Great Plains Energy 10Q 2006 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2006

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

EXCHANGE ACT OF 1934

For the transition period from _______ to _______

	Exact name of registrant as specified in its charter,
Commission	state of incorporation, address of principal	I.R.S. Employer
File Number	executive offices and telephone number	Identification Number

001-32206	GREAT PLAINS ENERGY INCORPORATED	43-1916803
	(A Missouri Corporation)
	1201 Walnut Street
	Kansas City, Missouri 64106
	(816) 556-2200
	www.greatplainsenergy.com

000-51873	KANSAS CITY POWER & LIGHT COMPANY	44-0308720
	(A Missouri Corporation)
	1201 Walnut Street
	Kansas City, Missouri 64106
	(816) 556-2200
	www.kcpl.com

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

Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to

file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Great Plains Energy Incorporated

Yes

Kansas City Power & Light Company

Yes

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

definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Great Plains Energy Incorporated

Large accelerated filer

Accelerated filer

Non-accelerated filer

Kansas City Power & Light Company

Large accelerated filer

Accelerated filer

Non-accelerated filer

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

Great Plains Energy Incorporated

Yes

Kansas City Power & Light Company

Yes

On November 1, 2006, Great Plains Energy Incorporated had 80,303,446 shares of common stock outstanding.

On November 1, 2006, Kansas City Power & Light Company had one share of common stock outstanding, which was held by

Great Plains Energy Incorporated.

Great Plains Energy Incorporated and Kansas City Power & Light Company (KCP&L) separately file this combined Quarterly Report on Form 10-Q. Information contained herein relating to an individual registrant and its subsidiaries is filed by such registrant on its own behalf. Each registrant makes representations only as to information relating to itself and its subsidiaries.

In March 2006, KCP&L filed a registration statement to register its common stock under Section 12(g) of the Securities Exchange Act of 1934, as amended (Exchange Act). This registration statement became effective in April 2006 and KCP&L is now required to file reports, including quarterly reports on Form 10-Q, under Section 13(a) of the Exchange Act.

This report should be read in its entirety. No one section of the report deals with all aspects of the subject matter. It should be read in conjunction with the consolidated financial statements and related notes and with the management’s discussion and analysis included in the companies’ 2005 Form 10-K.

CAUTIONARY STATEMENTS REGARDING CERTAIN FORWARD-LOOKING INFORMATION

Statements made in this report that are not based on historical facts are forward-looking, may involve risks and uncertainties, and are intended to be as of the date when made. Forward-looking statements include, but are not limited to, statements regarding projected delivered volumes and margins, the outcome of regulatory proceedings, cost estimates of the comprehensive energy plan and other matters affecting future operations. In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, the registrants are providing a number of important factors that could cause actual results to differ materially from the provided forward-looking information. These important factors include: future economic conditions in the regional, national and international markets, including but not limited to regional and national wholesale electricity markets; market perception of the energy industry and Great Plains Energy; changes in business strategy, operations or development plans; effects of current or proposed state and federal legislative and regulatory actions or developments, including, but not limited to, deregulation, re-regulation and restructuring of the electric utility industry; decisions of regulators regarding rates KCP&L can charge for electricity; adverse changes in applicable laws, regulations, rules, principles or practices governing tax, accounting and environmental matters including, but not limited to, air and water quality; financial market conditions and performance including, but not limited to, changes in interest rates and in availability and cost of capital and the effects on pension plan assets and costs; credit ratings; inflation rates; effectiveness of risk management policies and procedures and the ability of counterparties to satisfy their contractual commitments; impact of terrorist acts; increased competition including, but not limited to, retail choice in the electric utility industry and the entry of new competitors; ability to carry out marketing and sales plans; weather conditions including weather-related damage; cost, availability, quality and deliverability of fuel; ability to achieve generation planning goals and the occurrence and duration of unplanned generation outages; delays in the anticipated in-service dates and cost increases of additional generating capacity; nuclear operations; ability to enter new markets successfully and capitalize on growth opportunities in non-regulated businesses and the effects of competition; application of critical accounting policies, including, but not limited to, those related to derivatives and pension liabilities; workforce risks including compensation and benefits costs; performance of projects undertaken by non-regulated businesses and the success of efforts to invest in and develop new opportunities and other risks and uncertainties.

This list of factors is not all-inclusive because it is not possible to predict all factors. Part II Item 1A. Risk Factors included in this report together with the risk factors included in the companies’ 2005 Form 10-K under Part I Item 1A, should be carefully read for further understanding of potential risks to the companies. Other sections of this report and other periodic reports filed by the companies with the Securities and Exchange Commission (SEC) should also be read for more information regarding risk factors.

GLOSSARY OF TERMS

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

Abbreviation or Acronym		Definition

BART		Best available retrofit technology
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CO₂		Carbon Dioxide
Company		Great Plains Energy Incorporated and its subsidiaries
Consolidated KCP&L		KCP&L and its wholly owned subsidiaries
DOE		Department of Energy
DTI		DTI Holdings, Inc. and its subsidiaries, Digital Teleport, Inc. and Digital Teleport of Virginia, Inc.
EBITDA		Earnings before interest, income taxes, depreciation and amortization
EEI		Edison Electric Institute
EIRR		Environmental Improvement Revenue Refunding
EPA		Environmental Protection Agency
EPS		Earnings per common share
FASB		Financial Accounting Standards Board
FELINE PRIDES^SM		Flexible Equity Linked Preferred Increased Dividend Equity Securities,
		a service mark of Merrill Lynch & Co., Inc.
FERC		The Federal Energy Regulatory Commission
FIN		Financial Accounting Standards Board Interpretation
FSS		Forward Starting Swaps
GAAP		Generally Accepted Accounting Principles
Great Plains Energy		Great Plains Energy Incorporated and its subsidiaries
HSS		Home Service Solutions Inc., a wholly owned subsidiary of KCP&L
IEC		Innovative Energy Consultants Inc., a wholly owned subsidiary of Great Plains Energy
ISO		Independent System Operator
KCC		The State Corporation Commission of the State of Kansas
KCP&L		Kansas City Power & Light Company, a wholly owned subsidiary of Great Plains Energy
KLT Gas		KLT Gas Inc., a wholly owned subsidiary of KLT Inc.
KLT Inc.		KLT Inc., a wholly owned subsidiary of Great Plains Energy
KLT Investments		KLT Investments Inc., a wholly owned subsidiary of KLT Inc.
KLT Telecom		KLT Telecom Inc., a wholly owned subsidiary of KLT Inc.
KW		Kilowatt
kWh		Kilowatt hour
MAC		Material Adverse Change
MD&A		Management’s Discussion and Analysis of Financial Condition and
		Results of Operations
MISO		Midwest Independent Transmission System Operator, Inc.
MPSC		Public Service Commission of the State of Missouri
MW		Megawatt

Abbreviation or Acronym		Definition

MWh		Megawatt hour
NEIL		Nuclear Electric Insurance Limited
NO_x		Nitrogen Oxide
NPNS		Normal Purchases and Normal Sales
NRC		Nuclear Regulatory Commission
OCI		Other Comprehensive Income
PJM		PJM Interconnection
PRB		Powder River Basin
Receivables Company		Kansas City Power & Light Receivables Company, a wholly owned subsidiary of KCP&L
RTO		Regional Transmission Organization
SEC		Securities and Exchange Commission
SECA		Seams Elimination Charge Adjustment
SE Holdings		SE Holdings, L.L.C.
Services		Great Plains Energy Services Incorporated
SFAS		Statement of Financial Accounting Standards
SIP		State Implementation Plan
SO₂		Sulfur Dioxide
SPP		Southwest Power Pool, Inc.
STB		Surface Transportation Board
Strategic Energy		Strategic Energy, L.L.C., a subsidiary of KLT Energy Services
T - Locks		Treasury Locks
Union Pacific		Union Pacific Railroad Company
WCNOC		Wolf Creek Nuclear Operating Corporation
Wolf Creek		Wolf Creek Generating Station
Worry Free		Worry Free Service, Inc., a wholly owned subsidiary of HSS

PART I - FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS



GREAT PLAINS ENERGY
Consolidated Balance Sheets
(Unaudited)

	September 30		December 31
	2006		2005
ASSETS	(thousands)
Current Assets
Cash and cash equivalents	$	59,259	$	103,068
Restricted cash		-		1,900
Receivables, net		355,508		259,043
Fuel inventories, at average cost		25,269		17,073
Materials and supplies, at average cost		59,414		57,017
Deferred income taxes		46,329		-
Assets of discontinued operations		-		627
Derivative instruments		5,485		39,189
Other		14,189		13,001
Total		565,453		490,918
Nonutility Property and Investments
Affordable housing limited partnerships		24,475		28,214
Nuclear decommissioning trust fund		98,975		91,802
Other		14,718		17,291
Total		138,168		137,307
Utility Plant, at Original Cost
Electric		5,224,095		4,959,539
Less-accumulated depreciation		2,423,708		2,322,813
Net utility plant in service		2,800,387		2,636,726
Construction work in progress		160,058		100,952
Nuclear fuel, net of amortization of $127,029 and $115,240		37,703		27,966
Total		2,998,148		2,765,644
Deferred Charges and Other Assets
Regulatory assets		207,453		179,922
Prepaid pension costs		70,806		98,295
Goodwill		88,139		87,624
Derivative instruments		2,507		21,812
Other		43,973		52,204
Total		412,878		439,857
Total	$	4,114,647	$	3,833,726

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY
Consolidated Balance Sheets
(Unaudited)

	September 30			December 31
	2006			2005
LIABILITIES AND CAPITALIZATION	(thousands)
Current Liabilities
Notes payable	$	-		$	6,000
Commercial paper		80,600			31,900
Current maturities of long-term debt		389,902			1,675
Accounts payable		260,663			231,496
Accrued taxes		97,403			37,140
Accrued interest		13,515			13,329
Accrued payroll and vacations		32,356			36,024
Accrued refueling outage costs		15,707			8,974
Deferred income taxes		-			1,351
Supplier collateral		-			1,900
Liabilities of discontinued operations		-			64
Derivative instruments		81,641			7,411
Other		24,459			25,658
Total		996,246			402,922
Deferred Credits and Other Liabilities
Deferred income taxes		582,904			621,359
Deferred investment tax credits		27,413			29,698
Asset retirement obligations		91,072			145,907
Pension liability		89,812			87,355
Regulatory liabilities		107,500			69,641
Derivative instruments		72,318			7,750
Other		63,846			65,787
Total		1,034,865			1,027,497
Capitalization
Common shareholders' equity
Common stock-150,000,000 shares authorized without par value
80,341,419 and 74,783,824 shares issued, stated value		893,850			744,457
Retained earnings		479,609			488,001
Treasury stock-45,680 and 43,376 shares, at cost		(1,367	)		(1,304	)
Accumulated other comprehensive loss		(79,863	)		(7,727	)
Total		1,292,229			1,223,427
Cumulative preferred stock $100 par value
3.80% - 100,000 shares issued		10,000			10,000
4.50% - 100,000 shares issued		10,000			10,000
4.20% - 70,000 shares issued		7,000			7,000
4.35% - 120,000 shares issued		12,000			12,000
Total		39,000			39,000
Long-term debt (Note 8)		752,307			1,140,880
Total		2,083,536			2,403,307
Commitments and Contingencies (Note 14)
Total	$	4,114,647		$	3,833,726

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY
Consolidated Statements of Income
(Unaudited)

	Three Months Ended						Year to Date
	September 30						September 30
	2006			2005			2006			2005
Operating Revenues		(thousands, except per share amounts)
Electric revenues - KCP&L	$	359,270		$	352,974		$	890,551		$	858,272
Electric revenues - Strategic Energy		458,538			429,407			1,127,056			1,099,895
Other revenues		730			446			2,220			1,495
Total		818,538			782,827			2,019,827			1,959,662
Operating Expenses
Fuel		77,154			73,935			180,751			160,228
Purchased power - KCP&L		5,157			28,303			18,844			56,590
Purchased power - Strategic Energy		462,299			386,499			1,117,404			1,003,201
Skill set realignment costs (Note 9)		1,389			-			15,905			-
Other		88,145			76,358			244,030			240,628
Maintenance		19,746			19,230			67,235			69,140
Depreciation and amortization		40,422			38,382			118,618			114,485
General taxes		31,826			31,197			87,234			83,619
(Gain) loss on property		28			3,419			(569	)		1,906
Total		726,166			657,323			1,849,452			1,729,797
Operating income		92,372			125,504			170,375			229,865
Non-operating income		9,852			3,563			16,741			15,334
Non-operating expenses		(2,141	)		(4,699	)		(5,593	)		(15,671	)
Interest charges		(17,974	)		(17,904	)		(53,113	)		(53,777	)
Income from continuing operations before income taxes,
minority interest in subsidiaries and loss from equity
investments		82,109			106,464			128,410			175,751
Income taxes		(26,482	)		(17,300	)		(36,683	)		(32,396	)
Minority interest in subsidiaries		-			-			-			(7,805	)
Loss from equity investments, net of income taxes		(468	)		(69	)		(1,047	)		(758	)
Income from continuing operations		55,159			89,095			90,680			134,792
Discontinued operations, net of income taxes (Note 12)		-			1,780			-			(1,826	)
Net income		55,159			90,875			90,680			132,966
Preferred stock dividend requirements		411			412			1,234			1,235
Earnings available for common shareholders	$	54,748		$	90,463		$	89,446		$	131,731

Average number of common shares outstanding		80,081			74,653			77,266			74,561

Basic and diluted earnings (loss) per common share
Continuing operations	$	0.68		$	1.19		$	1.16		$	1.79
Discontinued operations		-			0.02			-			(0.02	)
Basic and diluted earnings per common share	$	0.68		$	1.21		$	1.16		$	1.77

Cash dividends per common share	$	0.415		$	0.415		$	1.245		$	1.245

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY
Consolidated Statements of Cash Flows
(Unaudited)
				Revised
Year to Date September 30	2006			2005
Cash Flows from Operating Activities		(thousands)
Net income	$	90,680		$	132,966
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		118,618			114,485
Amortization of:
Nuclear fuel		11,789			9,396
Other		6,965			8,035
Deferred income taxes, net		(32,930	)		(15,736	)
Investment tax credit amortization		(2,285	)		(2,917	)
Loss from equity investments, net of income taxes		1,047			758
(Gain) loss on property		(569	)		1,658
Minority interest in subsidiaries		-			7,805
Fair value impacts from energy contracts		64,507			(26,032	)
Other operating activities (Note 4)		(18,829	)		59,867
Net cash from operating activities		238,993			290,285
Cash Flows from Investing Activities
Utility capital expenditures		(371,056	)		(260,589	)
Allowance for borrowed funds used during construction		(4,060	)		(1,174	)
Purchases of investments		(700	)		(14,976	)
Purchases of nonutility property		(3,518	)		(4,822	)
Proceeds from sale of assets and investments		319			17,123
Purchases of nuclear decommissioning trust investments		(37,333	)		(22,811	)
Proceeds from nuclear decommissioning trust investments		34,596			20,147
Hawthorn No. 5 partial insurance recovery		-			10,000
Hawthorn No. 5 partial litigation recoveries		15,829			-
Other investing activities		(852	)		(679	)
Net cash from investing activities		(366,775	)		(257,781	)
Cash Flows from Financing Activities
Issuance of common stock		151,624			7,462
Issuance fees		(6,144	)		(2,031	)
Issuance of long-term debt		-			85,922
Repayment of long-term debt		(872	)		(88,417	)
Net change in short-term borrowings		42,700			(6,400	)
Dividends paid		(98,913	)		(94,071	)
Other financing activities		(4,422	)		(4,244	)
Net cash from financing activities		83,973			(101,779	)
Net Change in Cash and Cash Equivalents		(43,809	)		(69,275	)
Less: Net Change in Cash and Cash Equivalents from
Discontinued Operations		-			(560	)
Cash and Cash Equivalents at Beginning of Year		103,068			127,129
Cash and Cash Equivalents at End of Period	$	59,259		$	58,414

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY
Consolidated Statements of Common Shareholders' Equity
(Unaudited)

Year to Date September 30	2006						2005
		Shares			Amount			Shares			Amount
Common Stock		(thousands, except share amounts)
Beginning balance		74,783,824		$	744,457			74,394,423		$	731,977
Issuance of common stock		5,510,769			151,624			257,222			7,745
Issuance of restricted common stock		46,826			1,320			76,375			2,334
Common stock issuance fees					(5,194	)					-
Equity compensation expense					1,929						1,360
Unearned Compensation
Issuance of restricted common stock					(1,355	)					(2,334	)
Forfeiture of restricted common stock					56						188
Compensation expense recognized					982						1,143
Other					31						(99	)
Ending balance		80,341,419			893,850			74,728,020			742,314
Retained Earnings
Beginning balance					488,001						451,491
Net income					90,680						132,966
Dividends:
Common stock					(97,631	)					(92,836	)
Preferred stock - at required rates					(1,234	)					(1,235	)
Performance shares					(207	)					-
Ending balance					479,609						490,386
Treasury Stock
Beginning balance		(43,376	)		(1,304	)		(28,488	)		(856	)
Treasury shares acquired		(3,519	)		(99	)		(6,380	)		(193	)
Treasury shares reissued		1,215			36			-			-
Ending balance		(45,680	)		(1,367	)		(34,868	)		(1,049	)
Accumulated Other Comprehensive Income (Loss)
Beginning balance					(7,727	)					(41,018	)
Derivative hedging activity, net of tax					(72,136	)					41,996
Minimum pension obligation, net of tax					-						(585	)
Ending balance					(79,863	)					393
Total Common Shareholders' Equity				$	1,292,229					$	1,232,044

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY
Consolidated Statements of Comprehensive Income
(Unaudited)

	Three Months Ended						Year to Date
	September 30						September 30
	2006			2005			2006			2005
	(thousands)
Net income	$	55,159		$	90,875		$	90,680		$	132,966
Other comprehensive income
Gain (loss) on derivative hedging instruments		(75,050	)		80,317			(152,214	)		99,540
Income taxes		30,631			(33,097	)		62,966			(41,468	)
Net gain on derivative hedging instruments		(44,419	)		47,220			(89,248	)		58,072
Reclassification to expenses, net of tax		7,576			(12,571	)		17,112			(16,076	)
Derivative hedging activity, net of tax		(36,843	)		34,649			(72,136	)		41,996
Change in minimum pension obligation		-			-			-			(60	)
Income taxes		-			(548	)		-			(525	)
Net change in minimum pension obligation		-			(548	)		-			(585	)
Comprehensive income	$	18,316		$	124,976		$	18,544		$	174,377

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
(Unaudited)

	September 30		December 31
	2006		2005
ASSETS		(thousands)
Current Assets
Cash and cash equivalents	$	400	$	2,961
Receivables, net		122,293		70,264
Fuel inventories, at average cost		25,269		17,073
Materials and supplies, at average cost		59,414		57,017
Deferred income taxes		11,282		8,944
Prepaid expenses		8,072		11,292
Total		226,730		167,551
Nonutility Property and Investments
Nuclear decommissioning trust fund		98,975		91,802
Other		5,351		7,694
Total		104,326		99,496
Utility Plant, at Original Cost
Electric		5,224,095		4,959,539
Less-accumulated depreciation		2,423,708		2,322,813
Net utility plant in service		2,800,387		2,636,726
Construction work in progress		160,058		100,952
Nuclear fuel, net of amortization of $127,029 and $115,240		37,703		27,966
Total		2,998,148		2,765,644
Deferred Charges and Other Assets
Regulatory assets		207,453		179,922
Prepaid pension costs		70,806		98,002
Other		29,752		27,905
Total		308,011		305,829
Total	$	3,637,215	$	3,338,520

The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
(Unaudited)

	September 30			December 31
	2006			2005
LIABILITIES AND CAPITALIZATION	(thousands)
Current Liabilities
Notes payable to Great Plains Energy	$	550		$	500
Commercial paper		80,600			31,900
Current maturities of long-term debt		225,500			-
Accounts payable		119,616			106,040
Accrued taxes		99,342			27,448
Accrued interest		11,783			11,549
Accrued payroll and vacations		25,158			27,520
Accrued refueling outage costs		15,707			8,974
Derivative instruments		812			-
Other		8,694			8,600
Total		587,762			222,531
Deferred Credits and Other Liabilities
Deferred income taxes		623,531			627,048
Deferred investment tax credits		27,413			29,698
Asset retirement obligations		91,072			145,907
Pension liability		85,848			85,301
Regulatory liabilities		107,500			69,641
Derivative instruments		2,196			2,601
Other		42,981			38,387
Total		980,541			998,583
Capitalization
Common shareholder's equity
Common stock-1,000 shares authorized without par value
1 share issued, stated value		1,021,656			887,041
Retained earnings		326,408			283,850
Accumulated other comprehensive loss		(30,602	)		(29,909	)
Total		1,317,462			1,140,982
Long-term debt (Note 8)		751,450			976,424
Total		2,068,912			2,117,406
Commitments and Contingencies (Note 14)
Total	$	3,637,215		$	3,338,520

The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Income
(Unaudited)

	Three Months Ended						Year to Date
	September 30						September 30
	2006			2005			2006			2005
Operating Revenues		(thousands)
Electric revenues	$	359,270		$	352,974		$	890,551		$	858,272
Other revenues		-			-			-			113
Total		359,270			352,974			890,551			858,385
Operating Expenses
Fuel		77,154			73,935			180,751			160,228
Purchased power		5,157			28,303			18,844			56,590
Skill set realignment costs (Note 9)		1,330			-			15,560			-
Other		69,326			60,912			196,692			195,738
Maintenance		19,745			19,225			67,223			69,111
Depreciation and amortization		38,451			36,776			112,797			109,836
General taxes		30,894			30,091			84,058			80,100
(Gain) loss on property		26			3,602			(572	)		3,089
Total		242,083			252,844			675,353			674,692
Operating income		117,187			100,130			215,198			183,693
Non-operating income		8,586			2,822			13,121			13,665
Non-operating expenses		(2,049	)		(2,477	)		(4,341	)		(4,257	)
Interest charges		(15,569	)		(15,015	)		(45,473	)		(45,116	)
Income before income taxes and minority
interest in subsidiaries		108,155			85,460			178,505			147,985
Income taxes		(39,393	)		(16,512	)		(61,946	)		(31,943	)
Minority interest in subsidiaries		-			-			-			(7,805	)
Net income	$	68,762		$	68,948		$	116,559		$	108,237

The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Cash Flows
(Unaudited)

Year to Date September 30	2006			2005
Cash Flows from Operating Activities	(thousands)
Net income	$	116,559		$	108,237
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		112,797			109,836
Amortization of:
Nuclear fuel		11,789			9,396
Other		4,955			5,850
Deferred income taxes, net		(3,089	)		(32,575	)
Investment tax credit amortization		(2,285	)		(2,917	)
(Gain) loss on property		(572	)		3,089
Minority interest in subsidiaries		-			7,805
Other operating activities (Note 4)		11,015			81,378
Net cash from operating activities		251,169			290,099
Cash Flows from Investing Activities
Utility capital expenditures		(371,056	)		(265,361	)
Allowance for borrowed funds used during construction		(4,060	)		(1,174	)
Purchases of nonutility property		(51	)		(113	)
Proceeds from sale of assets		319			224
Purchases of nuclear decommissioning trust investments		(37,333	)		(22,811	)
Proceeds from nuclear decommissioning trust investments		34,596			20,147
Hawthorn No. 5 partial insurance recovery		-			10,000
Hawthorn No. 5 partial litigation recoveries		15,829			-
Other investing activities		(852	)		(679	)
Net cash from investing activities		(362,608	)		(259,767	)
Cash Flows from Financing Activities
Issuance of long-term debt		-			85,922
Repayment of long-term debt		-			(85,922	)
Net change in short-term borrowings		48,750			13,576
Dividends paid to Great Plains Energy		(74,001	)		(92,700	)
Equity contribution from Great Plains Energy		134,615			-
Issuance fees		(486	)		(2,031	)
Net cash from financing activities		108,878			(81,155	)
Net Change in Cash and Cash Equivalents		(2,561	)		(50,823	)
Cash and Cash Equivalents at Beginning of Year		2,961			51,619
Cash and Cash Equivalents at End of Period	$	400		$	796

The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Common Shareholder's Equity
(Unaudited)

Year to Date September 30	2006					2005
		Shares		Amount			Shares		Amount
Common Stock	(thousands, except share amounts)
Beginning balance		1	$	887,041			1	$	887,041
Equity contribution from Great Plains Energy		-		134,615			-		-
Ending balance		1		1,021,656			1		887,041
Retained Earnings
Beginning balance				283,850					252,893
Net income				116,559					108,237
Dividends:
Common stock held by Great Plains Energy				(74,001	)				(92,700	)
Ending balance				326,408					268,430
Accumulated Other Comprehensive Loss
Beginning balance				(29,909	)				(40,334	)
Derivative hedging activity, net of tax				(693	)				4,015
Minimum pension obligation, net of tax				-					(2,538	)
Ending balance				(30,602	)				(38,857	)
Total Common Shareholder's Equity			$	1,317,462				$	1,116,614

The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Comprehensive Income
(Unaudited)

	Three Months Ended						Year to Date
	September 30						September 30
	2006			2005			2006			2005
	(thousands)
Net income	$	68,762		$	68,948		$	116,559		$	108,237
Other comprehensive income
Gain (loss) on derivative hedging instruments		(6,105	)		9,193			(812	)		6,902
Income taxes		2,295			(3,478	)		305			(2,598	)
Net gain on derivative hedging instruments		(3,810	)		5,715			(507	)		4,304
Reclassification to expenses, net of tax		(61	)		(286	)		(186	)		(289	)
Derivative hedging activity, net of tax		(3,871	)		5,429			(693	)		4,015
Change in minimum pension obligation		-			(3,170	)		-			(3,230	)
Income taxes		-			669			-			692
Net change in minimum pension obligation		-			(2,501	)		-			(2,538	)
Comprehensive income	$	64,891		$	71,876		$	115,866		$	109,714

The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED

KANSAS CITY POWER & LIGHT COMPANY

Notes to Unaudited Consolidated Financial Statements

The notes to unaudited consolidated financial statements that follow are a combined presentation for Great Plains Energy Incorporated and Kansas City Power & Light Company, both registrants under this filing. The terms “Great Plains Energy,” “Company,” “KCP&L” and “consolidated KCP&L” are used throughout this report. “Great Plains Energy” and the “Company” refer to Great Plains Energy Incorporated and its consolidated subsidiaries, unless otherwise indicated. “KCP&L” refers to Kansas City Power & Light Company, and “consolidated KCP&L” refers to KCP&L and its consolidated subsidiaries.

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

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

KCP&L is an integrated, regulated electric utility that provides electricity to customers primarily in the states of Missouri and Kansas. KCP&L has two wholly owned subsidiaries, Kansas City Power & Light Receivables Company (Receivables Company) and Home Service Solutions Inc. (HSS). HSS has no active operations.

KLT Inc. is an intermediate holding company that primarily holds indirect interests in Strategic Energy, L.L.C. (Strategic Energy), which provides competitive retail electricity supply services in several electricity markets offering retail choice, and investments in affordable housing limited partnerships. KLT Inc. also wholly owns KLT Gas Inc. (KLT Gas), which has no active operations in 2006.

Innovative Energy Consultants Inc. (IEC) is an intermediate holding company that holds an indirect interest in Strategic Energy. IEC does not own or operate any assets other than its indirect interest in Strategic Energy. When combined with KLT Inc.’s indirect interest in Strategic Energy, the Company indirectly owns 100% of Strategic Energy.

·	Great Plains Energy Services Incorporated (Services) provides services at cost to Great Plains Energy and its subsidiaries, including consolidated KCP&L.

The operations of Great Plains Energy and its subsidiaries are divided into two reportable segments, KCP&L and Strategic Energy. Great Plains Energy’s legal structure differs from the functional management and financial reporting of its reportable segments. Other activities not considered a reportable segment include HSS, Services, all KLT Inc. activity other than Strategic Energy, and holding company operations.

2.	BASIC AND DILUTED EARNINGS PER COMMON SHARE CALCULATION

There was no significant dilutive effect on Great Plains Energy’s EPS from other securities for the three months ended and year to date September 30, 2006 and 2005. To determine basic EPS, preferred stock dividend requirements are deducted from income from continuing operations and net income before dividing by the average number of common shares outstanding. The earnings (loss) per share impact of discontinued operations, net of income taxes, is determined by dividing discontinued operations, net of income taxes, by the average number of common shares outstanding. The effect of dilutive securities, calculated using the treasury stock method, assumes the issuance of common shares applicable to stock options, performance shares, restricted stock, a forward sale agreement and FELINE PRIDES^SM.

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


	Three Months Ended					Year to Date
		September 30				September 30
			2006		2005		2006		2005
Income			(millions, except per share amounts)
Income from continuing operations		$	55.2	$	89.1	$	90.7	$	134.8
Less: preferred stock dividend requirements			0.5		0.5		1.3		1.3
Income available to common shareholders		$	54.7	$	88.6	$	89.4	$	133.5
Common Shares Outstanding
Average number of common shares outstanding			80.1		74.7		77.3		74.6
Add: effect of dilutive securities			0.2		-		0.1		-
Diluted average number of common shares outstanding			80.3		74.7		77.4		74.6

Basic and diluted EPS from continuing operations		$	0.68	$	1.19	$	1.16	$	1.79

The computation of diluted EPS excludes anti-dilutive shares for the three months ended and year to date September 30, 2006, of 105,198 and 106,706 performance shares and 99,838 and 116,468 restricted stock shares, respectively. Additionally, for the three months ended and year to date September 30, 2006, 6.5 million of anti-dilutive FELINE PRIDES were excluded from the computation of diluted EPS and there were no anti-dilutive shares applicable to stock options or a forward sale agreement. For the three months ended and year to date September 30, 2005, there were no significant anti-dilutive shares applicable to stock options, performance shares, restricted stock or FELINE PRIDES.

In October 2006, the Board of Directors declared a quarterly dividend of $0.415 per share on Great Plains Energy’s common stock. The common dividend is payable December 20, 2006, to shareholders of record as of November 29, 2006. The Board of Directors also declared regular dividends on Great Plains Energy’s preferred stock, payable March 1, 2007, to shareholders of record as of February 7, 2007.

CASH

Cash and Cash Equivalents

Cash equivalents consist of highly liquid investments with maturities of three months or less at acquisition. For Great Plains Energy, this includes Strategic Energy’s cash held in trust of $11.2 million and $21.9 million at September 30, 2006 and December 31, 2005, respectively.

Strategic Energy has entered into collateral arrangements with selected electricity power suppliers that require selected customers to remit payment to lockboxes that are held in trust and managed by a Trustee. As part of the trust administration, the Trustee remits payment to the supplier of electricity purchased by Strategic Energy. On a monthly basis, any remittances into the lockboxes in excess of disbursements to the supplier are remitted back to Strategic Energy.

Restricted Cash

Strategic Energy has entered into Master Power Purchase and Sale Agreements with its power suppliers. Certain of these agreements contain provisions whereby, to the extent Strategic Energy has a net exposure to the purchased power supplier, collateral requirements are to be maintained. Collateral posted in the form of cash to Strategic Energy is restricted by agreement, but would become unrestricted in the event of a default by the purchased power supplier. Strategic Energy held no restricted cash collateral at September 30, 2006, and $1.9 million at December 31, 2005.

4. SUPPLEMENTAL CASH FLOW INFORMATION

*Great Plains Energy Other Operating Activities*
				Revised
Year to Date September 30	2006			2005
Cash flows affected by changes in:	(millions)
Receivables	$	(96.2	)	$	(43.9	)
Fuel inventories		(8.2	)		2.3
Materials and supplies		(2.4	)		(2.5	)
Accounts payable		6.9			12.3
Accrued taxes		60.6			51.1
Accrued interest		0.2			1.2
Deposits with suppliers		(4.4	)		0.1
Accrued refueling outage costs		6.7			(7.7	)
Pension and postretirement benefit assets and obligations		10.8			6.0
Allowance for equity funds used during construction		(3.7	)		(1.1	)
Proceeds from the sale of SO₂ emission allowances		0.8			31.0
Other		10.1			11.1
Total other operating activities	$	(18.8	)	$	59.9
Cash paid during the period:
Interest	$	50.9		$	54.3
Income taxes	$	39.9		$	24.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	34.7		$	4.1

*Consolidated KCP&L Other Operating Activities*
Year to Date September 30	2006			2005
Cash flows affected by changes in:	(millions)
Receivables	$	(52.1	)	$	(20.4	)
Fuel inventories		(8.2	)		2.3
Materials and supplies		(2.4	)		(2.5	)
Accounts payable		(9.2	)		(2.7	)
Accrued taxes		71.9			66.9
Accrued interest		0.2			1.2
Accrued refueling outage costs		6.7			(7.7	)
Pension and postretirement benefit assets and obligations		8.3			2.3
Allowance for equity funds used during construction		(3.7	)		(1.1	)
Proceeds from the sale of SO₂ emission allowances		0.8			31.0
Other		(1.3	)		12.1
Total other operating activities	$	11.0		$	81.4
Cash paid during the period:
Interest	$	43.6		$	42.1
Income taxes	$	29.1		$	32.4
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	34.4		$	3.5

Discontinued Operations and Proceeds From Sale of SO₂ Emission Allowances Presentation

In the fourth quarter of 2005, the Company changed the presentation of its consolidated statements of cash flows to include the cash flows from operating, investing and financing activities of discontinued operations within the respective categories of operating, investing and financing activities as well as to reflect proceeds from the sale of SO₂emission allowances by consolidated KCP&L as operating

activities rather than investing activities and retroactively revised the consolidated statement of cash flows year to date September 30, 2005, to be consistent with this presentation. Great Plains Energy’s net cash flows from operating activities year to date September 30, 2005, increased $30.2 million due to a $31.0 million increase for KCP&L’s proceeds from the sale of SO₂ emission allowances and a $0.8 million decrease for discontinued operations operating activities from amounts previously reported. Net cash flows from investing activities decreased $30.7 million due to a $31.0 million decrease for KCP&L’s proceeds from the sale of SO₂ emission allowances and a $0.3 million increase from discontinued operations from amounts previously reported.

Significant Non-Cash Items

In the third quarter of 2006, Wolf Creek Nuclear Operating Corporation (WCNOC) submitted an application to the Nuclear Regulatory Commission (NRC) for a new operating license for Wolf Creek Generating Station (Wolf Creek), which would extend Wolf Creek’s operating period to 2045. KCP&L recorded a $65.0 million decrease in the asset retirement obligation (ARO) to decommission Wolf Creek with a $25.8 million net decrease in property and equipment. The regulatory asset for ARO decreased $8.2 million and a $31.0 million regulatory liability was established to recognize current funding of the related decommissioning trust at September 30, 2006, in excess of the ARO due to the extended operating period. This activity had no impact to Great Plains Energy’s or consolidated KCP&L’s cash flows year to date September 30, 2006. See Note 17 for additional information.

5.	RECEIVABLES

The Company’s receivables are detailed in the following table.


	September 30			December 31
	2006			2005
Consolidated KCP&L	(millions)
Customer accounts receivable ^(a)	$	58.4		$	34.0
Allowance for doubtful accounts		(1.8	)		(1.0	)
Other receivables		65.7			37.3
Consolidated KCP&L receivables		122.3			70.3
Other Great Plains Energy
Other receivables		237.7			193.0
Allowance for doubtful accounts		(4.5	)		(4.3	)
Great Plains Energy receivables	$	355.5		$	259.0
^(a) Customer accounts receivable included unbilled receivables of $36.4 million
and $31.4 million at September 30, 2006 and December 31, 2005, respectively.

Consolidated KCP&L’s other receivables at September 30, 2006 and December 31, 2005, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables. Great Plains Energy’s other receivables at September 30, 2006 and December 31, 2005, consisted primarily of accounts receivable held by Strategic Energy, including unbilled receivables of $112.0 million and $99.9 million, respectively.

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. 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 2.5% of the outstanding principal amount of the receivables sold to Receivables Company. KCP&L does not recognize a servicing asset or liability because management determined the collection agent fee earned by KCP&L approximates market value.

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, 2006	KCP&L			Company		KCP&L
	(millions)
Receivables (sold) purchased	$	(325.5	)	$	325.5	$	-
Gain (loss) on sale of accounts receivable ^(a)		(3.3	)		3.3		-
Servicing fees		1.0			(1.0)		-
Fees to outside investor		-			(1.0)		(1.0	)
Cash flows during the period
Cash from customers transferred to
Receivables Company		(323.0	)		323.0		-
Cash paid to KCP&L for receivables purchased		323.6			(323.6)		-
Servicing fees		1.0			(1.0)		-
Interest on intercompany note		1.1			(1.1)		-


				Receivables		Consolidated
Year to Date September 30, 2006	KCP&L			Company		KCP&L
	(millions)
Receivables (sold) purchased	$	(774.8	)	$	774.8	$	-
Gain (loss) on sale of accounts receivable ^(a)		(7.8	)		7.6		(0.2	)
Servicing fees		2.2			(2.2)		-
Fees to outside investor		-			(2.8)		(2.8	)
Cash flows during the period
Cash from customers transferred to
Receivables Company		(754.0	)		754.0		-
Cash paid to KCP&L for receivables purchased		750.3			(750.3)		-
Servicing fees		2.2			(2.2)		-
Interest on intercompany note		1.9			(1.9)		-


Three Months Ended and				Receivables		Consolidated
Year to Date September 30, 2006	KCP&L			Company		KCP&L
	(millions)
Receivables (sold) purchased	$	(396.7	)	$	396.7	$	-
Gain (loss) on sale of accounts receivable ^(a)		(4.0	)		2.7		(1.3	)
Servicing fees		0.7			(0.7)		-
Fees to outside investor		-			(0.7)		(0.7	)
Cash flows during the period
Cash from customers transferred to
Receivables Company		(273.7	)		273.7		-
Cash paid to KCP&L for receivables purchased		(271.0	)		271.0		-
Servicing fees		0.7			(0.7)		-
Funds from outside investors ^(b)		70.0			-		70.0
Interest on intercompany note		0.6			(0.6)		-

^(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.
^(b)	During the third quarter of 2005, Receivables Company received $70 million cash from the
	outside investor for the sale of accounts receivable, which was then forwarded to KCP&L for
	consideration of its sale.

6.	NUCLEAR PLANT

KCP&L owns 47% of WCNOC, the operating company for Wolf Creek, its only nuclear generating unit. Wolf Creek is regulated by the NRC, with respect to licensing, operations and safety-related requirements.

Spent Nuclear Fuel and 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 kilowatt-hour of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel. These disposal costs are charged to fuel expense. In 2002, the U.S. Senate approved Yucca Mountain, Nevada as a long-term geologic repository. In July 2006, the DOE announced plans to submit a license application to the NRC for a nuclear waste repository at Yucca Mountain, Nevada, not later that June 30, 2008. The DOE also announced if requested legislative changes are enacted, the repository would be able to accept spent nuclear fuel and high-level waste starting in early 2017. Management cannot predict when this site may be available for Wolf Creek. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel first from the owners with the older spent fuel. Wolf Creek has completed an on-site storage facility designed to hold all spent fuel generated at the plant through the end of its current 40-year licensed life in 2025. If the DOE meets its revised timetable for accepting spent fuel for disposal by 2017, management expects that the DOE would begin accepting some of Wolf Creek’s spent fuel by 2025. Management will continue to monitor this activity. See Note 15 for a related legal proceeding.

Nuclear Liability and Insurance

The owners of Wolf Creek (Owners) maintain nuclear insurance for Wolf Creek in four areas: liability, worker radiation, property and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war. Both the nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts of terrorism and related losses, as defined by the Terrorism Risk Insurance Act, including replacement power costs. An industry aggregate limit of $0.3 billion exists for liability claims, regardless of the number of non-certified acts affecting Wolf Creek or any other nuclear energy liability policy or the number of policies in place. An industry aggregate limit of $3.2 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), the Owners’ insurance provider, exists for property claims, including accidental outage power costs for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. For certified acts of terrorism, the individual policy limits apply. In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

Liability Insurance

Pursuant to the Price-Anderson Act, which was reauthorized through December 31, 2025, by the Energy Policy Act of 2005, the Owners are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently $10.8 billion. This limit of liability consists of the maximum available commercial insurance of $0.3 billion, and the remaining $10.5 billion is provided through an industry-wide retrospective assessment program mandated by law, known as the Secondary Financial Protection (SFP) program. Under the SFP program, the Owners can be assessed up to $100.6 million ($47.3 million, KCP&L’s 47% share) per incident at any commercial reactor in the country, payable at no more than $15 million ($7.1 million, KCP&L’s 47% share) per incident per year. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. This assessment also applies to worker

radiation claims insurance. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

Property, Decontamination, Premature Decommissioning and Extra Expense Insurance

The Owners carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, KCP&L's 47% share). NEIL provides this insurance.

In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. KCP&L’s share of any remaining proceeds can be used for further decontamination, property damage restoration and premature decommissioning costs. Premature decommissioning coverage applies only if an accident at Wolf Creek exceeds $500 million in property damage and decontamination expenses, and only after trust funds have been exhausted.

Accidental Nuclear Outage Insurance

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

Under all NEIL policies, the Owners are subject to retrospective assessments if NEIL losses, for each policy year, exceed the accumulated funds available to the insurer under that policy. The estimated maximum amount of retrospective assessments under the current policies could total approximately $26.1 million ($12.3 million, KCP&L’s 47% share) per policy year.

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

Low-Level Waste

The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that the various states, individually or through interstate compacts, develop alternative low-level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (Compact) and selected a site in northern Nebraska to locate a disposal facility. WCNOC and the owners of the other five nuclear units in the Compact provided most of the pre-construction financing for this project.

After many years of effort, Nebraska regulators denied the facility developer’s license application in December 1998, a prolonged lawsuit ensued, and Nebraska eventually settled the case by paying the Compact Commission $145.8 million in damages. The Compact Commission then paid out pro rata portions of the settlement money to the various parties who originally funded the project. To date, WCNOC has received refunds totaling $21.3 million (KCP&L’s 47% share being $10 million), including $1.7 million ($0.8 million, KCP&L’s 47% share) received in 2006. The Commission continues to explore alternative long-term waste disposal capability and has retained an insignificant portion of the settlement money. In April 2006, WCNOC and other affected generators filed a lawsuit in Federal District Court in Nebraska seeking to preserve their ability to continue to pursue their claim for their share of the retained amount plus interest. The parties took the case to mediation in October 2006.

Accrued Refueling Outage Costs

KCP&L accrues anticipated incremental costs to be incurred during scheduled Wolf Creek refueling outages monthly over the unit's operating cycle, normally the 18 months preceding the outage.

Estimated incremental costs, which include operating, maintenance and replacement power expenses, are based on anticipated outage costs and the estimated outage duration. Changes to or variances from those estimates are recorded when known or are probable. In September 2006, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities.” FSP No. AUG AIR-1 prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities. Great Plains Energy and consolidated KCP&L are required to adopt the provisions of FSP No. AUG AIR-1 for periods beginning after December 15, 2006. The guidance in FSP No. AUG AIR-1 will be applied retrospectively. Management has determined that KCP&L will adopt the deferral method allowed under the FSP and has not yet determined the impact on Great Plains Energy and consolidated KCP&L’s consolidated financial statements.

7.	REGULATORY MATTERS

KCP&L’s Comprehensive Energy Plan

KCP&L continues to make progress in implementing its comprehensive energy plan under orders received from the MPSC and KCC in 2005. The Sierra Club and Concerned Citizens of Platte County have appealed the MPSC order, and the Sierra Club has appealed the KCC order. In March 2006, the Circuit Court of Cole County, Missouri, affirmed the MPSC Order and the Sierra Club has appealed the decision to the Missouri Court of Appeals. The Kansas District Court denied the Sierra Club’s appeal in May 2006 and the Sierra Club has appealed to the Kansas Court of Appeals. Although subject to the appeals, the MPSC and KCC orders remain in effect pending the applicable court’s decision.

Although control budgets and workflow scheduling are not complete, developing market conditions indicate overall cost estimates of the comprehensive energy plan are currently expected to be about 20% above the estimate in the 2005 Form 10-K. The primary driver of the increased cost of the comprehensive energy plan is the environmental retrofit of selected existing coal-fired plants. The demand for environmental projects has increased substantially with many utilities in the United States starting similar projects to address changing environmental regulations. This demand has constrained labor and material resources resulting in a significant escalation in the cost and completion times for environmental retrofits. The first phase of environmental upgrades at LaCygne No. 1, installation of SCR equipment, began in late 2005 and is expected to be in-service for the summer of 2007. KCP&L has approximately 88% of the total estimated cost for the first phase under firm contract as of September 30, 2006. The second phase of environmental upgrades at LaCygne No. 1 is currently in the planning stage, and the market conditions noted above could impact the scope and timing. Iatan No. 1 environmental upgrades are on schedule with approximately 80% of the total estimated costs under firm contract as of September 30, 2006.

The construction projects contemplated in the comprehensive energy plan rely upon the supply of a significant percentage of materials from overseas sources. This global procurement subjects the delivery of procured material to issues beyond what would be expected if such material were supplied from sources within the United States. These risks include, but are not limited to, delays in clearing customs, ocean transportation and potential civil unrest in sourcing countries, among others. Additionally, as with any major construction program, inadequate availability of qualified craft labor may have an adverse impact on both the estimated cost and completion date of the projects.

Over the last several months, KCP&L has finalized contracts and received bids for the largest cost components of the construction of Iatan No. 2. The estimated costs for Iatan No. 2 have also increased due to the constrained labor and material resources discussed above; however, the Iatan No. 2 estimated costs have not been as impacted as the estimated costs of the environmental retrofits. KCP&L has approximately 60% of the total estimated cost of Iatan No. 2 under firm contract as of September 30, 2006, and has started construction activities at the site. An owners’ engineer has been

hired and the engineering design for Iatan Station is approximately 25% complete, which is on schedule with the targeted project completion in summer 2010. During the second quarter of 2006, KCP&L finalized Iatan No. 2 co-ownership agreements with Aquila Inc., The Empire District Electric Company, Kansas Electric Power Cooperative and Missouri Joint Municipal Electric Utility Commission. KCP&L will own 54.71% or approximately 465 MW of the new unit. In the first quarter of 2006, KCP&L received the air permit and a water quality certification from the Missouri Department of Natural Resources relating to Iatan Station. The Sierra Club is appealing the air permit. In the third quarter of 2006, the Sierra Club filed a motion requesting that construction on Iatan No. 2 be stayed pending the outcome of its appeal. This motion was denied. KCP&L has received the remaining permits necessary to begin construction at Iatan Station, which included the wetlands permit and a permit for the construction of a temporary barge slip and collector wells from the U.S. Army Corps of Engineers (Corps). The Corps also executed an Environmental Assessment with a Finding of No Significant Impact.

Construction and commissioning of the 67 turbines at KCP&L’s Spearville Wind Energy Facility, a 100.5 MW wind project in western Kansas, was completed during the third quarter of 2006 in-line with cost estimates reported in the 2005 Form 10-K. Additional transmission construction to enhance KCP&L’s ability to carry power from the facility to its service territory is expected to be completed in the first half of 2007, and is reflected in the current cost estimates provided above.

KCP&L has implemented nine pilot affordability, energy efficiency and demand response programs in Missouri and four in Kansas. Initial results from the implemented pilot programs are beginning to demonstrate an ability to manage KCP&L’s customers’ retail load requirements and are on target with management's goal to achieve a potential 40MW reduction in retail load requirements by the end of 2006. These early results are evidenced by the success of KCP&L’s residential air conditioning cycling program, Energy Optimizer, which has experienced strong early participation with over 8,200 installations year to date September 30, 2006. Additionally, in September 2006, KCC initiated a generic investigation into energy efficiency. The general issues that KCC is investigating relate to when and how utilities should promote energy efficiency by their customers and what ratemaking treatment, including special mechanisms, is appropriate or desirable. This investigation provides a significant opportunity for the continued development of energy efficiency policy regulation in Kansas.

KCP&L Regulatory Proceedings

In February 2006, KCP&L filed requests with the MPSC and KCC for annual rate increases of $55.8 million or 11.5% and $42.3 million or 10.5%, respectively. The requested rate increases reflect recovery of increasing operating costs including fuel, transportation and pensions as well as investments in wind generation and customer programs and compensation for wholesale sales volatility and construction risks. The request is based on a return on equity of 11.5% and an adjusted equity ratio of 53.8%.

KCP&L reached a negotiated settlement with certain parties to the Kansas rate proceeding and filed an unopposed Stipulation and Agreement (Agreement) with KCC in the third quarter of 2006. The Agreement stipulates a $29 million increase in annual revenues effective January 1, 2007, including $4 million of accelerated depreciation to maintain cash flow levels as contemplated in the stipulation and agreement approved by KCC in 2005. The Agreement does not propose an energy cost adjustment (ECA) clause; however, KCP&L agreed to propose an ECA clause in its next rate case to be filed no later than March 1, 2007. The Agreement recommends various accounting and other provisions, including but not limited to, establishing annual pension costs beginning January 1, 2007, at approximately $43 million through the creation of a regulatory asset or liability, and establishing a regulatory asset or liability, effective January 1, 2006, for costs arising from defined benefit plan settlements and curtailments to be amortized over a five-year period beginning with the effective date of rates approved in KCP&L’s next rate case. The Agreement is subject to KCC approval, and is voidable

if not approved in its entirety. KCP&L expects KCC to act on the Agreement before the end of the year with any rate changes being effective on January 1, 2007.

In August 2006, the MPSC Staff filed its case regarding KCP&L’s rate request. In its filing, the Staff asserted that KCP&L’s annual revenues should be decreased by between $4.3 million and $5.1 million, before adjustments resulting from the September 30, 2006, true-up of test year information. The Staff’s filing assumed adjustments resulting from this true-up would increase revenue requirements by approximately $20 million, resulting in a net required increase in annual revenues of between $14.9 million and $15.7 million, which reflected approximately $75 million in accelerated depreciation, which the Staff asserted will maintain certain KCP&L credit ratios at investment-grade levels as provided for in the stipulation and agreement approved by the MPSC in 2005. The Staff’s position was revised in the hearings that were held in October 2006. The Staff’s current position is that KCP&L’s annual revenues should be increased by approximately $52 million (reflecting approximately $86 million in accelerated depreciation), before adjustments resulting from the September 30, 2006, true-up. A decision by the MPSC is expected before the end of the year with any rate changes being effective on January 1, 2007.

Regulatory Assets and Liabilities

KCP&L is subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” and has recorded assets and liabilities on its balance sheet resulting from the effects of the ratemaking process, which would not be recorded under GAAP for non-regulated entities.


	Amortization		September 30		December 31
	ending period		2006		2005
Regulatory Assets
Taxes recoverable through future rates		$	83.3	$	85.7
Decommission and decontaminate federal uranium
enrichment facilities	2007		0.8		1.3
Loss on reacquired debt	2037		6.6		7.1
January 2002 incremental ice storm costs (Missouri)	2007		1.5		4.9
Change in depreciable life of Wolf Creek	2045		40.9		27.4
Cost of removal			9.4		9.3
Asset retirement obligations			16.6		23.6
Pension accounting method difference	^(a)		6.5		-
Future recovery of pension costs	^(a)		31.0		15.6
Other	Various		10.9		5.0
Total Regulatory Assets		$	207.5	$	179.9
Regulatory Liabilities
Emission allowances	^(a)	$	64.5	$	64.3
Pension accounting method difference	^(a)		-		1.0
Asset retirement obligations			31.0		-
Additional Wolf Creek amortization (Missouri)	^(a)		12.0		4.3
Total Regulatory Liabilities		$	107.5	$	69.6
(a) Will be amortized in accordance with future rate cases.

Except as noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in KCP&L’s rate base, thereby providing a return on invested costs when included in rate base. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base. The pension accounting

method difference (which may be either a regulatory asset or liability) and certain insignificant items in other regulatory assets are not included in rate base.

Southwest Power Pool Regional Transmission Organization

KCP&L is a member of the Southwest Power Pool (SPP), which is a Federal Energy Regulatory Commission (FERC) approved Regional Transmission Organization (RTO). In July 2006, KCC granted interim approval for KCP&L to take SPP network integration transmission service for its retail customers. During 2006, KCC and MPSC both issued orders approving KCP&L’s participation in the SPP RTO, which also made final the previously granted KCC interim approval. In May 2006, SPP made a compliance filing in response to a previously issued FERC order on the SPP energy imbalance service market. In July 2006, FERC issued an order on the compliance filing accepting in part, as modified, and rejecting in part the filing, permitting the start of the SPP energy imbalance service market no earlier than October 1, 2006, and required SPP to make additional filings. The SPP Board met in October 2006 and delayed SPP’s readiness filing to FERC and plans to meet again in December 2006 to reassess SPP’s readiness for a February 1, 2007, energy imbalance service market start. KCP&L is continuing preparation for this new start-up date.

Revenue Sufficiency Guarantee

Since the April 2005 implementation of Midwest Independent Transmission System Operator Inc. (MISO) market operations, MISO’s business practice manuals and other instructions to market participants have stated that Revenue Sufficiency Guarantee (RSG) charges will not be imposed on day-ahead virtual offers to supply power not supported by actual generation. RSG charges are collected by MISO in order to compensate generators that are standing by to supply electricity when called upon by MISO. In April 2006, FERC issued an order regarding MISO RSG charges. In its order, FERC interpreted MISO's tariff to require that virtual supply offers be included in the calculation of RSG charges and that to the extent that MISO did not charge market participants RSG charges on virtual supply offers, MISO violated its tariff. The FERC order required MISO to recalculate RSG rates back to April 1, 2005, and make refunds to customers who paid RSG charges on imbalances, with interest, reflecting the recalculated charges. In order to make such refunds, RSG charges could have been retroactively imposed on market participants who submitted virtual supply offers during the recalculation period.

Strategic Energy is among the MISO participants that paid RSG charges on imbalances and could have received a refund as a result of the order. Strategic Energy could also have been subject to a retroactive assessment from MISO for RSG charges on virtual supply offers it submitted during the recalculation period. Consistent with MISO’s business practice manuals, management does not believe Strategic Energy should be assessed RSG charges retroactively or prospectively on its virtual supply offers.

Numerous requests for rehearing were filed and in October 2006, FERC entered an order granting requests for rehearing of the FERC’s decision to require MISO to retroactively recalculate RSG charges and provide refunds to customers that paid RSG charges on imbalances. As a result, MISO will not assess RSG charges retroactively on virtual supply offers, but RSG charges will apply prospectively on certain virtual supply offers. Parties may appeal the FERC Order. Management is unable to predict the outcome of any appeals.

Seams Elimination Charge Adjustment

Seams Elimination Charge Adjustment (SECA) is a transitional pricing mechanism authorized by FERC and intended to compensate transmission owners for the revenue lost as a result of FERC’s elimination of regional through and out rates between PJM Interconnection (PJM) and MISO during a 16-month transition period from December 1, 2004 through March 31, 2006. Each relevant PJM and MISO zone and the load-serving entities within that zone were allocated a portion of SECA based on transmission

services provided to that zone during 2002 and 2003. Strategic Energy did not record any significant SECA activity for the three months ended September 30, 2006. Year to date September 30, 2006, Strategic Energy recorded a reduction of purchased power expense of $2.4 million for SECA recoveries from suppliers, which offset $2.7 million of expense recorded in the first quarter. Strategic Energy recorded purchased power expenses totaling $3.3 million and $10.5 million for the three months ended and year to date September 30, 2005, for SECA transition charges. Strategic Energy recovered $1.3 million year to date September 30, 2006, of its SECA costs through billings to its retail customers. No further billings are anticipated pending the outcome of proceedings discussed below.

There are several unresolved matters and legal challenges related to SECA that are pending before FERC on rehearing. FERC established a schedule for resolution of certain SECA issues, including the issue of shifting SECA allocations to the shipper. The shipper in Strategic Energy’s situation is the wholesale supplier, which, through a contract with Strategic Energy, delivered power to various zones in which Strategic Energy was supplying retail customers. In most instances, the shipper was the purchaser of through and out transmission service and therefore included the cost of the through and out rate in its energy price.

In mid-2006, FERC held hearings on the justness and reasonableness of the SECA rate and on attempts by suppliers to shift SECA to wholesale counterparties. In August 2006, a favorable initial decision was extended by an administrative law judge, which could potentially result in a refund of prior SECA payments. Management is awaiting FERC action and is unable to predict the outcome of legal and regulatory challenges to the SECA mechanism.

8.	CAPITALIZATION

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


		September 30					December 31
	Year Due			2006			2005
Consolidated KCP&L			(millions)
General Mortgage Bonds
7.95% Medium-Term Notes	2007		$	0.5		$	0.5
3.73%* EIRR bonds	2012-2035			158.8			158.8
Senior Notes
6.00%	2007			225.0			225.0
6.50%	2011			150.0			150.0
6.05%	2035			250.0			250.0
Unamortized discount				(1.7	)		(1.8	)
EIRR bonds
4.75% Series A & B	2015			104.9			104.6
4.75% Series D	2017			39.4			39.3
4.65% Series 2005	2035			50.0			50.0
Current maturities				(225.5	)		-
Total consolidated KCP&L excluding current maturities				751.4			976.4

Other Great Plains Energy
7.74% Affordable Housing Notes	2006-2008			1.7			2.6
4.25% FELINE PRIDES Senior Notes	2009			163.6			163.6
Current maturities **				(164.4	)		(1.7	)
Total consolidated Great Plains Energy excluding current maturities			$	752.3		$	1,140.9
* Weighted-average interest rates at September 30, 2006.
** Includes $163.6 million of FELINE PRIDES Senior Notes scheduled to mature in 2009 that must be
remarketed between August 16, 2006 and February 16, 2007.

Effective Interest Rates on KCP&L’s Unsecured Notes at September 30, 2006

Interest rate swaps on KCP&L’s Series A, B and D EIRR bonds resulted in an effective interest rate of 6.27%. As a result of amortizing the gain recognized in other comprehensive income (OCI) on KCP&L’s 2005 Treasury Locks (T-Locks), the effective interest rate on KCP&L’s $250.0 million of 6.05% Senior Notes that were issued via a private placement during 2005 is 5.78%. In the second quarter of 2006, KCP&L completed an exchange of these privately placed notes for $250.0 million of registered 6.05% unsecured senior notes maturing in 2035 to fulfill its obligations under a 2005 registration rights agreement.

Amortization of Debt Expense

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


	Three Months Ended				Year to Date
	September 30				September 30
	2006		2005		2006		2005
	(millions)
Consolidated KCP&L	$	0.5	$	0.6	$	1.5	$	1.7
Other Great Plains Energy		0.2		0.1		0.5		0.5
Total Great Plains Energy	$	0.7	$	0.7	$	2.0	$	2.2

Forward Starting Swaps

During 2006, KCP&L entered into two Forward Starting Swaps (FSS) with a combined notional principal amount of $225.0 million to hedge interest rate volatility on the anticipated refinancing of KCP&L’s $225.0 million senior notes that mature in March 2007. See Note 18 for additional information.

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

During May 2006, Great Plains Energy entered into a five-year $600 million revolving credit facility with a group of banks. The facility replaced a $550 million revolving credit facility with a group of banks. A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $25.0 million is a default under the facility. Under the terms of this agreement, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At September 30, 2006, the Company was in compliance with this covenant. At September 30, 2006, Great Plains Energy had no cash borrowings and had issued letters of credit totaling $125.5 million under the credit facility as credit support for Strategic Energy. At December 31, 2005, Great Plains Energy had $6.0 million of outstanding borrowings with an interest rate of 4.98% and had issued letters of credit totaling $38.5 million under the credit facility as credit support for Strategic Energy.

During May 2006, KCP&L entered into a five-year $400 million revolving credit facility with a group of banks to provide support for its issuance of commercial paper and other general corporate purposes. Great Plains Energy and KCP&L may transfer and re-transfer up to $200 million of unused lender commitments between Great Plains Energy’s and KCP&L’s facilities, so long as the aggregate lender commitments under either facility does not exceed $600 million and the aggregate lender commitments under both facilities does not exceed $1 billion. The facility replaced a $250 million revolving credit facility with a group of banks. A default by KCP&L on other indebtedness totaling more than $25.0 million is a default under the facility. Under the terms of the agreement, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At September 30, 2006, KCP&L was in compliance with this covenant. At September 30, 2006, KCP&L had $80.6 million of commercial paper outstanding, at a weighted-average interest rate of 5.48% and no cash borrowings under the facility. At December 31, 2005, KCP&L had $31.9 million of commercial paper outstanding, at a weighted-average interest rate of 4.35% and no cash borrowings under the facility.

Strategic Energy has a $135 million revolving credit facility with a group of banks that expires in June 2009. So long as Strategic Energy is in compliance with the agreement, it may increase this amount by up to $15 million by increasing the commitment of one or more lenders that have agreed to such increase, or by adding one or more lenders with the consent of the administrative agent. In October 2006, Great Plains Energy, as permitted by the terms of the agreement, requested and received a reduction in its guarantee of this facility to a maximum amount of $12.5 million and has guaranteed the $12.5 million. A default by Strategic Energy on other indebtedness, as defined in the facility, totaling more than $7.5 million is a default under the facility. Under the terms of this agreement, Strategic Energy is required to maintain a minimum net worth of $75.0 million, a minimum fixed charge coverage ratio of at least 1.05 to 1.00 and a minimum debt service coverage ratio of at least 4.00 to 1.00, as those terms are defined in the agreement. In addition, under the terms of this agreement, Strategic Energy is required to maintain a maximum funded indebtedness to EBITDA ratio, as defined in the agreement, of 3.00 to 1.00, on a quarterly basis through June 30, 2007, and 2.75 to 1.00 thereafter. In the event of a breach of one or more of these four covenants, so long as no other default has occurred, Great Plains Energy may cure the breach through a cash infusion, a guarantee increase or a combination of the two. At September 30, 2006, Strategic Energy was in compliance with these covenants. At September 30, 2006, $70.9 million in letters of credit had been issued and there were no cash borrowings under the agreement. At December 31, 2005, $75.2 million in letters of credit had been issued and there were no cash borrowings under the agreement.

Common Shareholders’ Equity

Great Plains Energy filed a shelf registration statement with the Securities and Exchange Commission (SEC) in May 2006 relating to Senior Debt Securities, Subordinated Debt Securities, shares of Common Stock, Warrants, Stock Purchase Contracts and Stock Purchase Units. In May 2006, Great Plains Energy issued 5.2 million shares of common stock at $27.50 per share under this registration statement with $144.3 million in gross proceeds and issuance costs of $5.2 million.

In May 2006, Great Plains Energy also entered into a forward sale agreement with Merrill Lynch Financial Markets, Inc. (forward purchaser) for 1.8 million shares of Great Plains Energy common stock. The forward purchaser borrowed and sold the same number of shares of Great Plains Energy’s common stock to hedge its obligations under the forward sale agreement. Great Plains Energy did not initially receive any proceeds from the sale of common stock shares by the forward purchaser. The forward sale agreement provides for a settlement date or dates to be specified at Great Plains Energy’s discretion, subject to certain exceptions, no later than May 23, 2007. Subject to the provisions of the forward sale agreement, Great Plains Energy will receive an amount equal to $26.6062 per share, plus interest based on the federal funds rate less a spread and less certain scheduled decreases if Great Plains Energy elects to physically settle the forward sale agreement by delivering solely shares of common stock. In most circumstances, Great Plains Energy also has the right, in lieu of physical settlement, to elect cash or net physical settlement.

In May 2006, Great Plains Energy registered an additional 1.0 million shares of common stock with the SEC for its Dividend Reinvestment and Direct Stock Purchase Plan, bringing the total number of shares registered under this plan to 4.0 million. The plan allows for the purchase of common shares by reinvesting dividends or making optional cash payments.

In March 2006, Great Plains Energy registered an additional 1.0 million shares of common stock with the SEC for a defined contribution savings plan, bringing the total number of shares registered under this plan to 10.3 million. Shares issued under the plans may be either newly issued shares or shares purchased in the open market.

9.	PENSION PLANS AND OTHER EMPLOYEE BENEFITS

The Company maintains defined benefit pension plans for substantially all employees, including officers, of KCP&L, Services and WCNOC. Pension benefits under these plans reflect the employees’ compensation, years of service and age at retirement.

The MPSC and KCC issued orders in 2005 establishing KCP&L’s annual pension costs at $22 million for the years 2005 and 2006 through the creation of regulatory assets and liabilities for future recovery from or refund to customers, as appropriate. During the third quarter of 2005, KCP&L implemented these orders retroactive to January 1, 2005.

In addition to providing pension benefits, the Company provides certain postretirement health care and life insurance benefits for substantially all retired employees of KCP&L, Services and WCNOC. The cost of postretirement benefits charged to KCP&L are accrued during an employee's years of service and recovered through rates.

The following tables provide the components of net periodic benefit costs prior to the effects of capitalization and sharing with joint-owners of power plants. Included in net periodic benefit costs are settlement charges related to the workforce realignment, discussed below. The total amount of 2006 pension settlement charges related to the workforce realignments and other retirements will be determined in the fourth quarter after the year-end of the pension plans.


	Pension Benefits						Other Benefits
Three Months Ended September 30	2006			2005			2006			2005
Components of net periodic benefit cost	(millions)
Service cost	$	4.7		$	4.4		$	0.3		$	0.2
Interest cost		7.8			7.5			0.7			0.7
Expected return on plan assets		(8.1	)		(8.2	)		(0.1	)		(0.2	)
Amortization of prior service cost		1.0			1.1			-			0.1
Recognized net actuarial loss		7.9			4.7			0.2			0.2
Transition obligation		-			-			0.3			0.3
Settlement charges		2.0			-			-			-
Net periodic benefit cost before
regulatory adjustment		15.3			9.5			1.4			1.3
Regulatory adjustment		(7.6	)		(10.8	)		-			-
Net periodic benefit cost	$	7.7		$	(1.3	)	$	1.4		$	1.3


	Pension Benefits						Other Benefits
Year to Date September 30	2006			2005			2006			2005
Components of net periodic benefit cost	(millions)
Service cost	$	14.1		$	13.0		$	0.7		$	0.7
Interest cost		23.2			22.4			2.2			2.1
Expected return on plan assets		(24.5	)		(24.3	)		(0.4	)		(0.5	)
Amortization of prior service cost		3.2			3.2			0.1			0.2
Recognized net actuarial loss		23.9			14.0			0.6			0.4
Transition obligation		-			-			0.9			0.9
Settlement charges		9.5			-			-			-
Net periodic benefit cost before
regulatory adjustment		49.4			28.3			4.1			3.8
Regulatory adjustment		(22.9	)		(10.8	)		-			-
Net periodic benefit cost	$	26.5		$	17.5		$	4.1		$	3.8

During September 2006, the FASB issued Statement of SFAS No. 158, “Employers’ Accounting for Defined Pension and Other Postretirement Plans.” SFAS No. 158 addresses balance sheet measurements and reporting requirements and will require the Company to recognize the funded status of the pension and postretirement plans on the balance sheet in the fourth quarter of 2006. SFAS No. 158 will be applied prospectively. Prior to the adoption of SFAS No. 158, the funded status of the pension and postretirement plans was only disclosed in the notes to consolidated financial statements. Management is currently evaluating the impact of SFAS No. 158.

Skill Set Realignment and Pension Settlement Charges

expense. For the three months ended and year to date September 30, 2006, KCP&L incurred $2.0 million and $9.3 million of pension settlement charges associated with the realignment resulting in $1.4 million and $6.2 million, respectively, of expense recorded after amounts capitalized and billed to joint owners of power plants. The pension settlement charges were a result of the number of employees retiring and selecting the lump-sum payment option.

KCP&L anticipates recording additional expense related to pension settlement charges after amounts capitalized and billed to joint owners of power plants of approximately $8 million during the fourth quarter of 2006 associated with its management and union pension plans as a result of additional employees retiring and selecting the lump-sum payment option. The total amount of 2006 pension settlement charges related to the workforce realignments and other retirements will be determined in the fourth quarter after the year-end of the pension plans. In the second quarter of 2006, KCP&L requested regulatory accounting treatment from MPSC and KCC to defer pension settlement charges, effective from January 1, 2006, and amortize the deferred amount over a five-year period to be established in the rate proceeding following the current 2006 proceedings. In the third quarter of 2006, KCP&L reached a negotiated settlement with certain parties in the Kansas rate proceeding and filed a Stipulation and Agreement with KCC that includes this requested regulatory treatment for pension costs. At September 30, 2006, no amounts have been deferred pending the outcome of these requests.

10.

EQUITY COMPENSATION

As of January 1, 2006, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” using the modified prospective application method. The adoption of SFAS No. 123R had an insignificant effect on the companies’ consolidated statements of income and cash flows for the three months ended and year to date September 30, 2006.

The Company’s Long-Term Incentive Plan is an equity compensation plan approved by its shareholders. KCP&L does not have an equity compensation plan; however, KCP&L officers participate in Great Plains Energy’s Long-Term Incentive Plan. The Long-Term Incentive Plan permits the grant of restricted stock, stock options, limited stock appreciation rights and performance shares to officers of the Company and its subsidiaries. The maximum number of shares of Great Plains Energy common stock that can be issued under the plan is 3.0 million. Common stock shares delivered by the Company under the Long-Term Incentive Plan may be authorized but unissued, held in the treasury or purchased on the open market (including private purchases) in accordance with applicable security laws. The Company has a policy of delivering newly issued shares, or shares surrendered by Plan participants on account of withholding taxes and held in treasury, or both, to satisfy share option exercises and does not expect to repurchase common shares during 2006 to satisfy stock option exercises for the period.

SFAS No. 123R requires forfeitures to be estimated. Forfeiture rates are based on historical forfeitures and future expectations and will be reevaluated annually. The following table summarizes Great Plains Energy’s and KCP&L’s equity compensation expense and income tax benefits.


	Three Months Ended				Year to Date
	September 30				September 30
	2006		2005			2006		2005
Compensation expense	(millions)
Great Plains Energy	$	1.2	$	0.9		$	2.9	$	2.5
KCP&L		0.7		0.6			1.8		1.4
Income tax benefits
Great Plains Energy		0.4		0.3			0.8		0.9
KCP&L		0.2		0.2			0.5		0.5

Stock Options Granted 2001 - 2003

Stock options were granted under the plan at market value of the shares on the grant date. The options vest three years after the grant date and expire in ten years if not exercised. The fair value for the stock options granted in 2001 - 2003 was estimated at the date of grant using the Black-Scholes option-pricing model. Compensation expense and accrued dividends related to stock options are recognized over the stated vesting period. Exercise prices range from $24.90 to $27.73 and all stock options are fully vested at September 30, 2006. All stock option activity year to date September 30, 2006, is summarized in the following table.


				Exercise
Stock Options	Shares			Price*
Beginning balance		111,455		$	25.56
Forfeited or expired		(1,983	)		27.73
Exercisable at September 30		109,472			25.52
* weighted-average

At September 30, 2006, the remaining weighted-average contractual term was 5.2 years. The total fair value of stock options vested was insignificant for the three months ended and year to date September 30, 2006 and 2005.

Performance Shares

The payment of performance shares is contingent upon achievement of specific performance goals over a stated period of time as approved by the Compensation and Development Committee of the Company’s Board of Directors. The number of performance shares ultimately paid can vary from the number of shares initially granted depending on Company performance, based on internal and external measures, over stated performance periods. Performance shares have a value equal to the market value of the shares on the grant date with accruing dividends. Compensation expense, calculated by multiplying shares by the related grant-date fair value less the present value of dividends, and accrued dividends related to performance shares are recognized over the stated period.

Performance share activity year to date September 30, 2006, is summarized in the following table.


				Grant Date
Performance	Shares			Fair Value*
Beginning balance		172,761		$	30.17
Performance adjustment		(2,650	)
Granted		94,159			28.20
Issued		(9,499	)		27.73
Ending balance		254,771			29.56
* weighted-average

At September 30, 2006, the remaining weighted-average contractual term was 1.4 years. There was no activity for performance shares during the three months ended and the weighted-average grant-date fair value for shares granted was $28.20 and $30.34 year to date September 30, 2006 and 2005, respectively. At September 30, 2006, there was $3.1 million of total unrecognized compensation expense, net of forfeiture rates, related to performance shares granted under the Plan, which will be recognized over the remaining weighted-average contractual term. The total fair value of shares vested was insignificant during the three months ended and year to date September 30, 2006 and 2005.

Restricted Stock

Restricted stock cannot be sold or otherwise transferred by the recipient prior to vesting and has a value equal to the fair market value of the shares on the issue date. Restricted stock shares vest over a stated period of time with accruing reinvested dividends. Compensation expense, calculated by multiplying shares by the related grant-date fair value less the present value of dividends, and accrued dividends related to restricted stock are recognized over the stated vesting period. Restricted stock activity year to date September 30, 2006, is summarized in the following table.


Nonvested				Grant Date
Restricted stock	Shares			Fair Value*
Beginning balance		119,966		$	30.50
Issued		48,041			28.22
Forfeited		(2,000	)		28.20
Ending balance		166,007			29.86
* weighted-average

At September 30, 2006, the remaining weighted-average contractual term was 1.4 years. There was no activity for restricted shares during the three months ended and the weighted-average grant-date fair value of shares granted was $28.22 and $30.56 year to date September 30, 2006 and 2005, respectively. At September 30, 2006, there was $1.7 million of total unrecognized compensation expense, net of forfeiture rates, related to nonvested restricted stock granted under the Plan, which will be recognized over the remaining weighted-average contractual term. No shares vested during the three months ended and year to date September 30, 2006 and 2005.

11.

INCOME TAXES

Components of income taxes are detailed in the following tables.


	Three Months Ended						Year to Date
	September 30						September 30
Great Plains Energy	2006			2005			2006			2005
Current income taxes	(millions)
Federal	$	38.3		$	39.4		$	67.6		$	49.9
State		2.9			0.7			4.3			0.1
Total		41.2			40.1			71.9			50.0
Deferred income taxes
Federal		(12.0	)		(2.4	)		(26.7	)		0.1
State		(1.9	)		(18.0	)		(6.2	)		(15.8	)
Total		(13.9	)		(20.4	)		(32.9	)		(15.7	)
Investment tax credit amortization		(0.8	)		(1.0	)		(2.3	)		(2.9	)
Total income tax expense		26.5			18.7			36.7			31.4
Less: taxes on discontinued operations
Current tax (benefit) expense		-			1.4			-			(1.0	)
Income taxes on continuing operations	$	26.5		$	17.3		$	36.7		$	32.4


	Three Months Ended						Year to Date
	September 30						September 30
Consolidated KCP&L	2006			2005			2006			2005
Current income taxes		(millions)
Federal	$	36.5		$	45.1		$	60.0		$	63.2
State		4.6			1.6			7.3			4.2
Total		41.1			46.7			67.3			67.4
Deferred income taxes
Federal		(0.9	)		(10.6	)		(2.8	)		(13.7	)
State		(0.1	)		(18.5	)		(0.3	)		(18.8	)
Total		(1.0	)		(29.1	)		(3.1	)		(32.5	)
Investment tax credit amortization		(0.8	)		(1.0	)		(2.3	)		(2.9	)
Total	$	39.3		$	16.6		$	61.9		$	32.0

Income Tax Expense and Effective Income Tax Rates

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

Great Plains Energy


	Income Tax Expense						Income Tax Rate
Three Month Ended September 30	2006			2005			2006			2005
Federal statutory income tax	$	28.6		$	37.3			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		0.2			1.2			0.2			1.2
Amortization of investment tax credits		(0.8	)		(1.0	)		(0.9	)		(0.9	)
Federal income tax credits		(2.1	)		(2.2	)		(2.5	)		(2.1	)
State income taxes		0.9			2.5			1.0			2.4
Changes in uncertain tax positions, net		0.2			(7.8	)		0.2			(7.3	)
Rate change on deferred taxes		-			(11.7	)		-			(11.0	)
Other		(0.5	)		(1.0	)		(0.6	)		(1.0	)
Total	$	26.5		$	17.3			32.4	%		16.3	%


	Income Tax Expense						Income Tax Rate
Year to Date September 30	2006			2005			2006			2005
Federal statutory income tax	$	44.6		$	58.5			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		0.9			2.1			0.7			1.2
Amortization of investment tax credits		(2.3	)		(2.9	)		(1.8	)		(1.7	)
Federal income tax credits		(4.5	)		(7.4	)		(3.5	)		(4.4	)
State income taxes		-			2.9			(0.1	)		1.8
Changes in uncertain tax positions, net		0.2			(6.8	)		0.1			(4.1	)
Rate change on deferred taxes		-			(11.7	)		-			(7.0	)
Other		(2.2	)		(2.3	)		(1.6	)		(1.4	)
Total	$	36.7		$	32.4			28.8	%		19.4	%

Consolidated KCP&L


	Income Tax Expense						Income Tax Rate
Three Month Ended September 30	2006			2005			2006			2005
Federal statutory income tax	$	37.9		$	29.9			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		0.2			1.2			0.2			1.4
Federal income tax credits		(0.9	)		-			(0.8	)		-
Amortization of investment tax credits		(0.8	)		(1.0	)		(0.7	)		(1.1	)
State income taxes		3.0			2.0			2.8			2.3
Changes in uncertain tax positions, net		0.1			(1.9	)		0.1			(2.2	)
Parent company tax benefits		(1.1	)		(1.7	)		(1.0	)		(2.0	)
Rate change on deferred taxes		-			(11.7	)		-			(13.7	)
Other		0.9			(0.2	)		0.8			(0.4	)
Total	$	39.3		$	16.6			36.4	%		19.3	%


	Income Tax Expense						Income Tax Rate
Year to Date September 30	2006			2005			2006			2005
Federal statutory income tax	$	62.5		$	49.1			35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		0.9			2.1			0.5			1.5
Federal income tax credits		(0.9	)		-			(0.5	)		-
Amortization of investment tax credits		(2.3	)		(2.9	)		(1.3	)		(2.1	)
State income taxes		4.7			3.2			2.7			2.3
Changes in uncertain tax positions, net		0.6			(1.2	)		0.3			(0.8	)
Parent company tax benefits		(3.3	)		(4.5	)		(1.9	)		(3.2	)
Rate change on deferred taxes		-			(11.7	)		-			(8.4	)
Other		(0.3	)		(2.1	)		(0.1	)		(1.5	)
Total	$	61.9		$	32.0			34.7	%		22.8	%

For the three months ended and year to date September 30, 2005, Great Plains Energy’s and consolidated KCP&L’s income taxes were reduced by $11.7 million reflecting a reduction of KCP&L’s deferred tax balances as a result of a reduction in the companies’ composite tax rate due to the favorable impact of sustained audit positions. SFAS No. 109, “Accounting for Income Taxes” required the companies to adjust deferred tax balances to reflect tax rates that are anticipated to be in effect when the differences reverse. Great Plains Energy’s income tax expense was also reduced in 2005 by $5.7 million due to events during the three months ended September 30, 2005, that strengthened the probability of sustaining tax deductions taken on previously filed tax returns.

Deferred Income Taxes

Uncertain Tax Positions

In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes,” an interpretation of SFAS No. 109, “Accounting for Income Taxes”. FIN No. 48 clarifies how companies calculate and disclose uncertain tax positions. Great Plains Energy and consolidated KCP&L are required to adopt the provisions of FIN No. 48 for periods beginning in 2007, although earlier adoption is permitted. Management is currently evaluating the impact of FIN No. 48 and has not yet determined the impact on Great Plains Energy and consolidated KCP&L’s consolidated financial statements. Management evaluates and records tax liabilities for uncertain tax positions based on the probability of ultimately sustaining the tax deductions or income positions. Management assesses the probabilities of successfully defending the tax deductions or income positions based upon statutory, judicial or administrative authority.

At September 30, 2006 and December 31, 2005, the Company had $4.8 million and $4.6 million, respectively, of liabilities for uncertain tax positions related to tax deductions or income positions taken on the Company’s tax returns. Consolidated KCP&L had liabilities for uncertain tax positions of $1.8 million and $1.2 million at September 30, 2006 and December 31, 2005, respectively. Management believes the tax deductions or income positions are properly treated on such tax returns but has recorded reserves based upon its assessment of the probabilities that certain deductions or income positions may not be sustained when the returns are audited. The tax returns containing these tax deductions or income positions are currently under audit or will likely be audited. The timing of the resolution of these audits is uncertain. If the positions are ultimately sustained, the companies will reverse these tax provisions to net income. If the positions are not ultimately sustained, the companies

may be required to make cash payments plus interest and/or utilize the companies’ federal and state credit carryforwards.

12.

KLT GAS DISCONTINUED OPERATIONS

The KLT Gas natural gas properties (KLT Gas portfolio) was reported as discontinued operations in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” after the 2004 Board of Directors approval to sell the KLT Gas portfolio and discontinue the gas business. During 2004 and 2005, KLT Gas completed sales of the KLT Gas portfolio and in 2006 KLT Gas has no active operations.

13.

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

Consolidated KCP&L receives various support and administrative services from Services. These services are billed to consolidated KCP&L at cost, based on payroll and other expenses, incurred by Services for the benefit of consolidated KCP&L. These costs totaled $4.6 million and $14.1 million for the three months ended and year to date September 30, 2006, respectively, and $7.0 million and $37.9 million for the same periods in 2005. These costs consisted primarily of employee compensation, benefits and fees associated with various professional services. At September 30, 2006, and December 31, 2005, consolidated KCP&L had a net intercompany payable to Services of $2.6 million and $3.5 million, respectively. In the third quarter of 2005, approximately 80% of Services’ employees were transferred to KCP&L to better align resources with the operating business. At September 30, 2006, and December 31, 2005, consolidated KCP&L’s balance sheets reflect a note payable from HSS to Great Plains Energy of $0.6 million.

14.

COMMITMENTS AND CONTINGENCIES

Environmental Matters

The Company is subject to regulation by federal, state and local authorities with regard to air and other environmental matters primarily through KCP&L’s operations. The generation, transmission and distribution of electricity produces and requires disposal of certain hazardous products that are subject to these laws and regulations. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. Failure to comply with these laws and regulations could have a material adverse effect on consolidated KCP&L and Great Plains Energy.

KCP&L operates in an environmentally responsible manner and seeks to use current technology to avoid and treat contamination. KCP&L regularly conducts environmental audits designed to ensure compliance with governmental regulations and to detect contamination. At September 30, 2006, and December 31, 2005, KCP&L had $0.3 million accrued for environmental remediation expenses for water monitoring at one site. The amounts accrued were established on an undiscounted basis and KCP&L does not currently have an estimated time frame over which the accrued amounts may be paid out.

Environmental-related legislation is regularly introduced. Such legislation typically includes various compliance dates and compliance limits. Such legislation, including, but not limited to, potential carbon tax legislation, could have the potential for a significant financial impact on KCP&L, including the installation of new pollution control equipment to achieve compliance. However, KCP&L’s expectation is that any required environmental expenditures will be recovered through rates. KCP&L will continue to monitor proposed legislation.

The following table contains current estimates of expenditures to comply with environmental laws and regulations described below. The range of estimated expenditures has increased significantly from the range reported in the companies’ June 30, 2006, Form 10-Q. The demand for environmental projects has increased substantially with many utilities in the United States starting similar projects to address changing environmental regulations. This demand has constrained labor and material resources resulting in a significant escalation in the cost and completion times for environmental retrofits. KCP&L continues to refine its cost estimates detailed in the table below and explore alternatives. The allocation between states is based on location of the facilities and has no bearing as to recovery in jurisdictional rates.


Clean Air Estimated Required										Estimated
Environmental Expenditures	Missouri			Kansas			Total			Timetable
	(millions)
CAIR	$375	-	993	$	-		$375	-	993	2006 - 2015
Incremental BART		-		272	-	527	272	-	527	2006 - 2017
Incremental CAMR	11	-	15	5	-	6	16	-	21	2010 - 2018
Estimated required environmental expenditures	$386	-	1,008	$277	-	533	$633	-	1,541

Expenditure estimates provided in the table above include, but are not limited to, the accelerated environmental upgrade expenditures included in KCP&L’s comprehensive energy plan. See Note 7 for additional information regarding the status of environmental upgrade expenditures under KCP&L’s comprehensive energy plan. These expenditures are expected to reduce SO₂, NO_x, mercury and air particulate matter emissions.

Clean Air Interstate Rule

The Environmental Protection Agency (EPA) Clean Air Interstate Rule (CAIR) requires reductions in SO₂ and NO_x emissions in 28 states, including Missouri. The reduction in both SO₂ and NO_x emissions will be accomplished through establishment of permanent statewide caps for NO_x effective January 1, 2009, and SO₂ effective January 1, 2010. More restrictive caps will be effective January 1, 2015. KCP&L’s fossil fuel-fired plants located in Missouri are subject to CAIR, while its fossil fuel-fired plants in Kansas are not.

KCP&L expects to meet the emissions reductions required by CAIR at its Missouri plants through a combination of pollution control capital projects and the purchase of emission allowances in the open market as needed. The final CAIR rule establishes a market-based cap-and-trade program. Missouri has developed State Implementation Plan (SIP) rules, which include an emission allowance allocation mechanism, and has currently accepted comments on these preliminary rules in development. The SIP proposed rules will next be published for additional comment. Facilities will demonstrate compliance with CAIR by holding sufficient allowances for each ton of SO₂ and NO_x emitted in any given year with SO₂ emission allowances transferable among all regulated facilities nationwide and NO_x emission allowances transferable among all regulated facilities within the 28 CAIR states. KCP&L will also be allowed to utilize unused SO₂ emission allowances that it has accumulated during previous years of the Acid Rain Program to meet the more stringent CAIR requirements. At September 30, 2006, KCP&L had accumulated unused SO₂ emission allowances sufficient to support just under 120,000 tons of SO₂ emission under the provisions of the Acid Rain program, which are recorded in inventory at zero cost. KCP&L is permitted to sell excess SO₂ emission allowances in accordance with KCP&L’s comprehensive energy plan as approved by the MPSC and KCC.

Analysis of the final CAIR rule indicates that selective catalytic reduction technology for NO_x control and scrubbers for SO₂ control will likely be required for KCP&L’s Montrose Station in Missouri, in addition to the environmental upgrades at Iatan No. 1 included in the comprehensive energy plan. The timing of

the installation of such control equipment is currently being developed. As discussed below, certain of the control technology for SO₂ and NO_x will also aid in the control of mercury.

Best Available Retrofit Technology Rule

The EPA best available retrofit technology rule (BART) 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 LaCygne Nos. 1 and 2 in Kansas and Iatan No. 1 and Montrose No. 3 in Missouri. The CAIR suggests that states that meet the CAIR requirements may also meet BART requirements for individual sources. Missouri has included this understanding as part of the proposed CAIR SIP. Kansas is not a CAIR state and therefore BART will likely impact LaCygne Nos. 1 and 2. Kansas is in the process of completing modeling associated with the rule. States must submit a BART implementation plan in 2007 with required emission controls. The BART emission control equipment must be compliant within five years after the SIP is approved by the EPA. If emission controls to comply with BART are required at LaCygne Nos. 1 and 2, additional capital expenditures will be required above comprehensive energy plan upgrades. The ultimate cost of these regulations could be significantly different from the amounts estimated.

Mercury Emissions

The EPA Clean Air Mercury Rule (CAMR) regulates mercury emissions from coal-fired power plants located in 48 states, including Kansas and Missouri, under the New Source Performance Standards of the Clean Air Act. The rule established a market-based cap-and-trade program that will reduce nationwide utility emissions of mercury in two phases. The first phase cap is effective January 1, 2010, and will establish a permanent nationwide cap of 38 tons of mercury for coal-fired power plants. Management anticipates meeting the first phase cap by taking advantage of KCP&L’s mercury reductions achieved through capital expenditures to comply with CAIR and BART. The second phase is effective January 1, 2018, and will establish a permanent nationwide cap of 15 tons of mercury for coal-fired power plants. When fully implemented, the rule will reduce utility emissions of mercury by nearly 70% from current emissions of 48 tons per year.

Facilities will demonstrate compliance with the standard by holding allowances for each ounce of mercury emitted in any given year and allowances will be readily transferable among all regulated facilities nationwide. Under the cap-and-trade program, KCP&L will be able to purchase mercury allowances or elect to install pollution control equipment to achieve compliance. While it is expected that mercury allowances will be available in sufficient quantities for purchase in the 2010-2018 timeframe, the significant reduction in the nationwide cap in 2018 may hamper KCP&L’s ability to obtain reasonably priced allowances beyond 2018. Management expects capital expenditures will be required to install additional pollution control equipment to meet the second phase cap. During the ensuing years, management will closely monitor advances in technology for removal of mercury from Powder River Basin (PRB) coal and expects to make decisions regarding second phase removal based on then available technology to meet the 2018 compliance date. KCP&L participated in the Department of Energy (DOE) National Energy Technology Laboratory project to investigate control technology options for mercury removal from coal-fired plants burning sub-bituminous coal.

Carbon Dioxide

The Clear Skies Initiative includes a climate change policy, which is a voluntary program that relies heavily on incentives to encourage industry to voluntarily limit emissions. The strategy includes tax credits, energy conservation programs, funding for research into new technologies, and a plan to encourage companies to track and report their emissions so that companies could gain credits for use in any future emissions trading program. The greenhouse strategy links growth in emissions of greenhouse gases to economic output and is intended to reduce the greenhouse gas intensity of the U.S. economy 18% by 2012. Greenhouse gas intensity measures the ratio of greenhouse gas

emissions to economic output as measured by Gross Domestic Product (GDP). Under this plan, as the economy grows, greenhouse gases also would continue to grow, although at a slower rate than they would have without these policies in place. When viewed per unit of economic output, the rate of emissions would drop. The plan projects that the U.S. would lower its rate of greenhouse gas emissions from an estimated 183 metric tons per $1 million of GDP in 2002 to 151 metric tons per $1 million of GDP by 2012.

KCP&L is a member of the Power Partners through Edison Electric Institute (EEI). Power Partners is a voluntary program with the DOE under which utilities commit to undertake measures to reduce, avoid or sequester CO₂ emissions. Power Partners entered into a cooperative umbrella memorandum of understanding (MOU) with the DOE. This MOU contains supply and demand-side actions as well as offset projects that will be undertaken to reduce the power sector’s CO₂ emissions per kWh generated (carbon intensity), consistent with the EEI’s 2003 commitment of a 3% to 5% reduction over the next decade.

Air Particulate Matter and Ozone

The EPA standards for ozone and particulate matter air quality include an eight-hour ozone standard and a standard for particulate matter less than 2.5 microns (PM-2.5) in diameter. The EPA has designated the Kansas City area as attainment with respect to the PM-2.5 National Ambient Air Quality Standards (NAAQS). Additionally, the EPA designated Jackson, Platte, Clay and Cass counties in Missouri and Johnson, Linn, Miami and Wyandotte counties in Kansas as attainment with respect to the eight-hour ozone NAAQS.

In September 2006, the EPA announced the new NAAQS for both fine (PM-2.5) and coarse (PM-10) particulate matter. The new standards for PM-2.5 are 35 micrograms per cubic meter on a 24-hour basis and 15 micrograms per cubic meter on an annual basis. The EPA retained the 24-hour standard of 150 micrograms per cubic meter for PM-10 and revoked the annual PM-10 standard as unnecessary. The new 24-hour standard for PM-2.5 will increase the number of counties in non-attainment, but the Kansas City metro area will remain in attainment based on recent emission data.

In September 2006, the Missouri Department of Natural Resources and the Kansas Department of Health and Environment conducted a stakeholder meeting to discuss issues related to the development of the Missouri and Kansas Maintenance Plans for the Control of Ozone for the Kansas City area. The EPA will require Missouri and Kansas to submit these SIPs by June 2007. As part of the SIP requirements, contingency control measures must be included. These measures would go into effect only if associated triggers (such as a violation of the eight-hour ozone standard) occur. Although it is anticipated the proposed controls for CAIR and BART will provide the contingency control measures at KCP&L generation facilities, management will continue to be involved and monitor the SIP development.

Water Use Regulations

The EPA Clean Water Act established standards for cooling water intake structures. This regulation applies to certain existing power producing facilities that employ cooling water intake structures that withdraw 50 million gallons or more per day from lakes and rivers and use 25% or more of that water for cooling purposes. The regulation is designed to protect aquatic life from being killed or injured by cooling water intake structures. KCP&L is required to complete a comprehensive demonstration study on each of its generating facilities’ intake structures by the end of 2007. The studies are expected to cost a total of $1.2 million to $2.0 million. Depending on the outcome of the comprehensive demonstration studies, facilities may be required to implement technological, operational or restoration measures to achieve compliance. Compliance with this regulation is expected to be achieved between 2011 and 2014. Until the comprehensive demonstration studies are completed, the impact of this regulation cannot be quantified.

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

Contractual Obligations

The following table is an update to selected items from the contractual obligations in the 2005 Form

10-K to reflect significant changes.

*Great Plains Energy Contractual Obligations*
	Remainder
Payment due by period	of 2006		2007		2008		2009		2010		After 2010		Total
Purchase obligations
Fuel	$	86.6	$	98.5	$	107.1	$	43.3	$	43.0	$	84.5	$	463.0
Purchased power		184.5		526.4		195.3		113.2		94.7		48.7		1,162.8
Comprehensive energy plan		118.5		281.1		321.8		139.2		12.0		-		872.6
Total contractual obligations	$	389.6	$	906.0	$	624.2	$	295.7	$	149.7	$	133.2	$	2,498.4

*Consolidated KCP&L Contractual Obligations*
	Remainder
Payment due by period	of 2006		2007		2008		2009		2010		After 2010		Total
Purchase obligations
Fuel	$	86.6	$	98.5	$	107.1	$	43.3	$	43.0	$	84.5	$	463.0
Comprehensive energy plan		118.5		281.1		321.8		139.2		12.0		-		872.6
Total contractual obligations	$	205.1	$	379.6	$	428.9	$	182.5	$	55.0	$	84.5	$	1,335.6

Fuel represents KCP&L’s 47% share of Wolf Creek nuclear fuel commitments, KCP&L’s share of coal purchase commitments based on estimated prices to supply coal for generating plants and KCP&L’s share of rail transportation commitments for moving coal to KCP&L’s generating units. Purchased power represents Strategic Energy’s agreements to purchase electricity at various fixed prices to meet estimated supply requirements. Comprehensive energy plan represents KCP&L’s contractual commitments for projects contemplated by its comprehensive energy plan.

15.

LEGAL PROCEEDINGS

Union Pacific

In 2005, KCP&L filed a rate complaint case with the Surface Transportation Board (STB) charging that Union Pacific Railroad Company’s (Union Pacific) rates for transporting coal from the PRB in Wyoming to KCP&L’s Montrose Station are unreasonably high. Prior to the end of 2005, the rates were established under a contract with Union Pacific. Efforts to extend the term of the contract were unsuccessful and Union Pacific is the only service for coal transportation from the PRB to Montrose Station. KCP&L charged that Union Pacific possesses market dominance over the traffic and requested the STB prescribe maximum reasonable rates. In February 2006, the STB announced a rulemaking proceeding to address certain issues associated with the calculation of stand-alone costs in rate complaint cases. Proceedings in KCP&L’s rate complaint case have been suspended pending the outcome of this rulemaking. In the third quarter of 2006, the STB raised a question regarding

jurisdiction of the rate complaint. KCP&L and Union Pacific filed comments regarding the jurisdictional issue. If STB finds it does have jurisdiction, it will issue a new procedural schedule. Management currently expects a decision in the case in 2008. Until the STB case is decided, KCP&L is paying the higher tariff rates subject to refund.

Framatome

In 2005, WCNOC filed a lawsuit on behalf of itself, KCP&L and the other two Wolf Creek owners against Framatome ANP, Inc., and Framatome ANP Richland, Inc. (Framatome) in the District Court of Coffey County, Kansas. The suit alleged various claims against Framatome related to the proposed design, licensing and installation of a digital control system. The suit sought recovery of approximately $16 million in damages from Framatome. Framatome filed a counterclaim against the three Wolf Creek owners seeking recovery of damages alleged to be in excess of $20 million. In May 2006, the parties settled this case. The settlement had no significant impact on KCP&L’s results of operations or financial position.

Hawthorn No. 5 Subrogation Litigation

KCP&L filed suit in 2001, in Jackson County, Missouri Circuit Court against multiple defendants who are alleged to have responsibility for the 1999 Hawthorn No. 5 boiler explosion. KCP&L and National Union Fire Insurance Company of Pittsburgh, Pennsylvania (National Union) have entered into a subrogation allocation agreement under which recoveries in this suit are generally allocated 55% to National Union and 45% to KCP&L. Certain defendants were dismissed from the suit and various defendants settled, with KCP&L receiving a total of $38.2 million, of which $18.5 million was recorded as a recovery of capital expenditures. Trial of this case with the one remaining defendant resulted in a March 2004 jury verdict finding KCP&L’s damages as a result of the explosion were $452 million. In May 2004, the trial judge reduced the award against the defendant to $0.2 million. Both KCP&L and the defendant appealed this case to the Court of Appeals for the Western District of Missouri, and in May 2006, the Court of Appeals ordered the Circuit Court to enter judgment in KCP&L’s favor in accordance with the jury verdict. The defendant filed a motion for transfer of this case to the Missouri Supreme Court, which was denied. After deduction of amounts received from pre-trail settlements with other defendants and an amount for KCP&L’s comparative fault (as determined by the jury), KCP&L received proceeds of $38.9 million in 2006 pursuant to the subrogation allocation agreement after payment of attorney’s fees. The proceeds reduced purchased power expense by $10.8 million and fuel expense by $3.7 million. The proceeds also increased wholesale revenues by $2.5 million and included $6.1 million of interest that increased non-operating income. The remaining $15.8 million of proceeds were recorded as a recovery of capital expenditures.

KCP&L previously received reimbursement for Hawthorn No. 5 damages under a property damage insurance policy with Travelers Property Casualty Company of America (Travelers). Travelers filed suit in the Federal District Court for the Eastern District of Missouri in November 2005, against National Union, and KCP&L was added as a defendant in June 2006. Travelers seeks recovery of $10 million that KCP&L recovered in the April 2001 lawsuit described in the preceding paragraph. Management is unable to predict the outcome of this litigation.

Emergis Technologies, Inc.

In March 2006, Emergis Technologies, Inc. f/k/a BCE Emergis Technologies, Inc. (Emergis) filed suit against KCP&L in Federal District Court for the Western District of Missouri, alleging infringement of a patent, entitled “Electronic Invoicing and Payment System.” This patent relates to automated electronic bill presentment and payment systems, particularly those involving Internet billing and collection. In March 2006, KCP&L filed a response and denied infringing the patent. KCP&L counterclaimed for a declaration that the patent is invalid and not infringed. Emergis responded to KCP&L’s counterclaims in April 2006. Court ordered mediation occurred in July 2006, but the case was not resolved.

Management does not expect the outcome of this litigation to have a material impact on Great Plains Energy's or consolidated KCP&L's results of operations and financial position.

Spent Nuclear Fuel and Radioactive Waste

In 2004, KCP&L and the other two Wolf Creek owners filed suit against the United States in the U.S. Court of Federal Claims seeking an unspecified amount of monetary damages resulting from the government’s failure to begin accepting spent fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982. Approximately sixty other similar cases are pending before that court. A handful of the cases have received damages awards, most of which are on appeal now. The Wolf Creek case, previously on a court-ordered stay until October 2006 to allow for some of the earlier cases to be decided first, recently received an extension of the stay to January 2007. Another federal court already has determined that the government breached its obligation to begin accepting spent fuel for disposal. The questions now before the court in the pending cases are whether and to what extent the utilities are entitled to monetary damages for that breach. KCP&L management cannot predict the outcome of this Wolf Creek case.

Class Action Complaint

In 2005, a class action complaint for breach of contract was filed against Strategic Energy in the Court of Common Pleas of Allegheny County, Pennsylvania. The plaintiffs purportedly represent the interests of certain customers in Pennsylvania who entered into Power Supply Coordination Service Agreements (Agreements) for a certain product in Pennsylvania. The complaint seeks monetary damages, attorney fees and costs and a declaration that the customers may terminate their Agreements with Strategic Energy. In response to Strategic Energy’s preliminary objections, plaintiffs have filed an amended complaint that management is evaluating. The plaintiffs have granted Strategic Energy an indefinite extension of time to answer the complaint. Management is unable to predict the outcome of this litigation.

Texas Customer Dispute

In February 2006, a customer in Texas that procures electricity for schools notified Strategic Energy that it had selected another provider for its school members during the time it was under contract with Strategic Energy. Strategic Energy exercised it rights under the agreement for breach. In June 2006, Strategic Energy received a notice of demand for arbitration from the customer pursuant to the agreement. Management is evaluating the merits of the customer’s alleged damages and the parties are in the process of selecting an arbitrator. Management believes the ultimate outcome of this matter will not have a material impact on the Company’s financial position or results of operations.

Haberstroh

In 2004, Robert C. Haberstroh filed suit for breach of employment contract and violation of the Pennsylvania Wage Payment Collection Act against Strategic Energy Partners, Ltd. (Partners), SE Holdings, L.L.C. (SE Holdings) and Strategic Energy in the Court of Common Pleas of Allegheny County, Pennsylvania. In the first quarter of 2006, the suit was settled and as part of the settlement, Great Plains Energy acquired the remaining indirect interest in Strategic Energy for an insignificant amount.

Weinstein v. KLT Telecom

exercisable between September 1, 2003, and August 31, 2005. In June 2003, the stock of Holdings was cancelled and extinguished pursuant to the joint Chapter 11 plan confirmed by the Bankruptcy Court. In September 2003, Weinstein delivered a notice of exercise of his claimed rights under the put option. KLT Telecom rejected the notice of exercise, and Weinstein filed suit, alleging breach of contract. Weinstein sought damages of at least $15 million, plus statutory interest. In April 2005, summary judgment was granted in favor of KLT Telecom, and Weinstein appealed this judgment to the Missouri Court of Appeals for the Eastern District. In May 2006, the Court of Appeals affirmed the judgment. During July 2006, Weinstein filed an application for transfer of this case to the Missouri Supreme Court, which was granted. Oral arguments are scheduled for December 2006. The $15 million reserve has not been reversed pending the outcome of the appeal process.

16.

SEGMENT AND RELATED INFORMATION

Great Plains Energy

Great Plains Energy has two reportable segments based on its method of internal reporting, which generally segregates the reportable segments based on products and services, management responsibility and regulation. The two reportable business segments are KCP&L, an integrated, regulated electric utility, and Strategic Energy, a competitive electricity supplier. Other includes the operations of HSS, Services, all KLT Inc. operations other than Strategic Energy, 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 all of the reportable segments. For segment reporting, each segment’s income taxes include the effects of allocating holding company tax benefits. Segment performance is evaluated based on net income.

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


Three Months Ended				Strategic						Great Plains
September 30, 2006	KCP&L			Energy			Other			Energy
	(millions)
Operating revenues	$	359.3		$	459.2		$	-		$	818.5
Depreciation and amortization		(38.5	)		(1.9	)		-			(40.4	)
Interest charges		(15.5	)		(0.6	)		(1.9	)		(18.0	)
Income taxes		(39.5	)		10.2			2.8			(26.5	)
Loss from equity investments		-			-			(0.4	)		(0.4	)
Net income (loss)		70.0			(10.9	)		(3.9	)		55.2


Three Months Ended				Strategic						Great Plains
September 30, 2005	KCP&L			Energy			Other			Energy
	(millions)
Operating revenues	$	353.0		$	429.9		$	-		$	782.9
Depreciation and amortization		(36.7	)		(1.6	)		(0.1	)		(38.4	)
Interest charges		(15.0	)		(0.7	)		(2.2	)		(17.9	)
Income taxes		(16.4	)		(9.4	)		8.5			(17.3	)
Loss from equity investments		-			-			(0.1	)		(0.1	)
Discontinued operations		-			-			1.8			1.8
Net income		69.1			18.1			3.7			90.9


Year to Date				Strategic						Great Plains
September 30, 2006	KCP&L			Energy			Other			Energy
	(millions)
Operating revenues	$	890.6		$	1,129.2		$	-		$	2,019.8
Depreciation and amortization		(112.8	)		(5.8	)		-			(118.6	)
Interest charges		(45.4	)		(1.5	)		(6.2	)		(53.1	)
Income taxes		(62.1	)		17.4			8.0			(36.7	)
Loss from equity investments		-			-			(1.0	)		(1.0	)
Net income (loss)		117.8			(17.6	)		(9.5	)		90.7


Year to Date				Strategic						Great Plains
September 30, 2005	KCP&L			Energy			Other			Energy
	(millions)
Operating revenues	$	858.3		$	1,101.3		$	0.1		$	1,959.7
Depreciation and amortization		(109.7	)		(4.6	)		(0.2	)		(114.5	)
Interest charges		(45.1	)		(2.2	)		(6.5	)		(53.8	)
Income taxes		(32.4	)		(20.9	)		20.9			(32.4	)
Loss from equity investments		-			-			(0.8	)		(0.8	)
Discontinued operations		-			-			(1.8	)		(1.8	)
Net income (loss)		109.0			34.6			(10.6	)		133.0


			Strategic					Great Plains
	KCP&L		Energy		Other			Energy
September 30, 2006	(millions)
Assets	$	3,633.8	$	450.9	$	29.9		$	4,114.6
Capital expenditures ^(a)		371.1		3.2		0.3			374.6
December 31, 2005
Assets	$	3,334.6	$	441.8	$	57.3		$	3,833.7
Capital expenditures ^(a)		332.2		6.6		(4.7	)		334.1
^(a)Capital expenditures reflect year to date amounts for the periods presented.

Consolidated KCP&L

The following tables reflect summarized financial information concerning consolidated KCP&L’s reportable segment. Other includes the operations of HSS and intercompany eliminations. Intercompany eliminations include insignificant amounts of intercompany financing-related activities.


Three Months Ended							Consolidated
September 30, 2006	KCP&L			Other			KCP&L
	(millions)
Operating revenues	$	359.3		$	-		$	359.3
Depreciation and amortization		(38.5	)		-			(38.5	)
Interest charges		(15.5	)		(0.1	)		(15.6	)
Income taxes		(39.5	)		0.2			(39.3	)
Net income (loss)		70.0			(1.2	)		68.8


Three Months Ended							Consolidated
September 30, 2005	KCP&L			Other			KCP&L
	(millions)
Operating revenues	$	353.0		$	-		$	353.0
Depreciation and amortization		(36.7	)		-			(36.7	)
Interest charges		(15.0	)		-			(15.0	)
Income taxes		(16.4	)		(0.2	)		(16.6	)
Net income (loss)		69.1			(0.2	)		68.9


Year to Date							Consolidated
September 30, 2006	KCP&L			Other			KCP&L
	(millions)
Operating revenues	$	890.6		$	-		$	890.6
Depreciation and amortization		(112.8	)		-			(112.8	)
Interest charges		(45.4	)		(0.1	)		(45.5	)
Income taxes		(62.1	)		0.2			(61.9	)
Net income (loss)		117.8			(1.2	)		116.6


Year to Date							Consolidated
September 30, 2005	KCP&L			Other			KCP&L
	(millions)
Operating revenues	$	858.3		$	0.1		$	858.4
Depreciation and amortization		(109.7	)		(0.1	)		(109.8	)
Interest charges		(45.1	)		-			(45.1	)
Income taxes		(32.4	)		0.4			(32.0	)
Net income (loss)		109.0			(0.8	)		108.2


					Consolidated
	KCP&L		Other		KCP&L
September 30, 2006	(millions)
Assets	$	3,633.8	$	3.4	$	3,637.2
Capital expenditures ^(a)		371.1		-		371.1
December 31, 2005
Assets	$	3,334.6	$	3.9	$	3,338.5
Capital expenditures ^(a)		332.2		-		332.2
^(a)Capital expenditures reflect year to date amounts for the periods presented.

17.

ASSET RETIREMENT OBLIGATIONS

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

In the second quarter of 2006, KCP&L incurred an ARO related to decommissioning and site remediation associated with its Spearville Wind Energy Facility, a 100.5 MW wind project in western Kansas. KCP&L is obligated to remove the wind turbine towers and perform site remediation within 12 months after the end of the associated 30-year land lease agreements. The ARO was derived from a third party estimate of decommissioning and remediation costs. To estimate the ARO, KCP&L used a

credit-adjusted risk free discount rate of 6.68%. This rate was based on the rate at which KCP&L could issue 30-year bonds. KCP&L recorded a $3.1 million ARO for the decommissioning and site remediation and increased property and equipment by $3.1 million.

In the third quarter of 2006, WCNOC submitted an application for a new operating license for Wolf Creek with the NRC, which would extend Wolf Creek’s operating period to 2045. Management has determined the fair value of KCP&L’s ARO for nuclear decommissioning should reflect the change in timing in the undiscounted estimated cash flows to decommission Wolf Creek as a result of the extended operating period. Management calculated an ARO revision based on KCP&L’s most recent cost estimates to decommission Wolf Creek. To estimate the ARO layer attributable to the change in timing, KCP&L used a credit-adjusted risk free discount rate of 6.26%. The rate was based on the rate at which KCP&L could issue 40-year bonds. KCP&L recorded a $65.0 million decrease in the ARO to decommission Wolf Creek with a $25.8 million net decrease in property and equipment. The regulatory asset for ARO decreased $8.2 million and a $31.0 million regulatory liability for ARO was established to recognize current funding of the related decommissioning trust at September 30, 2006, in excess of the ARO due to the extended operating period.

KCP&L is a regulated utility subject to the provisions of SFAS No. 71 and management believes it is probable that any differences between expenses under FIN No. 47, “Accounting for Conditional Asset Retirement Obligations” or SFAS No. 143, “Accounting for Asset Retirement Obligation,” and expense recovered currently in rates will be recoverable in future rates. The following table summarizes the change in Great Plains Energy’s and consolidated KCP&L’s AROs.


	September 30			December 31
	2006			2005
	(millions)
Beginning balance	$	145.9		$	113.7
Additions		3.1			26.7
Extension of Wolf Creek life		(65.0	)		-
Settlements		-			(2.0	)
Accretion		7.1			7.5
Ending balance	$	91.1		$	145.9

18.

DERIVATIVE INSTRUMENTS

The companies 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 the companies’ operating results. The risk management activities, including the use of derivative instruments, are subject to the management, direction and control of internal risk management committees. Management’s interest rate risk management strategy uses derivative instruments to adjust the companies’ liability portfolio to optimize the mix of fixed and floating rate debt within an established range. In addition, management uses 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 and purchased power expense caused by commodity price volatility. Counterparties to commodity derivatives and interest rate swap agreements expose the companies to credit loss in the event of nonperformance. This credit loss is limited to the cost of replacing these contracts at current market rates less the application of counterparty collateral held and contract-based netting of credit exposures against payable balances. Derivative instruments, excluding those instruments that qualify for the Normal Purchases and Normal Sales (NPNS) election, which are accounted for by accrual accounting, are recorded on the balance sheet at fair value as an asset or

liability. Changes in the fair value are recognized currently in net income unless specific hedge accounting criteria are met.

Fair Value Hedges - Interest Rate Risk Management

In 2002, KCP&L remarketed its 1998 Series A, B and D EIRR bonds totaling $146.5 million to a five-year fixed interest rate of 4.75% ending October 1, 2007. Simultaneously with the remarketing, KCP&L entered into an interest rate swap for the $146.5 million based on the London Interbank Offered Rate (LIBOR) to effectively create a floating interest rate obligation. The transaction is a fair value hedge with no ineffectiveness. Changes in the fair market value of the swap are recorded on the balance sheet as an asset or liability with an offsetting entry to the respective debt balances with no net impact on net income.

Cash Flow Hedges - Forward Starting Swaps

In the first quarter of 2006, KCP&L entered into two Forward Starting Swaps to hedge against interest rate fluctuations on the long-term debt that KCP&L plans to issue before the end of the first quarter of 2007. The FSS will be settled simultaneously with the issuance of the long-term fixed rate debt. The FSS effectively removes most of the interest rate and credit spread uncertainty with respect to the debt to be issued, thereby enabling KCP&L to predict with greater assurance what its future interest costs on that debt will be. The FSS is accounted for as a cash flow hedge and the fair value is recorded as a current asset or liability with an offsetting entry to OCI, to the extent the hedge is effective, until the forecasted transaction occurs. No ineffectiveness has been recorded on the FSS. The pre-tax gain or loss on the FSS recorded to OCI will be reclassified to interest expense over the life of the future debt issuance.

Cash Flow Hedges - 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. As of September 30, 2006, KCP&L had hedged 22% and 7% of its 2007 and 2008 projected natural gas usage for retail load and firm MWh sales, respectively, primarily by utilizing fixed forward physical contracts. The fair values of these instruments are recorded as current assets or current liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, the ineffective portion of the change in fair market value is recorded currently in fuel expense. KCP&L did not record any gains or losses due to ineffectiveness during the three months ended and year to date September 30, 2006 and 2005, respectively.

Strategic Energy maintains a commodity-price risk management strategy that uses forward physical energy purchases and other derivative instruments to reduce the effects of fluctuations in purchased power expense caused by commodity-price volatility. Derivative instruments are used to limit the unfavorable effect that price increases will have on electricity purchases, effectively fixing the future purchase price of electricity for the applicable forecasted usage and protecting Strategic Energy from significant price volatility. The maximum term over which Strategic Energy hedged its exposure and variability of future cash flows was approximately five years at September 30, 2006 and December 31, 2005.

Certain forward fixed price purchases and swap agreements are designated as cash flow hedges. The fair values of these instruments are recorded as assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, the ineffective portion of the change in fair market value is recorded currently in purchased power. When the forecasted purchase is completed, the amounts in OCI are reclassified to purchased power. Purchased power expense for the three months ended and year to date September 30, 2006, includes a $13.1 million and $27.1 million loss, respectively, due to ineffectiveness of the cash flow hedges. Strategic Energy

recorded an $8.3 million and $10.4 million gain for the three months ended and year to date September 30, 2005, respectively, due to ineffectiveness of the cash flow hedges.

As part of its commodity-price risk management strategy, Strategic Energy also enters into economic hedges (non-hedging derivatives) that do not qualify for cash flow hedge accounting. The changes in the fair value of these derivative instruments recorded to purchased power expense were a $13.5 million loss and $9.9 million gain for the three months ended September 30, 2006 and 2005, respectively, and a $37.4 million loss and $15.6 million gain year to date September 30, 2006 and 2005, respectively.

The fair value of non-hedging derivatives at September 30, 2006, also includes certain forward contracts at Strategic Energy that were amended during 2005. Prior to being amended, the contracts were accounted for under the NPNS election in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” As a result of being amended, the contracts no longer qualify for NPNS exceptions or cash flow hedge accounting and are now accounted for as non-hedging derivatives with the fair value at amendment being recorded as a deferred liability that will be reclassified to net income as the contracts settle. For the three months ended and year to date September 30, 2006, Strategic Energy amortized $0.4 million and $5.0 million, respectively, of the deferred liability to purchased power expense related to the delivery of power under the contracts. Strategic Energy will amortize the remaining deferred liability over the remaining original contract lengths, which end in the first quarter of 2008. After the amendment, Strategic Energy is recording the change in fair value of these contracts to purchased power expense.

The notional and recorded fair values of the companies’ derivative instruments are summarized in the following table. The fair values of these derivatives are recorded on the consolidated balance sheets.


	September 30					December 31
	2006					2005
	Notional					Notional
	Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value
Great Plains Energy	(millions)
Swap contracts
Cash flow hedges	$	323.7	$	(47.6	)	$	164.7	$	23.8
Non-hedging derivatives		43.2		(8.8	)		35.5		-
Forward contracts
Cash flow hedges		577.2		(56.6	)		121.9		21.0
Non-hedging derivatives		214.1		(30.1	)		178.3		3.6
Forward starting swap
Cash flow hedges		225.0		(0.8	)		-		-
Interest rate swaps
Fair value hedges		146.5		(2.2	)		146.5		(2.6	)
Consolidated KCP&L
Forward contracts
Cash flow hedges		5.2		(0.1	)		-		-
Forward starting swap
Cash flow hedges		225.0		(0.8	)		-		-
Interest rate swaps
Fair value hedges		146.5		(2.2	)		146.5		(2.6	)

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


	Great Plains Energy						Consolidated KCP&L
	September 30			December 31			September 30			December 31
	2006			2005			2006			2005
	(millions)
Current assets	$	10.4		$	35.8		$	11.6		$	11.9
Other deferred charges		-			11.8			(0.8	)		-
Other current liabilities		(44.2	)		1.6			-			-
Deferred income taxes		30.3			(20.5	)		(4.1	)		(4.5	)
Other deferred credits		(39.0	)		1.0			-			-
Total	$	(42.5	)	$	29.7		$	6.7		$	7.4

Great Plains Energy’s accumulated OCI includes $44.3 million that is expected to be reclassified to expense over the next twelve months. Consolidated KCP&L’s accumulated OCI includes an insignificant amount that is expected to be reclassified to expense over the next twelve months.

The amounts reclassified to expenses are summarized in the following table.


	Three Months Ended						Year to Date
	September 30						September 30
	2006			2005			2006			2005
Great Plains Energy	(millions)
Fuel expense	$	-		$	(0.5	)	$	-		$	(0.5	)
Purchased power expense		13.0			(21.1	)		29.6			(27.2	)
Interest expense		(0.1	)		-			(0.3	)		-
Income taxes		(5.3	)		8.9			(12.2	)		11.6
OCI	$	7.6		$	(12.7	)	$	17.1		$	(16.1	)
Consolidated KCP&L
Fuel expense	$	-		$	(0.5	)	$	-		$	(0.5	)
Interest expense		(0.1	)		-			(0.3	)		-
Income taxes		-			0.2			0.1			0.2
OCI	$	(0.1	)	$	(0.3	)	$	(0.2	)	$	(0.3	)

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

The MD&A that follows is a combined presentation for Great Plains Energy and consolidated KCP&L, both registrants under this filing. The discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of the registrants during the periods presented.

Great Plains Energy is a public utility holding company and does not own or operate any significant assets other than the stock of its subsidiaries. Great Plains Energy’s direct subsidiaries with operations or active subsidiaries are KCP&L, KLT Inc., IEC and Services. As a diversified energy company, Great Plains Energy’s reportable business segments include KCP&L and Strategic Energy.

EXECUTING ON STRATEGIC INTENT

KCP&L’s Comprehensive Energy Plan

KCP&L Regulatory Proceedings

if not approved in its entirety. KCP&L expects KCC to act on the Agreement before the end of the year with any rate changes being effective on January 1, 2007.

KCP&L BUSINESS OVERVIEW

KCP&L is an integrated, regulated electric utility that engages in the generation, transmission, distribution and sale of electricity. KCP&L has over 4,000 MWs of generating capacity and has transmission and distribution facilities that provide electricity to slightly over 500,000 customers in the states of Missouri and Kansas. KCP&L has continued to experience modest load growth. Load growth consists of higher usage per customer and the addition of new customers. Retail electricity rates are below the national average.

KCP&L’s residential customers’ usage is significantly affected by weather. Bulk power sales, the major component of wholesale sales, vary with system requirements, generating unit and purchased power availability, fuel costs and requirements of other electric systems. Less than 1% of revenues include an automatic fuel adjustment provision. KCP&L’s coal base load equivalent availability factor was 88% for the three months ended and 82% year to date September 30, 2006, compared to 82% and 80% for the same periods in 2005.

KCP&L’s nuclear unit, Wolf Creek, accounts for approximately 20% of its base load capacity. In the third quarter of 2006, WCNOC submitted an application for a new operating license for Wolf Creek with the NRC, which would extend Wolf Creek’s operating period to 2045. Wolf Creek’s latest refueling outage began in early October 2006 and is currently expected to last approximately 30 days. The next refueling outage is scheduled to begin in March 2008.

The owners of Wolf Creek have on hand or under contract all of the uranium and conversion services needed to operate Wolf Creek through March 2011 and approximately 75% after that date through September 2018. The owners also have under contract 100% of the uranium enrichment required to operate Wolf Creek through March 2008. A non-binding letter of intent has been issued with a supplier for a substantial portion of Wolf Creek’s uranium enrichment requirements extending through at least 2024. Fabrication requirements are under contract through 2024. Management expects its cost of nuclear fuel to remain relatively stable through 2009 because of contracts in place. Between 2010 and 2018, management anticipates the cost of nuclear fuel to increase approximately 30% to 50% due to higher contracted prices and market conditions. Even with this anticipated increase, management expects nuclear fuel cost per MWh generated to remain less than the cost of other fuel sources.

The fuel cost per MWh generated and the purchased power cost per MWh has a significant impact on the results of operations for KCP&L. Generation fuel mix can substantially change the fuel cost per MWh generated. Nuclear fuel cost per MWh generated is substantially less than the cost of coal per

MWh generated, which is significantly lower than the cost of natural gas and oil per MWh generated. The cost per MWh for purchased power is significantly higher than the cost per MWh of coal and nuclear generation. KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply and purchased power, and the requirements of other electric systems to provide reliable power economically.

Rail companies have experienced longer cycle times for coal deliveries to utilities across the country since 2004. Approximately 98% of KCP&L��s coal requirements come from the PRB and originate on the Burlington Northern Santa Fe and the Union Pacific railroads, both of which have been affected by the current rail situation. Maintenance to repair significant sections of track on this rail line began in 2005 and is expected to be completed by the end of 2006. These repairs must be completed before normal train operations from the PRB can resume, which affects all users of PRB coal. Year to date coal shipments have improved significantly compared to deliveries experienced in 2005 and as a result, inventory levels have improved. KCP&L has suspended its coal conservation measures, implemented in 2005, of reducing coal generation. Management is monitoring the situation closely and steps will be taken, as necessary, to maintain an adequate energy supply for KCP&L’s retail load and firm MWh sales. However, an inability to obtain timely delivery of coal to meet generation requirements in the future could materially impact KCP&L’s results of operations by increasing its cost to serve its retail customers and/or reducing wholesale MWh sales.

STRATEGIC ENERGY BUSINESS OVERVIEW

Great Plains Energy indirectly owns 100% of Strategic Energy. Strategic Energy does not own any generation, transmission or distribution facilities. Strategic Energy provides competitive retail electricity supply services by entering into power supply contracts to supply electricity to its end-use customers. Of the states that offer retail choice, Strategic Energy operates in California, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas. Strategic Energy has begun expansion into Illinois, as well as additional utility territories in New York. Deliveries in Illinois are expected to begin in December 2006.

In addition to competitive retail electricity supply services, Strategic Energy also provides strategic planning, consulting and billing and scheduling services in the natural gas and electricity markets. The cost of supplying electric service to retail customers can vary widely by geographic market. This variability can be affected by many factors, including, but not limited to, geographic differences in the cost per MWh of purchased power, renewable energy requirements and capacity charges due to regional purchased power availability and requirements of other electricity providers and differences in transmission charges.

Strategic Energy provides services to approximately 70,400 commercial, institutional and small manufacturing accounts for approximately 20,900 customers including numerous Fortune 500 companies, smaller companies and governmental entities. Strategic Energy offers an array of products, including fixed price, index-based and month-to-month renewal products, designed to meet the various requirements of a diverse customer base. Strategic Energy’s volume-based customer retention rate, excluding month-to-month customers on market-based rates, was 58% for the three months ended and 53% year to date September 30, 2006. The corresponding volume-based customer retention rates including month-to-month customers on market-based rates were 80% and 66%, respectively. Retention rates year to date September 30, 2006, are lower than Strategic Energy has experienced. The decline is attributable to customer contract expirations in midwestern states where the savings competitive suppliers can offer to customers are reduced or in some cases unavailable due to host utility default rates that are not aligned with market prices for power. In these states, customers can receive lower rates from the host utility and are choosing to return to host utility service as their contracts with Strategic Energy expire. Management expects to have continued difficulty competing in

these states until more competitive market-driven pricing mechanisms are in place or market prices for power decrease below host utility rates.

Management has repositioned sales and marketing efforts to focus on states that currently provide a more competitive pricing environment in relation to host utility default rates. In these states, Strategic Energy continues to experience improvement in certain key metrics, including strong forecasted future MWh commitments (backlog) growth and longer contract durations. As a result, total backlog grew to 28.4 million at September 30, 2006, compared to 15.2 million at September 30, 2005, and average contract durations grew to 17 months from 13 months, respectively. Based solely on expected usage under current signed contracts, Strategic Energy has backlog of 4.1 million for the remainder of 2006, 11.2 million and 6.4 million for the years 2007 and 2008, respectively, and 6.7 million for 2009 through 2012. The combination of MWhs delivered through September 30, 2006, and backlog for the remainder of the year is 16.5 million, which is within the previously projected range for 2006 total MWhs delivered of 16 to 18 million. Strategic Energy expects to deliver additional MWhs above amounts currently in backlog through new and renewed term contracts and MWh deliveries to month-to-month customers.

The average retail gross margin per MWh (retail revenues less retail purchased power divided by retail MWhs delivered) reflected in the 11.2 million MWhs of 2007 backlog is projected to be in the range of $4.50 to $5.50. This range excludes unrealized changes in fair value of non-hedging energy contracts and from hedge ineffectiveness because management does not predict the future impact of these unrealized changes. This range is higher than the retail gross margin per MWh for new customer contracts discussed below primarily due to more favorable customer and product mix.

Management continues to expect Strategic Energy’s retail gross margin per MWh on new customer contracts entered into in 2006 to average from $3.00 to $4.00, excluding unrealized changes in fair value of non-hedging energy contracts and from hedge ineffectiveness. Management expects to realize additional retail gross margin on fixed price contracts of up to $0.50 per MWh over the life of the contracts. The additional expected margin is derived from management of the retail portfolio load requirements. These activities include benefits from financial transmission rights and auction revenue rights, short-term load balancing activities, short-term arbitrage activities and identifying and utilizing favorable transmission paths. Actual retail gross margin per MWh may differ from these estimates.

GREAT PLAINS ENERGY RESULTS OF OPERATIONS

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


	Three Months Ended						Year to Date
	September 30						September 30
	2006			2005			2006			2005
	(millions)
Operating revenues	$	818.5		$	782.9		$	2,019.8		$	1,959.7
Fuel		(77.2	)		(73.9	)		(180.8	)		(160.2	)
Purchased power		(467.4	)		(414.8	)		(1,136.2	)		(1,059.8	)
Skill set realignment costs		(1.4	)		-			(15.9	)		-
Other operating expenses		(139.7	)		(126.9	)		(398.5	)		(393.4	)
Depreciation and amortization		(40.4	)		(38.4	)		(118.6	)		(114.5	)
Gain (loss) on property		-			(3.4	)		0.6			(1.9	)
Operating income		92.4			125.5			170.4			229.9
Non-operating income (expenses)		7.7			(1.1	)		11.1			(0.3	)
Interest charges		(18.0	)		(17.9	)		(53.1	)		(53.8	)
Income taxes		(26.5	)		(17.3	)		(36.7	)		(32.4	)
Minority interest in subsidiaries		-			-			-			(7.8	)
Loss from equity investments		(0.4	)		(0.1	)		(1.0	)		(0.8	)
Income from continuing operations		55.2			89.1			90.7			134.8
Discontinued operations		-			1.8			-			(1.8	)
Net income		55.2			90.9			90.7			133.0
Preferred dividends		(0.5	)		(0.5	)		(1.3	)		(1.3	)
Earnings available for common shareholders	$	54.7		$	90.4		$	89.4		$	131.7

Great Plains Energy’s earnings for the three months ended September 30, 2006, decreased to $54.7 million, or $0.68 per share, from $90.4 million, or $1.21 per share, in the same period of 2005. Earnings year to date September 30, 2006, decreased to $89.4 million, or $1.16 per share, from $131.7 million, or $1.77 per share, compared to the same period of 2005.

Consolidated KCP&L’s net income was consistent for the three months ended and increased $8.4 million year to date September 30, 2006, compared to the same periods in 2005. Three months ended and year to date September 30, 2006, was favorably impacted by lower purchased power expense and year to date was favorably impacted by higher wholesale revenues. The year to date increase was partially offset by costs related to skill set realignments and increased fuel expense. Both three months ended and year to date September 30, 2006, reflect higher income taxes due to higher pre-tax income in 2006 and a decrease in 2005 income taxes reflecting a reduction in KCP&L’s deferred tax balances as a result of a reduction in KCP&L’s composite tax rate.

Strategic Energy had a net loss of $10.9 million for the three months ended and $17.6 million year to date September 30, 2006, compared to net income of $18.1 million and $34.6 million for the same periods in 2005, respectively. The net loss was primarily the result of the impact of $26.6 million and $64.5 million, respectively, in changes in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness.

CONSOLIDATED KCP&L RESULTS OF OPERATIONS

The following discussion of consolidated KCP&L results of operations includes KCP&L, an integrated, regulated electric utility and HSS, an unregulated subsidiary of KCP&L. References to KCP&L, in the

discussion that follows, reflect only the operations of the utility. The following table summarizes consolidated KCP&L's comparative results of operations.


	Three Months Ended						Year to Date
	September 30						September 30
	2006			2005			2006			2005
	(millions)
Operating revenues	$	359.3		$	353.0		$	890.6		$	858.4
Fuel		(77.2	)		(73.9	)		(180.8	)		(160.2	)
Purchased power		(5.1	)		(28.3	)		(18.8	)		(56.6	)
Skill set realignment costs		(1.4	)		-			(15.6	)		-
Other operating expenses		(119.9	)		(110.4	)		(348.0	)		(345.0	)
Depreciation and amortization		(38.5	)		(36.7	)		(112.8	)		(109.8	)
Gain (loss) on property		-			(3.6	)		0.6			(3.1	)
Operating income		117.2			100.1			215.2			183.7
Non-operating income (expenses)		6.5			0.4			8.8			9.4
Interest charges		(15.6	)		(15.0	)		(45.5	)		(45.1	)
Income taxes		(39.3	)		(16.6	)		(61.9	)		(32.0	)
Minority interest in subsidiaries		-			-			-			(7.8	)
Net income	$	68.8		$	68.9		$	116.6		$	108.2

Consolidated KCP&L Sales Revenues and MWh Sales


	Three Months Ended							Year to Date
	September 30					%		September 30				%
	2006			2005		Change		2006		2005		Change
Retail revenues	(millions)							(millions)
Residential		$	140.2	$	139.6		1	$	310.4	$	304.6		2
Commercial			140.2		138.3		1		347.7		341.3		2
Industrial			28.7		29.6		(3)		77.6		78.7		(1)
Other retail revenues			2.3		2.0		3		6.7		6.3		3
Total retail			311.4		309.5		1		742.4		730.9		2
Wholesale revenues			43.7		39.3		11		137.4		115.7		19
Other revenues			4.2		4.2		5		10.8		11.7		(7)
KCP&L electric revenues			359.3		353.0		2		890.6		858.3		4
Subsidiary revenues			-		-		-		-		0.1		NM
Consolidated KCP&L revenues		$	359.3	$	353.0		2	$	890.6	$	858.4		4


	Three Months Ended						Year to Date
	September 30				%		September 30				%
	2006		2005		Change		2006		2005		Change
Retail MWh sales	(thousands)						(thousands)
Residential		1,769		1,770		-		4,232		4,173		1
Commercial		2,117		2,116		-		5,654		5,577		1
Industrial		579		602		(4)		1,643		1,660		(1)
Other retail MWh sales		21		20		5		63		60		5
Total retail		4,486		4,508		(1)		11,592		11,470		1
Wholesale MWh Sales		1,058		918		15		3,240		3,166		2
KCP&L electric revenues		5,544		5,426		2		14,832		14,636		1

Retail revenues increased $1.9 million for the three months ended and $11.5 million year to date September 30, 2006, compared to the same periods in 2005. The year to date increase was primarily due to load growth, which consists of higher usage per customer and the addition of new customers.

Wholesale revenues increased $4.4 million for the three months ended September 30, 2006, compared to the same period in 2005 due to a 15% increase in wholesale MWh sales primarily due to greater plant availability. KCP&L’s coal base load equivalent availability factor increased to 88% for the three months ended compared to 82% for the same period in 2005. This increase in wholesale MWh sales was partially offset by a 25% decrease in the average market price per MWh to $37.99. Wholesale revenues increased $21.7 million year to date September 30, 2006, compared to the same period in 2005 primarily due to a 12% increase in the average market price per MWh to $45.09. Additionally, wholesale revenues for the three months ended and year to date September 30, 2006, include $2.5 million in litigation recoveries for the loss of use of Hawthorn No. 5 from a 1999 boiler explosion.

Consolidated KCP&L Fuel and Purchased Power


	Three Months Ended								Year to Date
	September 30					%			September 30				%
		2006		2005		Change			2006		2005		Change
Net MWhs Generated by Fuel Type		(thousands)						(thousands)
Coal			4,067		3,760		8			10,945		11,177		(2)
Nuclear			1,216		1,216		-			3,641		2,910		25
Natural gas and oil			346		356		(3)			522		456		15
Wind			24		-		-			24		-		-
Total Generation			5,653		5,332		6			15,132		14,543		4

Fuel expense increased $3.3 million for the three months ended and $20.6 million year to date September 30, 2006, compared to the same periods in 2005 due to the 6% and 4% increases, respectively, in MWhs generated and increased coal and coal transportation costs offset by $3.7 million in Hawthorn No. 5 litigation recoveries. KCP&L’s current coal and coal transportation contracts, including higher tariff rates being charged by Union Pacific, were entered into at higher average prices than related contracts in the same periods of 2005. KCP&L has filed a rate case complaint against Union Pacific with the STB and until the case is finalized, KCP&L is paying the tariff rates subject to refund. See Note 15 to the consolidated financial statements for more information.

Purchased power expense decreased $23.2 million for the three months ended and $37.8 million year to date September 30, 2006, compared to the same periods in 2005. The decreases were primarily due to recording $10.8 million in Hawthorn No. 5 litigation recoveries as a reduction in purchased power expense and a greater than 50% reduction in MWhs purchased during both periods. The reduction in MWhs purchased was due to uneconomical purchased power prices and increased net MWhs generated. In addition, capacity payments decreased $5.7 million year to date September 30, 2006, due to the expiration of two large contracts in the second quarter of 2005. KCP&L entered into new capacity contracts in June 2006.

In August 2005, Hawthorn No. 5’s generator step-up transformer (GSU) failed. A spare GSU was installed in September 2005; however, the size of the spare GSU limited the net capacity of the unit to 500 MW. During June 2006, a new GSU was installed at Hawthorn No. 5 returning its net capacity to 563 MW. The outage for the installation lasted 14 days.

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

Consolidated KCP&L's other operating expenses increased $9.5 million for the three months ended September 30, 2006, compared to the same period in 2005. This increase reflects a decrease in other operating expenses in the three months ended September 30, 2005, due to the regulatory accounting treatment of pension costs effective January 1, 2005, which reduced pension expense by $5.6 million related to the first six months of 2005.

Consolidated KCP&L Skill Set Realignment and Pension Settlement Charges

In 2005 and early 2006, management undertook a process to assess, improve and reposition the skill sets of employees for implementation of the comprehensive energy plan. KCP&L recorded $9.4 million year to date September 30, 2006, related to this workforce realignment process reflecting severance, benefits and related payroll taxes provided by KCP&L to employees. Management has been filling positions with the specific skill sets and talent needed to achieve KCP&L’s goals. Management believes that the realignment allows for optimization of employee levels and avoids future additional expense. For the three months ended and year to date September 30, 2006, KCP&L incurred $2.0 million and $9.3 million of pension settlement charges associated with the realignment resulting in $1.4 million and $6.2 million, respectively, of expense recorded after amounts capitalized and billed to joint owners of power plants. The pension settlement charges were a result of the number of employees retiring and selecting the lump-sum payment option.

Potential Future Pension Settlement Charges

Through 2010, approximately 21% of KCP&L’s current employees are eligible to retire with full pension benefits. The timing and number of employees retiring and selecting the lump-sum payment option could result in additional settlement charges that could materially affect KCP&L’s results of operations after 2006. If KCP&L receives its requested regulatory treatment, pension settlement charges would be deferred and amortized over five years beginning with the effective date of rates approved in KCP&L’s next rate case.

Consolidated KCP&L Income Taxes

Consolidated KCP&L's income taxes increased $22.7 million for the three months ended and $29.9 million year to date September 30, 2006, compared to the same periods of 2005 due to an increase in pre-tax income in 2006 and a decrease in 2005 of $11.7 million due to the impact of a lower composite tax rate on KCP&L’s deferred tax balances resulting from the favorable impact of sustained audit positions.

STRATEGIC ENERGY RESULTS OF OPERATIONS

The following table summarizes Strategic Energy's comparative results of operations.


	Three Months Ended						Year to Date
	September 30						September 30
	2006			2005			2006			2005
	(millions)
Operating revenues	$	459.2		$	429.9		$	1,129.2		$	1,101.3
Purchased power		(462.3	)		(386.5	)		(1,117.4	)		(1,003.2	)
Other operating expenses		(16.6	)		(14.3	)		(42.5	)		(37.6	)
Depreciation and amortization		(1.9	)		(1.6	)		(5.8	)		(4.6	)
Operating income (loss)		(21.6	)		27.5			(36.5	)		55.9
Non-operating income (expenses)		1.1			0.7			3.0			1.8
Interest charges		(0.6	)		(0.7	)		(1.5	)		(2.2	)
Income taxes		10.2			(9.4	)		17.4			(20.9	)
Net income (loss)	$	(10.9	)	$	18.1		$	(17.6	)	$	34.6

Retail MWhs delivered decreased 12% to 4.8 million for the three months ended and 18% to 12.4 million year to date September 30, 2006, compared to the same periods in 2005 due to the effect of market conditions in midwestern states and competition in other markets where Strategic Energy serves customers. The average retail gross margin per MWh declined to $(0.79) for the three months ended and $0.78 year to date September 30, 2006, compared to $7.84 and $6.29 for the same periods in 2005. The decline in the average retail gross margin per MWh for the three months ended and year to date was primarily due to the impact of $26.6 million and $64.5 million, respectively, in changes in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness.


	Three Months Ended				Year to Date
	September 30				September 30
	2006		2005		2006		2005
Average retail gross margin per MWh	$	(0.79)	$	7.84	$	0.78	$	6.29
Change in fair value related to non-hedging energy
contracts and from cash flow hedge ineffectiveness		5.60		(3.36)		5.21		(1.71)
Average retail gross margin per MWh without
fair value impacts	$	4.81	$	4.48	$	5.99	$	4.58

Average retail gross margin per MWh without fair value impacts is a non-GAAP financial measure that differs from GAAP because it excludes the impact of unrealized fair value gains or losses. Management and the Board of Directors use this as a measurement of Strategic Energy’s realized retail gross margin per delivered MWh, which are settled upon delivery at contracted prices. Fair value impacts result from changes in fair value of non-hedging energy contracts and from hedge ineffectiveness associated with MWhs under contract but not yet delivered. Due to their non-cash nature and volatility during periods prior to delivery, management believes excluding these fair value impacts results in a measure of retail gross margin per MWh that is more representative of contracted prices.

As detailed in the table above, average retail gross margin per MWh without the impact of unrealized fair value gains and losses increased to $4.81 for the three months ended and $5.99 year to date September 30, 2006, compared to $4.48 and $4.58 for the same periods in 2005. The increases for the three months ended and year to date September 30, 2006, were primarily due to the net impact of SECA recoveries and charges as compared to the same periods of 2005. The net SECA impact was

insignificant for the three months ended and increased average retail gross margin per MWh year to date September 30, 2006, by $0.08. During 2005, the net SECA impact decreased average retail gross margin per MWh by $0.18 and $0.54, respectively. Strategic Energy recorded SECA charges in excess of recoveries of $1.0 million for the three months ended and $8.2 million year to date September 30, 2005. Additional impacts to the average retail gross margin per MWh included increases primarily due to the management of retail portfolio load requirements, favorable product mix and settlements of supplier contracts. The increases were partially offset by higher customer acquisition costs in 2006. Additionally, the year to date increase was partially offset by a $1.2 million reduction of a gross receipts tax contingency in the first quarter of 2005.

Strategic Energy Purchased Power

Purchased power is the cost component of Strategic Energy’s average retail gross margin. Strategic Energy purchases electricity from power suppliers based on forecasted peak demand for its retail customers. Actual customer demand does not always equate to the volume purchased based on forecasted peak demand. Consequently, Strategic Energy makes short-term power purchases in the wholesale market when necessary to meet actual customer requirements. Strategic Energy also sells any excess retail electricity supply over actual customer requirements back into the wholesale market. These sales occur on many contracts, are usually short-term power sales (day ahead) and typically settle within the reporting period. Excess retail electricity supply sales also include long-term and short-term forward physical sales to wholesale counterparties, which are accounted for on a mark-to-market basis. Strategic Energy typically executes these transactions to manage basis and credit risks. The proceeds from excess retail supply sales are recorded as a reduction of purchased power, as they do not represent the quantity of electricity consumed by Strategic Energy’s customers. The amount of excess retail supply sales that reduced purchased power was $1.6 million for the three months ended and $67.0 million year to date September 30, 2006, compared to $48.1 million and $91.8 million for the same periods of 2005. Additionally, in certain markets, load-serving entities are required to sell to and purchase power from a RTO/ISO rather than directly transact with suppliers and end use customers. The sale and purchase activity related to these certain RTO/ISO markets is reflected on a net basis in Strategic Energy’s purchased power.

Strategic Energy utilizes derivative instruments, including forward physical delivery contracts, in the procurement of electricity. Purchased power is also impacted by the net change in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness. Net changes in fair value increased purchased power expenses by $26.6 million for the three months ended and $64.5 million year to date September 30, 2006, compared to reductions of $18.2 million and $26.0 million for the same periods in 2005. The increase in purchased power expense for the three months ended and year to date September 30, 2006, is a result of decreases in the forward market prices for power combined with Strategic Energy designating more derivative instruments as cash flow hedges that no longer quality for the NPNS election. See Note 18 to the consolidated financial statements for more information.

OTHER NON-REGULATED ACTIVITIES

Other non-regulated activities include the impact of investments in affordable housing limited partnerships discussed below. Additionally, other non-regulated net loss from continuing operations increased $5.1 million for the three months ended and $1.6 million year to date September 30, 2006, compared to the same periods in 2005. The three months ended and year to date September 30, 2005, net loss was favorably impacted by a $5.0 million net release of tax contingency reserves. This 2005 favorable impact was mostly offset year to date September 30, 2006, due to lower operating expenses as a result of Services transferring approximately 80% of its employees to KCP&L in the third quarter of 2005 to better align resources with the operating business.

Investment in Affordable Housing Limited Partnerships - KLT Investments

KLT Investments Inc.’s (KLT Investments) net income for the three months ended September 30, 2006, totaled $1.2 million (including no after-tax reduction in its affordable housing investment) compared to net income of $1.9 million for the three months ended September 30, 2005 (including an after tax reduction of $0.9 million in its affordable housing investment). KLT Investments’ net income included accrued tax credits related to its investments in affordable housing limited partnerships of $2.2 million and $3.7 million for the three months ended September 30, 2006 and 2005, respectively. Net income year to date September 30, 2006, totaled $3.3 million (including an after tax reduction of $0.7 million in its affordable housing investment) compared to net income of $2.4 million year to date September 30, 2005 (including an after tax reduction of $6.2 million in its affordable housing investment). KLT Investments’ net income included accrued tax credits of $6.8 million and $11.5 million year to date September 30, 2006 and 2005, respectively.

At September 30, 2006, KLT Investments had $24.5 million in affordable housing limited partnerships. Approximately 63% of these investments were recorded at cost; the equity method was used for the remainder. Tax expense is reduced in the year tax credits are generated. The investments generate future cash flows from tax credits and tax losses of the partnerships. The investments also generate cash flows from sales of the properties. For most investments, tax credits are received over ten years. A change in accounting principle relating to investments made after May 19, 1995, requires the use of the equity method when a company owns more than 5% in a limited partnership investment. Of the investments recorded at cost, $15.1 million exceed this 5% level but were made before May 19, 1995. Management does not anticipate making additional investments in affordable housing limited partnerships at this time.

On a quarterly basis, KLT Investments compares the cost of properties accounted for by the cost method to the total of projected residual value of the properties and remaining tax credits to be received. Based on the latest comparison, KLT Investments did not reduce its investments in affordable housing limited partnerships for the three months ended and recorded a $1.2 million reduction year to date September 30, 2006, compared to $1.4 million and $10.0 million for the three months ended and year to date September 30, 2005. Pre-tax reductions in affordable housing investments are estimated to be insignificant for the remainder of 2006 and $2 million for 2007. These projections are based on the latest information available but the ultimate amount and timing of actual reductions could be significantly different from the above estimates. Even after these estimated reductions, net income from the investments in affordable housing is expected to be positive for 2006 through 2008. The properties underlying the partnership investment are subject to certain risks inherent in real estate ownership and management.

GREAT PLAINS ENERGY AND CONSOLIDATED KCP&L Significant Balance Sheet Changes (September 30, 2006 compared to December 31, 2005)

Great Plains Energy’s and consolidated KCP&L’s receivables increased $96.5 million and $52.0 million, respectively. KCP&L’s receivables increased $23.6 million due to seasonal increases from higher summer tariff rates and usage and $22.4 million due to additional receivables from joint owners of comprehensive energy plan projects. Strategic Energy’s receivables increased $47.0 million due to seasonal increases in MWh deliveries and more customers billed on higher index-based rates.

·	Great Plains Energy’s and consolidated KCP&L’s fuel inventories increased $8.2 million primarily due to a $7.8 million increase in coal inventory as a result of planned plant outages, improved railroad performance in delivering coal and an increase in coal and coal transportation costs.

Great Plains Energy’s combined deferred income taxes - current assets and deferred income taxes - current liabilities changed from a liability of $1.3 million at December 31, 2005, to an asset of $46.3 million. The temporary differences due to the change in the fair value of Strategic Energy’s energy-related derivative instruments increased the asset $39.0 million. Consolidated KCP&L’s deferred income taxes - current assets increased $2.3 million primarily due to the timing of the Wolf Creek refueling outage.

Great Plains Energy’s derivative instruments, including current and deferred assets and liabilities, decreased $191.8 million from a net asset at December 31, 2005, to a net liability at September 30, 2006, primarily due to a $191.4 million decrease in the fair value of Strategic Energy’s energy-related derivative instruments as a result of decreases in the forward market prices for power combined with Strategic Energy designating more derivative instruments as cash flow hedges that no longer quality for the NPNS election.

Great Plains Energy’s and consolidated KCP&L’s combined electric utility plant and construction work in progress increased $323.7 million primarily due to $232.2 million related to KCP&L’s comprehensive energy plan, including $161.2 million for wind generation, $41.0 million for environmental upgrades and $30.0 million related to Iatan No. 2. Additionally, purchases of automated meter reading equipment for $13.8 million and rail cars for $23.4 million as well as $10.2 million in upgrades to a transmission line increased electric utility plant.

Great Plains Energy’s and consolidated KCP&L’s regulatory assets increased $27.5 million primarily due to the regulatory accounting treatment for pension expense and the change in Wolf Creek depreciable life for regulatory purposes in accordance with MPSC and KCC orders, which combined increased the asset $35.4 million. This increase was partially offset by an $8.2 million reduction in the regulatory asset related to the asset retirement obligation for decommissioning of Wolf Creek as a result of filing for a new 40-year operating license.

·	Great Plains Energy’s and consolidated KCP&L’s prepaid pension costs decreased $27.5 million and $27.2 million, respectively, due to 2006 pension expense accruals, including pension settlement charges of $8.6 million, in excess of contributions.

·	Great Plains Energy’s and consolidated KCP&L’s commercial paper increased $48.7 million primarily to support expenditures related to the comprehensive energy plan.

Great Plains Energy’s and consolidated KCP&L’s accrued taxes increased $60.3 million and $71.9 million, respectively, primarily due to the timing of annual property tax payments and income taxes currently payable due to year to date September 30, 2006, taxable income, partially offset by a third quarter 2006 income tax payment.

Great Plains Energy’s and consolidated KCP&L’s asset retirement obligations decreased $54.8 million due to a $65.0 million decrease for the decommissioning of Wolf Creek as a result of filing for a new operating license. This decrease was partially offset by a $3.1 million addition for the Spearville Wind Energy Facility and $7.1 million for accretion.

Great Plains Energy’s and consolidated KCP&L’s regulatory liabilities increased $37.9 million due to a $31.0 million increase in KCP&L’s regulatory liability related to the asset retirement obligation for decommissioning of Wolf Creek as a result of filing for a new operating license and amortization of $7.7 million related to the change in Wolf Creek depreciable life for regulatory purposes in accordance with an MPSC order.

Great Plains Energy’s accumulated other comprehensive loss increased $72.1 million primarily due to changes in the fair value of Strategic Energy’s energy related derivative instruments resulting from decreases in the forward market prices for power combined with Strategic Energy designating more derivative instruments as cash flow hedges that no longer quality for the NPNS election.

Great Plains Energy’s long-term debt decreased $388.6 million primarily to reflect FELINE PRIDES Senior Notes and consolidated KCP&L’s $225.0 million 6.00% Senior Notes as current maturities. Current maturities of long-term debt for the respective companies increased as a result of these classifications.

CAPITAL REQUIREMENTS AND LIQUIDITY

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

Great Plains Energy’s capital requirements are principally comprised of KCP&L’s utility construction and other capital expenditures, debt maturities and credit support provided to Strategic Energy. These items as well as additional cash and capital requirements for the companies are discussed below.

Great Plains Energy's liquid resources at September 30, 2006, consisted of $59.3 million of cash and cash equivalents on hand, including $0.4 million at consolidated KCP&L, and $858.0 million of unused bank lines of credit. The unused lines consisted of $319.4 million from KCP&L's revolving credit facility, $64.1 million from Strategic Energy’s revolving credit facility and $474.5 million from Great Plains Energy's revolving credit facility. See the Debt Agreements section below for more information on these agreements. At October 31, 2006, Great Plains Energy's unused bank lines of credit increased $35.8 million from the amount at September 30, 2006, due to a $16.2 million increase at consolidated KCP&L primarily due to the repayment of commercial paper and a $19.6 million increase due to less letters of credit outstanding.

KCP&L currently expects to fund its comprehensive energy plan from a combination of internal and external sources including, but not limited to, contributions from rate increases, capital contributions to KCP&L from Great Plains Energy's proceeds of equity issuances, including FELINE PRIDES equity to be issued in 2007, new short and long-term debt financing and internally generated funds.

KCP&L expects to meet day-to-day cash flow requirements including interest payments, construction requirements (excluding its comprehensive energy plan), dividends to Great Plains Energy and pension benefit plan funding requirements, discussed below, with internally generated funds. KCP&L might not be able to meet these requirements with internally generated funds because of the effect of inflation on operating expenses, the level of MWh sales, regulatory actions, compliance with future environmental regulations and the availability of generating units. The funds Great Plains Energy and consolidated KCP&L need to retire maturing debt will be provided from operations, the issuance of long and short-term debt and/or the issuance of equity or equity-linked instruments. In addition, the Company may issue debt, equity and/or equity-linked instruments to finance growth or take advantage of new opportunities.

Strategic Energy expects to meet day-to-day cash flow requirements including interest payments, credit support fees, capital expenditures and dividends to Great Plains Energy with internally generated funds. Strategic Energy might not be able to meet these requirements with internally generated funds

because of the effect of inflation on operating expenses, the level of MWh sales, seasonal working capital requirements, commodity-price volatility and the effects of counterparty non-performance.

Cash Flows from Operating Activities

Great Plains Energy and consolidated KCP&L generated positive cash flows from operating activities for the periods presented. The decrease in cash flows from operating activities for Great Plains Energy and consolidated KCP&L year to date September 30, 2006, compared to the same period in 2005 was primarily due to KCP&L’s sales of SO₂emission allowances during 2005 resulting in proceeds of $31.0 million. The timing of the Wolf Creek outage affects the refueling outage accrual, deferred income taxes and amortization of nuclear fuel. Other changes in working capital detailed in Note 4 to the consolidated financial statements also impacted operating cash flows. The individual components of working capital vary with normal business cycles and operations.

Cash Flows from Investing Activities

Great Plains Energy’s and consolidated KCP&L’s cash used for investing activities varies with the timing of utility capital expenditures and purchases of investments and nonutility property. Investing activities are offset by the proceeds from the sale of properties and insurance recoveries. Great Plains Energy’s and consolidated KCP&L’s utility capital expenditures increased $110.5 million and $105.7 million, respectively, year to date September 30, 2006, compared to the same period of 2005 primarily due to KCP&L’s cash utility capital expenditures including $175.1 million related to KCP&L’s comprehensive energy plan, $10.2 million to upgrade a transmission line, $13.8 million to purchase automated meter reading equipment and $23.4 million to purchase rail cars. KCP&L’s year to date September 30, 2005, capital expenditures included the exercise of its early termination option in the combustion turbine synthetic lease to purchase the leased property for $154.0 million. Additionally in 2006, KCP&L received $15.8 million of litigation recoveries related to Hawthorn No. 5, which were partially offset by $10.0 million of insurance recoveries received in 2005.

Cash Flows from Financing Activities

The change in Great Plains Energy’s cash flows from financing activities year to date September 30, 2006, compared to the same period in 2005 reflects Great Plains Energy’s May 2006 proceeds of $144.3 million from the issuance of 5.2 million shares of common stock at $27.50 per share. Fees related to this issuance were $5.2 million. Great Plains Energy used the proceeds to make a $134.6 million equity contribution to KCP&L. Additionally, Great Plains Energy and consolidated KCP&L’s net cash from financing activities in 2006 increased due to an increase in KCP&L’s commercial paper primarily to support expenditures related to the comprehensive energy plan. Consolidated KCP&L’s net cash from financing activities also increased due to an $18.7 million decrease in dividends paid to Great Plains Energy.

Significant Financing Activities

Great Plains Energy filed a shelf registration statement with the SEC in May 2006 relating to Senior Debt Securities, Subordinated Debt Securities, shares of Common Stock, Warrants, Stock Purchase Contracts and Stock Purchase Units. In May 2006, Great Plains Energy issued 5.2 million shares of common stock at $27.50 per share under this registration statement with $144.3 million in gross proceeds and issuance costs of $5.2 million.

forward sale agreement, Great Plains Energy will receive an amount equal to $26.6062 per share, plus interest based on the federal funds rate less a spread and less certain scheduled decreases if Great Plains Energy elects to physically settle the forward sale agreement by delivering solely shares of common stock. In most circumstances, Great Plains Energy also has the right, in lieu of physical settlement, to elect cash or net physical settlement.

Great Plains Energy’s FELINE PRIDES senior notes must be remarketed by February 16, 2007. During October 2006, Great Plains Energy entered into a T-Lock to hedge against interest rate fluctuations on the U.S. Treasury rate component of $77.6 million of the FELINE PRIDES senior notes. The T-Lock will be settled simultaneously with the issuance of the long-term fixed rate debt and is accounted for as a cash flow hedge.

KCP&L’s long-term financing activities are subject to the authorization of the MPSC. In November 2005, the MPSC authorized KCP&L to issue up to $635.0 million of long-term debt and to enter into interest rate hedging instruments in connection with such debt through December 31, 2009. KCP&L utilized $250.0 million of this amount with the issuance of its 6.05% unsecured senior notes maturing in 2035 leaving $385.0 million of authorization remaining. Under stipulations with the MPSC and KCC, Great Plains Energy and KCP&L maintain common equity at not less than 30% and 35%, respectively, of total capitalization.

During 2006, FERC authorized KCP&L to issue up to a total of $600.0 million in outstanding short-term debt instruments through February 2008. The authorizations are subject to four restrictions: (i) proceeds of debt backed by utility assets must be used for utility purposes; (ii) if any utility assets that secure authorized debt are divested or spun off, the debt must follow the assets and also be divested or spun off; (iii) if any proceeds of the authorized debt are used for non-utility purposes, the debt must follow the non-utility assets (specifically, if the non-utility assets are divested or spun off, then a proportionate share of the debt must follow the divested or spun off non-utility assets); and (iv) if utility assets financed by the authorized short-term debt are divested or spun off to another entity, a proportionate share of the debt must also be divested or spun off.

During 2006, KCP&L entered into two Forward Starting Swaps with a combined notional principal amount of $225.0 million to effectively remove most of the interest rate and credit spread uncertainty with respect to the anticipated refinancing of KCP&L’s $225.0 million senior notes that mature in March 2007. See Note 18 to the consolidated financial statements for more information.

In 2006, KCP&L completed an exchange of $250.0 million privately placed notes for $250.0 million registered 6.05% unsecured senior notes maturing in 2035 to fulfill its obligations under a 2005 registration rights agreement.

Debt Agreements

During 2006, Great Plains Energy entered into a five-year $600 million revolving credit facility with a group of banks. The facility replaced a $550 million revolving credit facility with a group of banks. A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $25.0 million is a default under the facility. Under the terms of this agreement, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At September 30, 2006, the Company was in compliance with this covenant. At September 30, 2006, Great Plains Energy had no cash borrowings and had issued letters of credit totaling $125.5 million under the credit facility as credit support for Strategic Energy.

During 2006, KCP&L entered into a five-year $400 million revolving credit facility with a group of banks to provide support for its issuance of commercial paper and other general corporate purposes. Great

Plains Energy and KCP&L may transfer and re-transfer up to $200 million of unused lender commitments between Great Plains Energy’s and KCP&L’s facilities, so long as the aggregate lender commitments under either facility does not exceed $600 million and the aggregate lender commitments under both facilities does not exceed $1 billion. The facility replaced a $250 million revolving credit facility with a group of banks. A default by KCP&L on other indebtedness totaling more than $25.0 million is a default under the facility. Under the terms of the agreement, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At September 30, 2006, KCP&L was in compliance with this covenant. At September 30, 2006, KCP&L had $80.6 million of commercial paper outstanding, at a weighted-average interest rate of 5.48% and no cash borrowings under the facility.

Strategic Energy has a $135 million revolving credit facility with a group of banks that expires in June 2009. So long as Strategic Energy is in compliance with the agreement, it may increase this amount by up to $15 million by increasing the commitment of one or more lenders that have agreed to such increase, or by adding one or more lenders with the consent of the administrative agent. In October 2006, Great Plains Energy, as permitted by the terms of the agreement, requested and received a reduction in its guarantee of this facility to a maximum amount of $12.5 million and has guaranteed the $12.5 million. The facility contains a MAC clause that requires Strategic Energy to represent, prior to receiving funding, that no MAC has occurred. A default by Strategic Energy on other indebtedness, as defined in the facility, totaling more than $7.5 million is a default under the facility. Under the terms of this agreement, Strategic Energy is required to maintain a minimum net worth of $75.0 million, a minimum fixed charge coverage ratio of at least 1.05 to 1.00 and a minimum debt service coverage ratio of at least 4.00 to 1.00, as those terms are defined in the agreement. In addition, under the terms of this agreement, Strategic Energy is required to maintain a maximum funded indebtedness to EBITDA ratio, as defined in the agreement, of 3.00 to 1.00, on a quarterly basis through June 30, 2007, and 2.75 to 1.00 thereafter. In the event of a breach of one or more of these four covenants, so long as no other default has occurred, Great Plains Energy may cure the breach through a cash infusion, a guarantee increase or a combination of the two. At September 30, 2006, Strategic Energy was in compliance with these covenants. At September 30, 2006, $70.9 million in letters of credit had been issued and there were no cash borrowings under the agreement.

Great Plains Energy has agreements with KLT Investments associated with notes KLT Investments issued to acquire its affordable housing investments. Great Plains Energy has agreed not to take certain actions including, but not limited to, merging, dissolving or causing the dissolution of KLT Investments, or withdrawing amounts from KLT Investments if the withdrawals would result in KLT Investments not being in compliance with minimum net worth and cash balance requirements. The agreements also give KLT Investments’ lenders the right to have KLT Investments repurchase the notes if Great Plains Energy’s senior debt rating falls below investment grade or if Great Plains Energy ceases to own at least 80% of KCP&L’s stock. At September 30, 2006, KLT Investments had $1.7 million in outstanding notes, including current maturities.

KCP&L Projected Utility Capital Expenditures

KCP&L's utility capital expenditure plan is subject to continual review and change and includes utility capital expenditures related to KCP&L's comprehensive energy plan for environmental investments and new capacity. Although control budgets and workflow scheduling are not complete, developing market conditions indicate overall cost estimates of the comprehensive energy plan are currently expected to be about 20% above the estimate in the 2005 Form 10-K. The primary drivers are increases in materials and labor costs due to a substantial increase in market demand for these materials and services. Actual costs could be materially different than the current estimates; however, management is confident that project costs will be competitive with other similar projects built in the same timeframe.

Pensions

The Company maintains defined benefit plans for substantially all employees of KCP&L, Services and WCNOC and incurs significant costs in providing the plans, with the majority incurred by KCP&L. At a minimum, plans are funded on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants consistent with the funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and further contributions may be made when deemed financially advantageous.

Year to date September 30, 2006, the Company has contributed $18.6 million to the plans and expects to contribute an additional $1.2 million during the remainder of 2006, all of which will be paid by KCP&L. Management believes the Company has adequate access to capital resources through cash flows from operations or through existing lines of credit to support the funding requirements.

Participants in the plans may request a lump-sum cash payment upon termination of their employment. A change in payment assumptions, including the amount and timing of lump-sum distributions, could result in increased cash requirements from pension plan assets with the Company being required to accelerate future funding. Under the terms of the pension plans, the Company reserves the right to amend or terminate the plans, and from time to time benefits have changed.

Strategic Energy Supplier Concentration and Credit

Strategic Energy enters into forward physical contracts with multiple suppliers. At September 30, 2006, Strategic Energy’s five largest suppliers under forward supply contracts represented 70% of the total future dollar committed purchases. Four of Strategic Energy’s five largest suppliers, or their guarantors, are rated investment grade; and the non-investment grade rated supplier collateralizes its position with Strategic Energy. In the event of supplier non-delivery or default, Strategic Energy’s results of operations could be affected to the extent the cost of replacement power exceeded the combination of the contracted price with the supplier and the amount of collateral held by Strategic Energy to mitigate its credit risk with the supplier. In addition to the collateral, if any, that the supplier provides, Strategic Energy’s risk may be further mitigated by the obligation of the supplier to make a default payment equal to the shortfall and to pay liquidated damages in the event of a failure to deliver power. There is no assurance that the supplier in such an instance would make the default payment and/or pay liquidated damages. Strategic Energy’s results of operations and financial position could also be affected, in a given period, if it were required to make a payment upon termination of a supplier contract to the extent the contracted price with the supplier exceeded the market value of the contract at the time of termination.

The following tables provide information on Strategic Energy’s credit exposure to suppliers, net of collateral, at September 30, 2006.


							Number Of		Net Exposure Of
							Counterparties		Counterparties
	Exposure						Greater Than		Greater Than
	Before Credit		Credit		Net		10% Of Net		10% of Net
Rating	Collateral		Collateral		Exposure		Exposure		Exposure
External rating			(millions)						(millions)
Investment Grade	$	4.2	$	-	$	4.2		3		$	4.2
Non-Investment Grade		3.8		3.8		-		-			-
Internal rating
Investment Grade		0.2		-		0.2		-			-
Non-Investment Grade		1.0		0.6		0.4		-			-
Total	$	9.2	$	4.4	$	4.8		3		$	4.2


Maturity Of Credit Risk Exposure Before Credit Collateral
	Less Than				Total
Rating	2 Years		2 - 5 Years		Exposure
External rating	(millions)
Investment Grade	$	4.2	$	-	$	4.2
Non-Investment Grade		(0.3)		4.1		3.8
Internal rating
Investment Grade		0.2		-		0.2
Non-Investment Grade		(0.3)		1.3		1.0
Total	$	3.8	$	5.4	$	9.2

External ratings are determined by using publicly available credit ratings of the counterparty. If a counterparty has provided a guarantee by a higher rated entity, the determination has been based on the rating of its guarantor. Internal ratings are determined by, among other things, an analysis of the counterparty’s financial statements and consideration of publicly available credit ratings of the counterparty’s parent. Investment grade counterparties are those with a minimum senior unsecured debt rating of BBB- from Standard & Poor’s or Baa3 from Moody’s Investors Service. Exposure before credit collateral has been calculated considering all netting agreements in place, netting accounts payable and receivable exposure with net mark-to-market exposure. Exposure before credit collateral, after consideration of all netting agreements, is impacted significantly by the power supply volume under contract with a given counterparty and the relationship between current market prices and contracted power supply prices. Credit collateral includes the amount of cash deposits and letters of credit received from counterparties. Net exposure has only been calculated for those counterparties to which Strategic Energy is exposed and excludes counterparties exposed to Strategic Energy.

Strategic Energy’s total exposure before credit collateral at September 30, 2006, decreased $246.1 million from December 31, 2005, primarily due to lower wholesale electricity prices. At September 30, 2006, Strategic Energy had exposure before collateral to non-investment grade counterparties totaling $4.8 million. In addition, Strategic Energy held collateral totaling $4.4 million limiting its exposure to these non-investment grade counterparties to $0.4 million.

Strategic Energy contracts with national and regional counterparties that have direct supplies and assets in the region of demand. Strategic Energy also manages its counterparty portfolio through

disciplined margining, collateral requirements and contract-based netting of credit exposures against payable balances.

Supplemental Capital Requirements and Liquidity Information

The following table is an update for significant changes to selected items from the contractual obligations in the 2005 Form 10-K.

*Great Plains Energy Contractual Obligations*
	Remainder
Payment due by period	of 2006		2007		2008		2009		2010		After 2010		Total
Purchase obligations
Fuel	$	86.6	$	98.5	$	107.1	$	43.3	$	43.0	$	84.5	$	463.0
Purchased power		184.5		526.4		195.3		113.2		94.7		48.7		1,162.8
Comprehensive energy plan		118.5		281.1		321.8		139.2		12.0		-		872.6
Total contractual obligations	$	389.6	$	906.0	$	624.2	$	295.7	$	149.7	$	133.2	$	2,498.4

*Consolidated KCP&L Contractual Obligations*
	Remainder
Payment due by period	of 2006		2007		2008		2009		2010		After 2010		Total
Purchase obligations
Fuel	$	86.6	$	98.5	$	107.1	$	43.3	$	43.0	$	84.5	$	463.0
Comprehensive energy plan		118.5		281.1		321.8		139.2		12.0		-		872.6
Total contractual obligations	$	205.1	$	379.6	$	428.9	$	182.5	$	55.0	$	84.5	$	1,335.6

Fuel represents KCP&L’s 47% share of Wolf Creek nuclear fuel commitments, KCP&L’s share of coal purchase commitments based on estimated prices to supply coal for generating plants and KCP&L’s share of rail transportation commitments for moving coal to KCP&L’s generating units. Purchased power represents Strategic Energy’s agreements to purchase electricity at various fixed prices to meet estimated supply requirements. Comprehensive energy plan represents KCP&L’ contractual commitments for projects contemplated by its comprehensive energy plan.

Off-Balance Sheet Arrangements

In the normal course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include, for example, guarantees, stand-by letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended business purposes. Great Plains Energy’s guarantees provided on behalf of Strategic Energy for its power purchases and regulatory requirements increased $126.4 million to $248.4 million at September 30, 2006, compared to $122.0 million at December 31, 2005. This increase is comprised of $39.4 million in direct guarantees and $87.0 million of letters of credit and is due to a combination of higher collateral requirements at Strategic Energy and more emphasis on using Great Plains Energy’s facilities for credit support due to its lower cost. Consolidated KCP&L’s guarantees of $3.9 million at September 30, 2006, were unchanged from December 31, 2005.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Great Plains Energy and consolidated KCP&L are exposed to market risks associated with commodity price and supply, interest rates and equity prices. Market risks are handled in accordance with established policies, which may include entering into various derivative transactions. In the normal

course of business, Great Plains Energy and consolidated KCP&L also face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, regulatory, operational and credit risks and are discussed elsewhere in this document as well as in the 2005 Form 10-K and therefore are not represented here.

Great Plains Energy and consolidated KCP&L interim period disclosures about market risk included in quarterly reports on Form 10-Q address material changes, if any, from the most recently filed annual report on Form 10-K. Therefore, these interim period disclosures should be read in connection with Item 7A. Quantitative and Qualitative Disclosures About Market Risk, included in the companies’ 2005 Form 10-K, incorporated herein by reference. There have been no material changes in Great Plains Energy’s or consolidated KCP&L’s market risk since December 31, 2005.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Great Plains Energy and KCP&L carried out evaluations of their disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the fiscal quarter ended September 30, 2006. These evaluations were conducted under the supervision, and with the participation, of each company’s management, including the chief executive officer and chief financial officer of each company and the companies’ disclosure committee.

Based upon these evaluations, the chief executive officer and chief financial officer of Great Plains Energy, and the chief executive officer and chief financial officer of KCP&L, respectively, have concluded as of the end of the period covered by this report that the disclosure controls and procedures of Great Plains Energy and KCP&L are functioning effectively to provide reasonable assurance that: (i) the information required to be disclosed by the respective companies in the reports that they file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) the information required to be disclosed by the respective companies in the reports that they file or submit under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to their respective management, including the principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in Great Plains Energy’s or KCP&L’s internal control over financial reporting that occurred during the quarterly period ended September 30, 2006, that has materially affected, or is reasonably likely to materially affect, those companies’ internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

KCP&L Rate Cases

On February 1, 2006, KCP&L filed retail rates cases with the MPSC and KCC, requesting annual rate increases effective January 1, 2007, of approximately $55.8 million (11.5%) and $42.3 million (10.5%), respectively, over current levels.

On September 29, 2006, KCP&L filed a stipulation containing a negotiated settlement of its Kansas request with the KCC Staff and certain other parties. The stipulation recommends a $29 million increase in annual revenues effective January 1, 2007, with $4 million of that amount resulting from accelerated depreciation to help maintain cash flow levels as contemplated in the stipulation and agreement approved by the KCC (filed as Exhibit 10.2.a to Form 10-Q for the quarter ended June 30, 2005). The Agreement does not propose an energy cost adjustment (ECA) clause; however, KCP&L

has agreed to propose an ECA clause in its next rate case to be filed no later than March 1, 2007. The Agreement recommends various accounting and other provisions, including but not limited to: (i) establishing for regulatory purposes annual pension cost for the period beginning January 1, 2007, of approximately $43 million ($19 million on a Kansas jurisdictional basis) through the creation of a regulatory asset or liability, as appropriate; (ii) establishing, effective January 1, 2006, a regulatory asset or liability as appropriate for costs arising from defined benefit plan settlements and curtailments which will be amortized over a five-year period beginning with the effective date of rates approved in KCP&L’s next rate case; and (iii) setting at 8.5% the equity rate for the equity component of the allowance for funds used during construction rate calculation for Iatan 2. The stipulation is subject to KCC approval, and is voidable if not approved in its entirety. KCP&L expects the KCC to act on the stipulation before the end of the year.

In August 2006, MPSC Staff filed its case regarding KCP&L’s rate request. In its filing, the Staff asserted that KCP&L’s annual revenues should be decreased by between $4.3 million and $5.1 million, before adjustments resulting from the September 30, 2006, true-up of test year information. The Staff’s filing assumed that adjustments resulting from this true-up will increase revenue requirements by approximately $20 million, resulting in a net required increase in annual revenues of between $14.9 million and $15.7 million, which reflected approximately $75 million in accelerated depreciation. Staff’s current position is that KCP&L’s annual revenues should be increased by approximately $52 million (reflecting approximately $86 million in accelerated depreciation) before adjustments resulting from the September 30, 2006, true-up. A decision by the MPSC is expected before the end of the year with any rate changes being effective on January 1, 2007.

Hawthorn No. 5 Litigation

KCP&L filed suit on April 3, 2001, in Jackson County, Missouri Circuit Court against multiple defendants who are alleged to have responsibility for the 1999 boiler explosion at KCP&L’s Hawthorn No. 5 generating unit, which was subsequently reconstructed and returned to service. KCP&L and National Union entered into a subrogation allocation agreement under which recoveries in this suit were generally allocated 55% to National Union and 45% to KCP&L. Certain defendants were dismissed from the suit and various defendants settled. Trial of this case with the one remaining defendant resulted in a March 2004 jury verdict finding KCP&L’s damages as a result of the explosion were $452 million. In May 2004, the trial judge reduced the award against the defendant to $0.2 million. Both KCP&L and the defendant appealed this case to the Court of Appeals for the Western District of Missouri and on May 9, 2006, the Court of Appeals ordered the Circuit Court to enter judgment in KCP&L’s favor in accordance with the jury verdict. The defendant filed a motion for transfer of this case to the Missouri Supreme Court, which was denied. After deduction of amounts received from pre-trial settlements with other defendants and an amount for KCP&L’s comparative fault (as determined by the jury), KCP&L received proceeds of $38.9 million pursuant to the subrogation allocation agreement after payment of attorney’s fees.

Weinstein v. KLT Telecom

Richard D. Weinstein (Weinstein) filed suit against KLT Telecom Inc. (KLT Telecom) in September 2003 in the St. Louis County, Missouri Circuit Court. KLT Telecom acquired a controlling interest in DTI Holdings, Inc. (Holdings) in February 2001 through the purchase of approximately two-thirds of the Holdings stock held by Weinstein. In connection with that purchase, KLT Telecom entered into a put option in favor of Weinstein, which granted Weinstein an option to sell to KLT Telecom his remaining shares of Holdings stock. The put option provided for an aggregate exercise price for the remaining shares equal to their fair market value with an aggregate floor amount of $15 million and was exercisable between September 1, 2003, and August 31, 2005. In June 2003, the stock of Holdings was cancelled and extinguished pursuant to the joint Chapter 11 plan confirmed by the Bankruptcy Court. In September 2003, Weinstein delivered a notice of exercise of his claimed rights under the put option. KLT Telecom rejected the notice of exercise, and Weinstein filed suit alleging breach of

contract. Weinstein sought damages of at least $15 million, plus statutory interest. In April 2005, summary judgment was granted in favor of KLT Telecom, and Weinstein appealed this judgment to the Missouri Court of Appeals for the Eastern District. On May 16, 2006, the Court of Appeals affirmed the judgment. Weinstein filed a motion for transfer of this case to the Missouri Supreme Court, which was granted. Oral arguments are scheduled for December 2006. The $15 million reserve has not been reversed pending the outcome of the appeal process.

Other Proceedings

The companies are parties to various other lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding other lawsuits and proceedings, see Notes 6, 7, 14 and 15 to the consolidated financial statements. Such descriptions are incorporated herein by reference.

ITEM 1A. RISK FACTORS

Actual results in future periods for Great Plains Energy and consolidated KCP&L could differ materially from historical results and the forward-looking statements contained in this report. Factors that might cause or contribute to such differences include, but are not limited to, those discussed below and in Item 1A. Risk Factors included in the companies’ 2005 Form 10-K. The companies’ business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results, and are often beyond the companies’ control. Additional risks and uncertainties not presently known or that the companies’ management currently believes to be immaterial may also adversely affect the companies. The information presented below updates the risk factors described in the companies’ 2005 Form 10-K. This information, as well as the other information included in this report and in the other documents filed with the SEC, should be carefully considered before making an investment in the securities of Great Plains Energy and KCP&L. Risk factors of consolidated KCP&L are also risk factors for Great Plains Energy.

The outcome of KCP&L’s pending and future retail rate proceedings could have a material impact on its business and are largely outside its control.

The rates that KCP&L is allowed to charge its customers are the single most important item influencing its results of operations, financial position and liquidity. These rates are subject to the determination, in large part, of governmental entities outside of KCP&L’s control, including the MPSC, KCC and FERC. Decisions made by these entities could have a material impact on KCP&L’s business including its results of operations, financial position, or liquidity.

In February 2006, for the first time in 20 years, KCP&L filed with the MPSC and KCC requests to increase the rates it is permitted to charge its retail customers in Missouri and Kansas, respectively. In these initial filings KCP&L sought an increase in annual rates of $55.8 million in Missouri and $42.3 million in Kansas. In September 2006, KCP&L, KCC Staff and other parties reached a negotiated settlement and submitted a stipulation to the KCC recommending a $29 million increase in annual rates in Kansas. The stipulation does not propose an energy cost adjustment (ECA) clause, but KCP&L has agreed to propose an ECA clause in its next rate case to be filed no later than March 1, 2007. Hearings in the Missouri rate proceedings concluded in October 2006. The MPSC Staff’s current position is that KCP&L’s annual revenues should be increased by approximately $52 million (reflecting approximately $86 million in accelerated depreciation) before adjustments resulting from a September 30, 2006, true-up of information. The requested rate increases are subject to the approval of the MPSC and KCC, which are expected to rule before the end of 2006. It is possible that the MPSC and/or KCC will authorize a lower rate increase than what KCP&L has requested, or no increase or a rate reduction. Management cannot predict or provide any assurances regarding the outcome of these, or any future, rate proceedings. Any rate changes approved by the MPSC and KCC in the pending proceedings are expected to take effect on January 1, 2007.

As a part of the Missouri and Kansas stipulations approved by the MPSC and KCC in 2005, KCP&L undertook to implement a Comprehensive Energy Plan (Plan). Under the Plan, KCP&L agreed to undertake certain projects, including building and owning a portion of Iatan No. 2, installing a new wind-powered generating facility, and installing environmental upgrades to certain existing plants. A reduction or rejection by the MPSC or KCC of rate increase requests may result in increased financing requirements for KCP&L. This could have a material impact on its results of operations, financial position or liquidity.

In response to competitive, economic, political, legislative and regulatory pressures, KCP&L may be subject to rate moratoriums, rate refunds, limits on rate increases or rate reductions, including phase-in plans. Any or all of these could have a significant adverse effect on KCP&L’s results of operations, financial position or liquidity.

KCP&L has Construction-Related Risks

KCP&L’s comprehensive energy plan includes the construction of an estimated 850 MW coal-fired generating plant, 100.5 MW of wind generation and environmental retrofits at two existing coal-fired units. KCP&L has not recently managed a construction program of this magnitude. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, and other events beyond KCP&L’s control may occur that may materially affect the schedule, budget and performance of these projects.

These and other risks may increase the costs of these construction projects, require KCP&L to purchase additional electricity to supply its retail customers until the projects are completed, or both, and may materially affect KCP&L’s results of operations and financial position.

KCP&L has Retirement-Related Risks

Through 2010, approximately 21% of KCP&L’s current employees will be eligible to retire with full pension benefits. Failure to hire and adequately train replacement employees, including the transfer of

significant internal historical knowledge and expertise to the new employees, may adversely affect KCP&L’s ability to manage and operate its business.

Substantially all of KCP&L’s employees participate in defined benefit and postretirement plans. If KCP&L employees retire when they become eligible for retirement through 2010, or if KCP&L’s plans experience adverse market returns on their investments, or if interest rates materially fall, KCP&L’s pension expense and contributions to the plans could rise substantially over historical levels. KCP&L expects to recognize additional pension settlement charges in 2006 resulting from employees retiring and electing to receive the pension benefit lump-sum payment option. The current estimate of additional expense related to pension settlement charges, based on retirement-eligible employees who left the company through September 2006, is approximately $8 million. The actual pension settlement charges in 2006 will depend on actual pension plan results during the pension plan year and the number of employees retiring throughout the year who select the lump-sum payment option. The amount of expense related to pension settlement charges to be recognized in 2006 may be materially greater than the current estimate. The timing and number of employees retiring after 2006 and selecting the lump-sum payment option could result in further pension settlement charges that could materially affect KCP&L’s results of operations. KCP&L has requested regulatory accounting treatment from MPSC and KCC to defer pension settlement charges, effective from to January 1, 2006, and amortize the deferred amount over a five-year period to be established in the rate proceeding following the current 2006 proceedings. At September 30, 2006, no amounts were deferred pending the outcome of these requests. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on KCP&L’s results of operations and financial position.

The Pension Protection Act of 2006, signed into law on August 17, 2006, alters the manner in which pension plan assets and liabilities are valued for purposes of calculating required pension contributions and changes the timing in which required contributions to underfunded plans are made. The funding rules, which become effective in 2008, could significantly affect the Company’s funding requirements. During September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 158, “Employers’ Accounting for Defined Pension and Other Postretirement Plans.” SFAS No. 158 addresses balance sheet measurements and reporting requirements and will require the Company to recognize the funded status of the pension and postretirement plans on the balance sheet for in the fourth quarter of 2006. The effects of SFAS No. 158 are currently being evaluated. The FASB has a project to reconsider the accounting for pensions and other post-retirement benefits. This project may result in accelerated expense, liability recognition and contributions.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

Change of Control Severance Agreement

The following information was required to be disclosed under Items 1.01 and 1.02 of Form 8-K but was not reported.

In connection with the offering of new change of control severance agreements (new agreements) described below, Great Plains Energy sent notice on September 1, 2006, to the executive and other officers that their existing change of control severance agreements (old agreements) would be terminated 120 days after the notice was provided to the officers. The forms of the old agreements were filed as Exhibit 10-e to Form 10-K for the year ended December 31, 2000, Exhibit 10.1.b to Form 10-Q for the period ended March 31, 2003, and Exhibit 10.1.q to Form 10-K for the year ended December 31, 2004.

The old agreements were similar to the new agreements. However, among other things the old agreements provided for benefits if the officer's employment were terminated for good reason or otherwise than for cause during the three-year period after the first date on which a Change in Control occurs, or if the officer’s employment was terminated for any reason within a thirty day period starting one year after a Change in Control occurred.

Subsequent to the September 1, 2006, notice, Great Plains Energy entered into new agreements with the executive and other officers of Great Plains Energy and its wholly owned subsidiaries KCP&L and Strategic Energy, L.L.C. (Strategic Energy). The form of the new agreements with Michael J. Chesser, Chairman of the Board and Chief Executive Officer of Great Plains Energy; William H. Downey, President and Chief Operating Officer of Great Plains Energy and President and Chief Executive Officer of KCP&L; John R. Marshall, Senior Vice President - Delivery of KCP&L; Shahid Malik, Executive Vice President of Great Plains Energy and President and Chief Executive Officer of Strategic Energy; and the other executive officers of Great Plains Energy and KCP&L are attached hereto as Exhibits 10.1.a, 10.1.b, 10.1.c, 10.1.d and 10.1.e, respectively.

Under the new agreements, an officer would be entitled to receive a lump-sum cash payment and certain insurance benefits if the officer's employment is terminated during the two-year period after the first date on which a Change in Control occurs (i) by the Company other than for cause or upon death or disability, or (ii) by the officer for good reason (as those terms are defined in the new agreements). These benefits would also be payable if the officer’s employment is terminated as described in the preceding sentence during the period beginning when (i) Great Plains Energy enters into an agreement, the consummation of which would result in a Change in Control, (ii) Great Plains Energy or any person publicly announces an intention to take or consider taking actions which if consummated would constitute a Change in Control; (iii) any person (other than Great Plains Energy, its subsidiaries, their respective employee benefit plans, underwriters temporarily holding securities pursuant to an offering, or a corporation owned directly or indirectly by the stockholders of Great Plains Energy in substantially the same proportions as their ownership of stock of Great Plains Energy) becomes the beneficial owner of 10% or more of the combined voting power of Great Plains Energy’s then outstanding voting securities, or (iv) the Board or stockholders adopt a resolution approving any of the foregoing or approving any Change in Control. Such period ends when the Change in Control transaction is either consummated, abandoned or terminated.

A Change in Control is defined as: (i) an acquisition by a person or group (other than Great Plains Energy, its subsidiaries, their respective employee benefit plans, underwriters temporarily holding securities pursuant to an offering, or a corporation owned directly or indirectly by the stockholders of Great Plains Energy in substantially the same proportions as their ownership of stock of Great Plains Energy) of 35% or more of the Great Plains Energy common stock (not including shares directly acquired from Great Plains Energy or its affiliates other than in connection with the acquisition by Great Plains Energy or its affiliates of a business); (ii) a change in a majority of the directors of the Board; (iii) a consummation of a merger, consolidation, reorganization or similar transaction (unless shareholders receive 60% or more of the stock of the surviving entity, or unless the transaction is effected to implement a recapitalization in which no person is or becomes the beneficial owner of 20% or more of the then outstanding shares); or (iii) the occurrence, or shareholder approval, of liquidation, dissolution or sale of

substantially all of Great Plains Energy’s assets (except to an entity in which Great Plains Energy’s shareholders have at least 60% of the combined voting power in substantially the same proportions as their ownership of Great Plains Energy stock immediately prior to the sale). The definition of Change in Control in Mr. Malik’s new agreement also includes certain events resulting in changes of 50% or more in the beneficial ownership of voting power in Strategic Energy.

Upon a termination entitling the officer for benefits under the new agreements, a lump-sum cash payment will be made to the officer of (i) the officer's base salary through the date of termination; (ii) a pro-rated bonus based upon the average of the bonuses paid to the officer for the last five fiscal years (or, if shorter, the years during which the officer was employed by the company); (iii) any accrued vacation pay; (iv) any compensation previously deferred by the officer; (v) two or three times the officer's highest base salary during the prior 12 months; (vi) two or three times the average of the bonuses paid to the officer for the last five fiscal years (or, if shorter, the years during which the officer was employed by the company); (vii) the actuarial equivalent of the excess of the officer's accrued pension benefits at age 65 including supplemental retirement benefits computed without reduction for early retirement and including two or three additional years of benefit accrual service, over the officer's vested accrued pension benefits (with the exception of Messrs. Chesser and Marshall, whose compensatory arrangements provide for two years of credited service for pension calculation purposes for every one year of service, resulting in additional years of benefit accrual service under their respective agreements); and (viii) the value of any unvested Great Plains Energy contributions for the benefit of the officer under the Great Plains Energy Employee Savings Plus Plan. Mr. Malik’s new agreement also provides, upon a termination entitling him to the benefits described in the preceding sentence, for the immediate vesting of all restricted stock previously granted to him, and a cash amount equal to the bonus he would have received under applicable long term incentive plans with respect to all outstanding grants and assuming performance at target levels.

In addition, health, disability and life insurance plan coverage must be provided to the officer and dependents substantially on the same terms and conditions that existed immediately prior to the termination for two or three years, or, if earlier, until the executive officer is covered by equivalent plan benefits. Certain "gross-up" payments regarding tax obligations relating to payments under the new agreements are required to be made, as well reimbursement of certain expenses relating to possible disputes that might arise.

The new agreements also provide that the officer will not disclose confidential information, and will not (without consent) either participate in a business that directly competes with the company, or solicit current employees of the company, during the time the officer is an employee of the company and for six months thereafter.

The term of the new agreements is for an initial period of two years, and the term will be automatically extended on each annual anniversary date for an additional year unless Great Plains Energy gives at least 60 days prior notice that the term will not be extended. However, during any period of time when the Board has knowledge that any person has taken steps reasonably calculated to effect a Change in Control, the term shall automatically be extended (and may not terminate) until, in the opinion of the Board, such person has abandoned or terminated its efforts to effect a Change in Control.

The description of the old agreements and new agreements set forth above is not complete and is qualified in its entirety by reference to such agreements.

Amendments to Strategic Energy Annual and Long Term Incentive Plans

The following information was required to be disclosed under Item 1.01 of Form 8-K but was not reported. At its October 31, 2006, meeting, the independent members of Great Plains Energy’s Board of Directors approved amendments to the Strategic Energy annual and long-term incentive plans. The

amendment to the annual incentive plan goals for 2006 removed the customer satisfaction metric, and reallocated the 10% weighting assigned to that metric equally between the expected future margin and MWhs under management metrics. The amendment to the long-term incentive plans for the periods 2005-2006 and 2005-2007 removed the return on average book equity metric and reallocated the 25% weighting assigned to that metric equally among the cumulative pre-tax net income, increase in customer accounts under contract, cumulative reduction in sales, general and administrative expense per MWh and supply cost reduction metrics.

ITEM 6. EXHIBITS

Great Plains Energy Documents

Exhibit Number		Description of Document
3.1		Articles of Incorporation of Great Plains Energy Incorporated dated as of February 26, 2001, and corrected as of October 13, 2006.
10.1.a	+	Form of Change of Control Severance Agreement with Michael J. Chesser.
10.1.b	+	Form of Change of Control Severance Agreement with William H. Downey.
10.1.c	+	Form of Change of Control Severance Agreement with John R. Marshall.
10.1.d	+	Form of Change of Control Severance Agreement with Shahid Malik.
10.1.e	+	Form of Change of Control Severance Agreement with certain officers of Great Plains Energy Incorporated, Kansas City Power & Light Company and Strategic Energy, L.L.C.
10.1.f		Amendment dated as of October 2, 2006, to Amended and Restated Limited Guaranty dated as of July 2, 2004, by Great Plains Energy Incorporated in favor of the lenders under the Amended and Restated Credit Agreement dated as of July 2, 2004, among Strategic Energy, L.L.C. and the financial institutions from time to time parties thereto.
10.1.g	+	Strategic Energy, L.L.C. Long-Term Incentive Plan Grants 2005, as amended May 2, 2005 and October 31, 2006.
10.1.h	+	Strategic Energy, L.L.C. Annual Incentive Plan 2006 goals as amended October 31, 2006.
12.1		Ratio of Earnings to Fixed Charges.
31.1.a		Rule 13a-14(a)/15d-14(a) Certifications of Michael J. Chesser.
31.1.b		Rule 13a-14(a)/15d-14(a) Certifications of Terry Bassham.
32.1		Section 1350 Certifications.

+ Indicates management contract or compensatory plan or arrangement.

Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from Great Plains Energy upon written request.

KCP&L Documents

Exhibit Number		Description of Document
10.2.a		Contract between Kansas City Power & Light Company and ALSTOM Power Inc. for Engineering, Procurement, and Constructions Services for Air Quality Control

		Systems and Selective Catalytic Reduction Systems at Iatan Generating Station Units 1 and 2 and the Pulverized Coal-Fired Boiler at Iatan Generating Station Unit 2, dated as of August 10, 2006.
10.2.b		Stipulation and Agreement dated as of September 29, 2006, among Kansas City Power & Light Company, the Staff of the Kansas Corporation Commission, the Citizens’ Utility Ratepayer Board, Wal-Mart Stores Inc. and the International Brotherhood of Electrical Workers, Local Union Nos. 412, 1464 and 1613.
12.2		Ratio of Earnings to Fixed Charges.
31.2.a		Rule 13a-14(a)/15d-14(a) Certifications of William H. Downey.
31.2.b		Rule 13a-14(a)/15d-14(a) Certifications of Terry Bassham.
32.2		Section 1350 Certifications.

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

SIGNATURES

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

	GREAT PLAINS ENERGY INCORPORATED

Dated: November 7, 2006	By: /s/Michael J. Chesser
	(Michael J. Chesser)
	(Chief Executive Officer)

Dated: November 7, 2006	By: /s/Lori A. Wright
	(Lori A. Wright)
	(Principal Accounting Officer)

	KANSAS CITY POWER & LIGHT COMPANY

Dated: November 7, 2006	By: /s/William H. Downey
	(William H. Downey)
	(Chief Executive Officer)

Dated: November 7, 2006	By: /s/Lori A. Wright
	(Lori A. Wright)
	(Principal Accounting Officer)

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Avg

Great Plains Energy (GXP) Inactive 10-Q2006 Q3 Quarterly report

Content analysis