10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

or

[  ] TRANSITION REPORT PURSUANT 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

Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is registered on the New York Stock Exchange:

Registrant	Title of each class
Great Plains Energy Incorporated	Cumulative Preferred Stock par value $100 per share	3.80%
	Cumulative Preferred Stock par value $100 per share	4.50%
	Cumulative Preferred Stock par value $100 per share	4.35%
	Common Stock without par value
	Corporate Units

Securities registered pursuant to Section 12(g) of the Act: Kansas City Power & Light Company Common Stock without par value.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Great Plains Energy Incorporated

Yes

X

No

_

Kansas City Power & Light Company

Yes

_

No

X

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Great Plains Energy Incorporated

Yes

_

No

X

Kansas City Power & Light Company

Yes

_

No

X

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained

herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by

reference in Part III of this Form 10-K or any amendment to the Form 10-K.

Great Plains Energy Incorporated

_

Kansas City Power & Light Company

X

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of Great Plains Energy

Incorporated (based on the closing price of its common stock on the New York Stock Exchange on June 30, 2011) was

approximately $2,819,307,073.  All of the common equity of Kansas City Power & Light Company is held by Great Plains

Energy Incorporated, an affiliate of Kansas City Power & Light Company.

On February 21, 2012, Great Plains Energy Incorporated had 136,161,064 shares of common stock outstanding.

On February 21, 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 (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

Documents Incorporated by Reference

Portions of the 2012 annual meeting proxy statement of Great Plains Energy Incorporated to be filed with the Securities and

Exchange Commission are incorporated by reference in Part III of this report.

TABLE OF CONTENTS
			Page
			Number
	Cautionary Statements Regarding Forward-Looking Information		3
	Glossary of Terms		4
	PART I
Item 1.	Business		6
Item 1A.	Risk Factors		11
Item 1B.	Unresolved Staff Comments		22
Item 2.	Properties		23
Item 3.	Legal Proceedings		24
Item 4.	Mine Safety Disclosures		24
	PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters
		and Issuer Purchases of Equity Securities	25
Item 6.	Selected Financial Data		26
Item 7.	Management's Discussion and Analysis of Financial Condition
		and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		52
Item 8.	Financial Statements and Supplementary Data		55
Item 9.	Changes in and Disagreements With Accountants on Accounting
		and Financial Disclosure	134
Item 9A.	Controls and Procedures		134
Item 9B.	Other Information		138
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		138
Item 11.	Executive Compensation		138
Item 12.	Security Ownership of Certain Beneficial Owners and Management
		and Related Stockholder Matters	139
Item 13.	Certain Relationships and Related Transactions, and Director Independence		139
Item 14.	Principal Accounting Fees and Services		140
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		141

2

This combined annual report on Form 10-K 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.

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 I Item 1A Risk Factors included in this report should be carefully read for further understanding of potential risks for each of Great Plains Energy and KCP&L.  Other sections of this report and other periodic reports filed by each of Great Plains Energy and KCP&L with the Securities and Exchange Commission (SEC) should also be read for more information regarding risk factors.  Each forward-looking statement speaks only as of the date of the 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.

3

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
FGIC	Financial Guaranty Insurance Company
FSS	Forward Starting Swaps
GAAP	Generally Accepted Accounting Principles
GMO	KCP&L Greater Missouri Operations Company, a wholly owned subsidiary of    Great Plains Energy
Great Plains Energy	Great Plains Energy Incorporated and its subsidiaries
ISO	Independent System Operator
KCC	The State Corporation Commission of the State of Kansas
KCP&L	Kansas City Power & Light Company, a wholly owned subsidiary    of Great Plains Energy
KDHE	Kansas Department of Health and Environment
kV	Kilovolt
KW	Kilowatt
kWh	Kilowatt hour
L&P	St. Joseph Light & Power, a division of GMO
MACT	Maximum achievable control technology
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

4

Abbreviation or Acronym	Definition
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
Receivables Company	Kansas City Power & Light Receivables Company, a wholly owned    subsidiary of KCP&L
RTO	Regional Transmission Organization
SCR	Selective catalytic reduction
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Syncora	Syncora Guarantee Inc.
WCNOC	Wolf Creek Nuclear Operating Corporation
Westar	Westar Energy, Inc., a Kansas utility company
Wolf Creek	Wolf Creek Generating Station

5

PART I

ITEM 1.  BUSINESS

General

Great Plains Energy Incorporated and Kansas City Power & Light Company are separate registrants filing this combined annual report on Form 10-K.  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.

Information in other Items of this report as to which reference is made in this Item 1 is hereby incorporated by reference in this Item 1.  The use of terms such as “see” or “refer to” shall be deemed to incorporate into this Item 1 the information to which such reference is made.

GREAT PLAINS ENERGY INCORPORATED

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

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

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

Great Plains Energy’s sole reportable business segment is electric utility.  For information regarding the revenues, income and assets attributable to the electric utility business segment, see Note 21 to the consolidated financial statements.  Comparative financial information and discussion regarding the electric utility business segment can be found in Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).

The electric utility segment consists of KCP&L, a regulated utility, and GMO’s regulated utility operations which include its Missouri Public Service and St. Joseph Light & Power (L&P) divisions.  Electric utility serves approximately 823,000 customers located in western Missouri and eastern Kansas.  Customers include approximately 725,000 residences, 96,000 commercial firms, and 2,600 industrials, municipalities and other electric utilities.  Electric utility’s retail revenues averaged approximately 90% of its total operating revenues over the last three years.  Wholesale firm power, bulk power sales and miscellaneous electric revenues accounted for the remainder of electric utility’s revenues.  Electric utility is significantly impacted by seasonality with approximately one-third of its retail revenues recorded in the third quarter.  Electric utility’s total electric revenues were 100% of Great Plains Energy’s revenues over the last three years.  Electric utility’s net income accounted for approximately 115%, 111% and 104% of Great Plains Energy’s income from continuing operations in 2011, 2010 and 2009, respectively.

6

Regulation

KCP&L and GMO are regulated by the Public Service Commission of the State of Missouri (MPSC), and KCP&L is also regulated by The State Corporation Commission of the State of Kansas (KCC), with respect to retail rates, certain accounting matters, standards of service and, in certain cases, the issuance of securities, certification of facilities and service territories.  KCP&L and GMO are also subject to regulation by The Federal Energy Regulatory Commission (FERC), with respect to transmission, wholesale sales and rates, and other matters, the Southwest Power Pool, Inc. (SPP) and the North American Electric Reliability Corporation (NERC).  KCP&L has a 47% ownership interest in the Wolf Creek Generating Station (Wolf Creek), which is subject to regulation by the Nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety-related requirements.

Missouri and Kansas jurisdictional retail revenues averaged approximately 71% and 29%, respectively, of electric utility’s total retail revenues over the last three years.  See Item 7 MD&A, Critical Accounting Policies section, and Note 5 to the consolidated financial statements for additional information concerning regulatory matters.

Competition

Missouri and Kansas continue on the fully integrated utility model and no legislation authorizing retail choice has been introduced in Missouri or Kansas for many years.  As a result, electric utility does not compete with others to supply and deliver electricity in its franchised service territory, although other sources of energy can provide alternatives to electric utility customers.  If Missouri or Kansas were to pass and implement legislation authorizing or mandating retail choice, electric utility may no longer be able to apply regulated utility accounting principles to deregulated portions of its operations and may be required to write off certain regulatory assets and liabilities.

Electric utility competes in the wholesale market to sell power in circumstances when the power it generates is not required for customers in its service territory.  In this regard, electric utility competes with owners of other generating stations and other power suppliers, principally utilities in its region, on the basis of availability and price.  Electric utility’s wholesale revenues averaged approximately 8% of its total revenues over the last three years.

Power Supply

Electric utility has over 6,600 MWs of generating capacity.  The projected peak summer demand for 2012 is approximately 5,700 MWs.  Electric utility expects to meet its projected capacity requirements through 2020 with its generation assets, capacity purchases or new capacity additions.

KCP&L and GMO are members of the SPP.  SPP is a Regional Transmission Organization (RTO) mandated by FERC to ensure reliable supply of power, adequate transmission infrastructure and competitive wholesale prices of electricity.  As members of the SPP, KCP&L and GMO are required to maintain a capacity margin of at least 12% of their projected peak summer demand.  This net positive supply of capacity and energy is maintained through their generation assets and capacity, power purchase agreements and peak demand reduction programs.  The capacity margin is designed to ensure the reliability of electric energy in the SPP region in the event of operational failure of power generating units utilized by the members of the SPP.

7

Fuel

The principal fuel sources for electric utility’s electric generation are coal and nuclear fuel.  It is expected, with normal weather, that approximately 95% of 2012 generation will come from these sources with the remainder provided by wind, natural gas and oil.  The actual 2011 and estimated 2012 fuel mix and delivered cost in cents per net kWh generated are outlined in the following table.

							Fuel cost in cents per
	Fuel Mix (a)						net kWh generated
	Estimated			Actual			Estimated		Actual
Fuel	2012			2011			2012		2011
Coal		80	%		83	%		2.06		2.06
Nuclear		15			13			0.71		0.72
Natural gas and oil		3			2			5.45		7.82
Wind		2			2			-		-
Total Generation		100	%		100	%		1.95		1.92
(a) Fuel mix based on percent of net MWhs generated.

GMO’s retail rates and KCP&L’s retail rates in Kansas contain certain fuel recovery mechanisms.  KCP&L’s Missouri retail rates do not contain a fuel recovery mechanism.  To the extent the price of fuel or purchased power increases significantly, or if electric utility’s lower cost units do not meet anticipated availability levels, Great Plains Energy’s net income may be adversely affected unless and until the increased cost could be reflected in KCP&L’s Missouri retail rates.

Coal

During 2012, electric utility’s generating units, including jointly owned units, are projected to burn approximately 16 million tons of coal.  KCP&L and GMO have entered into coal-purchase contracts with various suppliers in Wyoming's Powder River Basin (PRB), the nation's principal supply region of low-sulfur coal, and with local suppliers.  The coal to be provided under these contracts is expected to satisfy almost all of the projected coal requirements for 2012 and approximately 95% for 2013, 70% for 2014 and 20% for 2015.  The remainder of the coal requirements is expected to be fulfilled through additional contracts or spot market purchases.  KCP&L and GMO have entered into coal contracts over time at higher average prices affecting coal costs for 2012 and beyond.

KCP&L and GMO have also entered into rail transportation contracts with various railroads to transport coal from the PRB to their generating units.  The transportation services to be provided under these contracts are expected to satisfy approximately 95% of the projected transportation requirements for 2012 and approximately 85% for 2013 and 20% for each of 2014 and 2015.  The contract rates adjust for changes in railroad costs.

Nuclear Fuel

KCP&L owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek, which is electric utility’s only nuclear generating unit.  Wolf Creek purchases uranium and has it processed for use as fuel in its reactor.  This process involves conversion of uranium concentrates to uranium hexafluoride, enrichment of uranium hexafluoride and fabrication of nuclear fuel assemblies.  The owners of Wolf Creek have on hand or under contract all of the uranium and conversion services needed to operate Wolf Creek through March 2014 and approximately 78% after that date through March 2020.  The owners also have under contract all of the uranium enrichment and fabrication required to operate Wolf Creek through March 2026.

See Note 4 to the consolidated financial statements for additional information regarding nuclear plant.

8

Natural Gas

At December 31, 2011, KCP&L had hedged approximately 66%, 56% and 13% of its 2012, 2013 and 2014, respectively, projected natural gas usage for generation requirements to serve retail load and firm MWh sales.  At December 31, 2011, GMO had hedged approximately 45%, 38% and 38% of its 2012, 2013 and 2014, respectively, expected on-peak natural gas usage and natural gas equivalent purchased power.

Purchased Capacity and Power

KCP&L and GMO have distinct rate and dispatching areas.  As a result, KCP&L and GMO do not joint-dispatch their respective generation.  KCP&L purchases power to meet its customers’ needs when it does not have sufficient available generation or when the cost of purchased power is less than KCP&L’s cost of generation or to satisfy firm power commitments or renewable energy standards.  During 2011, KCP&L entered into long-term power purchase agreements for approximately 231 MWs of wind generation beginning in 2012 which expire in 2032.  GMO has long-term purchased capacity agreements for approximately 135 MWs, which expire in 2014 through 2016, and in 2011 entered into a long-term power purchase agreement for approximately 100 MWs of wind generation beginning in 2012 that expires in 2032.  Management believes electric utility will be able to obtain enough power to meet its future demands due to the coordination of planning and operations in the SPP region; however, price and availability of power purchases may be impacted during periods of high demand.  Electric utility’s purchased power, as a percentage of MWh requirements, averaged approximately 16% over the last three years.

Environmental Matters

See Note 14 to the consolidated financial statements for information regarding environmental matters.

KANSAS CITY POWER & LIGHT COMPANY

KCP&L, headquartered in Kansas City, Missouri, is an integrated, regulated electric utility that engages in the generation, transmission, distribution and sale of electricity.  KCP&L serves approximately 511,000 customers located in western Missouri and eastern Kansas.  Customers include approximately 451,000 residences, 58,000 commercial firms, and 2,100 industrials, municipalities and other electric utilities.  KCP&L’s retail revenues averaged approximately 87% of its total operating revenues over the last three years.  Wholesale firm power, bulk power sales and miscellaneous electric revenues accounted for the remainder of KCP&L’s revenues.  KCP&L is significantly impacted by seasonality with approximately one-third of its retail revenues recorded in the third quarter.  Missouri and Kansas jurisdictional retail revenues averaged approximately 56% and 44%, respectively, of total retail revenues over the last three years.

GREAT PLAINS ENERGY AND KCP&L EMPLOYEES

At December 31, 2011, Great Plains Energy and KCP&L had 3,053 employees, including 1,917 represented by three local unions of the International Brotherhood of Electrical Workers (IBEW).  KCP&L has labor agreements with Local 1613, representing clerical employees (expires March 31, 2013), with Local 1464, representing transmission and distribution workers (expires January 31, 2013), and with Local 412, representing power plant workers (expires February 28, 2013).

9

Executive Officers

All of the individuals in the following table have been officers or employees in a responsible position with the Company in the positions noted below for the past five years unless otherwise indicated in the footnotes.  The executive officers were reappointed to the indicated positions by the respective boards of directors, effective January 1, 2012, to hold such positions until their resignation, removal or the appointment of their successors.  There are no family relationships between any of the executive officers, nor any arrangement or understanding between any executive officer and any other person involved in officer selection.  Each executive officer holds the same position with GMO as he or she does with KCP&L.

			Year First
			Assumed
			an Officer
Name	Age	Current Position(s)	Position
Michael J. Chesser (a)	63	Chairman of the Board and Chief Executive Officer – Great Plains Energy and KCP&L	2003
Terry Bassham (b)	51	President and Chief Operating Officer – Great Plains Energy and KCP&L	2005
James C. Shay (c)	48	Senior Vice President – Finance and Strategic Development  and Chief Financial Officer  – Great Plains Energy and KCP&L	2010
Kevin E. Bryant (d)	36	Vice President – Investor Relations and Treasurer – Great Plains Energy and KCP&L	2006
Charles A. Caisley (e)	39	Vice President – Marketing and Public Affairs – Great Plains Energy and KCP&L	2011
Michael L. Deggendorf (f)	50	Senior Vice President – Delivery – KCP&L	2005
Ellen E. Fairchild (g)	50	Vice President, Corporate Secretary and Chief Compliance Officer – Great Plains Energy and KCP&L	2010
Scott H. Heidtbrink (h)	50	Senior Vice President – Supply – KCP&L	2008
Heather A. Humphrey (i)	41	General Counsel and Senior Vice President – Human Resources – Great Plains Energy and KCP&L	2010
Lori A. Wright (j)	49	Vice President - Business Planning and Controller – Great Plains Energy and KCP&L	2002

(a)

Mr. Chesser was appointed Chairman of the Board and Chief Executive Officer of Great Plains Energy in 2003.  He was appointed Chairman of the Board of KCP&L in 2003, and Chief Executive Officer of KCP&L and Chairman of the Board and Chief Executive Officer of GMO in 2008.

(b)

Mr. Bassham was appointed President and Chief Operating Officer of Great Plains Energy, KCP&L and GMO in 2011.  He served as Executive Vice President – Utility Operations of KCP&L and GMO (2010-2011).  He was Executive Vice President – Finance and Strategic Development and Chief Financial Officer of Great Plains Energy (2005-2010) and of KCP&L and GMO (2009-2010).  He was Chief Financial Officer of KCP&L (2005-2008) and GMO (2008).

(c) Mr. Shay was appointed Senior Vice President – Finance and Strategic Development and Chief Financial Officer of Great Plains Energy, KCP&L and GMO in 2010.  He was Chief Financial Officer, with responsibilities for finance, accounting and information technology, at Northern Power Systems, Inc., a wind turbine manufacturing business (2009-2010); Managing Director, with responsibilities for business development, transaction execution and advisory work, at Frontier Investment Banc Corporation (2007-2008); and Chief Financial Officer, with responsibilities for finance, accounting, human resources, information technology and procurement, at Machine Laboratory LLC, a manufacturer of machined parts for the automotive industry (2006-2007).  Prior to that, Mr. Shay was Chief Financial Officer, with

10

responsibilities for finance and accounting, at General Electric Co. Environmental Services (2004-2006) after its acquisition of BHA Group Holdings, Inc., a supplier of aftermarket parts and service for industrial air pollution equipment.

(d)	Mr. Bryant was appointed Vice President – Investor Relations and Treasurer of Great Plains Energy, KCP&L and GMO in 2011.  He was Vice President – Strategy and Risk Management of KCP&L and GMO (2011) and Vice President – Energy Solutions (2006-2011) of KCP&L and GMO.
(e)	Mr. Caisley was appointed Vice President – Marketing and Public Affairs of Great Plains Energy, KCP&L and GMO in 2011.  He was Senior Director of Public Affairs (2008-2011) and Director of Governmental Affairs (2007-2008).  Prior to that, he was the president of the Missouri Energy Development Association (2005-2007).

(f)	Mr. Deggendorf was appointed Senior Vice President – Delivery of KCP&L and GMO in 2008.  He was Vice President – Public Affairs of Great Plains Energy (2005-2008) and Senior Director, Energy Solutions (2002-2005) of KCP&L.
(g)	Ms. Fairchild was appointed Vice President, Corporate Secretary and Chief Compliance Officer of Great Plains Energy, KCP&L and GMO in 2010.  She was Senior Director of Investor Relations and Assistant Secretary (2010) and Director of Investor Relations (2008-2010) of Great Plains Energy, KCP&L and GMO.  Prior to that, she was an associate at Hagen and Partners (2005-2007), a public relations firm.
(h)	Mr. Heidtbrink was appointed Senior Vice President – Supply of KCP&L and GMO in 2009.  He was Senior Vice President – Corporate Services of KCP&L and GMO (2008), and Vice President – Power Generation & Energy Resources (2006-2008) of GMO.
(i)	Ms. Humphrey was appointed General Counsel and Vice President – Human Resources of Great Plains Energy, KCP&L and GMO in 2010.  She was Senior Director of Human Resources and Interim General Counsel of Great Plains Energy, KCP&L and GMO (2010) and Managing Attorney of KCP&L (2007-2010).  Prior to that, she was a shareholder of the law firm of Shughart Thomson & Kilroy (1996-2006).
(j)	Ms. Wright was appointed Vice President and Controller of Great Plains Energy, KCP&L and GMO in 2009.  She was Controller of Great Plains Energy and KCP&L (2002-2008) and GMO (2008).

Available Information

Great Plains Energy’s website is www.greatplainsenergy.com and KCP&L’s website is www.kcpl.com.  Information contained on these websites is not incorporated herein.  The Companies make available, free of charge, on or through their websites, their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after the companies electronically file such material with, or furnish it to, the SEC.  In addition, the Companies make available on or through their websites all other reports, notifications and certifications filed electronically with the SEC.

The public may read and copy any materials that the Companies file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549.  For information on the operation of the Public Reference Room, please call the SEC at 1-800-SEC-0330.  The SEC also maintains an Internet site at http://www.sec.gov that contains reports, proxy statements and other information regarding the Companies.

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.  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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Utility Regulatory Risks:

Complex utility regulation could adversely affect the Companies’ results of operations, financial position and cash flows.

The Companies are subject to, or affected by, extensive federal and state utility regulation, including regulation by the MPSC, KCC, FERC, NRC, SPP and NERC.  The Companies must address in their business planning and management of operations the effects of existing and proposed laws and regulations and potential changes in the regulatory framework, including initiatives by federal and state legislatures, RTOs, utility regulators and taxing authorities.  Failure of the Companies to obtain adequate rates or regulatory approvals in a timely manner, new or changed laws, regulations, standards, interpretations or other legal requirements, and increased compliance costs and potential non-compliance consequences may materially affect the Companies’ results of operations, financial position and cash flows.  Certain of these risks are addressed in greater detail below.

The outcome of retail rate proceedings could have a material impact on the business and is largely outside the Companies’ control.

The rates that KCP&L and GMO are allowed to charge their customers significantly influence the Companies’ results of operations, financial position and cash flows.  These rates are subject to the determination, in large part, of governmental entities outside of the Companies’ control, including the MPSC, KCC and FERC.  

The utility rate-setting principle generally applicable to KCP&L and GMO is that rates should provide a reasonable opportunity to recover expenses and investment prudently incurred to provide utility service plus a reasonable return on such investment.  Various expenses incurred by KCP&L and GMO have been excluded from rates by the MPSC and KCC in past rate cases as not being prudently incurred or not providing utility customer benefit, and there is a risk that certain expenses incurred in the future may not be recovered in rates.  The MPSC and KCC also have in the past and may in the future exclude from rates all or a portion of investments in various facilities as not being prudently incurred or not being useful in providing utility service.  

In March 2007, KCP&L entered into a Collaboration Agreement with the Sierra Club and the Concerned Citizens of Platte County that provides for increases in KCP&L’s wind generation capacity and energy efficiency initiatives, reductions in certain emission permit levels at its Iatan and La Cygne generating stations, and projects to offset certain CO2 emissions.  The wind generation, energy efficiency and emission permit reductions are conditioned on regulatory approval.  In addition to these commitments, as discussed in the “Environmental Risks” and “Financial Risks” sections below, the Companies’ capital expenditures are expected to be substantial over the next several years for additional environmental projects, as well as other projects, and there is a risk that a portion of the capital costs could be excluded from rates in future rate cases.

The Companies are also exposed to cost-recovery shortfalls due to the inherent “regulatory lag” in the rate-setting process, especially during periods of significant cost inflation or declining retail usage, as KCP&L’s and GMO’s utility rates are generally based on historical information and are not subject to adjustment (other than principally for fuel and purchased power for KCP&L in Kansas and for GMO) between rate cases.  These and other factors may result in under-recovery of costs, failure to earn the authorized return on investment, or both.

There are mandatory renewable energy standards in Missouri and Kansas.  There is the potential for future federal or state mandatory energy efficiency requirements.  KCP&L and GMO have implemented certain energy efficiency programs, and currently the recovery of these program expenses are on a deferred basis with no recovery mechanism for associated lost revenues.

     Failure to timely recover the full investment costs of capital projects, or the impact of renewable energy and energy efficiency programs, or other utility costs and expenses due to regulatory disallowances,

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regulatory lag or other factors could lead to lowered credit ratings, reduced access to capital markets, increased financing costs, lower flexibility due to constrained financial resources and increased collateral security requirements, or reductions or delays in planned capital expenditures.  In response to competitive, economic, political, legislative, public perception (including, but not limited to, the Companies’ environmental reputation) and regulatory pressures, the Companies may be subject to rate moratoriums, rate refunds, limits on rate increases, lower allowed returns on investment or rate reductions, including phase-in plans designed to spread the impact of rate increases over an extended period of time for the benefit of customers.  

Regulatory requirements regarding utility operations may increase costs and may expose the Companies to compliance penalties or adverse rate consequences.

The FERC, NERC and SPP have implemented and enforce an extensive set of transmission system reliability, cyber security and critical infrastructure protection standards that apply to public utilities, including KCP&L and GMO.  The MPSC and KCC have the authority to implement utility operational standards and requirements, such as vegetation management standards, facilities inspection requirements and quality of service standards.  In addition, the Companies are also subject to health, safety and other requirements enacted by the Occupational Safety and Health Administration, the Department of Transportation, the Department of Labor and other federal and state agencies.  As discussed more fully under “Operational Risks,” the NRC extensively regulates nuclear power plants, including Wolf Creek.  The costs of existing, new or modified regulations, standards and other requirements could have an adverse effect on the Companies’ results of operations, financial position and cash flows as a result of increased operations or maintenance and capital expenditures for new facilities or to repair or improve existing facilities.  In addition, failure to meet quality of service, reliability, cyber security, critical infrastructure protection, operational or other standards and requirements could expose the Companies to penalties, additional compliance costs, or adverse rate consequences.

Environmental Risks:

The Companies are subject to current and potential environmental requirements and the incurrence of environmental liabilities, any or all of which may adversely affect their business and financial results.

The Companies 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 for historical and pre-existing conditions, these laws, regulations and permits authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions.  There is also a risk that new environmental laws and regulations, new judicial interpretations of environmental laws and regulations, or the requirements in new or renewed environmental permits could adversely affect the Companies’ operations.  In addition, there is also a risk of lawsuits brought by third parties alleging violations of environmental commitments or requirements, creation of a public nuisance or other matters, and seeking injunctions or monetary or other damages.  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 damages.

Environmental permits are subject to periodic renewal, which may result in more stringent permit conditions and limits.  New facilities, or modifications of existing facilities, may require new environmental permits or amendments to existing permits.  Delays in the environmental permitting process, public opposition and challenges, denials of permit applications, limits or conditions imposed in permits and the associated uncertainty may materially adversely affect the cost and timing of projects, and thus materially adversely affect the Companies’ results of operations, financial position and cash flows.

KCP&L and GMO periodically seek recovery of capital costs and expenses for environmental compliance and remediation through rate increases; however, there can be no assurance that recovery of these costs would be granted.  

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As discussed above, KCP&L and GMO may be subject to material adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies’ environmental reputation.  The costs of compliance or noncompliance with environmental requirements, remediation costs, adverse outcomes of lawsuits, or failure to timely recover environmental costs could have a material adverse effect on the Companies’ results of operations, financial position and cash flows.  Certain of these matters are discussed in more detail below.  See Note 14 to the consolidated financial statements for additional information regarding certain significant environmental matters.

Air and Climate Change

The Companies believe it is likely that additional federal or relevant regional, state or local laws or regulations could be enacted to address global climate change.  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 laws or regulations could require the control or reduction of emissions of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels.  These requirements could include, among other things, taxes or fees on fossil fuels or emissions, cap and trade programs, emission limits and clean or renewable energy standards.  The Companies’ current generation capacity is over 50% coal-fired, and is estimated to produce about one ton of CO2 per MWh generated.  Great Plains Energy and KCP&L produce about 25 million and 18 million tons of CO2 per year, respectively.  Missouri law requires at least 2% of the electricity provided by certain utilities, including KCP&L and GMO, to come from renewable resources, increasing to 15% by 2021.  Kansas law requires certain utilities, including KCP&L, to have renewable energy generation capacity equal to at least 10% of their three-year average Kansas peak retail demand, increasing to 15% by 2016 and 20% by 2020.

Management believes that national renewable energy standards are also possible.  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.  Such requirements could have a significant financial and operational impact on the Companies.

The Environmental Protection Agency (EPA) has enacted various regulations regarding the reporting and permitting of greenhouse gases and has proposed other regulations under the existing Clean Air Act.  The EPA has established thresholds for greenhouse gas emissions, defining when Clean Air Act permits under the New Source Performance Standards, New Source Review and Title V operating permits programs would be required for new or existing industrial facilities and when the installation of best available control technology would be required.  Most of the Companies’ generating facilities are affected by these existing rules and would be affected by the proposed rules.  Additional federal and/or state legislation or regulation respecting greenhouse gas emissions may be proposed or enacted in the future.  Further, pursuant to the Collaboration Agreement, KCP&L agreed to pursue a set of initiatives including energy efficiency, additional wind generation, lower emission permit levels at its Iatan and La Cygne stations and other initiatives designed to offset CO2 emissions.  Requirements to reduce greenhouse gas emissions may cause the Companies to incur significant costs relating to their ongoing operations (for additional environmental control equipment, retiring and replacing existing generation, or selecting more costly generation alternatives), or to procure emission allowance credits, or due to the imposition of taxes, fees or other governmental charges as a result of such emissions.  

Rules issued by the EPA regarding emissions of mercury and other hazardous air pollutants, NOX, SO2 and particulates are also in a state of flux.  Some of these rules have been overturned by the courts and remanded to the EPA to be revised consistent with the courts’ orders while others have been stayed pending judicial review or are otherwise subject to revision.  The Companies’ current estimates of capital expenditures (exclusive of Allowance for Funds Used During Construction (AFUDC) and property taxes)

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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 is approximately $1 billion.  However, it is unknown what requirements and standards will be imposed in the future, when the Companies may have to comply or what costs may ultimately be required.

Water

The Clean Water Act and associated regulations enacted by the EPA form a comprehensive program to preserve water quality.  All of the Companies’ generating facilities, and certain of their other facilities, are subject to the Clean Water Act.

Previously issued EPA regulations regarding protection of aquatic life from being killed or injured by cooling water intake structures have been suspended; however, the EPA has proposed revised rulemaking on this matter.  At this time, the Companies are unable to predict how the EPA will respond or how that response will impact the Companies’ operations.

KCP&L holds a permit from the Missouri Department of Natural Resources (MDNR) authorizing KCP&L to, among other things, withdraw water from the Missouri River for cooling purposes and return the heated water to the Missouri river at its Hawthorn Station.  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 adverse 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 in September 2009 announced plans to revise the existing standards for waste water discharges from coal-fired power plants.  In November 2010, the EPA filed a motion requesting court approval of a consent agreement in which the EPA agreed to propose a rule in July 2012 and to finalize it in January 2014.  Until a rule is proposed and finalized, the financial and operational impacts cannot be determined.  Further, the possible effects of climate change, including potentially increased temperatures and reduced precipitation, could make it more difficult and costly to comply with the final permit requirements.

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.  The Companies principally use coal in generating electricity and dispose of coal combustion residuals (CCRs) in both on-site facilities and facilities owned by third parties.  In response to an incident at a Tennessee Valley Authority coal combustion product containment area, the EPA has proposed regulations regarding the handling and disposal of CCRs, which include alternative proposals to regulate CCRs as special or hazardous wastes or as non-hazardous wastes.  If enacted, any new laws and regulations, especially if CCRs are classified as hazardous waste, could have a material adverse effect on the Companies’ results of operations, financial position and cash flows.

Remediation

Under current law, the Companies are also generally responsible for any liabilities associated with the environmental condition of their properties, and other properties at which the Companies arranged for the disposal or treatment of hazardous substances, including properties that they have previously owned or operated, such as manufactured gas plants (MGP), regardless of whether they were responsible for the contamination or whether the liabilities arose before, during or after the time they owned or operated the properties or arranged for the disposal or treatment of hazardous substances. 

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Due to all of the above, the Companies’ projected capital and other expenditures for environmental compliance are subject to significant uncertainties, including the timing of implementation of any new or modified environmental requirements, the emissions limits imposed by such requirements and the types and costs of the compliance alternatives selected by the Companies.  As a result, costs to comply with environmental requirements cannot be estimated with certainty, and actual costs could be significantly higher than projections.  Other new environmental laws and regulations affecting the operations of the Companies may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to the Companies or their facilities, any of which may materially adversely affect the Companies’ business, adversely affect the Companies’ ability to continue operating its power plants as currently done and substantially increase their environmental expenditures or liabilities in the future.

Financial Risks:

Financial market disruptions and declines in credit ratings may increase financing costs and/or limit access to the credit markets, which may adversely affect liquidity and results.

The Companies’ capital requirements are expected to be substantial over the next several years.  The Companies rely on access to short-term money markets, revolving credit facilities provided by financial institutions and long-term capital markets as significant sources of liquidity for capital requirements not satisfied by cash flows from operations.  The Companies also rely on bank-provided credit facilities for credit support, such as letters of credit, to support operations.  The amount of credit support required for operations varies and is impacted by a number of factors, including the amount and price of wholesale power purchased or sold.  

Great Plains Energy, KCP&L, GMO and certain of their securities are rated by Moody's Investors Service and Standard & Poor's.  These ratings impact the Companies’ cost of funds and Great Plains Energy’s ability to provide credit support for its subsidiaries.  The interest rates on borrowings under the Companies’ revolving credit agreements and on a substantial portion of Great Plains Energy’s and GMO’s debt are subject to increase as their respective credit ratings decrease.  The Companies have agreed to not seek rate recovery of GMO interest costs in excess of equivalent investment-grade debt.  The amount of collateral or other credit support required under power supply and certain other agreements is also dependent on credit ratings.  

Although the United States capital and credit markets have generally stabilized after an extended period of volatility and disruption, there is no assurance that conditions will not deteriorate in the future due to the current instability in Europe or unforeseen events both in the United States and around the world.  Adverse market conditions or decreases in Great Plains Energy’s, KCP&L’s or GMO’s credit ratings could have material adverse effects on the Companies.  These effects could include, among others: reduced access to capital and increased cost of funds; dilution resulting from equity issuances at reduced prices; changes in the type and/or increases in the amount of collateral or other credit support obligations required to be posted with contractual counterparties; increased nuclear decommissioning trust and pension and other post-retirement benefit plan funding requirements; rate case disallowance of KCP&L’s or GMO’s costs of capital; reductions in or delays of capital expenditures, or reductions in Great Plains Energy’s ability to provide credit support for its subsidiaries.  Any of these results could adversely affect the Companies’ results of operations, financial position and cash flows.  In addition, market disruption and volatility could have an adverse impact on the Companies’ lenders, suppliers and other counterparties or customers, causing them to fail to meet their obligations.

Great Plains Energy has guaranteed substantially all of the outstanding debt of GMO and payments under these guarantees may adversely affect Great Plains Energy’s liquidity.

In connection with the GMO acquisition, Great Plains Energy issued guarantees covering substantially all of the outstanding debt of GMO and has guaranteed GMO’s current $450 million revolving credit facility.  The guarantees are a factor in GMO maintaining investment-grade ratings and the guarantees obligate Great Plains Energy to pay amounts owed by GMO directly to the holders of the guaranteed debt in the event GMO defaults on its payment obligations.  Great Plains Energy may also guarantee debt that GMO may issue in the future.  Any guarantee payments could adversely affect Great Plains Energy’s liquidity.

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The inability of Great Plains Energy’s subsidiaries to provide sufficient dividends to Great Plains Energy, or the inability otherwise of Great Plains Energy to pay dividends to its shareholders and meet its financial obligations would have an adverse effect.

Great Plains Energy is a holding company with no significant operations of its own.  The primary source of funds for payment of dividends to its shareholders and its other financial obligations is dividends paid to it by its subsidiaries, particularly KCP&L and GMO.  The ability of Great Plains Energy’s subsidiaries to pay dividends or make other distributions, and accordingly, Great Plains Energy’s ability to pay dividends on its common stock and meet its financial obligations principally depends on the actual and projected earnings and cash flow, capital requirements and general financial position of its subsidiaries, as well as regulatory factors, financial covenants, general business conditions and other matters.

In addition, Great Plains Energy, KCP&L and GMO are subject to certain corporate and regulatory restrictions and financial covenants that could affect their ability to pay dividends.  Great Plains Energy’s articles of incorporation restrict the payment of common stock dividends in the event common equity is 25% or less of total capitalization.  In addition, if preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares.  If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of directors necessary to constitute a majority of the full Great Plains Energy Board of Directors.  Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at least 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress).  Under the Federal Power Act, KCP&L and GMO generally can pay dividends only out of retained earnings.  The revolving credit agreements of Great Plains Energy, KCP&L and GMO contain a covenant requiring each company to maintain a consolidated indebtedness to consolidated total capitalization ratio of not more than 0.65 to 1.00.  In addition, Great Plains Energy is prohibited from paying dividends on its common and preferred stock in the event its Equity Unit contract payments or interest payments on the debt underlying the Equity Units are deferred until such deferrals have been paid.  While these corporate and regulatory restrictions and financial covenants are not expected to affect the Companies’ ability to pay dividends at the current level in the foreseeable future, there is no assurance that adverse financial results would not trigger such restrictions or covenants and reduce or eliminate the Companies’ ability to pay dividends.

Market performance, increased retirements and retirement plan regulations could significantly impact retirement plan funding requirements and associated cash needs and expenses.

Substantially all of the Companies’ and WCNOC’s employees participate in defined benefit retirement and post-retirement plans.  Former employees also have accrued benefits in defined benefit retirement and post-retirement plans.  The costs of these plans depend on a number of factors, including the rates of return on plan assets, the level and nature of the provided benefits, discount rates, the interest rates used to measure required minimum funding levels, changes in benefit design, changes in laws or regulations, and the Companies’ required or voluntary contributions to the plans.  The Companies currently have substantial unfunded liabilities under these plans.  Also, if the rate of retirements exceeds planned levels, or if these plans experience adverse market returns on investments, or if interest rates materially fall, the Companies’ contributions to the plans could rise substantially over historical levels.  In addition, changes in accounting rules and assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, could have a significant impact on the Companies’ results of operations, financial position and cash flows.

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The use of derivative contracts in the normal course of business could result in losses that could negatively impact the Companies’ results of operations, financial position and cash flows.

The Companies use derivative instruments, such as swaps, options, futures and forwards, to manage commodity and financial risks.  Losses could be recognized as a result of volatility in the market values of these contracts, if a counterparty fails to perform, or if the underlying transactions which the derivative instruments are intended to hedge fail to materialize.  In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or the use of estimates.  As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

As a service provider to GMO, KCP&L may have exposure to GMO’s financial performance and operations.

GMO has no employees of its own.  KCP&L employees operate and manage GMO’s properties, and KCP&L charges GMO for the cost of these services.  These arrangements may pose risks to KCP&L, including possible claims arising from actions of KCP&L employees in operating GMO’s properties and providing other services to GMO.  KCP&L’s claims for reimbursement for services provided to GMO are unsecured and rank equally with other unsecured obligations of GMO.  KCP&L’s ability to be reimbursed for the costs incurred for the benefit of GMO depends on the financial ability of GMO to make such payments.

Customer and Weather-Related Risks:

Changes in customer electricity consumption due to sustained financial market disruptions, downturns or sluggishness in the economy, technological advances, or other factors may adversely affect the Companies’ results of operations, financial position and cash flows.

The results of operations, financial position and cash flows of the Companies can be materially affected by changes in customer electricity consumption.  The Companies estimate customer electricity consumption based on historical trends to procure fuel and purchased power.  Sustained downturns or sluggishness in the economy generally affect the markets in which the Companies operate.  Additionally, technological advances or other energy conservation measures could reduce customer electricity consumption.

Weather is a major driver of the Companies’ results of operations, financial position and cash flow.

Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities.  Great Plains Energy and KCP&L are significantly impacted by seasonality, with approximately one-third of their retail electric revenues recorded in the third quarter.  Unusually mild winter or summer weather can adversely affect sales.  In addition, severe weather, including but not limited to tornados, snow, rain, flooding and ice storms can be destructive causing outages and property damage that can potentially result in additional expenses, lower revenues and additional capital restoration costs.  KCP&L’s and GMO’s rates may not always be adjusted timely and adequately to reflect these increased costs.  Some of the Companies’ generating stations utilize water from the Missouri River for cooling purposes.  Low water and flow levels, which have been experienced in past years, can increase maintenance costs at these stations and, if these levels were to get low enough, could require modifications to plant operations.  The possible effects of climate change (such as increased temperatures, increased occurrence of severe weather or reduced precipitation, among other possible results) could potentially increase the volatility of demand and prices for energy commodities, the frequency and impact of severe weather, increase the frequency of flooding or decrease water and flow levels.

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Operational Risks:

Operations risks may adversely affect the Companies’ results of operations, financial position and cash flows.

The operation of the Companies’ electric generation, transmission, distribution and information systems involves many risks, including breakdown or failure of equipment, processes and personnel performance; problems that delay or increase the cost of returning facilities to service after outages; limitations that may be imposed by equipment conditions, environmental, safety or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; transmission scheduling constraints; and catastrophic events such as fires, explosions, terrorism, cyber-threats, severe weather or other similar occurrences.  An equipment or system outage or constraint can, among other things:

·   in the case of generation equipment, affect operating costs, increase capital requirements and costs, increase purchased power volumes and costs and reduce wholesale sales opportunities;

·   in the case of transmission equipment, affect operating costs, increase capital requirements and costs, require changes in the source of generation and affect wholesale sales opportunities and the ability to meet regulatory reliability and security requirements;

·   in the case of distribution systems, affect revenues and operating costs, increase capital requirements and costs, and affect the ability to meet regulatory service metrics and customer expectations; and

·   in the case of information systems, affect the control and operations of generation, transmission, distribution and other business operations and processes, increase operating costs, increase capital requirements and costs, and affect the ability to meet regulatory reliability and security requirements and customer expectations.

With the exception of Hawthorn No. 5, which was substantially rebuilt in 2001, and Iatan No. 2, which was completed in 2010, all of KCP&L’s and GMO’s coal-fired generating units and its nuclear generating unit were constructed prior to 1986.  The age of these generating units increases the risk of unplanned outages, reduced generation output and higher maintenance expense.  Training, preventive maintenance and other programs have been implemented, but there is no assurance that these programs will prevent or minimize future breakdowns or failures of the Companies’ generation facilities or increased maintenance expense.

The Companies currently have general liability and property insurance in place to cover their facilities in amounts that management considers appropriate.  These policies, however, do not cover the Companies’ transmission or distribution systems, and the cost of repairing damage to these systems may adversely affect the Companies’ results of operations, financial position and cash flows.  Such policies are subject to certain limits and deductibles and do not include business interruption coverage.  Insurance coverage may not be available in the future at reasonable costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of the Companies’ facilities may not be sufficient to restore the loss or damage.

These and other operating events may reduce the Companies’ revenues, increase their costs, or both, and may materially affect their results of operations, financial position and cash flows.

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The cost and schedule of construction projects may materially change and expected performance may not be achieved.

Great Plains Energy’s and KCP&L’s businesses are capital intensive.  The Companies currently have significant construction projects pending and may also have significant construction projects in the future.  The risks of any construction project include: that actual costs may exceed estimated costs due to inflation or other factors; risks associated with the incurrence of additional debt or the issuance of additional equity to fund such projects; delays that may occur in obtaining permits and materials; the failure of suppliers and contractors to perform as required under their contracts; inadequate availability or increased cost of equipment, materials or qualified craft labor; the scope, cost and timing of projects may change due to new or changed environmental requirements or other factors; and other events beyond the Companies’ control may occur that may materially affect the schedule, cost and performance of these projects.

These and other risks could materially increase the estimated costs of construction projects, delay the in-service dates of projects, adversely affect the performance of the projects, and/or require the Companies to purchase additional electricity to supply their respective retail customers until the projects are completed.  Thus, these risks may significantly affect the Companies’ results of operations, financial position and cash flows.

Failure of one or more generation plant co-owners to pay their share of construction or operations and maintenance costs could increase the Companies’ costs and capital requirements.

KCP&L owns 47% of Wolf Creek, 50% of La Cygne Station, 70% of Iatan No. 1 and 55% of Iatan No. 2.  GMO owns 18% of both Iatan units and 8% of Jeffrey Energy Center.  The remaining portions of these facilities are owned by other utilities that are contractually obligated to pay their proportionate share of capital and other costs.

While the ownership agreements provide that a defaulting co-owner’s share of the electricity generated can be sold by the non-defaulting co-owners, there is no assurance that the revenues received will recover the increased costs borne by the non-defaulting co-owners.  Occurrence of these or other events could materially increase the Companies’ costs and capital requirements.

The Companies are subject to information security risks and risks of unauthorized access to their systems.

In the course of their businesses, the Companies handle a range of system security and sensitive customer information. KCP&L and GMO are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information.  A security breach of the utilities' information systems such as theft or the inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on the results of operations, financial condition and cash flows of the Companies.

KCP&L and GMO operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  Despite implementation of security measures, the technology systems are vulnerable to disability, failures, or unauthorized access.  Such failures or breaches of the systems could impact the reliability of the utilities’ generation and transmission and distribution systems and also subject the Companies to financial harm.  If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on the Companies’ results of operations, financial condition and cash flows.

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KCP&L is exposed to risks associated with the ownership and operation of a nuclear generating unit, which could result in an adverse effect on the Companies’ business and financial results.

KCP&L owns 47% of Wolf Creek.  The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including Wolf Creek.  In the event of non-compliance, the NRC has the authority to impose fines, shut down the facilities, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Any revised safety requirements promulgated by the NRC could result in substantial capital expenditures at Wolf Creek.  In addition, the events at the Fukushima nuclear power plant following the 2011 earthquake and tsunami in Japan could result in increased regulation of the nuclear industry and the introduction of additional requirements with respect to emergency planning and ability to deal with natural disasters.

Wolf Creek has the lowest fuel cost per MWh of any of KCP&L's generating units.  An extended outage of Wolf Creek, whether resulting from NRC action, an incident at the plant or otherwise, could have a material adverse effect on KCP&L's results of operations, financial position and cash flows in the event KCP&L incurs higher replacement power and other costs that are not recovered through rates or insurance.  If a long-term outage occurred, the state regulatory commissions could reduce rates by excluding the Wolf Creek investment from rate base.  Wolf Creek was constructed prior to 1986 and the age of Wolf Creek increases the risk of unplanned outages and higher maintenance costs.

Ownership and operation of a nuclear generating unit exposes KCP&L to risks regarding decommissioning costs at the end of the unit's life.  KCP&L contributes annually based on estimated decommissioning costs to a tax-qualified trust fund to be used to decommission Wolf Creek.  The funding level assumes a projected level of return on trust assets.  If the actual return on trust assets is below the projected level or actual decommissioning costs are higher than estimated, KCP&L could be responsible for the balance of funds required and may not be allowed to recover the balance through rates.

KCP&L is also exposed to other risks associated with the ownership and operation of a nuclear generating unit, including, but not limited to, potential liability associated with the potential harmful effects on the environment and human health resulting from the operation of a nuclear generating unit and the storage, handling, disposal and potential release (by accident, through third-party actions or otherwise) of radioactive materials.  Under the structure for insurance among owners of nuclear generating units, KCP&L is also liable for potential retrospective premium assessments (subject to a cap) per incident at any commercial reactor in the country and losses in excess of insurance coverage.

Commodity Price Risks:

Changes in commodity prices could have an adverse effect on the Companies’ results of operations, financial position and cash flows.

The Companies engage in the wholesale and retail marketing of electricity and are exposed to risks associated with the price of electricity.  To the extent that exposure to the price of electricity is not successfully hedged, the Companies could experience losses associated with the changing market price for electricity.

Increases in fuel, fuel transportation and purchased power prices could have an adverse impact on the Companies’ costs.

KCP&L’s Kansas retail rates contain an energy cost adjustment mechanism.  KCP&L’s Missouri retail rates do not contain a similar provision.  GMO’s retail electric and steam rates contain a fuel adjustment mechanism under which most, but not all, of the difference between actual fuel and purchased power costs and the amount of fuel and purchased power costs provided in base rates is passed along to GMO’s customers.  As a result, the Companies are exposed to varying degrees of risk from changes in the market prices of fuel for generation of electricity and purchased power.  Changes in the Companies’ fuel mix due to electricity demand, plant availability, transportation issues, fuel prices, fuel availability and other factors can also adversely affect the Companies’ fuel and purchased power costs.

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The Companies do not hedge their respective entire exposure from fuel and transportation price volatility.  Consequently, the Companies’ results of operations, financial position and cash flows may be materially impacted by changes in these prices unless and until increased costs are recovered in KCP&L’s Missouri retail rates.

Wholesale electricity sales affect revenues, creating earnings volatility.

The levels of the Companies’ wholesale sales depend on the wholesale market price, transmission availability and the availability of generation for wholesale sales, among other factors.  A substantial portion of wholesale sales are made in the spot market, and thus the Companies have immediate exposure to wholesale price changes.  Wholesale power prices can be volatile and generally increase in times of high regional demand and high natural gas prices.  Conversely, wholesale power prices generally decrease in times of low regional demand and low natural gas prices.  While an allocated portion of wholesale sales are reflected in KCP&L’s Kansas energy cost adjustment and GMO’s fuel adjustment mechanisms, KCP&L’s Missouri rates are set on an estimated amount of wholesale sales.  KCP&L will not recover any shortfall in non-firm wholesale electric sales margin from the level included in Missouri rates and any amount above the level reflected in Missouri retail rates will be returned to Missouri retail customers in a future rate case.  Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce the Companies’ wholesale sales and may materially affect the Companies’ results of operations, financial conditions and cash flows.

Litigation Risks:

The outcome of legal proceedings cannot be predicted.  An adverse finding could have a material adverse effect on the Companies’ results of operations, financial position and cash flows.

The Companies are party to various material litigation and regulatory matters arising out of their business operations.  The ultimate outcome of these matters cannot presently be determined, nor, in many cases, can the liability that could potentially result from a negative outcome in each case be reasonably estimated.  The liability that the Companies may ultimately incur with respect to any of these cases in the event of a negative outcome may be in excess of amounts currently reserved and insured against with respect to such matters.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

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ITEM 2.  PROPERTIES

Electric Utility Generation Resources

				Year	Estimated 2012			Primary
		Unit	Location	Completed	MW Capacity			Fuel
Base Load		Iatan No. 2	Missouri	2010		482	(a)	Coal
		Wolf Creek	Kansas	1985		547	(a)	Nuclear
		Iatan No. 1	Missouri	1980		493	(a)	Coal
		La Cygne No. 2	Kansas	1977		343	(a)	Coal
		La Cygne No. 1	Kansas	1973		368	(a)	Coal
		Hawthorn No. 5 (b)	Missouri	1969		564		Coal
		Montrose No. 3	Missouri	1964		176		Coal
		Montrose No. 2	Missouri	1960		164		Coal
		Montrose No. 1	Missouri	1958		170		Coal
Peak Load		West Gardner Nos. 1, 2, 3 and 4	Kansas	2003		310		Natural Gas
		Osawatomie	Kansas	2003		75		Natural Gas
		Hawthorn Nos. 6 and 9	Missouri	2000		232		Natural Gas
		Hawthorn No. 8	Missouri	2000		77		Natural Gas
		Hawthorn No. 7	Missouri	2000		77		Natural Gas
		Northeast Black Start Unit	Missouri	1985		2		Oil
		Northeast Nos. 17 and 18	Missouri	1977		110		Oil
		Northeast Nos. 13 and 14	Missouri	1976		105		Oil
		Northeast Nos. 15 and 16	Missouri	1975		94		Oil
		Northeast Nos. 11 and 12	Missouri	1972		99		Oil
Wind		Spearville 2 Wind Energy Facility (c)	Kansas	2010		4		Wind
		Spearville Wind Energy Facility (d)	Kansas	2006		8		Wind
Total KCP&L						4,500
Base Load		Iatan No. 2	Missouri	2010		159	(a)	Coal
		Iatan No. 1	Missouri	1980		127	(a)	Coal
		Jeffrey Energy Center Nos. 1, 2 and 3	Kansas	1978, 1980, 1983		174	(a)	Coal
		Sibley Nos. 1, 2 and 3	Missouri	1960, 1962, 1969		463		Coal
		Lake Road Nos. 2 and 4	Missouri	1957, 1967		119		Coal and Natural Gas
Peak Load		South Harper Nos. 1, 2 and 3	Missouri	2005		317		Natural Gas
		Crossroads Energy Center	Mississippi	2002		297		Natural Gas
		Ralph Green No. 3	Missouri	1981		71		Natural Gas
		Greenwood Nos. 1, 2, 3 and 4	Missouri	1975-1979		253		Natural Gas/Oil
		Lake Road No. 5	Missouri	1974		65		Natural Gas/Oil
		Lake Road Nos. 1 and 3	Missouri	1951, 1962		33		Natural Gas/Oil
		Lake Road Nos. 6 and 7	Missouri	1989, 1990		42		Oil
		Nevada	Missouri	1974		19		Oil
Total GMO						2,139
Total Great Plains Energy						6,639
(a)	Share of a jointly owned unit.
(b)	The Hawthorn Generating Station returned to commercial operation in 2001 with a new boiler, air quality control equipment and
	an uprated turbine following a 1999 explosion.
(c)	The 48 MW Spearville 2 Wind Energy Facility's accredited capacity is 4 MW pursuant to SPP reliability standards.
(d)	The 100.5 MW Spearville Wind Energy Facility's accredited capacity is 8 MW pursuant to SPP reliability standards.

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KCP&L owns 50% of La Cygne Nos. 1 and 2, 70% of Iatan No. 1, 55% of Iatan No. 2 and 47% of Wolf Creek.  GMO owns 18% of Iatan Nos. 1 and 2 and 8% of Jeffrey Energy Center Nos. 1, 2 and 3.

Electric Utility Transmission and Distribution Resources

Electric utility’s electric transmission system interconnects with systems of other utilities for reliability and to permit wholesale transactions with other electricity suppliers.  Electric utility has approximately 3,600 circuit miles of transmission lines, 15,600 circuit miles of overhead distribution lines and 6,600 circuit miles of underground distribution lines in Missouri and Kansas.  Electric utility has all material franchise rights necessary to sell electricity within its retail service territory.  Electric utility’s transmission and distribution systems are continuously monitored for adequacy to meet customer needs.  Management believes the current systems are adequate to serve customers.

Electric Utility General

Electric utility’s generating plants are located on property owned (or co-owned) by KCP&L or GMO, except the Spearville Wind Energy Facilities which are located on easements and the Crossroads Energy Center and South Harper which are contractually controlled.  Electric utility’s service centers, electric substations and a portion of its transmission and distribution systems are located on property owned or leased by electric utility.  Electric utility’s transmission and distribution systems are for the most part located above or underneath highways, streets, other public places or property owned by others.  Electric utility believes that it has satisfactory rights to use those places or properties in the form of permits, grants, easements, licenses or franchise rights; however, it has not necessarily undertaken efforts to examine the underlying title to the land upon which the rights rest.  Great Plains Energy’s and KCP&L’s headquarters are located in leased office space.

Substantially all of the fixed property and franchises of KCP&L, which consist principally of electric generating stations, electric transmission and distribution lines and systems, and buildings (subject to exceptions, reservations and releases), are subject to a General Mortgage Indenture and Deed of Trust dated as of

December 1, 1986.  Mortgage bonds totaling $642.5 million were outstanding at December 31, 2011.

Substantially all of the fixed property and franchises of GMO’s St. Joseph Light & Power division is subject to a General Mortgage Indenture and Deed of Trust dated as of April 1, 1946.  Mortgage bonds totaling $11.2 million were outstanding at December 31, 2011.

ITEM 3.  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, 14 and 15 to the consolidated financial statements.  Such descriptions are incorporated herein by reference.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

GREAT PLAINS ENERGY

Great Plains Energy’s common stock is listed on the New York Stock Exchange under the symbol “GXP”.  At February 21, 2012, Great Plains Energy’s common stock was held by 20,770 shareholders of record.  Information relating to market prices and cash dividends on Great Plains Energy's common stock is set forth in the following table.

	Common Stock Price Range (a)								Common Stock
	2011				2010				Dividends Declared
Quarter	High		Low		High		Low		2012			2011		2010
First	$	20.08	$	18.94	$	19.60	$	17.43	$	0.2125	(b)	$	0.2075	$	0.2075
Second		21.17		19.70		19.63		16.85					0.2075		0.2075
Third		21.24		16.53		19.06		16.95					0.2075		0.2075
Fourth		21.97		18.68		19.63		18.58					0.2125		0.2075
(a) Based on closing stock prices.
(b) Declared February 7, 2012, and payable March 20, 2012, to shareholders of record as of February 28, 2012.

Dividend Restrictions

For information regarding dividend restrictions, see Note 12 to the consolidated financial statements.

Purchases of Equity Securities

The following table provides information regarding purchases by the Company of its equity securities during the fourth quarter of 2011.

Issuer Purchases of Equity Securities
								Maximum Number
						Total Number of		(or Approximate
						Shares (or Units)		Dollar Value) of
	Total					Purchased as		Shares (or Units)
	Number of			Average		Part of Publicly		that May Yet Be
	Shares			Price Paid		Announced		Purchased Under
	(or Units)			per Share		Plans or		the Plans or
Month	Purchased			(or Unit)		Programs		Programs
October 1 - 31		-		$	-		-		N/A
November 1 - 30		210	(1)		19.97		-		N/A
December 1 - 31		-			-		-		N/A
Total		210		$	19.97		-		N/A
(1) Represents restricted common shares surrendered to the Company following the resignation of a certain officer.

KCP&L

KCP&L is a wholly owned subsidiary of Great Plains Energy, which holds the one share of issued and outstanding KCP&L common stock.

Dividend Restrictions

For information regarding dividend restrictions, see Note 12 to the consolidated financial statements.

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ITEM 6.  SELECTED FINANCIAL DATA

Year Ended December 31	2011		2010		2009		2008		2007
Great Plains Energy (a)	(dollars in millions except per share amounts)
Operating revenues	$	2,318	$	2,256	$	1,965	$	1,670	$	1,293
Income from continuing operations (b)	$	174	$	212	$	152	$	120	$	121
Net income attributable to Great Plains Energy	$	174	$	212	$	150	$	155	$	159
Basic earnings per common
share from continuing operations	$	1.27	$	1.55	$	1.16	$	1.16	$	1.41
Basic earnings per common share	$	1.27	$	1.55	$	1.15	$	1.51	$	1.86
Diluted earnings per common
share from continuing operations	$	1.25	$	1.53	$	1.15	$	1.16	$	1.40
Diluted earnings per common share	$	1.25	$	1.53	$	1.14	$	1.51	$	1.85
Total assets at year end	$	9,118	$	8,818	$	8,483	$	7,869	$	4,832
Total redeemable preferred stock, mandatorily
redeemable preferred securities and long-
term debt (including current maturities)	$	3,544	$	3,428	$	3,214	$	2,627	$	1,103
Cash dividends per common share	$	0.835	$	0.83	$	0.83	$	1.66	$	1.66
SEC ratio of earnings to fixed charges		2.03		2.28		1.81		2.26		2.53
KCP&L
Operating revenues	$	1,558	$	1,517	$	1,318	$	1,343	$	1,293
Net income	$	136	$	163	$	129	$	125	$	157
Total assets at year end	$	6,292	$	6,026	$	5,702	$	5,229	$	4,292
Total redeemable preferred stock, mandatorily
redeemable preferred securities and long-
term debt (including current maturities)	$	1,915	$	1,780	$	1,780	$	1,377	$	1,003
SEC ratio of earnings to fixed charges		2.52		2.86		2.44		2.87		3.53
(a) Great Plains Energy's results include GMO only from the July 14, 2008, acquisition date.
(b) This amount is before income (loss) from discontinued operations, net of income taxes, of $(1.5) million, $35.0 million
and $38.3 million in 2009 through 2007, respectively.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GREAT PLAINS ENERGY INCORPORATED

EXECUTIVE SUMMARY

Description of Business

Great Plains Energy is a public utility holding company and does not own or operate any significant assets other than the stock of its subsidiaries.  Great Plains Energy’s direct subsidiaries with operations or active subsidiaries are KCP&L and GMO.  Great Plains Energy’s sole reportable business segment is electric utility for the periods presented.

Electric utility consists of KCP&L, a regulated utility, and GMO’s regulated utility operations, which include its Missouri Public Service and St. Joseph Light & Power divisions.  Electric utility has over 6,600 MWs of generating capacity and engages in the generation, transmission, distribution and sale of electricity to approximately 823,000 customers in the states of Missouri and Kansas.  Electric utility’s retail electricity rates are below the national average of investor-owned utilities.

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2011 Earnings Overview

Great Plains Energy’s 2011 earnings available for common shareholders decreased to $172.8 million or $1.25 per share from $210.1 million or $1.53 per share in 2010.  Several of KCP&L’s coal-fired power plants were impacted by flooding along the Missouri River in 2011, which decreased gross margin by an estimated $16 million due to coal conservation activities and increased other operating expenses $3.3 million.  Gross margin also decreased due to unfavorable weather and demand, an estimated $11 million from the impact of an extended refueling outage at Wolf Creek, and $7.5 million from increased coal transportation costs not recovered in KCP&L’s Missouri retail rates where there is no fuel recovery mechanism.  Also in 2011, Great Plains Energy recognized $12.7 million of expense related to a voluntary separation program and a $13.1 million increase in electric utility’s general taxes driven by higher property taxes.

Partially offsetting these decreases were new retail rates in Kansas effective December 1, 2010, and Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO.  In 2010, electric utility recognized a $16.8 million pre-tax loss representing KCP&L’s and GMO’s combined share of construction costs for the Iatan No. 1 environmental equipment and the Iatan No. 2 construction project.

Gross margin is a financial measure that is not calculated in accordance with Generally Accepted Accounting Principles (GAAP).  See the explanation of gross margin and the reconciliation to GAAP operating revenues under Great Plains Energy’s Results of Operations for further information.

KCP&L Kansas Rate Case Proceedings

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

KCP&L Missouri Rate Case Proceedings

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

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

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

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

GMO Missouri Rate Case Proceedings

On February 27, 2012, GMO filed an application with the MPSC to request an increase of its retail rates of $58.3 million for its Missouri Public Service division and $25.2 million for its L&P division, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%.  The requests include recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service, costs related to energy efficiency and demand side management programs, and increased fuel costs.

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

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

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

Additionally, with respect to GMO’s Missouri Public Service division, the MPSC concluded that GMO’s decision to add Crossroads Energy Center (Crossroads) to its generation asset resources was prudent and reasonable; however, the order disallowed from rate base approximately $50 million for Crossroads, disallowed $4.9 million in associated annual transmission expense and offset rate base by approximately $15 million to reflect accumulated deferred taxes associated with Crossroads.  GMO’s request included a net plant amount of approximately $104 million for Crossroads.  In assessing the impact of the Crossroads disallowances, management considered that KCP&L’s and GMO’s generation asset resources include a diverse fuel mix consisting primarily of coal and nuclear fuel providing base load generation with natural gas facilities such as

28

Crossroads to provide critical peaking and capacity support.  This combined collection of generating assets meets KCP&L’s and GMO’s service obligations and produces joint cash flows based on system-wide average costs.  Great Plains Energy conducted an analysis to assess the recoverability of the combined collection of generation asset resources and determined that no potential impairment exists.

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

GMO Fuel Adjustment Clause (FAC) Prudence Review

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

Transmission Investment Opportunities

In September 2010, GMO accepted a Notification to Construct from SPP for the Missouri portion of a 175-mile, 345kV transmission line in GMO’s service territory from Sibley, Missouri to Nebraska City, Nebraska with an estimated cost of about $380 million for GMO’s portion of the line and an expected 2017 in-service date.  This line is one of a number of priority projects that the SPP has developed as part of its transmission expansion plans for the region.  In June 2010, FERC approved the SPP’s proposed cost allocation method for these projects.  KCP&L has also accepted a Notification to Construct from SPP for a 30-mile, 345kV transmission line, with estimated construction costs of $54 million and an expected 2015 in-service date, from KCP&L’s Iatan generating station to KCP&L’s Nashua substation.  GMO and KCP&L have the obligation to build their separate lines, which may be done solely or with other entities, unless the obligation is transferred to another qualified transmission owner.  GMO and KCP&L are evaluating alternative courses of action.  SPP retains the authority to revise or withdraw existing Notifications to Construct for transmission projects based upon emerging transmission plans and the associated needs for specific projects.

Wolf Creek Outage

On January 13, 2012, a breaker in a substation located at Wolf Creek failed.  This failure was immediately followed by a loss of station power to Wolf Creek resulting in an unscheduled shutdown of Wolf Creek.  Wolf Creek is expected to resume normal operations in March 2012 following the completion of repairs.  This schedule assumes no discovery during the course of repairs of additional required work, and that all requirements of the NRC for resumption of normal operations are satisfied.  Additional maintenance expenses and capital expenditures are expected as a result of this unscheduled outage.

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ENVIRONMENTAL MATTERS

Electric utility’s current generation capacity is over 50% coal-fired and subject to extensive environmental regulation.  Approximately 60% of electric utility’s coal-fired generation facilities have emission control equipment installed.  Current plans call for 85% of the coal-fired facilities to have emission control equipment installed by approximately 2016.  It is less likely that the remaining coal-fired units will have emission control equipment installed and they have a combined remaining net book value of approximately 1.5% of the Company’s $7.1 billion utility plant balance.  In the event that the Company decides it is not cost effective to proceed with these less likely projects and determines that early retirement is the most prudent course of action for these generating facilities, the Company expects that the costs would continue to be capitalized and recovered in rates.  However, there is no assurance that these investments would be recovered in rates and any amount not recovered would be recorded as a loss when such loss becomes probable.  See Note 14 to the consolidated financial statements for additional information regarding environmental matters.

RELATED PARTY TRANSACTIONS

See Note 17 to the consolidated financial statements for information regarding related party transactions.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures.  Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or different estimates that could have been used could have a material impact on Great Plains Energy’s results of operations and financial position.  Management has identified the following accounting policies as critical to the understanding of Great Plains Energy’s results of operations and financial position.  Management has discussed the development and selection of these critical accounting policies with the Audit Committee of the Great Plains Energy Board of Directors (Board).

Pensions

Great Plains Energy and KCP&L incur significant costs in providing non-contributory defined pension benefits.  The costs are measured using actuarial valuations that are dependent upon numerous factors derived from actual plan experience and assumptions of future plan experience.

Pension costs are impacted by actual employee demographics (including age, life expectancies, compensation levels and employment periods), earnings on plan assets, the level of contributions made to the plan, and plan amendments.  In addition, pension costs are also affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

The assumed rate of return on plan assets was developed based on the weighted-average of long-term returns forecast for the expected portfolio mix of investments held by the plan.  The assumed discount rate was selected based on the prevailing market rate of fixed income debt instruments with maturities matching the expected timing of the benefit obligation.  These assumptions, updated annually at the measurement date, are based on management’s best estimates and judgment; however, material changes may occur if these assumptions differ from actual events.  See Note 8 to the consolidated financial statements for information regarding the assumptions used to determine benefit obligations and net costs.

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The following table reflects the sensitivities associated with a 0.5% increase or a 0.5% decrease in key actuarial assumptions.  Each sensitivity reflects the impact of the change based on a change in that assumption only.

					Impact on			Impact on
					Projected			2011
	Change in				Benefit			Pension
Actuarial assumption	Assumption				Obligation			Expense
					(millions)
Discount rate		0.5	%	increase	$	(64.4	)	$	(5.1	)
Rate of return on plan assets		0.5	%	increase		-			(2.8	)
Discount rate		0.5	%	decrease		69.1			5.2
Rate of return on plan assets		0.5	%	decrease		-			2.8

Pension expense for KCP&L is recorded in accordance with rate orders from the MPSC and KCC.  The orders allow the difference between pension costs under GAAP and pension costs for ratemaking to be recorded as a regulatory asset or liability with future ratemaking recovery or refunds, as appropriate.  The impact on 2011 pension expense in the table above reflects the impact on GAAP pension costs.  Under the Companies’ rate agreements, any increase or decrease would be deferred in a regulatory asset or liability for future ratemaking treatment.  KCP&L recorded 2011 pension expense of $42.6 million after allocations to the other joint owners of generating facilities and capitalized amounts in accordance with the MPSC and KCC rate orders.  GMO records pension expense in accordance with rate orders from the MPSC.  The difference between this expense and GAAP expense is recorded as a regulatory asset or liability.  See Note 8 to the consolidated financial statements for additional discussion of the accounting for pensions.

The Company's projected 2012 weighted average long-term rate of return on plan assets is 7.3%, unchanged from 2011.  Market conditions and interest rates significantly affect the future assets and liabilities of the plan.  It is difficult to predict future pension costs, changes in pension liability and cash funding requirements due to volatile market conditions.

Regulatory Matters

Great Plains Energy and KCP&L have recorded assets and liabilities on their consolidated balance sheets resulting from the effects of the ratemaking process, which would not otherwise be recorded under GAAP.  Regulatory assets represent incurred costs that are probable of recovery from future revenues.  Regulatory liabilities represent future reductions in revenues or refunds to customers.

Management regularly assesses whether regulatory assets and liabilities are probable of future recovery or refund by considering factors such as decisions by the MPSC, KCC or FERC in electric utility’s rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedent on matters applicable to electric utility; and changes in laws and regulations.  If recovery or refund of regulatory assets or liabilities is not approved by regulators or is no longer deemed probable, these regulatory assets or liabilities are recognized in the current period results of operations.  Electric utility’s continued ability to meet the criteria for recording regulatory assets and liabilities may be affected in the future by restructuring and deregulation in the electric industry or changes in accounting rules.  In the event that the criteria no longer applied to all or a portion of electric utility’s operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism were provided.  Additionally, these factors could result in an impairment on utility plant assets.  See Note 5 to the consolidated financial statements for additional information.

Impairments of Assets, Intangible Assets and Goodwill

Long-lived assets and intangible assets subject to amortization are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under GAAP.

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Accounting rules require goodwill to be tested for impairment annually and when an event occurs indicating the possibility that an impairment exists.  The goodwill impairment test is a two step process.  The first step compares the fair value of a reporting unit to its carrying amount, including goodwill, to identify potential impairment.  If the carrying amount exceeds the fair value of the reporting unit, the second step of the test is performed, consisting of assignment of the reporting unit’s fair value to its assets and liabilities to determine an implied fair value of goodwill, which is compared to the carrying amount of goodwill to determine the impairment loss, if any, to be recognized in the financial statements.  Great Plains Energy’s regulated electric utility operations are considered one reporting unit for assessment of impairment, as they are included within the same operating segment and have similar economic characteristics.

The annual impairment test for the $169.0 million of GMO acquisition goodwill was conducted on September 1, 2011.  Fair value of the reporting unit exceeded the carrying amount by over $800 million, including goodwill; therefore, there was no impairment of goodwill.

The determination of fair value of the reporting unit consisted of two valuation techniques: an income approach consisting of a discounted cash flow analysis and a market approach consisting of a determination of reporting unit invested capital using market multiples derived from the historical revenue, EBITDA and net utility asset values and market prices of stock of electric and gas company regulated peers.  The results of the two techniques were evaluated and weighted to determine a point within the range that management considered representative of fair value for the reporting unit, which involves a significant amount of management judgment.

The discounted cash flow analysis is most significantly impacted by two assumptions: estimated future cash flows and the discount rate applied to those cash flows.  Management determined the appropriate discount rate to be based on the reporting unit’s weighted average cost of capital (WACC).  The WACC takes into account both the cost of equity and after-tax cost of debt.  Estimated future cash flows are based on Great Plains Energy’s internal business plan, which assumes the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of return on equity, anticipated earnings/returns related to future capital investments, continued recovery of cost of service and the renewal of certain contracts.  Management also makes assumptions regarding the run rate of operations, maintenance and general and administrative costs based on the expected outcome of the aforementioned events.  Should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, revisions to current cash flow assumptions could cause the fair value of Great Plains Energy’s reporting unit under the income approach to be significantly different in future periods and could result in a future impairment charge to goodwill.

The market approach analysis is most significantly impacted by management’s selection of relevant electric and gas company regulated peers as well as the determination of an appropriate control premium to be added to the calculated invested capital of the reporting unit, as control premiums associated with a controlling interest are not reflected in the quoted market price of a single share of stock.  Management determined an appropriate control premium by using an average of control premiums for recent acquisitions in the industry.  Changes in results of peer companies, selection of different peer companies and future acquisitions with significantly different control premiums could result in a significantly different fair value of Great Plains Energy’s reporting unit.

Income Taxes

Income taxes are accounted for using the asset/liability approach.  Deferred tax assets and liabilities are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, applying enacted statutory tax rates in effect for the year in which the differences are expected to reverse.  Deferred investment tax credits are amortized ratably over the life of the related property.  Deferred tax assets are also recorded for net operating loss, capital loss and tax credit carryforwards.  The Company is required to estimate the amount of taxes payable or refundable for the current year and the deferred tax liabilities and assets for future tax consequences of events reflected in the Company’s consolidated financial statements or tax returns.  This process requires management to make assessments regarding the timing and probability of the

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ultimate tax impact.  The Company records valuation allowances on deferred tax assets if it is determined that it is more likely than not that the asset will not be realized.

Additionally, the Company establishes reserves for uncertain tax positions based upon management’s judgment regarding potential future challenges to those positions.  The accounting estimates related to the liability for uncertain tax positions require management to make judgments regarding the sustainability of each uncertain tax position based on its technical merits.  If it is determined that it is more likely than not a tax position will be sustained based on its technical merits, the impact of the position is recorded in the Company’s consolidated financial statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement.  These estimates are updated at each reporting date based on the facts, circumstances and information available.  Management is also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months.  See Note 20 to the consolidated financial statements for additional information.

GREAT PLAINS ENERGY RESULTS OF OPERATIONS

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

	2011			2010			2009
	(millions)
Operating revenues	$	2,318.0		$	2,255.5		$	1,965.0
Fuel		(483.8	)		(430.7	)		(405.5	)
Purchased power		(203.4	)		(213.8	)		(183.7	)
Transmission of electricity by others		(30.2	)		(27.4	)		(26.9	)
Gross margin (a)		1,600.6			1,583.6			1,348.9
Other operating expenses		(835.0	)		(779.7	)		(726.6	)
Voluntary separation program		(12.7	)		-			-
Depreciation and amortization		(273.1	)		(331.6	)		(302.2	)
Operating income		479.8			472.3			320.1
Non-operating income and expenses		(2.3	)		24.4			42.6
Interest charges		(218.4	)		(184.8	)		(180.9	)
Income tax expense		(84.8	)		(99.0	)		(29.5	)
Loss from equity investments		(0.1	)		(1.0	)		(0.4	)
Income from continuing operations		174.2			211.9			151.9
Loss from discontinued operations		-			-			(1.5	)
Net income		174.2			211.9			150.4
Less: Net (income) loss attributable to noncontrolling interest		0.2			(0.2	)		(0.3	)
Net income attributable to Great Plains Energy		174.4			211.7			150.1
Preferred dividends		(1.6	)		(1.6	)		(1.6	)
Earnings available for common shareholders	$	172.8		$	210.1		$	148.5
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin below.

2011 compared to 2010

Great Plains Energy’s 2011 earnings available for common shareholders decreased to $172.8 million, or $1.25 per share, from $210.1 million, or $1.53 per share in 2010.

Electric utility’s net income decreased $35.4 million in 2011 compared to 2010.  Flooding along the Missouri River in 2011 decreased gross margin by an estimated $16 million due to coal conservation activities and increased other operating expenses $3.3 million.  Gross margin also decreased due to unfavorable weather and demand, an estimated $11 million expense from the impact of an extended refueling outage at Wolf Creek and $7.5 million from increased coal transportation costs not recovered in KCP&L’s Missouri retail rates.  Also in 2011, electric utility recognized $12.7 million of expense related to a voluntary separation program and general

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taxes increased $13.1 million driven by higher property taxes.  Partially offsetting these decreases were new retail rates in Kansas effective December 1, 2010, and Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO.  In 2010, electric utility recognized a $16.8 million pre-tax loss representing KCP&L’s and GMO’s combined share of construction costs for the Iatan No. 1 environmental equipment and the Iatan No. 2 construction project.

Great Plains Energy’s corporate and other activities loss from continuing operations increased $1.9 million in 2011 compared to 2010.

2010 compared to 2009

Great Plains Energy’s 2010 earnings available for common shareholders increased to $210.1 million, or $1.53 per share, from $148.5 million, or $1.14 per share in 2009.

Electric utility’s net income increased $77.5 million in 2010 compared to 2009 primarily driven by an increase in gross margin due to new retail rates and favorable weather.  Partially offsetting the increase in gross margin were higher operating and maintenance expenses driven by planned plant outages, increased depreciation and amortization expense due to additional regulatory amortization pursuant to KCP&L’s 2009 rate cases and depreciation from placing in service the Iatan No. 1 environmental equipment during 2009 and Iatan No. 2 during 2010 (Kansas jurisdiction only), increased general taxes and a decrease in the equity component of AFUDC.  Electric utility also recorded a $16.8 million pre-tax loss in 2010 representing KCP&L’s and GMO’s combined share of the impact of disallowed construction costs for the Iatan No. 1 environmental equipment and the Iatan No. 2 construction project.

Great Plains Energy’s corporate and other activities had an additional $17.4 million loss from continuing operations in 2010 compared to 2009 primarily due to $7.1 million of after-tax write downs of affordable housing investments and an additional $6.8 million of after-tax interest expense for Equity Units issued in 2009.  Additionally, 2009 reflects a $16.0 million tax benefit due to the settlement of GMO’s 2003-2004 tax audit.  Partially offsetting these items was the recognition of $3.9 million of deferred tax credits upon the sale of GMO’s former headquarters and $2.4 million of after-tax interest income, net of fees, from an interest refund from the IRS in 2010.

Gross Margin

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

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ELECTRIC UTILITY RESULTS OF OPERATIONS

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

	2011			2010			2009
	(millions)
Operating revenues	$	2,318.0		$	2,255.5		$	1,965.0
Fuel		(483.8	)		(430.7	)		(405.5	)
Purchased power		(203.4	)		(213.8	)		(183.7	)
Transmission of electricity by others		(30.2	)		(27.4	)		(26.9	)
Gross margin (a)		1,600.6			1,583.6			1,348.9
Other operating expenses		(828.7	)		(773.4	)		(712.0	)
Voluntary separation program		(12.7	)		-			-
Depreciation and amortization		(273.1	)		(331.6	)		(302.2	)
Operating income		486.1			478.6			334.7
Non-operating income and expenses		-			23.1			37.7
Interest charges		(176.9	)		(143.1	)		(151.0	)
Income tax expense		(109.3	)		(123.3	)		(63.6	)
Net income	$	199.9		$	235.3		$	157.8
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great
Plains Energy's Results of Operations.

Electric Utility Gross Margin and MWh Sales

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

				%						%
Gross Margin (a)	2011			Change			2010			Change		2009
Retail revenues	(millions)
Residential	$	955.8			4		$	915.8			19	$	772.6
Commercial		878.8			5			838.0			11		752.5
Industrial		196.7			2			193.5			13		171.9
Other retail revenues		19.5			11			17.5			2		17.2
Kansas property tax surcharge		3.7		NA				-		NA			-
Provision for rate refund		(2.9	)		(23	)		(3.7	)	NA			-
Fuel recovery mechanism under recovery		50.6			18			42.9			31		32.8
Total retail		2,102.2			5			2,004.0			15		1,747.0
Wholesale revenues		172.4			(16	)		205.9			18		174.6
Other revenues		43.4			(5	)		45.6			5		43.4
Operating revenues		2,318.0			3			2,255.5			15		1,965.0
Fuel		(483.8	)		12			(430.7	)		6		(405.5	)
Purchased power		(203.4	)		(5	)		(213.8	)		16		(183.7	)
Transmission of electricity by others		(30.2	)		10			(27.4	)		2		(26.9	)
Gross margin	$	1,600.6			1		$	1,583.6			17	$	1,348.9
(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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			%					%
MWh Sales	2011		Change			2010		Change			2009
Retail MWh sales	(thousands)
Residential		9,285		(2	)		9,459		9			8,647
Commercial		10,782		(2	)		10,950		3			10,637
Industrial		3,218		(2	)		3,286		5			3,143
Other retail MWh sales		119		8			111		(9	)		122
Total retail		23,404		(2	)		23,806		6			22,549
Wholesale MWh sales		5,491		(16	)		6,534		16			5,626
Total MWh sales		28,895		(5	)		30,340		8			28,175

Electric utility’s residential customers’ usage is significantly affected by weather.  Bulk power sales, the major component of wholesale sales, vary with system requirements, generating unit, purchased power and transmission availability, fuel costs, and requirements of other electric systems.  Electric utility’s revenues contain certain fuel recovery mechanisms as follows:

·   KCP&L’s Kansas retail rates contain an Energy Cost Adjustment (ECA) tariff.  The ECA tariff reflects the projected annual amounts of fuel, purchased power, emission allowances, transmission costs and asset-based off-system sales margin.  These projected amounts are subject to quarterly re-forecasts.  Any difference between the ECA revenue collected and the actual ECA amounts for a given year (which may be positive or negative) is recorded as an increase to or reduction of retail revenues and deferred as a regulatory asset or liability to be recovered from or refunded to Kansas retail customers over twelve months beginning April 1 of the succeeding year.

·   GMO’s electric retail rates contain a Fuel Adjustment Clause (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 FAC cycle consists of an accumulation period of six months beginning in June and December with FAC rate approval requested every six months for a twelve month recovery period.  The FAC is recorded as an increase to or reduction of retail revenues and deferred as a regulatory asset or liability to be recovered from or refunded to GMO’s electric retail customers.

·   GMO’s steam rates contain a Quarterly Cost Adjustment (QCA) under which 85% of the difference between actual fuel costs and base fuel costs is passed along to GMO’s steam customers.  The QCA is recorded as an increase to or reduction of other revenues and deferred as a regulatory asset or liability to be recovered from or refunded to GMO’s steam customers.

KCP&L’s Missouri retail rates do not contain a fuel recovery mechanism, meaning that changes in fuel and purchased power costs will not be reflected in rates until new rates are authorized by the MPSC creating a regulatory lag between the time costs change and when they are reflected in rates.  This regulatory lag applies to all costs not included in fuel recovery mechanisms as described above.  In the current rising cost environment, regulatory lag can be expected to have an adverse impact, which could be material, on Great Plains Energy’s results of operations.  Additionally, KCP&L’s retail rates in Missouri reflect a set level of non-firm wholesale electric sales margin.  KCP&L will not recover any shortfall in non-firm wholesale electric sales margin from the level included in Missouri retail rates and any amount of margin above the level reflected in Missouri retail rates will be returned to KCP&L Missouri retail customers in a future rate case.

Electric utility’s gross margin increased $17.0 million in 2011 compared to 2010 primarily due to new retail rates effective December 1, 2010, and May 4, 2011, for KCP&L in Kansas and Missouri, respectively, and June 25, 2011, for GMO.  This increase was partially offset by:

·   unfavorable weather, with a 6% decrease in cooling degree days;

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·   a decrease in weather-normalized retail demand;

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

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

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

Electric utility’s gross margin increased $234.7 million in 2010 compared to 2009 primarily due to new retail rates effective August 1, 2009 and September 1, 2009, for Kansas and Missouri, respectively, and favorable weather.

Retail MWhs sold in 2010 increased due to favorable weather, with a 2% increase in heating degree days and a 56% increase in cooling degree days.  Cooling degree days were 23% above normal based on a 30-year average.  Wholesale MWhs sold increased due to a 9% increase in generation resulting in more MWhs available for sale, partially offset by the higher retail load requirements.  The increase in generation was primarily a result of Iatan No. 2 being placed in service during 2010 and Iatan No. 1 being off-line from January through mid-April 2009 to complete an environmental upgrade and unit overhaul, with the expenditures being capitalized and therefore not impacting operating and maintenance expenses.  The coal base load equivalent availability factor increased to 82% in 2010 compared to 79% for 2009.

The following table provides cooling degree days (CDD) and heating degree days (HDD) for the last three years at the Kansas City International Airport.  CDD and HDD are used to reflect the demand for energy to cool or heat homes and buildings.

			%					%
	2011		Change			2010		Change		2009
CDD		1,598		(6	)		1,705		56		1,090
HDD		5,220		1			5,160		2		5,069

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

Electric utility’s other operating expenses increased $55.3 million in 2011 compared to 2010 primarily due to the following:

·   a $23.4 million increase in plant operating and maintenance expenses primarily due to Iatan No. 2 expenses being recognized with Kansas and Missouri rates effective December 1, 2010, and May 4, 2011, respectively, for KCP&L and Missouri rates effective June 25, 2011, for GMO;

·   a $13.1 million increase in general taxes driven by increased property taxes;

·   a $13.1 million increase in pension expense corresponding to the resetting of pension trackers with the effective dates of new retail rates at KCP&L and GMO;

·   a $6.8 million increase in amortization of regulatory assets pursuant to rate orders;

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·   $3.3 million of expenses related to the impact of flooding; and

·   as a result of disallowances in the 2011 MPSC rate orders, KCP&L and GMO recognized combined losses of $2.3 million for construction costs related to Iatan No. 2 and to the Iatan No. 1 environmental project in 2011.  KCP&L and GMO also recognized a $3.9 million loss for other disallowed costs in the MPSC rate orders.  In 2010, KCP&L and GMO recognized combined losses of $16.8 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project.

Electric utility’s other operating expenses increased $61.4 million in 2010 compared to 2009 primarily due to the following:

·   a $17.8 million increase in plant operating and maintenance expenses primarily driven by planned plant outages, including the impact of outages in 2009 that included capitalizable improvements and therefore did not impact operating and maintenance expenses;

·   a $14.8 million increase in general taxes driven by increased gross receipts taxes on increased retail revenues and increased property taxes; and

·   a $5.4 million increase from the accounting effects of the 2010 KCC rate order.

These increases were partially offset by $7.5 million expensed in September 2009 after KCP&L exercised its option to terminate an agreement for the construction of a wind project.

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

Electric Utility Voluntary Separation Program

In March 2011, Great Plains Energy announced an organizational realignment and voluntary separation program to assist in the management of overall costs within the level reflected in the Company’s retail electric rates and to enhance organizational efficiency.  Savings from the realignment process and voluntary separation program, including approximately $15 million in labor costs on an annual basis, are expected to partially offset projected cost increases.  Under the voluntary separation program, any non-union employee of the Company could voluntarily elect to separate from the Company and receive a severance payment equal to two weeks of salary for every year of employment, with a minimum severance payment equal to fourteen weeks of salary.  There were 140 employees that made such elections and the majority separated from the Company on April 30, 2011.  Electric utility recorded expense of $12.7 million 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 $58.5 million in 2011 compared to 2010 primarily due to a $32.7 million decrease attributable to lower depreciation rates for KCP&L and a $58.2 million decrease in regulatory amortization for KCP&L in Kansas and Missouri.  These decreases were partially offset by $13.0 million of depreciation for Iatan No. 2, as well as increased depreciation expense for other capital additions.

Electric utility’s depreciation and amortization costs increased $29.4 million in 2010 compared to 2009 primarily due to $14.4 million of additional regulatory amortization pursuant to KCP&L’s 2009 rate cases.  The remaining

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increase was due to placing in service the Iatan No. 1 environmental equipment during 2009 and commencement of depreciation on Iatan No. 2 during 2010 (Kansas jurisdiction only), as well as increased depreciation expense for other capital additions.

Electric Utility Non-Operating Income and Expenses

Electric utility’s non-operating income and expenses decreased $23.1 million in 2011 compared to 2010 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010.

Electric utility’s non-operating income and expenses decreased $14.6 million in 2010 compared to 2009 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to KCP&L’s Comprehensive Energy Plan projects being placed in service.

Electric Utility Interest Charges

Electric utility’s interest charges increased $33.8 million in 2011 compared to 2010 primarily due to a $22.7 million decrease in the debt component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010, $21.9 million of interest on intercompany notes from Great Plains Energy to GMO issued in August 2010 and May 2011 and $5.9 million of interest on 5.30% Senior Notes issued in September 2011.  These items were partially offset by repayment of 7.95% Senior Notes, 7.75% Senior Notes and 6.50% Senior Notes in February 2011, June 2011 and November 2011, respectively.

Electric utility’s interest charges decreased $7.9 million in 2010 compared to 2009 primarily due to the deferral to a regulatory asset of construction accounting carrying costs for Iatan No. 1, Iatan No. 2 and common facilities and the maturity of $68.5 million of 7.625% Senior Notes in December 2009.  These decreases were partially offset by a decrease in the debt component of AFUDC resulting from a lower average construction work in progress balance due to KCP&L’s Comprehensive Energy Plan projects being placed in service, interest for a full year on $400.0 million of 7.15% Mortgage Bonds Series 2009A issued in March 2009 and interest on an intercompany note from Great Plains Energy to GMO issued in August 2010.

Electric Utility Income Tax Expense

Electric utility’s income tax expense decreased $14.0 million in 2011 primarily due to decreased pre-tax income.

Electric utility’s income tax expense increased $59.7 million in 2010 compared to 2009 due to increased pre-tax income and a $2.8 million increase in income tax expense for the cumulative change in tax treatment of the Medicare Part D subsidy under the Federal health care reform legislation signed into law in 2010.

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GREAT PLAINS ENERGY SIGNIFICANT BALANCE SHEET CHANGES

(December 31, 2011 compared to December 31, 2010)

·   Great Plains Energy’s deferred refueling outage costs increased $17.9 million due to the deferral of costs for the Wolf Creek refueling outage that began on March 19, 2011, and included several increases in work scope that extended the outage.  These deferred costs will be amortized over the months prior to the next refueling outage currently scheduled for the fall of 2012.

·   Great Plains Energy’s deferred income taxes – current assets decreased $6.8 million primarily due to increased temporary differences resulting from increased deferred refueling outage costs.

·   Great Plains Energy’s current maturities of long-term debt increased $315.7 million due to reclassification of $287.5 million of Great Plains Energy’s 10.00% Equity Units subordinated notes and $500.0 million of GMO’s 11.875% Senior Notes from long-term debt, partially offset by the repayment of $137.3 million and $197.0 million of GMO’s 7.95% and 7.75% Senior Notes, respectively, and repayment of KCP&L’s $150.0 million of 6.50% Senior Notes at maturity.

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

·   Great Plains Energy’s deferred income taxes – deferred credits and other liabilities increased $110.3 million primarily due to a $233.3 million increase in temporary differences mostly as a result of bonus depreciation partially offset by net operating losses created.

·   Great Plains Energy’s other deferred credits and other liabilities decreased $28.3 million primarily due to a decrease in unrecognized tax benefits related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years.

·   Great Plains Energy’s long-term debt decreased $200.4 million primarily due to reclassification of $287.5 million of Great Plains Energy’s 10.00% Equity Units Subordinated Notes and $500.0 million of GMO’s 11.875% Senior Notes to current maturities and the purchase in lieu of redemption of $112.8 million of KCP&L’s EIRR bonds, offset by Great Plains Energy’s issuance of $350.0 million of 4.85% Senior Notes in May 2011 and KCP&L’s issuance of $400.0 million of 5.30% Senior Notes in September 2011.

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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 is dependent on its receipt of dividends or other distributions from its subsidiaries, proceeds from the issuance of its securities and borrowing under its revolving credit facility.

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

Great Plains Energy's liquid resources at December 31, 2011, consisted of $6.2 million of cash and cash equivalents on hand and $929.7 million of unused bank lines of credit.  The unused lines consisted of $166.4 million from Great Plains Energy's revolving credit facility, $366.5 million from KCP&L's credit facilities and $396.8 million from GMO’s revolving credit facility.  See Note 10 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.

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

Cash Flows from Operating Activities

Great Plains Energy generated positive cash flows from operating activities for the periods presented.  The decrease in cash flows from operating activities for Great Plains Energy in 2011 compared to 2010 is primarily due to a reduction in net income, the payment of $26.1 million for the settlement of FSS upon the issuance of $350.0 million of 4.85% Senior Notes in May 2011, an increase in pension and postretirement benefit funding and an increase in deferred refueling outage costs, partially offset by the adoption of new accounting rules in 2010.  On January 1, 2010, Great Plains Energy adopted new accounting rules for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivable pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s balance sheet at December 31, 2010.  See Note 3 for additional information.  As a result, cash flows from operating activities were reduced by $95.0 million and cash flows from financing activities were raised by $95.0 million with no impact to the net change in cash in 2010.

The increase in cash flows from operating activities for Great Plains Energy in 2010 compared to 2009 is primarily due to an increase in net income, an increase in deferred income taxes from utilizing bonus depreciation, which defers the cash payment for taxes on current year income, and a decrease in cash flows for accounts payable due to the completion of significant construction projects.  Cash flows from operating activities were reduced by $95.0 million and cash flow from financing activities were raised by $95.0 million with no impact to

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the net change in cash in 2010 from the adoption of new accounting rules for transfers of financial assets as discussed above.  Additionally, cash flows from operating activities in 2009 reflect the payment of $79.1 million for the settlement of FSS upon the issuance of $400.0 million of 7.15% Mortgage Bonds Series 2009A.

Other changes in working capital are detailed in Note 2 to the consolidated financial statements.  The individual components of working capital vary with normal business cycles and operations.

Cash Flows from Investing Activities

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

Great Plains Energy’s utility capital expenditures decreased $161.4 million in 2011 compared to 2010 due to a decrease in cash utility capital expenditures primarily related to Iatan No. 2.

Great Plains Energy’s utility capital expenditures decreased $223.1 million in 2010 compared to 2009 due to a decrease in cash utility capital expenditures primarily related to the Iatan No. 1 environmental project, Iatan No. 2 and Spearville 2 Wind Energy Facility.

Cash Flows from Financing Activities

Great Plains Energy’s cash flows from financing activities in 2011 reflect the issuance, at a discount, of $350.0 million of 4.85% Senior Notes that mature in 2021.  Great Plains Energy used the proceeds to make a ten-year intercompany loan to GMO with GMO using the proceeds to repay $137.3 million of 7.95% Senior Notes and $197.0 million of 7.75% Senior Notes at maturity.  KCP&L purchased in lieu of redemption its $63.3 million EIRR Series 2007A-1, $10.0 million EIRR Series 2007A-2 and $39.5 million EIRR Series 1993B bonds.  Also reflected is KCP&L’s issuance, at a discount, of $400.0 million of 5.30% Senior Notes that mature in 2041.  KCP&L used the proceeds to repay short-term borrowings and its $150.0 million of 6.50% Senior Notes at maturity.

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

Great Plains Energy’s cash flows from financing activities in 2009 reflect gross proceeds of $161.0 million from the issuance of 11.5 million shares of common stock at $14.00 per share and gross proceeds of $287.5 million from the issuance of 5.8 million Equity Units.  See Note 11 to the consolidated financial statements for more information on the Equity Units.  Also reflected in the cash flows from financing activities in 2009 is KCP&L’s issuance, at a discount, of $400.0 million of Mortgage Bonds Series 2009A that mature in 2019.  Additionally, Great Plains Energy sold 3.8 million shares of common stock for $50.0 million in gross proceeds under a Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC (BNYMCM).  Great Plains Energy paid $22.8 million in 2009 for fees related to all issuances of debt and common stock.  The proceeds from these issuances were used primarily to repay short-term borrowings.

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Impact of Credit Ratings on Liquidity

The ratings of Great Plains Energy’s, KCP&L’s and GMO’s securities by the credit rating agencies impact their liquidity, including the cost of borrowings under their revolving credit agreements and in the capital markets.  The Companies view maintenance of strong credit ratings as extremely important to their access to and cost of debt financing and to that end maintain an active and ongoing dialogue with the agencies with respect to results of operations, financial position, and future prospects.  While a decrease in these credit ratings would not cause any acceleration of Great Plains Energy’s, KCP&L’s or GMO’s debt, it could increase interest charges under Great Plains Energy’s 6.875% Senior Notes due 2017, GMO’s 11.875% Senior Notes due 2012, and Great Plains Energy’s, KCP&L’s and GMO’s revolving credit agreements.  A decrease in credit ratings could also have, among other things, an adverse impact, which could be material, on Great Plains Energy’s, KCP&L’s and GMO’s access to capital, the cost of funds, the ability to recover actual interest costs in state regulatory proceedings, the type and amounts of collateral required under supply agreements and Great Plains Energy’s ability to provide credit support for its subsidiaries.

At December 31, 2011, the major credit rating agencies rated Great Plains Energy’s and KCP&L’s securities as detailed in the following table.

	Moody's	Standard
	Investors Service	& Poor's
Great Plains Energy
Outlook	Stable	Stable
Corporate Credit Rating	-	BBB
Preferred Stock	Ba2	BB+
Senior Unsecured Debt	Baa3	BBB-
KCP&L
Outlook	Stable	Stable
Senior Secured Debt	A3	BBB+
Senior Unsecured Debt	Baa2	BBB
Commercial Paper	P-2	A-2
GMO
Outlook	Stable	Stable
Senior Unsecured Debt (a)	Baa3	BBB
Commercial Paper (a)	P-3	A-2
(a) reflects Great Plains Energy guarantee

A securities rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.

Financing Authorization

Under stipulations with the MPSC and KCC, Great Plains Energy and KCP&L maintain common equity at not less than 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress).  KCP&L’s long-term financing activities are subject to the authorization of the MPSC.  In March 2010, the MPSC authorized KCP&L to issue up to $450.0 million of long-term debt and to enter into interest rate hedging instruments in connection with such debt through December 31, 2011.  KCP&L utilized $400.0 million of this amount with the issuance in September 2011 of 5.30% unsecured Senior Notes maturing in 2041.  In December 2011, KCP&L filed a request with the MPSC for authorization to issue up to $300.0 million of long-term debt and enter into interest rate hedging instruments in connection with such debt through December 31, 2013.  This authorization would replace the authorization which expired on December 31, 2011.

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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 December 31, 2011, there was $773.0 million available under this authorization.

In March 2010, and modified in April 2010, FERC authorized GMO to have outstanding at any time up to a total of $500.0 million in short-term debt instruments through March 2012, conditioned on GMO’s borrowing costs not exceeding 4.3% over LIBOR, the prime rate or federal funds rate, as applicable, and subject to the same four restrictions as the KCP&L FERC short-term authorization discussed in the preceding paragraph.  At December 31, 2011, there was $460.0 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.  This authorization will become effective and replace the current authorization when it expires in March 2012.

In November 2011, FERC authorized GMO to issue up to a total of $850.0 million of long-term debt through December 2013.  At December 31, 2011, there was $850.0 million available under this authorization.

KCP&L and GMO are also authorized by FERC to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO.  At December 31, 2011, KCP&L had an outstanding payable under the money pool of $8.5 million to Great Plains Energy.

Significant Financing Activities

Great Plains Energy

Great Plains Energy has an effective shelf registration statement for the sale of unspecified amounts of securities with the SEC that was filed and became effective in May 2009 and expects to file a new shelf registration statement prior to the May 2012 expiration of its current one.

In May 2011, Great Plains Energy issued $350.0 million of 4.85% unsecured Senior Notes, maturing in 2021.  Great Plains Energy settled six FSS simultaneously with the issuance of the debt and paid $26.1 million in cash for the settlement.

In August 2010, Great Plains Energy issued $250.0 million of 2.75% Senior Notes, maturing in 2013.  Great Plains Energy settled two FSS simultaneously with the issuance of the three-year long-term debt and paid $6.9 million in cash for the settlement.

In May 2009, Great Plains Energy issued 11.5 million shares of common stock at $14.00 per share with $161.0 million in gross proceeds and 5.8 million Equity Units with gross proceeds of $287.5 million.  See Note 11 to the consolidated financial statements for additional information on the Equity Units.

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KCP&L

KCP&L has an effective shelf registration statement providing for the sale of unspecified amounts of investment grade notes and general mortgage bonds with the SEC that was filed and became effective in May 2009 and expects to file a new shelf registration statement prior to the May 2012 expiration of its current one.

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

In March 2009, KCP&L issued $400.0 million of 7.15% Mortgage Bonds Series 2009A, maturing in 2019.  KCP&L settled FSS simultaneously with the issuance of its $400.0 million 10-year long-term debt and paid $79.1 million in cash for the settlement.

Debt Agreements

See Note 10 to the consolidated financial statements for information regarding revolving credit facilities.

Projected Utility Capital Expenditures

Great Plains Energy’s cash utility capital expenditures, excluding AFUDC to finance construction, were $456.6 million, $618.0 million and $841.1 million in 2011, 2010 and 2009, respectively.  Utility capital expenditures projected for the next three years, excluding AFUDC, are detailed in the following table.  This utility capital expenditure plan is subject to continual review and change.

	2012		2013		2014
	(millions)
Generating facilities	$	202.4	$	245.6	$	229.6
Distribution and transmission facilities (a)		186.4		212.0		185.8
SPP balanced portfolio and priority transmission projects		4.2		42.2		70.9
General facilities		42.1		53.8		34.6
Nuclear fuel		20.8		40.1		25.3
Environmental		178.1		189.3		127.3
Total utility capital expenditures	$	634.0	$	783.0	$	673.5
(a) Excludes SPP balanced portfolio and priority transmission projects

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).

In 2011 and 2010, the Company contributed $128.8 million and $64.5 million to the pension plans, respectively, and in 2012 the Company expects to contribute $94.5 million to the plans to satisfy the ERISA funding requirements and the MPSC and KCC rate orders, with the majority paid by KCP&L.  Additional contributions to the plans are expected beyond 2012 in amounts at least sufficient to meet the greater of ERISA or regulatory funding requirements; however, these amounts have not yet been determined.

Additionally, the Company provides post-retirement health and life insurance benefits for certain retired employees and expects to make benefit contributions of $16.7 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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Supplemental Capital Requirements and Liquidity Information

The information in the following table is provided to summarize Great Plains Energy’s cash obligations and commercial commitments.

Payment due by period		2012		2013		2014		2015		2016		After 2016		Total
Long-term debt		(millions)
	Principal	$	801.4	$	263.1	$	1.5	$	15.5	$	1.6	$	2,449.2	$	3,532.3
	Interest		242.1		182.3		160.4		145.6		145.2		1,215.5		2,091.1
Lease commitments
	Operating lease		19.7		16.3		14.8		13.6		9.8		119.2		193.4
	Capital lease		0.4		0.4		0.4		0.4		0.4		4.7		6.7
Pension and other post-retirement plans (a)			111.2		111.2		111.2		111.2		111.2		N/A		556.0
Purchase commitments
	Fuel		397.4		360.5		202.0		103.9		83.2		94.1		1,241.1
	Power		8.5		29.2		34.8		34.8		34.8		686.3		828.4
	Capacity		13.4		12.4		4.5		4.2		2.4		-		36.9
	La Cygne environmental project		376.6		300.2		125.4		5.5		-		-		807.7
	Non-regulated natural gas
	transportation		2.8		3.6		3.6		3.6		3.6		0.9		18.1
	Other		54.4		101.7		21.0		25.4		3.7		49.8		256.0
Total contractual commitments (a)		$	2,027.9	$	1,380.9	$	679.6	$	463.7	$	395.9	$	4,619.7	$	9,567.7
(a)	The Company expects to make contributions to the pension and other post-retirement plans beyond 2012 but the amounts
	are not yet determined. Amounts for years after 2012 are estimates based on information available in determining the amount
	for 2012. Actual amounts for years after 2012 could be significantly different than the estimated amounts in the table above.

Long-term debt includes current maturities.  Long-term debt principal excludes $4.9 million of discounts on senior notes.  Variable rate interest obligations are based on rates as of December 31, 2011.  Equity Units subordinated notes totaling $287.5 million mature in 2042 but must be remarketed by June 12, 2012.  In connection with a successful remarketing of the notes, Great Plains Energy may elect, without the consent of any of the holders, to modify the notes’ stated maturity to any date on or after June 15, 2014 and earlier than June 15, 2042.  If the notes have not been successfully remarketed by June 12, 2012, the holders of all notes will have the right to put their notes to Great Plains Energy on June 15, 2012, in payment of the associated common stock purchase contracts and Great Plains Energy will issue to the holders newly issued shares of the Company’s common stock.  Interest on the Equity Units subordinated notes is included up to June 15, 2014.  See Note 11 to the consolidated financial statements for additional information.

Great Plains Energy has expected sublease income of $1.2 million for the years 2012-2013.  Lease commitments end in 2048 and include capital and operating lease obligations.  Lease obligations also include railcars to serve jointly-owned generating units where KCP&L is the managing partner.  Of the amounts included in the table above, KCP&L will be reimbursed by the other owners for approximately $2.2 million per year from 2012 to 2015 and then $0.4 million per year from 2016 to 2025, for a total of $13.0 million.

The Company expects to contribute $111.2 million to the pension and other post-retirement plans in 2012, of which the majority is expected to be paid by KCP&L.  Additional contributions to the plans are expected beyond 2012 in amounts at least sufficient to meet the greater of ERISA or regulatory funding requirements; however, these amounts have not yet been determined.  Amounts for years after 2012 are estimates based on information available in determining the amount for 2012.  Actual amounts for years after 2012 could be significantly different than the estimated amounts in the table above.

Fuel commitments consist of commitments for nuclear fuel, coal and coal transportation costs.  Power commitments consist of commitments for renewable energy under power purchase agreements.  KCP&L and GMO purchase capacity from other utilities and nonutility suppliers.  Purchasing capacity provides the option to

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purchase energy if needed or when market prices are favorable.  KCP&L has capacity sales agreements not included above that total $3.8 million for 2012 and $1.6 million for 2013.  La Cygne environmental project represents contractual commitments related to environmental upgrades at KCP&L’s La Cygne station.  KCP&L owns 50% of the La Cygne station and expects to be reimbursed by the other owner for its 50% share of the costs.  Non-regulated natural gas transportation consists of MPS Merchant’s commitments.  Other represents individual commitments entered into in the ordinary course of business.

At December 31, 2011, the total liability for unrecognized tax benefits for Great Plains Energy was $24.0 million, which is not included in the table above.  Great Plains Energy is unable to determine reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.  See Note 20 to the consolidated financial statements for information regarding the recognition of tax benefits in the next twelve months, which is not expected to have a cash impact.

Great Plains Energy has other insignificant long-term liabilities recorded on its consolidated balance sheet at December 31, 2011, which do not have a definitive cash payout date and are not included in the table above.

Off-Balance Sheet Arrangements

In the ordinary course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries.  Such agreements include, for example, guarantees and letters of credit.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended business purposes.  The majority of these agreements guarantee the Company’s own future performance, so a liability for the fair value of the obligation is not recorded.

At December 31, 2011, Great Plains Energy has provided $666.0 million of credit support for GMO as follows:

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

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

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

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

None of the guaranteed obligations are subject to default or prepayment as a result of a downgrade of GMO’s credit ratings, although such a downgrade has in the past, and could in the future, increase interest charges under GMO’s 11.875% Senior Notes due 2012 and revolving line of credit.

At December 31, 2011, KCP&L had issued letters of credit totaling $21.5 million as credit support to certain counterparties.

KCP&L has bond insurance policies for its secured 1992 Series EIRR bonds totaling $31.0 million, Series 1993A bonds totaling $40.0 million, EIRR Bond Series 2005 totaling $85.9 million and EIRR Bonds Series 2007B totaling $73.2 million.  The insurance agreement between KCP&L and the issuer of the bond insurance policies provides for reimbursement by KCP&L for any amounts the insurer pays under the bond insurance policies.  As the insurers’ credit ratings are below KCP&L’s credit ratings, the bonds are rated at KCP&L’s credit ratings.

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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.

	2011			2010			2009
	(millions)
Operating revenues	$	1,558.3		$	1,517.1		$	1,318.2
Fuel		(333.5	)		(278.8	)		(251.3	)
Purchased power		(70.8	)		(78.9	)		(70.8	)
Transmission of electricity by others		(18.8	)		(15.0	)		(12.3	)
Gross margin (a)		1,135.2			1,144.4			983.8
Other operating expenses		(611.7	)		(576.6	)		(522.0	)
Voluntary separation program		(9.2	)		-			-
Depreciation and amortization		(193.1	)		(256.4	)		(229.6	)
Operating income		321.2			311.4			232.2
Non-operating income and expenses		(1.0	)		19.1			28.5
Interest charges		(115.6	)		(85.7	)		(84.9	)
Income tax expense		(69.1	)		(81.6	)		(46.9	)
Net income	$	135.5		$	163.2		$	128.9
(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.

				%						%
Gross Margin (a)	2011			Change			2010			Change		2009
Retail revenues	(millions)
Residential	$	593.0			5		$	564.5			20	$	472.2
Commercial		637.8			6			604.3			11		542.7
Industrial		121.9			(1	)		122.8			13		108.8
Other retail revenues		12.5			5			11.7			9		10.9
Kansas property tax surcharge		3.7		NA				-		NA			-
Provision for rate refund		-		NM				(3.7	)	NA			-
Kansas ECA (over) under recovery		11.7			35			8.7		NM			(0.7	)
Total retail		1,380.6			6			1,308.3			15		1,133.9
Wholesale revenues		159.4			(16	)		188.9			14		166.2
Other revenues		18.3			(8	)		19.9			10		18.1
Operating revenues		1,558.3			3			1,517.1			15		1,318.2
Fuel		(333.5	)		20			(278.8	)		11		(251.3	)
Purchased power		(70.8	)		(10	)		(78.9	)		11		(70.8	)
Transmission of electricity by others		(18.8	)		25			(15.0	)		22		(12.3	)
Gross margin	$	1,135.2			(1	)	$	1,144.4			16	$	983.8
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great
Plains Energy's Results of Operations.

48

			%					%
MWh Sales	2011		Change			2010		Change		2009
Retail MWh sales	(thousands)
Residential		5,624		(2	)		5,719		10		5,203
Commercial		7,614		(1	)		7,705		3		7,506
Industrial		1,884		(4	)		1,956		4		1,884
Other retail MWh sales		88		1			87		-		88
Total retail		15,210		(2	)		15,467		5		14,681
Wholesale MWh sales		5,165		(15	)		6,051		12		5,381
Total MWh sales		20,375		(5	)		21,518		7		20,062

KCP&L’s gross margin decreased $9.2 million in 2011 compared to 2010 primarily due to:

·   unfavorable weather, with a 6% decrease in cooling degree days;

·   a decrease in weather-normalized retail demand;

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

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

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

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

KCP&L’s gross margin increased $160.6 million in 2010 compared to 2009 primarily due to the increase in retail revenues driven by new retail rates effective August 1, 2009, and September 1, 2009, for Kansas and Missouri, respectively, and favorable weather.

KCP&L’s retail MWhs sold in 2010 increased due to favorable weather, with a 2% increase in heating degree days and a 56% increase in cooling degree days.  Cooling degree days were 23% above normal based on a 30-year average.  Wholesale MWhs sold increased due to a 9% increase in generation resulting in more MWhs available for sale, partially offset by the higher retail load requirements.  The increase in generation was a result of Iatan No. 2 being placed in service during 2010 and Iatan No. 1 being off-line from January through mid-April 2009 to complete an environmental upgrade and unit overhaul, with the expenditures being capitalized and therefore not impacting operating and maintenance expenses.  As a result, KCP&L’s coal base load equivalent availability factor increased to 81% in 2010 compared to 79% in 2009.

49

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

KCP&L’s other operating expenses increased $35.1 million in 2011 compared to 2010 primarily due to:

·   a $14.6 million increase in plant operating and maintenance expenses primarily due to Iatan No. 2 expenses being recognized with Kansas and Missouri rates effective December 1, 2010, and May 4, 2011, respectively;

·   a $10.4 million increase in general taxes driven by increased property taxes;

·   a $6.4 million increase in amortization of regulatory assets pursuant to rate orders;

·   $3.0 million of expenses related to the impact of flooding; and

·   as a result of disallowances in the 2011 MPSC rate order, KCP&L recognized losses of $1.5 million for construction costs related to Iatan No. 2 and to the Iatan No. 1 environmental project in 2011.  KCP&L also recognized a $2.4 million loss for other disallowed costs in the MPSC rate order. In 2010, KCP&L recognized losses of $13.0 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project.

KCP&L’s other operating expenses increased $54.6 million in 2010 compared to 2009 primarily due to:

·   a $13.6 million increase in plant operating and maintenance expenses primarily driven by planned plant outages, including the impact of outages in 2009 that included capitalizable improvements and therefore did not impact operating and maintenance expenses;

·   a $10.6 million increase in general taxes driven by increased gross receipts taxes on increased retail revenues and increased property taxes; and

·   a $5.4 million increase resulting from the accounting effects of the 2010 KCC rate order.

These increases were partially offset by $7.5 million expensed in September 2009 after KCP&L exercised its option to terminate an agreement for the construction of a wind project.

Accounting rules state that when it becomes probable that part of the cost of a recently completed plant will be disallowed for rate-making purposes and a reasonable estimate of the amount of the disallowance can be made, the estimated amount of the probable disallowance shall be deducted from the reported cost of the plant and recognized as a loss.  As a result of disallowances in the 2010 KCC rate order, KCP&L recognized Kansas jurisdictional losses of $4.4 million for construction costs related to Iatan No. 2 and $2.0 million for construction costs related to the Iatan No. 1 environmental project.  Management determined it was probable that the MPSC would disallow these costs as well in KCP&L’s pending rate case.  Therefore, KCP&L’s Missouri jurisdictional portion of these costs was recognized as a loss in addition to the KCP&L Kansas jurisdictional portion resulting in a $13.0 million loss for KCP&L’s construction costs incurred through December 31, 2010.

KCP&L Voluntary Separation Program

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

KCP&L Depreciation and Amortization

KCP&L’s depreciation and amortization costs decreased $63.3 million in 2011 compared to 2010 due to a $32.7 million decrease attributable to lower depreciation rates for KCP&L and a $58.2 million decrease in regulatory amortization for KCP&L in Kansas and Missouri.  These decreases were partially offset by $9.4 million of depreciation for Iatan No. 2, as well as increased depreciation expense for other capital additions.

KCP&L’s depreciation and amortization costs increased $26.8 million in 2010 compared to 2009 primarily due to $14.4 million of additional regulatory amortization pursuant to KCP&L’s 2009 rate cases.  The remaining

50

increase was due to placing in service the Iatan No. 1 environmental equipment during 2009 and commencement of depreciation on Iatan No. 2 during 2010 (Kansas jurisdiction only), as well as increased depreciation expense for other capital additions.

KCP&L Non-operating Income and Expenses

KCP&L’s non-operating income and expenses decreased $20.1 million in 2011 compared to 2010 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010.

KCP&L’s non-operating income and expenses decreased $9.4 million in 2010 compared to 2009 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to KCP&L’s Comprehensive Energy Plan projects being placed in service.

KCP&L Interest Charges

KCP&L’s interest charges increased $29.9 million in 2011 compared to 2010 primarily due to a $19.5 million decrease in the debt component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010, a $7.1 million increase to interest expense relating to deferral to a regulatory asset of construction accounting carrying costs for Iatan Nos. 1 and 2 and common facilities and $5.9 million of interest on 5.30% Senior Notes issued in September 2011.

KCP&L’s interest charges increased $0.8 million in 2010 compared to 2009 primarily due to interest for a full year on $400.0 million of 7.15% Mortgage Bonds Series 2009A issued in March 2009 and a decrease in the debt component of AFUDC resulting from a lower average construction work in progress balance due to KCP&L’s Comprehensive Energy Plan projects being placed in service, mostly offset by the deferral to a regulatory asset of construction accounting carrying costs for Iatan No. 1, Iatan No. 2 and common facilities.

KCP&L Income Tax Expense

KCP&L’s income tax expense decreased $12.5 million in 2011 compared to 2010 primarily due to decreased pre-tax income.

KCP&L’s income tax expense increased $34.7 million in 2010 compared to 2009 primarily due to increased pre-tax income and a $2.8 million increase in income tax expense for the cumulative change in tax treatment of the Medicare Part D subsidy under the Federal health care reform legislation signed into law in the first quarter of 2010.

51

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In the ordinary course of business, Great Plains Energy and KCP&L face risks that are either non-financial or non-quantifiable.  Such risks principally include business, legal, operations and credit risks and are not represented in the following analysis.  See Item 1A Risk Factors and Item 7 MD&A for further discussion of risk factors.

Great Plains Energy and KCP&L are exposed to market risks associated with commodity price and supply, interest rates and equity prices.  Management has established risk management policies and strategies to reduce the potentially adverse effects the volatility of the markets may have on its operating results.  During the ordinary course of business, under the direction and control of an internal risk management committee, Great Plains Energy’s and KCP&L’s hedging strategies are reviewed to determine the hedging approach deemed appropriate based upon the circumstances of each situation.  Though management believes its risk management practices are effective, it is not possible to identify and eliminate all risk.  Great Plains Energy and KCP&L could experience losses, which could have a material adverse effect on its results of operations or financial position, due to many factors, including unexpectedly large or rapid movements or disruptions in the energy markets, from regulatory-driven market rule changes and/or bankruptcy or non-performance of customers or counterparties, and/or failure of underlying transactions that have been hedged to materialize.

Hedging Strategies

Derivative instruments are frequently utilized to execute risk management and hedging strategies.  Derivative instruments, such as futures, forward contracts, swaps or options, derive their value from underlying assets, indices, reference rates or a combination of these factors.  These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives, and instruments listed and traded on an exchange.

Interest Rate Risk

Great Plains Energy and KCP&L manage interest expense and short and long-term liquidity through a combination of fixed and variable rate debt.  Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly rated financial institutions may also be used to achieve the desired combination.  At December 31, 2011, less than 1% of Great Plains Energy’s long-term debt was variable rate debt.  KCP&L had no variable rate long-term debt at December 31, 2011.  Interest rates impact the fair value of long-term debt.  A change in interest rates would impact Great Plains Energy and KCP&L to the extent they redeemed any of their outstanding long-term debt.  Great Plains Energy’s and KCP&L’s book values of long-term debt were below fair value by 11% and 15%, respectively, at December 31, 2011.

Great Plains Energy had $22.0 million of notes payable outstanding at December 31, 2011.  The principal amount of the notes payable, which will vary during the year, drives Great Plains Energy’s notes payable interest expense.  Assuming that $22.0 million of notes payable was outstanding for all of 2012, a hypothetical 10% increase in interest rates associated with short-term variable rate debt would result in an immaterial increase in interest expense for 2012.

Great Plains Energy and KCP&L had $267.0 million and $227.0 million, respectively, of commercial paper outstanding at December 31, 2011.  The principal amount of the commercial paper, which will vary during the year, drives Great Plains Energy’s and KCP&L’s commercial paper interest expense.  Assuming that $267.0 million and $227.0 million of commercial paper was outstanding for all of 2012 for Great Plains Energy and KCP&L, respectively, a hypothetical 10% increase in commercial paper rates would result in an immaterial increase in interest expense for 2012.   Assuming that $267.0 million and $227.0 million of commercial paper was outstanding for all of 2012 for Great Plains Energy and KCP&L, respectively, a hypothetical 100 basis point increase in commercial paper rates would result in an increase in interest expense of $2.7 million for Great Plains Energy and $2.3 million for KCP&L in 2012.

52

Commodity Risk

Great Plains Energy and KCP&L engage in the wholesale and retail marketing of electricity and are exposed to risk associated with the price of electricity.  Exposure to these risks is affected by a number of factors including the quantity and availability of fuel used for generation and the quantity of electricity customers consume.  Customers’ electricity usage could also vary from year to year based on the weather or other factors.  Quantities of fossil fuel used for generation vary from year to year based on the availability, price and deliverability of a given fuel type as well as planned and unplanned outages at facilities that use fossil fuels.

KCP&L's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity.  KCP&L also enters into additional power purchase transactions with the objective of obtaining the most economical energy to meet its physical delivery obligations to customers.  KCP&L is required to maintain a capacity margin of at least 12% of its peak summer demand.  This net positive supply of capacity and energy is maintained through KCP&L’s generation assets and capacity and power purchase agreements to protect KCP&L from the potential operational failure of one of its power generating units.  KCP&L continually evaluates the need for additional risk mitigation measures in order to minimize its financial exposure to, among other things, spikes in wholesale power prices during periods of high demand.

KCP&L's sales include the sales of electricity to its retail customers and bulk power sales of electricity in the wholesale market.  KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply, the availability and cost of purchased power and the requirements of other electric systems; therefore, the impact of the hypothetical amounts that follow could be significantly reduced depending on the system requirements and market prices at the time of the increases.  A hypothetical 10% increase in the market price of power could result in a $0.4 million decrease in operating income for 2012 related to purchased power.  In 2012, approximately 77% of KCP&L’s net MWhs generated are expected to be coal-fired.  KCP&L currently has all of its coal requirements for 2012 under contract.  A hypothetical 10% increase in the market price of coal could result in less than a $2.6 million increase in fuel expense for 2012.  KCP&L has also implemented price risk mitigation measures to reduce its exposure to high natural gas prices.  A hypothetical 10% increase in natural gas and oil market prices could result in an increase of $0.1 million in fuel expense for 2012.  At December 31, 2011, KCP&L had hedged approximately 66%, 56% and 13% of its 2012, 2013 and 2014, respectively, projected natural gas usage for generation requirements to serve retail load and firm MWh sales.  KCP&L’s Kansas ECA allows for the recovery of increased fuel and purchased power costs from Kansas retail customers.  KCP&L’s Missouri retail rates do not contain a fuel recovery mechanism, meaning that changes in fuel costs create a regulatory lag.

In the GMO regulated electric operations in 2011, approximately 62% of the power sold was generated and the remaining 38% was purchased through long-term contracts or in the open market.  GMO has an FAC that allows GMO to adjust retail electric rates based on 95% of the difference between actual fuel and purchased power costs and the amount of fuel and purchased power costs provided in base rates.

Several measures have been taken to mitigate commodity price risk exposure in GMO’s electric utility operations. One of these measures is contracting for a diverse supply of coal to meet approximately 97% and 86% of its 2012 and 2013, respectively, native load fuel requirements of coal-fired generation.  The price risk associated with natural gas and on-peak spot market purchased power requirements is also mitigated through a hedging plan using New York Mercantile Exchange (NYMEX) futures contracts and options.  A hypothetical 10% increase in natural gas market prices could result in an increase of $2.5 million in fuel expense for 2012.  At December 31, 2011, GMO had financial contracts in place to hedge approximately 45%, 38% and 38% of expected on-peak natural gas and natural gas equivalent purchased power price exposure for 2012, 2013 and 2014, respectively.  The mark-to-market value of these contracts at December 31, 2011, was a liability of $5.0 million.

53

Credit Risk – MPS Merchant

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 December 31, 2011, was $13.3 million.

Investment Risk

KCP&L maintains trust funds, as required by the NRC, to fund its share of decommissioning the Wolf Creek nuclear power plant.  As of December 31, 2011, these funds were invested primarily in domestic equity securities and fixed income securities and are reflected at fair value on KCP&L’s balance sheets.  The mix of securities is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs; however, the equity securities in the trusts are exposed to price fluctuations in equity markets and the value of fixed rate fixed income securities are exposed to changes in interest rates.  A hypothetical increase in interest rates resulting in a hypothetical 10% decrease in the value of the fixed income securities would have resulted in a $4.9 million reduction in the value of the decommissioning trust funds at December 31, 2011.  A hypothetical 10% decrease in equity prices would have resulted in an $8.4 million reduction in the fair value of the equity securities at December 31, 2011.  KCP&L's exposure to investment risk associated with the decommissioning trust funds is in large part mitigated due to the fact that KCP&L is currently allowed to recover its decommissioning costs in its rates.  If the actual return on trust assets is below the anticipated level, KCP&L could be responsible for the balance of funds required to decommission Wolf Creek; however, while there can be no assurances, management believes a rate increase would be allowed to recover decommissioning costs over the remaining life of the unit.

54

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
			Page
			Number
Great Plains Energy Incorporated
Consolidated Statements of Income			56
Consolidated Balance Sheets			57
Consolidated Statements of Cash Flows			59
Consolidated Statements of Common Shareholders’ Equity and Noncontrolling Interest			60
Consolidated Statements of Comprehensive Income			61
Kansas City Power & Light Company
Consolidated Statements of Income			62
Consolidated Balance Sheets			63
Consolidated Statements of Cash Flows			65
Consolidated Statements of Common Shareholder’s Equity			66
Consolidated Statements of Comprehensive Income			67
Combined Notes to Consolidated Financial Statements for Great Plains Energy Incorporated
and Kansas City Power & Light Company
	Note 1:	Summary of Significant Accounting Policies	68
	Note 2:	Supplemental Cash Flow Information	74
	Note 3:	Receivables	76
	Note 4:	Nuclear Plant	77
	Note 5:	Regulatory Matters	80
	Note 6:	Goodwill and Intangible Assets	84
	Note 7:	Asset Retirement Obligations	85
	Note 8:	Pension Plans, Other Employee Benefits and Voluntary Separation Program	86
	Note 9:	Equity Compensation	95
	Note 10:	Short-Term Borrowings and Short-Term Bank Lines of Credit	98
	Note 11:	Long-Term Debt	99
	Note 12:	Common Shareholders’ Equity	102
	Note 13:	Preferred Stock	103
	Note 14:	Commitments and Contingencies	103
	Note 15:	Legal Proceedings	112
	Note 16:	Guarantees	113
	Note 17:	Related Party Transactions and Relationships	113
	Note 18:	Derivative Instruments	113
	Note 19:	Fair Value Measurements	118
	Note 20:	Taxes	123
	Note 21:	Segments and Related Information	128
	Note 22:	Discontinued Operations	129
	Note 23:	Jointly Owned Electric Utility Plants	129
	Note 24:	Quarterly Operating Results (Unaudited)	130
Report of Independent Registered Public Accounting Firm
	Great Plains Energy Incorporated		132
	Kansas City Power & Light Company		133

55

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Income
Year Ended December 31	2011			2010			2009
Operating Revenues	(millions, except per share amounts)
Electric revenues	$	2,318.0		$	2,255.5		$	1,965.0
Operating Expenses
Fuel		483.8			430.7			405.5
Purchased power		203.4			213.8			183.7
Transmission of electricity by others		30.2			27.4			26.9
Utility operating and maintenance expenses		658.2			602.5			572.4
Voluntary separation program		12.7			-			-
Depreciation and amortization		273.1			331.6			302.2
General taxes		170.9			155.1			139.8
Other		5.9			22.1			14.4
Total		1,838.2			1,783.2			1,644.9
Operating income		479.8			472.3			320.1
Non-operating income		5.9			43.9			49.5
Non-operating expenses		(8.2	)		(19.5	)		(6.9	)
Interest charges		(218.4	)		(184.8	)		(180.9	)
Income from continuing operations before income tax expense and
loss from equity investments		259.1			311.9			181.8
Income tax expense		(84.8	)		(99.0	)		(29.5	)
Loss from equity investments, net of income taxes		(0.1	)		(1.0	)		(0.4	)
Income from continuing operations		174.2			211.9			151.9
Loss from discontinued operations, net of income taxes (Note 22)		-			-			(1.5	)
Net income		174.2			211.9			150.4
Less:  Net (income) loss attributable to noncontrolling interest		0.2			(0.2	)		(0.3	)
Net income attributable to Great Plains Energy		174.4			211.7			150.1
Preferred stock dividend requirements		1.6			1.6			1.6
Earnings available for common shareholders	$	172.8		$	210.1		$	148.5
Average number of basic common shares outstanding		135.6			135.1			129.3
Average number of diluted common shares outstanding		138.7			136.9			129.8
Basic earnings (loss) per common share
Continuing operations	$	1.27		$	1.55		$	1.16
Discontinued operations		-			-			(0.01	)
Basic earnings per common share	$	1.27		$	1.55		$	1.15
Diluted earnings (loss) per common share
Continuing operations	$	1.25		$	1.53		$	1.15
Discontinued operations		-			-			(0.01	)
Diluted earnings per common share	$	1.25		$	1.53		$	1.14
Cash dividends per common share	$	0.835		$	0.83		$	0.83
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

56

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets
	December 31
	2011		2010
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	6.2	$	10.8
Funds on deposit		1.4		5.2
Receivables, net		231.2		241.7
Accounts receivable pledged as collateral		95.0		95.0
Fuel inventories, at average cost		89.0		85.1
Materials and supplies, at average cost		140.3		132.8
Deferred refueling outage costs		27.5		9.6
Refundable income taxes		0.3		2.1
Deferred income taxes		7.5		14.3
Derivative instruments		1.0		1.1
Prepaid expenses and other assets		19.7		13.9
Total		619.1		611.6
Utility Plant, at Original Cost
Electric		10,924.8		10,536.9
Less-accumulated depreciation		4,235.8		4,031.3
Net utility plant in service		6,689.0		6,505.6
Construction work in progress		287.9		307.5
Nuclear fuel, net of amortization of $132.7 and $131.1		76.6		79.2
Total		7,053.5		6,892.3
Investments and Other Assets
Nuclear decommissioning trust fund		135.3		129.2
Regulatory assets		1,058.2		924.0
Goodwill		169.0		169.0
Derivative instruments		6.8		7.8
Other		76.1		84.3
Total		1,445.4		1,314.3
Total	$	9,118.0	$	8,818.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

57

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets
	December 31
	2011			2010
LIABILITIES AND CAPITALIZATION	(millions, except share amounts)
Current Liabilities
Notes payable	$	22.0		$	9.5
Collateralized note payable		95.0			95.0
Commercial paper		267.0			263.5
Current maturities of long-term debt		801.4			485.7
Accounts payable		275.6			276.3
Accrued taxes		25.8			26.6
Accrued interest		76.9			75.4
Accrued compensation and benefits		40.8			46.8
Pension and post-retirement liability		4.4			4.1
Derivative instruments		-			20.8
Other		26.0			35.6
Total		1,634.9			1,339.3
Deferred Credits and Other Liabilities
Deferred income taxes		628.6			518.3
Deferred tax credits		131.2			133.4
Asset retirement obligations		149.6			143.3
Pension and post-retirement liability		461.9			427.5
Regulatory liabilities		268.5			258.2
Other		101.1			129.4
Total		1,740.9			1,610.1
Capitalization
Great Plains Energy common shareholders' equity
Common stock - 250,000,000 shares authorized without par value
136,406,306 and 136,113,954 shares issued, stated value		2,330.6			2,324.4
Retained earnings		684.7			626.5
Treasury stock - 264,567 and 400,889 shares, at cost		(5.6	)		(8.9	)
Accumulated other comprehensive loss		(49.8	)		(56.1	)
Total		2,959.9			2,885.9
Noncontrolling interest		1.0			1.2
Cumulative preferred stock $100 par value
3.80% - 100,000 shares issued		10.0			10.0
4.50% - 100,000 shares issued		10.0			10.0
4.20% - 70,000 shares issued		7.0			7.0
4.35% - 120,000 shares issued		12.0			12.0
Total		39.0			39.0
Long-term debt (Note 11)		2,742.3			2,942.7
Total		5,742.2			5,868.8
Commitments and Contingencies (Note 14)
Total	$	9,118.0		$	8,818.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

58

GREAT PLAINS ENERGY
Consolidated Statements of Cash Flows
Year Ended December 31	2011			2010			2009
Cash Flows from Operating Activities	(millions)
Net income	$	174.2		$	211.9		$	150.4
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		273.1			331.6			302.2
Amortization of:
Nuclear fuel		21.4			25.1			16.1
Other		12.7			(4.7	)		(10.1	)
Deferred income taxes, net		111.2			123.8			(3.6	)
Investment tax credit amortization		(2.2	)		(2.9	)		(2.2	)
Loss from equity investments, net of income taxes		0.1			1.0			0.4
Other operating activities (Note 2)		(147.5	)		(133.7	)		(117.8	)
Net cash from operating activities		443.0			552.1			335.4
Cash Flows from Investing Activities
Utility capital expenditures		(456.6	)		(618.0	)		(841.1	)
Allowance for borrowed funds used during construction		(5.8	)		(28.5	)		(37.7	)
Payment to Black Hills for asset sale working capital adjustment		-			-			(7.7	)
Purchases of nuclear decommissioning trust investments		(18.5	)		(83.3	)		(99.0	)
Proceeds from nuclear decommissioning trust investments		15.1			79.6			95.3
Other investing activities		(19.9	)		(7.5	)		(7.4	)
Net cash from investing activities		(485.7	)		(657.7	)		(897.6	)
Cash Flows from Financing Activities
Issuance of common stock		5.9			6.2			219.9
Issuance of long-term debt		747.1			249.9			700.7
Issuance fees		(10.7	)		(12.1	)		(22.8	)
Repayment of long-term debt		(598.5	)		(1.3	)		(70.7	)
Net change in short-term borrowings		16.0			(165.6	)		(145.6	)
Net change in collateralized short-term borrowings		-			95.0			-
Dividends paid		(115.1	)		(114.2	)		(110.5	)
Other financing activities		(6.6	)		(7.4	)		(4.0	)
Net cash from financing activities		38.1			50.5			567.0
Net Change in Cash and Cash Equivalents		(4.6	)		(55.1	)		4.8
Cash and Cash Equivalents at Beginning of Year		10.8			65.9			61.1
Cash and Cash Equivalents at End of Year	$	6.2		$	10.8		$	65.9
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

59

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest
Year Ended December 31	2011						2010						2009
	Shares			Amount			Shares			Amount			Shares			Amount
Common Stock	(millions, except share amounts)
Beginning balance		136,113,954		$	2,324.4			135,636,538		$	2,313.7			119,375,923		$	2,118.4
Issuance of common stock		292,352			5.9			347,279			6.6			15,883,948			220.1
Common stock issuance fees					-						-						(7.0	)
Issuance of restricted common stock		-			-			130,137			2.3			376,667			5.4
Equity compensation expense, net of forfeitures					0.3						1.0						0.8
Unearned Compensation
Issuance of restricted common stock					(3.5	)					(2.3	)					(5.4	)
Forfeiture of restricted common stock					0.9						0.8						1.1
Compensation expense recognized					2.3						2.2						3.8
Equity Units allocated fees and expenses and the
present value of contract adjustment payments					-						-						(22.5	)
Other					0.3						0.1						(1.0	)
Ending balance		136,406,306			2,330.6			136,113,954			2,324.4			135,636,538			2,313.7
Retained Earnings
Beginning balance					626.5						529.2						489.3
Net income attributable to Great Plains Energy					174.4						211.7						150.1
Loss on reissuance of treasury stock					(0.7	)					-						-
Dividends:
Common stock					(113.5	)					(112.6	)					(108.9	)
Preferred stock - at required rates					(1.6	)					(1.6	)					(1.6	)
Performance shares					(0.4	)					(0.2	)					(0.1	)
Performance shares amendment					-						-						0.4
Ending balance					684.7						626.5						529.2
Treasury Stock
Beginning balance		(400,889	)		(8.9	)		(213,423	)		(5.5	)		(120,677	)		(3.6	)
Treasury shares acquired		(125,234	)		(2.4	)		(188,383	)		(3.4	)		(132,593	)		(2.9	)
Treasury shares reissued		261,556			5.7			917			-			39,847			1.0
Ending balance		(264,567	)		(5.6	)		(400,889	)		(8.9	)		(213,423	)		(5.5	)
Accumulated Other Comprehensive Income (Loss)
Beginning balance					(56.1	)					(44.9	)					(53.5	)
Derivative hedging activity, net of tax					6.8						(10.6	)					5.3
Change in unrecognized pension expense, net of tax					(0.5	)					(0.6	)					3.3
Ending balance					(49.8	)					(56.1	)					(44.9	)
Total Great Plains Energy Common Shareholders' Equity				$	2,959.9					$	2,885.9					$	2,792.5
Noncontrolling Interest
Beginning balance				$	1.2					$	1.2					$	1.0
Net income (loss) attributable to noncontrolling interest					(0.2	)					0.2						0.3
Distribution					-						(0.2	)					(0.1	)
Ending balance				$	1.0					$	1.2					$	1.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

60

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Comprehensive Income
Year Ended December 31	2011			2010			2009
	(millions)
Net income	$	174.2		$	211.9		$	150.4
Other comprehensive income (loss)
Loss on derivative hedging instruments		(5.9	)		(28.0	)		(0.4	)
Income tax benefit		2.3			10.8			0.1
Net loss on derivative hedging instruments		(3.6	)		(17.2	)		(0.3	)
Reclassification to expenses, net of tax (Note 18)		10.4			6.6			5.6
Derivative hedging activity, net of tax		6.8			(10.6	)		5.3
Defined benefit pension plans
Net gain (loss) arising during period		(1.2	)		(1.3	)		5.0
Less:  amortization of net gain included in net periodic benefit costs		0.4			0.3			0.4
Income tax (expense) benefit		0.3			0.4			(2.1	)
Change in unrecognized pension expense, net of tax		(0.5	)		(0.6	)		3.3
Comprehensive income		180.5			200.7			159.0
Less:  comprehensive (income) loss attributable to noncontrolling interest		0.2			(0.2	)		(0.3	)
Comprehensive income attributable to Great Plains Energy	$	180.7		$	200.5		$	158.7
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

61

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Income
Year Ended December 31	2011			2010			2009
Operating Revenues	(millions)
Electric revenues	$	1,558.3		$	1,517.1		$	1,318.2
Operating Expenses
Fuel		333.5			278.8			251.3
Purchased power		70.8			78.9			70.8
Transmission of electricity by others		18.8			15.0			12.3
Operating and maintenance expenses		470.9			434.3			403.3
Voluntary separation program		9.2			-			-
Depreciation and amortization		193.1			256.4			229.6
General taxes		139.7			129.3			118.7
Other		1.1			13.0			-
Total		1,237.1			1,205.7			1,086.0
Operating income		321.2			311.4			232.2
Non-operating income		2.9			24.7			33.2
Non-operating expenses		(3.9	)		(5.6	)		(4.7	)
Interest charges		(115.6	)		(85.7	)		(84.9	)
Income before income tax expense		204.6			244.8			175.8
Income tax expense		(69.1	)		(81.6	)		(46.9	)
Net income	$	135.5		$	163.2		$	128.9
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

62

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
	December 31
	2011		2010
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	1.9	$	3.6
Funds on deposit		0.1		0.4
Receivables, net		172.9		169.4
Accounts receivable pledged as collateral		95.0		95.0
Fuel inventories, at average cost		59.0		44.9
Materials and supplies, at average cost		101.1		94.4
Deferred refueling outage costs		27.5		9.6
Refundable income taxes		5.7		9.0
Deferred income taxes		-		5.6
Prepaid expenses and other assets		16.0		10.0
Total		479.2		441.9
Utility Plant, at Original Cost
Electric		7,829.3		7,540.9
Less-accumulated depreciation		3,243.0		3,104.4
Net utility plant in service		4,586.3		4,436.5
Construction work in progress		203.5		227.6
Nuclear fuel, net of amortization of $132.7 and $131.1		76.6		79.2
Total		4,866.4		4,743.3
Investments and Other Assets
Nuclear decommissioning trust fund		135.3		129.2
Regulatory assets		780.7		679.6
Other		30.6		32.3
Total		946.6		841.1
Total	$	6,292.2	$	6,026.3
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

63

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
	December 31
	2011			2010
LIABILITIES AND CAPITALIZATION	(millions, except share amounts)
Current Liabilities
Collateralized note payable	$	95.0		$	95.0
Commercial paper		227.0			263.5
Current maturities of long-term debt		12.7			150.3
Accounts payable		214.8			201.7
Accrued taxes		20.6			21.3
Accrued interest		30.0			26.2
Accrued compensation and benefits		40.8			46.8
Pension and post-retirement liability		3.0			2.6
Other		13.7			7.8
Total		657.6			815.2
Deferred Credits and Other Liabilities
Deferred income taxes		772.7			692.0
Deferred tax credits		127.9			129.4
Asset retirement obligations		134.3			129.7
Pension and post-retirement liability		440.9			407.3
Regulatory liabilities		142.8			141.3
Other		68.6			76.7
Total		1,687.2			1,576.4
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		513.8			478.3
Accumulated other comprehensive loss		(31.4	)		(36.4	)
Total		2,045.5			2,005.0
Long-term debt (Note 11)		1,901.9			1,629.7
Total		3,947.4			3,634.7
Commitments and Contingencies (Note 14)
Total	$	6,292.2		$	6,026.3
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

64

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Cash Flows
Year Ended December 31	2011			2010			2009
Cash Flows from Operating Activities	(millions)
Net income	$	135.5		$	163.2		$	128.9
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		193.1			256.4			229.6
Amortization of:
Nuclear fuel		21.4			25.1			16.1
Other		29.5			24.2			19.0
Deferred income taxes, net		80.6			83.2			(38.2	)
Investment tax credit amortization		(1.5	)		(2.1	)		(1.4	)
Other operating activities (Note 2)		(118.3	)		(127.8	)		(66.1	)
Net cash from operating activities		340.3			422.2			287.9
Cash Flows from Investing Activities
Utility capital expenditures		(336.5	)		(463.1	)		(626.5	)
Allowance for borrowed funds used during construction		(2.9	)		(22.4	)		(31.1	)
Purchases of nuclear decommissioning trust investments		(18.5	)		(83.3	)		(99.0	)
Proceeds from nuclear decommissioning trust investments		15.1			79.6			95.3
Net money pool lending		12.1			(6.1	)		(6.0	)
Other investing activities		(9.7	)		(13.4	)		(0.6	)
Net cash from investing activities		(340.4	)		(508.7	)		(667.9	)
Cash Flows from Financing Activities
Issuance of long-term debt		397.4			-			413.2
Repayment of long-term debt		(263.1	)		(0.2	)		-
Net change in short-term borrowings		(36.5	)		76.9			(193.6	)
Net change in collateralized short-term borrowings		-			95.0			-
Net money pool borrowings		6.7			1.1			0.9
Dividends paid to Great Plains Energy		(100.0	)		(95.0	)		(72.0	)
Equity contribution from Great Plains Energy		-			-			247.5
0Issuance fees		(6.1	)		(5.1	)		(4.0	)
Net cash from financing activities		(1.6	)		72.7			392.0
Net Change in Cash and Cash Equivalents		(1.7	)		(13.8	)		12.0
Cash and Cash Equivalents at Beginning of Year		3.6			17.4			5.4
Cash and Cash Equivalents at End of Year	$	1.9		$	3.6		$	17.4
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are
an integral part of these statements.

65

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Common Shareholder's Equity
Year Ended December 31	2011					2010					2009
	Shares		Amount			Shares		Amount			Shares		Amount
Common Stock	(millions, except share amounts)
Beginning balance		1	$	1,563.1			1	$	1,563.1			1	$	1,315.6
Equity contribution from Great Plains Energy				-					-					247.5
Ending balance		1		1,563.1			1		1,563.1			1		1,563.1
Retained Earnings
Beginning balance				478.3					410.1					353.2
Net income				135.5					163.2					128.9
Dividends:
Common stock held by Great Plains Energy				(100.0	)				(95.0	)				(72.0	)
Ending balance				513.8					478.3					410.1
Accumulated Other Comprehensive Income (Loss)
Beginning balance				(36.4	)				(41.5	)				(46.9	)
Derivative hedging activity, net of tax				5.0					5.1					5.4
Ending balance				(31.4	)				(36.4	)				(41.5	)
Total Common Shareholder's Equity			$	2,045.5				$	2,005.0				$	1,931.7
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these
statements.

66

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Comprehensive Income
Year Ended December 31	2011			2010			2009
	(millions)
Net income	$	135.5		$	163.2		$	128.9
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments		(0.6	)		(0.9	)		0.2
Income tax (expense) benefit		0.2			0.3			(0.1	)
Net gain (loss) on derivative hedging instruments		(0.4	)		(0.6	)		0.1
Reclassification to expenses, net of tax (Note 18)		5.4			5.7			5.3
Derivative hedging activity, net of tax		5.0			5.1			5.4
Comprehensive income	$	140.5		$	168.3		$	134.3
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

67

GREAT PLAINS ENERGY INCORPORATED

KANSAS CITY POWER & LIGHT COMPANY

Notes to Consolidated Financial Statements

The notes to 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.

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

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

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

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

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

Great Plains Energy’s sole reportable business segment is electric utility.  See Note 21 for additional information.

Use of Estimates

The process of preparing financial statements in conformity with Generally Accepted Accounting Principles (GAAP) requires the use of estimates and assumptions that affect the reported amounts of certain types of assets, liabilities, revenues, and expenses.  Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements.  Accordingly, upon settlement, actual results may differ from estimated amounts.

Cash and Cash Equivalents

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

Funds on Deposit

Funds on deposit consist primarily of cash provided to counterparties in support of margin requirements related to commodity purchases, commodity swaps and futures contracts.  Pursuant to individual contract terms with counterparties, deposit amounts required vary with changes in market prices, credit provisions and various other factors.  Interest is earned on most funds on deposit.  Great Plains Energy also holds funds on deposit from counterparties in the same manner.  These funds are included in other current liabilities on the consolidated balance sheets.

68

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it is practicable to estimate that value.

Nuclear decommissioning trust fund – KCP&L’s nuclear decommissioning trust fund assets are recorded at fair value.  Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.

Rabbi trust –GMO’s rabbi trusts related to its Supplemental Executive Retirement Plan (SERP) are recorded at fair value, which are based on quoted market prices of the investments held by the trusts and/or valuation models.  The rabbi trusts are included in Other – Investments and Other Assets on Great Plains Energy’s consolidated balance sheets.

Long-term debt – Fair value is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices were not available.  At December 31, 2011, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.5 billion and $3.9 billion, respectively.  At December 31, 2011, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.9 billion and $2.2 billion, respectively.  At December 31, 2010, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.4 billion and $3.7 billion, respectively.  At December 31, 2010, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.8 billion and $1.9 billion, respectively.

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

Pension plans – For financial reporting purposes, the market value of plan assets is the fair value.  KCP&L uses a five-year smoothing of assets to determine fair value for regulatory reporting purposes.

Derivative Instruments

The Company records derivative instruments on the balance sheet at fair value in accordance with GAAP.  Great Plains Energy and KCP&L enter into derivative contracts to manage exposure to commodity price and interest rate fluctuations.  Derivative instruments designated as normal purchases and normal sales (NPNS) and cash flow hedges are used solely for hedging purposes and are not issued or held for speculative reasons.

The Company considers various qualitative factors, such as contract and market place attributes, in designating derivative instruments at inception.  Great Plains Energy and KCP&L may elect the NPNS exception, which requires the effects of the derivative to be recorded when the underlying contract settles.  Great Plains Energy and KCP&L account for derivative instruments that are not designated as NPNS as cash flow hedges or non-hedging derivatives, which are recorded as assets or liabilities on the consolidated balance sheets at fair value.  In addition, if a derivative instrument is designated as a cash flow hedge, Great Plains Energy and KCP&L document the method of determining hedge effectiveness and measuring ineffectiveness.  See Note 18 for additional information regarding derivative financial instruments and hedging activities.

Great Plains Energy and KCP&L offset fair value amounts recognized for derivative instruments under master netting arrangements, which include rights to reclaim cash collateral (a receivable), or the obligation to return cash collateral (a payable). Great Plains Energy and KCP&L classify cash flows from derivative instruments in the same category as the cash flows from the items being hedged.

69

Utility Plant

Great Plains Energy’s and KCP&L's utility plant is stated at historical cost.  These costs include taxes, an allowance for the cost of borrowed and equity funds used to finance construction and payroll-related costs, including pensions and other fringe benefits.  Replacements, improvements and additions to units of property are capitalized.  Repairs of property and replacements of items not considered to be units of property are expensed as incurred (except as discussed under Deferred Refueling Outage Costs).  When property units are retired or otherwise disposed, the original cost, net of salvage, is charged to accumulated depreciation.  Substantially all of KCP&L’s utility plant is pledged as collateral for KCP&L’s mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented.  Substantially all of GMO’s St. Joseph Light & Power division utility plant is pledged as collateral for GMO’s mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented.

As prescribed by The Federal Energy Regulatory Commission (FERC), Allowance for Funds Used During Construction (AFUDC) is charged to the cost of the plant during construction.  AFUDC equity funds are included as a non-cash item in non-operating income and AFUDC borrowed funds are a reduction of interest charges.  The rates used to compute gross AFUDC are compounded semi-annually and averaged 0.2% in 2011, 6.8% in 2010 and 7.6% in 2009 for KCP&L and for GMO averaged 5.4% in 2011, 4.6% in 2010 and 5.4% in 2009.

Great Plains Energy’s and KCP&L’s balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following tables.

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

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

70

Depreciation and Amortization

Depreciation and amortization of utility plant other than nuclear fuel is computed using the straight-line method over the estimated lives of depreciable property based on rates approved by state regulatory authorities.  Annual depreciation rates average approximately 3%.  Nuclear fuel is amortized to fuel expense based on the quantity of heat produced during the generation of electricity.

Great Plains Energy’s depreciation expense was $239.9 million, $243.6 million and $228.9 million for 2011, 2010 and 2009, respectively.  KCP&L’s depreciation expense was $162.0 million, $170.9 million and $158.4 million for 2011, 2010 and 2009, respectively.  Great Plains Energy’s and KCP&L’s depreciation and amortization expense includes $14.4 million, $72.6 million and $58.2 million for 2011, 2010 and 2009, respectively, of additional amortization to help maintain cash flow levels during KCP&L’s Comprehensive Energy Plan pursuant to orders of the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC).  This additional amortization concluded following the December 2010 and May 2011 effective dates of new retail rates for KCP&L in Kansas and Missouri, respectively.

Nuclear Plant Decommissioning Costs

Nuclear plant decommissioning cost estimates are based on the immediate dismantlement method and include the costs of decontamination, dismantlement and site restoration.  Based on these cost estimates, KCP&L contributes to a tax-qualified trust fund to be used to decommission Wolf Creek Generating Station (Wolf Creek).  Related liabilities for decommissioning are included on Great Plains Energy’s and KCP&L’s balance sheets in Asset Retirement Obligations (AROs).

As a result of the authorized regulatory treatment and related regulatory accounting, differences between the decommissioning trust fund asset and the related ARO are recorded as a regulatory asset or liability.  See Note 7 for discussion of AROs including those associated with nuclear plant decommissioning costs.

Deferred Refueling Outage Costs

KCP&L uses the deferral method to account for operations and maintenance expenses incurred in support of Wolf Creek’s scheduled refueling outages and amortizes them evenly (monthly) over the unit’s operating cycle of 18 months until the next scheduled outage.  Replacement power costs during an outage are expensed as incurred.

Regulatory Matters

KCP&L and GMO defer items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded if KCP&L and GMO were not regulated.  See Note 5 for additional information concerning regulatory matters.

Revenue Recognition

Great Plains Energy and KCP&L recognize revenues on sales of electricity when the service is provided.  Revenues recorded include electric services provided but not yet billed by KCP&L and GMO.  Unbilled revenues are recorded for kWh usage in the period following the customers’ billing cycle to the end of the month.  KCP&L’s and GMO’s estimate is based on net system kWh usage less actual billed kWhs.  KCP&L’s and GMO’s estimated unbilled kWhs are allocated and priced by regulatory jurisdiction across the rate classes based on actual billing rates.

KCP&L and GMO collect from customers gross receipts taxes levied by state and local governments.  These taxes from KCP&L’s Missouri customers are recorded gross in operating revenues and general taxes on Great Plains Energy’s and KCP&L’s statements of income.  KCP&L’s gross receipts taxes collected from Missouri customers were $55.6 million, $54.3 million, and $46.8 million in 2011, 2010 and 2009, respectively.  These taxes from KCP&L’s Kansas customers and GMO’s customers are recorded net in operating revenues on Great Plains Energy’s statements of income.

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Great Plains Energy and KCP&L collect sales taxes from customers and remit to state and local governments.  These taxes are presented on a net basis on Great Plains Energy’s and KCP&L’s statements of income.

Great Plains Energy and KCP&L record sale and purchase activity on a net basis in wholesale revenue or purchased power when transacting with Regional Transmission Organization (RTO)/Independent System Operator (ISO) markets.

Allowance for Doubtful Accounts

This reserve represents estimated uncollectible accounts receivable and is based on management’s judgment considering historical loss experience and the characteristics of existing accounts.  Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses.  Receivables are charged off against the reserve when they are deemed uncollectible.

Property Gains and Losses

Net gains and losses from the sale of assets and businesses and from asset impairments are recorded in operating expenses.

Asset Impairments

Long-lived assets and finite-lived intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  If the sum of the undiscounted expected future cash flows from an asset to be held and used is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements.  The amount of impairment recognized is the excess of the carrying value of the asset over its fair value.

Goodwill and indefinite lived intangible assets are tested for impairment annually and when an event occurs indicating the possibility that an impairment exists.  The annual test must be performed at the same time each year.  If the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements.  To measure the amount of the impairment loss to recognize, the implied fair value of the reporting unit goodwill is compared with its carrying value.

Income Taxes

Income taxes are accounted for using the asset/liability approach.  Deferred tax assets and liabilities are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, applying enacted statutory tax rates in effect for the year in which the differences are expected to reverse.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized.

Great Plains Energy and KCP&L recognize tax benefits based on a “more-likely-than-not” recognition threshold.  In addition, Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.

Great Plains Energy files a consolidated federal income tax return as well as unitary and combined income tax returns in several state jurisdictions with Kansas and Missouri being the most significant.  Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss.  KCP&L’s income tax provision includes taxes allocated based on its separate company income or loss.

Great Plains Energy and KCP&L have established a net regulatory asset for the additional future revenues to be collected from customers for deferred income taxes.  Tax credits are recognized in the year generated except for certain KCP&L and GMO investment tax credits that have been deferred and amortized over the remaining service lives of the related properties.

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Environmental Matters

Environmental costs are accrued when it is probable a liability has been incurred and the amount of the liability can be reasonably estimated.

Basic and Diluted Earnings per Common Share Calculation

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

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

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

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

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

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

Dividends Declared

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

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

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2.   SUPPLEMENTAL CASH FLOW INFORMATION

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

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

Significant Non-Cash Items

On January 1, 2010, Great Plains Energy and KCP&L adopted new accounting guidance for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivable pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s and KCP&L’s balance sheets.  As a result, cash flows from operating activities were reduced by $95.0 million and cash flows from financing activities were raised by $95.0 million with no impact to the net change in cash for the year ended December 31, 2010.

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3.   RECEIVABLES

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

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

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

Sale of Accounts Receivable – KCP&L

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

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

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

				Receivables			Consolidated
2011	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,415.6	)	$	1,415.6		$	-
Gain (loss) on sale of accounts receivable (a)		(17.9	)		17.7			(0.2	)
Servicing fees		2.6			(2.6	)		-
Fees to outside investor		-			(1.2	)		(1.2	)
Cash flows during the period
Cash from customers transferred to Receivables Company		(1,412.4	)		1,412.4			-
Cash paid to KCP&L for receivables purchased		1,394.7			(1,394.7	)		-
Servicing fees		2.6			(2.6	)		-
Interest on intercompany note		0.5			(0.5	)		-

				Receivables			Consolidated
2010	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,341.0	)	$	1,341.0		$	-
Gain (loss) on sale of accounts receivable (a)		(17.0	)		16.8			(0.2	)
Servicing fees		3.2			(3.2	)		-
Fees to outside investor		-			(1.2	)		(1.2	)
Cash flows during the period
Cash from customers transferred to Receivables Company		(1,337.4	)		1,337.4			-
Cash paid to KCP&L for receivables purchased		1,320.7			(1,320.7	)		-
Servicing fees		3.2			(3.2	)		-
Interest on intercompany note		0.5			(0.5	)		-
(a) Any net gain (loss) is the result of the timing difference inherent in collecting receivables and
over the life of the agreement will net to zero.

4.   NUCLEAR PLANT

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

Spent Nuclear Fuel and High-Level Radioactive Waste

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel.  KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kWh of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel.  These disposal costs are charged to fuel expense.  In 2010, the DOE filed a motion with the Nuclear Regulatory Commission (NRC) to withdraw its then pending application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada.  An NRC board denied the DOE’s

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motion to withdraw its application, and the DOE appealed that decision to the full NRC.  In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of September 2011 due to a lack of funding.  These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application.  Oral argument to the court is expected later in 2012.  Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025, and believes it will be able to expand on-site storage as needed past 2025.  Management cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.  See Note 15 for a related legal proceeding.

Low-Level Radioactive Waste

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

Nuclear Plant Decommissioning Costs

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

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

Nuclear Decommissioning Trust Fund

In 2011 and 2010, KCP&L contributed approximately $3.4 million and $3.7 million, respectively, to a tax-qualified trust fund to be used to decommission Wolf Creek.  Amounts funded are charged to other operating expense and recovered in customers’ rates.  The funding level assumes a projected level of return on trust assets.  If the actual return on trust assets is below the projected level or actual decommissioning costs are higher than estimated, KCP&L could be responsible for the balance of funds required; however, while there can be no assurances, management believes a rate increase would be allowed to recover decommissioning costs over the remaining life of the unit.

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

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

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

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

The weighted average maturity of debt securities held by the trust at December 31, 2011, was approximately 7 years.  The costs of securities sold are determined on the basis of specific identification.  The following table summarizes the realized gains and losses from the sale of securities in the nuclear decommissioning trust fund.

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

Nuclear Insurance

The owners of Wolf Creek (Owners) maintain nuclear insurance for Wolf Creek for nuclear liability, nuclear property and accidental outage.  These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war.  The nuclear property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for acts of terrorism and related losses, including replacement power costs.  There is no industry aggregate limit for liability claims related to terrorism, regardless of the number of acts of terrorism affecting Wolf Creek or any other nuclear energy liability policy or the number of policies in place.  An industry aggregate limit of $3.2 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), the Owners’ insurance provider, exists for property claims related to terrorism, including accidental outage power costs for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act.  These limits plus any recoverable reinsurance are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts.  In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

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In the event of a catastrophic loss at Wolf Creek, the insurance coverage may not be adequate to cover property damage and extra expenses incurred.  Uninsured losses, to the extent not recovered through rates, would be assumed by KCP&L and the other owners and could have a material effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, which was reauthorized through December 31, 2025, by the Energy Policy Act of 2005, the Owners are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently $12.6 billion.  This limit of liability consists of the maximum available commercial insurance of $0.4 billion and the remaining $12.2 billion is provided through an industry-wide retrospective assessment program mandated by law, known as the Secondary Financial Protection (SFP) program.  Under the SFP program, the Owners can be assessed up to $117.5 million ($55.2 million, KCP&L’s 47% share) per incident at any commercial reactor in the country, payable at no more than $17.5 million ($8.2 million, KCP&L’s 47% share) per incident per year.  This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes.  In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

Nuclear Property Insurance

The Owners carry decontamination liability, premature decommissioning liability and property damage insurance from NEIL for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, KCP&L's 47% share).  In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC.  KCP&L’s share of any remaining proceeds can be used for further decontamination, property damage restoration and premature decommissioning costs.  Premature decommissioning coverage applies only if an accident at Wolf Creek exceeds $500 million in property damage and decontamination expenses, and only after trust funds have been exhausted.

Accidental Nuclear Outage Insurance

The Owners also carry additional insurance from NEIL to cover costs of replacement power and other extra expenses incurred in the event of a prolonged outage resulting from accidental property damage at Wolf Creek.

Under all NEIL policies, the Owners are subject to retrospective assessments if NEIL losses, for each policy year, exceed the accumulated funds available to the insurer under that policy.  The estimated maximum amount of retrospective assessments under the current policies could total approximately $30.9 million ($14.5 million, KCP&L’s 47% share) per policy year.

5.   REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

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

KCP&L Missouri Rate Case Proceedings

On February 27, 2012, KCP&L filed an application with the MPSC to request an increase of its retail rates of $105.7 million, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%.  The request includes recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service and also includes a lower annual offset to the revenue requirement for the Missouri jurisdictional

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portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset).  KCP&L currently expects that it will not be able to achieve the $45.9 million wholesale margin offset currently reflected in its retail rates due to a decline in wholesale power prices, which is being driven by low natural gas prices.

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

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

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

GMO Missouri Rate Case Proceedings

On February 27, 2012, GMO filed an application with the MPSC to request an increase of its retail rates of $58.3 million for its Missouri Public Service division and $25.2 million for its L&P division, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%.  The requests include recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service, costs related to energy efficiency and demand side management programs, and increased fuel costs.

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

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

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which is the amount over GMO’s requested $22.1 million increase for that division, and will phase in the deferred revenue amount in equal parts over a two-year period, plus carrying costs.  In addition, GMO shall be allowed to recover the revenue which would have been allowed in the absence of a phase in.

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

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

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

GMO Fuel Adjustment Clause (FAC) Prudence Review

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

SPP and NERC Inquiries

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

Regulatory Assets and Liabilities

Great Plains Energy and KCP&L have recorded assets and liabilities on their consolidated balance sheets resulting from the effects of the ratemaking process, which would not otherwise be recorded if the Companies were not regulated.  Regulatory assets represent incurred costs that are probable of recovery from future revenues.  Regulatory liabilities represent future reductions in revenues or refunds to customers.

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Management regularly assesses whether regulatory assets and liabilities are probable of future recovery or refund by considering factors such as decisions by the MPSC, KCC or FERC in KCP&L’s and GMO’s rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedent on matters applicable to the Companies; and changes in laws and regulations.  If recovery or refund of regulatory assets or liabilities is not approved by regulators or is no longer deemed probable, these regulatory assets or liabilities are recognized in the current period results of operations.  The Companies’ continued ability to meet the criteria for recording regulatory assets and liabilities may be affected in the future by restructuring and deregulation in the electric industry or changes in accounting rules.  In the event that the criteria no longer applied to any or all of the Companies’ operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism were provided.  Additionally, these factors could result in an impairment on utility plant assets.   Great Plains Energy’s and KCP&L’s regulatory assets and liabilities are detailed in the following tables.

							Great
December 31, 2011	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	119.6		$	24.6		$	144.2
Loss on reacquired debt		9.1	(a)		2.7	(a)		11.8
Cost of removal		4.6			-			4.6
Asset retirement obligations		31.4			13.8			45.2
Pension and post-retirement costs		466.4	(b)		122.0	(b)		588.4
Deferred customer programs		48.2	(c)		20.6			68.8
Rate case expenses		9.6	(d)		3.8	(d)		13.4
Skill set realignment costs		3.4	(e)		-			3.4
Fuel adjustment clauses		14.0	(d)		36.4	(d)		50.4
Acquisition transition costs		24.7	(f )		20.2	(f )		44.9
Derivative instruments		-			7.6	(g)		7.6
Iatan No. 1 and Common facilities depreciation and carrying costs		16.4			6.1			22.5
Iatan No. 2 construction accounting costs		27.9			15.4			43.3
Kansas property tax surcharge		3.7	(d)		-			3.7
Other		1.7	(h)		4.3	(h)		6.0
Total	$	780.7		$	277.5		$	1,058.2
Regulatory Liabilities
Emission allowances	$	82.0		$	0.2		$	82.2
Asset retirement obligations		49.3			-			49.3
Pension		0.7			40.8			41.5
Cost of removal		-			61.9	(i)		61.9
Other		10.8			22.8			33.6
Total	$	142.8		$	125.7		$	268.5

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

(b) Represents unrecognized gains and losses, prior service and transition costs that will be recognized in future net periodic pension and post-retirement costs, pension settlements amortized over various periods and financial and regulatory accounting method differences not included in rate base that will be eliminated over the life of the pension plans.

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

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

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

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

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

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

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

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

6.   GOODWILL AND INTANGIBLE ASSETS

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

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Great Plains Energy’s and KCP&L’s intangible assets are included in electric utility plant on the consolidated balance sheets and are detailed in the following table.

	December 31, 2011					December 31, 2010
	Gross Carrying		Accumulated			Gross Carrying		Accumulated
	Amount		Amortization			Amount		Amortization
KCP&L	(millions)
Computer software	$	171.7	$	(129.9	)	$	168.2	$	(118.0	)
Asset improvements		11.7		(0.6	)		5.8		-
Great Plains Energy
Computer software	$	202.5	$	(143.5	)	$	201.1	$	(137.3	)
Asset improvements		27.0		(3.7	)		27.9		(4.4	)

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

	2011		2010
	(millions)
Great Plains Energy	$	13.5	$	13.1
KCP&L		12.6		12.2

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

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

7.   ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations associated with tangible long-lived assets are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.  These liabilities are recognized at estimated fair value as incurred and capitalized as part of the cost of the related long-lived assets and depreciated over their useful lives.  Accretion of the liabilities due to the passage of time is recorded to a regulatory asset and/or liability.  Changes in the estimated fair values of the liabilities are recognized when known.

KCP&L has AROs related to decommissioning Wolf Creek, site remediation of its Spearville Wind Energy Facilities, asbestos abatement and for removal of storage tanks, an ash pond and landfill.  GMO has AROs related to asbestos abatement, an ash pond and landfill and removal of storage tanks and communication towers.

GPE and KCP&L have identified an additional asbestos ARO.  Certain wiring used in generating stations includes asbestos insulation, which would require special handling if disturbed.  Due to the inability to reasonably estimate the quantities or the amount of disturbance that will be necessary during dismantlement at the end of the life of a plant, a fair value of the obligation cannot be reasonably estimated at this time.  Management will continue to monitor the obligation and will recognize a liability in the period in which sufficient information becomes available to reasonably estimate its fair value.

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

	Great Plains Energy					KCP&L
	2011			2010		2011			2010
	(millions)
Beginning balance	$	143.3		$	132.6	$	129.7		$	119.8
Additions		0.8			2.0		-			2.0
Revision in timing and/or estimates		(3.8	)		-		(3.8	)		-
Accretion		9.3			8.7		8.4			7.9
Ending balance	$	149.6		$	143.3	$	134.3		$	129.7

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

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

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

During 2011, Great Plains Energy recorded settlement charges of $10.1 million from the voluntary separation program as a result of accelerated pension distributions.  The Companies deferred substantially all of the charges as a regulatory asset and expect to recover it over future periods pursuant to regulatory agreements.  See below for information regarding the voluntary separation program.

The following pension benefits tables provide information relating to the funded status of all defined benefit pension plans on an aggregate basis as well as the components of net periodic benefit costs.  For financial reporting purposes, the market value of plan assets is the fair value.  KCP&L uses a five-year smoothing of assets to determine fair value for regulatory reporting purposes.  Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with joint owners of power plants.

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

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

For financial reporting purposes, the estimated prior service cost and net loss for the defined benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2012 are $4.5 million and $44.5 million, respectively.  For financial reporting purposes, net actuarial gains and losses are recognized on a rolling five-year average basis.  For regulatory reporting purposes, net actuarial gains and losses are amortized over ten years.  The estimated prior service cost, net gain and transition costs for the other post-retirement benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2012 are $7.2 million, $(0.1) million and $1.0 million, respectively.

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

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

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The GMO SERP is reflected as an unfunded ABO of $20.6 million.  Great Plains Energy has segregated approximately $20.1 million of assets for this plan as of December 31, 2011, and expects to fund future benefit payments from these assets.

The expected long-term rate of return on plan assets represents Great Plains Energy’s estimate of the long-term return on plan assets and is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios.  Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns of various asset classes.  Based on the target asset allocation for each asset class, the overall expected rate of return for the portfolios was developed and adjusted for the effect of projected benefits paid from plan assets and future plan contributions.  The following tables provide the weighted-average assumptions used to determine benefit obligations and net costs.

Weighted-average assumptions used to determine	Pension Benefits						Other Benefits
the benefit obligation at plan year-end	2011			2010			2011			2010
Discount rate		5.01	%		5.54	%		5.03	%		5.50	%
Rate of compensation increase		4.08	%		4.08	%		4.07	%		4.06	%
Weighted-average assumptions used to determine	Pension Benefits						Other Benefits
net costs for years ended December 31	2011			2010			2011			2010
Discount rate		5.54	%		5.92	%		5.50	%		5.87	%
Expected long-term return on plan assets		7.29	%		8.00	%		2.83	% *		4.25	% *
Rate of compensation increase		4.08	%		4.26	%		4.06	%		4.25	%
* after tax

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

Great Plains Energy expects to contribute $94.5 million to the pension plans in 2012 to meet Employee Retirement Income Security Act of 1974 (ERISA) funding requirements and regulatory orders, the majority of which is expected to be paid by KCP&L.  Great Plains Energy’s funding policy is to contribute amounts sufficient to meet the ERISA funding requirements and MPSC and KCC rate orders plus additional amounts as considered appropriate; therefore, actual contributions may differ from expected contributions.  Great Plains Energy also expects to contribute $16.7 million to other post-retirement benefit plans in 2012, the majority of which is expected to be paid by KCP&L.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid through 2021.

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

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Pension plan assets are managed in accordance with prudent investor guidelines contained in the ERISA requirements.  The investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets within a reasonable and prudent level of risk.  The portfolios are invested, and periodically rebalanced, to achieve targeted allocations of approximately 27% U.S. large cap and small cap equity securities, 20% international equity securities, 36% fixed income securities, 7% real estate, 6% commodities and 4% hedge funds.  Fixed income securities include domestic and foreign corporate bonds, collateralized mortgage obligations and asset-backed securities, U.S. government agency, state and local obligations, U.S. treasury notes and money market funds.

The fair values of Great Plains Energy’s pension plan assets at December 31, 2011 and 2010, by asset category are in the following tables.

			Fair Value Measurements Using
Description	December 31 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions)
Pension Plans
Equity securities
U.S.(a)	$	156.3	$	94.6	$	61.7	$	-
International(b)		117.0		40.9		76.1		-
Real estate(c)		34.7		-		-		34.7
Commodities(d)		34.6		-		34.6		-
Fixed income securities
Fixed income funds(e)		166.5		34.2		132.3		-
U.S. Treasury		4.9		4.9		-		-
U.S. Agency, state and local obligations		17.7		-		17.7		-
U.S. corporate bonds(f)		26.6		-		26.6		-
Foreign corporate bonds		2.6		-		2.6		-
Hedge funds(g)		21.7		-		-		21.7
Total	$	582.6	$	174.6	$	351.6	$	56.4
Cash equivalents - money market funds		8.5
Total Pension Plans	$	591.1

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				Fair Value Measurements Using
Description		December 31 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Pension Plans
	Equity securities
	U.S.(a)	$	158.5	$	90.5	$	68.0	$	-
	International(b)		122.4		39.4		83.0		-
	Limited partnerships		0.1		-		-		0.1
	Real estate(c)		30.3		-		-		30.3
	Commodities(d)		37.0		-		37.0		-
	Fixed income securities
	Fixed income funds(e)		148.7		23.0		125.7		-
	U.S. Treasury		1.8		1.8		-		-
	U.S. Agency, state and local obligations		14.8		-		14.8		-
	U.S. corporate bonds(f)		24.2				24.2		-
	Foreign corporate bonds		1.5		-		1.5		-
	Hedge funds(g)		8.4		-		-		8.4
	Total	$	547.7	$	154.7	$	354.2	$	38.8
	Cash equivalents - money market funds		9.9
	Total Pension Plans	$	557.6
(a)	At December 31, 2011 and 2010, this category is comprised of $94.6 million and $90.5 million, respectively, of traded mutual funds valued at daily listed prices and $61.7 million and $68.0 million, respectively,
	of institutional common/collective trust funds valued at daily Net Asset Values (NAV) per share.
(b)	At December 31, 2011 and 2010, this category is comprised of $40.9 million and $39.4 million, respectively, of traded mutual funds valued at daily listed prices and $76.1 million and $83.0 million, respectively,
	of institutional common/collective trust funds valued at daily NAV per share.
(c)	This category is comprised of institutional common/collective trust funds and a limited partnership valued at NAV on a quarterly basis.
(d)	This category is comprised of institutional common/collective trust funds valued at daily NAV per share.
(e)	At December 31, 2011 and 2010, this category is comprised of $34.2 million and $23.0 million, respectively, of traded mutual funds valued at daily listed prices and $132.3 million and $125.7 million, respectively, of institutional common/collective trust funds valued at daily NAV per share.
(f)	At December 31, 2011 and 2010, this category is comprised of $18.1 million and $13.9 million, respectively, of corporate bonds, $6.1 million and $8.0 million, respectively, of collateralized mortgage obligations
	and $2.4 million and $2.3 million, respectively, of other asset-backed securities.
(g)	This category is comprised of closely-held limited partnerships valued at NAV on a quarterly basis.

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The following tables reconcile the beginning and ending balances for all level 3 pension plan assets measured at fair value on a recurring basis for 2011 and 2010.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Real		Hedge			Limited
Description	Estate		Funds			Partnerships			Total
	(millions)
Balance January 1, 2011	$	30.3	$	8.4		$	0.1		$	38.8
Actual return on plan assets
Relating to assets still held		3.9		(1.3	)		(0.1	)		2.5
Relating to assets sold		-		-			-			-
Purchase, sales, and settlements		0.5		14.6			-			15.1
Transfers in and/or out of Level 3		-		-			-			-
Balance December 31, 2011	$	34.7	$	21.7		$	-		$	56.4

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

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Other post-retirement plan assets are also managed in accordance with prudent investor guidelines contained in the ERISA requirements.  The investment strategy supports the objective of the funds, which is to preserve capital, maintain sufficient liquidity and earn a consistent rate of return.  Other post-retirement plan assets are invested primarily in fixed income securities, which may include domestic and foreign corporate bonds, collateralized mortgage obligations and asset-backed securities, U.S. government agency, state and local obligations, U.S. Treasury notes and money market funds, as well as domestic and international equity funds.

The fair values of Great Plains Energy’s other post-retirement plan assets at December 31, 2011 and 2010, by asset category are in the following tables.

				Fair Value Measurements Using
Description		December 31 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
	Equity securities	$	1.4	$	1.4	$	-	$	-
	Fixed income
	U.S. Treasury		14.3		14.3		-		-
	U.S. Agency, state and local obligations		27.2		-		27.2		-
	U.S. corporate bonds (a)		14.8		-		14.8		-
	Foreign corporate bonds		1.5		-		1.5		-
	Mutual funds		0.2		0.2		-		-
	Total	$	59.4	$	15.9	$	43.5	$	-
	Cash and cash equivalents - money market funds		18.0
	Total Other Post-Retirement Benefit Plans	$	77.4
(a)	This category is comprised of $12.7 million of corporate bonds, $0.6 million of collateralized mortgage obligations and $1.5 million
	of other asset-backed securities.

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				Fair Value Measurements Using
Description		December 31 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
	Fixed income
	U.S. Treasury	$	12.1	$	12.1	$	-	$	-
	U.S. Agency, state and local obligations		22.2		-		22.2		-
	U.S. corporate bonds (a)		11.4		-		11.4		-
	Foreign corporate bonds		1.0				1.0
	Mutual funds		0.1		0.1		-		-
	Total	$	46.8	$	12.2	$	34.6	$	-
	Cash and cash equivalents - money market funds		19.0
	Total Other Post-Retirement Benefit Plans	$	65.8
(a)	This category is comprised of $9.2 million of corporate bonds, $0.9 million of collateralized mortgage obligations and $1.3 million
	of other asset-backed securities.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.  The cost trend assumed for 2011 and 2012 was 8.0%, with the rate declining through 2018 to the ultimate cost trend rate of 5%.  The health care plan requires retirees to make monthly contributions on behalf of themselves and their dependents in an amount determined by Great Plains Energy.

The effects of a one-percentage point change in the assumed health care cost trend rates, holding all other assumptions constant, at December 31, 2011, are detailed in the following table.  The results reflect the increase in the Medicare Part D employer subsidy which is assumed to increase with the medical trend and employer caps on post-65 plans.

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

Employee Savings Plans

Great Plains Energy has defined contribution savings plans (401(k)) that cover substantially all employees.  Great Plains Energy matches employee contributions, subject to limits.  The annual cost of the plans was approximately $9.2 million, $8.9 million and $8.8 million in 2011, 2010 and 2009, respectively.  KCP&L’s annual cost of the plans was approximately $6.7 million, $6.5 million and $6.5 million in 2011, 2010 and 2009, respectively.

Voluntary Separation Program

In March 2011, Great Plains Energy and KCP&L announced an organizational realignment and voluntary separation program to assist in the management of overall costs within the level reflected in the Companies’ retail electric rates and to enhance organizational efficiency.  Savings from the realignment process and voluntary separation program, including approximately $15 million in labor costs on an annual basis, are expected to partially offset projected cost increases.  Under the voluntary separation program, any non-union employee could

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voluntarily elect to separate and receive a severance payment equal to two weeks of salary for every year of employment, with a minimum severance payment equal to fourteen weeks of salary.  There were 140 employees that made such elections and the majority separated on April 30, 2011.  Great Plains Energy recorded $12.7 million in 2011 related to this voluntary separation program reflecting severance and related payroll taxes to employees who elected to voluntarily separate.  KCP&L recorded $9.2 million in 2011 related to this voluntary separation program.

9.   EQUITY COMPENSATION

Great Plains Energy’s Long-Term Incentive Plan is an equity compensation plan approved by Great Plains Energy’s shareholders.  The Long-Term Incentive Plan permits the grant of restricted stock, restricted stock units, bonus shares, stock options, stock appreciation rights, limited stock appreciation rights, director shares, director deferred share units and performance shares to directors, officers and other employees of Great Plains Energy and KCP&L.  The maximum number of shares of Great Plains Energy common stock that can be issued under the plan is 8.0 million.  Common stock shares delivered by Great Plains Energy under the Long-Term Incentive Plan may be authorized but unissued, held in the treasury or purchased on the open market (including private purchases) in accordance with applicable securities laws.  Great Plains Energy has a policy of delivering newly issued shares, or shares surrendered by Long-Term Incentive Plan participants on account of withholding taxes and held in treasury, or both, and does not expect to repurchase common shares during 2012 to satisfy performance share payments, stock option exercises and director deferred share unit conversion.  Forfeiture rates are based on historical forfeitures and future expectations and are reevaluated annually.

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

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

Performance Shares

The payment of performance shares is contingent upon achievement of specific performance goals over a stated period of time as approved by the Compensation and Development Committee of Great Plains Energy’s Board of Directors.  The number of performance shares ultimately paid can vary from the number of shares initially granted depending on Great Plains Energy’s performance over stated performance periods.  Compensation expense for performance shares is calculated by taking the change in fair value between reporting periods for the portion for which the requisite service has been rendered.  Dividends are accrued over the vesting period and paid in cash based on the number of performance shares ultimately paid.

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

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

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

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

Restricted Stock

Restricted stock cannot be sold or otherwise transferred by the recipient prior to vesting and has a value equal to the fair market value of the shares on the issue date.  Restricted stock shares vest over a stated period of time with accruing reinvested dividends subject to the same restrictions.  Compensation expense, calculated by multiplying shares by the grant-date fair value related to restricted stock, is recognized over the stated vesting period.  Restricted stock activity for 2011 is summarized in the following table.

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

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

Stock Options

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

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

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

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

Director Deferred Share Units

Non-employee directors receive shares of Great Plains Energy’s common stock as part of their annual retainer.  Each director may elect to defer receipt of their shares until the end of January in the year after they leave the Board.  Director Deferred Share Units have a value equal to the market value of Great Plains Energy’s common stock on the grant date with accruing dividends.  Compensation expense, calculated by multiplying the director deferred share units by the related grant-date fair value, is recognized at the grant date.  The total fair value of shares of Director Deferred Share Units issued was insignificant for 2011 and 2010.  Director Deferred Share Units activity for 2011 is summarized in the following table.

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

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

Great Plains Energy’s $200 Million Revolving Credit Facility

In December 2011, Great Plains Energy entered into an amendment to its $200 million revolving credit facility with a group of banks to extend the term to December 2016 from August 2013.  The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time.  A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At December 31, 2011, Great Plains Energy was in compliance with this covenant.  At December 31, 2011, Great Plains Energy had $22.0 million of outstanding cash borrowings at a weighted-average interest rate of 2.06% and had issued letters of credit totaling $11.6 million under the credit facility.  At December 31, 2010, Great Plains Energy had $9.5 million of outstanding cash borrowings at a weighted-average interest rate of 3.06% and had issued letters of credit totaling $15.8 million under the credit facility.

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

In December 2011, KCP&L entered into an amendment to its $600 million revolving credit facility with a group of banks that provides support for its issuance of commercial paper and other general corporate purposes to extend the term to December 2016 from August 2013.  Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities.  A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At December 31, 2011, KCP&L was in compliance with this covenant.  At December 31, 2011, KCP&L had $227.0 million of commercial paper outstanding, at a weighted-average interest rate of 0.50%, had issued letters of credit totaling $21.5 million and had no outstanding cash borrowings under the credit facility.  At December 31, 2010, KCP&L had $263.5 million of commercial paper outstanding, at a weighted-average interest rate of 0.41%, had issued letters of credit totaling $24.4 million and had no outstanding cash borrowings under the credit facility.

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

In December 2011, GMO entered into an amendment to its $450 million revolving credit facility with a group of banks that provides support for its issuance of commercial paper and other general corporate purposes to extend the term to December 2016 from August 2013.  Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities.  A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At December 31, 2011, GMO was in compliance with this covenant.  At December 31, 2011, GMO had $40.0 million of commercial paper outstanding, at a weighted-average interest rate of 0.88%, had issued letters of credit totaling $13.2 million and had no outstanding cash borrowings under the credit facility.  At December 31, 2010, GMO had no outstanding cash borrowings and had issued letters of credit totaling $13.2 million under the credit facility.

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11.   LONG-TERM DEBT

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

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

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Amortization of Debt Expense

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

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

KCP&L General Mortgage Bonds and EIRR Bonds

KCP&L has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented (Indenture).  The Indenture creates a mortgage lien on substantially all of KCP&L’s utility plant.

In April 2011, KCP&L purchased in lieu of redemption its $63.3 million EIRR Series 2007A-1, $10.0 million EIRR Series 2007A-2 and $39.5 million EIRR Series 1993B bonds.  KCP&L opted to purchase rather than remarket the bonds given the poor conditions in the tax-exempt market.  As of December 31, 2011, the bonds were still outstanding, but were not reported as a liability on the balance sheet since they are being held by KCP&L.  KCP&L has the ability to remarket these bonds to third parties whenever it determines market conditions are sufficiently attractive to do so.

Mortgage bonds totaling $642.5 million and $755.3 million were outstanding at December 31, 2011 and 2010, respectively.

KCP&L Municipal Bond Insurance Policies

KCP&L’s EIRR Bonds Series 2007 A-1, 2007 A-2 and 2007B totaling $146.5 million are covered by a municipal bond insurance policy issued by Financial Guaranty Insurance Company (FGIC).  The insurance agreement between KCP&L and FGIC provides for reimbursement by KCP&L for any amounts that FGIC pays under the municipal bond insurance policy.  The policy also restricts the amount of secured debt KCP&L may issue.  In 2009, because KCP&L issued debt secured by liens not permitted by the agreement or resulting in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization, KCP&L was required to issue and deliver collateral to FGIC in the form of $146.5 million of Mortgage Bonds Series 2007 EIRR Issuer due 2035.  The bonds are not incremental debt for KCP&L but collateralize FGIC’s claim on KCP&L if FGIC was required to meet its obligation under the insurance agreement.

KCP&L’s secured 1992 Series EIRR bonds totaling $31.0 million, secured Series 1993A and 1993B EIRR bonds totaling $79.5 million, and secured and unsecured EIRR Bonds Series 2005 totaling $35.9 million and $50.0 million, respectively, are covered by a municipal bond insurance policy between KCP&L and Syncora Guarantee, Inc. (Syncora).  The insurance agreements between KCP&L and Syncora provide for reimbursement by KCP&L for any amounts that Syncora pays under the municipal bond insurance policies.  The insurance agreements contain a covenant that the indebtedness to total capitalization ratio of KCP&L and its consolidated subsidiaries will not be greater than 0.68 to 1.00.  At December 31, 2011, KCP&L was in compliance with this covenant.  KCP&L is also restricted from issuing additional bonds under its General Mortgage Indenture if, after giving effect to such additional bonds, the proportion of secured debt to total indebtedness would be more than 75%, or more than 50% if the long term rating for such bonds by Standard & Poor’s or Moody’s Investors Service would be at or below A- or A3, respectively.  The insurance agreement covering the unsecured EIRR Bond Series 2005 also required KCP&L to provide collateral to Syncora in the form of $50.0 million of Mortgage Bonds Series 2005 EIRR Insurer due 2035 for KCP&L’s obligations under the insurance agreement as a result of KCP&L issuing general mortgage bonds in 2009 (other than refunding of outstanding general mortgage bonds) that resulted in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization.  The bonds are not incremental debt for KCP&L but collateralize Syncora’s claim on KCP&L if Syncora was

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required to meet its obligation under the insurance agreement.  In the event of a default under the insurance agreements, Syncora may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.

KCP&L Senior Notes

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

GMO First Mortgage Bonds

GMO has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented.  The Indenture creates a mortgage lien on substantially all of GMO’s St. Joseph Light & Power division utility plant.  Mortgage bonds totaling $11.2 million and $12.4 million, respectively, were outstanding at December 31, 2011 and 2010.

GMO Senior Notes

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

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

Great Plains Energy Senior Notes

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

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

In May 2009, Great Plains Energy issued $287.5 million of Equity Units.  Equity Units, each with a stated amount of $50, initially consist of a 5% undivided beneficial interest in $1,000 principal amount of 10.00% subordinated notes due June 15, 2042, and a purchase contract requiring the holder to purchase the Company’s common stock by June 15, 2012 (the settlement date).  Each purchase contract obligates the holder of the purchase contract to purchase, and Great Plains Energy to sell, no later than June 15, 2012, for $50 in cash, newly issued shares of the Company’s common stock equal to the settlement rate.  The purchase contracts may be settled earlier at the option of the holder subject to certain conditions, including but not limited to, the occurrence of a fundamental change (as defined in the agreement) at least 20 business days prior to June 15, 2012.  The settlement rate will vary according to the applicable market value of the Company’s common stock at the settlement date.  The applicable market value will be measured by the average of the closing price per share of the Company’s common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding June 15, 2012.  The settlement rate will be applied to the 5,750,000 Equity Units at the settlement date to issue a number of common shares determined as described in the following table.

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Applicable		Settlement rate	Market value
market value		(in common shares)	per Equity Unit (a)
$16.80 or greater		2.9762 to 1	Greater than $50 per Equity Unit
$16.80 to $14.00		$50 divided by the applicable	Equal to $50 per Equity Unit
		market value to 1
$14.00 or less		3.5714 to 1	Less than $50 per Equity Unit
(a)	Assumes that the market price of the Company's common stock on June 15, 2012,
	is the same as the applicable market value.

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

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

Scheduled Maturities

Great Plains Energy’s and KCP&L’s long-term debt maturities for the next five years are detailed in the following table.

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

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

12.   COMMON SHAREHOLDERS’ EQUITY

Great Plains Energy has an effective shelf registration statement for the sale of unspecified amounts of securities with the Securities and Exchange Commission (SEC) that was filed and became effective in May 2009.

Great Plains Energy has 5.0 million shares of common stock registered with the SEC for its Dividend Reinvestment and Direct Stock Purchase Plan.  The plan allows for the purchase of common shares by reinvesting

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dividends or making optional cash payments.  Great Plains Energy can issue new shares or purchase shares on the open market for the plan.  At December 31, 2011, 0.7 million shares remained available for future issuances.

Great Plains Energy has 12.3 million shares of common stock registered with the SEC for a defined contribution savings plan.  Shares issued under the plan may be either newly issued shares or shares purchased in the open market.  At December 31, 2011, 0.4 million shares remained available for future issuances.

Treasury shares are held for future distribution upon issuance of shares in conjunction with the Company’s Long-Term Incentive Plan.

Great Plains Energy’s articles of incorporation restrict the payment of common stock dividends in the event common equity is 25% or less of total capitalization.  In addition, if preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares.  If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of directors necessary to constitute a majority of the full Board.  Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at least 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress).  Under the Federal Power Act, KCP&L and GMO generally can pay dividends only out of retained earnings.  The revolving credit agreements of Great Plains Energy, KCP&L and GMO contain a covenant requiring each company to maintain a consolidated indebtedness to consolidated total capitalization ratio of not more than 0.65 to 1.00.  In addition, Great Plains Energy is prohibited from paying dividends on its common and preferred stock in the event its Equity Unit contract payments or interest payments on the debt underlying the Equity Units are deferred until such deferrals have been paid.

As of December 31, 2011, all of Great Plains Energy’s and KCP&L’s retained earnings and net income were free of restrictions.  As a result of the above restrictions, Great Plains Energy’s subsidiaries had restricted net assets of approximately $2.8 billion as of December 31, 2011.  The restrictions are not expected to affect the Companies’ ability to pay dividends at the current level in the foreseeable future.

13.   PREFERRED STOCK

At December 31, 2011, 1.6 million shares of Cumulative No Par Preferred Stock, 390,000 shares of Cumulative Preferred Stock, $100 par value and 11.0 million shares of no par Preference Stock were authorized under Great Plains Energy’s articles of incorporation.  All of the 390,000 authorized shares of Cumulative Preferred Stock are issued and outstanding.  Great Plains Energy has the option to redeem the $39.0 million of issued Cumulative Preferred Stock at prices ranging from 101% to 103.7% of par value.  If Great Plains Energy voluntarily files for dissolution or liquidation, the Cumulative Preferred Stock holders are entitled to receive the redemption prices.  If a proceeding for dissolution or liquidation is filed against Great Plains Energy, the Cumulative Preferred Stock holders are entitled to receive the $100 par value per share plus accrued and unpaid dividends.

14.   COMMITMENTS AND CONTINGENCIES

Environmental Matters

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

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

Air and Climate Change Overview

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Best Available Retrofit Technology (BART) Rule

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

Mercury and Air Toxics Standards (MATS) Rule

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

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

Industrial Boiler Rule

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

New Source Review

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

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

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

Collaboration Agreement

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

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

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

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

Climate Change

The Companies are subject to existing greenhouse gas reporting regulations and certain greenhouse gas permitting requirements.  Management believes it is possible that additional federal or relevant state or local laws or regulations could be enacted to address global climate change.  At the international level, while the United States is not a current party to the international Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions.  International agreements legally binding on the United States may be

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reached in the future.  Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels.  The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 25 million tons and 18 million tons per year for Great Plains Energy and KCP&L, respectively.

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

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

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

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

KCP&L and GMO project that they will be compliant with the Missouri renewable requirements, exclusive of the solar requirement, through 2023 for KCP&L and 2018 for GMO.  KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri solar requirements for the foreseeable future.  KCP&L also projects that it will be compliant with the Kansas renewable requirements through 2016.

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

SO2 NAAQS

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

Montrose Station Notice of Violation

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

Water

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

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

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

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

Solid Waste

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

Remediation

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

At December 31, 2011 and 2010, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site.  At December 31, 2011 and 2010, Great Plains Energy had $0.4 million accrued for environmental remediation expenses, which includes the $0.3 million at KCP&L, and additional potential remediation and ground water monitoring costs relating to two GMO sites.  The amounts accrued were established on an undiscounted basis and Great Plains Energy and KCP&L do not currently have an estimated time frame over which the accrued amounts may be paid.

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

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

Contractual Commitments

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

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

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

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

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

Great Plains Energy has expected sublease income of $1.2 million for the years 2012-2013.  Lease commitments end in 2048.  Operating lease commitments include rail cars to serve jointly-owned generating units where KCP&L is the managing partner.  Of the amounts included in the table above, KCP&L will be reimbursed by the other owners for approximately $2.2 million per year from 2012 to 2015 and then $0.4 million per year from 2016 to 2025, for a total of $13.0 million.

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Fuel commitments consist of commitments for nuclear fuel, coal and coal transportation.  Power commitments consist of commitments for renewable energy under power purchase agreements.  KCP&L and GMO purchase capacity from other utilities and nonutility suppliers.  Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable.  KCP&L has capacity sales agreements not included above that total $3.8 million for 2012 and $1.6 million for 2013.  La Cygne environmental project represents contractual commitments related to environmental upgrades at KCP&L’s La Cygne station.  KCP&L owns 50% of the La Cygne station and expects to be reimbursed by the other owner for its 50% share of the costs.  Non-regulated natural gas transportation consists of MPS Merchant’s commitments.  Other represents individual commitments entered into in the ordinary course of business.

15.   LEGAL PROCEEDINGS

KCP&L Spent Nuclear Fuel and Radioactive Waste

In January 2004, KCP&L and the other two Wolf Creek owners filed a lawsuit against the United States in the U.S. Court of Federal Claims seeking $14.1 million of damages resulting from the government’s failure to begin accepting spent nuclear fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982.  The Wolf Creek case was tried before a U.S. Court of Federal Claims judge in June 2010, and a decision was issued in November 2010, granting KCP&L and the other two Wolf Creek owners $10.6 million ($5.0 million KCP&L share) in damages.  In January 2011, KCP&L and the other two Wolf Creek owners as well as the United States filed appeals of the decision to the U.S. Court of Appeals for the Federal Circuit.  Briefing to the Court was completed in December 2011, and oral argument has been scheduled for March 7, 2012.

GMO Price Reporting Litigation

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

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

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16.   GUARANTEES

In the ordinary course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries.  Such agreements include, for example, guarantees and letters of credit.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended business purposes.  The majority of these agreements guarantee the Company’s own future performance, so a liability for the fair value of the obligation is not recorded.

At December 31, 2011, Great Plains Energy has provided $666.0 million of credit support for GMO as follows:

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

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

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

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

17.   RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

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

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

18.   DERIVATIVE INSTRUMENTS

Great Plains Energy and KCP&L are exposed to a variety of market risks including interest rates and commodity prices.  Management has established risk management policies and strategies to reduce the potentially adverse effects that the volatility of the markets may have on Great Plains Energy’s and KCP&L’s operating results.  Commodity risk management activities, including the use of certain derivative instruments, are subject to the management, direction and control of an internal risk management committee.  Management’s interest rate risk management strategy uses derivative instruments to adjust Great Plains Energy’s and KCP&L’s liability portfolio to optimize the mix of fixed and floating rate debt within an established range.  In addition, Great Plains Energy and KCP&L use derivative instruments to hedge against future interest rate fluctuations on anticipated debt issuances.  Management maintains commodity price risk management strategies that use derivative instruments to reduce the effects of fluctuations in fuel expense caused by commodity price volatility.  Counterparties to commodity derivatives and interest rate swap agreements expose Great Plains Energy and KCP&L to credit loss in the event of nonperformance.  This credit loss is limited to the cost of replacing these contracts at current

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

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

Interest Rate Risk Management

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

Commodity Risk Management

KCP&L’s risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales.  At December 31, 2011, KCP&L had hedged 66%, 56% and 13%, respectively, of the 2012, 2013 and 2014 projected natural gas usage for retail load and firm MWh sales by utilizing futures contracts.  KCP&L has designated the natural gas hedges as cash flow hedges.  The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge.  To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense.  KCP&L has not recorded any ineffectiveness on natural gas hedges in 2011, 2010 or 2009.

GMO’s risk management policy is to use derivative instruments to mitigate price exposure to natural gas price volatility in the market.  The fair value of the portfolio relates to financial contracts that will settle against actual purchases of natural gas and purchased power.  At December 31, 2011, GMO had financial contracts in place to hedge approximately 45%, 38% and 38%, respectively, of the expected on-peak natural gas and natural gas equivalent purchased power price exposure for 2012, 2013 and 2014.  GMO has designated its natural gas hedges as economic hedges (non-hedging derivatives).  In connection with GMO’s 2005 Missouri electric rate case, it was agreed that the settlement costs of these contracts would be recognized in fuel expense.  The settlement cost is included in GMO’s FAC.  A regulatory asset has been 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.

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

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

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

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.8		5.0
Total Derivatives		$	7.8	$	5.5
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9

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KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

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

Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
Interest rate contracts	$	(5.3	)	Interest charges	$	(16.9	)
Commodity contracts		(0.6	)	Fuel		(0.1	)
Income tax benefit		2.3		Income tax benefit		6.6
Total	$	(3.6	)	Total	$	(10.4	)
2010
Interest rate contracts	$	(27.1	)	Interest charges	$	(10.1	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		10.8		Income tax benefit		4.0
Total	$	(17.2	)	Total	$	(6.6	)

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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
2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(8.7	)
Commodity contracts		(0.6	)	Fuel		(0.1	)
Income tax benefit		0.2		Income tax benefit		3.4
Total	$	(0.4	)	Total	$	(5.4	)
2010
Interest rate contracts	$	-		Interest charges	$	(8.8	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		0.3		Income tax benefit		3.6
Total	$	(0.6	)	Total	$	(5.7	)

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

Great Plains Energy
Derivatives in Regulatory Account Relationship
				Gain (Loss) Reclassified from
				Regulatory Account
	Amount of Gain (Loss)
	Recognized on Regulatory
	Account on Derivatives			Income Statement
	(Effective Portion)			Classification	Amount
	(millions)				(millions)
2011
Commodity contracts	$	(8.3	)	Fuel	$	(3.8	)
Total	$	(8.3	)	Total	$	(3.8	)
2010
Commodity contracts	$	(8.2	)	Fuel	$	(7.2	)
Total	$	(8.2	)	Total	$	(7.2	)

Great Plains Energy’s income statement reflects losses for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $1.1 million for 2011 and $0.2 million for 2010.

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

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

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

19.   FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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

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

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

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

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other
	Great
	Plains
	Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains
included in non-operating income		10.9
Settlements		(11.5	)
Balance December 31, 2011	$	3.1
Total unrealized losses included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at December 31, 2011	$	(0.2	)

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Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other
				Great			Great
				Plains			Plains
	KCP&L			Energy			Energy
	State & Local			Derivative
	Obligations			Instruments			Total
	(millions)
Balance January 1, 2010	$	0.2		$	4.1		$	4.3
Total realized/unrealized losses
included in non-operating income		-			(12.5	)		(12.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			12.1			12.1
Balance December 31, 2010	$	-		$	3.7		$	3.7
Total unrealized gains included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at December 31, 2010	$	-		$	0.1		$	0.1

Investments in Affordable Housing Limited Partnerships

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

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20.   TAXES

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

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

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

Income Tax Expense and Effective Income Tax Rates

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

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

124

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

Deferred Income Taxes

The tax effects of major temporary differences resulting in deferred income tax assets (liabilities) in the consolidated balance sheets are in the following tables.

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

125

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

Tax Credit Carryforwards

At December 31, 2011 and 2010, Great Plains Energy had $118.0 million and $102.6 million, respectively, of federal general business income tax credit carryforwards.  At December 31, 2011 and 2010, KCP&L had $116.8 million and $101.5 million, respectively, of federal general business income tax credit carryforwards.  The carryforwards for both Great Plains Energy and KCP&L relate primarily to Advanced Coal Investment Tax Credits and Wind Production tax credits and expire in the years 2028 to 2031.  Approximately $0.5 million of Great Plains Energy’s credits are related to Low Income Housing credits that were acquired in the GMO acquisition.  Due to federal limitations on the utilization of income tax attributes acquired in the GMO acquisition, management expects these credits to expire unutilized and has provided a valuation allowance against $0.4 million of the federal income tax benefit. 

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

At December 31, 2011 and 2010, Great Plains Energy had $4.7 million and $11.8 million, respectively, of state income tax credit carryforwards.  The state income tax credits relate primarily to the Company’s Missouri affordable housing investment portfolio, and the carryforwards expire in the years 2012 to 2016.  Management expects that a portion of these credits will expire unutilized and has provided a valuation allowance against $0.3 million of the state income tax benefit.

Net Operating Loss Carryforwards

At December 31, 2011 and 2010, Great Plains Energy had $473.1 million and $353.0 million, respectively, of tax benefits related to federal net operating loss (NOL) carryforwards.  Approximately $315.7 million and $317.5 million, at December 31, 2011 and 2010, respectively, are tax benefits related to NOLs that were acquired in the GMO acquisition.  The tax benefits for NOLs are $32.6 million originating in 2003, $152.4 million originating in 2004, $74.1 million originating in 2005, $53.3 million originating in 2006, $1.3 million originating in 2007, $2.4 million originating in 2008, $23.4 million originating in 2009, $11.6 million originating in 2010, and $122.0 million originating in 2011.  The federal NOL carryforwards expire in years 2023 to 2031.

In addition, Great Plains Energy also had deferred tax benefits of $70.6 million and $56.2 million related to state NOLs as of December 31, 2011 and 2010, respectively.  Approximately $49.9 million and $49.4 million at December 31, 2011 and 2010, respectively, were acquired in the GMO acquisition.  Management does not expect to utilize $23.2 million of NOLs in state tax jurisdictions where the Company does not expect to operate in the future.  Therefore, a valuation allowance has been provided against $23.2 million of state tax benefits.

Valuation Allowances

Great Plains Energy is required to assess the ultimate realization of deferred tax assets using a “more likely than not” assessment threshold.  This assessment takes into consideration tax planning strategies within Great Plains Energy’s control.  As a result of this assessment, Great Plains Energy has established a partial valuation allowance for federal and state tax NOL carryforwards, and tax credit carryforwards.

126

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

Uncertain Tax Positions

At December 31, 2011 and 2010, Great Plains Energy had $24.0 million and $42.0 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $11.8 million and $17.3 million at December 31, 2011 and 2010, respectively, are expected to impact the effective tax rate if recognized.  The $18.0 million decrease in unrecognized tax benefits in 2011 is primarily due to a decrease of $18.4 million of unrecognized tax benefits related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years.  The $18.4 million tax benefit recognized related to the 2006-2008 audit was offset by an increase of $16.4 million in deferred income tax liabilities since a significant portion of the unrecognized tax benefits were related to temporary tax differences, which resulted in an increase to net income of $2.0 million.

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

At December 31, 2011 and 2010, KCP&L had $8.7 million and $19.1 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $0.2 million and $0.3 million at December 31, 2011 and 2010, respectively, are expected to impact the effective tax rate if recognized.  The $10.4 million decrease in unrecognized tax benefits in 2011 is primarily due to a decrease of $12.1 million related to the settlements of the IRS audit for Great Plains Energy’s 2006-2008 tax years.  The tax benefit recognized related to the 2006-2008 audit was offset by an increase of deferred income tax liabilities which resulted in an insignificant impact to net income.  At December 31, 2009, KCP&L had $20.9 million of liabilities related to unrecognized tax benefits of which $0.4 million was expected to impact the effective rate if recognized.

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

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

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

127

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

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

Great Plains Energy files a consolidated federal income tax return as well as unitary and combined income tax returns in several state jurisdictions with Kansas and Missouri being the most significant.  The Company also files separate company returns in Canada and certain other states.

21.   SEGMENTS AND RELATED INFORMATION

Great Plains Energy has one reportable segment based on its method of internal reporting, which segregates reportable segments based on products and services, management responsibility and regulation.  The one reportable business segment is electric utility, consisting of KCP&L and GMO’s regulated utility operations.  Other includes GMO activity other than its regulated utility operations, unallocated corporate charges, consolidating entries and intercompany eliminations.  Intercompany eliminations include insignificant amounts of intercompany financing-related activities.  The summary of significant accounting policies applies to the reportable segment.  Segment performance is evaluated based on net income attributable to Great Plains Energy.

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

	Electric						Great Plains
2011	Utility			Other			Energy
	(millions)
Operating revenues	$	2,318.0		$	-		$	2,318.0
Depreciation and amortization		(273.1	)		-			(273.1	)
Interest charges		(176.9	)		(41.5	)		(218.4	)
Income tax (expense) benefit		(109.3	)		24.5			(84.8	)
Net income (loss) attributable to Great Plains Energy		199.9			(25.5	)		174.4

	Electric						Great Plains
2010	Utility			Other			Energy
	(millions)
Operating revenues	$	2,255.5		$	-		$	2,255.5
Depreciation and amortization		(331.6	)		-			(331.6	)
Interest charges		(143.1	)		(41.7	)		(184.8	)
Income tax (expense) benefit		(123.3	)		24.3			(99.0	)
Net income (loss) attributable to Great Plains Energy		235.3			(23.6	)		211.7

128

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

	Electric							Great Plains
	Utility		Other		Eliminations			Energy
2011	(millions)
Assets	$	9,483.4	$	51.9	$	(417.3	)	$	9,118.0
Capital expenditures		456.6		-		-			456.6
2010
Assets	$	9,152.7	$	66.3	$	(400.8	)	$	8,818.2
Capital expenditures		618.1		-		-			618.1
2009
Assets	$	8,765.3	$	152.5	$	(435.0	)	$	8,482.8
Capital expenditures		841.3		-		-			841.3

22.   DISCONTINUED OPERATIONS

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

23.   JOINTLY-OWNED ELECTRIC UTILITY PLANTS

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

Great Plains Energy
	Wolf Creek			La Cygne			Iatan No. 1			Iatan No. 2			Iatan			Jeffrey
	Unit			Units			Unit			Unit			Common			Energy Center
	(millions, except MW amounts)
Great Plains Energy's share		47	%		50	%		88	%		73	%		79	%		8	%
Utility plant in service	$	1,473.8		$	493.6		$	667.9		$	1,293.0		$	364.4		$	158.4
Accumulated depreciation		776.3			303.1			252.8			270.0			30.4			75.5
Nuclear fuel, net		76.6			-			-			-			-			-
Construction work in progress		39.4			79.1			6.5			5.9			30.2			5.3
2012 accredited capacity-MWs		547			711			620			641		NA				174

129

KCP&L
	Wolf Creek			La Cygne			Iatan No. 1			Iatan No. 2			Iatan
	Unit			Units			Unit			Unit			Common
	(millions, except MW amounts)
KCP&L's share		47	%		50	%		70	%		55	%		61	%
Utility plant in service	$	1,473.8		$	493.6		$	542.3		$	985.1		$	287.5
Accumulated depreciation		776.3			303.1			207.9			261.3			26.0
Nuclear fuel, net		76.6			-			-			-			-
Construction work in progress		39.4			79.1			2.6			4.4			9.3
2012 accredited capacity-MWs		547			711			493			482		NA

Each owner must fund its own portion of the plant's operating expenses and capital expenditures.  KCP&L’s and GMO’s share of direct expenses are included in the appropriate operating expense classifications in Great Plains Energy’s and KCP&L’s financial statements.

24.   QUARTERLY OPERATING RESULTS (UNAUDITED)

	Quarter
Great Plains Energy	1st		2nd		3rd		4th
2011	(millions, except per share amounts)
Operating revenue	$	492.9	$	565.1	$	773.7	$	486.3
Operating income		41.2		115.6		262.7		60.3
Net income		2.3		43.4		126.6		1.9
Net income attributable to Great Plains Energy		2.4		43.4		126.5		2.1
Basic earnings per common share		0.02		0.32		0.93		0.01
Diluted earnings per common share		0.01		0.31		0.91		0.01
2010
Operating revenue	$	506.9	$	552.0	$	728.8	$	467.8
Operating income		62.0		134.9		243.8		31.6
Net income (loss)		20.3		64.4		132.0		(4.8	)
Net income (loss) attributable to Great Plains Energy		20.3		64.3		132.0		(4.9	)
Basic earnings (loss) per common share		0.15		0.47		0.97		(0.04	)
Diluted earnings (loss) per common share		0.15		0.47		0.96		(0.04	)

	Quarter
KCP&L	1st		2nd		3rd		4th
2011	(millions)
Operating revenue	$	330.8	$	383.4	$	506.3	$	337.8
Operating income		26.5		77.8		169.2		47.7
Net income		4.0		33.4		85.4		12.7
2010
Operating revenue	$	335.6	$	372.6	$	486.5	$	322.4
Operating income		40.5		84.7		163.6		22.6
Net income		19.2		48.2		92.6		3.2

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

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Great Plains Energy recorded an $11.2 million pre-tax impairment loss related to its investments in affordable housing limited partnerships.

131

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Great Plains Energy Incorporated

Kansas City, Missouri

We have audited the accompanying consolidated balance sheets of Great Plains Energy Incorporated and subsidiaries (the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, common shareholders' equity and noncontrolling interest, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Great Plains Energy Incorporated and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2012 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/DELOITTE & TOUCHE LLP

Kansas City, Missouri

February 28, 2012

132

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Kansas City Power & Light Company

Kansas City, Missouri

We have audited the accompanying consolidated balance sheets of Kansas City Power & Light Company and subsidiaries (the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, common shareholder’s equity and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Kansas City Power & Light Company and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2012 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/DELOITTE & TOUCHE LLP

Kansas City, Missouri

February 28, 2012

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ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.  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 December 31, 2011, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.  Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) for Great Plains Energy.  Under the supervision and with the participation of Great Plains Energy’s chief executive officer and chief financial officer, management evaluated the effectiveness of Great Plains Energy’s internal control over financial reporting as of December 31, 2011.  Management used for this evaluation the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission.

Management has concluded that, as of December 31, 2011, Great Plains Energy’s internal control over financial reporting is effective based on the criteria set forth in the COSO framework.  Deloitte & Touche LLP, the independent registered public accounting firm that audited the financial statements included in this annual report on Form 10-K, has issued its attestation report on Great Plains Energy’s internal control over financial reporting, which is included below.

134

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Great Plains Energy Incorporated

Kansas City, Missouri

We have audited the internal control over financial reporting of Great Plains Energy Incorporated and subsidiaries (the "Company") as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2011, of the Company and our report dated February 28, 2012 expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/DELOITTE & TOUCHE LLP

Kansas City, Missouri

February 28, 2012

135

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 December 31, 2011, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.  Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) for KCP&L.  Under the supervision and with the participation of KCP&L’s chief executive officer and chief financial officer, management evaluated the effectiveness of KCP&L’s internal control over financial reporting as of December 31, 2011.  Management used for this evaluation the framework in Internal Control – Integrated Framework issued by the COSO of the Treadway Commission.

Management has concluded that, as of December 31, 2011, KCP&L’s internal control over financial reporting is effective based on the criteria set forth in the COSO framework.  Deloitte & Touche LLP, the independent registered public accounting firm that audited the financial statements included in this annual report on Form 10-K, has issued its attestation report on KCP&L’s internal control over financial reporting, which is included below.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Kansas City Power & Light Company

Kansas City, Missouri

We have audited the internal control over financial reporting of Kansas City Power & Light Company and subsidiaries (the "Company") as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2011, of the Company and our report dated February 28, 2012 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/DELOITTE & TOUCHE LLP

Kansas City, Missouri

February 28, 2012

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ITEM 9B.  OTHER INFORMATION

None.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Great Plains Energy Directors

The information required by this item is incorporated by reference from the Great Plains Energy 2012 Proxy Statement (Proxy Statement), which will be filed with the SEC no later than April 30, 2012:

·   Information regarding the directors of Great Plains Energy required by this item is contained in the Proxy Statement section titled “Election of Directors.”

·   Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934 required by this item is contained in the Proxy Statement section titled “Security Ownership of Certain Beneficial Owners, Directors and Officers - Section 16(a) Beneficial Ownership Reporting Compliance.”

·   Information regarding the Audit Committee of Great Plains Energy required by this item is contained in the Proxy Statement section titled “Corporate Governance – Committees of the Board.”

Great Plains Energy and KCP&L Executive Officers

Information required by this item regarding the executive officers of Great Plains Energy and KCP&L is contained in this report in the Part I, Item 1 section titled “Executive Officers.”

Great Plains Energy and KCP&L Code of Ethical Business Conduct

The Company has adopted a Code of Ethical Business Conduct (Code), which applies to all directors, officers and employees of Great Plains Energy, KCP&L and their subsidiaries.  The Code is posted on the corporate governance page of the Internet websites at www.greatplainsenergy.com and www.kcpl.com.  A copy of the Code is available, without charge, upon written request to Corporate Secretary, Great Plains Energy Incorporated, 1200 Main St., Kansas City, Missouri 64105.  Great Plains Energy and KCP&L intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or a waiver from, a provision of the Code that applies to the principal executive officer, principal financial officer, principal accounting officer or controller of those companies by posting such information on the corporate governance page of the Internet websites.

Other KCP&L Information

The other information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).

ITEM 11.  EXECUTIVE COMPENSATION

Great Plains Energy

The information required by this item contained in the sections titled “Executive Compensation,” “Director Compensation,” “Compensation Discussion and Analysis”, “Compensation Committee Report” and “Director Independence – Compensation Committee Interlocks and Insider Participation” of the Proxy Statement is incorporated by reference.

KCP&L

The other information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).

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ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Great Plains Energy

The information required by this item regarding security ownership of the directors and executive officers of Great Plains Energy contained in the section titled “Security Ownership of Certain Beneficial Owners, Directors and Officers” of the Proxy Statement is incorporated by reference.

KCP&L

The information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).

Equity Compensation Plans

Great Plains Energy’s Long-Term Incentive Plan is an equity compensation plan approved by its 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.

KCP&L does not have an equity compensation plan; however, KCP&L officers and certain employees participate in Great Plains Energy’s Long-Term Incentive Plan.

The following table provides information, as of December 31, 2011, regarding the number of common shares to be issued upon exercise of outstanding options, warrants and rights, their weighted average exercise price, and the number of shares of common stock remaining available for future issuance.  The table excludes shares issued or issuable under Great Plains Energy’s defined contribution savings plans.

								Number of securities
								remaining available
		Number of securities						for future issuance
		to be issued upon			Weighted-average			under equity
		exercise of			exercise price of			compensation plans
		outstanding options,			outstanding options,			(excluding securities
		warrants and rights			warrants and rights			reflected in column (a))
Plan Category		(a)			(b)			(c)
Equity compensation plans approved by security holders
Great Plains Energy Long-Term Incentive Plan			505,626	(1)	$	25.91	(2)		5,528,707
Equity compensation plans not approved by security holders			-			-			-
Total			505,626	(1)	$	25.91	(2)		5,528,707
(1)	Includes 442,042 performance shares at target performance levels, options for 9,353 shares of Great Plains Energy common
	stock and director deferred share units for 54,231 shares of Great Plains Energy common stock outstanding at December 31, 2011.
(2)	The 442,042 performance shares and director deferred share units for 54,231 shares of Great Plains Energy common stock have
	no exercise price and therefore are not reflected in the weighted average exercise price.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Great Plains Energy

The information required by this item contained in the section titled “Director Independence” and “Related Party Transactions” of the Proxy Statement is incorporated by reference.

139

KCP&L

The information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

Great Plains Energy

The information required by this item regarding the independent auditors of Great Plains Energy and its subsidiaries contained in the section titled “Ratification of Appointment of Independent Auditors” of the Proxy Statement is incorporated by reference.

KCP&L

The Audit Committee of the Great Plains Energy Board functions as the Audit Committee of KCP&L.  The following table sets forth the aggregate fees billed by Deloitte & Touche LLP for audit services rendered in connection with the consolidated financial statements and reports for 2011 and 2010 and for other services rendered during 2011 and 2010 on behalf of KCP&L, as well as all out-of-pocket costs incurred in connection with these services:

Fee Category	2011		2010
Audit Fees	$	1,125,215	$	1,098,722
Audit-Related Fees		70,750		104,169
Tax Fees		231,643		112,058
All Other Fees		91,975		-
Total Fees	$	1,519,583	$	1,314,949

Audit Fees:  Consists of fees billed for professional services rendered for the audits of the annual consolidated financial statements of KCP&L and reviews of the interim condensed consolidated financial statements included in quarterly reports.  Audit fees also include: services provided by Deloitte & Touche LLP in connection with statutory and regulatory filings or engagements; audit reports on audits of the effectiveness of internal control over financial reporting and other attest services, except those not required by statute or regulation; services related to filings with the SEC, including comfort letters, consents and assistance with and review of documents filed with the SEC; and accounting research in support of the audit.

Audit-Related Fees:  Consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of consolidated financial statements of KCP&L and are not reported under “Audit Fees”.  These services include consultation concerning financial accounting and reporting standards.

Tax Fees:  Consists of fees billed for tax compliance and related support of tax returns and other tax services, including assistance with tax audits, and tax research and planning.

All Other Fees:  Consists of fees for all other services other than those described above.  In 2011, these fees included a pension plan review.

Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditors

The Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accounting firm to KCP&L.  These services may include audit services, audit-related services, tax services and other services.  The Audit Committee has adopted for KCP&L policies and procedures for the pre-approval of services provided by the independent registered public accounting firm.  Under these policies and procedures, the Audit Committee may pre-approve certain types of services, up to aggregate fee levels established by the Audit Committee.  Any proposed service within a pre-approved type of service that would cause the applicable fee level to be exceeded cannot be provided unless the Audit Committee either amends the applicable fee level or specifically approves the proposed service.  Pre-approval is generally provided for up to one year,

140

unless the Audit Committee specifically provides for a different period.  The Audit Committee receives reports at each regular meeting regarding the pre-approved services performed by the independent auditor.  The Chairman of the Audit Committee may between meetings pre-approve audit and non-audit services provided by the independent auditor, and report such pre-approval at the next Audit Committee meeting.

PART IV

ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements
Great Plains Energy		Page No.
a.	Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009	56
b.	Consolidated Balance Sheets - December 31, 2011 and 2010	57
c.	Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009	59
d.	Consolidated Statements of Common Shareholders’ Equity and Noncontrolling Interest for the years ended December 31, 2011, 2010 and 2009	60
e.	Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009	61
f.	Notes to Consolidated Financial Statements	68
g.	Report of Independent Registered Public Accounting Firm	132
KCP&L
h.	Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009	62
i.	Consolidated Balance Sheets - December 31, 2011 and 2010	63
j.	Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009	65
k.	Consolidated Statements of Common Shareholder’s Equity for the years ended December 31, 2011, 2010 and 2009	66
l.	Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009	67
m.	Notes to Consolidated Financial Statements	68
n.	Report of Independent Registered Public Accounting Firm	133
Financial Statement Schedules
	Great Plains Energy
a.	Schedule I – Parent Company Financial Statements	157

141

b.	Schedule II – Valuation and Qualifying Accounts and Reserves	160
	KCP&L
c.	Schedule II – Valuation and Qualifying Accounts and Reserves	161

Exhibits

Exhibit Number		Description of Document	Registrant
2.1	*	Agreement and Plan of Merger among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp., and Black Hills Corporation dated as of February 6, 2007 (Exhibit 2.1 to Form 8-K filed on February 8, 2007).	Great Plains Energy
2.2	*	Mutual Notice of Extension among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp., and Black Hills Corporation dated as of January 31, 2008 (Exhibit 2.1.2 to Form 10-K for the year ended December 31, 2007).	Great Plains Energy
2.3	*	Mutual Notice of Extension among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp., and Black Hills Corporation dated as of April 29, 2008 (Exhibit 10.1 to Form 8-K filed on April 30, 2008).	Great Plains Energy
3.1	*	Articles of Incorporation of Great Plains Energy Incorporated, as amended effective May 7, 2009 (Exhibit 3.1.1 to Form 10-Q for the quarter ended March 31, 2009).	Great Plains Energy
3.2	*	By-laws of Great Plains Energy Incorporated, as amended May 4, 2010 (Exhibit 3.1 to Form 8-K filed on May 5, 2010).	Great Plains Energy
3.3	*	Restated Articles of Consolidation of Kansas City Power & Light Company, restated as of October 26, 2010. (Exhibit 3.3 to Form 10-K for the year ended December 31, 2010)	KCP&L
3.4	*	By-laws of Kansas City Power & Light Company, as amended April 1, 2008 (Exhibit 3.2 to Form 8-K filed on April 7, 2008).	KCP&L
4.1	*	Indenture, dated June 1, 2004, between Great Plains Energy Incorporated and BNY Midwest Trust Company, as Trustee (Exhibit 4.4 to Form 8-A/A filed on June 14, 2004).	Great Plains Energy
4.2	*	First Supplemental Indenture, dated June 14, 2004, between Great Plains Energy Incorporated and BNY Midwest Trust Company, as Trustee (Exhibit 4.5 to Form 8-A/A filed on June 14, 2004).	Great Plains Energy
4.3	*	Second Supplemental Indenture dated as of September 25, 2007, between Great Plains Energy Incorporated and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on September 26, 2007).	Great Plains Energy

142

4.4	*	Third Supplemental Indenture dated as of August 13, 2010 between Great Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on August 13, 2010).	Great Plains Energy
4.5	*	Fourth Supplemental Indenture dated as of May 19, 2011 between Great Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as Trustee (Exhibit 4.1 to Form 8-K filed on May 19, 2011).	Great Plains Energy
4.6	*	Subordinated Indenture dated as of May 18, 2009 between Great Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on May 19, 2009).	Great Plains Energy
4.7	*	Supplemental Indenture No. 1 dated as of May 18, 2009 between Great Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.2 to Form 8-K filed on May 19, 2009).	Great Plains Energy
4.8	*	Purchase Contract and Pledge Agreement dated as of May 18, 2009 among Great Plains Energy Incorporated, The Bank of New York Mellon Trust Company, N.A., as purchase contract agent and The Bank of New York Mellon Trust Company, N.A., as collateral agent, custodial agent and securities intermediary (Exhibit 4.3 to Form 8-K filed on May 19, 2009).	Great Plains Energy
4.9	*	Indenture, dated as of August 24, 2001, between Aquila, Inc. and BankOne Trust Company, N.A., as Trustee (Exhibit 4(d) to Registration Statement on Form S-3 (File No. 333-68400) filed by Aquila, Inc. on August 27, 2001).	Great Plains Energy
4.10	*	Second Supplemental Indenture, dated as of July 3, 2002, between Aquila, Inc. and BankOne Trust Company, N.A., as Trustee related to 11.875% Senior Notes due July 1, 2012 (Exhibit 4(c) to Form S-4 (File No. 333-100204) filed by Aquila, Inc. on September 30, 2002).	Great Plains Energy
4.11	*	General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, n.a. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4-bb to Form 10-K for the year ended December 31, 1986).	Great Plains Energy   KCP&L
4.12	*	Fifth Supplemental Indenture dated as of September 15, 1992, to Indenture dated as of December 1, 1986 (Exhibit 4-a to Form 10-Q for the quarter ended September 30, 1992).	Great Plains Energy   KCP&L
4.13	*	Seventh Supplemental Indenture dated as of October 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4-a to Form 10-Q for the quarter ended September 30, 1993).	Great Plains Energy   KCP&L

143

4.14	*	Eighth Supplemental Indenture dated as of December 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4 to Registration Statement, Registration No. 33-51799).	Great Plains Energy   KCP&L
4.15	*	Eleventh Supplemental Indenture dated as of August 15, 2005, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2005).	Great Plains Energy   KCP&L
4.16	*	Twelfth Supplemental Indenture, dated as of March 1, 2009, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.2 to Form 8-K filed on March 24, 2009).	Great Plains Energy   KCP&L
4.17	*	Thirteenth Supplemental Indenture, dated as of March 1, 2009, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.3 to Form 8-K filed on March 24, 2009).	Great Plains Energy   KCP&L
4.18	*	Fourteenth Supplemental Indenture, dated as of March 1, 2009, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.4 to Form 8-K filed on March 24, 2009).	Great Plains Energy   KCP&L
4.19	*	Fifteenth Supplemental Indenture, dated as of June 30, 2011, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.1 to Form 10-Q for the quarter ended June 30, 2011).	Great Plains Energy   KCP&L
4.20	*	Indenture dated as of December 1, 2000, between Kansas City Power & Light Company and The Bank of New York (Exhibit 4-a to Form 8-K filed on December 18, 2000).	Great Plains Energy   KCP&L
4.21	*	Term sheet for $150 million aggregate principal amount of 6.50% Senior Notes due November 15, 2011 (Exhibit 4-b to Form 8-K filed on November 19, 2001).	Great Plains Energy   KCP&L
4.22	*	Indenture dated March 1, 2002 between The Bank of New York and Kansas City Power & Light Company (Exhibit 4.1.b. to Form 10-Q for the quarter ended March 31, 2002).	Great Plains Energy   KCP&L
4.23	*	Supplemental Indenture No. 1 dated as of November 15, 2005, to Indenture dated March 1, 2002 between The Bank of New York and Kansas City Power & Light Company (Exhibit 4.2.j to Form 10-K for the year ended December 31, 2005).	Great Plains Energy   KCP&L

144

4.24	*	Indenture dated as of May 1, 2007, between Kansas City Power & Light Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on June 4, 2007).	Great Plains Energy   KCP&L
4.25	*	Supplemental Indenture No. 1 dated as of June 4, 2007 between Kansas City Power & Light Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.2 to Form 8-K filed on June 4, 2007).	Great Plains Energy   KCP&L
4.26	*	Supplemental Indenture No. 2 dated as of March 11, 2008, between Kansas City Power & Light Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.2 to Form 8-K filed on March 11, 2008).	Great Plains Energy   KCP&L
4.27	*+	Supplemental Indenture No. 3 dated as of September 20, 2011 between Kansas City Power & Light Company and The Bank of New York Mellon Trust Company, N.A., Trustee (Exhibit 4.1 to Form 8-K filed on September 20, 2011).	Great Plains Energy KCP&L
10.1	*+	Amended Long-Term Incentive Plan, effective as of May 7, 2002 (Exhibit 10.1.a to Form 10-K for the year ended December 31, 2002).	Great Plains Energy   KCP&L
10.2	*+	Great Plains Energy Incorporated Long-Term Incentive Plan as amended May 1, 2007 (Exhibit 10.1 to Form 8-K filed on May 4, 2007).	Great Plains Energy   KCP&L
10.3	*+	Great Plains Energy Incorporated Amended Long-Term Incentive Plan adopted as of May 3, 2011 (Exhibit 10.1 to Form 8-K filed on May 6, 2011).	Great Plains Energy KCP&L
10.4	*+	Great Plains Energy Incorporated Long-Term Incentive Plan Awards Standards and Performance Criteria Effective as of May 6, 2008 (Exhibit 10.1.25 to Form 10-Q for the quarter ended June 30, 2008).	Great Plains Energy KCP&L
10.5	*+	Great Plains Energy Incorporated Long-Term Incentive Plan awards Standards and Performance Criteria effective as of January 1, 2009 (Exhibit 10.1.6 to Form 10-Q for the quarter ended June 30, 2009).	Great Plains Energy KCP&L
10.6	*+	Great Plains Energy Incorporated Long-Term Incentive Plan Awards Standards and Performance Criteria Effective as of January 1, 2010 (Exhibit 10.1.3 to Form 10-Q for the quarter ended March 31, 2010).	Great Plains Energy KCP&L
10.7	*+	Great Plains Energy Incorporated Long-Term Incentive Plan Awards Standards and Performance Criteria Effective as of January 1, 2011 (Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 2011).	Great Plains Energy KCP&L
10.8	*+	Form of Restricted Stock Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1.6 to Form 10-K for the year ended December 31, 2006).	Great Plains Energy KCP&L

145

10.9	*+	Form of 2008 Restricted Stock Agreement (Exhibit 10.1.20 to Form 10-Q for the quarter ended June 30, 2008).	Great Plains Energy KCP&L
10.10	*+	Form of Restricted Stock Agreement between Great Plains Energy Incorporated and grantee dated May 5, 2009 (Exhibit 10.1.5 to Form 10-Q for the quarter ended June 30, 2009).	Great Plains Energy KCP&L
10.11	*+	Form of Performance Share Agreement between Great Plains Energy Incorporated and grantee dated May 5, 2009 (Exhibit 10.1.4 to Form 10-Q for the quarter ended March 31, 2009).	Great Plains Energy KCP&L
10.12	*+	Form of 2001 and 2002 Nonqualified Stock Option Agreement (Exhibit 10.1.13 to Form 10-K for the year ended December 31, 2009).	Great Plains Energy KCP&L
10.13	*+	Form of 2003 Nonqualified Stock Option Agreement (Exhibit 10.1.14 to Form 10-K for the year ended December 31, 2009).	Great Plains Energy KCP&L
10.14	*+	Form of Amendment to 2003 Stock Option Grants (Exhibit 10.1.9 to Form 10-Q for the quarter ended September 30, 2007).	Great Plains Energy KCP&L
10.15	*+	Form of 2010 three-year Performance Share Agreement (Exhibit 10.1.1 to Form 10-Q for the quarter ended March 31, 2010).	Great Plains Energy KCP&L
10.16	*+	Form of 2010 Restricted Stock Agreement (Exhibit 10.1.2 to Form 10-Q for the quarter ended March 31, 2010).	Great Plains Energy KCP&L
10.17	*+	Form of 2011 three-year Performance Share Agreement (Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2011).	Great Plains Energy KCP&L
10.18	*+	Form of 2011 Restricted Stock Agreement (Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2011).	Great Plains Energy KCP&L
10.19	*+	Aquila, Inc. 2002 Omnibus Incentive Compensation Plan (Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2002, filed by Aquila, Inc.).	Great Plains Energy
10.20	*+	Great Plains Energy Incorporated, Kansas City Power & Light Company and KCP&L Greater Missouri Operations Company Annual Incentive Plan amended effective as of January 1, 2011 (Exhibit 10.4 to Form 10-Q for the quarter ended March 31, 2011).	Great Plains Energy KCP&L
10.21	*+	Form of Indemnification Agreement with each officer and director (Exhibit 10-f to Form 10-K for year ended December 31, 1995).	Great Plains Energy KCP&L
10.22	*+	Form of Conforming Amendment to Indemnification Agreement with each officer and director (Exhibit 10.1.a to Form 10-Q for the quarter ended March 31, 2003).	Great Plains Energy KCP&L
10.23	*+	Form of Indemnification Agreement with each director and officer (Exhibit 10.1 to Form 8-K filed on December 8, 2008).	Great Plains Energy KCP&L

146

10.24	*+	Form of Indemnification Agreement with officers and directors (Exhibit 10.1.p to Form 10-K for the year ended December 31, 2005).	Great Plains Energy KCP&L
10.25	*+	Form of Change in Control Severance Agreement with Michael J. Chesser (Exhibit 10.1.a to Form 10-Q for the quarter ended September 30, 2006).	Great Plains Energy KCP&L
10.26	*+	Form of Change in Control Severance Agreement with William H. Downey (Exhibit 10.1.b to Form 10-Q for the quarter ended September 30, 2006).	Great Plains Energy KCP&L
10.27	*+	Form of Change in Control Severance Agreement with other executive officers of Great Plains Energy Incorporated and Kansas City Power & Light Company (Exhibit 10.1.e to Form 10-Q for the quarter ended September 30, 2006).	Great Plains Energy KCP&L
10.28	*+	Great Plains Energy Incorporated Supplemental Executive Retirement Plan (As Amended and Restated for I.R.C. §409A) (Exhibit 10.1.10 to Form 10-Q for the quarter ended September 30, 2007).	Great Plains Energy KCP&L
10.29	*+	Great Plains Energy Incorporated Supplemental Executive Retirement Plan (As Amended and Restated for I.R.C. §409A), as amended February 10, 2009 (Exhibit 10.1.29 to Form 10-K for the year ended December 31, 2008).	Great Plains Energy KCP&L
10.30	*+	Great Plains Energy Incorporated Supplemental Executive Retirement Plan (As Amended and Restated for I.R.C. §409A), as amended December 8, 2009 (Exhibit 10.1.27 to Form 10-K for the year ended December 31, 2009).	Great Plains Energy KCP&L
10.31	*+	Great Plains Energy Incorporated Nonqualified Deferred Compensation Plan (As Amended and Restated for I.R.C. §409A) (Exhibit 10.1.11 to Form 10-Q for the quarter ended September 30, 2007).	Great Plains Energy KCP&L
10.32	*+	Great Plains Energy Incorporated Nonqualified Deferred Compensation Plan (As Amended and Restated for I.R.C. §409A), amended effective January 1, 2010 (Exhibit 10.1.5 to Form 10-Q for the quarter ended March 31, 2010).	Great Plains Energy KCP&L
10.33	*+	Letter regarding enhanced supplemental retirement and severance benefit for William H. Downey, dated August 5, 2008 (Exhibit 10.1.23 to Form 10-Q for the quarter ended June 30, 2008).	Great Plains Energy KCP&L
10.34	*+	Employment offer letters to Michael J. Chesser dated September 10 and September 16, 2003 (Exhibit 10.1.35 to Form 10-K for the year ended December 31, 2008).	Great Plains Energy KCP&L

147

10.35	*+	Bonus Agreement dated as of May 5, 2009 between Great Plains Energy Incorporated and Michael J. Chesser (Exhibit 10.1.10 to Form 10-Q for the quarter ended June 30, 2009).	Great Plains Energy KCP&L
10.36	*+	Discretionary Bonus Agreement dated as of May 5, 2009 between Great Plains Energy Incorporated and Terry Bassham (Exhibit 10.1.11 to Form 10-Q for the quarter ended June 30, 2009).	Great Plains Energy KCP&L
10.37	*+	Retirement and Consulting Agreement among Great Plains Energy Incorporated, Kansas City Power & Light Company, KCP&L Greater Missouri Operations Company and John R. Marshall (Exhibit 10.1 to Form 8-K filed on May 5, 2010).	Great Plains Energy KCP&L
10.38	*+	Consulting Services Assignment and Assumption Agreement between John R. Marshall and Coastal Partners Inc. (Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2010).	Great Plains Energy KCP&L
10.39	*+	Retirement and Consulting Agreement among Great Plains Energy Incorporated, Kansas City Power & Light Company, KCP&L Greater Missouri Operations Company and Barbara B. Curry (Exhibit 10.1 to Form 8-K filed on May 5, 2010).	Great Plains Energy KCP&L
10.40	*+	Retirement and Consulting Agreement dated May 20, 2011 between Great Plains Energy Incorporated, Kansas City Power & Light Company, KCP&L Greater Missouri Operations Company and William H. Downey (Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2011).	Great Plains Energy KCP&L
10.41	*+	Agreement among Great Plains Energy Incorporated, Kansas City Power & Light Company, KCP&L Greater Missouri Operations Company and William G. Riggins dated as of October 26, 2010. (Exhibit 10.45 to Form 10-K for the year ended December 31, 2010)	Great Plains Energy KCP&L
10.42	*	Asset Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated, and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.1 to Form 8-K filed on February 8, 2007).	Great Plains Energy
10.43	*	Partnership Interests Purchase Agreement by and among Aquila, Inc., Aquila Colorado, LLC, Black Hills Corporation, Great Plains Energy Incorporated, and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.2 to Form 8-K filed on February 8, 2007).	Great Plains Energy
10.44	*	Letter Agreement dated as of June 29, 2007 to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated, and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.1.1 to Form 10-Q for the quarter ended June 30, 2007).	Great Plains Energy

148

10.45	*	Letter Agreement dated as of August 31, 2007, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.4 to Form 10-Q for the quarter ended September 30, 2007).	Great Plains Energy
10.46	*	Letter Agreement dated as of September 28, 2007, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.5 to Form 10-Q for the quarter ended September 30, 2007).	Great Plains Energy
10.47	*	Letter Agreement dated as of October 3, 2007, to Agreement and Plan of Merger, Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.6 to Form 10-Q for the quarter ended September 30, 2007).	Great Plains Energy
10.48	*	Letter Agreement dated as of November 30, 2007, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.40 to Form 10-K for the year ended December 31, 2007).	Great Plains Energy
10.49	*	Letter Agreement dated as of January 30, 2008, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.41 to Form 10-K for the year ended December 31, 2007).	Great Plains Energy
10.50	*	Letter Agreement dated as of February 28, 2008, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.3 to Form 10-Q for the quarter ended March 31, 2008).	Great Plains Energy
10.51	*	Letter Agreement dated as of March 28, 2008, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.4 to Form 10-Q for the quarter ended March 31, 2008).	Great Plains Energy
10.52	*	Letter Agreement dated as of April 28, 2008, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.5 to Form 10-Q for the quarter ended March 31, 2008).	Great Plains Energy

149

10.53	*	Letter Agreement dated as of May 29, 2008, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.5 to Form 10-Q for the quarter ended June 30, 2008).	Great Plains Energy
10.54	*	Letter Agreement dated as of June 19, 2008, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.6 to Form 10-Q for the quarter ended June 30, 2008).	Great Plains Energy
10.55	*	Letter Agreement dated as of June 27, 2008, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp. (Exhibit 10.1.7 to Form 10-Q for the quarter ended June 30, 2008).	Great Plains Energy
10.56	*	Joint Motion and Settlement Agreement dated as of February 26, 2008, among Great Plains Energy Incorporated, Kansas City Power & Light Company, the Kansas Corporation Commission Staff, the Citizens’ Utility Ratepayers Board, Aquila, Inc. d/b/a Aquila Networks, Black Hills Corporation, and Black Hills/Kansas Gas Utility Company, LLC (Exhibit 10.1.7 to Form 10-Q for the quarter ended March 31, 2008).	Great Plains Energy KCP&L
10.57	*	Purchase Agreement, dated as of April 1, 2008, by and among Custom Energy Holdings, L.L.C., Direct Energy Services, LLC and Great Plains Energy Incorporated (Exhibit 10.1 to Form 8-K filed on April 2, 2008).	Great Plains Energy
10.58	*	Credit Agreement dated as of August 9, 2010 among Great Plains Energy Incorporated, Certain Lenders, Bank of America, N.A., as Administrative Agent, and Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, Barclays Bank PLC and U.S. Bank National Association, 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 (Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2010).	Great Plains Energy
10.59		First Amendment to Credit Agreement dated as of December 9, 2011 among Great Plains Energy Incorporated, Certain Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, Bank of America, N.A., as Administrative Agent, Barclays Bank PLC and U.S. Bank National Association, 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.	Great Plains Energy

150

10.60	*	Credit Agreement dated as of August 9, 2010 among Kansas City Power & Light Company, Certain Lenders, 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 (Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2010).	Great Plains Energy KCP&L
10.61		First Amendment to Credit Agreement dated as of December 9, 2011 among Kansas City Power & Light Company, Certain Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, Bank of America, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A. and The Bank of Nova Scotia, 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.	Great Plains Energy KCP&L
10.62	*	Credit Agreement dated as of August 9, 2010 among KCP&L Greater Missouri Operations Company, Certain Lenders, 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 (Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2010).	Great Plains Energy
10.63		First Amendment to Credit Agreement dated as of December 9, 2011 among KCP&L Greater Missouri Operations Company, Great Plains Energy Incorporated, Certain Lenders, 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.	Great Plains Energy
10.64	*	Guaranty dated as of July 15, 2008, issued by Great Plains Energy Incorporated in favor of Union Bank of California, N.A., as successor trustee, and the holders of the Aquila, Inc., 7.75% Senior Notes due June 15, 2011 (Exhibit 10.4 to Form 8-K filed on July 18, 2008).	Great Plains Energy
10.65	*	Guaranty dated as of July 15, 2008, issued by Great Plains Energy Incorporated in favor of Union Bank of California, N.A., as successor trustee, and the holders of the Aquila, Inc., 7.95% Senior Notes due February 1, 2011 (Exhibit 10.5 to Form 8-K filed on July 18, 2008).	Great Plains Energy

151

10.66	*	Guaranty dated as of July 15, 2008, issued by Great Plains Energy Incorporated in favor of Union Bank of California, N.A., as successor trustee, and the holders of the Aquila, Inc., 8.27% Senior Notes due November 15, 2021 (Exhibit 10.6 to Form 8-K filed on July 18, 2008).	Great Plains Energy
10.67	*	Sales Agency Financing Agreement dated August 14, 2008 between Great Plains Energy Incorporated and BNY Mellon Capital Markets, LLC (Exhibit 1.1 to Form 8-K filed on August 14, 2008).	Great Plains Energy
10.68	*	Insurance agreement between Kansas City Power & Light Company and XL Capital Assurance Inc., dated December 5, 2002 (Exhibit 10.2.f to Form 10-K for the year ended December 31, 2002).	Great Plains Energy KCP&L
10.69	*	Insurance Agreement dated as of August 1, 2004, between Kansas City Power & Light Company and XL Capital Assurance Inc. (Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2004).	Great Plains Energy KCP&L
10.70	*	Insurance Agreement dated as of September 1, 2005, between Kansas City Power & Light Company and XL Capital Assurance Inc. (Exhibit 10.2.e to Form 10-K for the year ended December 31, 2005).	Great Plains Energy KCP&L
10.71	*	Insurance Agreement dated as of September 1, 2005, between Kansas City Power & Light Company and XL Capital Assurance Inc. (Exhibit 10.2.f to Form 10-K for the year ended December 31, 2005).	Great Plains Energy KCP&L
10.72	*	Insurance Agreement dated as of September 19, 2007, by and between Financial Guaranty Insurance Company and Kansas City Power & Light Company (Exhibit 10.2.2 to Form 10-Q for the quarter ended September 30, 2007).	Great Plains Energy KCP&L
10.73	*	Purchase and Sale Agreement dated as of July 1, 2005, between Kansas City Power & Light Company, as Originator, and Kansas City Power & Light Receivables Company, as Buyer (Exhibit 10.2.b to Form 10-Q for the quarter ended June 30, 2005).	Great Plains Energy KCP&L
10.74	*	Receivables Sale Agreement dated as of July 1, 2005, among Kansas City Power & Light Receivables Company, as the Seller, Kansas City Power & Light Company, as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi, Ltd., New York Branch, as the Agent, and Victory Receivables Corporation (Exhibit 10.2.c to Form 10-Q for the quarter ended June 30, 2005).	Great Plains Energy KCP&L

152

10.75	*	Amendment No. 1 dated as of April 2, 2007, among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation to the Receivables Sale Agreement dated as of July 1, 2005 (Exhibit 10.2.2 to Form 10-Q for the quarter ended March 31, 2007).	Great Plains Energy KCP&L
10.76	*	Amendment No. 2 dated as of July 11, 2008, among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation to the Receivables Sale Agreement dated as of July 1, 2005 (Exhibit 10.2.2 to Form 10-Q for the quarter ended June 30, 2008).	Great Plains Energy KCP&L
10.77	*	Amendment dated as of July 9, 2009 to Receivables Sale Agreement dated as of July 1, 2005 among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation (Exhibit 10.4 to Form 8-K filed on July 13, 2009).	Great Plains Energy KCP&L
10.78	*	Amendment and Waiver dated as of September 25, 2009 to the Receivables Sale Agreement dated as of July 1, 2005 among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation (Exhibit 10.2.2 to Form 10-Q for the quarter ended September 30, 2009).	Great Plains Energy KCP&L
10.79	*	Amendment dated as of May 5, 2010 to Receivables Sale Agreement dated as of July 1, 2005 among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation (Exhibit 10.2.2 to Form 10-Q for the quarter ended March 31, 2010).	Great Plains Energy KCP&L
10.80	*	Amendment dated as of February 23, 2011 to Receivables Sale Agreement dated as of July 1, 2005 among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation. (Exhibit 10.5 to Form 10-Q for the quarter ended March 31, 2011).	Great Plains Energy KCP&L
10.81	*	Amendment dated as of September 9, 2011 to Receivables Sale Agreement dated as of July 1, 2005, among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation (Exhibit 10.1 to Form 8-K filed on September 13, 2011).	Great Plains Energy KCP&L

153

10.82	*	Iatan Unit 2 and Common Facilities Ownership Agreement, dated as of May 19, 2006, among Kansas City Power & Light Company, Aquila, Inc., The Empire District Electric Company, Kansas Electric Power Cooperative, Inc., and Missouri Joint Municipal Electric Utility Commission (Exhibit 10.2.a to Form 10-Q for the quarter ended June 30, 2006).	Great Plains Energy KCP&L
10.83	*	Stipulation and Agreement dated March 28, 2005, among Kansas City Power & Light Company, Staff of the Missouri Public Service Commission, Office of the Public Counsel, Missouri Department of Natural Resources, Praxair, Inc., Missouri Independent Energy Consumers, Ford Motor Company, Aquila, Inc., The Empire District Electric Company, and Missouri Joint Municipal Electric Utility Commission (Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2005).	Great Plains Energy KCP&L
10.84	*	Stipulation and Agreement filed April 27, 2005, among Kansas City Power & Light Company, the Staff of the State Corporation Commission of the State of Kansas, Sprint, Inc., and the Kansas Hospital Association (Exhibit 10.2.a to Form 10-Q for the quarter ended June 30, 2005).	Great Plains Energy KCP&L
10.85	*	Joint Motion and Settlement Agreement dated as of February 26, 2008, among Great Plains Energy Incorporated, Kansas City Power & Light Company, the Kansas Corporation Commission Staff, the Citizens’ Utility Ratepayers Board, Aquila, Inc. d/b/a Aquila Networks, Black Hills Corporation, and Black Hills/Kansas Gas Utility Company, LLC (Exhibit 10.1.7 to Form 10-Q for the quarter ended March 31, 2008).	Great Plains Energy KCP&L
10.86	*	Stipulation and Agreement dated April 24, 2009, among Kansas City Power & Light Company, Staff of the Missouri Public Service Commission, Office of Public Counsel, Praxair, Inc., Midwest Energy Users Association, U.S. Department of Energy and the U.S. Nuclear Security Administration, Ford Motor Company, Missouri Industrial Energy Consumers and Missouri Department of Natural Resources (Exhibit 10.1 to Form 8-K filed April 30, 2009).	Great Plains Energy KCP&L
10.87	*	Non-Unanimous Stipulation and Agreement dated May 22, 2009 among KCP&L Greater Missouri Operations Company, the Staff of the Missouri Public Service Commission, the Office of the Public Counsel, Missouri Department of Natural Resources and Dogwood Energy, LLC (Exhibit 10.1 to Form 8-K filed on May 27, 2009).	Great Plains Energy
10.88	*	Collaboration Agreement dated as of March 19, 2007, among Kansas City Power & Light Company, Sierra Club and Concerned Citizens of Platte County, Inc. (Exhibit 10.1 to Form 8-K filed on March 20, 2007).	Great Plains Energy KCP&L

154

10.89	*	Amendment to the Collaboration Agreement effective as of September 5, 2008 among Kansas City Power & Light Company, Sierra Club and Concerned Citizens of Platte County, Inc. (Exhibit 10.2.20 to Form 10-K for the year ended December 31, 2009).	Great Plains Energy KCP&L
10.90	*	Joint Operating Agreement between Kansas City Power & Light Company and Aquila, Inc., dated as of October 10, 2008 (Exhibit 10.2.2 to Form 10-Q for the quarter ended September 30, 2008).	Great Plains Energy KCP&L
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
21.1		List of Subsidiaries of Great Plains Energy Incorporated.	Great Plains Energy
23.1		Consent of Independent Registered Public Accounting Firm.	Great Plains Energy
23.2		Consent of Independent Registered Public Accounting Firm.	KCP&L
24.1		Powers of Attorney.	Great Plains Energy
24.2		Powers of Attorney.	KCP&L
31.1		Rule 13a-14(a)/15d-14(a) Certification of Michael J. Chesser.	Great Plains Energy
31.2		Rule 13a-14(a)/15d-14(a) Certification of James C. Shay.	Great Plains Energy
31.3		Rule 13a-14(a)/15d-14(a) Certification of Michael J. Chesser.	KCP&L
31.4		Rule 13a-14(a)/15d-14(a) Certification of James C. Shay.	KCP&L

32.1	**	Section 1350 Certifications.	Great Plains Energy
32.2	**	Section 1350 Certifications.	KCP&L
101.INS	**	XBRL Instance Document.	Great Plains Energy KCP&L
101.SCH	**	XBRL Taxonomy Extension Schema Document.	Great Plains Energy KCP&L
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase Document.	Great Plains Energy KCP&L
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase Document.	Great Plains Energy KCP&L
101.LAB	**	XBRL Taxonomy Extension Labels Linkbase Document.	Great Plains Energy KCP&L

155

101.PRE ** XBRL Taxonomy Extension Presentation Linkbase Document. Great Plains Energy KCP&L  

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

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

+ Indicates management contract or compensatory plan or arrangement.

Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from KCP&L 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.

156

Schedule I – Parent Company Financial Statements

GREAT PLAINS ENERGY INCORPORATED
Income Statements of Parent Company
Year Ended December 31	2011			2010			2009
Operating Expenses	(millions, except per share amounts)
Selling, general and administrative	$	0.8		$	1.2		$	8.8
Maintenance		-			-			0.2
General taxes		0.9			0.9			1.1
Total		1.7			2.1			10.1
Operating loss		(1.7	)		(2.1	)		(10.1	)
Equity in earnings from subsidiaries		200.8			239.3			174.7
Non-operating income		24.7			3.4			-
Interest charges		(66.5	)		(44.7	)		(28.2	)
Income from continuing operations before income taxes		157.3			195.9			136.4
Income tax benefit		17.1			15.8			15.2
Income from continuing operations		174.4			211.7			151.6
Equity in loss from discontinued subsidiary		-			-			(1.5	)
Net income		174.4			211.7			150.1
Preferred stock dividend requirements		1.6			1.6			1.6
Earnings available for common shareholders	$	172.8		$	210.1		$	148.5
Average number of basic common shares outstanding		135.6			135.1			129.3
Average number of diluted common shares outstanding		138.7			136.9			129.8
Basic earnings (loss) per common share
Continuing operations	$	1.27		$	1.55		$	1.16
Discontinued operations		-			-			(0.01	)
Basic earnings per common share	$	1.27		$	1.55		$	1.15
Diluted earnings (loss) per common share
Continuing operations	$	1.25		$	1.53		$	1.15
Discontinued operations		-			-			(0.01	)
Diluted earnings per common share	$	1.25		$	1.53		$	1.14
Cash dividends per common share	$	0.835		$	0.83		$	0.83
The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.

157

GREAT PLAINS ENERGY INCORPORATED
Balance Sheets of Parent Company
December 31	2011			2010
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	-		$	0.3
Notes receivable from subsidiaries		0.6			249.4
Money pool receivable		0.9			2.0
Taxes receivable		0.9			7.2
Other		0.6			0.7
Total		3.0			259.6
Investments and Other Assets
Investment in KCP&L		2,045.5			2,005.0
Investments in other subsidiaries		1,377.0			1,360.2
Note receivable from subsidiaries		596.2			-
Deferred income taxes		33.7			7.2
Other		6.4			6.2
Total		4,058.8			3,378.6
Total	$	4,061.8		$	3,638.2
LIABILITIES AND CAPITALIZATION
Current Liabilities
Notes payable	$	22.0		$	9.5
Current maturities of long-term debt		287.5			-
Accounts payable to subsidiaries		31.8			31.1
Accrued taxes		5.1			-
Accrued interest		7.6			6.4
Derivative instruments		-			20.8
Other		2.9			7.1
Total		356.9			74.9
Deferred Credits and Other Liabilities
Other		6.7			1.4
Total		6.7			1.4
Capitalization
Common shareholders' equity
Common stock - 250,000,000 shares authorized without par value
136,406,306 and 136,113,954 shares issued, stated value		2,330.6			2,324.4
Retained earnings		684.7			626.5
Treasury stock - 264,567 and 400,889 shares, at cost		(5.6	)		(8.9	)
Accumulated other comprehensive loss		(49.8	)		(56.1	)
Total		2,959.9			2,885.9
Cumulative preferred stock $100 par value
3.80% - 100,000 shares issued		10.0			10.0
4.50% - 100,000 shares issued		10.0			10.0
4.20% - 70,000 shares issued		7.0			7.0
4.35% - 120,000 shares issued		12.0			12.0
Total		39.0			39.0
Long-term debt		699.3			637.0
Total		3,698.2			3,561.9
Commitments and Contingencies
Total	$	4,061.8		$	3,638.2
The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.

158

GREAT PLAINS ENERGY INCORPORATED
Statements of Cash Flows of Parent Company
Year Ended December 31	2011			2010			2009
Cash Flows from Operating Activities	(millions)
Net income	$	174.4		$	211.7		$	150.1
Adjustments to reconcile income to net cash from operating activities:
Amortization		11.2			3.9			1.9
Deferred income taxes, net		(18.6	)		13.9			(6.1	)
Equity in earnings from subsidiaries		(200.8	)		(239.3	)		(174.7	)
Equity in (earnings) loss from discontinued subsidiary		-			-			1.5
Cash flows affected by changes in:
Accounts receivable from subsidiaries		-			(2.6	)		3.7
Taxes receivable		6.3			-			4.8
Accounts payable to subsidiaries		(0.3	)		2.2			0.2
Other accounts payable		-			(0.1	)		0.1
Accrued taxes		5.2			-			-
Accrued interest		1.2			2.7			1.4
Cash dividends from subsidiaries		148.0			138.6			94.0
Interest hedge settlement		(26.1	)		(6.9	)		-
Other		2.1			(0.9	)		8.8
Net cash from operating activities		102.6			123.2			85.7
Cash Flows from Investing Activities
Equity contributions to subsidiaries		-			-			(455.0	)
Intercompany lending		(347.4	)		(248.8	)		-
Net money pool lending		1.1			(1.1	)		(0.9	)
Net cash from investing activities		(346.3	)		(249.9	)		(455.9	)
Cash Flows from Financing Activities
Issuance of common stock		5.9			6.2			219.9
Issuance of long-term debt		349.7			249.9			287.5
Issuance fees		(3.2	)		(3.2	)		(18.8	)
Net change in short-term borrowings		12.5			(10.5	)		(10.0	)
Dividends paid		(115.1	)		(114.2	)		(110.5	)
Other financing activities		(6.4	)		(7.3	)		(3.8	)
Net cash from financing activities		243.4			120.9			364.3
Net Change in Cash and Cash Equivalents		(0.3	)		(5.8	)		(5.9	)
Cash and Cash Equivalents at Beginning of Year		0.3			6.1			12.0
Cash and Cash Equivalents at End of Year	$	-		$	0.3		$	6.1
The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED

Statements of Common Shareholders’ Equity of Parent Company

Statements of Comprehensive Income of Parent Company

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

159

GREAT PLAINS ENERGY INCORPORATED

NOTES TO FINANCIAL STATEMENTS OF PARENT COMPANY

The Great Plains Energy Incorporated Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Great Plains Energy Incorporated Parent Company Financial Statements.

Schedule II – Valuation and Qualifying Accounts and Reserves

Great Plains Energy Incorporated
Valuation and Qualifying Accounts
Years Ended December 31, 2011, 2010 and 2009
				Additions
				Charged
		Balance At		To Costs			Charged						Balance
		Beginning		And			To Other						At End
	Description	Of Period		Expenses			Accounts			Deductions			Of Period
Year Ended December 31, 2011		(millions)
	Allowance for uncollectible accounts	$	7.0	$	13.7		$	6.9	(a)	$	20.8	(b)	$	6.8
	Legal reserves		10.2		(0.1	)		-			3.4	(c)		6.7
	Environmental reserves		2.5		-			-			-			2.5
	Tax valuation allowance		26.6		0.1			-			2.8	(d)		23.9
Year Ended December 31, 2010
	Allowance for uncollectible accounts	$	7.1	$	9.7		$	6.9	(a)	$	16.7	(b)	$	7.0
	Legal reserves		5.1		7.0			-			1.9	(c)		10.2
	Environmental reserves		2.4		0.1			-			-			2.5
	Tax valuation allowance		29.8		0.2			-			3.4	(d)		26.6
Year Ended December 31, 2009
	Allowance for uncollectible accounts	$	6.8	$	8.7		$	6.0	(a)	$	14.4	(b)	$	7.1
	Legal reserves		10.2		2.6			-			7.7	(c)		5.1
	Environmental reserves		0.5		2.0			-			0.1			2.4
	Tax valuation allowance		75.8		57.0			-			103.0	(d)		29.8
(a)	Recoveries.
(b)	Uncollectible accounts charged off.
(c)	Payment of claims.
(d)	Reversal of tax valuation allowance.

160

Kansas City Power & Light Company
Valuation and Qualifying Accounts
Years Ended December 31, 2011, 2010 and 2009
				Additions
				Charged
		Balance At		To Costs		Charged						Balance
		Beginning		And		To Other						At End
	Description	Of Period		Expenses		Accounts			Deductions			Of Period
Year Ended December 31, 2011		(millions)
	Allowance for uncollectible accounts	$	1.5	$	8.8	$	4.5	(a)	$	13.4	(b)	$	1.4
	Legal reserves		3.0		1.3		-			0.4	(c)		3.9
	Environmental reserves		0.3		-		-			-			0.3
Year Ended December 31, 2010
	Allowance for uncollectible accounts	$	1.7	$	6.2	$	4.3	(a)	$	10.7	(b)	$	1.5
	Legal reserves		2.3		1.9		-			1.2	(c)		3.0
	Environmental reserves		0.3		-		-			-			0.3
Year Ended December 31, 2009
	Allowance for uncollectible accounts	$	1.2	$	5.5	$	3.9	(a)	$	8.9	(b)	$	1.7
	Legal reserves		2.4		1.2		-			1.3	(c)		2.3
	Environmental reserves		0.3		-		-			-			0.3
(a)	Recoveries.
(b)	Uncollectible accounts charged off.
(c)	Payment of claims.

161

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

GREAT PLAINS ENERGY INCORPORATED

Date: February 28, 2012                                                                       By: /s/Michael J. Chesser

Michael J. Chesser

Chairman of the Board and

Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/Michael J. Chesser Michael J. Chesser	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)	) ) )
		)
/s/James C. Shay James C. Shay	Senior Vice President – Finance and Strategic Development and Chief Financial Officer (Principal Financial Officer)	) ) ) )
		)
/s/Lori A. Wright Lori A. Wright	Vice President – Business Planning and Controller (Principal Accounting Officer)	) ) )
		)
/s/Terry Bassham Terry Bassham	Director, President and Chief Operating Officer	) ) )
		)
David L. Bodde*	Director	)   February 28, 2012
		)
Randall C. Ferguson, Jr.*	Director	)
		)
Gary D. Forsee*	Director	)
		)
Thomas D. Hyde*	Director	)
		)
James A. Mitchell*	Director	)
		)
William C. Nelson*	Director	)
		)
John J. Sherman*	Director	)
		)
Linda H. Talbott*	Director	)
		)
Robert H. West*	Director	)

*By         /s/Michael J. Chesser

Michael J. Chesser

Attorney-in-Fact*

162

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

KANSAS CITY POWER & LIGHT COMPANY

Date: February 28, 2012                                                                       By: /s/Michael J. Chesser

Michael J. Chesser

Chairman of the Board and

Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/Michael J. Chesser Michael J. Chesser	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)	) ) )
		)
/s/James C. Shay James C. Shay	Senior Vice President – Finance and Strategic Development and Chief Financial Officer (Principal Financial Officer)	) ) ) )
		)
/s/Lori A. Wright Lori A. Wright	Vice President – Business Planning and Controller (Principal Accounting Officer)	) ) )
		)
/s/Terry Bassham Terry Bassham	Director, President and Chief Operating Officer	) ) )
		)
David L. Bodde*	Director	)   February 28, 2012
		)
Randall C. Ferguson, Jr.*	Director	)
		)
Gary D. Forsee*	Director	)
		)
Thomas D. Hyde*	Director	)
		)
James A. Mitchell*	Director	)
		)
William C. Nelson*	Director	)
		)
John J. Sherman*	Director	)
		)
Linda H. Talbott*	Director	)
		)

*By         /s/Michael J. Chesser

Michael J. Chesser

Attorney-in-Fact*

163

EX-10.59

Exhibit 10.59

FIRST AMENDMENT TO CREDIT AGREEMENT

Dated as of December 9, 2011

among

GREAT PLAINS ENERGY INCORPORATED,

as the Borrower,

CERTAIN LENDERS,

UNION BANK, N.A. and

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Syndication Agents

and

BANK OF AMERICA, N.A.,

as Administrative Agent, Swing Line Lender and an Issuer

BARCLAYS BANK PLC and

U.S. BANK NATIONAL ASSOCIATION,

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

FIRST AMENDMENT TO CREDIT AGREEMENT

THIS FIRST AMENDMENT TO CREDIT AGREEMENT dated as of December 9, 2011 (this “Agreement”) is entered into among Great Plains Energy Incorporated, a Missouri corporation (the “Borrower”), the Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents and Bank of America, N.A., as Administrative Agent, Swing Line Lender and an Issuer.  All capitalized terms used herein and not otherwise defined herein shall have the meanings given to such terms in the Credit Agreement (as defined below).

RECITALS

WHEREAS, the Borrower, the Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents and Bank of America, N.A., as Administrative Agent entered into that certain Credit Agreement dated as of August 9, 2010 (as amended or modified from time to time, the “Credit Agreement”);

WHEREAS, the Borrower has requested that the Lenders amend the Credit Agreement as set forth below;

NOW, THEREFORE, in consideration of the premises and the mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.           Amendments.  The Credit Agreement is hereby amended as follows:

(a)           The definition of “Administrative Agent’s Fee Letter” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Administrative Agent’s Fee Letter” means that certain fee letter dated November 10, 2011 among Bank of America, MLPFS, the Borrower, KCPL GMO and KCPL.

(b)           The definition of “Aggregate Commitment” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Aggregate Commitment” means the aggregate of the Commitments of all Lenders, as changed from time to time pursuant to the terms hereof.  The amount of the Aggregate Commitment in effect as of the First Amendment Effective Date is TWO HUNDRED MILLION DOLLARS ($200,000,000).

(c)           The definition of “Change” in Section 1.1 of the Credit Agreement is hereby deleted in its entirety and the definition of “Change in Law” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Change in Law” means the occurrence, after the First Amendment Effective Date, of any of the following: (a) the adoption or taking effect of any law, rule, regulation or treaty, (b) any change in any law, rule, regulation or treaty or in the administration, interpretation, implementation or application thereof by any Governmental Authority or (c) the making or issuance of any request, rules, guideline or directive (whether or not

having the force of law) by any Governmental Authority; provided, that, notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith 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 regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, adopted or issued.

(d)           The definition of “Facility Termination Date” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Facility Termination Date” means (a) the later of (i) December 9, 2016 and (ii) with respect to some or all of the Lenders if the facility termination date is extended pursuant to Section 2.21, such extended facility termination date or (b) any earlier date on which the Aggregate Commitment is reduced to zero or otherwise terminated pursuant to the terms hereof.

(e)           The definition of “Fee Letter” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Fee Letter” means that certain fee letter dated November 10, 2011 among Bank of America, Wells Fargo, BTMU, the Arrangers, the Borrower, KCPL GMO and KCPL.

(f)           The following definition is hereby added to Section 1.1 of the Credit Agreement in the appropriate alphabetical order to read as follows:

“First Amendment Effective Date” means December 9, 2011.

(g)           The definition of “BAS” is hereby deleted from Section 1.1 of the Credit Agreement in its entirety, each reference to “BAS” in the Credit Agreement is hereby amended to read “MLPFS” and the following definition is hereby added to Section 1.1 of the Credit Agreement in the appropriate alphabetical order to read as follows:

“MLPFS” means Merrill Lynch, Pierce, Fenner & Smith Incorporated, in its capacity as joint lead arranger and joint book manager.

(h)           The introductory paragraph and clause (i) of Section 3.1 of the Credit Agreement are hereby amended to read as follows:

If any Change in Law:

(i)           subjects any Lender or Issuer to any tax of any kind whatsoever with respect to this Agreement, any Letter of Credit, any participation in a Letter of Credit or any Eurodollar Loan made by it, or changes the basis of taxation of payments to such Lender or such Issuer in respect thereof (except for Indemnified Taxes or Other Taxes covered by Section 3.5 and the imposition of, or any change in the rate of, any Excluded Tax), or

(i)           Section 3.2 of the Credit Agreement is hereby amended to read as follows:

If a Lender or an Issuer determines the amount of capital required or expected to be maintained by such Lender, any Lending Installation of such Lender, such Issuer or any corporation controlling such Lender or such Issuer is increased as a result of a Change in Law, then, within thirty (30) days of written demand by such Lender or such Issuer, the Borrower shall pay such Lender or such Issuer the amount necessary to compensate for any shortfall in the rate of return on the portion of such increased capital which such Lender or such Issuer determines is attributable to this Agreement, its Outstanding Credit Exposure or its Commitment to make Loans or to issue or participate in Letters of Credit hereunder (after taking into account such Lender’s or such Issuer’s policies and the policies of any corporation controlling such Lender or such Issuer as to capital adequacy).

(j)           Section 3.3 of the Credit Agreement is hereby amended to read as follows:

If (i) any Lender determines, or any Governmental Authority has asserted, that making, funding or maintaining Loans whose interest is determined by reference to the Eurodollar Base Rate at a suitable Lending Installation, or determining or charging interest rates based on the Eurodollar Base Rate, would violate any applicable law, rule, regulation, or directive, whether or not having the force of law, enacted or imposed after the date of this Agreement, (ii) any Governmental Authority has imposed material restrictions on the authority of such Lender to purchase or sell, or to take deposits of, Dollars in the London interbank market, (iii) the Required Lenders determine that (a) deposits of a type and maturity appropriate to match fund Eurodollar Advances are not available or (b) the interest rate applicable to a Type of Advance does not accurately reflect the cost of making or maintaining such Advance or (iv) the Administrative Agent determines that adequate and reasonable means do not exist for determining the Eurodollar Base Rate, then the Administrative Agent shall suspend the availability of the affected Type of Advance (or, if such notice asserts the illegality of such Lender determining or charging interest rates based upon the Eurodollar Base Rate, the Administrative Agent shall during the period of such suspension compute the Alternate Base Rate applicable to such Lender without reference to the Eurodollar Base Rate component thereof until the Administrative Agent is advised in writing by such Lender that it is no longer illegal for such Lender to determine or charge interest rates based upon the Eurodollar Base Rate) and, in the case of clauses (i) and (ii), require any affected Eurodollar Advances to be repaid or converted to Floating Rate Advances, subject to the payment of any funding indemnification amounts required by Section 3.4.

(k)           Schedule I to the Credit Agreement is hereby amended to read as shown in Schedule I attached to this Agreement.

(l)           The pricing grid in Schedule III to the Credit Agreement is hereby amended to read as follows:

	>A-/A3	BBB+/Baa1	BBB/Baa2	BBB-/Baa3	BB+/Ba1	<BB/Ba2
Pricing	Level I Status	Level II Status	Level III Status	Level IV Status	Level V Status	Level VI Status
Applicable Margin for Eurodollar Advances and Letter of Credit Fee Rate	1.125%	1.25%	1.50%	1.75%	2.00%	2.25%
Commitment Fee Rate	0.125%	0.175%	0.225%	0.275%	0.375%	0.50%
Applicable Margin for Floating Rate Advances	0.125%	0.25%	0.50%	0.75%	1.00%	1.25%

2.           Conditions Precedent.  This Agreement shall be effective upon:

(a)           receipt by the Administrative Agent of counterparts of this Agreement duly executed by the Borrower, the Administrative Agent and the Lenders;

(b)           the receipt by the Administrative Agent of the following, each of which shall be originals or facsimiles (followed promptly by originals), in form and substance satisfactory to the Administrative Agent:

(i)           copies of the Organization Documents of the Borrower certified to be true and complete as of a recent date by the appropriate Governmental Authority of the state or other jurisdiction of its incorporation or organization and certified by a secretary or assistant secretary of the Borrower to be true and correct as of the date hereof;

(ii)           such certificates of resolutions and/or other certificates of Authorized Officers of the Borrower as the Administrative Agent may require evidencing the identity, authority and capacity of each Authorized Officer thereof authorized to act as an Authorized Officer in connection with this Agreement; and

(iii)           such documents and certifications as the Administrative Agent may require to evidence that the Borrower is duly organized or formed, and is validly existing, in good standing and qualified to engage in business in its state of organization or formation;

(c)           any portion of the Loans and Commitments held by a Person who is not executing this Agreement as a Lender shall have been assigned to a Person who is a Lender under the Credit Agreement (as amended by this Agreement).

(d)           the receipt by the Administrative Agent of favorable opinions of legal counsel to the Borrower, addressed to the Administrative Agent and each Lender, dated as of the date hereof and in form and substance satisfactory to the Administrative Agent, addressing the execution, delivery and enforceability of this Agreement and other matters that were addressed in the opinion provided in connection with the original delivery of the Credit Agreement on August 9, 2010, with respect to this Agreement; and

(e)           all fees required to be paid to the Administrative Agent, the Arrangers and the Lenders pursuant to the Fee Letter and the Administrative Agent’s Fee Letter on or before the date hereof shall have been paid.

3.           Miscellaneous.

(a)           The Credit Agreement, and the obligations of the Borrower thereunder and under the other Loan Documents, are hereby ratified and confirmed and shall remain in full force and effect according to their terms.  The Borrower acknowledges and confirms that as of the date hereof the Borrower’s obligation to repay the outstanding principal amount of the Loans and 
 

reimburse the Issuers for any drawing on a Letter of Credit is unconditional and not subject to any offsets, defenses or counterclaims.  The Administrative Agent, each Syndication Agent, each Lender and the Borrower acknowledge and confirm that by entering into this Agreement, each party does not waive or release any term or condition of the Credit Agreement or any of the other Loan Documents or any of their rights or remedies under such Loan Documents or applicable Law or any of the obligations of such party thereunder.

(b)           The Borrower hereby represents and warrants as follows:

(i)           The Borrower has taken all necessary corporate action to authorize the execution, delivery and performance of this Agreement.

(ii)           This Agreement has been duly executed and delivered by the Borrower and constitutes the Borrower’s legal, valid and binding obligations, enforceable in accordance with its terms, except as such enforceability may be subject to (i) bankruptcy, insolvency, reorganization, fraudulent conveyance or transfer, moratorium or similar laws affecting creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).

(iii)           No consent, approval, authorization or order of, or filing, registration or qualification with, any court or governmental authority or third party is required in connection with the execution, delivery or performance by the Borrower of this Agreement.

(c)           The Borrower represents and warrants to the Lenders that (i) the representations and warranties of the Borrower set forth in Article V of the Credit Agreement are true and correct as of the date hereof with the same effect as if made on and as of the date hereof, except to the extent such representations and warranties expressly relate solely to an earlier date and (ii) no event has occurred and is continuing which constitutes a Default or an Unmatured Default.

(d)           This Agreement may be executed in any number of counterparts, each of which when so executed and delivered shall be an original, but all of which shall constitute one and the same instrument.  Delivery of an executed counterpart of this Agreement by telecopy or electronic mail shall be effective as an original and shall constitute a representation that an executed original shall be delivered.

(e)           THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

(f)           Upon and after the execution of this Agreement by each of the parties hereto, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement as modified hereby.  This Amendment shall constitute a Loan Document.

[remainder of page intentionally left blank]

BORROWER:	GREAT PLAINS ENERGY INCORPORATED, a Missouri corporation By:  /s/ Kevin E. Bryant                                                                 Name:  Kevin E. Bryant                                                                 Title:   Vice President – Investor Relations and Treasurer
ADMINISTRATIVE AGENT	BANK OF AMERICA, N.A., as Administrative Agent By: /s/ Kelly Weaver                                                                 Name:  Kelly Weaver                                                       Title:    Assistant Vice President
LENDERS:	BANK OF AMERICA, N.A., as a Lender, an Issuer and Swing Line Lender By:  /s/ Patrick Martin                                                                 Name:  Patrick Martin                                                                 Title:    Director        WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Lender, Syndication Agent and an Issuer By:/s/ Allison Newman                                                                 Name: Allison Newman                                            Title:    Director     THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as a Lender and as an Issuer By: /s/ Chi-Cheng Chen                                                                 Name:  Chi-Cheng Chen                                            Title:     Vice President UNION BANK, N.A., as a Lender and Syndication Agent By: /s/ Susan K. Johnson                                                       Name:  Susan K. Johnson                                            Title:    Vice President                                                       BARCLAYS BANK PLC, as a Lender By: /s/ David Barton                                                                 Name:  David Barton                                                       Title:  Director                                                                 BNP PARIBAS, as a Lender By: /s/ Francis DeLaney                                                                 Name:  Francis DeLaney                                                       Title:  Managing Director                                                       By: /s/ Pasquale Perraglia                                                       Name:  Pasquale Perraglia                                            Title:  Vice President                                                                 GOLDMAN SACHS BANK USA. as a Lender By: /s/ Mark Walton                                                                 Name:  Mark Walton                                            Title:  Authorized Signatory
	JPMORGAN CHASE BANK, N.A as a Lender By: /s/ John E. Zur                                                       Name:  John E. Zur                                            Title:  Authorized Officer
	THE BANK OF NOVA SCOTIA as a Lender By: /s/ Thane Rattew                                                                 Name:  Thane Rattew                                                       Title:  Managing Director
	THE ROYAL BANK OF SCOTLAND plc, as a Lender By: /s/ Andrew N. Taylor                                                       Name:  Andrew N. Taylor                                                       Title:  Vice President
	U.S. Bank National Association, as a Lender By: /s/ Eric J. Cosgrove                                                                 Name:           Eric J. Cosgrove                                            Title:  Vice President
	SUNTRUST BANK, as a Lender By: /s/ Andrew Johnson                                                                 Name:  Andrew Johnson                                            Title:  Director
	KeyBank National Association as a Lender By: /s/ Craig A. Hanselman                                                                 Name:  Craig A. Hanselman                                                       Title:  Vice President
	The Bank of New York Mellon as a Lender By: /s/ Hussam S. Alsahlani                                                                 Name:  Hussam S. Alsahlani                                                       Title:  Vice President
	UMB BANK, N.A. As a Lender By: /s/ Robert P. Elbert                                                                 Name:  Robert P. Elbert                                                       Title:  Senior Vice President
	COMMERCE BANK as a Lender By: /s/ Aaron M. Siders                                                                 Name:  Aaron M. Siders                                            Title:  Vice President

SCHEDULE I

COMMITMENTS

Lender	Commitment
Bank of America, N.A.	$18,400,000
Wells Fargo Bank, National Association	$18,400,000
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$9,200,000
Union Bank, N.A.	$9,200,000
Barclays Bank PLC	$13,600,000
BNP Paribas	$13,600,000
Goldman Sachs Bank USA	$13,600,000
JPMorgan Chase Bank, N.A.	$13,600,000
The Bank of Nova Scotia	$13,600,000
The Royal Bank of Scotland plc	$13,600,000
U.S. Bank National Association	$13,600,000
SunTrust Bank	$12,800,000
KeyBank National Association	$12,000,000
The Bank of New York Mellon	$12,000,000
UMB Bank, N.A.	$8,000,000
Commerce Bank	$4,800,000
Total	$200,000,000

LETTER OF CREDIT COMMITMENTS

Issuer	Letter of Credit Commitment
Bank of America, N.A.	$16,666,666.67
Wells Fargo Bank, National Association	$16,666,666.67
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$16,666,666.66
Total	$50,000,000.00

EX-10.61

Exhibit 10.61

FIRST AMENDMENT TO CREDIT AGREEMENT

Dated as of December 9, 2011

among

KANSAS CITY POWER & LIGHT COMPANY,

as the Borrower,

CERTAIN LENDERS,

UNION BANK, N.A. and

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Syndication Agents

and

BANK OF AMERICA, N.A.,

as Administrative Agent, Swing Line Lender and an Issuer

JPMORGAN CHASE BANK, N.A. and

THE BANK OF NOVA SCOTIA,

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

FIRST AMENDMENT TO CREDIT AGREEMENT

THIS FIRST AMENDMENT TO CREDIT AGREEMENT dated as of December 9, 2011 (this “Agreement”) is entered into among Kansas City Power & Light Company, a Missouri corporation (the “Borrower”), the Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents and Bank of America, N.A., as Administrative Agent, Swing Line Lender and an Issuer.  All capitalized terms used herein and not otherwise defined herein shall have the meanings given to such terms in the Credit Agreement (as defined below).

RECITALS

WHEREAS, the Borrower, the Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents and Bank of America, N.A., as Administrative Agent entered into that certain Credit Agreement dated as of August 9, 2010 (as amended or modified from time to time, the “Credit Agreement”);

WHEREAS, the Borrower has requested that the Lenders amend the Credit Agreement as set forth below;

NOW, THEREFORE, in consideration of the premises and the mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.           Amendments.  The Credit Agreement is hereby amended as follows:

(a)           The definition of “Administrative Agent’s Fee Letter” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Administrative Agent’s Fee Letter” means that certain fee letter dated November 10, 2011 among Bank of America, MLPFS, the Borrower, Great Plains and KCPL GMO.

(b)           The definition of “Aggregate Commitment” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Aggregate Commitment” means the aggregate of the Commitments of all Lenders, as changed from time to time pursuant to the terms hereof.  The amount of the Aggregate Commitment in effect as of the First Amendment Effective Date is SIX HUNDRED MILLION DOLLARS ($600,000,000).

(c)           The definition of “Change” in Section 1.1 of the Credit Agreement is hereby deleted in its entirety and the definition of “Change in Law” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Change in Law” means the occurrence, after the First Amendment Effective Date, of any of the following: (a) the adoption or taking effect of any law, rule, regulation or treaty, (b) any change in any law, rule, regulation or treaty or in the administration, interpretation, implementation or application thereof by any Governmental Authority or (c) the making or issuance of any request, rules, guideline or directive (whether or not

having the force of law) by any Governmental Authority; provided, that, notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith 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 regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, adopted or issued.

(d)           The definition of “Facility Termination Date” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Facility Termination Date” means (a) the later of (i) December 9, 2016 and (ii) with respect to some or all of the Lenders if the facility termination date is extended pursuant to Section 2.21, such extended facility termination date or (b) any earlier date on which the Aggregate Commitment is reduced to zero or otherwise terminated pursuant to the terms hereof.

(e)           The definition of “Fee Letter” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Fee Letter” means that certain fee letter dated November 10, 2011 among Bank of America, Wells Fargo, BTMU, the Arrangers, the Borrower, Great Plains and KCPL GMO.

(f)           The following definition is hereby added to Section 1.1 of the Credit Agreement in the appropriate alphabetical order to read as follows:

“First Amendment Effective Date” means December 9, 2011.

(g)           The definition of “BAS” is hereby deleted from Section 1.1 of the Credit Agreement in its entirety, each reference to “BAS” in the Credit Agreement is hereby amended to read “MLPFS” and the following definition is hereby added to Section 1.1 of the Credit Agreement in the appropriate alphabetical order to read as follows:

“MLPFS” means Merrill Lynch, Pierce, Fenner & Smith Incorporated, in its capacity as joint lead arranger and joint book manager.

(h)           The introductory paragraph and clause (i) of Section 3.1 of the Credit Agreement are hereby amended to read as follows:

If any Change in Law:

(i)           subjects any Lender or Issuer to any tax of any kind whatsoever with respect to this Agreement, any Letter of Credit, any participation in a Letter of Credit or any Eurodollar Loan made by it, or changes the basis of taxation of payments to such Lender or such Issuer in respect thereof (except for Indemnified Taxes or Other Taxes covered by Section 3.5 and the imposition of, or any change in the rate of, any Excluded Tax), or

(i)           Section 3.2 of the Credit Agreement is hereby amended to read as follows:

If a Lender or an Issuer determines the amount of capital required or expected to be maintained by such Lender, any Lending Installation of such Lender, such Issuer or any corporation controlling such Lender or such Issuer is increased as a result of a Change in Law, then, within thirty (30) days of written demand by such Lender or such Issuer, the Borrower shall pay such Lender or such Issuer the amount necessary to compensate for any shortfall in the rate of return on the portion of such increased capital which such Lender or such Issuer determines is attributable to this Agreement, its Outstanding Credit Exposure or its Commitment to make Loans or to issue or participate in Letters of Credit hereunder (after taking into account such Lender’s or such Issuer’s policies and the policies of any corporation controlling such Lender or such Issuer as to capital adequacy).

(j)           Section 3.3 of the Credit Agreement is hereby amended to read as follows:

If (i) any Lender determines, or any Governmental Authority has asserted, that making, funding or maintaining Loans whose interest is determined by reference to the Eurodollar Base Rate at a suitable Lending Installation, or determining or charging interest rates based on the Eurodollar Base Rate, would violate any applicable law, rule, regulation, or directive, whether or not having the force of law, enacted or imposed after the date of this Agreement, (ii) any Governmental Authority has imposed material restrictions on the authority of such Lender to purchase or sell, or to take deposits of, Dollars in the London interbank market, (iii) the Required Lenders determine that (a) deposits of a type and maturity appropriate to match fund Eurodollar Advances are not available or (b) the interest rate applicable to a Type of Advance does not accurately reflect the cost of making or maintaining such Advance or (iv) the Administrative Agent determines that adequate and reasonable means do not exist for determining the Eurodollar Base Rate, then the Administrative Agent shall suspend the availability of the affected Type of Advance (or, if such notice asserts the illegality of such Lender determining or charging interest rates based upon the Eurodollar Base Rate, the Administrative Agent shall during the period of such suspension compute the Alternate Base Rate applicable to such Lender without reference to the Eurodollar Base Rate component thereof until the Administrative Agent is advised in writing by such Lender that it is no longer illegal for such Lender to determine or charge interest rates based upon the Eurodollar Base Rate) and, in the case of clauses (i) and (ii), require any affected Eurodollar Advances to be repaid or converted to Floating Rate Advances, subject to the payment of any funding indemnification amounts required by Section 3.4.

(k)           Schedule I to the Credit Agreement is hereby amended to read as shown in Schedule I attached to this Agreement.

(l)           The pricing grid in Schedule III to the Credit Agreement is hereby amended to read as follows:

	>A-/A3	BBB+/Baa1	BBB/Baa2	BBB-/Baa3	BB+/Ba1	<BB/Ba2
Pricing	Level I Status	Level II Status	Level III Status	Level IV Status	Level V Status	Level VI Status
Applicable Margin for Eurodollar Advances and Letter of Credit Fee Rate	1.125%	1.25%	1.50%	1.75%	2.00%	2.25%
Commitment Fee Rate	0.125%	0.175%	0.225%	0.275%	0.375%	0.50%
Applicable Margin for Floating Rate Advances	0.125%	0.25%	0.50%	0.75%	1.00%	1.25%

2.           Conditions Precedent.  This Agreement shall be effective upon:

(a)           receipt by the Administrative Agent of counterparts of this Agreement duly executed by the Borrower, the Administrative Agent and the Lenders;

(b)           the receipt by the Administrative Agent of the following, each of which shall be originals or facsimiles (followed promptly by originals), in form and substance satisfactory to the Administrative Agent:

(i)           copies of the Organization Documents of the Borrower certified to be true and complete as of a recent date by the appropriate Governmental Authority of the state or other jurisdiction of its incorporation or organization and certified by a secretary or assistant secretary of the Borrower to be true and correct as of the date hereof;

(ii)           such certificates of resolutions and/or other certificates of Authorized Officers of the Borrower as the Administrative Agent may require evidencing the identity, authority and capacity of each Authorized Officer thereof authorized to act as an Authorized Officer in connection with this Agreement; and

(iii)           such documents and certifications as the Administrative Agent may require to evidence that the Borrower is duly organized or formed, and is validly existing, in good standing and qualified to engage in business in its state of organization or formation;

(c)           any portion of the Loans and Commitments held by a Person who is not executing this Agreement as a Lender shall have been assigned to a Person who is a Lender under the Credit Agreement (as amended by this Agreement).

(d)           the receipt by the Administrative Agent of favorable opinions of legal counsel to the Borrower, addressed to the Administrative Agent and each Lender, dated as of the date hereof and in form and substance satisfactory to the Administrative Agent, addressing the execution, delivery and enforceability of this Agreement and other matters that were addressed in the opinion provided in connection with the original delivery of the Credit Agreement on August 9, 2010, with respect to this Agreement; and

(e)           all fees required to be paid to the Administrative Agent, the Arrangers and the Lenders pursuant to the Fee Letter and the Administrative Agent’s Fee Letter on or before the date hereof shall have been paid.

3.           Miscellaneous.

(a)           The Credit Agreement, and the obligations of the Borrower thereunder and under the other Loan Documents, are hereby ratified and confirmed and shall remain in full force and effect according to their terms.  The Borrower acknowledges and confirms that as of the date

hereof the Borrower’s obligation to repay the outstanding principal amount of the Loans and reimburse the Issuers for any drawing on a Letter of Credit is unconditional and not subject to any offsets, defenses or counterclaims.  The Administrative Agent, each Syndication Agent, each Lender and the Borrower acknowledge and confirm that by entering into this Agreement, each party does not waive or release any term or condition of the Credit Agreement or any of the other Loan Documents or any of their rights or remedies under such Loan Documents or applicable Law or any of the obligations of such party thereunder.

(b)           The Borrower hereby represents and warrants as follows:

(i)           The Borrower has taken all necessary corporate action to authorize the execution, delivery and performance of this Agreement.

(ii)           This Agreement has been duly executed and delivered by the Borrower and constitutes the Borrower’s legal, valid and binding obligations, enforceable in accordance with its terms, except as such enforceability may be subject to (i) bankruptcy, insolvency, reorganization, fraudulent conveyance or transfer, moratorium or similar laws affecting creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).

(iii)           No consent, approval, authorization or order of, or filing, registration or qualification with, any court or governmental authority or third party is required in connection with the execution, delivery or performance by the Borrower of this Agreement.

(c)           The Borrower represents and warrants to the Lenders that (i) the representations and warranties of the Borrower set forth in Article V of the Credit Agreement are true and correct as of the date hereof with the same effect as if made on and as of the date hereof, except to the extent such representations and warranties expressly relate solely to an earlier date and (ii) no event has occurred and is continuing which constitutes a Default or an Unmatured Default.

(d)           This Agreement may be executed in any number of counterparts, each of which when so executed and delivered shall be an original, but all of which shall constitute one and the same instrument.  Delivery of an executed counterpart of this Agreement by telecopy or electronic mail shall be effective as an original and shall constitute a representation that an executed original shall be delivered.

(e)           THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

(f)           Upon and after the execution of this Agreement by each of the parties hereto, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement as modified hereby.  This Amendment shall constitute a Loan Document.

[remainder of page intentionally left blank]

Each of the parties hereto has caused a counterpart of this Agreement to be duly executed and delivered as of the date first above written.

BORROWER:	KANSAS CITY POWER & LIGHT COMPANY, a Missouri corporation By:  /s/ Kevin E. Bryant                                                                 Name:  Kevin E. Bryant                                                                 Title:    Vice President – Investor Relations and Treasurer
ADMINISTRATIVE AGENT	BANK OF AMERICA, N.A., as Administrative Agent By: /s/ Kelly Weaver                                                                 Name:  Kelly Weaver                                                       Title:    Assistant Vice President
LENDERS:	BANK OF AMERICA, N.A., as a Lender, an Issuer and Swing Line Lender By:  /s/ Patrick Martin                                                                 Name:  Patrick Martin                                                                 Title:    Director        WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Lender, Syndication Agent and an Issuer By:/s/ Allison Newman                                                                 Name: Allison Newman                                            Title:    Director     THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as a Lender and as an Issuer By: /s/ Chi-Cheng Chen                                                                 Name:  Chi-Cheng Chen                                            Title:     Vice President UNION BANK, N.A., as a Lender and Syndication Agent By: /s/ Susan K. Johnson                                                       Name:  Susan K. Johnson                                            Title:    Vice President                                                       BARCLAYS BANK PLC, as a Lender By: /s/ David Barton                                                                 Name:  David Barton                                                       Title:  Director                                                                 BNP PARIBAS, as a Lender By: /s/ Francis DeLaney                                                                 Name:  Francis DeLaney                                                       Title:  Managing Director                                                       By: /s/ Pasquale Perraglia                                                       Name:  Pasquale Perraglia                                            Title:  Vice President                                                                 GOLDMAN SACHS BANK USA. as a Lender By: /s/ Mark Walton                                                                 Name:  Mark Walton                                            Title:  Authorized Signatory
	JPMORGAN CHASE BANK, N.A as a Lender By: /s/ John E. Zur                                                       Name:  John E. Zur                                            Title:  Authorized Officer
	THE BANK OF NOVA SCOTIA as a Lender By: /s/ Thane Rattew                                                                 Name:  Thane Rattew                                                       Title:  Managing Director
	THE ROYAL BANK OF SCOTLAND plc, as a Lender By: /s/ Andrew N. Taylor                                                       Name:  Andrew N. Taylor                                                       Title:  Vice President
	U.S. Bank National Association, as a Lender By: /s/ Eric J. Cosgrove                                                                 Name:           Eric J. Cosgrove                                            Title:  Vice President
	SUNTRUST BANK, as a Lender By: /s/ Andrew Johnson                                                                 Name:  Andrew Johnson                                            Title:  Director
	KeyBank National Association as a Lender By: /s/ Craig A. Hanselman                                                                 Name:  Craig A. Hanselman                                                       Title:  Vice President
	The Bank of New York Mellon as a Lender By: /s/ Hussam S. Alsahlani                                                                 Name:  Hussam S. Alsahlani                                                       Title:  Vice President
	UMB BANK, N.A. As a Lender By: /s/ Robert P. Elbert                                                                 Name:  Robert P. Elbert                                                       Title:  Senior Vice President
	COMMERCE BANK as a Lender By: /s/ Aaron M. Siders                                                                 Name:  Aaron M. Siders                                            Title:  Vice President

SCHEDULE I

COMMITMENTS

Lender	Commitment
Bank of America, N.A.	$55,200,000
Wells Fargo Bank, National Association	$55,200,000
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$27,600,000
Union Bank, N.A.	$27,600,000
Barclays Bank PLC	$40,800,000
BNP Paribas	$40,800,000
Goldman Sachs Bank USA	$40,800,000
JPMorgan Chase Bank, N.A.	$40,800,000
The Bank of Nova Scotia	$40,800,000
The Royal Bank of Scotland plc	$40,800,000
U.S. Bank National Association	$40,800,000
SunTrust Bank	$38,400,000
KeyBank National Association	$36,000,000
The Bank of New York Mellon	$36,000,000
UMB Bank, N.A.	$24,000,000
Commerce Bank	$14,400,000
Total	$600,000,000

LETTER OF CREDIT COMMITMENTS

Issuer	Letter of Credit Commitment
Bank of America, N.A.	$25,000,000.00
Wells Fargo Bank, National Association	$25,000,000.00
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$25,000,000.00
Total	$75,000,000.00

EX-10.63

Exhibit 10.63

FIRST AMENDMENT TO CREDIT AGREEMENT

Dated as of December 9, 2011

among

KCP&L GREATER MISSOURI OPERATIONS COMPANY,

as the Borrower,

GREAT PLAINS ENERGY INCORPORATED,

as the Guarantor,

CERTAIN LENDERS,

UNION BANK, N.A. and

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Syndication Agents

and

BANK OF AMERICA, N.A.,

as Administrative Agent, Swing Line Lender and an Issuer

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

FIRST AMENDMENT TO CREDIT AGREEMENT

THIS FIRST AMENDMENT TO CREDIT AGREEMENT dated as of December 9, 2011 (this “Agreement”) is entered into among KCP&L Greater Missouri Operations Company, a Delaware corporation (the “Borrower”), Great Plains Energy Incorporated, a Missouri corporation (the “Guarantor”), the Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents and Bank of America, N.A., as Administrative Agent, Swing Line Lender and an Issuer.  All capitalized terms used herein and not otherwise defined herein shall have the meanings given to such terms in the Credit Agreement (as defined below).

RECITALS

WHEREAS, the Borrower, the Guarantor, the Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents and Bank of America, N.A., as Administrative Agent entered into that certain Credit Agreement dated as of August 9, 2010 (as amended or modified from time to time, the “Credit Agreement”);

WHEREAS, the Borrower has requested that the Lenders amend the Credit Agreement as set forth below;

NOW, THEREFORE, in consideration of the premises and the mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.           Amendments.  The Credit Agreement is hereby amended as follows:

(a)           The definition of “Administrative Agent’s Fee Letter” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Administrative Agent’s Fee Letter” means that certain fee letter dated November 10, 2011 among Bank of America, MLPFS, the Guarantor, the Borrower and KCPL.

(b)           The definition of “Aggregate Commitment” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Aggregate Commitment” means the aggregate of the Commitments of all Lenders, as changed from time to time pursuant to the terms hereof.  The amount of the Aggregate Commitment in effect as of the First Amendment Effective Date is FOUR HUNDRED AND FIFTY MILLION DOLLARS ($450,000,000).

(c)           The definition of “Change” in Section 1.1 of the Credit Agreement is hereby deleted in its entirety and the definition of “Change in Law” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Change in Law” means the occurrence, after the First Amendment Effective Date, of any of the following: (a) the adoption or taking effect of any law, rule, regulation or treaty, (b) any change in any law, rule, regulation or treaty or in the administration, interpretation, implementation or application thereof by any Governmental Authority or

(c) the making or issuance of any request, rules, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided, that, notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith 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 regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, adopted or issued.

(d)           The definition of “Facility Termination Date” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Facility Termination Date” means (a) the later of (i) December 9, 2016 and (ii) with respect to some or all of the Lenders if the facility termination date is extended pursuant to Section 2.21, such extended facility termination date or (b) any earlier date on which the Aggregate Commitment is reduced to zero or otherwise terminated pursuant to the terms hereof.

(e)           The definition of “Fee Letter” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“Fee Letter” means that certain fee letter dated November 10, 2011 among Bank of America, Wells Fargo, BTMU, the Arrangers, the Guarantor, the Borrower and KCPL.

(f)           The following definition is hereby added to Section 1.1 of the Credit Agreement in the appropriate alphabetical order to read as follows:

“First Amendment Effective Date” means December 9, 2011.

(g)           The definition of “BAS” is hereby deleted from Section 1.1 of the Credit Agreement in its entirety, each reference to “BAS” in the Credit Agreement is hereby amended to read “MLPFS” and the following definition is hereby added to Section 1.1 of the Credit Agreement in the appropriate alphabetical order to read as follows:

“MLPFS” means Merrill Lynch, Pierce, Fenner & Smith Incorporated, in its capacity as joint lead arranger and joint book manager.

(h)           The introductory paragraph and clause (i) of Section 3.1 of the Credit Agreement are hereby amended to read as follows:

If any Change in Law:

(i)           subjects any Lender or Issuer to any tax of any kind whatsoever with respect to this Agreement, any Letter of Credit, any participation in a Letter of Credit or any Eurodollar Loan made by it, or changes the basis of taxation of payments to such Lender or such Issuer in respect thereof (except for Indemnified Taxes or Other Taxes covered by Section 3.5 and the imposition of, or any change in the rate of, any Excluded Tax), or

(i)           Section 3.2 of the Credit Agreement is hereby amended to read as follows:

If a Lender or an Issuer determines the amount of capital required or expected to be maintained by such Lender, any Lending Installation of such Lender, such Issuer or any corporation controlling such Lender or such Issuer is increased as a result of a Change in Law, then, within thirty (30) days of written demand by such Lender or such Issuer, the Borrower shall pay such Lender or such Issuer the amount necessary to compensate for any shortfall in the rate of return on the portion of such increased capital which such Lender or such Issuer determines is attributable to this Agreement, its Outstanding Credit Exposure or its Commitment to make Loans or to issue or participate in Letters of Credit hereunder (after taking into account such Lender’s or such Issuer’s policies and the policies of any corporation controlling such Lender or such Issuer as to capital adequacy).

(j)           Section 3.3 of the Credit Agreement is hereby amended to read as follows:

If (i) any Lender determines, or any Governmental Authority has asserted, that making, funding or maintaining Loans whose interest is determined by reference to the Eurodollar Base Rate at a suitable Lending Installation, or determining or charging interest rates based on the Eurodollar Base Rate, would violate any applicable law, rule, regulation, or directive, whether or not having the force of law, enacted or imposed after the date of this Agreement, (ii) any Governmental Authority has imposed material restrictions on the authority of such Lender to purchase or sell, or to take deposits of, Dollars in the London interbank market, (iii) the Required Lenders determine that (a) deposits of a type and maturity appropriate to match fund Eurodollar Advances are not available or (b) the interest rate applicable to a Type of Advance does not accurately reflect the cost of making or maintaining such Advance or (iv) the Administrative Agent determines that adequate and reasonable means do not exist for determining the Eurodollar Base Rate, then the Administrative Agent shall suspend the availability of the affected Type of Advance (or, if such notice asserts the illegality of such Lender determining or charging interest rates based upon the Eurodollar Base Rate, the Administrative Agent shall during the period of such suspension compute the Alternate Base Rate applicable to such Lender without reference to the Eurodollar Base Rate component thereof until the Administrative Agent is advised in writing by such Lender that it is no longer illegal for such Lender to determine or charge interest rates based upon the Eurodollar Base Rate) and, in the case of clauses (i) and (ii), require any affected Eurodollar Advances to be repaid or converted to Floating Rate Advances, subject to the payment of any funding indemnification amounts required by Section 3.4.

(k)           Schedule I to the Credit Agreement is hereby amended to read as shown in Schedule I attached to this Agreement.

(l)           The pricing grid in Schedule III to the Credit Agreement is hereby amended to read as follows:

	>A-/A3	BBB+/Baa1	BBB/Baa2	BBB-/Baa3	BB+/Ba1	<BB/Ba2
Pricing	Level I Status	Level II Status	Level III Status	Level IV Status	Level V Status	Level VI Status
Applicable Margin for Eurodollar Advances and Letter of Credit Fee Rate	1.125%	1.25%	1.50%	1.75%	2.00%	2.25%
Commitment Fee Rate	0.125%	0.175%	0.225%	0.275%	0.375%	0.50%
Applicable Margin for Floating Rate Advances	0.125%	0.25%	0.50%	0.75%	1.00%	1.25%

2.           Conditions Precedent.  This Agreement shall be effective upon:

(a)           receipt by the Administrative Agent of counterparts of this Agreement duly executed by the Borrower, the Guarantor, the Administrative Agent and the Lenders;

(b)           the receipt by the Administrative Agent of the following, each of which shall be originals or facsimiles (followed promptly by originals), in form and substance satisfactory to the Administrative Agent:

(i)           copies of the Organization Documents of the Borrower and of the Guarantor certified to be true and complete as of a recent date by the appropriate Governmental Authority of the state or other jurisdiction of its incorporation or organization, where applicable, and certified by a secretary or assistant secretary of the Borrower or the Guarantor, as applicable, to be true and correct as of the date hereof;

(ii)           such certificates of resolutions and/or other certificates of Authorized Officers of each of the Borrower and the Guarantor as the Administrative Agent may require evidencing the identity, authority and capacity of each Authorized Officer thereof authorized to act as an Authorized Officer in connection with this Agreement; and

(iii)           such documents and certifications as the Administrative Agent may require to evidence that each of the Borrower and the Guarantor is duly organized or formed, and is validly existing, in good standing and qualified to engage in business in its state of organization or formation;

(c)           any portion of the Loans and Commitments held by a Person who is not executing this Agreement as a Lender shall have been assigned to a Person who is a Lender under the Credit Agreement (as amended by this Agreement).

(d)           the receipt by the Administrative Agent of favorable opinions of legal counsel to the Borrower and the Guarantor, addressed to the Administrative Agent and each Lender, dated as of the date hereof and in form and substance satisfactory to the Administrative Agent, addressing the execution, delivery and enforceability of this Agreement and other matters that were addressed in the opinion provided in connection with the original delivery of the Credit Agreement on August 9, 2010, with respect to this Agreement; and

(e)           all fees required to be paid to the Administrative Agent, the Arrangers and the Lenders pursuant to the Fee Letter and the Administrative Agent’s Fee Letter on or before the date hereof shall have been paid.

3.           Miscellaneous.

(a)           The Credit Agreement, and the obligations of the Borrower and the Guarantor thereunder and under the other Loan Documents, are hereby ratified and confirmed and shall

remain in full force and effect according to their terms.  The Borrower and the Guarantor acknowledge and confirm that as of the date hereof the Borrower’s obligation to repay the outstanding principal amount of the Loans and reimburse the Issuers for any drawing on a Letter of Credit is unconditional and not subject to any offsets, defenses or counterclaims.  The Administrative Agent, each Syndication Agent, each Lender, the Borrower and the Guarantor acknowledge and confirm that by entering into this Agreement, each party does not waive or release any term or condition of the Credit Agreement or any of the other Loan Documents or any of their rights or remedies under such Loan Documents or applicable Law or any of the obligations of such party thereunder.

(b)           The Borrower and the Guarantor hereby represent and warrant as follows:

(i)           The Borrower and the Guarantor have taken all necessary corporate action to authorize the execution, delivery and performance of this Agreement.

(ii)           This Agreement has been duly executed and delivered by each of the Borrower and the Guarantor and constitutes the Borrower’s and the Guarantor’s legal, valid and binding obligations, enforceable in accordance with its terms, except as such enforceability may be subject to (i) bankruptcy, insolvency, reorganization, fraudulent conveyance or transfer, moratorium or similar laws affecting creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).

(iii)           No consent, approval, authorization or order of, or filing, registration or qualification with, any court or governmental authority or third party is required in connection with the execution, delivery or performance by the Borrower or the Guarantor of this Agreement.

(c)           The Borrower and the Guarantor represent and warrant to the Lenders that (i) the representations and warranties of the Borrower and the Guarantor set forth in Article VI of the Credit Agreement are true and correct as of the date hereof with the same effect as if made on and as of the date hereof, except to the extent such representations and warranties expressly relate solely to an earlier date and (ii) no event has occurred and is continuing which constitutes a Default or an Unmatured Default.

(d)           The Guarantor (a) acknowledges and consents to all of the terms and conditions of this Agreement, (b) affirms all of its obligations under the Loan Documents and (c) agrees that this Agreement and all documents executed in connection herewith do not operate to reduce or discharge its obligations under the Credit Agreement or the other Loan Documents except as expressly set forth herein.

(e)           This Agreement may be executed in any number of counterparts, each of which when so executed and delivered shall be an original, but all of which shall constitute one and the same instrument.  Delivery of an executed counterpart of this Agreement by telecopy or electronic mail shall be effective as an original and shall constitute a representation that an executed original shall be delivered.

(f)           THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

(g)           Upon and after the execution of this Agreement by each of the parties hereto, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement as modified hereby.  This Amendment shall constitute a Loan Document.

[remainder of page intentionally left blank]

Each of the parties hereto has caused a counterpart of this Agreement to be duly executed and delivered as of the date first above written.

BORROWER:	KCP&L GREATER MISSOURI OPERATIONS COMPANY, a Delaware corporation By:  /s/ Kevin E. Bryant                                                                 Name:  Kevin E. Bryant                                                                 Title:    Vice President – Investor Relations and Treasurer
GUARANTOR:	GREAT PLAINS ENERGY INCORPORATED, a Missouri corporation By:  /s/ Kevin E. Bryant                                                                 Name:  Kevin E. Bryant                                                                 Title:   Vice President – Investor Relations and Treasurer
ADMINISTRATIVE AGENT	BANK OF AMERICA, N.A., as Administrative Agent By: /s/ Kelly Weaver                                                                 Name:  Kelly Weaver                                                       Title:    Assistant Vice President
LENDERS:	BANK OF AMERICA, N.A., as a Lender, an Issuer and Swing Line Lender By:  /s/ Patrick Martin                                                                 Name:  Patrick Martin                                                                 Title:    Director        WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Lender, Syndication Agent and an Issuer By:/s/ Allison Newman                                                                 Name: Allison Newman                                            Title:    Director     THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as a Lender and as an Issuer By: /s/ Chi-Cheng Chen                                                                 Name:  Chi-Cheng Chen                                            Title:     Vice President UNION BANK, N.A., as a Lender and Syndication Agent By: /s/ Susan K. Johnson                                                       Name:  Susan K. Johnson                                            Title:    Vice President                                                       BARCLAYS BANK PLC, as a Lender By: /s/ David Barton                                                                 Name:  David Barton                                                       Title:  Director                                                                 BNP PARIBAS, as a Lender By: /s/ Francis DeLaney                                                                 Name:  Francis DeLaney                                                       Title:  Managing Director                                                       By: /s/ Pasquale Perraglia                                                       Name:  Pasquale Perraglia                                            Title:  Vice President                                                                 GOLDMAN SACHS BANK USA. as a Lender By: /s/ Mark Walton                                                                 Name:  Mark Walton                                            Title:  Authorized Signatory
	JPMORGAN CHASE BANK, N.A as a Lender By: /s/ John E. Zur                                                       Name:  John E. Zur                                            Title:  Authorized Officer
	THE BANK OF NOVA SCOTIA as a Lender By: /s/ Thane Rattew                                                                 Name:  Thane Rattew                                                       Title:  Managing Director
	THE ROYAL BANK OF SCOTLAND plc, as a Lender By: /s/ Andrew N. Taylor                                                       Name:  Andrew N. Taylor                                                       Title:  Vice President
	U.S. Bank National Association, as a Lender By: /s/ Eric J. Cosgrove                                                                 Name:           Eric J. Cosgrove                                            Title:  Vice President
	SUNTRUST BANK, as a Lender By: /s/ Andrew Johnson                                                                 Name:  Andrew Johnson                                            Title:  Director
	KeyBank National Association as a Lender By: /s/ Craig A. Hanselman                                                                 Name:  Craig A. Hanselman                                                       Title:  Vice President
	The Bank of New York Mellon as a Lender By: /s/ Hussam S. Alsahlani                                                                 Name:  Hussam S. Alsahlani                                                       Title:  Vice President
	UMB BANK, N.A. As a Lender By: /s/ Robert P. Elbert                                                                 Name:  Robert P. Elbert                                                       Title:  Senior Vice President
	COMMERCE BANK as a Lender By: /s/ Aaron M. Siders                                                                 Name:  Aaron M. Siders                                            Title:  Vice President

SCHEDULE I

COMMITMENTS

Lender	Commitment
Bank of America, N.A.	$41,400,000
Wells Fargo Bank, National Association	$41,400,000
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$20,700,000
Union Bank, N.A.	$20,700,000
Barclays Bank PLC	$30,600,000
BNP Paribas	$30,600,000
Goldman Sachs Bank USA	$30,600,000
JPMorgan Chase Bank, N.A.	$30,600,000
The Bank of Nova Scotia	$30,600,000
The Royal Bank of Scotland plc	$30,600,000
U.S. Bank National Association	$30,600,000
SunTrust Bank	$28,800,000
KeyBank National Association	$27,000,000
The Bank of New York Mellon	$27,000,000
UMB Bank, N.A.	$18,000,000
Commerce Bank	$10,800,000
Total	$450,000,000

LETTER OF CREDIT COMMITMENTS

Issuer	Letter of Credit Commitment
Bank of America, N.A.	$16,666,666.67
Wells Fargo Bank, National Association	$16,666,666.67
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$16,666,666.66
Total	$50,000,000.00

EX-12.1

											Exhibit 12.1
GREAT PLAINS ENERGY INCORPORATED
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
		2011		2010		2009		2008			2007
		(millions)
Income from continuing operations		$	174.2	$	211.9	$	151.9	$	119.7		$	120.9
Add
Equity investment loss			0.1		1.0		0.4		1.3			2.0
	Income subtotal		174.3		212.9		152.3		121.0			122.9
Add
Taxes on income			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		84.8		99.1		29.9		64.1			45.4
Interest on value of leased property			5.9		6.2		6.5		3.6			3.9
Interest on long-term debt			223.2		218.9		203.6		126.2			74.1
Interest on short-term debt			11.8		9.7		10.3		18.2			26.4
Other interest expense and amortization (a)			11.6		9.7		4.7		(1.4	)		5.8
	Total fixed charges		252.5		244.5		225.1		146.6			110.2
Earnings before taxes on
	income and fixed charges	$	511.6	$	556.5	$	407.3	$	331.7		$	278.5
Ratio of earnings to fixed charges			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
		2011		2010		2009		2008		2007
		(millions)
Income from continuing operations		$	135.5	$	163.2	$	128.9	$	125.2	$	156.7
Add
Taxes on income			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		69.1		81.7		47.1		60.3		59.8
Interest on value of leased property			5.4		5.7		6.0		3.3		3.9
Interest on long-term debt			118.5		117.9		110.4		79.3		54.5
Interest on short-term debt			5.1		3.9		5.3		15.2		20.3
Other interest expense and amortization (a)			5.8		4.2		0.3		1.4		6.8
	Total fixed charges		134.8		131.7		122.0		99.2		85.5
Earnings before taxes on
	income and fixed charges	$	339.4	$	376.6	$	298.0	$	284.7	$	302.0
Ratio of earnings to fixed charges			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-21.1

Exhibit 21.1

Subsidiaries of Great Plains Energy Incorporated (1)

Name of Company	State of Incorporation
Kansas City Power & Light Company	Missouri
KCP&L Greater Missouri Operations Company	Delaware

(1)  Certain subsidiaries of Great Plains Energy Incorporated have been omitted pursuant to Item 601(b)(21)(ii) of Regulation S-K.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-159131 and 333-159141 on Form S-3, and Registration Statement Nos. 333-132828, 333-147939, 333-152313 and 333-176840 on Form S-8 of our reports dated February 28, 2012, relating to the consolidated financial statements and financial statement schedules of Great Plains Energy Incorporated and subsidiaries, and the effectiveness of Great Plains Energy Incorporated and subsidiaries' internal control over financial reporting, appearing in the Annual Report on Form 10-K of Great Plains Energy Incorporated for the year ended December 31, 2011.

/s/DELOITTE & TOUCHE LLP

Kansas City, Missouri

February 28, 2012

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-159131 on Form S-3 of our reports dated February 28, 2012, relating to the consolidated financial statements and financial statement schedule of Kansas City Power & Light Company and subsidiaries, and the effectiveness of Kansas City Power & Light Company and subsidiaries' internal control over financial reporting, appearing in the Annual Report on Form 10-K of Kansas City Power & Light Company for the year ended December 31, 2011.

/s/DELOITTE & TOUCHE LLP

Kansas City, Missouri

February 28, 2012

EX-24.1

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Great Plains Energy Incorporated, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K, and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ David. L. Bodde                                                         

David L. Bodde

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared David L. Bodde, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Great Plains Energy Incorporated, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ Gary D. Forsee

Gary D. Forsee

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared Gary D. Forsee, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Great Plains Energy Incorporated, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ Randall C. Ferguson, Jr.

Randall C. Ferguson, Jr.

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared Randall C. Ferguson, Jr., to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Great Plains Energy Incorporated, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ John J. Sherman

John J. Sherman

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared John J. Sherman, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Great Plains Energy Incorporated, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ James A. Mitchell

James A. Mitchell

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared James A. Mitchell, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Great Plains Energy Incorporated, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ William C. Nelson

William C. Nelson

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared William C. Nelson, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Great Plains Energy Incorporated, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ Linda H. Talbott

Linda H. Talbott

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared Linda H. Talbott, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Great Plains Energy Incorporated, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ Robert H. West

Robert H. West

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared Robert H. West, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Great Plains Energy Incorporated, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ Thomas D. Hyde

Thomas D. Hyde

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared Thomas D. Hyde, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

EX-24.2

Exhibit 24.2

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Kansas City Power & Light Company, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ David L. Bodde

David L. Bodde

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared David L. Bodde, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.2

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Kansas City Power & Light Company, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ Randall C. Ferguson, Jr.

Randall C. Ferguson, Jr.

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared Randall C. Ferguson, Jr., to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.2

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Kansas City Power & Light Company, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ Gary D. Forsee

Gary D. Forsee

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared Gary D. Forsee, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.2

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Kansas City Power & Light Company, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ John J. Sherman

John J. Sherman

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared John J. Sherman, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.2

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Kansas City Power & Light Company, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ James A. Mitchell

James A. Mitchell

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared James A. Mitchell, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.2

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Kansas City Power & Light Company, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ William C. Nelson

William C. Nelson

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared William C. Nelson, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.2

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Kansas City Power & Light Company, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ Linda H. Talbott

Linda H. Talbott

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared Linda H. Talbott, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

Exhibit 24.2

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS:

          That the undersigned, a Director of Kansas City Power & Light Company, a Missouri corporation, does hereby constitute and appoint Michael J. Chesser or Jaileah X. Huddleston, his true and lawful attorney and agent, with full power and authority to execute in the name and on behalf of the undersigned as such director an Annual Report on Form 10-K and any amendments thereto, hereby granting unto such attorney and agent full power of substitution and revocation in the premises; and hereby ratifying and confirming all that such attorney and agent may do or cause to be done by virtue of these presents.

          IN WITNESS WHEREOF, I have hereunto set my hand and seal this 7th day of February 2012.

/s/ Thomas D. Hyde

Thomas D. Hyde

STATE OF MISSOURI   COUNTY OF JACKSON ) ) )   ss

          On this 7th day of February 2012, before me the undersigned, a Notary Public, personally appeared Thomas D. Hyde, to be known to be the person described in and who executed the foregoing instrument, and who, being by me first duly sworn, acknowledged that he/she executed the same as his/her free act and deed.

          IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal the day and year last above written.

/s/ Annette G. Carter

Notary Public

My Commission Expires:

October 6, 2013

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Michael J. Chesser, certify that:

1.	I have reviewed this annual report on Form 10-K 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:	February 28, 2012	/s/ Michael J. Chesser
		Michael J. Chesser Chairman of the Board and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, James C. Shay, certify that:

1.	I have reviewed this annual report on Form 10-K 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:	February 28, 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, Michael J. Chesser, certify that:

1.	I have reviewed this annual report on Form 10-K 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:	February 28, 2012	/s/ Michael J. Chesser
		Michael J. Chesser Chairman of the Board and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, James C. Shay, certify that:

1.	I have reviewed this annual report on Form 10-K 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:	February 28, 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 Annual Report on Form 10-K of Great Plains Energy Incorporated (the "Company") for the annual period ended December 31, 2011, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Michael J. Chesser, as Chairman of the Board and Chief Executive Officer of the Company, and James C. Shay, as Senior Vice President - Finance and Strategic Development and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

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

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

	/s/ Michael J. Chesser
Name: Title:	Michael J. Chesser Chairman of the Board and Chief Executive Officer
Date:	February 28, 2012
	/s/ James C. Shay
Name: Title:	James C. Shay Senior Vice President – Finance and Strategic Development and Chief Financial Officer
Date:	February 28, 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 Annual Report on Form 10-K of Kansas City Power & Light Company (the "Company") for the annual period ended December 31, 2011, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Michael J. Chesser, as Chairman of the Board and Chief Executive Officer of the Company, and James C. Shay, as Senior Vice President – Finance and Strategic Development and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

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

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

	/s/ Michael J. Chesser
Name: Title:	Michael J. Chesser Chairman of the Board and Chief Executive Officer
Date:	February 28, 2012
	/s/ James C. Shay
Name: Title:	James C. Shay Senior Vice President – Finance and Strategic Development and Chief Financial Officer
Date:	February 28, 2012

XML

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Regulatory Matters [Abstract]

Regulatory assets

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

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

Regulatory liabilities

Regulatory Liabilities
Emission allowances	$	82.0	$	0.2		$	82.2
Asset retirement obligations		49.3		-			49.3
Pension		0.7		40.8			41.5
Cost of removal		-		61.9	(i)		61.9
Other		10.8		22.8			33.6
Total	$	142.8	$	125.7		$	268.5

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

(b) Represents unrecognized gains and losses, prior service and transition costs that will be recognized in future net periodic pension and post-retirement costs, pension settlements amortized over various periods and financial and regulatory accounting method differences not included in rate base that will be eliminated over the life of the pension plans.

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

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

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

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

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

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

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

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

XML

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

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Fair value of assets and liabilities

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

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

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

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

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

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

Unobservable inputs reconciliation

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other
	Great
	Plains
	Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains
included in non-operating income		10.9
Settlements		(11.5	)
Balance December 31, 2011	$	3.1
Total unrealized losses included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at December 31, 2011	$	(0.2	)

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other
				Great			Great
				Plains			Plains
	KCP&L			Energy			Energy
	State & Local			Derivative
	Obligations			Instruments			Total
	(millions)
Balance January 1, 2010	$	0.2		$	4.1		$	4.3
Total realized/unrealized losses
included in non-operating income		-			(12.5	)		(12.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			12.1			12.1
Balance December 31, 2010	$	-		$	3.7		$	3.7
Total unrealized gains included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at December 31, 2010	$	-		$	0.1		$	0.1

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Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	May 31, 2011	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011 Futures contracts [Member] Cash Flow Hedging [Member]	Dec. 31, 2010 Futures contracts [Member] Cash Flow Hedging [Member]	Dec. 31, 2011 Futures contracts [Member] Not Designated as Hedging Instrument [Member]	Dec. 31, 2010 Futures contracts [Member] Not Designated as Hedging Instrument [Member]	Dec. 31, 2011 Forward Contracts [Member] Not Designated as Hedging Instrument [Member]	Dec. 31, 2010 Forward Contracts [Member] Not Designated as Hedging Instrument [Member]	Dec. 31, 2011 Option contracts [Member] Not Designated as Hedging Instrument [Member]	Dec. 31, 2010 Option contracts [Member] Not Designated as Hedging Instrument [Member]	Dec. 31, 2011 Anticipated debt issuance [Member] Forward Starting Swaps [Member]	Dec. 31, 2010 Anticipated debt issuance [Member] Forward Starting Swaps [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Futures contracts [Member] Cash Flow Hedging [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Futures contracts [Member] Cash Flow Hedging [Member]
Interest Rate Risk Management [Abstract]
Amount of long-term debt issued	$ 350.0
Loss recorded in other comprehensive income on forward starting swaps settled with debt issue					26.1
Reclassification period for loss recorded in other comprehensive income (in years)					three years
Amount of loss reclassified from other comprehensive income to interest expense.					5.4
Commodity Risk Management [Abstract]
Percentage of projected natural gas usage hedged at KCPL (in hundredths)		13.00%	56.00%	66.00%
Percentage of expected on-peak natural gas and natural gas equivalent purchased power price exposure that is hedged at GMO (in hundredths)		38.00%	38.00%	45.00%
Notional Contract Amount						2.0	4.0	23.6	59.5	97.3	202.8	0.4	0.2	0	350.0	2.0	4.0
Fair Value						$ (0.5)	$ 0	$ (5.0)	$ (2.5)	$ 7.8	$ 8.9	$ 0	$ 0	$ 0	$ (20.8)	$ (0.5)	$ 0

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Receivables (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (2.5)		$ (2.7)
Receivables, net	231.2		241.7
Statement [Line Items]
Accounts receivables pledged as collateral	95.0		95.0
Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	(1.4)		(1.5)
Receivables, net	172.9		169.4
Statement [Line Items]
Accounts receivables pledged as collateral	95.0		95.0
Maximum percentage servicing fee received on receivables sold (in hundredths)	1.50%
Maximum amount of outstanding principal under receivables agreement	110.0
Accounts Receivable Sold [Line Items]
Receivables (sold) purchased	0		0
Gain (loss) on sale of accounts receivable	(0.2)	[1]	(0.2)	[1]
Servicing fees	0		0
Fees to outside investor	(1.2)		(1.2)
Cash flows during the period [Abstract]
Cash from customers transferred to Receivables Company	0		0
Cash paid to KCP and L for receivables purchased	0		0
Interest on intercompany note	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	(1,415.6)		(1,341.0)
Gain (loss) on sale of accounts receivable	(17.9)	[1]	(17.0)	[1]
Servicing fees	2.6		3.2
Fees to outside investor	0		0
Cash flows during the period [Abstract]
Cash from customers transferred to Receivables Company	(1,412.4)		(1,337.4)
Cash paid to KCP and L for receivables purchased	1,394.7		1,320.7
Interest on intercompany note	0.5		0.5
Kansas City Power and Light Company [Member] | Receivables Company [Member]
Accounts Receivable Sold [Line Items]
Receivables (sold) purchased	1,415.6		1,341.0
Gain (loss) on sale of accounts receivable	17.7	[1]	16.8	[1]
Servicing fees	(2.6)		(3.2)
Fees to outside investor	(1.2)		(1.2)
Cash flows during the period [Abstract]
Cash from customers transferred to Receivables Company	1,412.4		1,337.4
Cash paid to KCP and L for receivables purchased	(1,394.7)		(1,320.7)
Interest on intercompany note	(0.5)		(0.5)
Trade Accounts Receivable [Member] | Billed Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	69.8		62.0
Trade Accounts Receivable [Member] | Billed Revenues [Member] | Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	16.4		6.5
Trade Accounts Receivable [Member] | Unbilled Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	82.4		82.3
Trade Accounts Receivable [Member] | Unbilled Revenues [Member] | Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	50.0		50.1
Other Receivables [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	81.5		100.1
Other Receivables [Member] | Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	69.2		71.1
Intercompany Receivables [Member] | Kansas City Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, Gross, Current	$ 38.7		$ 43.2

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

XML

Quarterly Operating Results (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010
Operating revenue	$ 486.3	$ 773.7	$ 565.1	$ 492.9	$ 467.8	$ 728.8	$ 552.0	$ 506.9	$ 2,318.0	$ 2,255.5	$ 1,965.0
Operating income	60.3	262.7	115.6	41.2	31.6	243.8	134.9	62.0	479.8	472.3	320.1
Net income (loss)	1.9	126.6	43.4	2.3	(4.8)	132.0	64.4	20.3	174.2	211.9	150.4
Net income (loss) attributable to Great Plains Energy	2.1	126.5	43.4	2.4	(4.9)	132.0	64.3	20.3	174.4	211.7	150.1
Basic earnings (loss) per common share	$ 0.01	$ 0.93	$ 0.32	$ 0.02	$ (0.04)	$ 0.97	$ 0.47	$ 0.15	$ 1.27	$ 1.55	$ 1.15
Diluted earnings (loss) per common share	$ 0.01	$ 0.91	$ 0.31	$ 0.01	$ (0.04)	$ 0.96	$ 0.47	$ 0.15	$ 1.25	$ 1.53	$ 1.14
Disallowed construction costs on Iatan Nos 1 and 2					12.8	4.0
Pre-tax impairment loss on investments in affordable housing limited partnerships										11.2
Kansas City Power and Light Company [Member]
Operating revenue	337.8	506.3	383.4	330.8	322.4	486.5	372.6	335.6	1,558.3	1,517.1	1,318.2
Operating income	47.7	169.2	77.8	26.5	22.6	163.6	84.7	40.5	321.2	311.4	232.2
Net income (loss)	$ 12.7	$ 85.4	$ 33.4	$ 4.0	$ 3.2	$ 92.6	$ 48.2	$ 19.2	$ 135.5	$ 163.2	$ 128.9

XML

Related Party Transactions and Relationships (Tables)

12 Months Ended

Dec. 31, 2011

Related Party Transactions and Relationships [Abstract]

Schedule of related party receivables and payables

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

XML

Schedule II Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2011

Schedule II Valuation and Qualifying Accounts [Abstract]

Schedule II Valuation and Qualifying Accounts

GREAT PLAINS ENERGY INCORPORATED

NOTES TO FINANCIAL STATEMENTS OF PARENT COMPANY

The Great Plains Energy Incorporated Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Great Plains Energy Incorporated Parent Company Financial Statements.

Schedule II – Valuation and Qualifying Accounts and Reserves

Great Plains Energy Incorporated
Valuation and Qualifying Accounts
Years Ended December 31, 2011, 2010 and 2009
				Additions
				Charged
		Balance At		To Costs			Charged						Balance
		Beginning		And			To Other						At End
	Description	Of Period		Expenses			Accounts			Deductions			Of Period
Year Ended December 31, 2011		(millions)
	Allowance for uncollectible accounts	$	7.0	$	13.7		$	6.9	(a)	$	20.8	(b)	$	6.8
	Legal reserves		10.2		(0.1	)		-			3.4	(c)		6.7
	Environmental reserves		2.5		-			-			-			2.5
	Tax valuation allowance		26.6		0.1			-			2.8	(d)		23.9
Year Ended December 31, 2010
	Allowance for uncollectible accounts	$	7.1	$	9.7		$	6.9	(a)	$	16.7	(b)	$	7.0
	Legal reserves		5.1		7.0			-			1.9	(c)		10.2
	Environmental reserves		2.4		0.1			-			-			2.5
	Tax valuation allowance		29.8		0.2			-			3.4	(d)		26.6
Year Ended December 31, 2009
	Allowance for uncollectible accounts	$	6.8	$	8.7		$	6.0	(a)	$	14.4	(b)	$	7.1
	Legal reserves		10.2		2.6			-			7.7	(c)		5.1
	Environmental reserves		0.5		2.0			-			0.1			2.4
	Tax valuation allowance		75.8		57.0			-			103.0	(d)		29.8
(a)	Recoveries.
(b)	Uncollectible accounts charged off.
(c)	Payment of claims.
(d)	Reversal of tax valuation allowance.

Kansas City Power & Light Company
Valuation and Qualifying Accounts
Years Ended December 31, 2011, 2010 and 2009
				Additions
				Charged
		Balance At		To Costs		Charged						Balance
		Beginning		And		To Other						At End
	Description	Of Period		Expenses		Accounts			Deductions			Of Period
Year Ended December 31, 2011		(millions)
	Allowance for uncollectible accounts	$	1.5	$	8.8	$	4.5	(a)	$	13.4	(b)	$	1.4
	Legal reserves		3.0		1.3		-			0.4	(c)		3.9
	Environmental reserves		0.3		-		-			-			0.3
Year Ended December 31, 2010
	Allowance for uncollectible accounts	$	1.7	$	6.2	$	4.3	(a)	$	10.7	(b)	$	1.5
	Legal reserves		2.3		1.9		-			1.2	(c)		3.0
	Environmental reserves		0.3		-		-			-			0.3
Year Ended December 31, 2009
	Allowance for uncollectible accounts	$	1.2	$	5.5	$	3.9	(a)	$	8.9	(b)	$	1.7
	Legal reserves		2.4		1.2		-			1.3	(c)		2.3
	Environmental reserves		0.3		-		-			-			0.3
(a)	Recoveries.
(b)	Uncollectible accounts charged off.
(c)	Payment of claims.

XML

Schedule I Financial Statements of Parent Company (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010	Dec. 31, 2009	Dec. 31, 2008
Operating Expenses
Selling, general and administrative									$ 5.9	$ 22.1	$ 14.4
Maintenance									0	0	0.2
General taxes									170.9	155.1	139.8
Total									1,838.2	1,783.2	1,644.9
Operating loss	60.3	262.7	115.6	41.2	31.6	243.8	134.9	62.0	479.8	472.3	320.1
Equity in earnings from subsidiaries									200.8	239.3	174.7
Non-operating income									5.9	43.9	49.5
Interest charges									(218.4)	(184.8)	(180.9)
Income from continuing operations before income tax									259.1	311.9	181.8
Income tax (expense) benefit									(84.8)	(99.0)	(29.5)
Income from continuing operations									174.2	211.9	151.9
Equity in earnings (loss) from discontinued subsidiary									0	0	(1.5)
Net income (loss) attributable to Great Plains Energy	2.1	126.5	43.4	2.4	(4.9)	132.0	64.3	20.3	174.4	211.7	150.1
Preferred stock dividend requirements									1.6	1.6	1.6
Earnings available for common shareholders									172.8	210.1	148.5
Average number of basic common shares outstanding									135.6	135.1	129.3
Average number of diluted common shares outstanding									138.7	136.9	129.8
Basic earnings (loss) per common share
Continuing operations									$ 1.27	$ 1.55	$ 1.16
Discontinued operations									$ 0.00	$ 0.00	$ (0.01)
Basic earnings per common share	$ 0.01	$ 0.93	$ 0.32	$ 0.02	$ (0.04)	$ 0.97	$ 0.47	$ 0.15	$ 1.27	$ 1.55	$ 1.15
Diluted earnings (loss) per common share
Continuing operations									$ 1.25	$ 1.53	$ 1.15
Discontinued operations									$ 0.00	$ 0.00	$ (0.01)
Diluted earnings per common share	$ 0.01	$ 0.91	$ 0.31	$ 0.01	$ (0.04)	$ 0.96	$ 0.47	$ 0.15	$ 1.25	$ 1.53	$ 1.14
Cash dividends per common share									$ 0.835	$ 0.83	$ 0.83
Current Assets
Cash and cash equivalents	6.2				10.8				6.2	10.8			61.1
Taxes receivable	0.3				2.1				0.3	2.1
Total	619.1				611.6				619.1	611.6
Investments and Other Assets
Other	76.1				84.3				76.1	84.3
Total	1,445.4				1,314.3				1,445.4	1,314.3
Total	9,118.0				8,818.2				9,118.0	8,818.2		8,482.8
Current Liabilities
Current maturities of long-term debt	801.4				485.7				801.4	485.7
Accounts payable	275.6				276.3				275.6	276.3
Accrued taxes	25.8				26.6				25.8	26.6
Accrued interest	76.9				75.4				76.9	75.4
Derivative instruments	0				20.8				0	20.8
Other	26.0				35.6				26.0	35.6
Total	1,634.9				1,339.3				1,634.9	1,339.3
Deferred Credits and Other Liabilities
Other	101.1				129.4				101.1	129.4
Total	1,740.9				1,610.1				1,740.9	1,610.1
Common shareholders' equity
Common stock-250,000,000 shares authorized without par value 136,113,954 and 135,636,538 shares issued, stated value	2,330.6				2,324.4				2,330.6	2,324.4
Retained earnings	684.7				626.5				684.7	626.5
Treasury stock-264,567 and 400,889 shares, at cost	(5.6)				(8.9)				(5.6)	(8.9)
Accumulated other comprehensive loss	(49.8)				(56.1)				(49.8)	(56.1)
Total	2,959.9				2,885.9				2,959.9	2,885.9		2,792.5
Cumulative preferred stock $100 par value
3.8% - 100,000 shares issued	10.0				10.0				10.0	10.0
4.50% - 100,000 shares issued	10.0				10.0				10.0	10.0
4.20% - 70,000 shares issued	7.0				7.0				7.0	7.0
4.35% - 120,000 shares issued	12.0				12.0				12.0	12.0
Total	39.0				39.0				39.0	39.0
Long-term debt	2,742.3				2,942.7				2,742.3	2,942.7
Total	5,742.2				5,868.8				5,742.2	5,868.8
Commitments and Contingencies
Total	9,118.0				8,818.2				9,118.0	8,818.2
Cash Flows from Operating Activities
Net income	1.9	126.6	43.4	2.3	(4.8)	132.0	64.4	20.3	174.2	211.9	150.4
Adjustments to reconcile income to net cash from operating activities:
Amortization									11.2	3.9	1.9
Deferred income taxes, net									111.2	123.8	(3.6)
Equity in earnings from subsidiaries									(200.8)	(239.3)	(174.7)
Equity in (earnings) loss from discontinued subsidiary									0	0	1.5
Cash flows affected by changes in:
Accounts receivable from subsidiaries									0	(2.6)	3.7
Taxes receivable									6.3	0	4.8
Accounts payable to subsidiaries									(0.3)	2.2	0.2
Other accounts payable									0	(0.1)	0.1
Accrued taxes									1.4	6.7	42.2
Accrued interest									1.5	2.9	2.9
Cash dividends from subsidiaries									148.0	138.6	94.0
Other									(27.1)	(28.3)	9.0
Net cash from operating activities									443.0	552.1	335.4
Cash Flows from Investing Activities
Equity contributions to subsidiaries									0	0	(455.0)
Intercompany lending									(347.4)	(248.8)	0
Net cash from investing activities									(485.7)	(657.7)	(897.6)
Cash Flows from Financing Activities
Issuance of common stock									5.9	6.2	219.9
Issuance of long-term debt									747.1	249.9	700.7
Issuance fees									10.7	12.1	22.8
Net change in short-term borrowings									16.0	(165.6)	(145.6)
Dividends paid									115.1	114.2	110.5
Other financing activities									(6.6)	(7.4)	(4.0)
Net cash from financing activities									38.1	50.5	567.0
Net Change in Cash and Cash Equivalents									(4.6)	(55.1)	4.8
Cash and Cash Equivalents at Beginning of Year				10.8				65.9		65.9			61.1
Cash and Cash Equivalents at End of Year	6.2				10.8				6.2	10.8			61.1
Parent Company [Member]
Operating Expenses
Selling, general and administrative									0.8	1.2	8.8
Maintenance									0	0	0.2
General taxes									0.9	0.9	1.1
Total									1.7	2.1	10.1
Operating loss									(1.7)	(2.1)	(10.1)
Equity in earnings from subsidiaries									200.8	239.3	174.7
Non-operating income									24.7	3.4	0
Interest charges									(66.5)	(44.7)	(28.2)
Income from continuing operations before income tax									157.3	195.9	136.4
Income tax (expense) benefit									17.1	15.8	15.2
Income from continuing operations									174.4	211.7	151.6
Equity in earnings (loss) from discontinued subsidiary									0	0	(1.5)
Net income (loss) attributable to Great Plains Energy									174.4	211.7	150.1
Preferred stock dividend requirements									1.6	1.6	1.6
Earnings available for common shareholders									172.8	210.1	148.5
Average number of basic common shares outstanding									135.6	135.1	129.3
Average number of diluted common shares outstanding									138.7	136.9	129.8
Basic earnings (loss) per common share
Continuing operations									$ 1.27	$ 1.55	$ 1.16
Discontinued operations									$ 0.00	$ 0.00	$ (0.01)
Basic earnings per common share									$ 1.27	$ 1.55	$ 1.15
Diluted earnings (loss) per common share
Continuing operations									$ 1.25	$ 1.53	$ 1.15
Discontinued operations									$ 0.00	$ 0.00	$ (0.01)
Diluted earnings per common share									$ 1.25	$ 1.53	$ 1.14
Cash dividends per common share									$ 0.835	$ 0.83	$ 0.83
Current Assets
Cash and cash equivalents	0				0.3				0	0.3			12.0
Notes receivable from subsidiaries	0.6				249.4				0.6	249.4
Money pool receivable	0.9				2.0				0.9	2.0
Taxes receivable	0.9				7.2				0.9	7.2
Other	0.6				0.7				0.6	0.7
Total	3.0				259.6				3.0	259.6
Investments and Other Assets
Investment in KCP and L	2,045.5				2,005.0				2,045.5	2,005.0
Investments in other subsidiaries	1,377.0				1,360.2				1,377.0	1,360.2
Notes receivable from subsidiaries	596.2				0				596.2	0
Deferred income taxes	33.7				7.2				33.7	7.2
Other	6.4				6.2				6.4	6.2
Total	4,058.8				3,378.6				4,058.8	3,378.6
Total	4,061.8				3,638.2				4,061.8	3,638.2
Current Liabilities
Notes payable	22.0				9.5				22.0	9.5
Current maturities of long-term debt	287.5				0				287.5	0
Accounts payable to subsidiaries	31.8				31.1				31.8	31.1
Accrued taxes	5.1				0				5.1	0
Accrued interest	7.6				6.4				7.6	6.4
Derivative instruments	0				20.8				0	20.8
Other	2.9				7.1				2.9	7.1
Total	356.9				74.9				356.9	74.9
Deferred Credits and Other Liabilities
Other	6.7				1.4				6.7	1.4
Total	6.7				1.4				6.7	1.4
Common shareholders' equity
Common stock-250,000,000 shares authorized without par value 136,113,954 and 135,636,538 shares issued, stated value	2,330.6				2,324.4				2,330.6	2,324.4
Retained earnings	684.7				626.5				684.7	626.5
Treasury stock-264,567 and 400,889 shares, at cost	(5.6)				(8.9)				(5.6)	(8.9)
Accumulated other comprehensive loss	(49.8)				(56.1)				(49.8)	(56.1)
Total	2,959.9				2,885.9				2,959.9	2,885.9
Cumulative preferred stock $100 par value
Total	39.0				39.0				39.0	39.0
Long-term debt	699.3				637.0				699.3	637.0
Total	3,698.2				3,561.9				3,698.2	3,561.9
Total	4,061.8				3,638.2				4,061.8	3,638.2
Cash Flows from Operating Activities
Net income									174.4	211.7	150.1
Adjustments to reconcile income to net cash from operating activities:
Amortization									11.2	3.9	1.9
Deferred income taxes, net									(18.6)	13.9	(6.1)
Equity in earnings from subsidiaries									(200.8)	(239.3)	(174.7)
Equity in (earnings) loss from discontinued subsidiary									0	0	1.5
Cash flows affected by changes in:
Accounts receivable from subsidiaries									0	2.6	(3.7)
Taxes receivable									(6.3)	0	(4.8)
Accounts payable to subsidiaries									(0.3)	2.2	0.2
Other accounts payable									0	(0.1)	0.1
Accrued taxes									5.2	0	0
Accrued interest									1.2	2.7	1.4
Cash dividends from subsidiaries									148.0	138.6	94.0
Settlement Of Forward Starting Swaps									(26.1)	(6.9)	0
Other									2.1	(0.9)	8.8
Net cash from operating activities									102.6	123.2	85.7
Cash Flows from Investing Activities
Equity contributions to subsidiaries									0	0	(455.0)
Intercompany lending									(347.4)	(248.8)	0
Net money pool lending									1.1	(1.1)	(0.9)
Net cash from investing activities									(346.3)	(249.9)	(455.9)
Cash Flows from Financing Activities
Issuance of common stock									5.9	6.2	219.9
Issuance of long-term debt									349.7	249.9	287.5
Issuance fees									(3.2)	(3.2)	(18.8)
Net change in short-term borrowings									12.5	(10.5)	(10.0)
Dividends paid									(115.1)	(114.2)	(110.5)
Other financing activities									(6.4)	(7.3)	(3.8)
Net cash from financing activities									243.4	120.9	364.3
Net Change in Cash and Cash Equivalents									(0.3)	(5.8)	(5.9)
Cash and Cash Equivalents at Beginning of Year								6.1		6.1			12.0
Cash and Cash Equivalents at End of Year	0				0.3				0	0.3			12.0
Parent Company [Member] | Cumulative Preferred Stock [Member] | Preferred Stock 3 Point 80 [Member]
Cumulative preferred stock $100 par value
Total	10.0				10.0				10.0	10.0
Parent Company [Member] | Cumulative Preferred Stock [Member] | Preferred Stock 4 Point 50 [Member]
Cumulative preferred stock $100 par value
Total	10.0				10.0				10.0	10.0
Parent Company [Member] | Cumulative Preferred Stock [Member] | Preferred Stock 4 Point 20 [Member]
Cumulative preferred stock $100 par value
Total	7.0				7.0				7.0	7.0
Parent Company [Member] | Cumulative Preferred Stock [Member] | Preferred Stock 4 Point 35 [Member]
Cumulative preferred stock $100 par value
Total	$ 12.0				$ 12.0				$ 12.0	$ 12.0

XML

Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010
Liabilities [Abstract]
Cash and cash equivalents from nuclear decommissioning trust excluded from fair value disclosure	$ 3.0		$ 2.7
Cash and cash equivalents from SERP rabbi trust excluded from fair value disclosure	20.3		14.6
Cash collateral posted with third parties as part of netting agreements	5.5		2.5
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period			4.3
Total realized/unrealized gains or (losses) included in non-operating income			(12.5)
Sales			(0.2)
Settlements			12.1
Balance at end of period			3.7
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
Pre-tax impairment loss on investments in affordable housing limited partnerships			11.2
Kansas City Power and Light Company [Member] | US States and Political Subdivisions Debt Securities [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period			0.2
Total realized/unrealized gains or (losses) included in non-operating income			0
Sales			(0.2)
Settlements			0
Balance at end of period			0
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
Other Great Plains [Member] | Derivative Financial Instruments, Assets [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period			4.1
Total realized/unrealized gains or (losses) included in non-operating income	10.9		(12.5)
Sales			0
Settlements	(11.5)		12.1
Balance at end of period	3.1		7.4
Total unrealized gains and (losses) included in non-operating income relating to assets and liabilities still on the consolidated balance sheet at period end	(0.2)		0.1
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Assets [Abstract]
Derivative instruments, assets	7.8	[1]	8.9	[1]
Debt securities related to nuclear decommissioning trust [Abstract]
Total nuclear decommissioning trust	132.3	[2]	126.5	[2]
SERP rabbi trust [Abstract]
Total SERP rabbi trust	0.3	[3]	7.2	[3]
Total assets	140.4		142.6
Liabilities [Abstract]
Derivative instruments, liabilities	0	[1]	20.8	[1]
Total liabilities	0		20.8
Fair Value, Measurements, Recurring [Member] | Netting and Collateral [Member]
Assets [Abstract]
Derivative instruments, assets	0	[1],[4]	(0.6)	[1],[4]
Debt securities related to nuclear decommissioning trust [Abstract]
Total nuclear decommissioning trust	0	[2],[4]	0	[2],[4]
SERP rabbi trust [Abstract]
Total SERP rabbi trust	0	[3],[4]	0	[3],[4]
Total assets	0	[4]	(0.6)	[4]
Liabilities [Abstract]
Derivative instruments, liabilities	(5.5)	[1],[4]	(3.1)	[1],[4]
Total liabilities	(5.5)	[4]	(3.1)	[4]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Derivative instruments, assets	0	[1]	0.6	[1]
Debt securities related to nuclear decommissioning trust [Abstract]
Total nuclear decommissioning trust	99.6	[2]	94.4	[2]
SERP rabbi trust [Abstract]
Total SERP rabbi trust	0.2	[3]	0.2	[3]
Total assets	99.8		95.2
Liabilities [Abstract]
Derivative instruments, liabilities	5.5	[1]	3.1	[1]
Total liabilities	5.5		3.1
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Derivative instruments, assets	4.7	[1]	5.2	[1]
Debt securities related to nuclear decommissioning trust [Abstract]
Total nuclear decommissioning trust	32.7	[2]	32.1	[2]
SERP rabbi trust [Abstract]
Total SERP rabbi trust	0.1	[3]	7.0	[3]
Total assets	37.5		44.3
Liabilities [Abstract]
Derivative instruments, liabilities	0	[1]	20.8	[1]
Total liabilities	0		20.8
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Derivative instruments, assets	3.1	[1]	3.7	[1]
Debt securities related to nuclear decommissioning trust [Abstract]
Total nuclear decommissioning trust	0	[2]	0	[2]
SERP rabbi trust [Abstract]
Total SERP rabbi trust	0	[3]	0	[3]
Total assets	3.1		3.7
Liabilities [Abstract]
Derivative instruments, liabilities	0	[1]	0	[1]
Total liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Assets [Abstract]
Derivative instruments, assets	0	[1]	0	[1]
Nuclear decommissioning trust [Abstract]
Equity securities related to nuclear decommissioning trust	84.3	[2]	85.5	[2]
Debt securities related to nuclear decommissioning trust [Abstract]
U.S. Treasury	15.3	[2]	8.9	[2]
U.S. Agency	3.6	[2]	4.8	[2]
State and local obligations	2.6	[2]	2.5	[2]
Corporate bonds	26.4	[2]	23.7	[2]
Foreign governments	0.7	[2]	0.7	[2]
Other	(0.6)	[2]	0.4	[2]
Total nuclear decommissioning trust	132.3	[2]	126.5	[2]
SERP rabbi trust [Abstract]
Total assets	132.3		126.5
Liabilities [Abstract]
Derivative instruments, liabilities	0	[1]	0	[1]
Total liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Netting and Collateral [Member]
Assets [Abstract]
Derivative instruments, assets	0	[1],[4]	(0.1)	[1],[4]
Nuclear decommissioning trust [Abstract]
Equity securities related to nuclear decommissioning trust	0	[2],[4]	0	[2],[4]
Debt securities related to nuclear decommissioning trust [Abstract]
U.S. Treasury	0	[2],[4]	0	[2],[4]
U.S. Agency	0	[2],[4]	0	[2],[4]
State and local obligations	0	[2],[4]	0	[2],[4]
Corporate bonds	0	[2],[4]	0	[2],[4]
Foreign governments	0	[2],[4]	0	[2],[4]
Other	0	[2],[4]	0	[2],[4]
Total nuclear decommissioning trust	0	[2],[4]	0	[2],[4]
SERP rabbi trust [Abstract]
Total assets	0	[4]	(0.1)	[4]
Liabilities [Abstract]
Derivative instruments, liabilities	(0.5)	[1],[4]	(0.1)	[1],[4]
Total liabilities	(0.5)	[4]	(0.1)	[4]
Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Derivative instruments, assets	0	[1]	0.1	[1]
Nuclear decommissioning trust [Abstract]
Equity securities related to nuclear decommissioning trust	84.3	[2]	85.5	[2]
Debt securities related to nuclear decommissioning trust [Abstract]
U.S. Treasury	15.3	[2]	8.9	[2]
U.S. Agency	0	[2]	0	[2]
State and local obligations	0	[2]	0	[2]
Corporate bonds	0	[2]	0	[2]
Foreign governments	0	[2]	0	[2]
Other	0	[2]	0	[2]
Total nuclear decommissioning trust	99.6	[2]	94.4	[2]
SERP rabbi trust [Abstract]
Total assets	99.6		94.5
Liabilities [Abstract]
Derivative instruments, liabilities	0.5	[1]	0.1	[1]
Total liabilities	0.5		0.1
Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Derivative instruments, assets	0	[1]	0	[1]
Nuclear decommissioning trust [Abstract]
Equity securities related to nuclear decommissioning trust	0	[2]	0	[2]
Debt securities related to nuclear decommissioning trust [Abstract]
U.S. Treasury	0	[2]	0	[2]
U.S. Agency	3.6	[2]	4.8	[2]
State and local obligations	2.6	[2]	2.5	[2]
Corporate bonds	26.4	[2]	23.7	[2]
Foreign governments	0.7	[2]	0.7	[2]
Other	(0.6)	[2]	0.4	[2]
Total nuclear decommissioning trust	32.7	[2]	32.1	[2]
SERP rabbi trust [Abstract]
Total assets	32.7		32.1
Liabilities [Abstract]
Derivative instruments, liabilities	0	[1]	0	[1]
Total liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Kansas City Power and Light Company [Member] | Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Derivative instruments, assets	0	[1]	0	[1]
Nuclear decommissioning trust [Abstract]
Equity securities related to nuclear decommissioning trust	0	[2]	0	[2]
Debt securities related to nuclear decommissioning trust [Abstract]
U.S. Treasury	0	[2]	0	[2]
U.S. Agency	0	[2]	0	[2]
State and local obligations	0	[2]	0	[2]
Corporate bonds	0	[2]	0	[2]
Foreign governments	0	[2]	0	[2]
Other	0	[2]	0	[2]
Total nuclear decommissioning trust	0	[2]	0	[2]
SERP rabbi trust [Abstract]
Total assets	0		0
Liabilities [Abstract]
Derivative instruments, liabilities	0	[1]	0	[1]
Total liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Assets [Abstract]
Derivative instruments, assets	7.8	[1]	8.9	[1]
SERP rabbi trust [Abstract]
Equity securities related to SERP rabbi trust	0.2	[3]	0.2	[3]
Debt securities related to SERP rabbi trust	0.1	[3]	7.0	[3]
Total SERP rabbi trust	0.3	[3]	7.2	[3]
Total assets	8.1		16.1
Liabilities [Abstract]
Derivative instruments, liabilities	0	[1]	20.8	[1]
Total liabilities	0		20.8
Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Netting and Collateral [Member]
Assets [Abstract]
Derivative instruments, assets	0	[1],[4]	(0.5)	[1],[4]
SERP rabbi trust [Abstract]
Equity securities related to SERP rabbi trust	0	[3],[4]	0	[3],[4]
Debt securities related to SERP rabbi trust	0	[3],[4]	0	[3],[4]
Total SERP rabbi trust	0	[3],[4]	0	[3],[4]
Total assets	0	[4]	(0.5)	[4]
Liabilities [Abstract]
Derivative instruments, liabilities	(5.0)	[1],[4]	(3.0)	[1],[4]
Total liabilities	(5.0)	[4]	(3.0)	[4]
Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Derivative instruments, assets	0	[1]	0.5	[1]
SERP rabbi trust [Abstract]
Equity securities related to SERP rabbi trust	0.2	[3]	0.2	[3]
Debt securities related to SERP rabbi trust	0	[3]	0	[3]
Total SERP rabbi trust	0.2	[3]	0.2	[3]
Total assets	0.2		0.7
Liabilities [Abstract]
Derivative instruments, liabilities	5.0	[1]	3.0	[1]
Total liabilities	5.0		3.0
Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Derivative instruments, assets	4.7	[1]	5.2	[1]
SERP rabbi trust [Abstract]
Equity securities related to SERP rabbi trust	0	[3]	0	[3]
Debt securities related to SERP rabbi trust	0.1	[3]	7.0	[3]
Total SERP rabbi trust	0.1	[3]	7.0	[3]
Total assets	4.8		12.2
Liabilities [Abstract]
Derivative instruments, liabilities	0	[1]	20.8	[1]
Total liabilities	0		20.8
Fair Value, Measurements, Recurring [Member] | Other Great Plains [Member] | Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Derivative instruments, assets	3.1	[1]	3.7	[1]
SERP rabbi trust [Abstract]
Equity securities related to SERP rabbi trust	0	[3]	0	[3]
Debt securities related to SERP rabbi trust	0	[3]	0	[3]
Total SERP rabbi trust	0	[3]	0	[3]
Total assets	3.1		3.7
Liabilities [Abstract]
Derivative instruments, liabilities	0	[1]	0	[1]
Total liabilities	$ 0		$ 0

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

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

[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 $20.3 million and $14.6 million at December 31, 2011 and 2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

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

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Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended																																								12 Months Ended															12 Months Ended							12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended									12 Months Ended						12 Months Ended													12 Months Ended							12 Months Ended					12 Months Ended					12 Months Ended			12 Months Ended										12 Months Ended
	Dec. 31, 2010	Sep. 30, 2010	Dec. 31, 2011	Dec. 31, 2011 Emission allowances [Member]	Dec. 31, 2010 Emission allowances [Member]	Dec. 31, 2011 Asset retirement obligations [Member]	Dec. 31, 2010 Asset retirement obligations [Member]	Dec. 31, 2011 Pension [Member]	Dec. 31, 2010 Pension [Member]	Dec. 31, 2011 Cost of removal, liability [Member]		Dec. 31, 2010 Cost of removal, liability [Member]	Dec. 31, 2011 Other regulatory noncurrent liabilities [Member]	Dec. 31, 2010 Other regulatory noncurrent liabilities [Member]	Dec. 31, 2011 Taxes recoverable through future rates [Member]	Dec. 31, 2010 Taxes recoverable through future rates [Member]	Dec. 31, 2011 Loss on reacquired debt [Member]	Dec. 31, 2010 Loss on reacquired debt [Member]	Dec. 31, 2011 Cost of removal, asset [Member]	Dec. 31, 2010 Cost of removal, asset [Member]	Dec. 31, 2011 Asset Retirement Obligation Costs [Member]	Dec. 31, 2010 Asset Retirement Obligation Costs [Member]	Dec. 31, 2011 Pension and post-retirement costs [Member]	Dec. 31, 2010 Pension and post-retirement costs [Member]	Dec. 31, 2011 Deferred customer programs [Member]	Dec. 31, 2010 Deferred customer programs [Member]	Dec. 31, 2011 Rate case expenses [Member]	Dec. 31, 2010 Rate case expenses [Member]	Dec. 31, 2011 Skill set realignment costs [Member]	Dec. 31, 2010 Skill set realignment costs [Member]	Dec. 31, 2011 Fuel adjustment clauses [Member]	Dec. 31, 2010 Fuel adjustment clauses [Member]	Dec. 31, 2011 Acquisition transition costs [Member]	Dec. 31, 2010 Acquisition transition costs [Member]	Dec. 31, 2011 Derivative instruments [Member]	Dec. 31, 2010 Derivative instruments [Member]	Dec. 31, 2011 Iatan No. 1 and Common facilities depreciation and carrying costs [Member]	Dec. 31, 2010 Iatan No. 1 and Common facilities depreciation and carrying costs [Member]	Dec. 31, 2011 Iatan No. 2 construction accounting costs [Member]	Dec. 31, 2010 Iatan No. 2 construction accounting costs [Member]	Dec. 31, 2011 Kansas property tax surcharge [Member]	Dec. 31, 2011 Other regulatory noncurrent assets [Member]	Dec. 31, 2010 Other regulatory noncurrent assets [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Emission allowances [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Emission allowances [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Asset retirement obligations [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Asset retirement obligations [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Pension [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Pension [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Other regulatory noncurrent liabilities [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Other regulatory noncurrent liabilities [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Taxes recoverable through future rates [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Taxes recoverable through future rates [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Loss on reacquired debt [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Loss on reacquired debt [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Cost of removal, asset [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Cost of removal, asset [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Asset Retirement Obligation Costs [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Asset Retirement Obligation Costs [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Pension and post-retirement costs [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Pension and post-retirement costs [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Deferred customer programs [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Deferred customer programs [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Rate case expenses [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Rate case expenses [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Skill set realignment costs [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Skill set realignment costs [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Fuel adjustment clauses [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Fuel adjustment clauses [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Acquisition transition costs [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Acquisition transition costs [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Derivative instruments [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Derivative instruments [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Iatan No. 1 and Common facilities depreciation and carrying costs [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Iatan No. 1 and Common facilities depreciation and carrying costs [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Iatan No. 2 construction accounting costs [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Iatan No. 2 construction accounting costs [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Kansas property tax surcharge [Member]		Dec. 31, 2011 Kansas City Power and Light Company [Member] Other regulatory noncurrent assets [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Other regulatory noncurrent assets [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Rate jurisdiction - Kansas [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Rate jurisdiction - Missouri [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Emission allowances [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Emission allowances [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Pension [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Pension [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Cost of removal, liability [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Cost of removal, liability [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Other regulatory noncurrent liabilities [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Other regulatory noncurrent liabilities [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Taxes recoverable through future rates [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Taxes recoverable through future rates [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Loss on reacquired debt [Member]		Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Loss on reacquired debt [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Cost of removal, asset [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Cost of removal, asset [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Asset Retirement Obligation Costs [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Asset Retirement Obligation Costs [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Pension and post-retirement costs [Member]		Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Pension and post-retirement costs [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Deferred customer programs [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Deferred customer programs [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Rate case expenses [Member]		Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Rate case expenses [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Skill set realignment costs [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Skill set realignment costs [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Fuel adjustment clauses [Member]		Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Fuel adjustment clauses [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Acquisition transition costs [Member]		Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Acquisition transition costs [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Derivative instruments [Member]		Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Derivative instruments [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Iatan No. 1 and Common facilities depreciation and carrying costs [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Iatan No. 1 and Common facilities depreciation and carrying costs [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Iatan No. 2 construction accounting costs [Member]	Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Iatan No. 2 construction accounting costs [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Other regulatory noncurrent assets [Member]		Dec. 31, 2010 KCPL Greater Missouri Operations [Member] Other regulatory noncurrent assets [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Rate jurisdiction - Missouri public service division [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] Rate jurisdiction - St. Joseph Light and Power division [Member]
Regulatory Proceedings [Line Items]
Annual revenue increase																																																																																													$ 105.7																																														$ 58.3	$ 25.2
Modified annual revenue increase																																																																																												22.0																																															35.7	29.8
Return on equity (in hundredths)																																																																																													10.40%																																														10.40%	10.40%
Rate-making equity ratio (in hundredths)																																																																																													52.50%																																														52.50%	52.50%
Annual revenue increase authorized																																																																																												21.8	34.8																																														30.1	29.3
Return on equity, approved (in hundredths)																																																																																												10.00%	10.00%	10.00%
Rate-making equity ratio, approved (in hundredths)																																																																																												49.70%	46.30%	46.60%
Jurisdictional rate base																																																																																												1,781	2,000	1,760
Disallowed construction costs on Iatan Nos 1 and 2	12.8	4.0																																																																																											1.5	0.8
Other disallowed costs																																																																																													2.4	1.5
Wholesale Margin Offset																																																																																													45.9
Qualifying advance coal project tax credits to be reallocated from KCPL to GMO																																																																																													26.5
Unamortized deferred investment tax credits																																																																																													127.9	3.3
Amount of Crossroads disallowed from rate base																																																																																																																																											50.0
Amount of Crossroads transmission expense disallowed																																																																																																																																											4.9
Amount of Crossroads accumulated deferred taxes offset against rate base																																																																																																																																											15.0
Amount of Crossroads net plant requested																																																																																																																																											104.0
Amount of approved annual revenue increase deferred																																																																																																																																												7.7
Amount of revenue increase requested																																																																																																																																												22.1
Amount of FAC refund recommended by MPSC staff																																																																																														19.0
Additional rate case expenses allowed in rates																																																																																												0.2
Regulatory Assets [Line Items]
Regulatory Assets	924.0		1,058.2												144.2	142.5	11.8	5.7	4.6	8.5	45.2	40.3	588.4	492.8	68.8	60.3	13.4	15.6	3.4	4.8	50.4	45.5	44.9	51.8	7.6	3.1	22.5	19.4	43.3	23.7	3.7	6.0	10.0	780.7	679.6									119.6	117.2	9.1	[1]	5.0	4.6	8.5	31.4	27.5	466.4	[2]	386.1	48.2	[3]	44.7	9.6	[4]	12.3	3.4	[5]	4.8	14.0	[4]	8.4	24.7	[6]	29.3	0	0	16.4	15.1	27.9	17.2	3.7	[4]	1.7	[7]	3.5			277.5	244.4									24.6	25.3	2.7	[1]	0.7	0	0	13.8	12.8	122.0	[2]	106.7	20.6	15.6	3.8	[4]	3.3	0	0	36.4	[4]	37.1	20.2	[6]	22.5	7.6	[8]	3.1	6.1	4.3	15.4	6.5	4.3	[7]	6.5
Amount not included in rate base																																																																		10.4						2.4
Regulatory amortization period																																									various															over the life of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued							various			various			various			through 2017			various			through 2016									various		various																	over the life of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued							various					various					various			through 2016										various
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 258.2		$ 268.5	$ 82.2	$ 86.4	$ 49.3	$ 44.9	$ 41.5	$ 37.1	$ 61.9	[9]	$ 62.8	$ 33.6	$ 27.0																														$ 142.8	$ 141.3	$ 82.0	$ 85.9	$ 49.3	$ 44.9	$ 0.7	$ 0	$ 10.8	$ 10.5																																									$ 125.7	$ 116.9	$ 0.2	$ 0.5	$ 40.8	$ 37.1	$ 61.9	$ 62.8	$ 22.8	$ 16.5

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

[2] Represents unrecognized gains and losses, prior service and transition costs that will be recognized in future net periodic pension and post-retirement costs, pension settlements amortized over various periods and financial and regulatory accounting method differences not included in rate base that will be eliminated over the life of the pension plans.

[3] $10.4 million not included in rate base and amortized over various periods.

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

[5] $2.4 million not included in rate base and amortized through 2017.

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

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

[8] Represents the fair value of derivative instruments for commodity contracts. Settlements of the contracts are recognized in fuel expense and included in GMOs FAC.

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

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Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010
Discontinued Operations [Abstract]
Discontinued operations	$ 0	$ 0	$ (1.5)
Total income (loss) on discontinued operations before income taxes	$ 0	$ 0	$ (2.4)

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Jointly Owned Electric Utility Plants (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Nuclear fuel, net	$ 76.6	$ 79.2
Kansas City Power and Light Company [Member]
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Nuclear fuel, net	76.6	79.2
Jointly Owned Electricity Generation Plant [Member] | Wolf Creek Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	47.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	1,473.8
Accumulated depreciation	776.3
Nuclear fuel, net	76.6
Construction work in progress	39.4
Accredited capacity (in MegaWatts)	547
Jointly Owned Electricity Generation Plant [Member] | Wolf Creek Unit [Member] | Kansas City Power and Light Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	47.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	1,473.8
Accumulated depreciation	776.3
Nuclear fuel, net	76.6
Construction work in progress	39.4
Accredited capacity (in MegaWatts)	547
Jointly Owned Electricity Generation Plant [Member] | LaCygne Units [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	50.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	493.6
Accumulated depreciation	303.1
Construction work in progress	79.1
Accredited capacity (in MegaWatts)	711
Jointly Owned Electricity Generation Plant [Member] | LaCygne Units [Member] | Kansas City Power and Light Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	50.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	493.6
Accumulated depreciation	303.1
Construction work in progress	79.1
Accredited capacity (in MegaWatts)	711
Jointly Owned Electricity Generation Plant [Member] | Iatan No. 1 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	88.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	667.9
Accumulated depreciation	252.8
Construction work in progress	6.5
Accredited capacity (in MegaWatts)	620
Jointly Owned Electricity Generation Plant [Member] | Iatan No. 1 [Member] | Kansas City Power and Light Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	70.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	542.3
Accumulated depreciation	207.9
Construction work in progress	2.6
Accredited capacity (in MegaWatts)	493
Jointly Owned Electricity Generation Plant [Member] | Iatan No. 2 Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	73.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	1,293.0
Accumulated depreciation	270.0
Construction work in progress	5.9
Accredited capacity (in MegaWatts)	641
Jointly Owned Electricity Generation Plant [Member] | Iatan No. 2 Unit [Member] | Kansas City Power and Light Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	55.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	985.1
Accumulated depreciation	261.3
Construction work in progress	4.4
Accredited capacity (in MegaWatts)	482
Jointly Owned Electricity Generation Plant [Member] | Iatan Common [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	79.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	364.4
Accumulated depreciation	30.4
Construction work in progress	30.2
Jointly Owned Electricity Generation Plant [Member] | Iatan Common [Member] | Kansas City Power and Light Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	61.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	287.5
Accumulated depreciation	26.0
Construction work in progress	9.3
Jointly Owned Electricity Generation Plant [Member] | Jeffrey Energy Center [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership share (in hundredths)	8.00%
Jointly owned utility plant, gross ownership amount of plant in service [Abstract]
Utility plant in service	158.4
Accumulated depreciation	75.5
Construction work in progress	$ 5.3
Accredited capacity (in MegaWatts)	174

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Derivative Instruments Group 4 (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	$ (3.6)	$ (17.2)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(10.4)	(6.6)
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	1.1	0.2
Kansas City Power and Light Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	(0.4)	(0.6)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(5.4)	(5.7)
Interest charges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(16.9)	(10.1)
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)	(8.7)	(8.8)
Fuel Costs [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(0.1)	(0.5)
Gain(Loss) Reclassified from Regulatory Account into Income (Effective Portion)	(3.8)	(7.2)
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)	(0.1)	(0.5)
Income tax benefit (expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	2.3	10.8
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	6.6	4.0
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)	0.2	0.3
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	3.4	3.6
Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	(5.3)	(27.1)
Interest Rate Contract [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
Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	(0.6)	(0.9)
Amount of Gain (Loss) Recognized on Regulatory Account on Derivatives (Effective Portion)	(8.3)	(8.2)
Commodity Contract [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)	$ (0.6)	$ (0.9)

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Derivative Instruments

12 Months Ended

Dec. 31, 2011

Derivative Instruments [Abstract]

Derivative Instruments

18.   DERIVATIVE INSTRUMENTS

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

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

Interest Rate Risk Management

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

Commodity Risk Management

KCP&L’s risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales.  At December 31, 2011, KCP&L had hedged 66%, 56% and 13%, respectively, of the 2012, 2013 and 2014 projected natural gas usage for retail load and firm MWh sales by utilizing futures contracts.  KCP&L has designated the natural gas hedges as cash flow hedges.  The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge.  To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense.  KCP&L has not recorded any ineffectiveness on natural gas hedges in 2011, 2010 or 2009.

GMO’s risk management policy is to use derivative instruments to mitigate price exposure to natural gas price volatility in the market.  The fair value of the portfolio relates to financial contracts that will settle against actual purchases of natural gas and purchased power.  At December 31, 2011, GMO had financial contracts in place to hedge approximately 45%, 38% and 38%, respectively, of the expected on-peak natural gas and natural gas equivalent purchased power price exposure for 2012, 2013 and 2014.  GMO has designated its natural gas hedges as economic hedges (non-hedging derivatives).  In connection with GMO’s 2005 Missouri electric rate case, it was agreed that the settlement costs of these contracts would be recognized in fuel expense.  The settlement cost is included in GMO’s FAC.  A regulatory asset has been 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.

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

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

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.8		5.0
Total Derivatives		$	7.8	$	5.5
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9

KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

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

Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
Interest rate contracts	$	(5.3	)	Interest charges	$	(16.9	)
Commodity contracts		(0.6	)	Fuel		(0.1	)
Income tax benefit		2.3		Income tax benefit		6.6
Total	$	(3.6	)	Total	$	(10.4	)
2010
Interest rate contracts	$	(27.1	)	Interest charges	$	(10.1	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		10.8		Income tax benefit		4.0
Total	$	(17.2	)	Total	$	(6.6	)

KCP&L
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(8.7	)
Commodity contracts		(0.6	)	Fuel		(0.1	)
Income tax benefit		0.2		Income tax benefit		3.4
Total	$	(0.4	)	Total	$	(5.4	)
2010
Interest rate contracts	$	-		Interest charges	$	(8.8	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		0.3		Income tax benefit		3.6
Total	$	(0.6	)	Total	$	(5.7	)

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

Great Plains Energy
Derivatives in Regulatory Account Relationship
				Gain (Loss) Reclassified from
				Regulatory Account
	Amount of Gain (Loss)
	Recognized on Regulatory
	Account on Derivatives			Income Statement
	(Effective Portion)			Classification	Amount
	(millions)				(millions)
2011
Commodity contracts	$	(8.3	)	Fuel	$	(3.8	)
Total	$	(8.3	)	Total	$	(3.8	)
2010
Commodity contracts	$	(8.2	)	Fuel	$	(7.2	)
Total	$	(8.2	)	Total	$	(7.2	)

Great Plains Energy’s income statement reflects losses for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $1.1 million for 2011 and $0.2 million for 2010.

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

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

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

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Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2011

Segments and Related Information [Abstract]

Segment financial information

	Electric						Great Plains
2011	Utility			Other			Energy
	(millions)
Operating revenues	$	2,318.0		$	-		$	2,318.0
Depreciation and amortization		(273.1	)		-			(273.1	)
Interest charges		(176.9	)		(41.5	)		(218.4	)
Income tax (expense) benefit		(109.3	)		24.5			(84.8	)
Net income (loss) attributable to Great Plains Energy		199.9			(25.5	)		174.4

	Electric						Great Plains
2010	Utility			Other			Energy
	(millions)
Operating revenues	$	2,255.5		$	-		$	2,255.5
Depreciation and amortization		(331.6	)		-			(331.6	)
Interest charges		(143.1	)		(41.7	)		(184.8	)
Income tax (expense) benefit		(123.3	)		24.3			(99.0	)
Net income (loss) attributable to Great Plains Energy		235.3			(23.6	)		211.7

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

	Electric							Great Plains
	Utility		Other		Eliminations			Energy
2011	(millions)
Assets	$	9,483.4	$	51.9	$	(417.3	)	$	9,118.0
Capital expenditures		456.6		-		-			456.6
2010
Assets	$	9,152.7	$	66.3	$	(400.8	)	$	8,818.2
Capital expenditures		618.1		-		-			618.1
2009
Assets	$	8,765.3	$	152.5	$	(435.0	)	$	8,482.8
Capital expenditures		841.3		-		-			841.3

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Pension Plans and Other Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Pension Plans and Other Employee Benefits [Abstract]

Funded status of plans

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

Components of net periodic benefit costs

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

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

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

Weighted average assumptions

Weighted-average assumptions used to determine	Pension Benefits						Other Benefits
the benefit obligation at plan year-end	2011			2010			2011			2010
Discount rate		5.01	%		5.54	%		5.03	%		5.50	%
Rate of compensation increase		4.08	%		4.08	%		4.07	%		4.06	%
Weighted-average assumptions used to determine	Pension Benefits						Other Benefits
net costs for years ended December 31	2011			2010			2011			2010
Discount rate		5.54	%		5.92	%		5.50	%		5.87	%
Expected long-term return on plan assets		7.29	%		8.00	%		2.83	% *		4.25	% *
Rate of compensation increase		4.08	%		4.26	%		4.06	%		4.25	%
* after tax

Future benefit payments

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

Fair value of plan assets

			Fair Value Measurements Using
Description	December 31 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions)
Pension Plans
Equity securities
U.S.(a)	$	156.3	$	94.6	$	61.7	$	-
International(b)		117.0		40.9		76.1		-
Real estate(c)		34.7		-		-		34.7
Commodities(d)		34.6		-		34.6		-
Fixed income securities
Fixed income funds(e)		166.5		34.2		132.3		-
U.S. Treasury		4.9		4.9		-		-
U.S. Agency, state and local obligations		17.7		-		17.7		-
U.S. corporate bonds(f)		26.6		-		26.6		-
Foreign corporate bonds		2.6		-		2.6		-
Hedge funds(g)		21.7		-		-		21.7
Total	$	582.6	$	174.6	$	351.6	$	56.4
Cash equivalents - money market funds		8.5
Total Pension Plans	$	591.1

				Fair Value Measurements Using
Description		December 31 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
	Equity securities	$	1.4	$	1.4	$	-	$	-
	Fixed income
	U.S. Treasury		14.3		14.3		-		-
	U.S. Agency, state and local obligations		27.2		-		27.2		-
	U.S. corporate bonds (a)		14.8		-		14.8		-
	Foreign corporate bonds		1.5		-		1.5		-
	Mutual funds		0.2		0.2		-		-
	Total	$	59.4	$	15.9	$	43.5	$	-
	Cash and cash equivalents - money market funds		18.0
	Total Other Post-Retirement Benefit Plans	$	77.4
(a)	This category is comprised of $12.7 million of corporate bonds, $0.6 million of collateralized mortgage obligations and $1.5 million
	of other asset-backed securities.

				Fair Value Measurements Using
Description		December 31 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Pension Plans
	Equity securities
	U.S.(a)	$	158.5	$	90.5	$	68.0	$	-
	International(b)		122.4		39.4		83.0		-
	Limited partnerships		0.1		-		-		0.1
	Real estate(c)		30.3		-		-		30.3
	Commodities(d)		37.0		-		37.0		-
	Fixed income securities
	Fixed income funds(e)		148.7		23.0		125.7		-
	U.S. Treasury		1.8		1.8		-		-
	U.S. Agency, state and local obligations		14.8		-		14.8		-
	U.S. corporate bonds(f)		24.2				24.2		-
	Foreign corporate bonds		1.5		-		1.5		-
	Hedge funds(g)		8.4		-		-		8.4
	Total	$	547.7	$	154.7	$	354.2	$	38.8
	Cash equivalents - money market funds		9.9
	Total Pension Plans	$	557.6
(a)	At December 31, 2011 and 2010, this category is comprised of $94.6 million and $90.5 million, respectively, of traded mutual funds valued at daily listed prices and $61.7 million and $68.0 million, respectively,
	of institutional common/collective trust funds valued at daily Net Asset Values (NAV) per share.
(b)	At December 31, 2011 and 2010, this category is comprised of $40.9 million and $39.4 million, respectively, of traded mutual funds valued at daily listed prices and $76.1 million and $83.0 million, respectively,
	of institutional common/collective trust funds valued at daily NAV per share.
(c)	This category is comprised of institutional common/collective trust funds and a limited partnership valued at NAV on a quarterly basis.
(d)	This category is comprised of institutional common/collective trust funds valued at daily NAV per share.
(e)	At December 31, 2011 and 2010, this category is comprised of $34.2 million and $23.0 million, respectively, of traded mutual funds valued at daily listed prices and $132.3 million and $125.7 million, respectively, of institutional common/collective trust funds valued at daily NAV per share.
(f)	At December 31, 2011 and 2010, this category is comprised of $18.1 million and $13.9 million, respectively, of corporate bonds, $6.1 million and $8.0 million, respectively, of collateralized mortgage obligations
	and $2.4 million and $2.3 million, respectively, of other asset-backed securities.
(g)	This category is comprised of closely-held limited partnerships valued at NAV on a quarterly basis.

				Fair Value Measurements Using
Description		December 31 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
	Fixed income
	U.S. Treasury	$	12.1	$	12.1	$	-	$	-
	U.S. Agency, state and local obligations		22.2		-		22.2		-
	U.S. corporate bonds (a)		11.4		-		11.4		-
	Foreign corporate bonds		1.0				1.0
	Mutual funds		0.1		0.1		-		-
	Total	$	46.8	$	12.2	$	34.6	$	-
	Cash and cash equivalents - money market funds		19.0
	Total Other Post-Retirement Benefit Plans	$	65.8
(a)	This category is comprised of $9.2 million of corporate bonds, $0.9 million of collateralized mortgage obligations and $1.3 million
	of other asset-backed securities.

Fair value of assets using significant unobservable inputs

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Real		Hedge			Limited
Description	Estate		Funds			Partnerships			Total
	(millions)
Balance January 1, 2011	$	30.3	$	8.4		$	0.1		$	38.8
Actual return on plan assets
Relating to assets still held		3.9		(1.3	)		(0.1	)		2.5
Relating to assets sold		-		-			-			-
Purchase, sales, and settlements		0.5		14.6			-			15.1
Transfers in and/or out of Level 3		-		-			-			-
Balance December 31, 2011	$	34.7	$	21.7		$	-		$	56.4

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

Effective of one percent change in health care costs

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

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Segments and Related Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Operating revenues	$ 486.3	$ 773.7	$ 565.1	$ 492.9	$ 467.8	$ 728.8	$ 552.0	$ 506.9	$ 2,318.0	$ 2,255.5	$ 1,965.0
Depreciation and amortization									(273.1)	(331.6)	(302.2)
Interest charges									(218.4)	(184.8)	(180.9)
Income tax (expense) benefit									(84.8)	(99.0)	(29.5)
Discontinued operations									0	0	(1.5)
Net income (loss) attributable to Great Plains Energy	2.1	126.5	43.4	2.4	(4.9)	132.0	64.3	20.3	174.4	211.7	150.1
Assets	9,118.0				8,818.2				9,118.0	8,818.2		8,482.8
Utility capital expenditures									456.6	618.1	841.3
All Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues									0	0	0
Depreciation and amortization									0	0	0
Interest charges									(41.5)	(41.7)	(29.9)
Income tax (expense) benefit									24.5	24.3	34.1
Discontinued operations									0	0	(1.5)
Net income (loss) attributable to Great Plains Energy									(25.5)	(23.6)	(7.7)
Assets	51.9				66.3				51.9	66.3		152.5
Utility capital expenditures									0	0	0
Corporate Elimination [Member]
Segment Reporting Information [Line Items]
Assets	(417.3)				(400.8)				(417.3)	(400.8)		(435.0)
Utility capital expenditures									0	0	0
Electric Utility Segment [Member]
Segment Reporting Information [Line Items]
Operating revenues									2,318.0	2,255.5	1,965.0
Depreciation and amortization									(273.1)	(331.6)	(302.2)
Interest charges									(176.9)	(143.1)	(151.0)
Income tax (expense) benefit									(109.3)	(123.3)	(63.6)
Discontinued operations									0	0	0
Net income (loss) attributable to Great Plains Energy									199.9	235.3	157.8
Assets	9,483.4				9,152.7				9,483.4	9,152.7		8,765.3
Utility capital expenditures									$ 456.6	$ 618.1	$ 841.3

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Receivables (Tables)

12 Months Ended

Dec. 31, 2011

Receivables [Abstract]

Schedule of receivables

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

Schedule of accounts receivable sold

				Receivables			Consolidated
2011	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,415.6	)	$	1,415.6		$	-
Gain (loss) on sale of accounts receivable (a)		(17.9	)		17.7			(0.2	)
Servicing fees		2.6			(2.6	)		-
Fees to outside investor		-			(1.2	)		(1.2	)
Cash flows during the period
Cash from customers transferred to Receivables Company		(1,412.4	)		1,412.4			-
Cash paid to KCP&L for receivables purchased		1,394.7			(1,394.7	)		-
Servicing fees		2.6			(2.6	)		-
Interest on intercompany note		0.5			(0.5	)		-

				Receivables			Consolidated
2010	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,341.0	)	$	1,341.0		$	-
Gain (loss) on sale of accounts receivable (a)		(17.0	)		16.8			(0.2	)
Servicing fees		3.2			(3.2	)		-
Fees to outside investor		-			(1.2	)		(1.2	)
Cash flows during the period
Cash from customers transferred to Receivables Company		(1,337.4	)		1,337.4			-
Cash paid to KCP&L for receivables purchased		1,320.7			(1,320.7	)		-
Servicing fees		3.2			(3.2	)		-
Interest on intercompany note		0.5			(0.5	)		-
(a) Any net gain (loss) is the result of the timing difference inherent in collecting receivables and
over the life of the agreement will net to zero.

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Quarterly Operating Results (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Operating Results (Unaudited) [Abstract]

Schedule of quarterly operating results

	Quarter
Great Plains Energy	1st		2nd		3rd		4th
2011	(millions, except per share amounts)
Operating revenue	$	492.9	$	565.1	$	773.7	$	486.3
Operating income		41.2		115.6		262.7		60.3
Net income		2.3		43.4		126.6		1.9
Net income attributable to Great Plains Energy		2.4		43.4		126.5		2.1
Basic earnings per common share		0.02		0.32		0.93		0.01
Diluted earnings per common share		0.01		0.31		0.91		0.01
2010
Operating revenue	$	506.9	$	552.0	$	728.8	$	467.8
Operating income		62.0		134.9		243.8		31.6
Net income (loss)		20.3		64.4		132.0		(4.8	)
Net income (loss) attributable to Great Plains Energy		20.3		64.3		132.0		(4.9	)
Basic earnings (loss) per common share		0.15		0.47		0.97		(0.04	)
Diluted earnings (loss) per common share		0.15		0.47		0.96		(0.04	)

	Quarter
KCP&L	1st		2nd		3rd		4th
2011	(millions)
Operating revenue	$	330.8	$	383.4	$	506.3	$	337.8
Operating income		26.5		77.8		169.2		47.7
Net income		4.0		33.4		85.4		12.7
2010
Operating revenue	$	335.6	$	372.6	$	486.5	$	322.4
Operating income		40.5		84.7		163.6		22.6
Net income		19.2		48.2		92.6		3.2

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Legal Proceedings (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
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
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
Pending or Threatened Litigation [Member] | KCPL Greater Missouri Operations [Member]
Loss Contingencies [Line Items]
Approximate amount of refunds received as a net purchaser of power through settlements with sellers of power	8.0
Amount of claims addressed under refund proceedings	5.1
Gain Contingencies [Line Items]
Amount of pending claims against the United States in the U.S. Court	$ 12.0

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Equity Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Jan. 02, 2010
Equity Compensation [Abstract]
Maximum number of shares of common stock authorized (in shares)	8,000,000
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 5.2		$ 4.3		$ 6.3
Income tax benefits	1.9		1.0		1.6
Share-based Compensation Arrangement by share-based Payment Award, Options, Outstanding [Roll Forward]
Exercise price exercised (in dollars per share)			$ 9.21
Weighted-average grant-date fair value of options exercised			$ 9.21
Director [Member]
Director deferred share units [Roll Forward]
Director deferred share units, issued (in shares)	15,168
Director deferred share units, ending balance (in shares)	54,231		39,063
Weighted-average grant date fair value, director deferred share units, issued (in dollars per share)	$ 20.57	[1]
Weighted-average grant date fair value, director deferred share units, ending balance (in dollars per share)	$ 20.19	[1]	$ 20.04	[1]
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility, minimum (in hundreds)	28.00%
Expected volatility, maximum (in hundreds)	30.00%
Expected dividend yield, minimum (in hundreds)	3.98%
Expected dividend yield, maximum (in hundreds)	4.35%
Risk-free interest rate, minimum (in hundreds)	0.61%
Risk-free interest rate, maximum (in hundreds)	1.15%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Granted (in shares)	140,128
Earned (in shares)	(68,258)
Forfeited (in shares)	(61,612)
Ending balance (in shares)	442,042		431,784
Granted and issued (in shares)	140,128
Weighted average granted (in dollars per share)	$ 26.15	[1]	$ 23.37		$ 15.04
Weighted average earned (in dollars per share)	$ 11.04	[1]
Weighted average forfeited (in dollars per share)	$ 22.38	[1]
Weighted average ending balance (in dollars per share)	$ 21.06	[1]	$ 18.01	[1]
Share-based Compensation Arrangement by share-based Payment Award, Options, Outstanding [Roll Forward]
Weighted average granted and issued (in dollars per share)	$ 26.15	[1]	$ 23.37		$ 15.04
Remaining weighted-average contractual term (in years)	0.9
Weighted-average grant-date fair value of shares granted (in dollars per share)	$ 26.15	[1]	$ 23.37		$ 15.04
Fair value of performance shares earned and paid	0.8
Total unrecognized compensation expense	3.4
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Granted (in shares)	182,385
Forfeited (in shares)	(53,171)
Ending balance (in shares)	386,183		406,657
Granted and issued (in shares)	182,385
Vested (in shares)	(149,688)
Weighted average granted (in dollars per share)	$ 19.03	[1]	$ 17.80		$ 14.36
Weighted average forfeited (in dollars per share)	$ 17.25	[1]
Weighted average ending balance (in dollars per share)	$ 17.06	[1]	$ 16.23	[1]
Total fair value of shares vested	2.6		7.3		5.4
Share-based Compensation Arrangement by share-based Payment Award, Options, Outstanding [Roll Forward]
Weighted average granted and issued (in dollars per share)	$ 19.03	[1]	$ 17.80		$ 14.36
Remaining weighted-average contractual term (in years)	1.3
Weighted-average grant-date fair value of shares granted (in dollars per share)	$ 19.03	[1]	$ 17.80		$ 14.36
Weighted average vested (in dollars per share)	$ 17.29	[1]
Total unrecognized compensation expense	2.9
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Ending balance (in shares)			198,781
Weighted average ending balance (in dollars per share)	$ 25.91	[1]	$ 32.51	[1]
Share-based Compensation Arrangement by share-based Payment Award, Options, Outstanding [Roll Forward]
Forfeited or expired (in shares)	(189,428)
Outstanding and exercisable, ending balance (in shares)	9,353
Exercise price forfeited or expired (in dollars per share)	$ 32.83	[1]
Remaining weighted-average contractual term (in years)	0.6
Kansas City Power and Light Company [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	3.5		3.0		4.3
Income tax benefits	$ 1.3		$ 0.5		$ 0.8

[1] weighted-average

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Instruments [Abstract]

Values of open positions for derivative instruments

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

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

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.8		5.0
Total Derivatives		$	7.8	$	5.5
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9

KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

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

Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
Interest rate contracts	$	(5.3	)	Interest charges	$	(16.9	)
Commodity contracts		(0.6	)	Fuel		(0.1	)
Income tax benefit		2.3		Income tax benefit		6.6
Total	$	(3.6	)	Total	$	(10.4	)
2010
Interest rate contracts	$	(27.1	)	Interest charges	$	(10.1	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		10.8		Income tax benefit		4.0
Total	$	(17.2	)	Total	$	(6.6	)

KCP&L
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(8.7	)
Commodity contracts		(0.6	)	Fuel		(0.1	)
Income tax benefit		0.2		Income tax benefit		3.4
Total	$	(0.4	)	Total	$	(5.4	)
2010
Interest rate contracts	$	-		Interest charges	$	(8.8	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		0.3		Income tax benefit		3.6
Total	$	(0.6	)	Total	$	(5.7	)

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

Great Plains Energy
Derivatives in Regulatory Account Relationship
				Gain (Loss) Reclassified from
				Regulatory Account
	Amount of Gain (Loss)
	Recognized on Regulatory
	Account on Derivatives			Income Statement
	(Effective Portion)			Classification	Amount
	(millions)				(millions)
2011
Commodity contracts	$	(8.3	)	Fuel	$	(3.8	)
Total	$	(8.3	)	Total	$	(3.8	)
2010
Commodity contracts	$	(8.2	)	Fuel	$	(7.2	)
Total	$	(8.2	)	Total	$	(7.2	)

Accumulated other comprehensive income related to cash flow hedges

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

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

2.   SUPPLEMENTAL CASH FLOW INFORMATION

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

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

Significant Non-Cash Items

On January 1, 2010, Great Plains Energy and KCP&L adopted new accounting guidance for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivable pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s and KCP&L’s balance sheets.  As a result, cash flows from operating activities were reduced by $95.0 million and cash flows from financing activities were raised by $95.0 million with no impact to the net change in cash for the year ended December 31, 2010.

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Short-term Borrowings and Short-term Bank Lines of Credit (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Short-term Debt [Line Items]
Amount of outstanding cash borrowings	$ 22.0	$ 9.5
Commercial paper outstanding	267.0	263.5
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
Weighted-average interest rate from outstanding borrowings	2.06%	3.06%
Amount of letters of credit outstanding	11.6	15.8
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	227.0	263.5
Weighted-average interest rate from outstanding borrowings	0.50%	0.41%
Amount of letters of credit outstanding	21.5	24.4
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	40.0	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)

12 Months Ended

Dec. 31, 2011

Equity Compensation [Abstract]

Equity compensation expense and associated income tax benefits

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

Performance share activity

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

Restricted stock activity

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

Stock option activity

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

Director deferred share units activity

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

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Discontinued Operations

12 Months Ended

Dec. 31, 2011

Discontinued Operations [Abstract]

Discontinued Operations

22.   DISCONTINUED OPERATIONS

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

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Segments and Related Information

12 Months Ended

Dec. 31, 2011

Segments and Related Information [Abstract]

Segments and Related Information

21.   SEGMENTS AND RELATED INFORMATION

Great Plains Energy has one reportable segment based on its method of internal reporting, which segregates reportable segments based on products and services, management responsibility and regulation.  The one reportable business segment is electric utility, consisting of KCP&L and GMO’s regulated utility operations.  Other includes GMO activity other than its regulated utility operations, unallocated corporate charges, consolidating entries and intercompany eliminations.  Intercompany eliminations include insignificant amounts of intercompany financing-related activities.  The summary of significant accounting policies applies to the reportable segment.  Segment performance is evaluated based on net income attributable to Great Plains Energy.

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

	Electric						Great Plains
2011	Utility			Other			Energy
	(millions)
Operating revenues	$	2,318.0		$	-		$	2,318.0
Depreciation and amortization		(273.1	)		-			(273.1	)
Interest charges		(176.9	)		(41.5	)		(218.4	)
Income tax (expense) benefit		(109.3	)		24.5			(84.8	)
Net income (loss) attributable to Great Plains Energy		199.9			(25.5	)		174.4

	Electric						Great Plains
2010	Utility			Other			Energy
	(millions)
Operating revenues	$	2,255.5		$	-		$	2,255.5
Depreciation and amortization		(331.6	)		-			(331.6	)
Interest charges		(143.1	)		(41.7	)		(184.8	)
Income tax (expense) benefit		(123.3	)		24.3			(99.0	)
Net income (loss) attributable to Great Plains Energy		235.3			(23.6	)		211.7

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

	Electric							Great Plains
	Utility		Other		Eliminations			Energy
2011	(millions)
Assets	$	9,483.4	$	51.9	$	(417.3	)	$	9,118.0
Capital expenditures		456.6		-		-			456.6
2010
Assets	$	9,152.7	$	66.3	$	(400.8	)	$	8,818.2
Capital expenditures		618.1		-		-			618.1
2009
Assets	$	8,765.3	$	152.5	$	(435.0	)	$	8,482.8
Capital expenditures		841.3		-		-			841.3

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Nuclear Plant (Details) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010	Jan. 02, 2010
Investments in decommissioning trust fund [Line Items]
Cost Basis	$ 123,100,000		$ 114,600,000
Gross Unrealized Gains	16,800,000		15,700,000
Gross Unrealized Losses	(4,600,000)		(1,100,000)
Fair Value, Nuclear decommissioning trust fund	135,300,000		129,200,000
Weighted average maturity of debt securities	7.0
Realized Gains on investments in decommissioning trust fund	1,000,000		7,300,000	2,800,000
Realized Losses on investments in decommissioning trust fund	(700,000)		(600,000)	(8,300,000)
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, ending balance	135,300,000		129,200,000
Wolf Creek Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Current cost of decommissioning (in 2011 dollars)	630,000,000
Future cost of decommissioning (in 2045-2053 dollars)	2,455,000,000	[1]
Annual escalation factor	3.73%
Annual return on trust assets through 2025	6.89%	[2]
Annual return on trust assets beginning in 2053	1.81%
Nuclear decommissioning trust fund [Abstract]
Industry aggregate limit on nuclear insurance for property claims including accidental outage	3,200,000,000
Amount of insurance against public liability claims resulting from nuclear incidents to the full limit of public liability	12,600,000,000
Maximum available commercial insurance	400,000,000
Remaining balance provided through an industry-wide retrospective assessment program mandated by law	12,200,000,000
Maximum amount able to be assessed to owners	117,500,000
SFP Program-annual amount payable per incident	17,500,000
Amount of decontamination liability, premature decommissioning liability and property damage insurance	2,800,000,000
Premature decommissioning coverage applies only if property damage exceeds this amount and trust funds have been exhausted	500,000,000
Estimated maximum amount of retrospective assessments under the current policies	30,900,000
Equity Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	76,500,000		73,400,000
Gross Unrealized Gains	12,300,000		13,100,000
Gross Unrealized Losses	(4,500,000)		(1,000,000)
Fair Value, Nuclear decommissioning trust fund	84,300,000		85,500,000
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, ending balance	84,300,000		85,500,000
Debt Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	44,200,000		38,100,000
Gross Unrealized Gains	4,500,000		2,600,000
Gross Unrealized Losses	(100,000)		(100,000)
Fair Value, Nuclear decommissioning trust fund	48,600,000		40,600,000
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, ending balance	48,600,000		40,600,000
Other Securities [Member]
Investments in decommissioning trust fund [Line Items]
Cost Basis	2,400,000		3,100,000
Gross Unrealized Gains	0		0
Gross Unrealized Losses	0		0
Fair Value, Nuclear decommissioning trust fund	2,400,000		3,100,000
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, ending balance	2,400,000		3,100,000
Kansas City Power and Light Company [Member]
Investments in decommissioning trust fund [Line Items]
Fair Value, Nuclear decommissioning trust fund	135,300,000		129,200,000
Nuclear decommissioning trust fund [Abstract]
Nuclear decommissioning trust fund, beginning balance			112,500,000
Contributions to nuclear decommission trust fund	3,400,000		3,700,000
Nuclear decommissioning trust fund earned income, net of fees	4,800,000		2,000,000
Net realized gains (losses) on nuclear decommissioning trust fund	300,000		6,700,000
Net unrealized gains (losses) on nuclear decommissioning trust fund	(2,400,000)		4,300,000
Nuclear decommissioning trust fund, ending balance	135,300,000		129,200,000
Kansas City Power and Light Company [Member] | Wolf Creek Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentage in Wolf Creek, a nuclear generating unit (in hundredths)	47.00%
Current cost of decommissioning (in 2011 dollars)	296,000,000
Future cost of decommissioning (in 2045-2053 dollars)	1,154,000,000	[1]
Nuclear decommissioning trust fund [Abstract]
Maximum amount able to be assessed to owners	55,200,000
SFP Program-annual amount payable per incident	8,200,000
Amount of decontamination liability, premature decommissioning liability and property damage insurance	1,300,000,000
Estimated maximum amount of retrospective assessments under the current policies	$ 14,500,000

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

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

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Debt Disclosure [Abstract]

Long-term debt

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

Amortization of debt expense

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

Schedule of settlement rate by applicable market value

Applicable		Settlement rate	Market value
market value		(in common shares)	per Equity Unit (a)
$16.80 or greater		2.9762 to 1	Greater than $50 per Equity Unit
$16.80 to $14.00		$50 divided by the applicable	Equal to $50 per Equity Unit
		market value to 1
$14.00 or less		3.5714 to 1	Less than $50 per Equity Unit
(a)	Assumes that the market price of the Company's common stock on June 15, 2012,
	is the same as the applicable market value.

Scheduled maturities

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

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Jointly Owned Electric Utility Plants

12 Months Ended

Dec. 31, 2011

Jointly Owned Electric Utility Plants [Abstract]

Jointly Owned Electric Utility Plants

23.   JOINTLY-OWNED ELECTRIC UTILITY PLANTS

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

Great Plains Energy
	Wolf Creek			La Cygne			Iatan No. 1			Iatan No. 2			Iatan			Jeffrey
	Unit			Units			Unit			Unit			Common			Energy Center
	(millions, except MW amounts)
Great Plains Energy's share		47	%		50	%		88	%		73	%		79	%		8	%
Utility plant in service	$	1,473.8		$	493.6		$	667.9		$	1,293.0		$	364.4		$	158.4
Accumulated depreciation		776.3			303.1			252.8			270.0			30.4			75.5
Nuclear fuel, net		76.6			-			-			-			-			-
Construction work in progress		39.4			79.1			6.5			5.9			30.2			5.3
2012 accredited capacity-MWs		547			711			620			641		NA				174

KCP&L
	Wolf Creek			La Cygne			Iatan No. 1			Iatan No. 2			Iatan
	Unit			Units			Unit			Unit			Common
	(millions, except MW amounts)
KCP&L's share		47	%		50	%		70	%		55	%		61	%
Utility plant in service	$	1,473.8		$	493.6		$	542.3		$	985.1		$	287.5
Accumulated depreciation		776.3			303.1			207.9			261.3			26.0
Nuclear fuel, net		76.6			-			-			-			-
Construction work in progress		39.4			79.1			2.6			4.4			9.3
2012 accredited capacity-MWs		547			711			493			482		NA

Each owner must fund its own portion of the plant's operating expenses and capital expenditures.  KCP&L’s and GMO’s share of direct expenses are included in the appropriate operating expense classifications in Great Plains Energy’s and KCP&L’s financial statements.

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Quarterly Operating Results (Unaudited)

12 Months Ended

Dec. 31, 2011

Quarterly Operating Results (Unaudited) [Abstract]

Quarterly Operating Results (Unaudited)

24.   QUARTERLY OPERATING RESULTS (UNAUDITED)

	Quarter
Great Plains Energy	1st		2nd		3rd		4th
2011	(millions, except per share amounts)
Operating revenue	$	492.9	$	565.1	$	773.7	$	486.3
Operating income		41.2		115.6		262.7		60.3
Net income		2.3		43.4		126.6		1.9
Net income attributable to Great Plains Energy		2.4		43.4		126.5		2.1
Basic earnings per common share		0.02		0.32		0.93		0.01
Diluted earnings per common share		0.01		0.31		0.91		0.01
2010
Operating revenue	$	506.9	$	552.0	$	728.8	$	467.8
Operating income		62.0		134.9		243.8		31.6
Net income (loss)		20.3		64.4		132.0		(4.8	)
Net income (loss) attributable to Great Plains Energy		20.3		64.3		132.0		(4.9	)
Basic earnings (loss) per common share		0.15		0.47		0.97		(0.04	)
Diluted earnings (loss) per common share		0.15		0.47		0.96		(0.04	)

	Quarter
KCP&L	1st		2nd		3rd		4th
2011	(millions)
Operating revenue	$	330.8	$	383.4	$	506.3	$	337.8
Operating income		26.5		77.8		169.2		47.7
Net income		4.0		33.4		85.4		12.7
2010
Operating revenue	$	335.6	$	372.6	$	486.5	$	322.4
Operating income		40.5		84.7		163.6		22.6
Net income		19.2		48.2		92.6		3.2

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

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

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

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

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

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

Great Plains Energy’s sole reportable business segment is electric utility.  See Note 21 for additional information.

Use of Estimates

The process of preparing financial statements in conformity with Generally Accepted Accounting Principles (GAAP) requires the use of estimates and assumptions that affect the reported amounts of certain types of assets, liabilities, revenues, and expenses.  Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements.  Accordingly, upon settlement, actual results may differ from estimated amounts.

Cash and Cash Equivalents

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

Funds on Deposit

Funds on deposit consist primarily of cash provided to counterparties in support of margin requirements related to commodity purchases, commodity swaps and futures contracts.  Pursuant to individual contract terms with counterparties, deposit amounts required vary with changes in market prices, credit provisions and various other factors.  Interest is earned on most funds on deposit.  Great Plains Energy also holds funds on deposit from counterparties in the same manner.  These funds are included in other current liabilities on the consolidated balance sheets.

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it is practicable to estimate that value.

Nuclear decommissioning trust fund – KCP&L’s nuclear decommissioning trust fund assets are recorded at fair value.  Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.

Rabbi trust –GMO’s rabbi trusts related to its Supplemental Executive Retirement Plan (SERP) are recorded at fair value, which are based on quoted market prices of the investments held by the trusts and/or valuation models.  The rabbi trusts are included in Other – Investments and Other Assets on Great Plains Energy’s consolidated balance sheets.

Long-term debt – Fair value is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices were not available.  At December 31, 2011, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.5 billion and $3.9 billion, respectively.  At December 31, 2011, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.9 billion and $2.2 billion, respectively.  At December 31, 2010, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.4 billion and $3.7 billion, respectively.  At December 31, 2010, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.8 billion and $1.9 billion, respectively.

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

Pension plans – For financial reporting purposes, the market value of plan assets is the fair value.  KCP&L uses a five-year smoothing of assets to determine fair value for regulatory reporting purposes.

Derivative Instruments

The Company records derivative instruments on the balance sheet at fair value in accordance with GAAP.  Great Plains Energy and KCP&L enter into derivative contracts to manage exposure to commodity price and interest rate fluctuations.  Derivative instruments designated as normal purchases and normal sales (NPNS) and cash flow hedges are used solely for hedging purposes and are not issued or held for speculative reasons.

The Company considers various qualitative factors, such as contract and market place attributes, in designating derivative instruments at inception.  Great Plains Energy and KCP&L may elect the NPNS exception, which requires the effects of the derivative to be recorded when the underlying contract settles.  Great Plains Energy and KCP&L account for derivative instruments that are not designated as NPNS as cash flow hedges or non-hedging derivatives, which are recorded as assets or liabilities on the consolidated balance sheets at fair value.  In addition, if a derivative instrument is designated as a cash flow hedge, Great Plains Energy and KCP&L document the method of determining hedge effectiveness and measuring ineffectiveness.  See Note 18 for additional information regarding derivative financial instruments and hedging activities.

Great Plains Energy and KCP&L offset fair value amounts recognized for derivative instruments under master netting arrangements, which include rights to reclaim cash collateral (a receivable), or the obligation to return cash collateral (a payable). Great Plains Energy and KCP&L classify cash flows from derivative instruments in the same category as the cash flows from the items being hedged.

Utility Plant

Great Plains Energy’s and KCP&L's utility plant is stated at historical cost.  These costs include taxes, an allowance for the cost of borrowed and equity funds used to finance construction and payroll-related costs, including pensions and other fringe benefits.  Replacements, improvements and additions to units of property are capitalized.  Repairs of property and replacements of items not considered to be units of property are expensed as incurred (except as discussed under Deferred Refueling Outage Costs).  When property units are retired or otherwise disposed, the original cost, net of salvage, is charged to accumulated depreciation.  Substantially all of KCP&L’s utility plant is pledged as collateral for KCP&L’s mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented.  Substantially all of GMO’s St. Joseph Light & Power division utility plant is pledged as collateral for GMO’s mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented.

As prescribed by The Federal Energy Regulatory Commission (FERC), Allowance for Funds Used During Construction (AFUDC) is charged to the cost of the plant during construction.  AFUDC equity funds are included as a non-cash item in non-operating income and AFUDC borrowed funds are a reduction of interest charges.  The rates used to compute gross AFUDC are compounded semi-annually and averaged 0.2% in 2011, 6.8% in 2010 and 7.6% in 2009 for KCP&L and for GMO averaged 5.4% in 2011, 4.6% in 2010 and 5.4% in 2009.

Great Plains Energy’s and KCP&L’s balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following tables.

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

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

Depreciation and Amortization

Depreciation and amortization of utility plant other than nuclear fuel is computed using the straight-line method over the estimated lives of depreciable property based on rates approved by state regulatory authorities.  Annual depreciation rates average approximately 3%.  Nuclear fuel is amortized to fuel expense based on the quantity of heat produced during the generation of electricity.

Great Plains Energy’s depreciation expense was $239.9 million, $243.6 million and $228.9 million for 2011, 2010 and 2009, respectively.  KCP&L’s depreciation expense was $162.0 million, $170.9 million and $158.4 million for 2011, 2010 and 2009, respectively.  Great Plains Energy’s and KCP&L’s depreciation and amortization expense includes $14.4 million, $72.6 million and $58.2 million for 2011, 2010 and 2009, respectively, of additional amortization to help maintain cash flow levels during KCP&L’s Comprehensive Energy Plan pursuant to orders of the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC).  This additional amortization concluded following the December 2010 and May 2011 effective dates of new retail rates for KCP&L in Kansas and Missouri, respectively.

Nuclear Plant Decommissioning Costs

Nuclear plant decommissioning cost estimates are based on the immediate dismantlement method and include the costs of decontamination, dismantlement and site restoration.  Based on these cost estimates, KCP&L contributes to a tax-qualified trust fund to be used to decommission Wolf Creek Generating Station (Wolf Creek).  Related liabilities for decommissioning are included on Great Plains Energy’s and KCP&L’s balance sheets in Asset Retirement Obligations (AROs).

As a result of the authorized regulatory treatment and related regulatory accounting, differences between the decommissioning trust fund asset and the related ARO are recorded as a regulatory asset or liability.  See Note 7 for discussion of AROs including those associated with nuclear plant decommissioning costs.

Deferred Refueling Outage Costs

KCP&L uses the deferral method to account for operations and maintenance expenses incurred in support of Wolf Creek’s scheduled refueling outages and amortizes them evenly (monthly) over the unit’s operating cycle of 18 months until the next scheduled outage.  Replacement power costs during an outage are expensed as incurred.

Regulatory Matters

KCP&L and GMO defer items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded if KCP&L and GMO were not regulated.  See Note 5 for additional information concerning regulatory matters.

Revenue Recognition

Great Plains Energy and KCP&L recognize revenues on sales of electricity when the service is provided.  Revenues recorded include electric services provided but not yet billed by KCP&L and GMO.  Unbilled revenues are recorded for kWh usage in the period following the customers’ billing cycle to the end of the month.  KCP&L’s and GMO’s estimate is based on net system kWh usage less actual billed kWhs.  KCP&L’s and GMO’s estimated unbilled kWhs are allocated and priced by regulatory jurisdiction across the rate classes based on actual billing rates.

KCP&L and GMO collect from customers gross receipts taxes levied by state and local governments.  These taxes from KCP&L’s Missouri customers are recorded gross in operating revenues and general taxes on Great Plains Energy’s and KCP&L’s statements of income.  KCP&L’s gross receipts taxes collected from Missouri customers were $55.6 million, $54.3 million, and $46.8 million in 2011, 2010 and 2009, respectively.  These taxes from KCP&L’s Kansas customers and GMO’s customers are recorded net in operating revenues on Great Plains Energy’s statements of income.

Great Plains Energy and KCP&L collect sales taxes from customers and remit to state and local governments.  These taxes are presented on a net basis on Great Plains Energy’s and KCP&L’s statements of income.

Great Plains Energy and KCP&L record sale and purchase activity on a net basis in wholesale revenue or purchased power when transacting with Regional Transmission Organization (RTO)/Independent System Operator (ISO) markets.

Allowance for Doubtful Accounts

This reserve represents estimated uncollectible accounts receivable and is based on management’s judgment considering historical loss experience and the characteristics of existing accounts.  Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses.  Receivables are charged off against the reserve when they are deemed uncollectible.

Property Gains and Losses

Net gains and losses from the sale of assets and businesses and from asset impairments are recorded in operating expenses.

Asset Impairments

Long-lived assets and finite-lived intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  If the sum of the undiscounted expected future cash flows from an asset to be held and used is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements.  The amount of impairment recognized is the excess of the carrying value of the asset over its fair value.

Goodwill and indefinite lived intangible assets are tested for impairment annually and when an event occurs indicating the possibility that an impairment exists.  The annual test must be performed at the same time each year.  If the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements.  To measure the amount of the impairment loss to recognize, the implied fair value of the reporting unit goodwill is compared with its carrying value.

Income Taxes

Income taxes are accounted for using the asset/liability approach.  Deferred tax assets and liabilities are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, applying enacted statutory tax rates in effect for the year in which the differences are expected to reverse.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized.

Great Plains Energy and KCP&L recognize tax benefits based on a “more-likely-than-not” recognition threshold.  In addition, Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.

Great Plains Energy files a consolidated federal income tax return as well as unitary and combined income tax returns in several state jurisdictions with Kansas and Missouri being the most significant.  Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss.  KCP&L’s income tax provision includes taxes allocated based on its separate company income or loss.

Great Plains Energy and KCP&L have established a net regulatory asset for the additional future revenues to be collected from customers for deferred income taxes.  Tax credits are recognized in the year generated except for certain KCP&L and GMO investment tax credits that have been deferred and amortized over the remaining service lives of the related properties.

Environmental Matters

Environmental costs are accrued when it is probable a liability has been incurred and the amount of the liability can be reasonably estimated.

Basic and Diluted Earnings per Common Share Calculation

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

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

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

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

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

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

Dividends Declared

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

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

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Schedule I Financial Statements of Parent Company

12 Months Ended

Dec. 31, 2011

Schedule I Financial Statements of Parent Company [Abstract]

Schedule I Financial Statements of Parent Company

Schedule I – Parent Company Financial Statements

GREAT PLAINS ENERGY INCORPORATED
Income Statements of Parent Company
Year Ended December 31	2011			2010			2009
Operating Expenses	(millions, except per share amounts)
Selling, general and administrative	$	0.8		$	1.2		$	8.8
Maintenance		-			-			0.2
General taxes		0.9			0.9			1.1
Total		1.7			2.1			10.1
Operating loss		(1.7	)		(2.1	)		(10.1	)
Equity in earnings from subsidiaries		200.8			239.3			174.7
Non-operating income		24.7			3.4			-
Interest charges		(66.5	)		(44.7	)		(28.2	)
Income from continuing operations before income taxes		157.3			195.9			136.4
Income tax benefit		17.1			15.8			15.2
Income from continuing operations		174.4			211.7			151.6
Equity in loss from discontinued subsidiary		-			-			(1.5	)
Net income		174.4			211.7			150.1
Preferred stock dividend requirements		1.6			1.6			1.6
Earnings available for common shareholders	$	172.8		$	210.1		$	148.5
Average number of basic common shares outstanding		135.6			135.1			129.3
Average number of diluted common shares outstanding		138.7			136.9			129.8
Basic earnings (loss) per common share
Continuing operations	$	1.27		$	1.55		$	1.16
Discontinued operations		-			-			(0.01	)
Basic earnings per common share	$	1.27		$	1.55		$	1.15
Diluted earnings (loss) per common share
Continuing operations	$	1.25		$	1.53		$	1.15
Discontinued operations		-			-			(0.01	)
Diluted earnings per common share	$	1.25		$	1.53		$	1.14
Cash dividends per common share	$	0.835		$	0.83		$	0.83
The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Balance Sheets of Parent Company
December 31	2011			2010
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	-		$	0.3
Notes receivable from subsidiaries		0.6			249.4
Money pool receivable		0.9			2.0
Taxes receivable		0.9			7.2
Other		0.6			0.7
Total		3.0			259.6
Investments and Other Assets
Investment in KCP&L		2,045.5			2,005.0
Investments in other subsidiaries		1,377.0			1,360.2
Note receivable from subsidiaries		596.2			-
Deferred income taxes		33.7			7.2
Other		6.4			6.2
Total		4,058.8			3,378.6
Total	$	4,061.8		$	3,638.2
LIABILITIES AND CAPITALIZATION
Current Liabilities
Notes payable	$	22.0		$	9.5
Current maturities of long-term debt		287.5			-
Accounts payable to subsidiaries		31.8			31.1
Accrued taxes		5.1			-
Accrued interest		7.6			6.4
Derivative instruments		-			20.8
Other		2.9			7.1
Total		356.9			74.9
Deferred Credits and Other Liabilities
Other		6.7			1.4
Total		6.7			1.4
Capitalization
Common shareholders' equity
Common stock - 250,000,000 shares authorized without par value
136,406,306 and 136,113,954 shares issued, stated value		2,330.6			2,324.4
Retained earnings		684.7			626.5
Treasury stock - 264,567 and 400,889 shares, at cost		(5.6	)		(8.9	)
Accumulated other comprehensive loss		(49.8	)		(56.1	)
Total		2,959.9			2,885.9
Cumulative preferred stock $100 par value
3.80% - 100,000 shares issued		10.0			10.0
4.50% - 100,000 shares issued		10.0			10.0
4.20% - 70,000 shares issued		7.0			7.0
4.35% - 120,000 shares issued		12.0			12.0
Total		39.0			39.0
Long-term debt		699.3			637.0
Total		3,698.2			3,561.9
Commitments and Contingencies
Total	$	4,061.8		$	3,638.2
The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Statements of Cash Flows of Parent Company
Year Ended December 31	2011			2010			2009
Cash Flows from Operating Activities	(millions)
Net income	$	174.4		$	211.7		$	150.1
Adjustments to reconcile income to net cash from operating activities:
Amortization		11.2			3.9			1.9
Deferred income taxes, net		(18.6	)		13.9			(6.1	)
Equity in earnings from subsidiaries		(200.8	)		(239.3	)		(174.7	)
Equity in (earnings) loss from discontinued subsidiary		-			-			1.5
Cash flows affected by changes in:
Accounts receivable from subsidiaries		-			(2.6	)		3.7
Taxes receivable		6.3			-			4.8
Accounts payable to subsidiaries		(0.3	)		2.2			0.2
Other accounts payable		-			(0.1	)		0.1
Accrued taxes		5.2			-			-
Accrued interest		1.2			2.7			1.4
Cash dividends from subsidiaries		148.0			138.6			94.0
Interest hedge settlement		(26.1	)		(6.9	)		-
Other		2.1			(0.9	)		8.8
Net cash from operating activities		102.6			123.2			85.7
Cash Flows from Investing Activities
Equity contributions to subsidiaries		-			-			(455.0	)
Intercompany lending		(347.4	)		(248.8	)		-
Net money pool lending		1.1			(1.1	)		(0.9	)
Net cash from investing activities		(346.3	)		(249.9	)		(455.9	)
Cash Flows from Financing Activities
Issuance of common stock		5.9			6.2			219.9
Issuance of long-term debt		349.7			249.9			287.5
Issuance fees		(3.2	)		(3.2	)		(18.8	)
Net change in short-term borrowings		12.5			(10.5	)		(10.0	)
Dividends paid		(115.1	)		(114.2	)		(110.5	)
Other financing activities		(6.4	)		(7.3	)		(3.8	)
Net cash from financing activities		243.4			120.9			364.3
Net Change in Cash and Cash Equivalents		(0.3	)		(5.8	)		(5.9	)
Cash and Cash Equivalents at Beginning of Year		0.3			6.1			12.0
Cash and Cash Equivalents at End of Year	$	-		$	0.3		$	6.1
The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED

Statements of Common Shareholders’ Equity of Parent Company

Statements of Comprehensive Income of Parent Company

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

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Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2011

Goodwill and Intangible Assets [Abstract]

Intangible Assets included in Electric Utility Plant

	December 31, 2011					December 31, 2010
	Gross Carrying		Accumulated			Gross Carrying		Accumulated
	Amount		Amortization			Amount		Amortization
KCP&L	(millions)
Computer software	$	171.7	$	(129.9	)	$	168.2	$	(118.0	)
Asset improvements		11.7		(0.6	)		5.8		-
Great Plains Energy
Computer software	$	202.5	$	(143.5	)	$	201.1	$	(137.3	)
Asset improvements		27.0		(3.7	)		27.9		(4.4	)

Amortization expense

	2011		2010
	(millions)
Great Plains Energy	$	13.5	$	13.1
KCP&L		12.6		12.2

Schedule of future amortization expense for intangible assets

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

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Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Jan. 02, 2010
Utility plant [Abstract]
Cost	$ 10,924,800,000	[1]	$ 10,536,900,000	[1]
Depreciation and Amortization [Abstract]
Annual depreciation rates (in hundredths)	3.00%
Depreciation expense	239,900,000		243,600,000		228,900,000
Revenue Recognition [Abstract]
Gross receipts taxes collected	55,600,000		54,300,000		46,800,000
Income [Abstract]
Income from continuing operations	174,200,000		211,900,000		151,900,000
Less: net income attributable to noncontrolling interest	(200,000)		200,000		300,000
Less: preferred stock dividend requirements	1,600,000		1,600,000		1,600,000
Income from continuing operations available for common shareholders	172,800,000		210,100,000		150,000,000
Common Shares Outstanding [Abstract]
Average number of common shares outstanding (in shares)	135,600,000		135,100,000		129,300,000
Add: effect of dilutive securities (in shares)	3,100,000		1,800,000		500,000
Diluted average number of common shares outstanding (in shares)	138,700,000		136,900,000		129,800,000
Earnings per share [Abstract]
Basic EPS from continuing operations (in dollars per share)	$ 1.27		$ 1.55		$ 1.16
Diluted EPS from continuing operations (in dollars per share)	$ 1.25		$ 1.53		$ 1.15
Dividends Declared [Abstract]
Subsequent Event Description	Great Plains Energys Board of Directors declared a quarterly dividend and also declared regular dividends on Great Plains Energys preferred stock.
Dividend Declared [Member]
Dividends Declared [Abstract]
Subsequent event date	Feb. 01, 2012
Subsequent per share amount (in dollars per share)	$ 0.2125
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares (in shares)	43,641		251,526		438,281
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares (in shares)	6,000		196,137		231,670
Performance Shares [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares (in shares)	50,897		340,690		150,895
Utility plant generation [Member]
Utility plant [Abstract]
Cost	6,594,000,000		6,369,400,000
Useful life minimum	20
Useful life maximum	60
Utiltiy plant transmission [Member]
Utility plant [Abstract]
Cost	734,800,000		716,900,000
Useful life minimum	15
Useful life maximum	70
Utility plant distribution [Member]
Utility plant [Abstract]
Cost	2,921,100,000		2,813,400,000
Useful life minimum	8
Useful life maximum	66
Utility plant general [Member]
Utility plant [Abstract]
Cost	674,900,000		637,200,000
Useful life minimum	5
Useful life maximum	50
Land and other assets [Member]
Utility plant [Abstract]
Cost	105,500,000		103,000,000
Energy Plan [Member]
Depreciation and Amortization [Abstract]
Depreciation expense	14,400,000		72,600,000		58,200,000
Kansas City Power and Light Company [Member]
Utility plant [Abstract]
Cost	7,829,300,000	[2]	7,540,900,000	[2]
Interest rate on allowance for funds used during construction	0.20%		6.80%		7.60%
Depreciation and Amortization [Abstract]
Annual depreciation rates (in hundredths)	3.00%
Depreciation expense	162,000,000		170,900,000		158,400,000
Revenue Recognition [Abstract]
Gross receipts taxes collected	55,600,000		54,300,000		46,800,000
Kansas City Power and Light Company [Member] | Dividend Declared [Member]
Dividends Declared [Abstract]
Subsequent event date	Feb. 01, 2012
Subsequent Event Amount	25,000,000
Subsequent Event Description	KCP&Ls Board of Directors declared a cash dividend payable to Great Plains Energy
Kansas City Power and Light Company [Member] | Utility plant generation [Member]
Utility plant [Abstract]
Cost	5,078,100,000		4,886,200,000
Useful life minimum	20
Useful life maximum	60
Kansas City Power and Light Company [Member] | Utiltiy plant transmission [Member]
Utility plant [Abstract]
Cost	412,900,000		408,700,000
Useful life minimum	15
Useful life maximum	70
Kansas City Power and Light Company [Member] | Utility plant distribution [Member]
Utility plant [Abstract]
Cost	1,840,200,000		1,776,400,000
Useful life minimum	8
Useful life maximum	55
Kansas City Power and Light Company [Member] | Utility plant general [Member]
Utility plant [Abstract]
Cost	498,100,000		469,600,000
Useful life minimum	5
Useful life maximum	50
Kansas City Power and Light Company [Member] | Land and other assets [Member]
Utility plant [Abstract]
Cost	59,800,000		59,900,000
Kansas City Power and Light Company [Member] | Energy Plan [Member]
Depreciation and Amortization [Abstract]
Depreciation expense	14,400,000		72,600,000		58,200,000
KCPL Greater Missouri Operations [Member]
Utility plant [Abstract]
Interest rate on allowance for funds used during construction	5.40%		4.60%		5.40%
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair value of financial instruments [Abstract}
Long-term debt	3,500,000,000		3,400,000,000
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Kansas City Power and Light Company [Member]
Fair value of financial instruments [Abstract}
Long-term debt	1,900,000,000		1,800,000,000
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair value of financial instruments [Abstract}
Long-term debt	3,900,000,000		3,700,000,000
Estimate of Fair Value, Fair Value Disclosure [Member] | Kansas City Power and Light Company [Member]
Fair value of financial instruments [Abstract}
Long-term debt	$ 2,200,000,000		$ 1,900,000,000

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

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

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Derivative Instruments, Group 2 (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	$ (47.9)	$ (54.7)
Derivative [Line Items]
Accumulated other comprehensive income that is expected to be reclassified in the next twelve months	20.5
Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(31.4)	(36.4)
Derivative [Line Items]
Accumulated other comprehensive income that is expected to be reclassified in the next twelve months	9.1
Cash Flow Hedging [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	11.3	12.0
Cash Flow Hedging [Member] | Current assets [Member] | Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	11.3	12.0
Cash Flow Hedging [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(89.5)	(101.5)
Cash Flow Hedging [Member] | Current liabilities [Member] | Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(62.5)	(71.6)
Cash Flow Hedging [Member] | Noncurrent liabilities [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(0.2)	0
Cash Flow Hedging [Member] | Noncurrent liabilities [Member] | Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	(0.2)	0
Cash Flow Hedging [Member] | Deferred income taxes [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	30.5	34.8
Cash Flow Hedging [Member] | Deferred income taxes [Member] | Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Recorded amounts included in accumulated other comprehensive income	20.0	23.2
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Instrument, Current and Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	0	0.1
Derivative liability, fair value, amount not offset against collateral	0.5	0.1
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Instrument, Current and Noncurrent [Member] | Kansas City Power and Light Company [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	0	0.1
Derivative liability, fair value, amount not offset against collateral	0.5	0.1
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Derivative Instrument, Current and Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	7.8	9.4
Derivative liability, fair value, amount not offset against collateral	5.0	3.0
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Instrument, Current and Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	0	0
Derivative liability, fair value, amount not offset against collateral	0	20.8
Total Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, amount not offset against collateral	7.8	9.5
Derivative liability, fair value, amount not offset against collateral	$ 5.5	$ 23.9

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

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Expenses related to lease commitments

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

Lease and purchase commitments

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

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

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Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest (USD $) In Millions, except Share data, unless otherwise specified	Total	Kansas City Power and Light Company [Member]	Common Stock [Member]	Common Stock [Member] Kansas City Power and Light Company [Member]	Retained Earnings [Member]	Retained Earnings [Member] Kansas City Power and Light Company [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Other Comprehensive Income (Loss) [Member] Kansas City Power and Light Company [Member]	Noncontrolling Interest [Member]
Beginning balance at Dec. 31, 2009			$ 2,313.7	$ 1,563.1	$ 529.2	$ 410.1	$ (5.5)	$ (44.9)	$ (41.5)	$ 1.2
Beginning balance (in shares) at Dec. 31, 2009			135,636,538	1			(213,423)
Distribution										(0.2)
Total Great Plains Energy Common Shareholders' Equity	2,885.9	2,005.0
Derivative hedging activity, net of tax	(10.6)	5.1						(10.6)	5.1
Change in unrecognized pension expense, net of tax	(0.6)							(0.6)
Net income (loss) attributable to Great Plains Energy	211.7				211.7	163.2
Treasury shares acquired							(3.4)
Treasury shares acquired (in shares)							(188,383)
Treasury shares reissued							0
Treasury shares reissued (in shares)							917
Issuance of common stock			6.6
Issuance of common stock (in shares)			347,279
Common stock issuance fees			0
Issuance of restricted common stock			2.3
Issuance of restricted common stock (in shares)			130,137
Equity compensation expense, net of forfeitures			1.0
Unearned Compensation [Abstract]
Issuance of restricted common stock			(2.3)
Forfeiture of restricted common stock			0.8
Compensation expense recognized			2.2
Equity Units allocated fees and expenses and the present value of contract adjustment payments			0
Other			0.1
Equity contribution from Great Plains Energy				0
Dividends:
Common stock					(112.6)	(95.0)
Preferred stock - at required rates					(1.6)
Performance shares					(0.2)
Performance shares amendment					0
Net income attributable to noncontrolling interest										0.2
Ending balance at Dec. 31, 2010			2,324.4	1,563.1	626.5	478.3	(8.9)	(56.1)	(36.4)	1.2
Ending balance (in shares) at Dec. 31, 2010			136,113,954	1			(400,889)
Beginning balance at Jan. 01, 2011
Distribution										0
Total Great Plains Energy Common Shareholders' Equity	2,959.9	2,045.5
Derivative hedging activity, net of tax	6.8	5.0						6.8	5.0
Change in unrecognized pension expense, net of tax	(0.5)							(0.5)
Net income (loss) attributable to Great Plains Energy	174.4				174.4	135.5
Loss On Reissuance Of Treasury Stock					(0.7)
Treasury shares acquired							(2.4)
Treasury shares acquired (in shares)							(125,234)
Treasury shares reissued							5.7
Treasury shares reissued (in shares)							261,556
Issuance of common stock			5.9
Issuance of common stock (in shares)			292,352
Common stock issuance fees			0
Issuance of restricted common stock			0
Issuance of restricted common stock (in shares)			0
Equity compensation expense, net of forfeitures			0.3
Unearned Compensation [Abstract]
Issuance of restricted common stock			(3.5)
Forfeiture of restricted common stock			0.9
Compensation expense recognized			2.3
Equity Units allocated fees and expenses and the present value of contract adjustment payments			0
Other			0.3
Equity contribution from Great Plains Energy				0
Dividends:
Common stock					(113.5)	(100.0)
Preferred stock - at required rates					(1.6)
Performance shares					(0.4)
Performance shares amendment					0
Net income attributable to noncontrolling interest										(0.2)
Ending balance at Dec. 31, 2011			$ 2,330.6	$ 1,563.1	$ 684.7	$ 513.8	$ (5.6)	$ (49.8)	$ (31.4)	$ 1.0
Ending balance (in shares) at Dec. 31, 2011			136,406,306	1			(264,567)

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

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Utility plant schedule

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

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

Basic and diluted earnings per share

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

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Preferred Stock (Details) (USD $)	Dec. 31, 2011	Dec. 31, 2010
Class of Stock [Line Items]
Preferred stock shares, Par value	$ 100.00	$ 100.00
Preferred stock shares outstanding	390,000
Cumulative No Par Preferred Stock [Member]
Class of Stock [Line Items]
Preferred stock shares authorized	1,600,000
Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred stock shares authorized	390,000
Optional redemption percentage of par value, minimum (in hundredths)	101.00%
Optional redemption percentage of par value, maximum (in hundredths)	103.70%
Preference Stock [Member]
Class of Stock [Line Items]
Preferred stock shares authorized	11,000,000

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Legal Proceedings

12 Months Ended

Dec. 31, 2011

Legal Proceedings [Abstract]

Legal Proceedings

15.   LEGAL PROCEEDINGS

KCP&L Spent Nuclear Fuel and Radioactive Waste

In January 2004, KCP&L and the other two Wolf Creek owners filed a lawsuit against the United States in the U.S. Court of Federal Claims seeking $14.1 million of damages resulting from the government’s failure to begin accepting spent nuclear fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982.  The Wolf Creek case was tried before a U.S. Court of Federal Claims judge in June 2010, and a decision was issued in November 2010, granting KCP&L and the other two Wolf Creek owners $10.6 million ($5.0 million KCP&L share) in damages.  In January 2011, KCP&L and the other two Wolf Creek owners as well as the United States filed appeals of the decision to the U.S. Court of Appeals for the Federal Circuit.  Briefing to the Court was completed in December 2011, and oral argument has been scheduled for March 7, 2012.

GMO Price Reporting Litigation

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

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

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Elements [Abstract]

Supplemental cash flow information

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

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

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Related Party Transactions and Relationships

12 Months Ended

Dec. 31, 2011

Related Party Transactions and Relationships [Abstract]

Related Party Transactions and Relationships

17.   RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

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

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

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Guarantees (Details) (KCPL Greater Missouri Operations [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Direct Guarantee [Member]
Guarantor Obligations [Line Items]
Guarantor obligation, maximum exposure	$ 40.7
Term of guarantee	expire in 2012
Revolving Line of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor obligation, maximum exposure	450.0
Term of guarantee	expiring in December 2016
Letters of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor obligation, maximum exposure	11.6
Term of guarantee	expire in 2012
Long-term Debt Guarantee [Member]
Guarantor Obligations [Line Items]
Guarantor obligation, maximum exposure	$ 613.7
Term of guarantee	maturity dates ranging from 2012-2023

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

XML

Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 6.2	$ 10.8
Funds on deposit	1.4	5.2
Receivables, net	231.2	241.7
Accounts receivable pledged as collateral	95.0	95.0
Fuel inventories, at average cost	89.0	85.1
Materials and supplies, at average cost	140.3	132.8
Deferred refueling outage costs	27.5	9.6
Refundable income taxes	0.3	2.1
Deferred income taxes	7.5	14.3
Derivative instruments	1.0	1.1
Prepaid expenses and other assets	19.7	13.9
Total	619.1	611.6
Utility Plant, at Original Cost
Electric	10,924.8	10,536.9
Less-accumulated depreciation	4,235.8	4,031.3
Net utility plant in service	6,689.0	6,505.6
Construction work in progress	287.9	307.5
Nuclear fuel, net of amortization of $132.7 and $131.1	76.6	79.2
Total	7,053.5	6,892.3
Investments and Other Assets
Nuclear decommissioning trust fund	135.3	129.2
Regulatory Assets	1,058.2	924.0
Goodwill	169.0	169.0
Derivative instruments	6.8	7.8
Other	76.1	84.3
Total	1,445.4	1,314.3
Total	9,118.0	8,818.2
Current Liabilities
Notes payable	22.0	9.5
Collateralized note payable	95.0	95.0
Commercial paper	267.0	263.5
Current maturities of long-term debt	801.4	485.7
Accounts payable	275.6	276.3
Accrued taxes	25.8	26.6
Accrued interest	76.9	75.4
Accrued compensation and benefits	40.8	46.8
Pension and post-retirement liability	4.4	4.1
Derivative instruments	0	20.8
Other	26.0	35.6
Total	1,634.9	1,339.3
Deferred Credits and Other Liabilities
Deferred income taxes	628.6	518.3
Deferred tax credits	131.2	133.4
Asset retirement obligations	149.6	143.3
Pension and post-retirement liability	461.9	427.5
Regulatory Liabilities	268.5	258.2
Other	101.1	129.4
Total	1,740.9	1,610.1
Common shareholders' equity
Common stock - Great Plains - 250,000,000 shares authorized without par value 136,406,306 and 136,113,954 shares issued, stated value; Kansas City Power and Light Company - 1,000 shares authorized without par value, 1 share issued, stated value	2,330.6	2,324.4
Retained earnings	684.7	626.5
Treasury stock-264,567 and 400,889 shares, at cost	(5.6)	(8.9)
Accumulated other comprehensive loss	(49.8)	(56.1)
Total	2,959.9	2,885.9
Noncontrolling interest	1.0	1.2
Cumulative preferred stock $100 par value
3.8% - 100,000 shares issued	10.0	10.0
4.50% - 100,000 shares issued	10.0	10.0
4.20% - 70,000 shares issued	7.0	7.0
4.35% - 120,000 shares issued	12.0	12.0
Total	39.0	39.0
Long-term debt (Note 11)	2,742.3	2,942.7
Total	5,742.2	5,868.8
Commitments and Contingencies (Note 14)
Total	9,118.0	8,818.2
Kansas City Power and Light Company [Member]
Current Assets
Cash and cash equivalents	1.9	3.6
Funds on deposit	0.1	0.4
Receivables, net	172.9	169.4
Accounts receivable pledged as collateral	95.0	95.0
Fuel inventories, at average cost	59.0	44.9
Materials and supplies, at average cost	101.1	94.4
Deferred refueling outage costs	27.5	9.6
Refundable income taxes	5.7	9.0
Deferred income taxes	0	5.6
Prepaid expenses and other assets	16.0	10.0
Total	479.2	441.9
Utility Plant, at Original Cost
Electric	7,829.3	7,540.9
Less-accumulated depreciation	3,243.0	3,104.4
Net utility plant in service	4,586.3	4,436.5
Construction work in progress	203.5	227.6
Nuclear fuel, net of amortization of $132.7 and $131.1	76.6	79.2
Total	4,866.4	4,743.3
Investments and Other Assets
Nuclear decommissioning trust fund	135.3	129.2
Regulatory Assets	780.7	679.6
Other	30.6	32.3
Total	946.6	841.1
Total	6,292.2	6,026.3
Current Liabilities
Notes payable	0	0
Collateralized note payable	95.0	95.0
Commercial paper	227.0	263.5
Current maturities of long-term debt	12.7	150.3
Accounts payable	214.8	201.7
Accrued taxes	20.6	21.3
Accrued interest	30.0	26.2
Accrued compensation and benefits	40.8	46.8
Pension and post-retirement liability	3.0	2.6
Other	13.7	7.8
Total	657.6	815.2
Deferred Credits and Other Liabilities
Deferred income taxes	772.7	692.0
Deferred tax credits	127.9	129.4
Asset retirement obligations	134.3	129.7
Pension and post-retirement liability	440.9	407.3
Regulatory Liabilities	142.8	141.3
Other	68.6	76.7
Total	1,687.2	1,576.4
Common shareholders' equity
Common stock - Great Plains - 250,000,000 shares authorized without par value 136,406,306 and 136,113,954 shares issued, stated value; Kansas City Power and Light Company - 1,000 shares authorized without par value, 1 share issued, stated value	1,563.1	1,563.1
Retained earnings	513.8	478.3
Accumulated other comprehensive loss	(31.4)	(36.4)
Total	2,045.5	2,005.0
Cumulative preferred stock $100 par value
Long-term debt (Note 11)	1,901.9	1,629.7
Total	3,947.4	3,634.7
Total	$ 6,292.2	$ 6,026.3

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

12 Months Ended

Dec. 31, 2011

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

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

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

Great Plains Energy’s $200 Million Revolving Credit Facility

In December 2011, Great Plains Energy entered into an amendment to its $200 million revolving credit facility with a group of banks to extend the term to December 2016 from August 2013.  The facility’s terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time.  A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At December 31, 2011, Great Plains Energy was in compliance with this covenant.  At December 31, 2011, Great Plains Energy had $22.0 million of outstanding cash borrowings at a weighted-average interest rate of 2.06% and had issued letters of credit totaling $11.6 million under the credit facility.  At December 31, 2010, Great Plains Energy had $9.5 million of outstanding cash borrowings at a weighted-average interest rate of 3.06% and had issued letters of credit totaling $15.8 million under the credit facility.

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

In December 2011, KCP&L entered into an amendment to its $600 million revolving credit facility with a group of banks that provides support for its issuance of commercial paper and other general corporate purposes to extend the term to December 2016 from August 2013.  Great Plains Energy and KCP&L may transfer up to $200 million of unused commitments between Great Plains Energy’s and KCP&L’s facilities.  A default by KCP&L on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At December 31, 2011, KCP&L was in compliance with this covenant.  At December 31, 2011, KCP&L had $227.0 million of commercial paper outstanding, at a weighted-average interest rate of 0.50%, had issued letters of credit totaling $21.5 million and had no outstanding cash borrowings under the credit facility.  At December 31, 2010, KCP&L had $263.5 million of commercial paper outstanding, at a weighted-average interest rate of 0.41%, had issued letters of credit totaling $24.4 million and had no outstanding cash borrowings under the credit facility.

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

In December 2011, GMO entered into an amendment to its $450 million revolving credit facility with a group of banks that provides support for its issuance of commercial paper and other general corporate purposes to extend the term to December 2016 from August 2013.  Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy’s and GMO’s facilities.  A default by GMO, Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility.  Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.  At December 31, 2011, GMO was in compliance with this covenant.  At December 31, 2011, GMO had $40.0 million of commercial paper outstanding, at a weighted-average interest rate of 0.88%, had issued letters of credit totaling $13.2 million and had no outstanding cash borrowings under the credit facility.  At December 31, 2010, GMO had no outstanding cash borrowings and had issued letters of credit totaling $13.2 million under the credit facility.

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

XML

Long-Term Debt

12 Months Ended

Dec. 31, 2011

Debt Disclosure [Abstract]

Long-Term Debt

11.   LONG-TERM DEBT

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

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

Amortization of Debt Expense

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

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

KCP&L General Mortgage Bonds and EIRR Bonds

KCP&L has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented (Indenture).  The Indenture creates a mortgage lien on substantially all of KCP&L’s utility plant.

In April 2011, KCP&L purchased in lieu of redemption its $63.3 million EIRR Series 2007A-1, $10.0 million EIRR Series 2007A-2 and $39.5 million EIRR Series 1993B bonds.  KCP&L opted to purchase rather than remarket the bonds given the poor conditions in the tax-exempt market.  As of December 31, 2011, the bonds were still outstanding, but were not reported as a liability on the balance sheet since they are being held by KCP&L.  KCP&L has the ability to remarket these bonds to third parties whenever it determines market conditions are sufficiently attractive to do so.

Mortgage bonds totaling $642.5 million and $755.3 million were outstanding at December 31, 2011 and 2010, respectively.

KCP&L Municipal Bond Insurance Policies

KCP&L’s EIRR Bonds Series 2007 A-1, 2007 A-2 and 2007B totaling $146.5 million are covered by a municipal bond insurance policy issued by Financial Guaranty Insurance Company (FGIC).  The insurance agreement between KCP&L and FGIC provides for reimbursement by KCP&L for any amounts that FGIC pays under the municipal bond insurance policy.  The policy also restricts the amount of secured debt KCP&L may issue.  In 2009, because KCP&L issued debt secured by liens not permitted by the agreement or resulting in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization, KCP&L was required to issue and deliver collateral to FGIC in the form of $146.5 million of Mortgage Bonds Series 2007 EIRR Issuer due 2035.  The bonds are not incremental debt for KCP&L but collateralize FGIC’s claim on KCP&L if FGIC was required to meet its obligation under the insurance agreement.

KCP&L’s secured 1992 Series EIRR bonds totaling $31.0 million, secured Series 1993A and 1993B EIRR bonds totaling $79.5 million, and secured and unsecured EIRR Bonds Series 2005 totaling $35.9 million and $50.0 million, respectively, are covered by a municipal bond insurance policy between KCP&L and Syncora Guarantee, Inc. (Syncora).  The insurance agreements between KCP&L and Syncora provide for reimbursement by KCP&L for any amounts that Syncora pays under the municipal bond insurance policies.  The insurance agreements contain a covenant that the indebtedness to total capitalization ratio of KCP&L and its consolidated subsidiaries will not be greater than 0.68 to 1.00.  At December 31, 2011, KCP&L was in compliance with this covenant.  KCP&L is also restricted from issuing additional bonds under its General Mortgage Indenture if, after giving effect to such additional bonds, the proportion of secured debt to total indebtedness would be more than 75%, or more than 50% if the long term rating for such bonds by Standard & Poor’s or Moody’s Investors Service would be at or below A- or A3, respectively.  The insurance agreement covering the unsecured EIRR Bond Series 2005 also required KCP&L to provide collateral to Syncora in the form of $50.0 million of Mortgage Bonds Series 2005 EIRR Insurer due 2035 for KCP&L’s obligations under the insurance agreement as a result of KCP&L issuing general mortgage bonds in 2009 (other than refunding of outstanding general mortgage bonds) that resulted in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization.  The bonds are not incremental debt for KCP&L but collateralize Syncora’s claim on KCP&L if Syncora was required to meet its obligation under the insurance agreement.  In the event of a default under the insurance agreements, Syncora may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.

KCP&L Senior Notes

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

GMO First Mortgage Bonds

GMO has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented.  The Indenture creates a mortgage lien on substantially all of GMO’s St. Joseph Light & Power division utility plant.  Mortgage bonds totaling $11.2 million and $12.4 million, respectively, were outstanding at December 31, 2011 and 2010.

GMO Senior Notes

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

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

Great Plains Energy Senior Notes

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

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

In May 2009, Great Plains Energy issued $287.5 million of Equity Units.  Equity Units, each with a stated amount of $50, initially consist of a 5% undivided beneficial interest in $1,000 principal amount of 10.00% subordinated notes due June 15, 2042, and a purchase contract requiring the holder to purchase the Company’s common stock by June 15, 2012 (the settlement date).  Each purchase contract obligates the holder of the purchase contract to purchase, and Great Plains Energy to sell, no later than June 15, 2012, for $50 in cash, newly issued shares of the Company’s common stock equal to the settlement rate.  The purchase contracts may be settled earlier at the option of the holder subject to certain conditions, including but not limited to, the occurrence of a fundamental change (as defined in the agreement) at least 20 business days prior to June 15, 2012.  The settlement rate will vary according to the applicable market value of the Company’s common stock at the settlement date.  The applicable market value will be measured by the average of the closing price per share of the Company’s common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding June 15, 2012.  The settlement rate will be applied to the 5,750,000 Equity Units at the settlement date to issue a number of common shares determined as described in the following table.

Applicable		Settlement rate	Market value
market value		(in common shares)	per Equity Unit (a)
$16.80 or greater		2.9762 to 1	Greater than $50 per Equity Unit
$16.80 to $14.00		$50 divided by the applicable	Equal to $50 per Equity Unit
		market value to 1
$14.00 or less		3.5714 to 1	Less than $50 per Equity Unit
(a)	Assumes that the market price of the Company's common stock on June 15, 2012,
	is the same as the applicable market value.

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

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

Scheduled Maturities

Great Plains Energy’s and KCP&L’s long-term debt maturities for the next five years are detailed in the following table.

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

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

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Schedule II Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010	Dec. 31, 2008
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period		$ 7.1		$ 6.8
Additions charged to costs and expenses	13.7	9.7	8.7
Additions charged to other accounts	6.9	6.9	6.0
Deductions	20.8	16.7	14.4
Balance at end of period	6.8	7.0		6.8
Allowance for Doubtful Accounts [Member] | Kansas City Power and Light Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period		1.7		1.2
Additions charged to costs and expenses	8.8	6.2	5.5
Additions charged to other accounts	4.5	4.3	3.9
Deductions	13.4	10.7	8.9
Balance at end of period	1.4	1.5		1.2
Legal Reserve [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period		5.1		10.2
Additions charged to costs and expenses	(0.1)	7.0	2.6
Additions charged to other accounts	0	0	0
Deductions	3.4	1.9	7.7
Balance at end of period	6.7	10.2		10.2
Legal Reserve [Member] | Kansas City Power and Light Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period		2.3		2.4
Additions charged to costs and expenses	1.3	1.9	1.2
Additions charged to other accounts	0	0	0
Deductions	0.4	1.2	1.3
Balance at end of period	3.9	3.0		2.4
Reserve for Environmental Costs [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period		2.4		0.5
Additions charged to costs and expenses	0	0.1	2.0
Additions charged to other accounts	0	0	0
Deductions	0	0	0.1
Balance at end of period	2.5	2.5		0.5
Reserve for Environmental Costs [Member] | Kansas City Power and Light Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period		0.3		0.3
Additions charged to costs and expenses	0	0	0
Additions charged to other accounts	0	0	0
Deductions	0	0	0
Balance at end of period	0.3	0.3		0.3
Valuation Allowance of Deferred Tax Assets [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period		29.8		75.8
Additions charged to costs and expenses	0.1	0.2	57.0
Additions charged to other accounts	0	0	0
Deductions	2.8	3.4	103.0
Balance at end of period	$ 23.9	$ 26.6		$ 75.8

XML

Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Utility Plant, at Original Cost
Nuclear fuel, amortization	132.7	131.1
Common shareholder's equity
Common stock - shares authorized (in shares)	250,000,000	250,000,000
Common stock-shares issued (in shares)	136,406,306	136,113,954
Treasury stock- shares (in shares)	264,567	400,889
Cumulative preferred stock
Cumulative preferred stock par value (in dollars per share)	100.00	100.00
Preferred Stock 3 Point 80 [Member]
Cumulative preferred stock
Cumulative preferred stock, Shares issued (in share)	100,000	100,000
Cumulative preferred stock, Dividend rate (in hundredths)	3.80%	3.80%
Preferred Stock 4 Point 50 [Member]
Cumulative preferred stock
Cumulative preferred stock, Shares issued (in share)	100,000	100,000
Cumulative preferred stock, Dividend rate (in hundredths)	4.50%	4.50%
Preferred Stock 4 Point 20 [Member]
Cumulative preferred stock
Cumulative preferred stock, Shares issued (in share)	70,000	70,000
Cumulative preferred stock, Dividend rate (in hundredths)	4.20%	4.20%
Preferred Stock 4 Point 35 [Member]
Cumulative preferred stock
Cumulative preferred stock, Shares issued (in share)	120,000	120,000
Cumulative preferred stock, Dividend rate (in hundredths)	4.35%	4.35%
Subsidiaries [Member]
Utility Plant, at Original Cost
Nuclear fuel, amortization	132.7	131.1
Common shareholder's equity
Common stock - shares authorized (in shares)	1,000	1,000
Common stock-shares issued (in shares)	1	1

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Regulatory Matters

12 Months Ended

Dec. 31, 2011

Regulatory Matters [Abstract]

Regulatory Matters

5.   REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

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

KCP&L Missouri Rate Case Proceedings

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

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

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

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

GMO Missouri Rate Case Proceedings

On February 27, 2012, GMO filed an application with the MPSC to request an increase of its retail rates of $58.3 million for its Missouri Public Service division and $25.2 million for its L&P division, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%.  The requests include recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service, costs related to energy efficiency and demand side management programs, and increased fuel costs.

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

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

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

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

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

GMO Fuel Adjustment Clause (FAC) Prudence Review

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

SPP and NERC Inquiries

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

Regulatory Assets and Liabilities

Great Plains Energy and KCP&L have recorded assets and liabilities on their consolidated balance sheets resulting from the effects of the ratemaking process, which would not otherwise be recorded if the Companies were not regulated.  Regulatory assets represent incurred costs that are probable of recovery from future revenues.  Regulatory liabilities represent future reductions in revenues or refunds to customers.

Management regularly assesses whether regulatory assets and liabilities are probable of future recovery or refund by considering factors such as decisions by the MPSC, KCC or FERC in KCP&L’s and GMO’s rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedent on matters applicable to the Companies; and changes in laws and regulations.  If recovery or refund of regulatory assets or liabilities is not approved by regulators or is no longer deemed probable, these regulatory assets or liabilities are recognized in the current period results of operations.  The Companies’ continued ability to meet the criteria for recording regulatory assets and liabilities may be affected in the future by restructuring and deregulation in the electric industry or changes in accounting rules.  In the event that the criteria no longer applied to any or all of the Companies’ operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism were provided.  Additionally, these factors could result in an impairment on utility plant assets.   Great Plains Energy’s and KCP&L’s regulatory assets and liabilities are detailed in the following tables.

							Great
December 31, 2011	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	119.6		$	24.6		$	144.2
Loss on reacquired debt		9.1	(a)		2.7	(a)		11.8
Cost of removal		4.6			-			4.6
Asset retirement obligations		31.4			13.8			45.2
Pension and post-retirement costs		466.4	(b)		122.0	(b)		588.4
Deferred customer programs		48.2	(c)		20.6			68.8
Rate case expenses		9.6	(d)		3.8	(d)		13.4
Skill set realignment costs		3.4	(e)		-			3.4
Fuel adjustment clauses		14.0	(d)		36.4	(d)		50.4
Acquisition transition costs		24.7	(f )		20.2	(f )		44.9
Derivative instruments		-			7.6	(g)		7.6
Iatan No. 1 and Common facilities depreciation and carrying costs		16.4			6.1			22.5
Iatan No. 2 construction accounting costs		27.9			15.4			43.3
Kansas property tax surcharge		3.7	(d)		-			3.7
Other		1.7	(h)		4.3	(h)		6.0
Total	$	780.7		$	277.5		$	1,058.2
Regulatory Liabilities
Emission allowances	$	82.0		$	0.2		$	82.2
Asset retirement obligations		49.3			-			49.3
Pension		0.7			40.8			41.5
Cost of removal		-			61.9	(i)		61.9
Other		10.8			22.8			33.6
Total	$	142.8		$	125.7		$	268.5

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

(b) Represents unrecognized gains and losses, prior service and transition costs that will be recognized in future net periodic pension and post-retirement costs, pension settlements amortized over various periods and financial and regulatory accounting method differences not included in rate base that will be eliminated over the life of the pension plans.

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

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

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

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

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

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

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

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

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Nuclear Plant

12 Months Ended

Dec. 31, 2011

Nuclear Plant [Abstract]

Nuclear Plant

4.   NUCLEAR PLANT

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

Spent Nuclear Fuel and High-Level Radioactive Waste

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel.  KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kWh of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel.  These disposal costs are charged to fuel expense.  In 2010, the DOE filed a motion with the Nuclear Regulatory Commission (NRC) to withdraw its then pending application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada.  An NRC board denied the DOE’s motion to withdraw its application, and the DOE appealed that decision to the full NRC.  In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of September 2011 due to a lack of funding.  These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application.  Oral argument to the court is expected later in 2012.  Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025, and believes it will be able to expand on-site storage as needed past 2025.  Management cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.  See Note 15 for a related legal proceeding.

Low-Level Radioactive Waste

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

Nuclear Plant Decommissioning Costs

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

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

Nuclear Decommissioning Trust Fund

In 2011 and 2010, KCP&L contributed approximately $3.4 million and $3.7 million, respectively, to a tax-qualified trust fund to be used to decommission Wolf Creek.  Amounts funded are charged to other operating expense and recovered in customers’ rates.  The funding level assumes a projected level of return on trust assets.  If the actual return on trust assets is below the projected level or actual decommissioning costs are higher than estimated, KCP&L could be responsible for the balance of funds required; however, while there can be no assurances, management believes a rate increase would be allowed to recover decommissioning costs over the remaining life of the unit.

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

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

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

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

The weighted average maturity of debt securities held by the trust at December 31, 2011, was approximately 7 years.  The costs of securities sold are determined on the basis of specific identification.  The following table summarizes the realized gains and losses from the sale of securities in the nuclear decommissioning trust fund.

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

Nuclear Insurance

The owners of Wolf Creek (Owners) maintain nuclear insurance for Wolf Creek for nuclear liability, nuclear property and accidental outage.  These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war.  The nuclear property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for acts of terrorism and related losses, including replacement power costs.  There is no industry aggregate limit for liability claims related to terrorism, regardless of the number of acts of terrorism affecting Wolf Creek or any other nuclear energy liability policy or the number of policies in place.  An industry aggregate limit of $3.2 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), the Owners’ insurance provider, exists for property claims related to terrorism, including accidental outage power costs for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act.  These limits plus any recoverable reinsurance are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts.  In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

In the event of a catastrophic loss at Wolf Creek, the insurance coverage may not be adequate to cover property damage and extra expenses incurred.  Uninsured losses, to the extent not recovered through rates, would be assumed by KCP&L and the other owners and could have a material effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, which was reauthorized through December 31, 2025, by the Energy Policy Act of 2005, the Owners are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently $12.6 billion.  This limit of liability consists of the maximum available commercial insurance of $0.4 billion and the remaining $12.2 billion is provided through an industry-wide retrospective assessment program mandated by law, known as the Secondary Financial Protection (SFP) program.  Under the SFP program, the Owners can be assessed up to $117.5 million ($55.2 million, KCP&L’s 47% share) per incident at any commercial reactor in the country, payable at no more than $17.5 million ($8.2 million, KCP&L’s 47% share) per incident per year.  This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes.  In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

Nuclear Property Insurance

The Owners carry decontamination liability, premature decommissioning liability and property damage insurance from NEIL for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, KCP&L's 47% share).  In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC.  KCP&L’s share of any remaining proceeds can be used for further decontamination, property damage restoration and premature decommissioning costs.  Premature decommissioning coverage applies only if an accident at Wolf Creek exceeds $500 million in property damage and decontamination expenses, and only after trust funds have been exhausted.

Accidental Nuclear Outage Insurance

The Owners also carry additional insurance from NEIL to cover costs of replacement power and other extra expenses incurred in the event of a prolonged outage resulting from accidental property damage at Wolf Creek.

Under all NEIL policies, the Owners are subject to retrospective assessments if NEIL losses, for each policy year, exceed the accumulated funds available to the insurer under that policy.  The estimated maximum amount of retrospective assessments under the current policies could total approximately $30.9 million ($14.5 million, KCP&L’s 47% share) per policy year.

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Guarantees

12 Months Ended

Dec. 31, 2011

Guarantees [Abstract]

Guarantees

16.   GUARANTEES

In the ordinary course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries.  Such agreements include, for example, guarantees and letters of credit.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended business purposes.  The majority of these agreements guarantee the Company’s own future performance, so a liability for the fair value of the obligation is not recorded.

At December 31, 2011, Great Plains Energy has provided $666.0 million of credit support for GMO as follows:

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

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

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

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

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Common Shareholders' Equity

12 Months Ended

Dec. 31, 2011

Common Shareholders' Equity [Abstract]

Common Shareholders' Equity

12.   COMMON SHAREHOLDERS’ EQUITY

Great Plains Energy has an effective shelf registration statement for the sale of unspecified amounts of securities with the Securities and Exchange Commission (SEC) that was filed and became effective in May 2009.

Great Plains Energy has 5.0 million shares of common stock registered with the SEC for its Dividend Reinvestment and Direct Stock Purchase Plan.  The plan allows for the purchase of common shares by reinvesting dividends or making optional cash payments.  Great Plains Energy can issue new shares or purchase shares on the open market for the plan.  At December 31, 2011, 0.7 million shares remained available for future issuances.

Great Plains Energy has 12.3 million shares of common stock registered with the SEC for a defined contribution savings plan.  Shares issued under the plan may be either newly issued shares or shares purchased in the open market.  At December 31, 2011, 0.4 million shares remained available for future issuances.

Treasury shares are held for future distribution upon issuance of shares in conjunction with the Company’s Long-Term Incentive Plan.

Great Plains Energy’s articles of incorporation restrict the payment of common stock dividends in the event common equity is 25% or less of total capitalization.  In addition, if preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares.  If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of directors necessary to constitute a majority of the full Board.  Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at least 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress).  Under the Federal Power Act, KCP&L and GMO generally can pay dividends only out of retained earnings.  The revolving credit agreements of Great Plains Energy, KCP&L and GMO contain a covenant requiring each company to maintain a consolidated indebtedness to consolidated total capitalization ratio of not more than 0.65 to 1.00.  In addition, Great Plains Energy is prohibited from paying dividends on its common and preferred stock in the event its Equity Unit contract payments or interest payments on the debt underlying the Equity Units are deferred until such deferrals have been paid.

As of December 31, 2011, all of Great Plains Energy’s and KCP&L’s retained earnings and net income were free of restrictions.  As a result of the above restrictions, Great Plains Energy’s subsidiaries had restricted net assets of approximately $2.8 billion as of December 31, 2011.  The restrictions are not expected to affect the Companies’ ability to pay dividends at the current level in the foreseeable future.

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Pension Plans and Other Employee Benefits

12 Months Ended

Dec. 31, 2011

Pension Plans and Other Employee Benefits [Abstract]

Pension Plans and Other Employee Benefits

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

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

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

During 2011, Great Plains Energy recorded settlement charges of $10.1 million from the voluntary separation program as a result of accelerated pension distributions.  The Companies deferred substantially all of the charges as a regulatory asset and expect to recover it over future periods pursuant to regulatory agreements.  See below for information regarding the voluntary separation program.

The following pension benefits tables provide information relating to the funded status of all defined benefit pension plans on an aggregate basis as well as the components of net periodic benefit costs.  For financial reporting purposes, the market value of plan assets is the fair value.  KCP&L uses a five-year smoothing of assets to determine fair value for regulatory reporting purposes.  Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with joint owners of power plants.

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

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

For financial reporting purposes, the estimated prior service cost and net loss for the defined benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2012 are $4.5 million and $44.5 million, respectively.  For financial reporting purposes, net actuarial gains and losses are recognized on a rolling five-year average basis.  For regulatory reporting purposes, net actuarial gains and losses are amortized over ten years.  The estimated prior service cost, net gain and transition costs for the other post-retirement benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2012 are $7.2 million, $(0.1) million and $1.0 million, respectively.

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

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

The GMO SERP is reflected as an unfunded ABO of $20.6 million.  Great Plains Energy has segregated approximately $20.1 million of assets for this plan as of December 31, 2011, and expects to fund future benefit payments from these assets.

The expected long-term rate of return on plan assets represents Great Plains Energy’s estimate of the long-term return on plan assets and is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios.  Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns of various asset classes.  Based on the target asset allocation for each asset class, the overall expected rate of return for the portfolios was developed and adjusted for the effect of projected benefits paid from plan assets and future plan contributions.  The following tables provide the weighted-average assumptions used to determine benefit obligations and net costs.

Weighted-average assumptions used to determine	Pension Benefits						Other Benefits
the benefit obligation at plan year-end	2011			2010			2011			2010
Discount rate		5.01	%		5.54	%		5.03	%		5.50	%
Rate of compensation increase		4.08	%		4.08	%		4.07	%		4.06	%
Weighted-average assumptions used to determine	Pension Benefits						Other Benefits
net costs for years ended December 31	2011			2010			2011			2010
Discount rate		5.54	%		5.92	%		5.50	%		5.87	%
Expected long-term return on plan assets		7.29	%		8.00	%		2.83	% *		4.25	% *
Rate of compensation increase		4.08	%		4.26	%		4.06	%		4.25	%
* after tax

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

Great Plains Energy expects to contribute $94.5 million to the pension plans in 2012 to meet Employee Retirement Income Security Act of 1974 (ERISA) funding requirements and regulatory orders, the majority of which is expected to be paid by KCP&L.  Great Plains Energy’s funding policy is to contribute amounts sufficient to meet the ERISA funding requirements and MPSC and KCC rate orders plus additional amounts as considered appropriate; therefore, actual contributions may differ from expected contributions.  Great Plains Energy also expects to contribute $16.7 million to other post-retirement benefit plans in 2012, the majority of which is expected to be paid by KCP&L.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid through 2021.

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

Pension plan assets are managed in accordance with prudent investor guidelines contained in the ERISA requirements.  The investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets within a reasonable and prudent level of risk.  The portfolios are invested, and periodically rebalanced, to achieve targeted allocations of approximately 27% U.S. large cap and small cap equity securities, 20% international equity securities, 36% fixed income securities, 7% real estate, 6% commodities and 4% hedge funds.  Fixed income securities include domestic and foreign corporate bonds, collateralized mortgage obligations and asset-backed securities, U.S. government agency, state and local obligations, U.S. treasury notes and money market funds.

The fair values of Great Plains Energy’s pension plan assets at December 31, 2011 and 2010, by asset category are in the following tables.

			Fair Value Measurements Using
Description	December 31 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions)
Pension Plans
Equity securities
U.S.(a)	$	156.3	$	94.6	$	61.7	$	-
International(b)		117.0		40.9		76.1		-
Real estate(c)		34.7		-		-		34.7
Commodities(d)		34.6		-		34.6		-
Fixed income securities
Fixed income funds(e)		166.5		34.2		132.3		-
U.S. Treasury		4.9		4.9		-		-
U.S. Agency, state and local obligations		17.7		-		17.7		-
U.S. corporate bonds(f)		26.6		-		26.6		-
Foreign corporate bonds		2.6		-		2.6		-
Hedge funds(g)		21.7		-		-		21.7
Total	$	582.6	$	174.6	$	351.6	$	56.4
Cash equivalents - money market funds		8.5
Total Pension Plans	$	591.1

				Fair Value Measurements Using
Description		December 31 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Pension Plans
	Equity securities
	U.S.(a)	$	158.5	$	90.5	$	68.0	$	-
	International(b)		122.4		39.4		83.0		-
	Limited partnerships		0.1		-		-		0.1
	Real estate(c)		30.3		-		-		30.3
	Commodities(d)		37.0		-		37.0		-
	Fixed income securities
	Fixed income funds(e)		148.7		23.0		125.7		-
	U.S. Treasury		1.8		1.8		-		-
	U.S. Agency, state and local obligations		14.8		-		14.8		-
	U.S. corporate bonds(f)		24.2				24.2		-
	Foreign corporate bonds		1.5		-		1.5		-
	Hedge funds(g)		8.4		-		-		8.4
	Total	$	547.7	$	154.7	$	354.2	$	38.8
	Cash equivalents - money market funds		9.9
	Total Pension Plans	$	557.6
(a)	At December 31, 2011 and 2010, this category is comprised of $94.6 million and $90.5 million, respectively, of traded mutual funds valued at daily listed prices and $61.7 million and $68.0 million, respectively,
	of institutional common/collective trust funds valued at daily Net Asset Values (NAV) per share.
(b)	At December 31, 2011 and 2010, this category is comprised of $40.9 million and $39.4 million, respectively, of traded mutual funds valued at daily listed prices and $76.1 million and $83.0 million, respectively,
	of institutional common/collective trust funds valued at daily NAV per share.
(c)	This category is comprised of institutional common/collective trust funds and a limited partnership valued at NAV on a quarterly basis.
(d)	This category is comprised of institutional common/collective trust funds valued at daily NAV per share.
(e)	At December 31, 2011 and 2010, this category is comprised of $34.2 million and $23.0 million, respectively, of traded mutual funds valued at daily listed prices and $132.3 million and $125.7 million, respectively, of institutional common/collective trust funds valued at daily NAV per share.
(f)	At December 31, 2011 and 2010, this category is comprised of $18.1 million and $13.9 million, respectively, of corporate bonds, $6.1 million and $8.0 million, respectively, of collateralized mortgage obligations
	and $2.4 million and $2.3 million, respectively, of other asset-backed securities.
(g)	This category is comprised of closely-held limited partnerships valued at NAV on a quarterly basis.

The following tables reconcile the beginning and ending balances for all level 3 pension plan assets measured at fair value on a recurring basis for 2011 and 2010.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Real		Hedge			Limited
Description	Estate		Funds			Partnerships			Total
	(millions)
Balance January 1, 2011	$	30.3	$	8.4		$	0.1		$	38.8
Actual return on plan assets
Relating to assets still held		3.9		(1.3	)		(0.1	)		2.5
Relating to assets sold		-		-			-			-
Purchase, sales, and settlements		0.5		14.6			-			15.1
Transfers in and/or out of Level 3		-		-			-			-
Balance December 31, 2011	$	34.7	$	21.7		$	-		$	56.4

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

Other post-retirement plan assets are also managed in accordance with prudent investor guidelines contained in the ERISA requirements.  The investment strategy supports the objective of the funds, which is to preserve capital, maintain sufficient liquidity and earn a consistent rate of return.  Other post-retirement plan assets are invested primarily in fixed income securities, which may include domestic and foreign corporate bonds, collateralized mortgage obligations and asset-backed securities, U.S. government agency, state and local obligations, U.S. Treasury notes and money market funds, as well as domestic and international equity funds.

The fair values of Great Plains Energy’s other post-retirement plan assets at December 31, 2011 and 2010, by asset category are in the following tables.

				Fair Value Measurements Using
Description		December 31 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
	Equity securities	$	1.4	$	1.4	$	-	$	-
	Fixed income
	U.S. Treasury		14.3		14.3		-		-
	U.S. Agency, state and local obligations		27.2		-		27.2		-
	U.S. corporate bonds (a)		14.8		-		14.8		-
	Foreign corporate bonds		1.5		-		1.5		-
	Mutual funds		0.2		0.2		-		-
	Total	$	59.4	$	15.9	$	43.5	$	-
	Cash and cash equivalents - money market funds		18.0
	Total Other Post-Retirement Benefit Plans	$	77.4
(a)	This category is comprised of $12.7 million of corporate bonds, $0.6 million of collateralized mortgage obligations and $1.5 million
	of other asset-backed securities.

				Fair Value Measurements Using
Description		December 31 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
	Fixed income
	U.S. Treasury	$	12.1	$	12.1	$	-	$	-
	U.S. Agency, state and local obligations		22.2		-		22.2		-
	U.S. corporate bonds (a)		11.4		-		11.4		-
	Foreign corporate bonds		1.0				1.0
	Mutual funds		0.1		0.1		-		-
	Total	$	46.8	$	12.2	$	34.6	$	-
	Cash and cash equivalents - money market funds		19.0
	Total Other Post-Retirement Benefit Plans	$	65.8
(a)	This category is comprised of $9.2 million of corporate bonds, $0.9 million of collateralized mortgage obligations and $1.3 million
	of other asset-backed securities.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.  The cost trend assumed for 2011 and 2012 was 8.0%, with the rate declining through 2018 to the ultimate cost trend rate of 5%.  The health care plan requires retirees to make monthly contributions on behalf of themselves and their dependents in an amount determined by Great Plains Energy.

The effects of a one-percentage point change in the assumed health care cost trend rates, holding all other assumptions constant, at December 31, 2011, are detailed in the following table.  The results reflect the increase in the Medicare Part D employer subsidy which is assumed to increase with the medical trend and employer caps on post-65 plans.

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

Employee Savings Plans

Great Plains Energy has defined contribution savings plans (401(k)) that cover substantially all employees.  Great Plains Energy matches employee contributions, subject to limits.  The annual cost of the plans was approximately $9.2 million, $8.9 million and $8.8 million in 2011, 2010 and 2009, respectively.  KCP&L’s annual cost of the plans was approximately $6.7 million, $6.5 million and $6.5 million in 2011, 2010 and 2009, respectively.

Voluntary Separation Program

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

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Pension Plans and Other Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended																																																																								12 Months Ended											12 Months Ended																																							12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010	Dec. 31, 2011 Kansas City Power and Light Company [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member]	Jan. 02, 2010 Kansas City Power and Light Company [Member]	Dec. 31, 2012 Pension Plans, Defined Benefit [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member]	Jan. 02, 2010 Pension Plans, Defined Benefit [Member]	Sep. 30, 2011 Pension Plans, Defined Benefit [Member]	Sep. 30, 2010 Pension Plans, Defined Benefit [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] US Equity Securities [Member] Traded Mutual Funds [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] US Equity Securities [Member] Traded Mutual Funds [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] US Equity Securities [Member] Institutional Common Collective Trust Funds [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] US Equity Securities [Member] Institutional Common Collective Trust Funds [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] International Equity Securities [Member] Traded Mutual Funds [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] International Equity Securities [Member] Traded Mutual Funds [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] International Equity Securities [Member] Institutional Common Collective Trust Funds [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] International Equity Securities [Member] Institutional Common Collective Trust Funds [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Commodity Contract [Member] Traded Mutual Funds [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Commodity Contract [Member] Traded Mutual Funds [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] US corporate bonds [Member] Corporate Bonds [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] US corporate bonds [Member] Corporate Bonds [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] US corporate bonds [Member] Collateralized Mortgage Obligation Securities [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] US corporate bonds [Member] Collateralized Mortgage Obligation Securities [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] US corporate bonds [Member] Asset-backed Securities [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] US corporate bonds [Member] Asset-backed Securities [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] US Equity Securities [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] US Equity Securities [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] International Equity Securities [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] International Equity Securities [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] Fixed Income Funds [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] Fixed Income Funds [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] US Treasury [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] US Treasury [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] Total	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] Total	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US Equity Securities [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US Equity Securities [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] International Equity Securities [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] International Equity Securities [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Commodity Contract [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Commodity Contract [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Fixed Income Funds [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Fixed Income Funds [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US Agency, State and Political Subdivisions Debt Securities [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US Agency, State and Political Subdivisions Debt Securities [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US corporate bonds [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US corporate bonds [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Foreign corporate bonds [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Foreign corporate bonds [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Total	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Total	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 3 [Member] Real Estate [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 3 [Member] Real Estate [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 3 [Member] Hedge Funds [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 3 [Member] Hedge Funds [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 3 [Member] Limited Partnerships Equity Securities [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 3 [Member] Limited Partnerships Equity Securities [Member]	Dec. 31, 2009 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 3 [Member] Limited Partnerships Equity Securities [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 3 [Member] Total	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Fair Value, Inputs, Level 3 [Member] Total	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] Real Estate [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] Real Estate [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] Hedge Funds [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] Hedge Funds [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] Limited Partnerships Equity Securities [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] US Equity Securities [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] US Equity Securities [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] International Equity Securities [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] International Equity Securities [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] Commodity Contract [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] Commodity Contract [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] Fixed Income Funds [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] Fixed Income Funds [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] US Treasury [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] US Treasury [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] US Agency, State and Political Subdivisions Debt Securities [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] US Agency, State and Political Subdivisions Debt Securities [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] US corporate bonds [Member]		Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] US corporate bonds [Member]		Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] Foreign corporate bonds [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] Foreign corporate bonds [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member] Total [Member] Total	Dec. 31, 2010 Pension Plans, Defined Benefit [Member] Total [Member] Total	Dec. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]		Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member]		Jan. 02, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] US corporate bonds [Member] Corporate Bonds [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] US corporate bonds [Member] Corporate Bonds [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] US corporate bonds [Member] Collateralized Mortgage Obligation Securities [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] US corporate bonds [Member] Collateralized Mortgage Obligation Securities [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] US corporate bonds [Member] Asset-backed Securities [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] US corporate bonds [Member] Asset-backed Securities [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] US Equity Securities [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] Fixed Income Funds [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] Fixed Income Funds [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] US Treasury [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] US Treasury [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] Total	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 1 [Member] Total	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US Agency, State and Political Subdivisions Debt Securities [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US Agency, State and Political Subdivisions Debt Securities [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US corporate bonds [Member]		Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] US corporate bonds [Member]		Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Foreign corporate bonds [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Foreign corporate bonds [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Total	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Fair Value, Inputs, Level 2 [Member] Total	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] US Equity Securities [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] Fixed Income Funds [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] Fixed Income Funds [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] US Treasury [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] US Treasury [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] US Agency, State and Political Subdivisions Debt Securities [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] US Agency, State and Political Subdivisions Debt Securities [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] US corporate bonds [Member]		Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] US corporate bonds [Member]		Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] Foreign corporate bonds [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] Foreign corporate bonds [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] Total	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member] Total [Member] Total
Change in projected benefit obligation [Roll Forward]
Projected benefit obligation, at beginning of year							$ 980.6		$ 836.3																																																																																																																		$ 154.2			$ 148.9
Service cost								31.1	30.3	29.1																																																																																																																		3.1		3.8		4.1
Interest cost								49.6	49.3	47.3																																																																																																																		7.8		8.8		8.3
Contribution by participants																																																																																																																												6.6		5.6
Amendments								0	0.5
Actuarial (gain) loss								83.2	55.1																																																																																																																			7.4		(12.5)
Benefits paid								(54.7)	(60.1)																																																																																																																			(14.3)		(11.0)
Settlements								(40.0)	0
Projected benefit obligation, at end of plan year								980.6	911.4																																																																																																																			154.2		143.6
Change in plan assets [Roll Forward]
Fair value of plan assets at beginning of year							591.1		488.2				94.6	90.5	61.7	68.0	40.9	39.4	76.1	83.0	34.2	23.0	18.1	13.9	6.1	8.0	2.4	2.3	8.5	9.9	94.6	[1]	90.5	[1]	40.9	[2]	39.4	[2]	34.2	[3]	23.0	[3]	4.9	1.8	174.6	154.7	61.7	[1]	68.0	[1]	76.1	[2]	83.0	[2]	34.6	[4]	37.0	[4]	132.3	[3]	125.7	[3]	17.7	14.8	26.6	[5]	24.2	[5]	2.6	1.5	351.6	354.2										0.1				34.7	[6]	30.3	[6]	21.7	[7]	8.4	[7]	0.1	156.3	[1]	158.5	[1]	117.0	[2]	122.4	[2]	34.6	[4]	37.0	[4]	166.5	[3]	148.7	[3]	4.9	1.8	17.7	14.8	26.6	[5]	24.2	[5]	2.6	1.5	582.6	547.7	77.4			52.0					12.7	9.2	0.6	0.9	1.5	1.3	18.0	19.0	1.4	0.2	0.1	14.3	12.1	15.9	12.2	27.2	22.2	14.8	[8]	11.4	[9]	1.5	1.0	43.5	34.6	1.4	0.2	0.1	14.3	12.1	27.2	22.2	14.8	[8]	11.4	[9]	1.5	1.0	59.4	46.8
Actual return on plan assets								(3.7)	62.7																																																																																																																			2.5		0.5
Contributions by employer and participants								128.8	64.5																																																																																																																			23.0		23.9
Benefits paid								(91.6)	(57.8)																																																																																																																			(13.9)		(10.6)
Fair value of plan assets at end of plan year								591.1	557.6				94.6	90.5	61.7	68.0	40.9	39.4	76.1	83.0	34.2	23.0	18.1	13.9	6.1	8.0	2.4	2.3	8.5	9.9	94.6	[1]	90.5	[1]	40.9	[2]	39.4	[2]	34.2	[3]	23.0	[3]	4.9	1.8	174.6	154.7	61.7	[1]	68.0	[1]	76.1	[2]	83.0	[2]	34.6	[4]	37.0	[4]	132.3	[3]	125.7	[3]	17.7	14.8	26.6	[5]	24.2	[5]	2.6	1.5	351.6	354.2	34.7		30.3	[6]	21.7		8.4	[7]		0.1		56.4	38.8	34.7	[6]	30.3	[6]	21.7	[7]	8.4	[7]	0.1	156.3	[1]	158.5	[1]	117.0	[2]	122.4	[2]	34.6	[4]	37.0	[4]	166.5	[3]	148.7	[3]	4.9	1.8	17.7	14.8	26.6	[5]	24.2	[5]	2.6	1.5	582.6	547.7		77.4		65.8					12.7	9.2	0.6	0.9	1.5	1.3	18.0	19.0	1.4	0.2	0.1	14.3	12.1	15.9	12.2	27.2	22.2	14.8	[8]	11.4	[9]	1.5	1.0	43.5	34.6	1.4	0.2	0.1	14.3	12.1	27.2	22.2	14.8	[8]	11.4	[9]	1.5	1.0	59.4	46.8
Funded status at end of year								(389.5)	(353.8)																																																																																																																			(76.8)		(77.8)
Amounts recognized in the consolidated balance sheets [Abstract]
Current pension and other post-retirement liability	(4.4)	(4.1)		(3.0)	(2.6)			(3.5)	(3.1)																																																																																																																			(0.9)		(1.0)
Noncurrent pension liability and other post-retirement liability	(461.9)	(427.5)		(440.9)	(407.3)			(386.0)	(350.7)																																																																																																																			(75.9)		(76.8)
Net amount recognized before regulatory treatment								(389.5)	(353.8)																																																																																																																			(76.8)		(77.8)
Accumulated other comprehensive income or regulatory asset/liability								491.8	403.2																																																																																																																			52.5		54.8
Net amount recognized at December 31								102.3	49.4																																																																																																																			(24.3)		(23.0)
Amounts in accumulated other comprehensive income or regulatory asset/liability not yet recognized as a component of net periodic cost [Abstract]
Actuarial loss								295.6	219.5																																																																																																																			15.7		8.5
Prior service cost								10.7	15.3																																																																																																																			36.9		44.1
Transition obligation																																																																																																																												1.7		3.0
Other								185.5	168.4																																																																																																																			(1.8)		(0.8)
Accumulated other comprehensive income or regulatory asset/liability								491.8	403.2																																																																																																																			52.5		54.8
Components of net periodic benefit costs
Service cost								31.1	30.3	29.1																																																																																																																		3.1		3.8		4.1
Interest cost								49.6	49.3	47.3																																																																																																																		7.8		8.8		8.3
Expected return on plan assets								(38.0)	(36.6)	(32.4)																																																																																																																		(1.8)		(2.1)		(1.6)
Prior service cost								4.6	4.6	4.2																																																																																																																		7.2		7.2		6.9
Recognized net actuarial (gain) loss								38.7	37.4	36.3																																																																																																																		(0.5)		(0.1)		(0.4)
Transition obligation								0	0.1	0.1																																																																																																																		1.3		1.3		1.3
Settlement charges								10.1	0	0.1
Net period benefit costs before regulatory adjustment								96.1	85.1	84.7																																																																																																																		17.1		18.9		18.6
Regulatory adjustment								(27.9)	(32.3)	(28.4)																																																																																																																		1.1		0		(0.3)
Net periodic benefit costs								68.2	52.8	56.3																																																																																																																		18.2		18.9		18.3
Other changes in plan assets and benefit obligations recognized in other comprehensive income regulatory assets/liabilities [Abstract]
Current year net (gain) loss	1.2	1.3	(5.0)					114.8	29.1	(9.2)																																																																																																																		6.7		(10.9)		(0.2)
Amortization of gain (loss)	(0.4)	(0.3)	(0.4)					(38.7)	(37.4)	(36.3)																																																																																																																		0.5		0.1		0.4
Prior service cost								0	0.5	5.7																																																																																																																		0		0		24.8
Amortization of prior service cost								(4.6)	(4.6)	(4.2)																																																																																																																		(7.2)		(7.2)		(6.9)
Transition obligation																																																																																																																												0		0		1.2
Amortization of transition obligation								0	(0.1)	(0.1)																																																																																																																		(1.3)		(1.3)		(1.3)
Other regulatory activity								17.1	29.5	10.1																																																																																																																		(1.0)		0.1		(3.1)
Total recognized in other comprehensive income or regulatory asset/liability								88.6	17.0	(34.0)																																																																																																																		(2.3)		(19.2)		14.9
Total recognized in net periodic benefit costs and other comprehensive income or regulatory asset/liability								156.8	69.8	22.3																																																																																																																		15.9		(0.3)		33.2
Estimated prior service cost that will be amortized in the next fiscal year							4.5																																																																																																																				7.2
Net gain (loss) for the defined benefit plans that will be amortized in the next fiscal year							44.5																																																																																																																				(0.1)
Transition costs for the defined benefit plans that will be amortized in the next fiscal year																																																																																																																											1.0
Length of time for amortization of net actuarial gains and losses for financial reporting purposes (in years)								rolling five-year average																																																																																																																				rolling five-year average
Length of time for amortization of net actuarial gains and losses for regulatory reporting purposes (in years)								ten years																																																																																																																				ten years
Accumulated benefit obligation (ABO) for all defined benefit pension plans								852.6	808.8
Pension plans with the accumulated benefit obligation in excess of plan assets [Abstract]
Projected benefit obligation								980.6	911.4
Accumulated benefit obligation								852.6	808.8
Fair value of plan assets								591.1	557.6
Unfunded accumulated benefit obligation for GMO SERP	20.6
Segregated assets for GMO SERP	20.1
Weighted average assumptions used to determine the benefit obligation at plan year-end [Abstract]
Discount rate											5.01%	5.54%																																																																																																																					5.03%	5.50%
Rate of compensation increase											4.08%	4.08%																																																																																																																					4.07%	4.06%
Weighted average assumptions used to determine net costs [Abstract]
Discount rate								5.54%	5.92%																																																																																																																			5.50%		5.87%
Expected long-term return on plan assets							7.30%	7.29%	8.00%																																																																																																																			2.83%	[10]	4.25%	[10]
Rate of compensation increase								4.08%	4.26%																																																																																																																			4.06%		4.25%
Projected weighted average long-term rate of return on plan assets (in hundredths)							7.30%	7.29%	8.00%																																																																																																																			2.83%	[10]	4.25%	[10]
Contribute to plans in next year							94.5																																																																																																																				16.7
2012								76.6																																																																																																																				8.6
2013								65.5																																																																																																																				8.1
2014								67.3																																																																																																																				8.3
2015								66.5																																																																																																																				8.2
2016								70.1																																																																																																																				8.4
2017-2021								381.0																																																																																																																				46.3
Target allocation of U.S. large cap and small cap equity securities (in hundredths)								27.00%
Target allocation of international equity securities (in hundredths)								20.00%
Target allocation of fixed income securities (in hundredths)								36.00%
Target allocation of real estate (in hundredths)								7.00%
Target allocation of commodities (in hundredths)								6.00%
Target allocation of hedge funds (in hundredths)								4.00%
Fair value measurement with unobservable inputs [Roll Forward]
Balance at beginning of period		4.3																																																																									26.8				2.4			0.1	0.1		29.3
Actual return on plan assets [Abstract]
Relating to assets still held																																																																									3.9		2.5		(1.3)		(0.2)		(0.1)			2.5	2.3
Relating to assets sold																																																																															(0.7)						(0.7)
Purchase, sales, and settlements																																																																									0.5		1.0		14.6		6.9					15.1	7.9
Balance at end of period		3.7																																																																							34.7	[6]	30.3	[6]	21.7	[7]	8.4			0.1	0.1
Plan Assets, Fair Value								591.1	557.6				94.6	90.5	61.7	68.0	40.9	39.4	76.1	83.0	34.2	23.0	18.1	13.9	6.1	8.0	2.4	2.3	8.5	9.9	94.6	[1]	90.5	[1]	40.9	[2]	39.4	[2]	34.2	[3]	23.0	[3]	4.9	1.8	174.6	154.7	61.7	[1]	68.0	[1]	76.1	[2]	83.0	[2]	34.6	[4]	37.0	[4]	132.3	[3]	125.7	[3]	17.7	14.8	26.6	[5]	24.2	[5]	2.6	1.5	351.6	354.2	34.7		30.3	[6]	21.7		8.4	[7]		0.1		56.4	38.8	34.7	[6]	30.3	[6]	21.7	[7]	8.4	[7]	0.1	156.3	[1]	158.5	[1]	117.0	[2]	122.4	[2]	34.6	[4]	37.0	[4]	166.5	[3]	148.7	[3]	4.9	1.8	17.7	14.8	26.6	[5]	24.2	[5]	2.6	1.5	582.6	547.7		77.4		65.8					12.7	9.2	0.6	0.9	1.5	1.3	18.0	19.0	1.4	0.2	0.1	14.3	12.1	15.9	12.2	27.2	22.2	14.8	[8]	11.4	[9]	1.5	1.0	43.5	34.6	1.4	0.2	0.1	14.3	12.1	27.2	22.2	14.8	[8]	11.4	[9]	1.5	1.0	59.4	46.8
Health care cost trend (in hundredths)																																																																																																																											8.00%	8.00%
Health cost rate declining through																																																																																																																												2018
Ultimate cost trend rate (in hundredths)																																																																																																																												5.00%
Effect on total service and interest component, increase																																																																																																																												0.5
Effect on total service and interest component, decrease																																																																																																																												(0.4)
Effect on post-retirement benefit obligation, increase																																																																																																																												4.0
Effect on post-retirement benefit obligation, decrease																																																																																																																												(3.5)
Defined contribution savings plans cost of plan	9.2	8.9	8.8	6.7	6.5	6.5
Annual savings in labor costs from realignment process and voluntary separation program								$ 15.0

[1] At December 31, 2011 and 2010, this category is comprised of $94.6 million and $90.5 million, respectively, of traded mutual funds valued at daily listed prices and $61.7 million and $68.0 million, respectively, of institutional common/collective trust funds valued at daily Net Asset Values (NAV) per share.

[2] At December 31, 2011 and 2010, this category is comprised of $40.9 million and $39.4 million, respectively, of traded mutual funds valued at daily listed prices and $76.1 million and $83.0 million, respectively, of institutional common/collective trust funds valued at daily NAV per share.

[3] At December 31, 2011 and 2010, this category is comprised of $34.2 million and $23.0 million, respectively, of traded mutual funds valued at daily listed prices and $132.3 million and $125.7 million, respectively, of institutional common/collective trust funds valued at daily NAV per share.

[4] This category is comprised of institutional common/collective trust funds valued at daily NAV per share.

[5] At December 31, 2011 and 2010, this category is comprised of $18.1 million and $13.9 million, respectively, of corporate bonds, $6.1 million and $8.0 million, respectively, of collateralized mortgage obligations and $2.4 million and $2.3 million, respectively, of other asset-backed securities.

[6] This category is comprised of institutional common/collective trust funds and a limited partnership valued at NAV on a quarterly basis.

[7] This category is comprised of closely-held limited partnerships valued at NAV on a quarterly basis.

[8] This category is comprised of $12.7 million of corporate bonds, $0.6 million of collateralized mortgage obligations and $1.5 million of other asset-backed securities.

[9] This category is comprised of $9.2 million of corporate bonds, $0.9 million of collateralized mortgage obligations and $1.3 million of other asset-backed securities.

[10] after tax

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Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2011

Goodwill and Intangible Assets [Abstract]

Goodwill and Intangible Assets

6.   GOODWILL AND INTANGIBLE ASSETS

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

Great Plains Energy’s and KCP&L’s intangible assets are included in electric utility plant on the consolidated balance sheets and are detailed in the following table.

	December 31, 2011					December 31, 2010
	Gross Carrying		Accumulated			Gross Carrying		Accumulated
	Amount		Amortization			Amount		Amortization
KCP&L	(millions)
Computer software	$	171.7	$	(129.9	)	$	168.2	$	(118.0	)
Asset improvements		11.7		(0.6	)		5.8		-
Great Plains Energy
Computer software	$	202.5	$	(143.5	)	$	201.1	$	(137.3	)
Asset improvements		27.0		(3.7	)		27.9		(4.4	)

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

	2011		2010
	(millions)
Great Plains Energy	$	13.5	$	13.1
KCP&L		12.6		12.2

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

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

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

7.   ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations associated with tangible long-lived assets are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.  These liabilities are recognized at estimated fair value as incurred and capitalized as part of the cost of the related long-lived assets and depreciated over their useful lives.  Accretion of the liabilities due to the passage of time is recorded to a regulatory asset and/or liability.  Changes in the estimated fair values of the liabilities are recognized when known.

KCP&L has AROs related to decommissioning Wolf Creek, site remediation of its Spearville Wind Energy Facilities, asbestos abatement and for removal of storage tanks, an ash pond and landfill.  GMO has AROs related to asbestos abatement, an ash pond and landfill and removal of storage tanks and communication towers.

GPE and KCP&L have identified an additional asbestos ARO.  Certain wiring used in generating stations includes asbestos insulation, which would require special handling if disturbed.  Due to the inability to reasonably estimate the quantities or the amount of disturbance that will be necessary during dismantlement at the end of the life of a plant, a fair value of the obligation cannot be reasonably estimated at this time.  Management will continue to monitor the obligation and will recognize a liability in the period in which sufficient information becomes available to reasonably estimate its fair value.

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

	Great Plains Energy					KCP&L
	2011			2010		2011			2010
	(millions)
Beginning balance	$	143.3		$	132.6	$	129.7		$	119.8
Additions		0.8			2.0		-			2.0
Revision in timing and/or estimates		(3.8	)		-		(3.8	)		-
Accretion		9.3			8.7		8.4			7.9
Ending balance	$	149.6		$	143.3	$	134.3		$	129.7

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Equity Compensation

12 Months Ended

Dec. 31, 2011

Equity Compensation [Abstract]

Equity Compensation

9.   EQUITY COMPENSATION

Great Plains Energy’s Long-Term Incentive Plan is an equity compensation plan approved by Great Plains Energy’s shareholders.  The Long-Term Incentive Plan permits the grant of restricted stock, restricted stock units, bonus shares, stock options, stock appreciation rights, limited stock appreciation rights, director shares, director deferred share units and performance shares to directors, officers and other employees of Great Plains Energy and KCP&L.  The maximum number of shares of Great Plains Energy common stock that can be issued under the plan is 8.0 million.  Common stock shares delivered by Great Plains Energy under the Long-Term Incentive Plan may be authorized but unissued, held in the treasury or purchased on the open market (including private purchases) in accordance with applicable securities laws.  Great Plains Energy has a policy of delivering newly issued shares, or shares surrendered by Long-Term Incentive Plan participants on account of withholding taxes and held in treasury, or both, and does not expect to repurchase common shares during 2012 to satisfy performance share payments, stock option exercises and director deferred share unit conversion.  Forfeiture rates are based on historical forfeitures and future expectations and are reevaluated annually.

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

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

Performance Shares

The payment of performance shares is contingent upon achievement of specific performance goals over a stated period of time as approved by the Compensation and Development Committee of Great Plains Energy’s Board of Directors.  The number of performance shares ultimately paid can vary from the number of shares initially granted depending on Great Plains Energy’s performance over stated performance periods.  Compensation expense for performance shares is calculated by taking the change in fair value between reporting periods for the portion for which the requisite service has been rendered.  Dividends are accrued over the vesting period and paid in cash based on the number of performance shares ultimately paid.

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

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

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

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

Restricted Stock

Restricted stock cannot be sold or otherwise transferred by the recipient prior to vesting and has a value equal to the fair market value of the shares on the issue date.  Restricted stock shares vest over a stated period of time with accruing reinvested dividends subject to the same restrictions.  Compensation expense, calculated by multiplying shares by the grant-date fair value related to restricted stock, is recognized over the stated vesting period.  Restricted stock activity for 2011 is summarized in the following table.

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

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

Stock Options

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

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

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

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

Director Deferred Share Units

Non-employee directors receive shares of Great Plains Energy’s common stock as part of their annual retainer.  Each director may elect to defer receipt of their shares until the end of January in the year after they leave the Board.  Director Deferred Share Units have a value equal to the market value of Great Plains Energy’s common stock on the grant date with accruing dividends.  Compensation expense, calculated by multiplying the director deferred share units by the related grant-date fair value, is recognized at the grant date.  The total fair value of shares of Director Deferred Share Units issued was insignificant for 2011 and 2010.  Director Deferred Share Units activity for 2011 is summarized in the following table.

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

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Common Shareholders' Equity (Details) (USD $) In Billions, except Share data in Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Common Shareholders' Equity [Abstract]
Shares authorized under the Dividend Reinvestment and Direct Stock Purchase Plan (in shares)	5.0
Number of shares available for grant under Dividend Reinvestment and Direct Stock Purchase Plan (in shares)	0.7
Shares registered under the defined contribution savings plan (in shares)	12.3
Number of shares available under the defined contribution savings plan (in shares)	0.4
Restrictions on the payment of common stock dividends contained in the articles of incorporation	Great Plains Energy's articles of incorporation restrict the payment of common stock dividends in the event common equity is 25 percent or less of total capitalization. In addition, if preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of directors necessary to constitute a majority of the full Board.
Regulatory restrictions on the payment of dividends	Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at least 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress). Under the Federal Power Act, KCP&L and GMO generally can pay dividends only out of retained earnings.
Consolidated indebtedness to consolidated total capitalization ratio required under revolving credit agreement	.65
Restricted net assets of subsidiaries	$ 2.8

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Commitments and Contingencies (Details) (USD $)	12 Months Ended									12 Months Ended					12 Months Ended								12 Months Ended
	Dec. 31, 2011 T MW	Dec. 31, 2010	Jan. 02, 2010	Dec. 31, 2011 Public Utilities, Inventory, Fuel [Member]	Dec. 31, 2011 Power [Member]	Dec. 31, 2011 Purchased Capacity [Member]	Dec. 31, 2011 Non-Regulated Natural Gas Transportation [Member]	Dec. 31, 2011 La Cygne Environmental Project [Member]	Dec. 31, 2011 Other Purchase Commitments [Member]	Dec. 31, 2011 Sublease and Reimbursement Commitments [Member] Other Purchase Commitments [Member]	Dec. 31, 2011 Property, plant and equipment under operating leases [Member]	Dec. 31, 2011 Property, plant and equipment under capital leases [Member]	Dec. 31, 2011 Jeffrey Units Nos 1 and 2 [Member]	Dec. 31, 2011 LaCygne Station Evironmental Retrofits [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] MW T	Dec. 31, 2010 Kansas City Power and Light Company [Member]	Jan. 02, 2010 Kansas City Power and Light Company [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Public Utilities, Inventory, Fuel [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Power [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Purchased Capacity [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] La Cygne Environmental Project [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Other Purchase Commitments [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Sublease and Reimbursement Commitments [Member]	Dec. 31, 2013 Kansas City Power and Light Company [Member] Capacity Sales Agreements [Member]	Dec. 31, 2012 Kansas City Power and Light Company [Member] Capacity Sales Agreements [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Property, plant and equipment under operating leases [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Property, plant and equipment under capital leases [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] LaCygne Station Evironmental Retrofits [Member]	Dec. 31, 2011 KCPL Greater Missouri Operations [Member] MW	Dec. 31, 2011 Westar Energy Inc [Member] Jeffrey Units Nos 1 and 2 [Member]
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														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 by 2011 (in megawatts)															2														2
Cost of Supplemental Environmental Project															150,000
Collaboration Agreement with the Sierra Club and the Concerned Citizens of Platte County [Abstract]
Additional CO2 agreed to be offset (in tons)															711,000
Wind generation capacity installed at Spearville wind site in 2006 (in megawatts)															100
Increased wind generation capacity agreed to pursue in Collaboration Agreement by 2012 - Total (in megawatts)															500
Wind project completed in 2010 (in megawatts)															48
Increased wind generation capacity agreed to add in Collaboration Agreement by 2010 - Total (in megawatts)															100
Renewable energy credits secured (in megawatts)															52
Power purchase agreement (in megawatts)															231														100
Predetermination request for environmental equipment required at LaCygne Station to comply with BART														1,230,000,000														615,000,000
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													300,000	300,000
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
New Source Review [Abstract]
Amount of civil penalty settlement payment																														3,000,000
Estimated cost to install a selective catalytic reduction system at jeffrey Energy Center pursuant to a settlement agreement																														240,000,000
Coal fired units at Jeffrey Energy Center, a jointly owned facility (in number of coal fired facilities)													3
Unrecorded Unconditional Purchase Obligation and Lease Commitments [Line Items]
Lease expense	20,900,000	17,200,000	23,400,000												17,000,000	13,200,000	19,300,000
Operating leases [Abstract]
Operating Leases, Future Minimum Payments Due, Current											19,700,000															16,000,000
Operating Leases, Future Minimum Payments, Due in Two Years											16,300,000															14,000,000
Operating Leases, Future Minimum Payments, Due in Three Years											14,800,000															13,000,000
Operating Leases, Future Minimum Payments, Due in Four Years											13,600,000															12,200,000
Operating Leases, Future Minimum Payments, Due in Five Years											9,800,000															9,700,000
Operating Leases, Future Minimum Payments, Due Thereafter											119,200,000															119,200,000
Total											193,400,000															184,100,000
Capital leases [Abstract]
Capital Leases, Future Minimum Payments Due, Current												400,000															200,000
Capital Leases, Future Minimum Payments Due in Two Years												400,000															200,000
Capital Leases, Future Minimum Payments Due in Three Years												400,000															200,000
Capital Leases, Future Minimum Payments Due in Four Years												400,000															200,000
Capital Leases, Future Minimum Payments Due in Five Years												400,000															200,000
Capital Leases, Future Minimum Payments Due Thereafter												4,700,000															2,600,000
Total												6,700,000															3,600,000
Purchase commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Due within One Year				397,400,000	8,500,000	13,400,000	2,800,000	376,600,000	54,400,000									336,000,000	8,500,000	4,700,000	376,600,000	40,300,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years				360,500,000	29,200,000	12,400,000	3,600,000	300,200,000	101,700,000									298,800,000	29,200,000	3,700,000	300,200,000	100,900,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years				202,000,000	34,800,000	4,500,000	3,600,000	125,400,000	21,000,000									169,100,000	34,800,000	2,900,000	125,400,000	20,200,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years				103,900,000	34,800,000	4,200,000	3,600,000	5,500,000	25,400,000									91,500,000	34,800,000	3,000,000	5,500,000	24,600,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years				83,200,000	34,800,000	2,400,000	3,600,000		3,700,000									79,100,000	34,800,000	1,200,000		2,900,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years				94,100,000	686,300,000	0	900,000		49,800,000									94,100,000	499,100,000	0		39,500,000
Total				1,241,100,000	828,400,000	36,900,000	18,100,000	807,700,000	256,000,000									1,068,600,000	641,200,000	15,500,000	807,700,000	228,400,000
Total commitments [Abstract]
Total Commitments, Due within One Year	873,200,000														782,300,000
Total Commitments, Due within Two Years	824,300,000														747,000,000
Total Commitments, Due within Three Years	406,500,000														365,600,000
Total Commitments, Due within Four Years	191,400,000														171,800,000
Total Commitments, Due within Five Years	137,900,000														127,900,000
Total Commitments, Due after Five Years	955,000,000														754,500,000
Total	3,388,300,000														2,949,100,000
Expected sublease income										1,200,000
Reimbursements by the other owners 2012-2015 (per year)																							2,200,000
Reimbursement by Other Owners 2016-2025 (per year)																							400,000
Reimbursements by the other owners (total)																							13,000,000
Capacity sales agreements																								$ 1,600,000	$ 3,800,000

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Long-Term Debt (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended									12 Months Ended										12 Months Ended						12 Months Ended				12 Months Ended		12 Months Ended		12 Months Ended				12 Months Ended				12 Months Ended			12 Months Ended				12 Months Ended		12 Months Ended				12 Months Ended		12 Months Ended					12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended			12 Months Ended				12 Months Ended				12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010	Dec. 31, 2011 $16.80 or greater [Member]		Dec. 31, 2011 $16.80 to $14.00 [Member]		Dec. 31, 2011 $14.00 or less [Member]		Dec. 31, 2011 Kansas City Power and Light Company [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member]	Jan. 02, 2010 Kansas City Power and Light Company [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Secured 1992 Series EIRR Bonds [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Secured Series 1993A and 1993B EIRR bonds [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Secured EIRR Bonds Series 2005 [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior notes due 2018 KCPL [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior notes due 2018 KCPL [Member]		Dec. 31, 2011 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior notes due 2035 KCPL [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior notes due 2035 KCPL [Member]		Dec. 31, 2011 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior notes due 2011 KCPL [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior notes due 2011 KCPL [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior notes due 2017 [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior notes due 2017 [Member]		Dec. 31, 2011 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior Notes Due 2041 KCPL [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Corporate Debt Securities [Member] Senior Notes Due 2041 KCPL [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Other Long-Term Debt [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Other Long-Term Debt [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds EIRR due 2012-2035 [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds EIRR due 2012-2035 [Member]		Dec. 31, 2011 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds Series 2009 due 2019 [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds Series 2009 due 2019 [Member]		Dec. 31, 2011 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds EIRR series 2005 due 2035 [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds EIRR series 2005 due 2035 [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds EIRR series 2007A-2 due 2035 [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds EIRR series 2007A-2 due 2035 [Member]		Dec. 31, 2011 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds EIRR series 2007B due 2035 [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds EIRR series 2007B due 2035 [Member]	Dec. 31, 2011 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds Series 2007A-1 due 2035 [Member]		Dec. 31, 2010 Kansas City Power and Light Company [Member] Secured Debt [Member] General Mortgage bonds Series 2007A-1 due 2035 [Member]		Dec. 31, 2011 Kansas City Power and Light Company [Member] Environmental Improvement Revenue Refunding Bonds [Member]	Dec. 31, 2010 Kansas City Power and Light Company [Member] Environmental Improvement Revenue Refunding Bonds [Member]	Dec. 31, 2011 Other Great Plains [Member]	Dec. 31, 2010 Other Great Plains [Member]	Jan. 02, 2010 Other Great Plains [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO First Mortgage Bonds [Member] First mortgage bonds due 2012-2021 [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO First Mortgage Bonds [Member] First mortgage bonds due 2012-2021 [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO Medium Term Notes [Member] Medium term notes 7.17 percent series due 2023 [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO Medium Term Notes [Member] Medium term notes 7.17 percent series due 2023 [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO Medium Term Notes [Member] Medium term notes 7.33 percent series due 2023 [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO Medium Term Notes [Member] Medium term notes 7.33 percent series due 2023 [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO Medium Term Notes [Member] Medium term notes 7.16 percent series due 2013 [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO Medium Term Notes [Member] Medium term notes 7.16 percent series due 2013 [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO Pollution Control Bonds [Member] Pollution control bonds SJLP due 2013 [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO Pollution Control Bonds [Member] Pollution control bonds SJLP due 2013 [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO Pollution Control Bonds [Member] Pollution control bonds Wamego Series 1996 due 2026 [Member]		Dec. 31, 2010 Other Great Plains [Member] GMO Pollution Control Bonds [Member] Pollution control bonds Wamego Series 1996 due 2026 [Member]		Dec. 31, 2011 Other Great Plains [Member] GMO Pollution Control Bonds [Member] Pollution control bonds state environmental 1993 due 2028 [Member]		Dec. 31, 2010 Other Great Plains [Member] GMO Pollution Control Bonds [Member] Pollution control bonds state environmental 1993 due 2028 [Member]		Dec. 31, 2011 Other Great Plains [Member] GMO Senior Notes [Member] Senior notes 11.875 percent series due 2012 [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO Senior Notes [Member] Senior notes 11.875 percent series due 2012 [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO Senior Notes [Member] Senior notes 7.75 percent series due 2011 [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO Senior Notes [Member] Senior notes 7.75 percent series due 2011 [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO Senior Notes [Member] Fair value adjustment [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO Senior Notes [Member] Fair value adjustment [Member]	Jan. 02, 2010 Other Great Plains [Member] GMO Senior Notes [Member] Fair value adjustment [Member]	Jul. 14, 2008 Other Great Plains [Member] GMO Senior Notes [Member] Fair value adjustment [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO Senior Notes [Member] Senior notes 8.27 percent series due 2021 [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO Senior Notes [Member] Senior notes 8.27 percent series due 2021 [Member]	Dec. 31, 2011 Other Great Plains [Member] GMO Senior Notes [Member] Series 7.95 percent [Member]	Dec. 31, 2010 Other Great Plains [Member] GMO Senior Notes [Member] Series 7.95 percent [Member]	Dec. 31, 2011 Other Great Plains [Member] Great Plains Energy Equity Units Subordinated Notes [Member]	Dec. 31, 2010 Other Great Plains [Member] Great Plains Energy Equity Units Subordinated Notes [Member]	May 01, 2009 Other Great Plains [Member] Great Plains Energy Equity Units Subordinated Notes [Member]	Dec. 31, 2011 Other Great Plains [Member] Great Plains Energy Senior Notes [Member] Senior Notes Due 2021 [Member]		Dec. 31, 2010 Other Great Plains [Member] Great Plains Energy Senior Notes [Member] Senior Notes Due 2021 [Member]		Dec. 31, 2011 Other Great Plains [Member] Great Plains Energy Senior Notes [Member] Senor notes due 2013 [Member]		Dec. 31, 2010 Other Great Plains [Member] Great Plains Energy Senior Notes [Member] Senor notes due 2013 [Member]		Dec. 31, 2011 Other Great Plains [Member] Great Plains Energy Senior Notes [Member] Senior notes due 2017 [Member]		Dec. 31, 2010 Other Great Plains [Member] Great Plains Energy Senior Notes [Member] Senior notes due 2017 [Member]
Debt Instrument [Line Items]
Principal outstanding																$ 350.0	[1]	$ 350.0	[1]	$ 250.0	[1]	$ 250.0	[1]	$ 0	$ 150.0	$ 250.0	[1]	$ 250.0	[1]	$ 400.0	$ 0	$ 2.9	$ 3.3	$ 119.3	[2],[3]	$ 158.8	[2],[3]	$ 400.0	[1]	$ 400.0	[1]	$ 50.0		$ 50.0	$ 0	[4]	$ 10.0	[4]	$ 73.2	$ 73.2	$ 0	[4]	$ 63.3	[4]	$ 23.4	$ 23.4				$ 11.2	$ 12.4	$ 7.0	$ 7.0	$ 3.0	$ 3.0	$ 6.0	$ 6.0	$ 5.6	$ 5.6	$ 7.3	[5]	$ 7.3	[5]	$ 5.0	[5]	$ 5.0	[5]	$ 500.0	$ 500.0	$ 0	$ 197.0	$ 16.3	$ 49.9			$ 80.9	$ 80.9	$ 0	$ 137.3	$ 287.5	$ 287.5		$ 350.0	[1]	$ 0	[1]	$ 250.0	[1]	$ 250.0	[1]	$ 100.0	[1]	$ 100.0	[1]
Current maturities	801.4	485.7								12.7	150.3																																														(788.7)	(335.4)
Unamortized discount										(4.2)	(2.0)																																														(0.7)	(0.5)
Long-term debt excluding current maturities	2,742.3	2,942.7								1,901.9	1,629.7
Year due																2018	[1]			2035	[1]					2017	[1]			2041								2019	[1]			2035	[4]		2035	[2],[3]			2035		2035	[4]			2038							2023		2023		2013		2013		2026	[5]			2028	[5]			2012								2021				2012			2021	[1]			2013	[1]			2017	[1]
Debt Instrument Maturity Date Range Start																																2012		2012	[2],[3]																									2012
Debt Instrument Maturity Date Range End																																2018		2035																										2021
Interest rates (in hundredths)																6.375%	[1]			6.05%	[1]			6.50%		5.85%	[1]			5.30%				4.87%	[2],[3]			7.15%	[1]			4.65%							5.375%						4.90%					9.44%		7.17%		7.33%		7.16%		5.85%		0.164%	[5]			0.353%	[5]			11.875%		7.75%						8.27%		7.95%		10.00%			4.85%	[1]			2.75%	[1]			6.875%	[1]
Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)																7.49%	[1]			5.78%	[1]					5.72%	[1]											8.59%	[1]																																																						7.34%	[1]			3.67%	[1]			7.33%	[1]
Bonds purchased in lieu of redemption																																													10.0						63.3
Amortization of debt expense [Abstract]
Amortization of debt expense	8.1	6.4	4.4							3.6	2.8	2.0																																													4.5	3.6	2.4
Long-term debt detail [Abstract]
Principal outstanding covered by insurance policies													31.0	79.5	35.9																			50.0											10.0				73.2		63.3
Aggregate amount of outstanding general mortgage bonds as a percentage of total capitalization, maximum (in hundredths)													10.00%	10.00%	10.00%																											10.00%			10.00%				10.00%		10.00%
Proportion of secured debt to total indebtedness, maximum (in hundredths)													75.00%	75.00%	75.00%																											75.00%
Proportion of secured debt to total indebtedness based on bond ratings, maximum (in hundredths)													50.00%	50.00%	50.00%																											50.00%
Insurance agreement covenant indebtedness to total capitalization ratio, maximum													0.68	0.68	0.68																											0.68
Additional collateral necessary due to issuance of additional mortgage bonds																																										50.0			10.0				73.2		63.3
Amortization expense related to the fair value adjustment																																																																																		33.6	34.6	33.0
Number of outstanding equity units (in number of units)																																																																																										5,750,000
Payment terms																																																																																										Great Plains Energy makes quarterly contract adjustment payments at the rate of 2.00% per year of the stated amount of $50 per Equity Unit and interest payments at the rate of 10.00% per year on the subordinated notes.
Present value of the contract adjustment payments																																																																																												15.1
Compliance with Syncora bond insurance covenant													in compliance	in compliance	in compliance																			in compliance
Purchase accounting adjustment																																																																																					133.3
Long-term debt maturities for the next five years [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	801.4									12.7
Long-term Debt, Maturities, Repayments of Principal in Year Two	263.1									0.4
Long-term Debt, Maturities, Repayments of Principal in Year Three	1.5									0.4
Long-term Debt, Maturities, Repayments of Principal in Year Four	15.5									14.4
Long-term Debt, Maturities, Repayments of Principal in Year Five	$ 1.6									$ 0.4
Equity Units Subordinated Notes [Abstract]
Settlement rate (in common shares)				2.9762 to 1		$50 divided by the applicable market value to 1		3.5714 to 1
Market value per Equity Unit				Greater than $50 per Equity Unit	[6]	Equal to $50 per Equity Unit	[6]	Less than $50 per Equity Unit	[6]
Applicable market value, minimum				$ 16.80		$ 14.00
Applicable market value, maximum						$ 16.80		$ 14.00

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

[2] Weighted-average interest rates at December 31, 2011

[3] December 31, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by KCP&L

[4] December 31, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have been repurchased and are held by KCP&L

[5] Variable rate

[6] Assumes that the market price of the Company's common stock on June 15, 2012, is the same as the applicable market value.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

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 (Receivables Company).

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

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

Great Plains Energy’s sole reportable business segment is electric utility.  See Note 21 for additional information.

Use of Estimates

Use of Estimates

The process of preparing financial statements in conformity with Generally Accepted Accounting Principles (GAAP) requires the use of estimates and assumptions that affect the reported amounts of certain types of assets, liabilities, revenues, and expenses.  Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements.  Accordingly, upon settlement, actual results may differ from estimated amounts.

Cash and Cash Equivalents

Cash and Cash Equivalents

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

Funds on Deposit

Funds on Deposit

Funds on deposit consist primarily of cash provided to counterparties in support of margin requirements related to commodity purchases, commodity swaps and futures contracts.  Pursuant to individual contract terms with counterparties, deposit amounts required vary with changes in market prices, credit provisions and various other factors.  Interest is earned on most funds on deposit.  Great Plains Energy also holds funds on deposit from counterparties in the same manner.  These funds are included in other current liabilities on the consolidated balance sheets.

Fair Value of Financial Instruments

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it is practicable to estimate that value.

Nuclear decommissioning trust fund – KCP&L’s nuclear decommissioning trust fund assets are recorded at fair value.  Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.

Rabbi trust –GMO’s rabbi trusts related to its Supplemental Executive Retirement Plan (SERP) are recorded at fair value, which are based on quoted market prices of the investments held by the trusts and/or valuation models.  The rabbi trusts are included in Other – Investments and Other Assets on Great Plains Energy’s consolidated balance sheets.

Long-term debt – Fair value is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices were not available.  At December 31, 2011, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.5 billion and $3.9 billion, respectively.  At December 31, 2011, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.9 billion and $2.2 billion, respectively.  At December 31, 2010, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.4 billion and $3.7 billion, respectively.  At December 31, 2010, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.8 billion and $1.9 billion, respectively.

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

Pension plans – For financial reporting purposes, the market value of plan assets is the fair value.  KCP&L uses a five-year smoothing of assets to determine fair value for regulatory reporting purpose

Derivative Instruments

Derivative Instruments

The Company records derivative instruments on the balance sheet at fair value in accordance with GAAP.  Great Plains Energy and KCP&L enter into derivative contracts to manage exposure to commodity price and interest rate fluctuations.  Derivative instruments designated as normal purchases and normal sales (NPNS) and cash flow hedges are used solely for hedging purposes and are not issued or held for speculative reasons.

The Company considers various qualitative factors, such as contract and market place attributes, in designating derivative instruments at inception.  Great Plains Energy and KCP&L may elect the NPNS exception, which requires the effects of the derivative to be recorded when the underlying contract settles.  Great Plains Energy and KCP&L account for derivative instruments that are not designated as NPNS as cash flow hedges or non-hedging derivatives, which are recorded as assets or liabilities on the consolidated balance sheets at fair value.  In addition, if a derivative instrument is designated as a cash flow hedge, Great Plains Energy and KCP&L document the method of determining hedge effectiveness and measuring ineffectiveness.  See Note 18 for additional information regarding derivative financial instruments and hedging activities.

Great Plains Energy and KCP&L offset fair value amounts recognized for derivative instruments under master netting arrangements, which include rights to reclaim cash collateral (a receivable), or the obligation to return cash collateral (a payable). Great Plains Energy and KCP&L classify cash flows from derivative instruments in the same category as the cash flows from the items being hedged.

Utility Plant

Utility Plant

Great Plains Energy’s and KCP&L's utility plant is stated at historical cost.  These costs include taxes, an allowance for the cost of borrowed and equity funds used to finance construction and payroll-related costs, including pensions and other fringe benefits.  Replacements, improvements and additions to units of property are capitalized.  Repairs of property and replacements of items not considered to be units of property are expensed as incurred (except as discussed under Deferred Refueling Outage Costs).  When property units are retired or otherwise disposed, the original cost, net of salvage, is charged to accumulated depreciation.  Substantially all of KCP&L’s utility plant is pledged as collateral for KCP&L’s mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented.  Substantially all of GMO’s St. Joseph Light & Power division utility plant is pledged as collateral for GMO’s mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented.

As prescribed by The Federal Energy Regulatory Commission (FERC), Allowance for Funds Used During Construction (AFUDC) is charged to the cost of the plant during construction.  AFUDC equity funds are included as a non-cash item in non-operating income and AFUDC borrowed funds are a reduction of interest charges.  The rates used to compute gross AFUDC are compounded semi-annually and averaged 0.2% in 2011, 6.8% in 2010 and 7.6% in 2009 for KCP&L and for GMO averaged 5.4% in 2011, 4.6% in 2010 and 5.4% in 2009.

Great Plains Energy’s and KCP&L’s balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following tables.

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

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

Depreciation and Amortization

Depreciation and Amortization

Depreciation and amortization of utility plant other than nuclear fuel is computed using the straight-line method over the estimated lives of depreciable property based on rates approved by state regulatory authorities.  Annual depreciation rates average approximately 3%.  Nuclear fuel is amortized to fuel expense based on the quantity of heat produced during the generation of electricity.

Great Plains Energy’s depreciation expense was $239.9 million, $243.6 million and $228.9 million for 2011, 2010 and 2009, respectively.  KCP&L’s depreciation expense was $162.0 million, $170.9 million and $158.4 million for 2011, 2010 and 2009, respectively.  Great Plains Energy’s and KCP&L’s depreciation and amortization expense includes $14.4 million, $72.6 million and $58.2 million for 2011, 2010 and 2009, respectively, of additional amortization to help maintain cash flow levels during KCP&L’s Comprehensive Energy Plan pursuant to orders of the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC).  This additional amortization concluded following the December 2010 and May 2011 effective dates of new retail rates for KCP&L in Kansas and Missouri, respectively.

Nuclear Plant Decommissioning Costs

Nuclear Plant Decommissioning Costs

Nuclear plant decommissioning cost estimates are based on the immediate dismantlement method and include the costs of decontamination, dismantlement and site restoration.  Based on these cost estimates, KCP&L contributes to a tax-qualified trust fund to be used to decommission Wolf Creek Generating Station (Wolf Creek).  Related liabilities for decommissioning are included on Great Plains Energy’s and KCP&L’s balance sheets in Asset Retirement Obligations (AROs).

As a result of the authorized regulatory treatment and related regulatory accounting, differences between the decommissioning trust fund asset and the related ARO are recorded as a regulatory asset or liability.  See Note 7 for discussion of AROs including those associated with nuclear plant decommissioning costs.

Deferred Refueling Outage Costs

Deferred Refueling Outage Costs

KCP&L uses the deferral method to account for operations and maintenance expenses incurred in support of Wolf Creek’s scheduled refueling outages and amortizes them evenly (monthly) over the unit’s operating cycle of 18 months until the next scheduled outage.  Replacement power costs during an outage are expensed as incurred.

Regulatory Matters

Regulatory Matters

KCP&L and GMO defer items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded if KCP&L and GMO were not regulated.  See Note 5 for additional information concerning regulatory matters.

Revenue Recognition

Revenue Recognition

Great Plains Energy and KCP&L recognize revenues on sales of electricity when the service is provided.  Revenues recorded include electric services provided but not yet billed by KCP&L and GMO.  Unbilled revenues are recorded for kWh usage in the period following the customers’ billing cycle to the end of the month.  KCP&L’s and GMO’s estimate is based on net system kWh usage less actual billed kWhs.  KCP&L’s and GMO’s estimated unbilled kWhs are allocated and priced by regulatory jurisdiction across the rate classes based on actual billing rates.

KCP&L and GMO collect from customers gross receipts taxes levied by state and local governments.  These taxes from KCP&L’s Missouri customers are recorded gross in operating revenues and general taxes on Great Plains Energy’s and KCP&L’s statements of income.  KCP&L’s gross receipts taxes collected from Missouri customers were $55.6 million, $54.3 million, and $46.8 million in 2011, 2010 and 2009, respectively.  These taxes from KCP&L’s Kansas customers and GMO’s customers are recorded net in operating revenues on Great Plains Energy’s statements of income.

Great Plains Energy and KCP&L collect sales taxes from customers and remit to state and local governments.  These taxes are presented on a net basis on Great Plains Energy’s and KCP&L’s statements of income.

Great Plains Energy and KCP&L record sale and purchase activity on a net basis in wholesale revenue or purchased power when transacting with Regional Transmission Organization (RTO)/Independent System Operator (ISO) markets.

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts

This reserve represents estimated uncollectible accounts receivable and is based on management’s judgment considering historical loss experience and the characteristics of existing accounts.  Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses.  Receivables are charged off against the reserve when they are deemed uncollectible.

Property Gains and Losses

Property Gains and Losses

Net gains and losses from the sale of assets and businesses and from asset impairments are recorded in operating expenses.

Asset Impairments

Asset Impairments

Long-lived assets and finite-lived intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  If the sum of the undiscounted expected future cash flows from an asset to be held and used is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements.  The amount of impairment recognized is the excess of the carrying value of the asset over its fair value.

Goodwill and indefinite lived intangible assets are tested for impairment annually and when an event occurs indicating the possibility that an impairment exists.  The annual test must be performed at the same time each year.  If the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements.  To measure the amount of the impairment loss to recognize, the implied fair value of the reporting unit goodwill is compared with its carrying value.

Income Taxes

Income Taxes

Income taxes are accounted for using the asset/liability approach.  Deferred tax assets and liabilities are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, applying enacted statutory tax rates in effect for the year in which the differences are expected to reverse.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized.

Great Plains Energy and KCP&L recognize tax benefits based on a “more-likely-than-not” recognition threshold.  In addition, Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.

Great Plains Energy files a consolidated federal income tax return as well as unitary and combined income tax returns in several state jurisdictions with Kansas and Missouri being the most significant.  Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss.  KCP&L’s income tax provision includes taxes allocated based on its separate company income or loss.

Great Plains Energy and KCP&L have established a net regulatory asset for the additional future revenues to be collected from customers for deferred income taxes.  Tax credits are recognized in the year generated except for certain KCP&L and GMO investment tax credits that have been deferred and amortized over the remaining service lives of the related properties.

Environmental Matters

Environmental Matters

Environmental costs are accrued when it is probable a liability has been incurred and the amount of the liability can be reasonably estimated.

Basic and Diluted Earnings per Common Share Calculation

Basic and Diluted Earnings per Common Share Calculation

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

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

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

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

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

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

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Jointly Owned Electric Utility Plants (Tables)

12 Months Ended

Dec. 31, 2011

Jointly Owned Electric Utility Plants [Abstract]

Schedule of jointly owned electric utility plants

Great Plains Energy
	Wolf Creek			La Cygne			Iatan No. 1			Iatan No. 2			Iatan			Jeffrey
	Unit			Units			Unit			Unit			Common			Energy Center
	(millions, except MW amounts)
Great Plains Energy's share		47	%		50	%		88	%		73	%		79	%		8	%
Utility plant in service	$	1,473.8		$	493.6		$	667.9		$	1,293.0		$	364.4		$	158.4
Accumulated depreciation		776.3			303.1			252.8			270.0			30.4			75.5
Nuclear fuel, net		76.6			-			-			-			-			-
Construction work in progress		39.4			79.1			6.5			5.9			30.2			5.3
2012 accredited capacity-MWs		547			711			620			641		NA				174

KCP&L
	Wolf Creek			La Cygne			Iatan No. 1			Iatan No. 2			Iatan
	Unit			Units			Unit			Unit			Common
	(millions, except MW amounts)
KCP&L's share		47	%		50	%		70	%		55	%		61	%
Utility plant in service	$	1,473.8		$	493.6		$	542.3		$	985.1		$	287.5
Accumulated depreciation		776.3			303.1			207.9			261.3			26.0
Nuclear fuel, net		76.6			-			-			-			-
Construction work in progress		39.4			79.1			2.6			4.4			9.3
2012 accredited capacity-MWs		547			711			493			482		NA

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

14.   COMMITMENTS AND CONTINGENCIES

Environmental Matters

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

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

Air and Climate Change Overview

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Best Available Retrofit Technology (BART) Rule

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

Mercury and Air Toxics Standards (MATS) Rule

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

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

Industrial Boiler Rule

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

New Source Review

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

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

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

Collaboration Agreement

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

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

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

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

Climate Change

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

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

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

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

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

KCP&L and GMO project that they will be compliant with the Missouri renewable requirements, exclusive of the solar requirement, through 2023 for KCP&L and 2018 for GMO.  KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri solar requirements for the foreseeable future.  KCP&L also projects that it will be compliant with the Kansas renewable requirements through 2016.

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

SO2 NAAQS

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

Montrose Station Notice of Violation

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

Water

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

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

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

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

Solid Waste

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

Remediation

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

At December 31, 2011 and 2010, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site.  At December 31, 2011 and 2010, Great Plains Energy had $0.4 million accrued for environmental remediation expenses, which includes the $0.3 million at KCP&L, and additional potential remediation and ground water monitoring costs relating to two GMO sites.  The amounts accrued were established on an undiscounted basis and Great Plains Energy and KCP&L do not currently have an estimated time frame over which the accrued amounts may be paid.

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

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

Contractual Commitments

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

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

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

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

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

Great Plains Energy has expected sublease income of $1.2 million for the years 2012-2013.  Lease commitments end in 2048.  Operating lease commitments include rail cars to serve jointly-owned generating units where KCP&L is the managing partner.  Of the amounts included in the table above, KCP&L will be reimbursed by the other owners for approximately $2.2 million per year from 2012 to 2015 and then $0.4 million per year from 2016 to 2025, for a total of $13.0 million.

Fuel commitments consist of commitments for nuclear fuel, coal and coal transportation.  Power commitments consist of commitments for renewable energy under power purchase agreements.  KCP&L and GMO purchase capacity from other utilities and nonutility suppliers.  Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable.  KCP&L has capacity sales agreements not included above that total $3.8 million for 2012 and $1.6 million for 2013.  La Cygne environmental project represents contractual commitments related to environmental upgrades at KCP&L’s La Cygne station.  KCP&L owns 50% of the La Cygne station and expects to be reimbursed by the other owner for its 50% share of the costs.  Non-regulated natural gas transportation consists of MPS Merchant’s commitments.  Other represents individual commitments entered into in the ordinary course of business.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Fair Value Measurements

19.   FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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

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

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

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

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other
	Great
	Plains
	Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains
included in non-operating income		10.9
Settlements		(11.5	)
Balance December 31, 2011	$	3.1
Total unrealized losses included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at December 31, 2011	$	(0.2	)

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other
				Great			Great
				Plains			Plains
	KCP&L			Energy			Energy
	State & Local			Derivative
	Obligations			Instruments			Total
	(millions)
Balance January 1, 2010	$	0.2		$	4.1		$	4.3
Total realized/unrealized losses
included in non-operating income		-			(12.5	)		(12.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			12.1			12.1
Balance December 31, 2010	$	-		$	3.7		$	3.7
Total unrealized gains included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at December 31, 2010	$	-		$	0.1		$	0.1

Investments in Affordable Housing Limited Partnerships

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

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Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Taxes [Abstract]

Components of income tax expense (benefit)

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

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

Income tax expense (benefit) and effective income tax rates

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

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

Deferred income tax assets and liabilities

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

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

Liability for unrecognized tax benefits

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

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Change in asset retirement obligations

	Great Plains Energy					KCP&L
	2011			2010		2011			2010
	(millions)
Beginning balance	$	143.3		$	132.6	$	129.7		$	119.8
Additions		0.8			2.0		-			2.0
Revision in timing and/or estimates		(3.8	)		-		(3.8	)		-
Accretion		9.3			8.7		8.4			7.9
Ending balance	$	149.6		$	143.3	$	134.3		$	129.7

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

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Receivables

12 Months Ended

Dec. 31, 2011

Receivables [Abstract]

Receivables

3.   RECEIVABLES

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

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

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

Sale of Accounts Receivable – KCP&L

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

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

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

				Receivables			Consolidated
2011	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,415.6	)	$	1,415.6		$	-
Gain (loss) on sale of accounts receivable (a)		(17.9	)		17.7			(0.2	)
Servicing fees		2.6			(2.6	)		-
Fees to outside investor		-			(1.2	)		(1.2	)
Cash flows during the period
Cash from customers transferred to Receivables Company		(1,412.4	)		1,412.4			-
Cash paid to KCP&L for receivables purchased		1,394.7			(1,394.7	)		-
Servicing fees		2.6			(2.6	)		-
Interest on intercompany note		0.5			(0.5	)		-

				Receivables			Consolidated
2010	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,341.0	)	$	1,341.0		$	-
Gain (loss) on sale of accounts receivable (a)		(17.0	)		16.8			(0.2	)
Servicing fees		3.2			(3.2	)		-
Fees to outside investor		-			(1.2	)		(1.2	)
Cash flows during the period
Cash from customers transferred to Receivables Company		(1,337.4	)		1,337.4			-
Cash paid to KCP&L for receivables purchased		1,320.7			(1,320.7	)		-
Servicing fees		3.2			(3.2	)		-
Interest on intercompany note		0.5			(0.5	)		-
(a) Any net gain (loss) is the result of the timing difference inherent in collecting receivables and
over the life of the agreement will net to zero.

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

XML

Related Party Transactions and Relationships (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010
Related Party Transaction [Line Items]
KCP and L employees manage GMO's business and operate its facilities at cost.	$ 108.4	$ 100.9	$ 102.7
Kansas City Power and Light Company [Member] | KCPL Greater Missouri Operations [Member]
Related Party Transaction [Line Items]
Receivable from Related Party	24.1	29.9
Kansas City Power and Light Company [Member] | Great Plains Energy [Member]
Related Party Transaction [Line Items]
Receivable from Related Party	$ 9.5	$ 13.3

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Taxes

12 Months Ended

Dec. 31, 2011

Taxes [Abstract]

Taxes

20.   TAXES

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

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

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

Income Tax Expense and Effective Income Tax Rates

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

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

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

Deferred Income Taxes

The tax effects of major temporary differences resulting in deferred income tax assets (liabilities) in the consolidated balance sheets are in the following tables.

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

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

Tax Credit Carryforwards

At December 31, 2011 and 2010, Great Plains Energy had $118.0 million and $102.6 million, respectively, of federal general business income tax credit carryforwards.  At December 31, 2011 and 2010, KCP&L had $116.8 million and $101.5 million, respectively, of federal general business income tax credit carryforwards.  The carryforwards for both Great Plains Energy and KCP&L relate primarily to Advanced Coal Investment Tax Credits and Wind Production tax credits and expire in the years 2028 to 2031.  Approximately $0.5 million of Great Plains Energy’s credits are related to Low Income Housing credits that were acquired in the GMO acquisition.  Due to federal limitations on the utilization of income tax attributes acquired in the GMO acquisition, management expects these credits to expire unutilized and has provided a valuation allowance against $0.4 million of the federal income tax benefit. 

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

At December 31, 2011 and 2010, Great Plains Energy had $4.7 million and $11.8 million, respectively, of state income tax credit carryforwards.  The state income tax credits relate primarily to the Company’s Missouri affordable housing investment portfolio, and the carryforwards expire in the years 2012 to 2016.  Management expects that a portion of these credits will expire unutilized and has provided a valuation allowance against $0.3 million of the state income tax benefit.

Net Operating Loss Carryforwards

At December 31, 2011 and 2010, Great Plains Energy had $473.1 million and $353.0 million, respectively, of tax benefits related to federal net operating loss (NOL) carryforwards.  Approximately $315.7 million and $317.5 million, at December 31, 2011 and 2010, respectively, are tax benefits related to NOLs that were acquired in the GMO acquisition.  The tax benefits for NOLs are $32.6 million originating in 2003, $152.4 million originating in 2004, $74.1 million originating in 2005, $53.3 million originating in 2006, $1.3 million originating in 2007, $2.4 million originating in 2008, $23.4 million originating in 2009, $11.6 million originating in 2010, and $122.0 million originating in 2011.  The federal NOL carryforwards expire in years 2023 to 2031.

In addition, Great Plains Energy also had deferred tax benefits of $70.6 million and $56.2 million related to state NOLs as of December 31, 2011 and 2010, respectively.  Approximately $49.9 million and $49.4 million at December 31, 2011 and 2010, respectively, were acquired in the GMO acquisition.  Management does not expect to utilize $23.2 million of NOLs in state tax jurisdictions where the Company does not expect to operate in the future.  Therefore, a valuation allowance has been provided against $23.2 million of state tax benefits.

Valuation Allowances

Great Plains Energy is required to assess the ultimate realization of deferred tax assets using a “more likely than not” assessment threshold.  This assessment takes into consideration tax planning strategies within Great Plains Energy’s control.  As a result of this assessment, Great Plains Energy has established a partial valuation allowance for federal and state tax NOL carryforwards, and tax credit carryforwards.

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

Uncertain Tax Positions

At December 31, 2011 and 2010, Great Plains Energy had $24.0 million and $42.0 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $11.8 million and $17.3 million at December 31, 2011 and 2010, respectively, are expected to impact the effective tax rate if recognized.  The $18.0 million decrease in unrecognized tax benefits in 2011 is primarily due to a decrease of $18.4 million of unrecognized tax benefits related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years.  The $18.4 million tax benefit recognized related to the 2006-2008 audit was offset by an increase of $16.4 million in deferred income tax liabilities since a significant portion of the unrecognized tax benefits were related to temporary tax differences, which resulted in an increase to net income of $2.0 million.

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

At December 31, 2011 and 2010, KCP&L had $8.7 million and $19.1 million, respectively, of liabilities related to unrecognized tax benefits.  Of these amounts, $0.2 million and $0.3 million at December 31, 2011 and 2010, respectively, are expected to impact the effective tax rate if recognized.  The $10.4 million decrease in unrecognized tax benefits in 2011 is primarily due to a decrease of $12.1 million related to the settlements of the IRS audit for Great Plains Energy’s 2006-2008 tax years.  The tax benefit recognized related to the 2006-2008 audit was offset by an increase of deferred income tax liabilities which resulted in an insignificant impact to net income.  At December 31, 2009, KCP&L had $20.9 million of liabilities related to unrecognized tax benefits of which $0.4 million was expected to impact the effective rate if recognized.

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

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

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

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

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

Great Plains Energy files a consolidated federal income tax return as well as unitary and combined income tax returns in several state jurisdictions with Kansas and Missouri being the most significant.  The Company also files separate company returns in Canada and certain other states.

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Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2010	Dec. 31, 2009	Dec. 31, 2008
Current income taxes [Abstract]
Federal	$ 2.9	$ (7.4)	$ (11.1)
State	(6.0)	(4.3)	(0.9)
Foreign	(0.4)	0.1	1.3
Total	(3.5)	(11.6)	(10.7)
Deferred income taxes [Abstract]
Federal	90.5	99.8	(13.6)
State	20.7	24.0	10.0
Total	111.2	123.8	(3.6)
Noncurrent income taxes [Abstract]
Federal	(18.0)	(4.8)	8.3
State	(2.1)	(1.8)	1.1
Foreign	(0.6)	0.5	(1.5)
Total	(20.7)	(6.1)	7.9
Investment tax credit [Abstract]
Deferral	0	(4.2)	37.2
Amortization	(2.2)	(2.9)	(2.2)
Total	(2.2)	(7.1)	35.0
Total income tax expense	84.8	99.0	28.6
Less: taxes on discontinued operations [Abstract]
Current tax expense	0	0	(1.1)
Deferred tax expense	0	0	0.2
Income tax expense on continuing operations	84.8	99.0	29.5
Reconciliation of income tax expense [Abstract]
Federal statutory income tax	90.7	108.7	63.4
Differences between book and tax depreciation not normalized	4.0	(5.2)	(9.9)
Amortization of investment tax credits	(2.2)	(2.9)	(2.2)
Federal income tax credits	(13.1)	(12.5)	(8.0)
State income taxes	10.5	11.4	7.9
Medicare Part D subsidy legislation	0	2.8	0
Changes in uncertain tax positions, net	(4.4)	0.3	(72.1)
Valuation allowance	(2.2)	(2.7)	55.8
Other	1.5	(0.9)	(5.4)
Total	84.8	99.0	29.5
Reconciliation of income tax rate [Abstract]
Federal statutory income tax (in hundredths)	35.00%	35.00%	35.00%
Differences between book and tax depreciation not normalized (in hundredths)	1.50%	(1.70%)	(5.50%)
Amortization of investment tax credits (in hundredths)	(0.80%)	(0.90%)	(1.20%)
Federal income tax credits (in hundredths)	(5.00%)	(4.10%)	(4.40%)
State income taxes (in hundredths)	4.00%	3.70%	4.40%
Medicare Part D subsidy legislation (in hundredths)	0.00%	0.90%	0.00%
Changes in uncertain tax positions, net (in hundredths)	(1.70%)	0.10%	(39.80%)
Valuation allowance (in hundredths)	(0.80%)	(0.90%)	30.80%
Other (in hundredths)	0.50%	(0.30%)	(3.00%)
Total (in hundredths)	32.70%	31.80%	16.30%
Current deferred income taxes [Abstract]
Other, current	7.9	14.7
Net current deferred income tax asset before valuation allowance	7.9	14.7
Valuation allowance	(0.4)	(0.4)
Net current deferred income tax asset	7.5	14.3
Noncurrent deferred income taxes [Abstract]
Plant related	(1,193.6)	(975.5)
Income taxes on future regulatory recoveries	(144.3)	(142.6)
Derivative instruments	43.3	46.0
Pension and postretirement benefits	(34.2)	(16.3)
SO 2 emission allowance sales	31.1	30.8
Fuel clause adjustments	(17.2)	(16.6)
Transition costs	(17.4)	(20.0)
Tax credit carryforwards	213.7	204.3
Long-term debt fair value adjustment	6.3	19.2
Customer demand programs	(26.4)	(23.3)
Net operating loss carryforward, noncurrent	543.7	409.2
Other, noncurrent	(10.1)	(7.3)
Net noncurrent deferred tax liability before valuation allowance	(605.1)	(492.1)
Valuation allowance	(23.5)	(26.2)
Net noncurrent deferred tax liability	(628.6)	(518.3)
Net deferred income tax liability	(621.1)	(504.0)
Gross deferred income tax assets	1,203.6	1,140.7
Gross deferred income tax liabilities	(1,824.7)	(1,644.7)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period		51.4			97.3
Additions for current year tax positions	1.4	2.7	13.2
Additions for prior year tax positions	2.4	2.1	8.2
Additions for GMO prior year tax positions	0	0	11.6
Reductions for prior year tax positions	(20.9)	(10.6)	(1.3)
Settlements	0	(3.8)	(76.7)
Statute expirations	(0.7)	(0.3)	(0.7)
Balance at end of period	24.0	42.0			97.3
Foreign currency translation adjustments	(0.2)	0.5	(0.2)
Accrued interest related to unrecognized tax benefits	5.7	6.7		5.9
Accrued penalties with respect to unrecognized tax benefits	1.1	1.1		1.1
Interest expense related to unrecognized tax benefits	(0.9)	0.5	1.4
Amount of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities	4.7
Valuation Allowances [Abstract]
Tax (benefit) expense related to the valuation allowance against federal and state net operating loss carryforwards	2.7	3.2
Uncertain Tax Positions [Abstract]
Amount expected to impact the effective tax rate if recognized	11.8	17.3		17.3
Decrease in unrecognized tax benefits in the period	18.0		9.4
Increase to net income	2.0
Decrease of unrecognized tax benefits related to the settlement of IRS audit	18.4
Increase in deferred income tax liabilities	16.4
Decrease in unrecognized tax benefits related to the sale of certain GMO property		8.6
Increase in interest expense related to unrecognized benefits	(0.9)	0.5	1.4
Domestic Country [Member]
Net Operating Loss Carryforwards [Abstract]
Tax benefits related to net operating loss carryforwards	473.1	353.0
Amount of tax benefits related to the GMO acquisition.	315.7	317.5
Net operating losses year of origination [Abstract]
2003	32.6
2004	152.4
2005	74.1
2006	53.3
2007	1.3
2008	2.4
2009	23.4
2010	11.6
2011	122.0
State and Local Jurisdiction [Member]
Net Operating Loss Carryforwards [Abstract]
Tax benefits related to net operating loss carryforwards	70.6	56.2
Net Operating Losses Not Expected To Be Utilized	23.2
Amount of tax benefits related to the GMO acquisition.	49.9	49.4
General Business [Member]
Tax credit carryforward [Abstract]
Tax credit carryforward, amount	118.0	102.6
Tax credit carryforward, valuation allowance	0.4
Alternative Minimum [Member]
Tax credit carryforward [Abstract]
Tax credit carryforward, amount	91.0	90.0
Acquired in business combination	89.8
State [Member]
Tax credit carryforward [Abstract]
Tax credit carryforward, amount	4.7	11.8
Tax credit carryforward, valuation allowance	0.3
Kansas City Power and Light Company [Member]
Current income taxes [Abstract]
Federal	1.0	5.5	41.2
State	(0.6)	1.1	4.8
Total	0.4	6.6	46.0
Deferred income taxes [Abstract]
Federal	66.0	69.8	(41.7)
State	14.6	13.4	3.5
Total	80.6	83.2	(38.2)
Noncurrent income taxes [Abstract]
Federal	(9.3)	(1.6)	3.4
State	(1.1)	(0.3)	(0.1)
Total	(10.4)	(1.9)	3.3
Investment tax credit [Abstract]
Deferral	0	(4.2)	37.2
Amortization	(1.5)	(2.1)	(1.4)
Total	(1.5)	(6.3)	35.8
Total income tax expense	69.1	81.6	46.9
Reconciliation of income tax expense [Abstract]
Federal statutory income tax	71.6	85.7	61.5
Differences between book and tax depreciation not normalized	3.4	(4.5)	(7.7)
Amortization of investment tax credits	(1.5)	(2.1)	(1.4)
Federal income tax credits	(13.0)	(8.5)	(7.8)
State income taxes	8.1	8.9	5.8
Medicare Part D subsidy legislation	0	2.8	0
Changes in uncertain tax positions, net	0.3	0	(0.5)
Other	0.2	(0.7)	(3.0)
Reconciliation of income tax rate [Abstract]
Federal statutory income tax (in hundredths)	35.00%	35.00%	35.00%
Differences between book and tax depreciation not normalized (in hundredths)	1.60%	(1.80%)	(4.40%)
Amortization of investment tax credits (in hundredths)	(0.70%)	(0.90%)	(0.80%)
Federal income tax credits (in hundredths)	(6.30%)	(3.50%)	(4.40%)
State income taxes (in hundredths)	3.90%	3.60%	3.30%
Medicare Part D subsidy legislation (in hundredths)	0.00%	1.10%	0.00%
Changes in uncertain tax positions, net (in hundredths)	0.10%	0.00%	(0.30%)
Other (in hundredths)	0.20%	(0.20%)	(1.70%)
Total (in hundredths)	33.80%	33.30%	26.70%
Current deferred income taxes [Abstract]
Other, current	(0.1)	5.6
Net current deferred income tax asset before valuation allowance	(0.1)	5.6
Net current deferred income tax asset	(0.1)	5.6
Noncurrent deferred income taxes [Abstract]
Plant related	(861.6)	(711.5)
Income taxes on future regulatory recoveries	(119.6)	(117.2)
Derivative instruments	31.1	34.4
Pension and postretirement benefits	(11.7)	2.0
SO 2 emission allowance sales	31.9	33.4
Fuel clause adjustments	(5.4)	(3.2)
Transition costs	(9.6)	(11.4)
Tax credit carryforwards	116.8	101.5
Customer demand programs	(18.6)	(17.3)
Net operating loss carryforward, noncurrent	77.9	1.1
Other, noncurrent	(3.9)	(3.8)
Net noncurrent deferred tax liability before valuation allowance	(772.7)	(692.0)
Net noncurrent deferred tax liability	(772.7)	(692.0)
Net deferred income tax liability	(772.8)	(686.4)
Gross deferred income tax assets	618.7	602.4
Gross deferred income tax liabilities	(1,391.5)	(1,288.8)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period		20.9			17.6
Additions for current year tax positions	0	1.3	3.9
Additions for prior year tax positions	2.3	1.5	3.0
Reductions for prior year tax positions	(12.6)	(1.6)	(0.8)
Settlements	0	(2.9)	(2.2)
Statute expirations	(0.1)	(0.1)	(0.6)
Balance at end of period	8.7	19.1			17.6
Accrued interest related to unrecognized tax benefits	0.2	1.4		1.7
Interest expense related to unrecognized tax benefits	(1.2)	(0.3)
Amount of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities	0.2
Uncertain Tax Positions [Abstract]
Amount expected to impact the effective tax rate if recognized	0.2	0.3		0.4
Decrease in unrecognized tax benefits in the period	10.4
Decrease of unrecognized tax benefits related to the settlement of IRS audit	12.1
Increase in interest expense related to unrecognized benefits	(1.2)	(0.3)
Kansas City Power and Light Company [Member] | General Business [Member]
Tax credit carryforward [Abstract]
Tax credit carryforward, amount	$ 116.8	$ 101.5

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Nuclear Plant (Tables)

12 Months Ended

Dec. 31, 2011

Nuclear Plant [Abstract]

Changes in nuclear decommissioning trust fund

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

Detail of assets held in nuclear decommissioning trust fund

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

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

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

Nuclear Plant Decommissioning Costs

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

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Preferred Stock

12 Months Ended

Dec. 31, 2011

Preferred Stock Disclosure [Abstract]

Preferred Stock

13.   PREFERRED STOCK

At December 31, 2011, 1.6 million shares of Cumulative No Par Preferred Stock, 390,000 shares of Cumulative Preferred Stock, $100 par value and 11.0 million shares of no par Preference Stock were authorized under Great Plains Energy’s articles of incorporation.  All of the 390,000 authorized shares of Cumulative Preferred Stock are issued and outstanding.  Great Plains Energy has the option to redeem the $39.0 million of issued Cumulative Preferred Stock at prices ranging from 101% to 103.7% of par value.  If Great Plains Energy voluntarily files for dissolution or liquidation, the Cumulative Preferred Stock holders are entitled to receive the redemption prices.  If a proceeding for dissolution or liquidation is filed against Great Plains Energy, the Cumulative Preferred Stock holders are entitled to receive the $100 par value per share plus accrued and unpaid dividends.