-capital costs the Companies incur on an ongoing basis to comply with environmental laws, which may increase in the future due to current or future environmental laws.  The Companies expect to seek recovery of the costs associated with environmental requirements through rate increases; however, there can be no assurance that such rate increases would be granted.  The Companies may be subject to materially adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies’ environmental reputation.

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

The CAIR requires reductions in SO2 and 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.

In July 2008, the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit Court) vacated CAIR in its entirety and remanded the matter to the EPA to promulgate a new rule consistent with its opinion.  In December 2008, the court issued an order reinstating CAIR pending EPA’s development of a replacement regulation on remand.

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

Compliance with the CSAPR was scheduled to begin in 2012.  Multiple states, utilities and other parties, including KCP&L, filed requests for reconsideration and stays with the EPA and/or the D.C. Circuit Court.  In December 2011, the D.C. Circuit Court issued an order staying the CSAPR pending the Court's resolution of the petitions for review of the rule.  The order requires the EPA to continue administering the CAIR while the CSAPR is stayed.

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

Best Available Retrofit Technology (BART) Rule

The EPA BART rule directs state air quality agencies to identify whether visibility-reducing emissions from sources subject to BART are below limits set by the state or whether retrofit measures are needed to reduce emissions.  BART applies to specific eligible facilities including KCP&L’s La Cygne Nos. 1 and 2 in Kansas, KCP&L’s Iatan No. 1, in which GMO has an 18% interest, and KCP&L’s Montrose No. 3 in Missouri, GMO’s Sibley Unit No. 3 and Lake Road Unit No. 6 in Missouri and Westar Energy, Inc.’s (Westar) Jeffrey Unit Nos. 1 and 2 in Kansas, in which GMO has an 8% interest.  Both Missouri and Kansas have submitted BART plans to the EPA.  In December 2011, the EPA approved the Kansas BART plan.

In May 2012, the EPA finalized a rule that approves the CSAPR as an alternative to BART.  As a result, states in the CSAPR will be able to substitute participation in the CSAPR for source-specific BART.  In addition, the EPA finalized a limited disapproval of the BART plan that had been submitted by Missouri because it relied on requirements of the CAIR to satisfy certain regional haze requirements.  To address deficiencies in a CAIR-dependent BART plan, the EPA promulgated a Federal Implementation Plan (FIP) to replace reliance on CAIR with reliance on the CSAPR in the BART plan for Missouri.  In June 2012, the EPA finalized a limited approval of the Missouri BART plan that does not include the FIP-approved component of the BART plan.

Mercury and Air Toxics Standards (MATS) Rule

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

In December 2011, the EPA finalized theMATS Rule that will reduce emissions of toxic air pollutants, also known as hazardous air pollutants, from new and existing coal- and oil-fired EGUs with a capacity of greater than 25 MWs.  The rule establishes numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrochloric acid (a surrogate for acid gases).  The rule establishes work practices, instead of numerical emission limits, for organic air toxics, including dioxin/furan.  Compliance with the rule would need to be achieved by installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market or a combination of these and other alternatives.  The rule allows three years for compliance with authority for state permitting authorities to grant an additional year as needed for technology installation.  The EPA indicated that it expects this option to be broadly available.  The Missouri Department of Natural Resources (MDNR) has granted an extension at KCP&L’s Montrose Station and at GMO’s Lake Road and Sibley Stations.  The Kansas Department of Health and Environment (KDHE) has granted an extension at KCP&L’s La Cygne Station.

Industrial Boiler Rule

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

New Source Review

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

In 2010, Westar settled a lawsuit filed by the Department of Justice on behalf of the EPA.  The lawsuit asserted that certain projects completed at the Jeffrey Energy Center violated certain requirements of the New Source Review program.  The Jeffrey Energy Center is 92% owned by Westar and operated exclusively by Westar.  GMO has an 8% interest in the Jeffrey Energy Center and is generally responsible for its 8% share of the facility’s operating costs and capital expenditures.  The settlement agreement required, among other things, the installation of a selective catalytic reduction (SCR) system at one of the three Jeffrey Energy Center units by the end of 2014.  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.  GMO expects to seek recovery of its share of these costs through rate increases; however, there can be no assurance that such rate increases would be granted.

KCP&L had received requests for information from the KDHE pertaining to a past La Cygne No. 1 scrubber project.  In April 2012, KCP&L and KDHE agreed to resolve this matter with KCP&L completing supplemental environmental projects in the amount of $800,000 and paying a penalty in the amount of $350,000.

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 designed to offset CO2 emissions.

KCP&L agreed in the Collaboration Agreement to pursue increasing its wind generation capacity by 400 MWs by the end of 2012.  KCP&L and GMO have added 379 MWs of wind generation and have also added the equivalent CO2 offset of 21 MWs of wind through solar, landfill gas and other projects that were not required under the Collaboration Agreement.

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

Also in the Collaboration Agreement, KCP&L agreed to offset an additional 711,000 tons of CO2 by the end of 2012, which it has done.

Climate Change

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

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

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

In March 2012, the EPA proposed new source performance standards for emissions of CO2 for new affected fossil-fuel-fired electric utility generating units.  This action pursuant to the Clean Air Act would, for the first time, set national limits on the amount of CO2 that power plants built in the future can emit.  The proposal would not apply to Great Plains Energy’s and KCP&L’s existing units including modifications to those units.

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

KCP&L and GMO project that they will be compliant with the Missouri renewable requirements, exclusive of the solar requirement, through 2023 for KCP&L and 2018 for GMO.  KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri solar requirements for the foreseeable future.  KCP&L also projects that it will be compliant with the Kansas renewable requirements through 2015.

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

SO2 NAAQS

In June 2010, the EPA strengthened the primary NAAQS for SO2 by establishing a new 1-hour standard at a level of 0.075 ppm and revoking the two existing primary standards of 0.140 ppm evaluated over 24 hours and 0.030 ppm evaluated over an entire year.  In July 2011, the MDNR recommended to the EPA that part of Jackson County, Missouri, which is in the Companies’ service territory, be designated a nonattainment area for the new 1-hour SO2 standard.  In April 2012, the EPA announced it is seeking additional input from states, tribes, and other interested parties to refine the agency's approach for implementing the SO2 standard.

Particulate Matter (PM)NAAQS

In June 2012, the EPA proposed to strengthen the NAAQS for fine particulate matter (PM2.5).  The proposal strengthens the annual primary standard and seeks comment on alternative levels of the annual primary standard.  The proposal retains the existing 24‐hour PM2.5 primary standard, coarse particle matter (PM10) primary standard, and secondary standards for PM2.5 and PM10 identical to the primary standards.  The proposal also includes a separate PM2.5 standard to improve visibility.  The EPA is proposing two visibility options for this 24‐hour standard and is seeking comment on alternative levels. The EPA agreed to finalize the rule by December 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.

Water

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

In March 2011, the EPA proposed regulations pursuant to Section 316(b) of the Clean Water Act regarding cooling water intake structures pursuant to a court approved settlement.  KCP&L generation facilities with cooling water intake structures would be subject to a limit on how many fish can be killed by being pinned against intake screens (impingement) and would be required to conduct studies to determine whether and what site-specific controls, if any, would be required to reduce the number of aquatic organisms drawn into cooling water systems (entrainment).  The EPA agreed to finalize the rule by June 2013.  Although the impact on Great Plains Energy’s and KCP&L’s operations will not be known until after the rule is finalized, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

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

Additionally, the EPA plans to revise the existing standards for water discharges from coal-fired power plants with a proposed rule in November 2012 and final action in April 2014.  Until a rule is proposed and finalized, the financial and operational impacts to Great Plains Energy and KCP&L cannot be determined.

Solid Waste

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

Remediation

Certain federal and state laws, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), hold current and previous owners or operators of contaminated facilities and persons who arranged for the disposal or treatment of hazardous substances liable for the cost of investigation and cleanup.  CERCLA and other laws also authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment.  GMO is named as a potentially responsible party at two disposal sites for polychlorinated biphenyl (PCB) contamination, and retains some environmental liability for several operations and investments it no longer owns.  In addition, GMO also owns, or has acquired liabilities from companies that once owned or operated, former manufactured gas plant (MGP) sites, which are subject to the supervision of the EPA and various state environmental agencies.

At June 30, 2012, and December 31, 2011, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site.  At June 30, 2012, and December 31, 2011, 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 June 30, 2012, and December 31, 2011, Great Plains Energy had $2.1 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB contaminated sites and retained liabilities.  This estimate was based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary.  This estimate could change materially after further investigation, and could also be affected by the actions of environmental agencies and the financial viability of other potentially responsible parties; however, given the uncertainty of these items the possible loss or range of loss in excess of the amount accrued is not estimable.

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

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Taxes (Tables)

6 Months Ended

Jun. 30, 2012

Taxes [Abstract]

Components of income tax expense (benefit)

	Three Months Ended						Year to Date
	June 30						June 30
Great Plains Energy	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	(3.3	)	$	2.7		$	(3.3	)	$	3.8
State		0.4			(4.7	)		0.3			(4.0	)
Foreign		-			(0.1	)		-			(0.4	)
Total		(2.9	)		(2.1	)		(3.0	)		(0.6	)
Deferred income taxes
Federal		30.8			32.3			22.5			28.9
State		5.1			11.4			4.3			7.4
Total		35.9			43.7			26.8			36.3
Noncurrent income taxes
Federal		(0.2	)		(19.0	)		(0.2	)		(18.0	)
State		-			(2.0	)		-			(1.9	)
Foreign		(0.4	)		(0.1	)		(0.1	)		0.2
Total		(0.6	)		(21.1	)		(0.3	)		(19.7	)
Investment tax credit amortization		(0.6	)		(0.7	)		(1.2	)		(0.8	)
Income tax expense	$	31.8		$	19.8		$	22.3		$	15.2

	Three Months Ended						Year to Date
	June 30						June 30
KCP&L	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	0.1		$	1.3		$	0.2		$	2.4
State		0.1			0.2			0.1			0.5
Total		0.2			1.5			0.3			2.9
Deferred income taxes
Federal		19.4			23.2			16.1			19.9
State		4.2			4.7			4.1			4.5
Total		23.6			27.9			20.2			24.4
Noncurrent income taxes
Federal		(0.3	)		(11.5	)		0.1			(10.6	)
State		(0.1	)		(1.2	)		-			(1.1	)
Total		(0.4	)		(12.7	)		0.1			(11.7	)
Investment tax credit amortization		(0.4	)		(0.5	)		(0.9	)		(0.5	)
Income tax expense	$	23.0		$	16.2		$	19.7		$	15.1

Income tax expense (benefit) and effective income tax rates

Great Plains Energy	Income Tax Expense						Income Tax Rate
Three Months Ended June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	31.5		$	22.1			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.0			1.1			1.2			1.6
Amortization of investment tax credits		(0.6	)		(0.7	)		(0.7	)		(1.1	)
Federal income tax credits		(3.3	)		(3.8	)		(3.6	)		(6.0	)
State income taxes		3.5			2.6			3.9			4.1
Changes in uncertain tax positions, net		(0.3	)		(1.6	)		(0.4	)		(2.5	)
Valuation allowance		0.1			0.2			0.1			0.3
Other		(0.1	)		(0.1	)		-			-
Total	$	31.8		$	19.8			35.5	%		31.4	%

Great Plains Energy	Income Tax Expense						Income Tax Rate
Year to Date June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	25.0		$	21.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		2.1			1.9			3.0			3.0
Amortization of investment tax credits		(1.2	)		(0.8	)		(1.8	)		(1.4	)
Federal income tax credits		(6.1	)		(6.8	)		(8.6	)		(11.1	)
State income taxes		2.9			3.0			4.1			4.9
Changes in uncertain tax positions, net		(0.1	)		(1.3	)		(0.1	)		(2.2	)
Valuation allowance		0.1			(2.2	)		0.1			(3.6	)
Other		(0.4	)		-			(0.4	)		0.4
Total	$	22.3		$	15.2			31.3	%		25.0	%

KCP&L	Income Tax Expense						Income Tax Rate
Three Months Ended June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	23.4		$	17.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		0.9			0.8			1.3			1.6
Amortization of investment tax credits		(0.4	)		(0.5	)		(0.7	)		(1.0	)
Federal income tax credits		(3.3	)		(3.7	)		(4.9	)		(7.6	)
State income taxes		2.6			1.8			4.0			3.8
Changes in uncertain tax positions, net		-			0.4			-			0.9
Other		(0.2	)		-			(0.2	)		(0.2	)
Total	$	23.0		$	16.2			34.5	%		32.5	%

KCP&L	Income Tax Expense						Income Tax Rate
Year to Date June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	23.0		$	18.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.8			1.6			2.7			3.0
Amortization of investment tax credits		(0.9	)		(0.5	)		(1.4	)		(0.9	)
Federal income tax credits		(6.1	)		(6.7	)		(9.3	)		(12.9	)
State income taxes		2.6			2.0			4.1			3.9
Changes in uncertain tax positions, net		-			0.4			-			0.8
Other		(0.7	)		(0.1	)		(1.1	)		(0.3	)
Total	$	19.7		$	15.1			30.0	%		28.6	%

Liability for unrecognized tax benefits

	Great Plains Energy						KCP&L
	June 30			December 31			June 30			December 31
	2012			2011			2012			2011
	(millions)
Beginning balance January 1	$	24.0		$	42.0		$	8.7		$	19.1
Additions for current year tax positions		1.5			1.4			1.4			-
Additions for prior year tax positions		-			2.4			-			2.3
Reductions for prior year tax positions		(1.4	)		(20.9	)		(1.3	)		(12.6	)
Statute expirations		-			(0.7	)		-			(0.1	)
Foreign currency translation adjustments		(0.1	)		(0.2	)		-			-
Ending balance	$	24.0		$	24.0		$	8.8		$	8.7

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012 Derivative Financial Instruments, Assets [Member]	Jun. 30, 2011 Derivative Financial Instruments, Assets [Member]	Jun. 30, 2012 Derivative Financial Instruments, Assets [Member]	Jun. 30, 2011 Derivative Financial Instruments, Assets [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Netting and Collateral [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Netting and Collateral [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 1 [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 1 [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 3 [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 3 [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Netting and Collateral [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Netting and Collateral [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 1 [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 1 [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 2 [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 2 [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 3 [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Kansas City Power and Light Company [Member] Fair Value, Inputs, Level 3 [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Estimate of Fair Value, Fair Value Disclosure [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Netting and Collateral [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Netting and Collateral [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Fair Value, Inputs, Level 1 [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Fair Value, Inputs, Level 1 [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Fair Value, Inputs, Level 2 [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Fair Value, Inputs, Level 2 [Member]		Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Fair Value, Inputs, Level 3 [Member]		Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Other Great Plains [Member] Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Derivative instruments, assets					$ 6.7	[1]	$ 7.8	[1]	$ 0	[2]	$ 0	[2]	$ 0	[1]	$ 0	[1]	$ 4.5	[1]	$ 4.7	[1]	$ 2.2	[1]	$ 3.1	[1]																					$ 6.7	[1]	$ 7.8	[1]	$ 0	[2]	$ 0	[2]	$ 0	[1]	$ 0	[1]	$ 4.5	[1]	$ 4.7	[1]	$ 2.2	[1]	$ 3.1	[1]
Nuclear decommissioning trust [Abstract]
Equity securities related to nuclear decommissioning trust																									91.3		84.3		0	[2]	0	[2]	91.3		84.3		0		0		0		0
Debt securities related to nuclear decommissioning trust [Abstract]
U.S. Treasury																									16.2		15.3		0	[2]	0	[2]	16.2		15.3		0		0		0		0
U.S. Agency																									4.3		3.6		0	[2]	0	[2]	0		0		4.3		3.6		0		0
State and local obligations																									2.7		2.6		0	[2]	0	[2]	0		0		2.7		2.6		0		0
Corporate bonds																									26.9		26.4		0	[2]	0	[2]	0		0		26.9		26.4		0		0
Foreign governments																									0.7		0.7		0	[2]	0	[2]	0		0		0.7		0.7		0		0
Other assets related to nuclear decommissioning trust																									0.5		(0.6)		0	[2]	0	[2]	0		0		0.5		(0.6)		0		0
Total nuclear decommissioning trust					142.6	[3]	132.3	[3]	0	[2]	0	[2]	107.5	[3]	99.6	[3]	35.1	[3]	32.7	[3]	0	[3]	0	[3]	142.6	[3]	132.3	[3]	0	[2]	0	[2]	107.5	[3]	99.6	[3]	35.1	[3]	32.7	[3]	0	[3]	0	[3]
SERP rabbi trust [Abstract]
Equity securities related to SERP rabbi trust																																													0.2		0.2		0	[2]	0	[2]	0.2		0.2		0		0		0		0
Debt securities related to SERP rabbi trust																																													0.1		0.1		0	[2]	0	[2]	0		0		0.1		0.1		0		0
Total SERP rabbi trust					0.3	[4]	0.3	[4]	0	[2]	0	[2]	0.2	[4]	0.2	[4]	0.1	[4]	0.1	[4]	0	[4]	0	[4]																					0.3	[4]	0.3	[4]	0	[2]	0	[2]	0.2	[4]	0.2	[4]	0.1	[4]	0.1	[4]	0	[4]	0	[4]
Total assets					149.6		140.4		0	[2]	0	[2]	107.7		99.8		39.7		37.5		2.2		3.1		142.6		132.3		0	[2]	0	[2]	107.5		99.6		35.1		32.7		0		0		7.0		8.1		0	[2]	0	[2]	0.2		0.2		4.6		4.8		2.2		3.1
Liabilities [Abstract]
Derivative instruments, liabilities					0	[1]	0	[1]	(3.5)	[2]	(5.5)	[2]	3.5	[1]	5.5	[1]	0	[1]	0	[1]	0	[1]	0	[1]	0	[1]	0	[1]	(0.5)	[2]	(0.5)	[2]	0.5	[1]	0.5	[1]	0	[1]	0	[1]	0	[1]	0	[1]	0	[1]	0	[1]	(3.0)	[2]	(5.0)	[2]	3.0	[1]	5.0	[1]	0	[1]	0	[1]	0	[1]	0	[1]
Total liabilities					0		0		(3.5)	[2]	(5.5)	[2]	3.5		5.5		0		0		0		0		0		0		(0.5)	[2]	(0.5)	[2]	0.5		0.5		0		0		0		0		0		0		(3.0)	[2]	(5.0)	[2]	3.0		5.0		0		0		0		0
Cash and cash equivalents from nuclear decommissioning trust excluded from fair value disclosure																									2.3		3.0
Cash and cash equivalents from SERP rabbi trust excluded from fair value disclosure																																													20.2		20.3
Cash collateral posted with third parties as part of netting agreements					3.4		5.5
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	2.4	5.7	3.1	3.7
Total realized/unrealized gains or (losses) included in non-operating income	0.9	2.1	1.1	7.1
Settlements	(1.1)	(2.9)	(2.0)	(5.9)
Balance at end of period	2.2	4.9	2.2	4.9
Total unrealized gains and (losses) included in non-operating income relating to assets and liabilities still on the consolidated balance sheet at period end	$ (0.1)	$ (0.6)	$ (0.7)	$ 1.5

[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 June 30, 2012, and December 31, 2011, Great Plains Energy netted $3.4 million and $5.5 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 $2.3 million and $3.0 million at June 30, 2012, and December 31, 2011, 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 $20.2 million and $20.3 million at June 30, 2012, and December 31, 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

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Taxes

6 Months Ended

Jun. 30, 2012

Taxes [Abstract]

Taxes

15.   TAXES

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

	Three Months Ended						Year to Date
	June 30						June 30
Great Plains Energy	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	(3.3	)	$	2.7		$	(3.3	)	$	3.8
State		0.4			(4.7	)		0.3			(4.0	)
Foreign		-			(0.1	)		-			(0.4	)
Total		(2.9	)		(2.1	)		(3.0	)		(0.6	)
Deferred income taxes
Federal		30.8			32.3			22.5			28.9
State		5.1			11.4			4.3			7.4
Total		35.9			43.7			26.8			36.3
Noncurrent income taxes
Federal		(0.2	)		(19.0	)		(0.2	)		(18.0	)
State		-			(2.0	)		-			(1.9	)
Foreign		(0.4	)		(0.1	)		(0.1	)		0.2
Total		(0.6	)		(21.1	)		(0.3	)		(19.7	)
Investment tax credit amortization		(0.6	)		(0.7	)		(1.2	)		(0.8	)
Income tax expense	$	31.8		$	19.8		$	22.3		$	15.2

	Three Months Ended						Year to Date
	June 30						June 30
KCP&L	2012			2011			2012			2011
Current income taxes	(millions)
Federal	$	0.1		$	1.3		$	0.2		$	2.4
State		0.1			0.2			0.1			0.5
Total		0.2			1.5			0.3			2.9
Deferred income taxes
Federal		19.4			23.2			16.1			19.9
State		4.2			4.7			4.1			4.5
Total		23.6			27.9			20.2			24.4
Noncurrent income taxes
Federal		(0.3	)		(11.5	)		0.1			(10.6	)
State		(0.1	)		(1.2	)		-			(1.1	)
Total		(0.4	)		(12.7	)		0.1			(11.7	)
Investment tax credit amortization		(0.4	)		(0.5	)		(0.9	)		(0.5	)
Income tax expense	$	23.0		$	16.2		$	19.7		$	15.1

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 June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	31.5		$	22.1			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.0			1.1			1.2			1.6
Amortization of investment tax credits		(0.6	)		(0.7	)		(0.7	)		(1.1	)
Federal income tax credits		(3.3	)		(3.8	)		(3.6	)		(6.0	)
State income taxes		3.5			2.6			3.9			4.1
Changes in uncertain tax positions, net		(0.3	)		(1.6	)		(0.4	)		(2.5	)
Valuation allowance		0.1			0.2			0.1			0.3
Other		(0.1	)		(0.1	)		-			-
Total	$	31.8		$	19.8			35.5	%		31.4	%

Great Plains Energy	Income Tax Expense						Income Tax Rate
Year to Date June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	25.0		$	21.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		2.1			1.9			3.0			3.0
Amortization of investment tax credits		(1.2	)		(0.8	)		(1.8	)		(1.4	)
Federal income tax credits		(6.1	)		(6.8	)		(8.6	)		(11.1	)
State income taxes		2.9			3.0			4.1			4.9
Changes in uncertain tax positions, net		(0.1	)		(1.3	)		(0.1	)		(2.2	)
Valuation allowance		0.1			(2.2	)		0.1			(3.6	)
Other		(0.4	)		-			(0.4	)		0.4
Total	$	22.3		$	15.2			31.3	%		25.0	%

KCP&L	Income Tax Expense						Income Tax Rate
Three Months Ended June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	23.4		$	17.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		0.9			0.8			1.3			1.6
Amortization of investment tax credits		(0.4	)		(0.5	)		(0.7	)		(1.0	)
Federal income tax credits		(3.3	)		(3.7	)		(4.9	)		(7.6	)
State income taxes		2.6			1.8			4.0			3.8
Changes in uncertain tax positions, net		-			0.4			-			0.9
Other		(0.2	)		-			(0.2	)		(0.2	)
Total	$	23.0		$	16.2			34.5	%		32.5	%

KCP&L	Income Tax Expense						Income Tax Rate
Year to Date June 30	2012			2011			2012			2011
	(millions)
Federal statutory income tax	$	23.0		$	18.4			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		1.8			1.6			2.7			3.0
Amortization of investment tax credits		(0.9	)		(0.5	)		(1.4	)		(0.9	)
Federal income tax credits		(6.1	)		(6.7	)		(9.3	)		(12.9	)
State income taxes		2.6			2.0			4.1			3.9
Changes in uncertain tax positions, net		-			0.4			-			0.8
Other		(0.7	)		(0.1	)		(1.1	)		(0.3	)
Total	$	19.7		$	15.1			30.0	%		28.6	%

Uncertain Tax Positions

At June 30, 2012, and December 31, 2011, Great Plains Energy had $24.0 million of liabilities related to unrecognized tax benefits.  Of these amounts, $11.7 million and $11.8 million at June 30, 2012, and December 31, 2011, respectively, are expected to impact the effective tax rate if recognized.  

At June 30, 2012, and December 31, 2011, KCP&L had $8.8 million and $8.7 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $0.2 million at June 30, 2012, and December 31, 2011, is expected to impact the effective tax rate if recognized. 

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

	Great Plains Energy						KCP&L
	June 30			December 31			June 30			December 31
	2012			2011			2012			2011
	(millions)
Beginning balance January 1	$	24.0		$	42.0		$	8.7		$	19.1
Additions for current year tax positions		1.5			1.4			1.4			-
Additions for prior year tax positions		-			2.4			-			2.3
Reductions for prior year tax positions		(1.4	)		(20.9	)		(1.3	)		(12.6	)
Statute expirations		-			(0.7	)		-			(0.1	)
Foreign currency translation adjustments		(0.1	)		(0.2	)		-			-
Ending balance	$	24.0		$	24.0		$	8.8		$	8.7

Great Plains Energy and KCP&L recognize interest related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.  At June 30, 2012, and December 31, 2011, accrued interest related to unrecognized tax benefits for Great Plains Energy was $6.1 million and $5.7 million, respectively.  Amounts accrued for penalties with respect to unrecognized tax benefits was $1.1 million at June 30, 2012, and December 31, 2011.  Amounts accrued for interest and penalties with respect to unrecognized tax benefits for KCP&L are insignificant.  

The IRS is currently auditing Great Plains Energy and its subsidiaries for the 2009-2010 tax years.  The Company estimates that it is reasonably possible that $9.3 million for Great Plains Energy and $4.1 million for KCP&L of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities.

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Receivables (Tables)

6 Months Ended

Jun. 30, 2012

Receivables [Abstract]

Schedule of receivables

	June 30			December 31
	2012			2011
Great Plains Energy	(millions)
Customer accounts receivable - billed	$	4.2		$	69.8
Customer accounts receivable - unbilled		120.1			82.4
Allowance for doubtful accounts		(3.5	)		(2.5	)
Other receivables		85.3			81.5
Total	$	206.1		$	231.2
KCP&L
Customer accounts receivable - billed	$	-		$	16.4
Customer accounts receivable - unbilled		74.6			50.0
Allowance for doubtful accounts		(2.0	)		(1.4	)
Intercompany receivables		13.4			38.7
Other receivables		74.8			69.2
Total	$	160.8		$	172.9

Schedule of accounts receivable sold

				KCP&L									GMO			Consolidated
				Receivables			Consolidated						Receivables			Great Plains
Three Months Ended June 30, 2012	KCP&L			Company			KCP&L			GMO			Company			Energy
	(millions)
Receivables (sold) purchased	$	(368.6	)	$	368.6		$	-		$	(91.7	)	$	91.7		$	-
Gain (loss) on sale of accounts receivable (a)		(4.7	)		4.0			(0.7	)		(1.2	)		0.8			(1.1	)
Servicing fees received (paid)		0.6			(0.6	)		-			0.1			(0.1	)		-
Fees paid to outside investor		-			(0.3	)		(0.3	)		-			(0.1	)		(0.4	)
Cash from customers (transferred) received		(319.4	)		319.4			-			(64.7	)		64.7			-
Cash received from (paid for) receivables
purchased		315.3			(315.3	)		-			63.9			(63.9	)		-

				KCP&L									GMO			Consolidated
				Receivables			Consolidated						Receivables			Great Plains
Year to Date June 30, 2012	KCP&L			Company			KCP&L			GMO			Company			Energy
	(millions)
Receivables (sold) purchased	$	(662.1	)	$	662.1		$	-		$	(91.7	)	$	91.7		$	-
Gain (loss) on sale of accounts receivable (a)		(8.4	)		8.1			(0.3	)		(1.2	)		0.8			(0.7	)
Servicing fees received (paid)		1.1			(1.1	)		-			0.1			(0.1	)		-
Fees paid to outside investor		-			(0.6	)		(0.6	)		-			(0.1	)		(0.7	)
Cash from customers (transferred) received		(646.6	)		646.6			-			(64.7	)		64.7			-
Cash received from (paid for) receivables
purchased		638.4			(638.4	)		-			63.9			(63.9	)		-
Interest on intercompany note received (paid)		0.1			(0.1	)		-			-			-			-

	Three Months Ended June 30, 2011									Year to Date June 30, 2011
				KCP&L									KCP&L
				Receivables			Consolidated						Receivables			Consolidated
	KCP&L			Company			KCP&L			KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(347.7	)	$	347.7		$	-		$	(639.6	)	$	639.6		$	-
Gain (loss) on sale of accounts receivable (a)		(4.4	)		3.9			(0.5	)		(8.1	)		7.8			(0.3	)
Servicing fees received (paid)		0.5			(0.5	)		-			1.1			(1.1	)		-
Fees paid to outside investor		-			(0.3	)		(0.3	)		-			(0.6	)		(0.6	)
Cash from customers (transferred) received		(309.9	)		309.9			-			(618.2	)		618.2			-
Cash received from (paid for) receivables
purchased		306.0			(306.0	)		-			610.4			(610.4	)		-
Interest on intercompany note received (paid)		0.1			(0.1	)		-			0.2			(0.2	)		-
(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.

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Derivative Instruments Group 4 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Commodity [Member] | Not Designated as Hedging Instrument [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Gains (losses) reflected in the income statement for changes in fair value of commodity contracts not designated as hedging	$ (0.3)	$ (0.9)	$ (1.1)	$ 1.0
Cash Flow Hedging [Member] | Interest charges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(5.0)	(3.9)	(10.1)	(6.8)
Cash Flow Hedging [Member] | Interest charges [Member] | Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(2.2)	(2.2)	(4.4)	(4.4)
Cash Flow Hedging [Member] | Fuel Costs [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	0	0
Cash Flow Hedging [Member] | Fuel Costs [Member] | Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	0	0
Cash Flow Hedging [Member] | Income tax benefit (expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0	2.2	0.1	2.1
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	1.9	1.4	3.9	2.6
Cash Flow Hedging [Member] | Income tax benefit (expense) [Member] | Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0	0	0.1	0
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0.9	0.8	1.7	1.7
Regulatory Account [Member] | Fuel Costs [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain(Loss) Reclassified from Regulatory Account into Income (Effective Portion)	(2.0)	(1.0)	(2.7)	(2.9)
Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0	(5.8)	0	(5.3)
Interest Rate Contract [Member] | Cash Flow Hedging [Member] | Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0	0	0	0
Commodity Contract [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0.1	(0.1)	(0.2)	(0.1)
Commodity Contract [Member] | Cash Flow Hedging [Member] | Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0.1	(0.1)	(0.2)	(0.1)
Commodity Contract [Member] | Regulatory Account [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized on Regulatory Account on Derivatives (Effective Portion)	0.3	(1.0)	(2.7)	(1.3)
Total Derivatives [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0.1	(3.7)	(0.1)	(3.3)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(3.1)	(2.5)	(6.2)	(4.2)
Total Derivatives [Member] | Cash Flow Hedging [Member] | Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0.1	(0.1)	(0.1)	(0.1)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ (1.3)	$ (1.4)	$ (2.7)	$ (2.7)

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Pension Plans and Other Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension Plans, Defined Benefit [Member]
Components of net periodic benefit costs
Service cost	$ 8.8	$ 7.8	$ 17.7	$ 15.6
Interest cost	12.3	12.6	24.5	25.1
Expected return on plan assets	(10.7)	(9.7)	(21.4)	(19.3)
Prior service cost	1.1	1.2	2.2	2.3
Recognized net actuarial (gain) loss	11.2	9.5	22.3	19.2
Settlement charges	0	0.2	0	0.2
Net period benefit costs before regulatory adjustment	22.7	21.6	45.3	43.1
Regulatory adjustment	(3.8)	(5.9)	(7.7)	(12.3)
Net periodic benefit costs	18.9	15.7	37.6	30.8
Other Postretirement Benefit Plans, Defined Benefit [Member]
Components of net periodic benefit costs
Service cost	0.8	0.8	1.6	1.6
Interest cost	2.0	1.9	3.9	3.9
Expected return on plan assets	(0.4)	(0.5)	(0.9)	(0.9)
Prior service cost	1.8	1.8	3.6	3.6
Recognized net actuarial (gain) loss	0	(0.2)	0	(0.3)
Transition obligation	0.2	0.4	0.5	0.7
Net period benefit costs before regulatory adjustment	4.4	4.2	8.7	8.6
Regulatory adjustment	0.3	0.1	0.7	0.3
Net periodic benefit costs	$ 4.7	$ 4.3	$ 9.4	$ 8.9

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Consolidated Statements of Cash Flows (unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Cash Flows from Operating Activities
Net income	$ 48.8	$ 45.7
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	135.3	140.0
Amortization of:
Nuclear fuel	9.1	5.9
Other Amortization of Deferred Charges	9.2	1.3
Deferred income taxes, net	26.8	36.3
Investment tax credit amortization	(1.2)	(0.8)
Loss from equity investments, net of income taxes	0.1	0.1
Other operating activities	(62.8)	(157.4)
Net cash from operating activities	165.3	71.1
Cash Flows from Investing Activities
Utility capital expenditures	(263.4)	(193.2)
Allowance for borrowed funds used during construction	(2.7)	(2.1)
Purchases of nuclear decommissioning trust investments	(11.7)	(11.2)
Proceeds from nuclear decommissioning trust investments	10.0	9.4
Other investing activities	(7.5)	(13.6)
Net cash from investing activities	(275.3)	(210.7)
Cash Flows from Financing Activities
Issuance of common stock	290.3	3.0
Issuance of long-term debt	0	349.7
Issuance fees	(2.6)	(2.5)
Repayment of long-term debt	(13.4)	(448.3)
Net change in short-term borrowings	(167.0)	295.7
Net change in collateralized short-term borrowings	67.0	0
Dividends paid	(58.7)	(57.2)
Other financing activities	(4.9)	(3.8)
Net cash from financing activities	110.7	136.6
Net Change in Cash and Cash Equivalents	0.7	(3.0)
Cash and Cash Equivalents at Beginning of Year	6.2	10.8
Cash and Cash Equivalents at End of Year	6.9	7.8
Kansas City Power and Light Company [Member]
Cash Flows from Operating Activities
Net income	46.0	37.4
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	91.7	101.6
Amortization of:
Nuclear fuel	9.1	5.9
Other Amortization of Deferred Charges	14.9	14.1
Deferred income taxes, net	20.2	24.4
Investment tax credit amortization	(0.9)	(0.5)
Other operating activities	(26.1)	(95.1)
Net cash from operating activities	154.9	87.8
Cash Flows from Investing Activities
Utility capital expenditures	(208.6)	(143.0)
Allowance for borrowed funds used during construction	(1.4)	(1.2)
Purchases of nuclear decommissioning trust investments	(11.7)	(11.2)
Proceeds from nuclear decommissioning trust investments	10.0	9.4
Net money pool lending	0	12.1
Other investing activities	(6.3)	(7.8)
Net cash from investing activities	(218.0)	(141.7)
Cash Flows from Financing Activities
Repayment of long-term debt	(12.3)	(112.8)
Net change in short-term borrowings	(136.0)	213.2
Net change in collateralized short-term borrowings	11.0	0
Dividends paid	(50.0)	(50.0)
Net money pool borrowings	250.9	2.5
Other financing activities	0	(0.1)
Net cash from financing activities	63.6	52.8
Net Change in Cash and Cash Equivalents	0.5	(1.1)
Cash and Cash Equivalents at Beginning of Year	1.9	3.6
Cash and Cash Equivalents at End of Year	$ 2.4	$ 2.5

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Nuclear Plant

6 Months Ended

Jun. 30, 2012

Nuclear Plant [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.

Spent Nuclear Fuel and High-Level Radioactive Waste

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel.  KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kWh of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel.  These disposal costs are charged to fuel expense.  In 2010, the DOE filed a motion with the NRC to withdraw its then pending application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada.  An NRC board denied the DOE’s motion to withdraw its application, and the DOE appealed that decision to the full NRC.  In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of September 2011 due to a lack of funding.  These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application.  The court has not yet issued a final decision in the case, but in August 2012, the court ordered the parties to report to it, no later than December 14, 2012, on whether Congress by then had provided funding for the NRC to proceed on the license application.  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 Decommissioning Trust Fund

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

	June 30		December 31
	2012		2011
Decommissioning Trust	(millions)
Beginning balance January 1	$	135.3	$	129.2
Contributions		1.7		3.4
Earned income, net of fees		1.4		4.8
Net realized gains		0.5		0.3
Net unrealized gains (losses)		6.0		(2.4	)
Ending balance	$	144.9	$	135.3

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

	June 30									December 31
	2012									2011
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	77.9	$	17.2	$	(3.8	)	$	91.3	$	76.5	$	12.3	$	(4.5	)	$	84.3
Debt securities		46.0		4.9		(0.1	)		50.8		44.2		4.5		(0.1	)		48.6
Other		2.8		-		-			2.8		2.4		-		-			2.4
Total	$	126.7	$	22.1	$	(3.9	)	$	144.9	$	123.1	$	16.8	$	(4.6	)	$	135.3

The weighted average maturity of debt securities held by the trust at June 30, 2012, was approximately 7 years.  The costs of securities sold are determined on the basis of specific identification.  The following table summarizes the realized gains and losses from the sale of securities in the nuclear decommissioning trust fund.

	Three Months Ended						Year to Date
	June 30						June 30
	2012			2011			2012			2011
	(millions)
Realized gains	$	0.2		$	0.7		$	0.7		$	0.8
Realized losses		(0.1	)		(0.7	)		(0.2	)		(0.7	)

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Nuclear Plant (Tables)

6 Months Ended

Jun. 30, 2012

Nuclear Plant [Abstract]

Changes in nuclear decommissioning trust fund

	June 30		December 31
	2012		2011
Decommissioning Trust	(millions)
Beginning balance January 1	$	135.3	$	129.2
Contributions		1.7		3.4
Earned income, net of fees		1.4		4.8
Net realized gains		0.5		0.3
Net unrealized gains (losses)		6.0		(2.4	)
Ending balance	$	144.9	$	135.3

Detail of assets held in nuclear decommissioning trust fund

	June 30									December 31
	2012									2011
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	77.9	$	17.2	$	(3.8	)	$	91.3	$	76.5	$	12.3	$	(4.5	)	$	84.3
Debt securities		46.0		4.9		(0.1	)		50.8		44.2		4.5		(0.1	)		48.6
Other		2.8		-		-			2.8		2.4		-		-			2.4
Total	$	126.7	$	22.1	$	(3.9	)	$	144.9	$	123.1	$	16.8	$	(4.6	)	$	135.3

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

	Three Months Ended						Year to Date
	June 30						June 30
	2012			2011			2012			2011
	(millions)
Realized gains	$	0.2		$	0.7		$	0.7		$	0.8
Realized losses		(0.1	)		(0.7	)		(0.2	)		(0.7	)

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Receivables (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011		Dec. 31, 2011
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (3.5)				$ (3.5)				$ (2.5)
Receivables, net	206.1				206.1				231.2
Statement [Line Items]
Accounts receivables pledged as collateral	162.0				162.0				95.0
Accounts Receivable Sold [Line Items]
Receivables (sold) purchased	0				0
Gain (loss) on sale of accounts receivable	(1.1)	[1]			(0.7)	[1]
Servicing fees received (paid)	0				0
Fees paid to outside investor	(0.4)				(0.7)
Cash from customers (transferred to) received from Receivables Company	0				0
Cash received from (paid to) for receivables purchased	0				0
Interest on intercompany note received (paid)	0				0
G M O Receivables Company Member
Accounts Receivable Sold [Line Items]
Receivables (sold) purchased	91.7				91.7
Gain (loss) on sale of accounts receivable	0.8	[1]			0.8	[1]
Servicing fees received (paid)	(0.1)				(0.1)
Fees paid to outside investor	(0.1)				(0.1)
Cash from customers (transferred to) received from Receivables Company	64.7				64.7
Cash received from (paid to) for receivables purchased	(63.9)				(63.9)
Interest on intercompany note received (paid)	0				0
Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	(2.0)				(2.0)				(1.4)
Receivables, net	160.8				160.8				172.9
Statement [Line Items]
Accounts receivables pledged as collateral	106.0				106.0				95.0
Maximum percentage servicing fee received on receivables sold (in hundredths)					1.50%
Maximum amount of outstanding principal under receivables agreement	110.0				110.0
Accounts Receivable Sold [Line Items]
Receivables (sold) purchased	0		0		0		0
Gain (loss) on sale of accounts receivable	(0.7)	[1]	(0.5)	[1]	(0.3)	[1]	(0.3)	[1]
Servicing fees received (paid)	0		0		0		0
Fees paid to outside investor	(0.3)		(0.3)		(0.6)		(0.6)
Cash from customers (transferred to) received from Receivables Company	0		0		0		0
Cash received from (paid to) for receivables purchased	0		0		0		0
Interest on intercompany note received (paid)	0		0		0		0
Kansas City Power and Light Company [Member] | Kansas City Power And Light Company Unconsolidated [Member]
Accounts Receivable Sold [Line Items]
Receivables (sold) purchased	(368.6)		(347.7)		(662.1)		(639.6)
Gain (loss) on sale of accounts receivable	(4.7)	[1]	(4.4)	[1]	(8.4)	[1]	(8.1)	[1]
Servicing fees received (paid)	0.6		0.5		1.1		1.1
Fees paid to outside investor	0		0		0		0
Cash from customers (transferred to) received from Receivables Company	(319.4)		(309.9)		(646.6)		(618.2)
Cash received from (paid to) for receivables purchased	315.3		306.0		638.4		610.4
Interest on intercompany note received (paid)	0		0.1		0.1		0.2
Kansas City Power and Light Company [Member] | KCPL Receivables Company [Member]
Accounts Receivable Sold [Line Items]
Receivables (sold) purchased	368.6		347.7		662.1		639.6
Gain (loss) on sale of accounts receivable	4.0	[1]	3.9	[1]	8.1	[1]	7.8	[1]
Servicing fees received (paid)	(0.6)		(0.5)		(1.1)		(1.1)
Fees paid to outside investor	(0.3)		(0.3)		(0.6)		(0.6)
Cash from customers (transferred to) received from Receivables Company	319.4		309.9		646.6		618.2
Cash received from (paid to) for receivables purchased	(315.3)		(306.0)		(638.4)		(610.4)
Interest on intercompany note received (paid)	0		(0.1)		(0.1)		(0.2)
KCPL Greater Missouri Operations [Member]
Statement [Line Items]
Maximum percentage servicing fee received on receivables sold (in hundredths)					1.25%
Maximum amount of outstanding principal under receivables agreement from June 1 to October 31 of each year	80.0				80.0
Maximum amount of outstanding principal under receivables agreement from November 1 to May 31 of each year	65.0				65.0
Accounts Receivable Sold [Line Items]
Receivables (sold) purchased	(91.7)				(91.7)
Gain (loss) on sale of accounts receivable	(1.2)				(1.2)
Servicing fees received (paid)	0.1				0.1
Fees paid to outside investor	0				0
Cash from customers (transferred to) received from Receivables Company	(64.7)				(64.7)
Cash received from (paid to) for receivables purchased	63.9				63.9
Interest on intercompany note received (paid)	0				0
Trade Accounts Receivable [Member] | Billed Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	4.2				4.2				69.8
Trade Accounts Receivable [Member] | Billed Revenues [Member] | Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	0				0				16.4
Trade Accounts Receivable [Member] | Unbilled Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	120.1				120.1				82.4
Trade Accounts Receivable [Member] | Unbilled Revenues [Member] | Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	74.6				74.6				50.0
Other Receivables [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	85.3				85.3				81.5
Other Receivables [Member] | Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	74.8				74.8				69.2
Intercompany Receivables [Member] | Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	$ 13.4				$ 13.4				$ 38.7

[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.

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Fair Value Measurements

6 Months Ended

Jun. 30, 2012

Fair Value Measurements [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 and liabilities categorized within this level consist of Great Plains Energy’s and KCP&L’s various exchange traded derivative instruments and equity and U.S. Treasury securities that are actively traded within KCP&L’s decommissioning trust fund and GMO’s Supplemental Executive Retirement Plan (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 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 June 30, 2012, and December 31, 2011.

						Fair Value Measurements Using
Description	June 30 2012		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Nuclear decommissioning trust (b)
Equity securities	$	91.3	$	-		$	91.3	$	-	$	-
Debt securities
U.S. Treasury		16.2		-			16.2		-		-
U.S. Agency		4.3		-			-		4.3		-
State and local obligations		2.7		-			-		2.7		-
Corporate bonds		26.9		-			-		26.9		-
Foreign governments		0.7		-			-		0.7		-
Other		0.5		-			-		0.5		-
Total nuclear decommissioning trust		142.6		-			107.5		35.1		-
Total		142.6		-			107.5		35.1		-
Liabilities
Derivative instruments (a)		-		(0.5	)		0.5		-		-
Total	$	-	$	(0.5	)	$	0.5	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	6.7	$	-		$	-	$	4.5	$	2.2
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-
Debt securities		0.1		-			-		0.1		-
Total SERP rabbi trust		0.3		-			0.2		0.1		-
Total		7.0		-			0.2		4.6		2.2
Liabilities
Derivative instruments (a)		-		(3.0	)		3.0		-		-
Total	$	-	$	(3.0	)	$	3.0	$	-	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	6.7	$	-		$	-	$	4.5	$	2.2
Nuclear decommissioning trust (b)		142.6		-			107.5		35.1		-
SERP rabbi trust (c)		0.3		-			0.2		0.1		-
Total		149.6		-			107.7		39.7		2.2
Liabilities
Derivative instruments (a)		-		(3.5	)		3.5		-		-
Total	$	-	$	(3.5	)	$	3.5	$	-	$	-

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

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

(b)   Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.  The total does not include $2.3 million and $3.0 million at June 30, 2012, and December 31, 2011, 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 $20.2 million and $20.3 million at June 30, 2012, and December 31, 2011, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)   Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty.  At June 30, 2012, and December 31, 2011, Great Plains Energy netted $3.4 million and $5.5 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 June 30, 2012 and 2011.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative
	Instruments
	(millions)
Balance at April 1	$	2.4		$	5.7
Total realized/unrealized gains
included in non-operating income		0.9			2.1
Settlements		(1.1	)		(2.9	)
Balance at June 30	$	2.2		$	4.9
Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at June 30	$	(0.1	)	$	(0.6	)

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	2012			2011
	Derivative
	Instruments
	(millions)
Balance at January 1	$	3.1		$	3.7
Total realized/unrealized gains
included in non-operating income		1.1			7.1
Settlements		(2.0	)		(5.9	)
Balance at June 30	$	2.2		$	4.9
Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at June 30	$	(0.7	)	$	1.5