Significant Accounting Policies

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

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

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

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

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

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

Basic and Diluted Earnings per Common Share Calculation

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

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


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

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

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

The computation of diluted EPS for the three months ended September 30, 2010, excludes anti-dilutive shares consisting of 107,958 performance shares, 103,114 restricted stock shares and 203,879 stock options.

The computation of diluted EPS year to date September 30, 2010, excludes anti-dilutive shares consisting of 116,388 performance shares, 278,452 restricted stock shares and 209,837 stock options.

Dividends Declared

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

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

SUPPLEMENTAL CASH FLOW INFORMATION

9 Months Ended

Sep. 30, 2011

Supplemental Cash Flow Information

2.	SUPPLEMENTAL CASH FLOW INFORMATION

Great Plains Energy Other Operating Activities
Year to Date September 30	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(41.2	)	$	(45.9	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		12.9			4.9
Materials and supplies		(4.8	)		(10.0	)
Accounts payable		(71.5	)		(79.1	)
Accrued taxes		52.5			54.6
Accrued interest		(6.1	)		(2.0	)
Deferred refueling outage costs		(23.8	)		8.0
Fuel adjustment clauses		(27.3	)		(2.3	)
Pension and post-retirement benefit obligations		22.0			15.5
Allowance for equity funds used during construction		(0.3	)		(25.5	)
Interest rate hedge settlements		(26.1	)		(6.9	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		2.3			4.0
Uncertain tax positions		(20.2	)		(1.4	)
Other		(22.7	)		(18.1	)
Total other operating activities	$	(154.3	)	$	(199.2	)
Cash paid during the period:
Interest	$	195.1		$	175.4
Income taxes	$	2.4		$	0.4
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	34.8		$	36.4

KCP&L Other Operating Activities
Year to Date September 30	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(39.5	)	$	(0.1	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		2.9			0.1
Materials and supplies		(4.3	)		(7.2	)
Accounts payable		(43.2	)		(87.2	)
Accrued taxes		40.3			(6.3	)
Accrued interest		7.9			10.3
Deferred refueling outage costs		(23.8	)		8.0
Pension and post-retirement benefit obligations		32.1			31.1
Allowance for equity funds used during construction		-			(21.7	)
Kansas Energy Cost Adjustment		(22.0	)		(5.4	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		1.5			3.0
Uncertain tax positions		(10.1	)		(1.6	)
Other		(16.1	)		0.9
Total other operating activities	$	(74.3	)	$	(171.1	)
Cash paid during the period:
Interest	$	74.6		$	60.3
Income taxes	$	0.1		$	71.6
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	30.7		$	31.6

Significant Non-Cash Items

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

RECEIVABLES

9 Months Ended

Sep. 30, 2011

Receivables

3.	RECEIVABLES

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


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

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

Sale of Accounts Receivable – KCP&L

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

KCP&L sells its receivables at a fixed price based upon the expected cost of funds and charge-offs. These costs comprise KCP&L’s loss on the sale of accounts receivable. KCP&L services the receivables and receives an annual servicing fee of 1.5% of the outstanding principal amount of the receivables sold to Receivables Company. KCP&L does not recognize a servicing asset or liability because management determined the collection agent fee earned by KCP&L approximates market value. In September 2011, the agreement was extended to September 2014 and amended to allow for $110 million in aggregate outstanding principal amount at any time.

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


				Receivables			Consolidated
Three Months Ended September 30, 2011	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(468.8	)	$	468.8		$	-
Gain (loss) on sale of accounts receivable (a)		(5.9	)		5.8			(0.1	)
Servicing fees		0.9			(0.9	)		-
Fees to outside investor		-			(0.3	)		(0.3	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(463.4	)		463.4			-
Cash paid to KCP&L for receivables purchased		457.6			(457.6	)		-
Servicing fees		0.9			(0.9	)		-
Interest on intercompany note		0.2			(0.2	)		-


				Receivables			Consolidated
Year to Date September 30, 2011	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,108.4	)	$	1,108.4		$	-
Gain (loss) on sale of accounts receivable (a)		(14.0	)		13.6			(0.4	)
Servicing fees		2.0			(2.0	)		-
Fees to outside investor		-			(0.9	)		(0.9	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(1,081.6	)		1,081.6			-
Cash paid to KCP&L for receivables purchased		1,068.0			(1,068.0	)		-
Servicing fees		2.0			(2.0	)		-
Interest on intercompany note		0.4			(0.4	)		-


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

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


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

Cash flows during the period
Cash from customers transferred to Receivables Company			(1,029.8	)		1,029.8			-
Cash paid to KCP&L for receivables purchased			1,016.9			(1,016.9	)		-
Servicing fees			1.9			(1.9	)		-
Interest on intercompany note			0.4			(0.4	)		-
(a)	Any net gain (loss) is the result of the timing difference inherent in collecting receivables and
	over the life of the agreement will net to zero.

NUCLEAR PLANT

9 Months Ended

Sep. 30, 2011

Nuclear plant

4.	NUCLEAR PLANT

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

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

Spent Nuclear Fuel and High-Level Radioactive Waste

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kWh of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel. These disposal costs are charged to fuel expense. In March 2010, the DOE filed a motion to withdraw its application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada, which would bring the licensing process to an end. An NRC board denied the DOE’s motion to withdraw its application in June 2010, and the DOE appealed that decision to the full NRC in July 2010. In September 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of September 2011 due to a lack of funding. Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025, and believes it will be able to expand on-site storage as needed past 2025. Management cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity. See Note 11 for a related legal proceeding.

Low-Level Radioactive Waste

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

Nuclear Plant Decommissioning Costs

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


		Total			KCP&L's
		Station			47% Share
		(millions)
Current cost of decommissioning (in 2011 dollars)		$	630		$	296
Future cost of decommissioning (in 2045-2053 dollars) (a)			2,455			1,154

Annual escalation factor			3.73	%
Annual return on trust assets (b)			6.89	%
(a)	Total future cost over an eight year decommissioning period.
(b)	The 6.89% rate of return is through 2025. The rate then systematically decreases
	through 2053 to 1.81% based on the assumption that the fund's investment mix
	will become increasingly more conservative as the decommissioning period
	approaches.

Nuclear Decommissioning Trust Fund

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


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

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


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

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


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

REGULATORY MATTERS

9 Months Ended

Sep. 30, 2011

Regulatory matters

5.	REGULATORY MATTERS

KCP&L Kansas Rate Case Proceedings

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

KCP&L Missouri Rate Case Proceedings

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

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

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

GMO Missouri Rate Case Proceedings

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

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

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

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

SPP and NERC Inquiries

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

MPSC Regulatory Approval of the GMO Acquisition

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

Regulatory Assets and Liabilities

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


							Great
September 30, 2011	KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	119.0		$	24.9		$	143.9
Loss on reacquired debt		6.5	(a)		0.6	(a)		7.1
Cost of removal		7.0			-			7.0
Asset retirement obligations		30.4			13.6			44.0
Pension and post-retirement costs		373.2	(b)		120.4	(b)		493.6
Deferred customer programs		48.2	(c)		19.5			67.7
Rate case expenses		9.9	(d)		4.5	(d)		14.4
Skill set realignment costs		3.7	(e)		-			3.7
Fuel adjustment clauses		30.1	(d)		42.5	(d)		72.6
Acquisition transition costs		26.2	(f)		21.3	(f)		47.5
St. Joseph Light & Power acquisition		-			2.2	(g)		2.2
Storm damage		-			2.0	(h)		2.0
Derivative instruments		-			3.1	(i)		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		16.5			6.1			22.6
Iatan No. 2 construction accounting costs		27.6			15.5			43.1
Other		2.3	(j)		0.4	(j)		2.7
Total	$	700.6		$	276.6		$	977.2
Regulatory Liabilities
Emission allowances	$	83.0		$	0.3		$	83.3
Asset retirement obligations		40.9			-			40.9
Pension		0.5			39.9			40.4
Cost of removal		-			62.5	(k)		62.5
Other		11.2			19.5			30.7
Total	$	135.6		$	122.2		$	257.8

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

(b)

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

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

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

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

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

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

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

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

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

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


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

PENSION PLANS AND OTHER EMPLOYEE BENEFITS

9 Months Ended

Sep. 30, 2011

Pension Plans, Other Employee Benefits and Voluntary Separation Program

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

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

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

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


	Pension Benefits						Other Benefits
Three Months Ended September 30	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	7.8		$	7.6		$	0.7		$	1.0
Interest cost		12.4			12.3			2.0			2.2
Expected return on plan assets		(9.5	)		(9.2	)		(0.4	)		(0.5	)
Prior service cost		1.1			1.1			1.8			1.8
Recognized net actuarial loss (gain)		9.7			9.4			(0.1	)		(0.1	)
Transition obligation		-			-			0.3			0.3
Settlement charge		10.0			-			-			-
Net periodic benefit costs before
regulatory adjustment		31.5			21.2			4.3			4.7
Regulatory adjustment		(12.8	)		(8.1	)		0.4			-
Net periodic benefit costs	$	18.7		$	13.1		$	4.7		$	4.7


	Pension Benefits						Other Benefits
Year to Date September 30	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	23.4		$	22.8		$	2.3		$	2.8
Interest cost		37.5			36.9			5.9			6.6
Expected return on plan assets		(28.8	)		(27.5	)		(1.3	)		(1.6	)
Prior service cost		3.4			3.5			5.4			5.4
Recognized net actuarial loss (gain)		28.9			28.1			(0.4	)		(0.1	)
Transition obligation		-			-			1.0			1.0
Settlement charge		10.2			-			-			-
Net periodic benefit costs before
regulatory adjustment		74.6			63.8			12.9			14.1
Regulatory adjustment		(25.1	)		(24.6	)		0.7			-
Net periodic benefit costs	$	49.5		$	39.2		$	13.6		$	14.1

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

Voluntary Separation Program

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

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

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

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 158

-Paragraph 7, 21, 22

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5, 6, 7, 8

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 8

-Subparagraph m

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 106

-Paragraph 518

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 87

-Paragraph 264

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph b

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph a

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph h

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph q

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

-Publisher FASB

-Name FASB Staff Position (FSP)

-Number FAS106-2

-Paragraph 20, 21, 22

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

-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 03-2

-Paragraph 8

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

-Publisher AICPA

-Name Accounting Principles Board Opinion (APB)

-Number 30

-Paragraph 26

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

-Publisher FASB

-Name Implementation Guide (Q and A)

-Number FAS88

-Paragraph 63

+ Details

EQUITY COMPENSATION

9 Months Ended

Sep. 30, 2011

Equity Compensation

7.	EQUITY COMPENSATION

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

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


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

Performance Shares

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


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

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

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

Restricted Stock

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


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

At September 30, 2011, the remaining weighted-average contractual term was 1.6 years. The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2011, was $17.89 and $19.03, respectively. The weighted-average grant-date fair value of shares granted for the three months ended and year to date September 30, 2010, was $18.32 and $17.80, respectively. At September 30, 2011, there was $3.4 million of total unrecognized compensation expense, net of forfeiture rates, related to nonvested restricted stock granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term. There were no shares vested for the three months ended September 30, 2011. The total fair value of shares vested year to date September 30, 2011, was $2.6 million. The total fair value of shares vested for the three months ended and year to date September 30, 2010, was $0.9 million and $7.3 million, respectively.

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

9 Months Ended

Sep. 30, 2011

Short-term debt

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

Great Plains Energy’s $200 Million Revolving Credit Facility

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

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

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

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

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

LONG-TERM DEBT

9 Months Ended

Sep. 30, 2011

Long-term debt

9.	LONG-TERM DEBT

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


		September 30			December 31
	Year Due	2011			2010
KCP&L		(millions)
General Mortgage Bonds
4.87% EIRR bonds (a)(b)	2012-2035	$	119.3		$	158.8
7.15% Series 2009A (8.59% rate)(c)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
EIRR Series 2007A-1(d)	2035		-			63.3
EIRR Series 2007A-2(d)	2035		-			10.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
6.50% Series	2011		150.0			150.0
5.85% Series (5.72% rate)(c)	2017		250.0			250.0
6.375% Series (7.49% rate)(c)	2018		350.0			350.0
6.05% Series (5.78% rate)(c)	2035		250.0			250.0
5.30% Series	2041		400.0			-
EIRR bonds
4.90% Series 2008	2038		23.4			23.4
Other	2012-2018		2.9			3.3
Current maturities			(162.7	)		(150.3	)
Unamortized discount			(4.3	)		(2.0	)
Total KCP&L			1,901.8			1,629.7

Other Great Plains Energy
GMO First Mortgage Bonds
9.44% Series	2012-2021		11.2			12.4
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.214% Wamego Series 1996 (e)	2026		7.3			7.3
0.263% State Environmental 1993 (e)	2028		5.0			5.0
GMO Senior Notes
7.95% Series			-			137.3
7.75% Series			-			197.0
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			24.2			49.9
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(c)	2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(c)	2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes	2012		287.5			287.5
Great Plains Energy 4.85% Senior Notes (7.34% rate)(c)	2021		350.0			-
Current maturities			(788.7	)		(335.4	)
Unamortized discount			(0.7	)		(0.5	)
Total Great Plains Energy excluding current maturities		$	2,750.1		$	2,942.7
(a) Weighted-average interest rates at September 30, 2011
(b) September 30, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by
KCP&L
(c) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(d) September 30, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the
bonds have been repurchased and are held by KCP&L
(e) Variable rate

Fair Value of Long-Term Debt

Fair value of long-term debt is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices were not available. At September 30, 2011, and December 31, 2010, the book value of Great Plains Energy’s long-term debt, including current maturities, was $3.7 billion and $3.4 billion, respectively. At September 30, 2011, and December 31, 2010, the fair value of Great Plains Energy’s long-term debt, including current maturities, was $4.1 billion and $3.7 billion, respectively. At September 30, 2011, and December 31, 2010, the book value of KCP&L’s long-term debt, including current maturities, was $2.1 billion and $1.8 billion, respectively. At September 30, 2011, and December 31, 2010, the fair value of KCP&L’s long-term debt, including current maturities, was $2.3 billion and $1.9 billion, respectively.

KCP&L General Mortgage Bonds and EIRR Bonds

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

KCP&L Senior Notes

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

GMO Senior Notes

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

Great Plains Energy Senior Notes

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

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

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

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

COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2011

Commitments and contingencies

10.	COMMITMENTS AND CONTINGENCIES

Environmental Matters

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

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

Air and Climate Change Overview

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

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

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

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

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

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

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

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

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

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

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

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

CAIR currently establishes a market-based cap-and-trade program with an emission allowance allocation. Facilities demonstrate compliance with CAIR by holding sufficient allowances for each ton of SO2 and NOx emitted in any given year. KCP&L and GMO are currently allowed to utilize unused SO2 emission allowances that they have either accumulated during previous years of the Acid Rain Program or purchased to meet the more stringent CAIR requirements. At September 30, 2011, KCP&L had accumulated unused SO2 emission allowances sufficient to support over 150,000 tons of SO2 emissions (enough to support expected requirements under the CAIR and the Acid Rain Program for the foreseeable future) under the provisions of the Acid Rain program, which are recorded in inventory at zero cost. At September 30, 2011, GMO had accumulated unused SO2 emission allowances sufficient to support just over 9,000 tons of SO2 emissions (enough to support expected requirements under the CAIR and Acid Rain Program through 2011), which it has received under the Acid Rain Program or purchased, and are recorded in inventory at average cost. KCP&L and GMO purchase NOx allowances as needed.

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

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

Best Available Retrofit Technology (BART) Rule

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

Mercury and Other Hazardous Air Pollutant Emissions

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

In July 2009, the EPA sent letters notifying KCP&L that MACT determinations and schedules of compliance are required for coal and oil-fired EGUs that began actual construction or reconstruction after December 15, 2000, and identified Iatan No. 2 and Hawthorn No. 5 as affected EGUs. This was an outcome of the D.C. Court of Appeals’ vacatur of both the CAMR and the contemporaneously promulgated rule removing EGUs from MACT requirements. In May 2011, KCP&L received a letter from the Missouri Department of Natural Resources (MDNR) stating the MACT determination was not required for Hawthorn No. 5. It is not currently known how MACT determinations and schedules of compliance will impact the permitting or operating requirements for Iatan No. 2, but it is possible a MACT determination may ultimately require additional emission control equipment and permit limits.

In April 2010, the EPA, in a court approved settlement, agreed to develop MACT standards for mercury and potentially other hazardous air pollutant emissions. In the settlement agreement, the EPA agreed to propose MACT standards in March 2011 and is expected to issue final standards by December 2011. In March 2011, the EPA issued a proposed rule that would reduce emissions of hazardous air pollutants from new and existing coal-fired EGUs with a capacity of 25MW or greater. The proposed rule would establish numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrogen chloride (a surrogate for acid gases). The proposed rule would establish work practices, instead of numerical emission limits, for organic hazardous air pollutants, including dioxin/furan. Compliance with the rule would need to be addressed by installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market or a combination of these and other alternatives. Any final rule could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Industrial Boiler Rule

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

New Source Review

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

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

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

Collaboration Agreement

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

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

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

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

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

Climate Change

The Companies are subject to existing greenhouse gas reporting regulations and, as discussed below, are subject to certain greenhouse gas permitting requirements starting in 2011. Management believes it is possible that additional federal or relevant state or local laws or regulations could be enacted to address global climate change. At the international level, while the United States is not a current party to the Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions. International agreements legally binding on the United States may be reached in the future. Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels. The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 23 million tons and 17 million tons per year for Great Plains Energy and KCP&L, respectively.

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

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

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

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

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

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

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

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

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

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

Ozone NAAQS

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

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

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

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

SO2 NAAQS

In June 2010, the EPA strengthened the primary NAAQS for SO2. The EPA revised the primary SO2 standard by establishing a new 1-hour standard at a level of 0.075 ppm. The EPA revoked the two existing primary standards of 0.140 ppm evaluated over 24 hours and 0.030 ppm evaluated over an entire year. In July 2011, the MDNR recommended to the EPA that part of Jackson County, Missouri, which is in the Companies' service territory, be designated a nonattainment area for the new 1-hour SO2 standard. Although the impact on Great Plains Energy’s and KCP&L’s operations will not be known until after the nonattainment designations are approved and the state implementation plans are submitted, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Montrose Station Notice of Violation

In June 2009, KCP&L received notification from the MDNR alleging that its Montrose Station had excess particulate matter emissions in 2008. KCP&L is working with the MDNR to resolve this issue and management believes the outcome will not have a significant impact on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Water

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

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

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

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

Solid Waste

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

Remediation

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

At September 30, 2011, and December 31, 2010, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site. At September 30, 2011, and December 31, 2010, Great Plains Energy had $0.4 million accrued for environmental remediation expenses, which includes the $0.3 million at KCP&L, and additional potential remediation and ground water monitoring costs relating to two GMO sites. The amounts accrued were established on an undiscounted basis and Great Plains Energy and KCP&L do not currently have an estimated time frame over which the accrued amounts may be paid.

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

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

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

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

Contractual Commitments

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

LEGAL PROCEEDINGS

9 Months Ended

Sep. 30, 2011

Legal proceedings

11.	LEGAL PROCEEDINGS

KCP&L Spent Nuclear Fuel and Radioactive Waste

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

Iatan Levee Litigation

On May 22, 2009, several farmers filed suit against Great Plains Energy and KCP&L in the Circuit Court of Platte County, Missouri, alleging negligence, private nuisance, trespass and violations of the Missouri Crop Protection Act and seeking unspecified compensatory and punitive damages. These allegations stem from flooding at or near the Iatan Station in 2007 and 2008. The farmers allege the flooding was a result of maintenance of a nearby levee. Written discovery and depositions are underway and this matter is set for trial in May 2012. Management cannot predict the outcome of this matter.

GMO Price Reporting Litigation

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

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

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

9 Months Ended

Sep. 30, 2011

12.	RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO’s business and operate its facilities at cost. These costs totaled $25.0 million and $82.2 million, respectively, for the three months ended and year to date September 30, 2011, respectively. These costs totaled $26.3 million and $73.5 million, respectively, for the same periods in 2010. Additionally, KCP&L and GMO engage in wholesale electricity transactions with each other. KCP&L and GMO are also authorized to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO. The following table summarizes KCP&L’s related party receivables and payables.


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

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

+ References+ Details

DERIVATIVE INSTRUMENTS

9 Months Ended

Sep. 30, 2011

Derivative Instruments

13.	DERIVATIVE INSTRUMENTS

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

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

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

Interest Rate Risk Management

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

Commodity Risk Management

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

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

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

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


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

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

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.3		2.0
Total Derivatives		$	9.3	$	2.2

December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9


KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2

December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

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

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

Year to Date September 30, 2011
Interest rate contracts	$	(5.3	)	Interest charges	$	(11.9	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		2.2		Income tax benefit (expense)		4.7
Total	$	(3.3	)	Total	$	(7.3	)

Three Months Ended September 30, 2010
Interest rate contracts	$	(9.9	)	Interest charges	$	(2.6	)
Commodity contracts		(0.4	)	Fuel		(0.5	)
Income tax benefit (expense)		4.0		Income tax benefit (expense)		1.1
Total	$	(6.3	)	Total	$	(2.0	)

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

KCP&L
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification	Amount
Three Months Ended September 30, 2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(2.1	)
Commodity contracts		(0.1	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		0.9
Total	$	-		Total	$	(1.3	)

Year to Date September 30, 2011
Interest rate contracts	$	-		Interest charges	$	(6.5	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		2.6
Total	$	(0.1	)	Total	$	(4.0	)

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

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

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

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

Year to Date September 30, 2011
Commodity contracts	$	(3.5	)	Fuel	$	(3.5	)
Total	$	(3.5	)	Total	$	(3.5	)

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

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

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

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


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

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

FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2011

Fair value measurements

14.	FAIR VALUE MEASUREMENTS

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

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

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

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

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


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


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

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

(b)

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

(c)

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

(d)

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

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


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other Great
	Plains Energy
	Derivative
	Instruments
	(millions)
Balance July 1, 2011	$	4.9
Total realized/unrealized gains or (losses)
Included in non-operating income		4.0
Settlements		(4.4	)
Balance September 30, 2011	$	4.5

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at September 30, 2011	$	(0.3	)


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other Great
	Plains Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains or (losses)
Included in non-operating income		11.1
Settlements		(10.3	)
Balance September 30, 2011	$	4.5

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at September 30, 2011	$	1.2


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

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


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other Great			Great Plains
	KCP&L			Plains Energy			Energy
	State & Local			Derivative
	Obligations			Instruments			Total
	(millions)
Balance January 1, 2010	$	0.2		$	4.1		$	4.3
Total realized/unrealized gains or (losses)
Included in non-operating income		-			(9.5	)		(9.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			9.1			9.1
Balance September 30, 2010	$	-		$	3.7		$	3.7

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

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

+ References+ Details

TAXES

9 Months Ended

Sep. 30, 2011

Taxes

15.

TAXES

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


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


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

Income Tax Expense and Effective Income Tax Rates

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


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


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


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


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

Uncertain Tax Positions

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

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

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


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

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

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

SEGMENTS AND RELATED INFORMATION

9 Months Ended

Sep. 30, 2011

Segments and Related Information

16.	SEGMENTS AND RELATED INFORMATION

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

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


Three Months Ended	Electric						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	773.7		$	-		$	773.7
Depreciation and amortization		(65.9	)		-			(65.9	)
Interest charges		(50.2	)		(10.6	)		(60.8	)
Income tax (expense) benefit		(82.9	)		7.5			(75.4	)
Net income (loss) attributable to Great Plains Energy		133.9			(7.4	)		126.5


Year to Date	Electric						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	1,831.7		$	-		$	1,831.7
Depreciation and amortization		(205.9	)		-			(205.9	)
Interest charges		(124.8	)		(31.2	)		(156.0	)
Income tax (expense) benefit		(109.8	)		19.2			(90.6	)
Net income (loss) attributable to Great Plains Energy		189.9			(17.6	)		172.3


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


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


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

GOODWILL

9 Months Ended

Sep. 30, 2011

Goodwill

17.

GOODWILL

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

Discloses the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain or loss on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss. This element may be used as a single block of text to include the entire intangible asset disclosure including data and tables.

+ References+ Details

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2011

Basic and Diluted Earnings per Common Share Calculations

Organization

·	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).

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

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

Basic and Diluted Earnings per Common Share Calculation

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


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

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

The computation of diluted EPS year to date September 30, 2010, excludes anti-dilutive shares consisting of 116,388 performance shares, 278,452 restricted stock shares and 209,837 stock options.

Description containing the entire organization, consolidation and basis of presentation of financial statements disclosure. May be provided in more than one note to the financial statements, as long as users are provided with an understanding of (1) the significant judgments and assumptions made by an enterprise in determining whether it must consolidate a VIE and/or disclose information about its involvement with a VIE, (2) the nature of restrictions on a consolidated VIE's assets reported by an enterprise in its statement of financial position, including the carrying amounts of such assets, (3) the nature of, and changes in, the risks associated with an enterprise's involvement with the VIE, and (4) how an enterprise's involvement with the VIE affects the enterprise's financial position, financial performance, and cash flows. Describes procedure if disclosures are provided in more than one note to the financial statements.

+ References+ Details

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2011

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


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

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

9 Months Ended

Sep. 30, 2011

Cash Flow, Supplemental Disclosures [Text Block]

Great Plains Energy Other Operating Activities
Year to Date September 30	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(41.2	)	$	(45.9	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		12.9			4.9
Materials and supplies		(4.8	)		(10.0	)
Accounts payable		(71.5	)		(79.1	)
Accrued taxes		52.5			54.6
Accrued interest		(6.1	)		(2.0	)
Deferred refueling outage costs		(23.8	)		8.0
Fuel adjustment clauses		(27.3	)		(2.3	)
Pension and post-retirement benefit obligations		22.0			15.5
Allowance for equity funds used during construction		(0.3	)		(25.5	)
Interest rate hedge settlements		(26.1	)		(6.9	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		2.3			4.0
Uncertain tax positions		(20.2	)		(1.4	)
Other		(22.7	)		(18.1	)
Total other operating activities	$	(154.3	)	$	(199.2	)
Cash paid during the period:
Interest	$	195.1		$	175.4
Income taxes	$	2.4		$	0.4
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	34.8		$	36.4

KCP&L Other Operating Activities
Year to Date September 30	2011			2010
Cash flows affected by changes in:	(millions)
Receivables	$	(39.5	)	$	(0.1	)
Accounts receivable pledged as collateral		-			(95.0	)
Fuel inventories		2.9			0.1
Materials and supplies		(4.3	)		(7.2	)
Accounts payable		(43.2	)		(87.2	)
Accrued taxes		40.3			(6.3	)
Accrued interest		7.9			10.3
Deferred refueling outage costs		(23.8	)		8.0
Pension and post-retirement benefit obligations		32.1			31.1
Allowance for equity funds used during construction		-			(21.7	)
Kansas Energy Cost Adjustment		(22.0	)		(5.4	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		1.5			3.0
Uncertain tax positions		(10.1	)		(1.6	)
Other		(16.1	)		0.9
Total other operating activities	$	(74.3	)	$	(171.1	)
Cash paid during the period:
Interest	$	74.6		$	60.3
Income taxes	$	0.1		$	71.6
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	30.7		$	31.6

RECEIVABLES (Tables)

9 Months Ended

Sep. 30, 2011

Schedule of accounts receivable


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

Schedule of accounts receivable sold


				Receivables			Consolidated
Three Months Ended September 30, 2011	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(468.8	)	$	468.8		$	-
Gain (loss) on sale of accounts receivable (a)		(5.9	)		5.8			(0.1	)
Servicing fees		0.9			(0.9	)		-
Fees to outside investor		-			(0.3	)		(0.3	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(463.4	)		463.4			-
Cash paid to KCP&L for receivables purchased		457.6			(457.6	)		-
Servicing fees		0.9			(0.9	)		-
Interest on intercompany note		0.2			(0.2	)		-


				Receivables			Consolidated
Year to Date September 30, 2011	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,108.4	)	$	1,108.4		$	-
Gain (loss) on sale of accounts receivable (a)		(14.0	)		13.6			(0.4	)
Servicing fees		2.0			(2.0	)		-
Fees to outside investor		-			(0.9	)		(0.9	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(1,081.6	)		1,081.6			-
Cash paid to KCP&L for receivables purchased		1,068.0			(1,068.0	)		-
Servicing fees		2.0			(2.0	)		-
Interest on intercompany note		0.4			(0.4	)		-


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

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


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

Cash flows during the period
Cash from customers transferred to Receivables Company			(1,029.8	)		1,029.8			-
Cash paid to KCP&L for receivables purchased			1,016.9			(1,016.9	)		-
Servicing fees			1.9			(1.9	)		-
Interest on intercompany note			0.4			(0.4	)		-
(a)	Any net gain (loss) is the result of the timing difference inherent in collecting receivables and
	over the life of the agreement will net to zero.

NUCLEAR PLANT (Tables)

9 Months Ended

Sep. 30, 2011

Changes in nuclear decommissioning trust fund


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

Detail of assets held in nuclear decommissioning trust fund


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

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


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

Nuclear Plant Decommissioning Costs


		Total			KCP&L's
		Station			47% Share
		(millions)
Current cost of decommissioning (in 2011 dollars)		$	630		$	296
Future cost of decommissioning (in 2045-2053 dollars) (a)			2,455			1,154

Annual escalation factor			3.73	%
Annual return on trust assets (b)			6.89	%
(a)	Total future cost over an eight year decommissioning period.
(b)	The 6.89% rate of return is through 2025. The rate then systematically decreases
	through 2053 to 1.81% based on the assumption that the fund's investment mix
	will become increasingly more conservative as the decommissioning period
	approaches.

REGULATORY MATTERS (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2011

Dec. 31, 2010

Regulatory assets


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

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

(b)

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

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

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

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

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

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

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

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


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

Regulatory liabilities


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

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


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

PENSION PLANS AND OTHER EMPLOYEE BENEFITS (Tables)

9 Months Ended

Sep. 30, 2011

Components of Net Periodic Benefit Costs


	Pension Benefits						Other Benefits
Three Months Ended September 30	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	7.8		$	7.6		$	0.7		$	1.0
Interest cost		12.4			12.3			2.0			2.2
Expected return on plan assets		(9.5	)		(9.2	)		(0.4	)		(0.5	)
Prior service cost		1.1			1.1			1.8			1.8
Recognized net actuarial loss (gain)		9.7			9.4			(0.1	)		(0.1	)
Transition obligation		-			-			0.3			0.3
Settlement charge		10.0			-			-			-
Net periodic benefit costs before
regulatory adjustment		31.5			21.2			4.3			4.7
Regulatory adjustment		(12.8	)		(8.1	)		0.4			-
Net periodic benefit costs	$	18.7		$	13.1		$	4.7		$	4.7


	Pension Benefits						Other Benefits
Year to Date September 30	2011			2010			2011			2010
Components of net periodic benefit costs	(millions)
Service cost	$	23.4		$	22.8		$	2.3		$	2.8
Interest cost		37.5			36.9			5.9			6.6
Expected return on plan assets		(28.8	)		(27.5	)		(1.3	)		(1.6	)
Prior service cost		3.4			3.5			5.4			5.4
Recognized net actuarial loss (gain)		28.9			28.1			(0.4	)		(0.1	)
Transition obligation		-			-			1.0			1.0
Settlement charge		10.2			-			-			-
Net periodic benefit costs before
regulatory adjustment		74.6			63.8			12.9			14.1
Regulatory adjustment		(25.1	)		(24.6	)		0.7			-
Net periodic benefit costs	$	49.5		$	39.2		$	13.6		$	14.1

EQUITY COMPENSATION (Tables)

9 Months Ended

Sep. 30, 2011

Equity compensation expense and associated income tax benefits


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

Performance share activity


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

Restricted stock activity


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

LONG-TERM DEBT (Tables)

9 Months Ended

Sep. 30, 2011

Long-term debt


		September 30			December 31
	Year Due	2011			2010
KCP&L		(millions)
General Mortgage Bonds
4.87% EIRR bonds (a)(b)	2012-2035	$	119.3		$	158.8
7.15% Series 2009A (8.59% rate)(c)	2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0
EIRR Series 2007A-1(d)	2035		-			63.3
EIRR Series 2007A-2(d)	2035		-			10.0
5.375% EIRR Series 2007B	2035		73.2			73.2
Senior Notes
6.50% Series	2011		150.0			150.0
5.85% Series (5.72% rate)(c)	2017		250.0			250.0
6.375% Series (7.49% rate)(c)	2018		350.0			350.0
6.05% Series (5.78% rate)(c)	2035		250.0			250.0
5.30% Series	2041		400.0			-
EIRR bonds
4.90% Series 2008	2038		23.4			23.4
Other	2012-2018		2.9			3.3
Current maturities			(162.7	)		(150.3	)
Unamortized discount			(4.3	)		(2.0	)
Total KCP&L			1,901.8			1,629.7

Other Great Plains Energy
GMO First Mortgage Bonds
9.44% Series	2012-2021		11.2			12.4
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6
0.214% Wamego Series 1996 (e)	2026		7.3			7.3
0.263% State Environmental 1993 (e)	2028		5.0			5.0
GMO Senior Notes
7.95% Series			-			137.3
7.75% Series			-			197.0
11.875% Series	2012		500.0			500.0
8.27% Series	2021		80.9			80.9
Fair Value Adjustment			24.2			49.9
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0
7.33% Series	2023		3.0			3.0
7.17% Series	2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(c)	2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(c)	2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes	2012		287.5			287.5
Great Plains Energy 4.85% Senior Notes (7.34% rate)(c)	2021		350.0			-
Current maturities			(788.7	)		(335.4	)
Unamortized discount			(0.7	)		(0.5	)
Total Great Plains Energy excluding current maturities		$	2,750.1		$	2,942.7
(a) Weighted-average interest rates at September 30, 2011
(b) September 30, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by
KCP&L
(c) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(d) September 30, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the
bonds have been repurchased and are held by KCP&L
(e) Variable rate

DERIVATIVE INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2011

Values of open positions for derivative instruments


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

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

Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.3		2.0
Total Derivatives		$	9.3	$	2.2

December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9


KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
September 30, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.2

December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

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

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

Year to Date September 30, 2011
Interest rate contracts	$	(5.3	)	Interest charges	$	(11.9	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		2.2		Income tax benefit (expense)		4.7
Total	$	(3.3	)	Total	$	(7.3	)

Three Months Ended September 30, 2010
Interest rate contracts	$	(9.9	)	Interest charges	$	(2.6	)
Commodity contracts		(0.4	)	Fuel		(0.5	)
Income tax benefit (expense)		4.0		Income tax benefit (expense)		1.1
Total	$	(6.3	)	Total	$	(2.0	)

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

KCP&L
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)
	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification	Amount
Three Months Ended September 30, 2011	(millions)				(millions)
Interest rate contracts	$	-		Interest charges	$	(2.1	)
Commodity contracts		(0.1	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		0.9
Total	$	-		Total	$	(1.3	)

Year to Date September 30, 2011
Interest rate contracts	$	-		Interest charges	$	(6.5	)
Commodity contracts		(0.2	)	Fuel		(0.1	)
Income tax benefit (expense)		0.1		Income tax benefit (expense)		2.6
Total	$	(0.1	)	Total	$	(4.0	)

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

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

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

Year to Date September 30, 2011
Commodity contracts	$	(3.5	)	Fuel	$	(3.5	)
Total	$	(3.5	)	Total	$	(3.5	)

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

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

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

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

Year to Date September 30, 2011
Commodity contracts	$	(3.5	)	Fuel	$	(3.5	)
Total	$	(3.5	)	Total	$	(3.5	)

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

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

Accumulated other comprehensive income related to cash flow hedges


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

FAIR VALUE MEASUREMENTS (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2011

Dec. 31, 2010

Balances of financial assets measured at fair value


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

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

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

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

(b)

(c)

(d)


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

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

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

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

(b)

(c)

(d)

Balances of financial liabilities measured at fair value

Fair Value Measurements Using

Description

September 30

2011

Netting(d)

Quoted Prices in Active Markets for Identical Assets

(Level 1)

Significant Other Observable Inputs

(Level 2)

Significant Unobservable Inputs

(Level 3)

KCP&L

(millions)

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

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

(d)

Fair Value Measurements Using

Description

December 31

2010

Netting(d)

Quoted Prices in Active Markets for Identical Assets

(Level 1)

Significant Other Observable Inputs

(Level 2)

Significant Unobservable Inputs

(Level 3)

KCP&L

(millions)

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

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

(d)

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


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other Great
	Plains Energy
	Derivative
	Instruments
	(millions)
Balance July 1, 2011	$	4.9
Total realized/unrealized gains or (losses)
Included in non-operating income		4.0
Settlements		(4.4	)
Balance September 30, 2011	$	4.5

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at September 30, 2011	$	(0.3	)


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other Great
	Plains Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains or (losses)
Included in non-operating income		11.1
Settlements		(10.3	)
Balance September 30, 2011	$	4.5

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at September 30, 2011	$	1.2


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

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


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other Great			Great Plains
	KCP&L			Plains Energy			Energy
	State & Local			Derivative
	Obligations			Instruments			Total
	(millions)
Balance January 1, 2010	$	0.2		$	4.1		$	4.3
Total realized/unrealized gains or (losses)
Included in non-operating income		-			(9.5	)		(9.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			9.1			9.1
Balance September 30, 2010	$	-		$	3.7		$	3.7

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

TAXES (Tables)

9 Months Ended

Sep. 30, 2011

Components of income tax expense (benefit)


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


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

Income tax expense (benefit) and effective income tax rates


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


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


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


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

Liability for unrecognized tax benefits


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

The disclosure required for tax positions taken in the tax returns filed or to be filed for which it is more likely than not that the tax position will not be sustained upon examination by taxing authorities (i.e., uncertain tax positions) and other types of income tax contingencies, including: (1) the policy on classification of interest and penalties; (2) a tabular reconciliation of the total amounts of unrecognized tax benefits at the beginning and end of the period; the total amount(s) of: (3) unrecognized tax benefits that, if recognized, would affect the effective tax rate, and (4) interest and penalties recognized in each of the income statement and balance sheet; (5) for positions for which it is reasonably possible that the total amounts unrecognized will significantly change within 12 months of the reporting date the: (i) nature of the uncertainty, (ii) nature of the event that could occur that would cause the change, and (iii) an estimate of the range of the reasonably possible change or a statement that an estimate of the range cannot be made; and (6) a description of tax years that remain subject to examination by major tax jurisdictions.

+ References+ Details

SEGMENTS AND RELATED INFORMATION (Tables)

9 Months Ended

Sep. 30, 2011

Summarized Financial Information based on segments


Three Months Ended	Electric						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	773.7		$	-		$	773.7
Depreciation and amortization		(65.9	)		-			(65.9	)
Interest charges		(50.2	)		(10.6	)		(60.8	)
Income tax (expense) benefit		(82.9	)		7.5			(75.4	)
Net income (loss) attributable to Great Plains Energy		133.9			(7.4	)		126.5


Year to Date	Electric						Great Plains
September 30, 2011	Utility			Other			Energy
	(millions)
Operating revenues	$	1,831.7		$	-		$	1,831.7
Depreciation and amortization		(205.9	)		-			(205.9	)
Interest charges		(124.8	)		(31.2	)		(156.0	)
Income tax (expense) benefit		(109.8	)		19.2			(90.6	)
Net income (loss) attributable to Great Plains Energy		189.9			(17.6	)		172.3


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


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


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

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

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

RECEIVABLES (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2010

Sep. 30, 2011

Sep. 30, 2010

Dec. 31, 2010

Allowance for doubtful accounts

$ (3.8)

$ (2.7)

Receivables, net

275.6

241.7

Accounts receivable sold [Line Items]

Accounts receivable pledged as collateral

95.0

Collateralized note payable

95.0

Maximum percentage servicing fee received on receivables sold (in hundredths)

1.50%

Maximum Amount Of Outstanding Principal Under Receivables Agreement

110.0

Kansas City Power and Light Company [Member]

Accounts receivable (sold) purchased [Abstract]

Receivables (sold) purchased

(468.8)

(442.0)

(1,108.4)

(1,067.7)

Gain (loss) on sale of accounts receivables

(5.9)

^[1]

(5.6)

^[1]

(14.0)

^[1]

(13.5)

^[1]

Servicing fees

0.9

0.8

2.0

1.9

Fees to outside investor

Cash from customers transferred to receivables company

(463.4)

(430.9)

(1,081.6)

(1,029.8)

Cash paid to KCPL for receivables purchased

457.6

425.5

1,068.0

1,016.9

Interest on intercompany note

0.2

0.4

Receivables Company [Member]

Accounts receivable (sold) purchased [Abstract]

Receivables (sold) purchased

468.8

442.0

1,108.4

1,067.7

Gain (loss) on sale of accounts receivables

5.8

^[1]

5.4

^[1]

13.6

^[1]

12.9

^[1]

Servicing fees

(0.9)

(0.8)

(2.0)

(1.9)

Fees to outside investor

(0.3)

(0.9)

Cash from customers transferred to receivables company

463.4

430.9

1,081.6

1,029.8

Cash paid to KCPL for receivables purchased

(457.6)

(425.5)

(1,068.0)

(1,016.9)

Interest on intercompany note

(0.2)

(0.4)

Great Plains Energy Incorporated [Member] | Billed Revenues [Member]

122.3

62.0

Great Plains Energy Incorporated [Member] | Unbilled Revenues [Member]

74.3

82.3

Great Plains Energy Incorporated [Member] | Other Receivables [Member}

82.8

100.1

Kansas City Power and Light Company [Member]

Allowance for doubtful accounts

(2.5)

(1.5)

Receivables, net

223.1

169.4

Accounts receivable sold [Line Items]

Accounts receivable pledged as collateral

95.0

Collateralized note payable

95.0

Accounts receivable (sold) purchased [Abstract]

Receivables (sold) purchased

Gain (loss) on sale of accounts receivables

(0.1)

^[1]

(0.2)

^[1]

(0.4)

^[1]

(0.6)

^[1]

Servicing fees

Fees to outside investor

(0.3)

(0.9)

Cash from customers transferred to receivables company

Cash paid to KCPL for receivables purchased

Interest on intercompany note

Kansas City Power and Light Company [Member] | Billed Revenues [Member]

43.5

6.5

Kansas City Power and Light Company [Member] | Unbilled Revenues [Member]

45.8

50.1

Kansas City Power and Light Company [Member] | Intercompany Receivables [Member]

68.2

43.2

Kansas City Power and Light Company [Member] | Other Receivables [Member}

$ 68.1

$ 71.1

[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.

NUCLEAR PLANT (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2011

Sep. 30, 2010

Sep. 30, 2011

Sep. 30, 2010

Dec. 31, 2010

Nuclear decommissioning trust fund beginning balance

$ 129.2

$ 112.5

Contributions to nuclear decommissioning trust fund

2.5

3.7

Nuclear decommissioning trust fund earned income, net of fees

4.0

2.0

Net realized gains/(losses)on nuclear decommissioning trust fund

0.3

6.7

Net unrealized gains/(losses) on nuclear decommissioning trust fund

(10.5)

4.3

Ending balance of nuclear decommissioning trust fund

125.5

129.2

Investments in decommissioning trust fund [Line Items]

121.4

114.6

10.9

15.7

(6.8)

(1.1)

Weighted average maturity of debt securities

125.5

129.2

7.0

Realized Gains on investments in decommissioning trust fund

0.2

1.0

7.2

Realized Losses on investments in decommissioning trust fund

(0.1)

(0.7)

(0.6)

Nuclear Plant Decommissioning Costs [Line Items]

Annual escalation factor

3.73%

Annual return on trust assets through 2025

6.89%

^[1]

6.89%

^[1]

Annual return on trust assets beginning in 2053

1.81%

Equity securities [Member]

Nuclear decommissioning trust fund beginning balance

85.5

Ending balance of nuclear decommissioning trust fund

75.2

85.5

Investments in decommissioning trust fund [Line Items]

75.3

73.4

6.5

13.1

(6.6)

(1.0)

75.2

85.5

Debt securities [Member]

Nuclear decommissioning trust fund beginning balance

40.6

Ending balance of nuclear decommissioning trust fund

46.9

40.6

Investments in decommissioning trust fund [Line Items]

42.7

38.1

4.4

2.6

(0.2)

(0.1)

46.9

40.6

Other [Member]

Nuclear decommissioning trust fund beginning balance

3.1

Ending balance of nuclear decommissioning trust fund

3.4

3.1

Investments in decommissioning trust fund [Line Items]

3.4

3.1

3.4

3.1

Kansas City Power and Light Company [Member]

Ending balance of nuclear decommissioning trust fund

125.5

129.2

Investments in decommissioning trust fund [Line Items]

Nuclear Plant Decommissioning Costs [Line Items]

125.5

129.2

Current cost of decommissioning (in 2011 dollars)

296.0

Future cost of decommissioning (in 2045-2053 dollars)

1,154.0

^[2]

1,154.0

^[2]

Total Wolf Creek [Member]

Nuclear Plant Decommissioning Costs [Line Items]

Current cost of decommissioning (in 2011 dollars)

630.0

Future cost of decommissioning (in 2045-2053 dollars)

$ 2,455.0

^[2]

$ 2,455.0

^[2]

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

REGULATORY MATTERS (Details) (USD $)
In Millions, unless otherwise specified

9 Months Ended

Sep. 30, 2011

Dec. 31, 2010

$ 977.2

$ 924.0

257.8

258.2

Emission allowances [Member]

83.3

86.4

Asset retirement obligations [Member]

40.9

44.9

Pension [Member]

40.4

37.1

Cost of removal, liability [Member]

62.5

62.8

Other [Member]

30.7

27.0

Taxes recoverable through future rates [Member]

143.9

142.5

Loss on reacquired debt [Member]

7.1

5.7

Cost of removal, asset [Member]

7.0

8.5

Asset retirement obligations [Member]

44.0

40.3

Pension and post-retirement costs [Member]

493.6

492.8

Deferred customer programs [Member]

67.7

60.3

Rate case expenses [Member]

14.4

15.6

Skill set realignment costs [Member]

3.7

4.8

Fuel adjustment clauses [Member]

72.6

45.5

Acquisition transition costs [Member]

47.5

51.8

St. Joseph Light and Power acquisition [Member]

2.2

2.6

Storm damage [Member]

2.0

3.2

Derivative instruments [Member]

3.1

Iatan No. 1 and Common facilities depreciation and carrying costs [Member]

22.6

19.4

Iatan No. 2 construction accounting costs [Member]

43.1

23.7

Other [Member]

2.7

4.2

Kansas City Power and Light Company [Member]

Deferred tax credits (note)

128.4

700.6

679.6

135.6

141.3

Kansas City Power and Light Company [Member] | Emission allowances [Member]

83.0

85.9

Kansas City Power and Light Company [Member] | Asset retirement obligations [Member]

40.9

44.9

Kansas City Power and Light Company [Member] | Pension [Member]

0.5

Kansas City Power and Light Company [Member] | Cost of removal, liability [Member]

Kansas City Power and Light Company [Member] | Other [Member]

11.2

10.5

Kansas City Power and Light Company [Member] | Taxes recoverable through future rates [Member]

119.0

117.2

Kansas City Power and Light Company [Member] | Loss on reacquired debt [Member]

6.5

^[1]

5.0

Kansas City Power and Light Company [Member] | Cost of removal, asset [Member]

7.0

8.5

Kansas City Power and Light Company [Member] | Asset retirement obligations [Member]

30.4

27.5

Kansas City Power and Light Company [Member] | Pension and post-retirement costs [Member]

373.2

^[2]

386.1

Kansas City Power and Light Company [Member] | Deferred customer programs [Member]

Amount not included in rate base

48.2

^[3]

44.7

11.3

various

Kansas City Power and Light Company [Member] | Rate case expenses [Member]

9.9

^[4]

12.3

various

Kansas City Power and Light Company [Member] | Skill set realignment costs [Member]

Amount not included in rate base

3.7

^[5]

4.8

2.5

2017

Kansas City Power and Light Company [Member] | Fuel adjustment clauses [Member]

30.1

^[4]

8.4

Kansas City Power and Light Company [Member] | Acquisition transition costs [Member]

26.2

^[6]

29.3

2016

Kansas City Power and Light Company [Member] | St. Joseph Light and Power acquisition [Member]

Kansas City Power and Light Company [Member] | Storm damage [Member]

Kansas City Power and Light Company [Member] | Derivative instruments [Member]

Kansas City Power and Light Company [Member] | Iatan No. 1 and Common facilities depreciation and carrying costs [Member]

16.5

15.1

Kansas City Power and Light Company [Member] | Iatan No. 2 construction accounting costs [Member]

27.6

17.2

Kansas City Power and Light Company [Member] | Other [Member]

2.3

^[7]

3.5

various

KCPL Greater Missouri Operations Company [Member]

Deferred tax credits (note)

3.5

276.6

244.4

122.2

116.9

KCPL Greater Missouri Operations Company [Member] | Emission allowances [Member]

0.3

0.5

KCPL Greater Missouri Operations Company [Member] | Asset retirement obligations [Member]

KCPL Greater Missouri Operations Company [Member] | Pension [Member]

39.9

37.1

KCPL Greater Missouri Operations Company [Member] | Cost of removal, liability [Member]

62.5

^[8]

62.8

KCPL Greater Missouri Operations Company [Member] | Other [Member]

19.5

16.5

KCPL Greater Missouri Operations Company [Member] | Taxes recoverable through future rates [Member]

24.9

25.3

KCPL Greater Missouri Operations Company [Member] | Loss on reacquired debt [Member]

0.6

^[1]

0.7

KCPL Greater Missouri Operations Company [Member] | Cost of removal, asset [Member]

KCPL Greater Missouri Operations Company [Member] | Asset retirement obligations [Member]

13.6

12.8

KCPL Greater Missouri Operations Company [Member] | Pension and post-retirement costs [Member]

120.4

^[2]

106.7

KCPL Greater Missouri Operations Company [Member] | Deferred customer programs [Member]

19.5

15.6

KCPL Greater Missouri Operations Company [Member] | Rate case expenses [Member]

4.5

^[4]

3.3

various

KCPL Greater Missouri Operations Company [Member] | Skill set realignment costs [Member]

KCPL Greater Missouri Operations Company [Member] | Fuel adjustment clauses [Member]

42.5

^[4]

37.1

KCPL Greater Missouri Operations Company [Member] | Acquisition transition costs [Member]

21.3

^[6]

22.5

2016

KCPL Greater Missouri Operations Company [Member] | St. Joseph Light and Power acquisition [Member]

2.2

^[9]

2.6

2015

KCPL Greater Missouri Operations Company [Member] | Storm damage [Member]

2.0

^[10]

3.2

2012

KCPL Greater Missouri Operations Company [Member] | Derivative instruments [Member]

3.1

^[11]

3.1

KCPL Greater Missouri Operations Company [Member] | Iatan No. 1 and Common facilities depreciation and carrying costs [Member]

6.1

4.3

KCPL Greater Missouri Operations Company [Member] | Iatan No. 2 construction accounting costs [Member]

15.5

6.5

KCPL Greater Missouri Operations Company [Member] | Other [Member]

0.4

^[7]

0.7

various

Rate jurisdiction - Kansas [Member] | Kansas City Power and Light Company [Member]

10.00%

49.70%

Dec. 01, 2010

Adjusted annual revenue increased authorized

21.8

Jurisdictional rate base

1,781

22.0

Annual revenue increase authorized but considered as interim subject to refund or true-up

1.4

Rate jurisdiction - Missouri [Member] | Kansas City Power and Light Company [Member]

Adjusted annual revenue increase

File date

Jun. 04, 2010

Annual revenue increase

92.1

66.5

10.00%

46.30%

May 04, 2011

Wholesale margin offset requested

34.8

Jurisdictional rate base

2,000

29.4

Wholesale margin offset authorized

45.9

Disallowed construction costs on Iatan Nos 1 and 2

1.5

Other disallowed costs

2.4

Qualifying advance coal project tax credits to be reallocated from KCPL to GMO

26.5

Rate jurisdiction - Missouri [Member] | KCPL Greater Missouri Operations Company [Member]

Disallowed construction costs on Iatan Nos 1 and 2

Jurisdictional rate base

1,760

0.8

Other disallowed costs

1.5

Rate jurisdiction - Missouri public service division [Member] | KCPL Greater Missouri Operations Company [Member]

Adjusted annual revenue increase

File date

Jun. 04, 2010

Annual revenue increase

75.8

65.9

10.00%

46.60%

Jun. 25, 2011

Adjusted annual revenue increased authorized

30.1

35.7

Amount of Crossroads disallowed from rate base

50.0

Amount of Crossroads transmission expense disallowed

4.9

Amount of Crossroads accumulated deferred taxes offset against rate base

15.0

Amount of Crossroads requested in rate base

104.0

Rate jurisdiction - St. Joseph Light and Power division [Member] | KCPL Greater Missouri Operations Company [Member]

Adjusted annual revenue increase

File date

Jun. 04, 2010

Annual revenue increase

22.1

23.2

10.00%

46.60%

Jun. 25, 2011

Adjusted annual revenue increased authorized

29.3

29.8

Deferred annual revenue increase

$ 7.7

[1]	Amortized over the life of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.
[2]	Represents the funded status of the pension plans more than offset by related liabilities. Also includes pension settlements amortized over various periods and financial and regulatory accounting method differences not included in rate base that will be eliminated over the life of the pension plans.
[3]	$11.3 million not included in rate base and amortized over various periods.
[4]	Not included in rate base and amortized over various periods.
[5]	$2.5 million not included in rate base and amortized through 2017.
[6]	Not included in rate base and amortized through 2016.
[7]	Certain insignificant items are not included in rate base and amortized over various periods.
[8]	Estimated cumulative net provision for future removal costs.
[9]	Not included in rate base and amortized through 2015.
[10]	Not included in rate base and amortized through 2012.
[11]	Represents the fair value of derivative instruments for commodity contracts. Settlements of the contracts are recognized in fuel expense and included in GMO's fuel adjustment clause (FAC).

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

EQUITY COMPENSATION (Details) (USD $)
In Millions, except Share data, unless otherwise specified

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2010

Sep. 30, 2011

Sep. 30, 2010

Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]

Compensation expense

$ 1.2

$ 0.8

$ 4.5

$ 3.4

Income tax benefits

0.4

0.2

1.8

0.8

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]

Expected volatility, minimum (in hundredths)

28.00%

Expected volatility, maximum (in hundredths)

30.00%

Expected dividend yields, minimum (in hundredths)

3.98%

Expected dividend yields, maximum (in hundredths)

4.35%

Risk-free interest rates, minimum (in hundredths)

0.61%

Risk-free interest rates, maximum (in hundredths)

1.15%

Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]

Balance at beginning of period (in number of shares)

431,784

Granted and issued (in number of shares)

140,128

Earned (in number of shares)

(68,258)

Forfeited (in number of shares)

(61,612)

Balance at end of period (in number of shares)

442,042

Weighted-average grant date fair value per share price, beginning of period (in dollars per shares)

$ 18.01

^[1]

Granted and issued (in dollars per shares)

$ 26.30

$ 0.00

$ 26.15

^[1]

$ 23.37

Earned (in dollars per shares)

$ 11.04

^[1]

Forfeited (in dollars per shares)

$ 22.38

^[1]

$ 22.38

^[1]

Weighted-average grant date fair value per share price, end of period (in dollars per shares)

$ 21.06

^[1]

$ 21.06

^[1]

Remaining weighted-average contractual term (in years)

1.2

Total unrecognized compensation expense, net of forfeiture rates

4.0

Total fair value of shares vested

0.8

Restricted Stock [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]

Balance at beginning of period (in number of shares)

406,657

Granted and issued (in number of shares)

182,385

Vested (in number of shares)

(149,688)

Forfeited (in number of shares)

(53,171)

Balance at end of period (in number of shares)

386,183

Weighted-average grant date fair value per share price, beginning of period (in dollars per shares)

$ 16.23

^[1]

Granted and issued (in dollars per shares)

$ 17.89

$ 18.32

$ 19.03

^[1]

$ 17.80

Vested (in dollars per shares)

$ 17.29

^[1]

Forfeited (in dollars per shares)

$ 17.25

^[1]

$ 17.25

^[1]

Weighted-average grant date fair value per share price, end of period (in dollars per shares)

$ 17.06

^[1]

$ 17.06

^[1]

Remaining weighted-average contractual term (in years)

1.6

Total unrecognized compensation expense, net of forfeiture rates

3.4

Total fair value of shares vested

0.9

2.6

7.3

Kansas City Power and Light Company [Member]

Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]

Compensation expense

0.8

0.6

3.1

2.4

Income tax benefits

$ 0.2

$ 1.2

$ 0.4

[1]	weighted-average

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

LONG-TERM DEBT (Details) (USD $)

9 Months Ended

Sep. 30, 2011

Dec. 31, 2010

Long-term debt excluding current maturities

Current maturities

$ (951,400,000)

$ (485,700,000)

2,750,100,000

2,942,700,000

Fair value value of long-term debt, including current maturities

4,100,000,000

3,700,000,000

Kansas City Power and Light Company [Member]

Long-term debt excluding current maturities

Current maturities

(162,700,000)

(150,300,000)

Unamortized discount

(4,300,000)

(2,000,000)

1,901,800,000

1,629,700,000

Fair value value of long-term debt, including current maturities

2,300,000,000

1,900,000,000

Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds EIRR due 2012-2035 [Member]

Debt Instrument Maturity Date Range Start

2012

Debt Instrument Maturity Date Range End

2035

Weighted-average interest rate (in hundredths)

119,300,000

^[1]

158,800,000

^[1]

4.87%

^[2]

Bonds purchased in lieu of redemption

39,500,000

Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds Series 2009 due 2019 [Member]

400,000,000

7.15%

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

2019

8.59%

^[3]

Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds EIRR series 2005 due 2035 [Member]

50,000,000

4.65%

2035

Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds Series 2007A-1 due 2035 [Member]

^[4]

63,300,000

Bonds purchased in lieu of redemption

2035

63,300,000

Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds EIRR series 2007A-2 due 2035 [Member]

^[4]

10,000,000

Bonds purchased in lieu of redemption

2035

10,000,000

Kansas City Power and Light Company [Member] | General Mortgage Bonds [Member] | General Mortgage bonds EIRR series 2007B due 2035 [Member]

73,200,000

5.375%

2035

Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior notes due 2011 KCPL [Member]

150,000,000

6.50%

2011

Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior notes due 2017 KCPL [Member]

250,000,000

5.85%

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

2017

5.72%

^[3]

Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior notes due 2018 KCPL [Member]

350,000,000

6.375%

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

2018

7.49%

^[3]

Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior notes due 2035 KCPL [Member]

250,000,000

6.05%

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

2035

5.78%

^[3]

Kansas City Power and Light Company [Member] | Senior Notes [Member] | Senior Notes Due 2041 KCPL [Member]

400,000,000

5.30%

2041

Kansas City Power and Light Company [Member] | Environmental Improvement Revenue Refunding Bonds [Member] | EIRR bonds due 2038 [Member]

23,400,000

4.90%

2038

Kansas City Power and Light Company [Member] | Other Long-Term Debt [Member] | Other due 2012-2018 [Member]

Debt Instrument Maturity Date Range Start

2012

Debt Instrument Maturity Date Range End

2018

2,900,000

3,300,000

Other Great Plains Energy [Member]

Current maturities

(788,700,000)

(335,400,000)

Unamortized discount

(700,000)

(500,000)

Other Great Plains Energy [Member] | GMO First Mortgage Bonds [Member] | First mortgage bonds due 2012-2021 [Member]

Debt Instrument Maturity Date Range Start

2012

Debt Instrument Maturity Date Range End

2021

11,200,000

12,400,000

9.44%

Other Great Plains Energy [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds SJLP due 2013 [Member]

5,600,000

5.85%

2013

Other Great Plains Energy [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds Wamego Series 1996 due 2026 [Member]

7,300,000

Variable rate (in hundredths)

2026

0.214%

^[5]

Other Great Plains Energy [Member] | GMO Pollution Control Bonds [Member] | Pollution control bonds state environmental 1993 due 2028 [Member]

5,000,000

Variable rate (in hundredths)

2028

0.263%

^[5]

Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Senior notes 7.95 percent series due 2011 [Member]

137,300,000

7.95%

Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Senior notes 7.75 percent series due 2011 [Member]

197,000,000

7.75%

Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Senior notes 11.875 percent series due 2012 [Member]

500,000,000

11.875%

2012

Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Senior notes 8.27 percent series due 2021 [Member]

80,900,000

8.27%

2021

Other Great Plains Energy [Member] | GMO Senior Notes [Member] | Fair value adjustment [Member]

24,200,000

49,900,000

Other Great Plains Energy [Member] | Great Plains Energy Senior Notes [Member] | Senior notes due 2013 [Member]

250,000,000

2.75%

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

2013

3.67%

^[3]

Other Great Plains Energy [Member] | Great Plains Energy Senior Notes [Member] | Senior notes due 2017 [Member]

100,000,000

6.875%

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

2017

7.33%

^[3]

Other Great Plains Energy [Member] | Great Plains Energy Senior Notes [Member] | Senior Notes Due2021 Member [Member]

350,000,000

4.85%

Rate after amortizing gains or losses in Other Comprehensive Income (in hundredths)

2021

7.34%

^[3]

Other Great Plains Energy [Member] | GMO Medium Term Notes [Member] | Medium term notes notes 7.16 percent series due 2013 [Member]

6,000,000

7.16%

2013

Other Great Plains Energy [Member] | GMO Medium Term Notes [Member] | Medium term notes notes 7.33 percent series due 2023 [Member]

3,000,000

7.33%

2023

Other Great Plains Energy [Member] | GMO Medium Term Notes [Member] | Medium term notes notes 7.17 percent series due 2023 [Member]

7,000,000

7.17%

2023

Other Great Plains Energy [Member] | Great Plains Energy Equity Units Subordinated Notes [Member] | Equity Units subordinated notes due 2042 [Member]

$ 287,500,000

10.00%