UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20052006

or

[ ] TRANSITION REPORT PURSUANT SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______to_______

  
Exact name of registrant as specified in 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
  
     
1-707000-51873 
KANSAS CITY POWER & LIGHT COMPANY
 44-0308720
  (A Missouri Corporation)  
  1201 Walnut Street  
  Kansas City, Missouri 64106  
  (816) 556-2200  
  
www.kcpl.com
  

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

Registrant
Title of each class
Great Plains Energy Incorporated
Cumulative Preferred Stock par value $100 per share
3.80%
 Cumulative Preferred Stock par value $100 per share4.50%
 Cumulative Preferred Stock par value $100 per share4.35%
 Common Stock without par value 
 
Income PRIDESSM(to February 16, 2007)
 

Securities registered pursuant to Section 12(g) of the Act.  None.Act: Kansas City Power & Light Company Common Stock without par value.



 

 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Great Plains Energy IncorporatedYes
 X  
No
    
 Kansas City Power & Light CompanyYes
    
No
 X  
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Great Plains Energy Incorporated
Yes
    
No
 X  
 Kansas City Power & Light CompanyYes
    X  
No
 X 
       
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Great Plains Energy IncorporatedYes
    X  
No
 X 
 Kansas City Power & Light CompanyYes
    
No
 X  
        
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will
not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to the Form 10-K.   
  Great Plains Energy Incorporated
X
 
Kansas City Power & Light Company          X
 
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
 X  
Accelerated filer
    
Non-accelerated filer
    
Kansas City Power & Light Company
Large accelerated filer
     
Accelerated filer
    
Non-accelerated filer
 X
                  
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Great Plains Energy IncorporatedYes
    
No
 X  
 Kansas City Power & Light CompanyYes
     
No
 X
                  
The aggregate market value of the voting and non-voting common equity held by non-affiliates of Great Plains Energy
Incorporated (based on the closing price of its common stock on the New York Stock Exchange on June 30, 2005)2006) was
approximately $2,380,255,632.$2,234,971,993. All of the common equity of Kansas City Power & Light Company is held by Great Plains
Energy Incorporated, an affiliate of Kansas City Power & Light Company.
                  
On February 28, 2006,21, 2007, Great Plains Energy Incorporated had 74,835,68785,925,671 shares of common stock outstanding. The
aggregate market value of the common stock held by non-affiliates of Great Plains Energy Incorporated (based upon the
closing price of its common stock on the New York Stock Exchange on February 28, 2006)21, 2007) was approximately
$2,115,604,125.
  $2,735,366,235. On February 28, 2006,21, 2007, Kansas City Power & Light Company had one share of common stock outstanding
and held by Great Plains Energy Incorporated.
                  
  Kansas City Power & Light Company meets the conditions set forth in General Instruction (l)(1)(a) and (b) of Form 10-K and is therefore
  filing this Form 10-K with the reduced disclosure format.
                  
Documents Incorporated by Reference
Portions of the 20062007 Proxy Statement of Great Plains Energy Incorporated to be filed with the Securities and Exchange
Commission are incorporated by reference in Part III of this report.

 
 
TABLE OF CONTENTS
  
Page
  
Number
 Cautionary Statements Regarding Forward-Looking Information 3 3
 Glossary of Terms 4 4
 
PART I
  
Item 1Business 6 6
Item 1ARisk Factors 14 15
Item 1BUnresolved Staff Comments 21 20
Item 2Properties 22 21
Item 3Legal Proceedings 23 22
Item 4Submission of Matters to a Vote of Security Holders 26 24
 
PART II
  
Item 5Market for the Registrant's Common Equity, Related Stockholder Matters 26 
 and Issuer Purchases of Equity Securities  24
Item 6Selected Financial Data 29 26
Item 7Management's Discussion and Analysis of Financial Condition 30 
 and Results of Operation  27
Item 7AQuantitative and Qualitative Disclosures About Market Risks  56 54
Item 8Consolidated Financial Statements and Supplementary Data  
 Great Plains Energy  
 Consolidated Statements of Income 59 57
  Consolidated Balance Sheets 60 58
  Consolidated Statements of Cash Flows 62 60
  Consolidated Statements of Common Stock Equity 63 61
  Consolidated Statements of Comprehensive Income 64 62
  Kansas City Power & Light Company  
  Consolidated Statements of Income 65 63
  Consolidated Balance Sheets 66 64
  Consolidated Statements of Cash Flows 68 66
  Consolidated Statements of Common Stock Equity 69 67
  Consolidated Statements of Comprehensive Income 70 68
  Great Plains Energy  
  Kansas City Power & Light Company  
  Notes to Consolidated Financial Statements 71 69
Item 9Changes in and Disagreements With Accountants on Accounting 128 
 and Financial Disclosure  123
Item 9AControls and Procedures 128 123
Item 9BOther Information 131 126
 
PART III
  
Item 10Directors, and Executive Officers of the Registrantsand Corporate Governance 131 126
Item 11Executive Compensation 132 129
Item 12Security Ownership of Certain Beneficial Owners and Management 132 
 and Related Stockholder Matters  138
Item 13Certain Relationships and Related Transactions, and Director Independence 133 139
Item 14Principal Accounting Fees and Services 133 139
 
PART IV
  
Item 15Exhibits, Financial Statement Schedules 134 140
 
2
This combined annual report on Form 10-K is being filed by Great Plains Energy Incorporated (Great Plains Energy) and Kansas City Power & Light Company separately file(KCP&L). KCP&L is a wholly owned subsidiary of Great Plains Energy and represents a significant portion of its assets, liabilities, revenues, expenses and operations. Thus, all information contained in this combined Annual Report on Form 10-K. Information contained herein relatingreport relates to, an individual registrant and its subsidiaries is filed by, Great Plains Energy. Information that is specifically identified in this report as relating solely to Great Plains Energy, such registrant onas its own behalf. Each registrant makes representations only as tofinancial statements and all information relating to itselfGreat Plains Energy’s other operations, businesses and its subsidiaries. This report should be read in its entirety. No one section of the report deals with all aspects of the subject matter.
Kansas City Power & Light Companysubsidiaries, including Strategic Energy, L.L.C. (Strategic Energy), does not relate to, and is not requiredfiled by, KCP&L. KCP&L makes no representation as to file reportsthat information. Neither Great Plains Energy or Strategic Energy have any obligation in respect of KCP&L’s debt securities and holders of such securities should not consider Great Plains Energy’s or Strategic Energy’s financial resources or results of operations in making a decision with the Securities and Exchange Commission (SEC) under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended (the Exchange Act); however, Kansas City Power & Light Company has continuedrespect to file such reports, including this Annual Report on Form 10-K, with the SEC voluntarily and will continue to do so. In addition, Kansas City Power & Light Company may determine to register its common stock under Section 12(g) of the Exchange Act and upon the effectiveness of the registration it will be required to file such reports.KCP&L’s debt securities.
 
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, Great Plains Energy and KCP&L; changes in business strategy, operations or development plans; effects of current or proposed state and federal legislative and regulatory actions or developments, including, but not limited to, deregulation, re-regulation and restructuring of the electric utility industry; decisions of regulators regarding rates 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; the ability to successfully complete merger, acquisition or divestiture plans (including the acquisition of Aquila, Inc., and the sale of assets to Black Hills Corporation) and other risks and uncertainties.
 
·  
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 the Company
·  
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
·  
adverse changes in applicable laws, regulations, rules, principles or practices governing tax, accounting and environmental matters including, but not limited to, air 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 the Company’s 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 of additional generating capacity
·  
nuclear operations
·  
ability to enter new markets successfully and capitalize on growth opportunities in non-regulated businesses
·  
performance of projects undertaken by the Company’s 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. Item 1A. Risk Factors included in this report 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 SECSecurities and Exchange Commission (SEC) should also be read for more information regarding risk factors. Great Plains Energy and KCP&L undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
 
3
GLOSSARY OF TERMS
 
The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.
 
Abbreviation or Acronym
 
Definition
   
ARO
 Asset Retirement Obligation
BART
 Best available retrofit technology
CAIR
 Clean Air Interstate Rule
CAMR
 Clean Air Mercury Rule
Clean Air Act
 Clean Air Act Amendments of 1990
CO2
 Carbon Dioxide
Company
 Great Plains Energy Incorporated and its subsidiaries
Consolidated KCP&L
 KCP&L and its wholly owned subsidiaries
Digital Teleport
 Digital Teleport, Inc.
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
ECA
Energy Cost Adjustment
EEI
 Edison Electric Institute
EIRR
 Environmental Improvement Revenue Refunding
EPA
 Environmental Protection Agency
EPS
 Earnings per common share
ERISA
Employee Retirement Income Security Act of 1974
FASB
 Financial Accounting Standards Board
FELINE PRIDESSM
 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
GPP
 Great Plains Power Incorporated
Great Plains Energy
 Great Plains Energy Incorporated and its subsidiaries
Holdings
 DTI Holdings, Inc.
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 Gas portfolio
 KLT Gas natural gas properties
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

4

Abbreviation or Acronym
 
Definition
   
MISO
 Midwest Independent Transmission System Operator, Inc.
MPSC
 Public Service Commission of the State of Missouri
MW
 Megawatt
MWh
 Megawatt hour
NEIL
 Nuclear Electric Insurance Limited
NOx
 Nitrogen Oxide
NPNS
 Normal Purchases and Normal Sales
NRC
 Nuclear Regulatory Commission
OCI
 Other Comprehensive Income
PJM
 PJM Interconnection, LLC
PRB
 Powder River Basin
PURPA
 Public Utility Regulatory Policy Act
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
SIP
State Implementation Plan
SFAS
 Statement of Financial Accounting Standards
SO2
 Sulfur Dioxide
SPP
 Southwest Power Pool, Inc.
Strategic Energy
 Strategic Energy, L.L.C., a subsidiary of KLT Energy Services
T - Lock
 Treasury Lock
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
 

5
PART I
 
ITEM 1. BUSINESS
 
General
Great Plains Energy Incorporated and Kansas City Power & Light Company are separate registrants filing this combined annual report. 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.
 
Information in other Items of this report as to which reference is made in this Item 1. is hereby incorporated by reference in this Item 1. The use of terms such as see or refer to shall be deemed to incorporate into this Item 1. the information to which such reference is made.
 
GREAT PLAINS ENERGY
Great Plains Energy, a Missouri corporation incorporated in 2001 and headquartered in Kansas City, Missouri, is a public utility holding company and does not own or operate any significant assets other than the stock of its subsidiaries. Great Plains Energy has four direct subsidiaries with operations or active subsidiaries:
 
·  KCP&L is described below.
 
·  KLT Inc. is an intermediate holding company that primarily holds directly or indirectly,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 holds investments in affordable housing limited partnerships. KLT Inc. also wholly owns KLT Gas Inc. (KLT Gas). See Note 8 to the consolidated financial statements for additional information regarding KLT Gas discontinued, which has no active operations.
 
·  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 just under 100% of the indirect interest in Strategic Energy.
 
·  Great Plains Energy Services Incorporated (Services) provides services at cost to Great Plains Energy and its subsidiaries, including consolidated KCP&L.
 
Great Plains Energy’s wholly owned subsidiary, Great Plains Power Incorporated (GPP), focused on the development of wholesale generation. GPP sold all of its capital assets related to the siting and permitting process for construction of Iatan No. 2, a coal-fired generating plant, to KCP&L, at cost, during 2005. GPP was dissolved in 2005.
Executing On Strategic Intent
For a discussion of the Company’s strategic intent and KCP&L’s comprehensive energy plan, please refer to the Executing On Strategic Intent section in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) and Note 5 to the consolidated financial statements for additional discussion of KCP&L’s comprehensive energy plan.

6
CONSOLIDATED KCP&L
KCP&L, a Missouri corporation incorporated in 1922, is an integrated, regulated electric utility, which provides electricity to customers primarily in the states of Missouri and Kansas. KCP&L’s&L has two wholly owned subsidiary,subsidiaries, Kansas City Power & Light Receivables Company (Receivables Company) and Home Service Solutions Inc. (HSS), sold its wholly owned subsidiary Worry Free Service, Inc. (Worry Free) in February 2005 and completed the disposition of its interest in R.S. Andrews Enterprises, Inc. (RSAE) in June 2003. After these sales,. HSS has no active operations.
 
Business Segments of Great Plains Energy and KCP&L
Consolidated KCP&L’s sole reportable business segment is KCP&L. Great Plains Energy, through its direct and indirect subsidiaries, has two reportable business segments: KCP&L and Strategic Energy.
 
For information regarding the revenues, income and assets attributable to the Company's reportable business segments, see Note 17 to the consolidated financial statements. Comparative financial information and discussion regarding the Company’s and KCP&L’s reportable business segments can be found in Item 7. MD&A.
 
Regulation - General
Regulatory matters affecting KCP&L and Strategic Energy are described below in the discussion on each of these reportable business segments.
6
Capital Program and Financing
For information on the Company's and KCP&L’s capital program and financial needs, see Item 7. MD&A, Capital Requirements and Liquidity section and Notes 18 and 19 to the consolidated financial statements.
KCP&L
KCP&L, headquartered in Kansas City, Missouri, is an integrated, regulated electric utility that engages in the generation, transmission, distribution and sale of electricity. KCP&L serves approximately 500,000over 505,000 customers located in all or portions of 24 counties in western Missouri and eastern Kansas. Customers include approximately 440,000446,000 residences, over 55,00057,000 commercial firms, and overapproximately 2,200 industrials, municipalities and other electric utilities. KCP&L’s retail revenues averaged approximately 82%81% of its total operating revenues over the last three years. Wholesale firm power, bulk power sales and miscellaneous electric revenues accounted for the remainder of utility revenues. KCP&L is significantly impacted by seasonality with approximately one-third of its retail revenues recorded in the third quarter. KCP&L’s total electric revenues averaged approximately 45%43% of Great Plains Energy’s revenues over the last three years. KCP&L’s net income from continuing operations accounted for approximately 88%119%, 86%88% and 67%87% of Great Plains Energy’s income from continuing operations in 2006, 2005 2004 and 2003,2004, respectively.
 
Regulation
KCP&L is regulated by the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC) with respect to retail rates, certain accounting matters, standards of service and, in certain cases, the issuance of securities, certification of facilities and service territories. KCP&L is classified as a public utility under the Federal Power Act and accordingly, is subject to regulation by the Federal Energy Regulatory Commission (FERC). By virtue of its 47% ownership interest in Wolf Creek Generating Station (Wolf Creek), KCP&L is subject to regulation by the Nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety-related requirements.
 
Missouri and Kansas jurisdictional retail revenues averaged 57% of KCP&L’s total retail revenue over the last three years. Kansas jurisdictional retail revenues averagedand 43%, respectively, of KCP&L’s total retail revenue over the last three years. See Item 7. MD&A, Critical Accounting Policies section and Note 56 to the consolidated financial statements for additional information concerning regulatory matters.
 
7
Missouri and Kansas Rate Case Filings
In FebruaryDecember 2006, KCP&L filed rate cases withreceived orders from the MPSC and the KCC.KCC regarding its rate cases filed in February 2006. For information on these rate cases, see Note 56 to the consolidated financial statementsstatements. In February 2007, KCP&L filed a request with the MPSC for additional discussionan annual rate increase of approximately $45 million. KCP&L’s comprehensive energy plan.&L is required to file a rate request with KCC on March 1, 2007.
 
Southwest Power Pool Regional Transmission Organization
Under FERC Order 2000,In 2006, KCP&L as an investor-owned utility, is strongly encouragedreceived approval from both the MPSC and KCC to join a FERC approved RTO.participate in the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization (RTO). See Note 56 to the consolidated financial statements for further information.
 
Competition
Missouri and Kansas continue on the fully integrated utility model and no legislation authorizing retail choice has been introduced in Missouri or Kansas for several years. As a result, KCP&L does not compete with others to supply and deliver electricity in its franchised service territory, although other sources of energy can provide alternatives to KCP&L’s customers. If Missouri or Kansas were to pass and implement legislation authorizing or mandating retail choice, KCP&L may no longer be able to apply regulated utility accounting principles to deregulated portions of its operations and may be required to write off certain regulatory assets and liabilities.
 
KCP&L does competecompetes in the wholesale market to sell power in circumstances when the power generatedit generates is not required for customers in its service territory. In this regard, KCP&L competes in this regard with other owners of other generating stations and other power suppliers, principally utilities in its region, on the basis of availability and price. In recent years, these wholesale sales have been an important source of
7
revenues to KCP&L. KCP&L’s wholesale revenues averaged approximately 17% of its total revenues over the last three years.
 
Power Supply
KCP&L has over 4,000 MWs of generating capacity. KCP&L’s maximum system net hourly summer peak load of 3,721 MW occurred on July 19, 2006. The maximum winter peak load of 2,563 MW occurred on December 7, 2005. During 2006, the winter peak load was 2,467 MW. The projected peak summer demand for 2007 is 3,677 MW. KCP&L expects to meet its projected capacity requirements for the years 2007 through 2009 with its generation assets, through short-term capacity purchases and demand-side management and efficiency programs. As part of its comprehensive energy plan, KCP&L installed 100.5 MW of wind generation in 2006 and expects to have Iatan No. 2, a coal-fired plant, in service in 2010.
KCP&L is a member of the Southwest Power Pool, Inc. (SPP)SPP reliability region. As one of the ten regional members of the North American Electric Reliability Council, SPP is responsible for maintaining reliability in its area through coordination of planning and operations. As a member of the SPP, KCP&L is required to maintain a capacity margin of at least 12% of its projected peak summer demand. This net positive supply of capacity and energy is maintained through its generation assets and capacity, power purchase agreements and peak demand reduction programs. The capacity margin is designed to ensure the reliability of electric energy in the SPP region in the event of operational failure of power generating units utilized by the members of the SPP.
 
KCP&L’s maximum system net hourly summer peak load of 3,610 MW occurred on August 21, 2003. The maximum winter peak load of 2,563 MW occurred on December 7, 2005. During 2005, the summer peak load was 3,512 MW. The projected peak summer demand for 2006 is 3,595 MW. KCP&L expects to meet its projected capacity requirements for the years 2006 through 2009 with its generation assets and through short-term capacity purchases, additional demand-side management and efficiency programs and the addition of wind generation. As part of its comprehensive energy plan, KCP&L expects to have Iatan No. 2 in service in 2010.
8
Fuel
The principal fuel sources of fuel for KCP&L’s electric generation are coal and nuclear fuel. KCP&L expects, with normal weather, to satisfy approximately 98%96% of its 2006 fuel2007 generation requirements from these sources with the remainder provided by natural gas, oil and oil.wind. The actual 20052006 and estimated 20062007 fuel mix and delivered cost in cents per net kWh generated are in the following table.
 
   
Fuel cost in cents per
 
Fuel Mix (a)
 
net kWh generated
 
Estimated
 
Actual
 
Estimated
 
Actual
Fuel
2007
 
2006
 
2007
 
2006
Coal74% 75% 1.28 1.15
Nuclear22  22  0.45 0.43
Natural gas and oil2  3  9.58 7.37
Wind2  -  - -
Total Generation100% 100% 1.19 1.16
(a)Fuel mix based on percent of total MWhs generated.
 
 
          
    
Fuel cost in cents per
 
  
Fuel Mix (a)
 
net kWh generated
 
  
Estimated
Actual
Estimated
Actual
Fuel 
2006
2005
2006
2005
Coal  77% 77% 1.24  1.01 
Nuclear  21  21  0.44  0.44 
Natural gas and oil  2  2  11.15  8.29 
Total Generation  100% 100% 1.22  1.06 
(a) Fuel mix based on percent of total MWhs generated.

Less than 1% of KCP&L’s rates contain an automatic fuel adjustment clause. Consequently, toTo the extent the price of coal, coal transportation, nuclear fuel, nuclear fuel processing, natural gas or purchased power increaseincreases significantly after the expiration of the contracts described in this section, or if KCP&L’s lower fuel cost units do not meet anticipated availability levels, KCP&L’s net income may be adversely affected until the increased cost could be reflected in rates. KCP&L will file an energy cost adjustment (ECA) clause as part of its Kansas rate case to be filed March 1, 2007.
 
Coal
During 2006,2007, KCP&L’s generating units, including jointly owned units, are projected to burn approximately 13.513.3 million tons of coal. KCP&L has entered into coal-purchase contracts with various suppliers in Wyoming's Powder River Basin (PRB), the nation's principal supply region of low-sulfur
8
coal, and with local suppliers. TheseThe coal to be provided under these contracts will satisfy all projected coal requirements for 2006 and 2007 and 84%approximately 95%, 35%45% and 22% respectively,35% for 2008 through 2010.2010, respectively. The remainder of KCP&L’s coal requirements will be fulfilled through additional contracts or spot market purchases. KCP&L has entered into its coal contracts over time at higher average prices affecting coal costs for 20062007 and beyond.
 
KCP&L has also entered into rail transportation contracts with various railroads for movingto transport coal from the PRB to its generating units. TheseThe transportation services to be provided under these contracts will satisfy approximatelyvirtually all of the projected requirements for 2006 and 2007, and 98%, 78% and 77%, respectively,more than 95% for 2008 through 2010; however, KCP&L has been experiencing coal delivery issues.and approximately 75% for 2009 and 2010. Coal transportation costs are expected to increase in 20062007 and beyond. See Note 15 to the consolidated financial statements regarding a rate complaint case against Union Pacific Railroad Company. See Item 7. MD&A, KCP&L Business Overview for additional information.
 
Nuclear Fuel
KCP&L owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek, its only nuclear generating unit. Wolf Creek purchases uranium and has it processed for use as fuel in its reactor. This is a three step process that involves conversion of uranium concentrates to uranium hexafluoride, enrichment of uranium hexafluoride and fabrication of nuclear fuel assemblies. The owners of Wolf Creek have on hand or under contract 100%all of the uranium and conversion services needed to operate Wolf Creek through March 2011 and approximately 75% after that date through September 2009.2018. A supply interruption at a major uranium mine owned in part by one of Wolf Creek’s suppliers will result in deferral of a small portion of the uranium scheduled for delivery to Wolf Creek in 2007. It is possible that this supply interruption will impact small portions of Wolf Creek's uranium deliveries beyond 2007 as well. In anticipation of this possibility, the owners of Wolf Creek authorized the purchase of additional uranium from an alternate supplier. That purchase, combined with strategic inventory acquired earlier in 2005 and other strategies that have already been adopted, minimizes the risks from such supply interruptions. The owners also have under contract 100% of the uranium enrichment and fabrication required to operate Wolf Creek through March 2008. Fabrication requirements are under contract through 2024. Letters of intent have been issued with suppliers for a substantial portion of Wolf Creek’s uranium, conversion and enrichment requirements extending through at least 2017.2025.
 
9
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.
 
All uranium, uranium conversion and uranium enrichment arrangements, as well as the fabrication agreement, have been entered into in the ordinary course of business. However, contraction and consolidation among suppliers of these commodities and services, coupled with increasing worldwide demand and past inventory drawdowns, have introduced some uncertainty as to Wolf Creek's ability to replace some of these contracts in the event of a protracted supply disruption. Great Plains Energy’s management believes this potential problemrisk is common to the nuclear industry. Accordingly, in the event the affected contracts were required to be replaced, Great Plains Energy’s and Wolf Creek's management believesbelieve that the industry and government would work together to minimize disruption of the nuclear industry's operations, including Wolf Creek's operations.
 
See Note 45 to the consolidated financial statements for additional information regarding nuclear plant.
 
Natural Gas
KCP&L is projecting decreased use of natural gas during 2007. At December 31, 2006, as a result of KCP&L’s projected normal summer weather and fewer plant outages in 2006. KCP&L hashad hedged approximately 45%30% and 9% of its 20062007 and 2008, respectively, projected natural gas usage for generation requirements to serve retail load and firm MWh sales.
 
9
Purchased Power
At times, KCP&L purchases power to meet its customers’ needs. Management believes KCP&L will be able to obtain enough power to meet its future demands due to the coordination of planning and operations in the SPP region; however, price and availability of power purchases may be impacted during periods of high demand. KCP&L’s purchased power, as a percent of MWh requirements, averaged approximately 5%3% for 2006, 2005 2004 and 2003.2004.
 
Environmental Matters
KCP&L’s operations are subject to regulation by federal, state and local authorities with regard to air and other environmental matters. The generation and transmission 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 KCP&L.
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. Environmental-related legislation is continuously introduced in Congress. Such legislation typically includes various compliance dates and compliance limits. Such 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 would seek recovery of capital costs and expenses for such compliance through rates. KCP&L will continue to monitor proposed legislation. See Note 13 to the consolidated financial statements for additional information regarding environmental matters.
 
STRATEGIC ENERGY
Great Plains Energy indirectly owns just under 100% of the indirect interest in Strategic Energy. 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, Illinois, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas. In addition to competitive retail electricity supply services, Strategic Energy records insignificant wholesale revenues and purchased power expense incidental to the retail services provided.has begun expansion into Connecticut. Strategic Energy also provides strategic planning, consulting and billing and scheduling services in the natural gas and electricity markets.
 
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Strategic Energy provides services to approximately 51,00088,200 commercial, institutional and small manufacturing accounts for approximately 10,30025,000 customers, including numerous Fortune 500 companies, smaller companies and governmental entities. Strategic Energy offers an array of products designed to meet the various requirements of a diverse customer base including fixed price, index-based and month-to-month renewal products. Strategic Energy’s projected MWh deliveries for 2006 based on signed contracts and expected additional MWh contracts and deliveries2007 are in the range of 1618 to 1822 million MWhs. Based solely on expected usage under current signed contracts, Strategic Energy has forecasted future MWh commitments (backlog) of 10.414.7 million, 4.38.9 million and 2.34.1 million for the years 20062007 through 2008, respectively.2009, respectively, and 5.1 million over the years 2010 through 2012.
 
Strategic Energy’s revenues averaged approximately 55%57% of Great Plains Energy’s revenues over the last three years. Strategic Energy’s net income (loss) accounted for approximately 17%(8%), 24%17% and 21%24% of Great Plains Energy’s income from continuing operations in 2006, 2005 2004 and 2003,2004, respectively.
 
Strategic Energy’s growth objective is to continue to expand in retail choice states and continue to earnincrease its share of a large and growing market opportunity. Strategic Energy’s continued success is dependent on a number of industry and operational factors including, but not limited to, the ability to contract for wholesale MWhs to meet its customers’ needs at prices that are competitive with the host utility territory rates and with current and/or future competitors, the ability to provide value-added customer services and the ability to attract and retain employees experienced in providing service in retail choice states.
 
Power Supply
Strategic Energy does not own any generation, transmission or distribution facilities. Strategic Energy purchases blocks of electricity from power suppliers based on forecasted peak demand for its retail customers. Management believes it will have adequate access to energy in the markets it serves.
 
Regulation
Strategic Energy, as a participant in the wholesale electricity and transmission markets, is subject to FERC jurisdiction. Additionally, Strategic Energy is subject to regulation by state regulatory agencies in states where Strategic Energy is licensed to sell power. Each state has a public utility commission and rules related to retail choice. Each state’s rules are distinct and may conflict. These rules do not restrict the amount Strategic Energy can charge for its services, but can have an impact on Strategic Energy’s ability to provide retail electricity servicescompete in any jurisdiction.
 
Texas
During 2005, the Public Utility Commission of Texas (Texas PUC) opened a project to review rules related to the Price-to-Beat (PTB) and Provider of Last Resort. Should the Texas PUC change the current PTB mechanism to one that is less reflective of market-based rates, the change could have an impact on this competitive market and Strategic Energy’s prospects for growth in Texas.
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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 the Midwest Independent Transmission System Operator, Inc. (MISO) during a 16-month transition period from December 1, 2004, through March 31, 2006. See Note 5 to the consolidated financial statements for further information regarding SECA.
Transmission
In many markets, RTOs/ISOsRegional Transmission Organizations (RTO)/Independent System Operators (ISO) manage the power flows, maintain reliability and administer transmission access for the electric transmission grid in a defined region. RTOs/ISOs coordinate and monitor communications among the generator, distributor and retail electricity provider. Additionally, RTOs/ISOs manage the real-time electricity supply and demand, and direct the energy flow. Through these activities, RTOs/ISOs maintain a reliable energy supply within their region.
 
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As a competitive retail electricity supplier, Strategic Energy must register with each RTO/ISO in order to operate in the markets covered by their grids. Strategic Energy primarily engages with PJM Interconnection, LLC (PJM), New England RTO (formerly ISO-New England), California ISO, New York ISO, Electric Reliability Council of Texas (ERCOT) and MISO.the Midwest Independent Transmission System Operator, Inc. (MISO).
 
In some cases, RTO/ISOs provide Strategic Energy with all or a combination of the data for billing, settlement, application of electricity rates and information regarding the imbalance of electricity supply. In addition, they provide balancing energy services and ancillary services to Strategic Energy in the fulfillment of providing services to retail end users. Strategic Energy must go through a settlement process with each RTO/ISO in which the RTO/ISO compares scheduled power with actual meter usage during a given time period and adjusts the original costs charged to Strategic Energy through a revised settlement. All participants in the RTOs/ISOs have exposure to other market participants. In the event of default by a market participant within the RTOs/ISOs, the uncollectible balance is generally allocated to the remaining participants in proportion to their load share.
 
RTOs/ISOs may continue to modify the market structure and mechanisms in an attempt to improve market efficiency. In addition, existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to Strategic Energy’s activities. These actions could have an effect on Strategic Energy’s results of operations. Strategic Energy participates extensively, together with other market participants, in relevant RTO/ISO governance and regulatory issues.
 
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 and MISO during a 16-month transition period from December 1, 2004, through March 31, 2006. See Note 6 to the consolidated financial statements for further information regarding SECA.
Revenue Sufficiency Guarantee
Since the April 2005 implementation of 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. See Note 6 to the consolidated financial statements for further information regarding RSG.
Competition
The principal elements of competition are price, service and product differentiation. Strategic Energy operates in several retail choice electricity markets. Strategic Energy has several competitors that operate in most or all of the same states in which it provides services to customers. Some of these competitors also operate in states other than where Strategic Energy has operations. Strategic Energy also faces competition in certain markets from regional suppliers and deregulated utility affiliates formed by holding companies affiliated with regulated utilities to provide retail load in their home market territories. Strategic Energy’s competitors vary in size from small companies to large corporations,
11
some of which have significantly greater financial, marketing, and procurement resources than Strategic Energy. Additionally, Strategic Energy, as well as its other competitors, must compete with the host utility in order to convince customers to switch from the host utility. In most markets, thereThere is a regulatory lag in several RTOs/ISOs that slows the adjustment of host public utility rates in response to changes in wholesale prices, which may negatively affect Strategic Energy’s ability to compete in a rising wholesale price environment. The principal elements of competition are price, service and product differentiation.
 
GREAT PLAINS ENERGY AND CONSOLIDATED KCP&L EMPLOYEES
At December 31, 2005,2006, Great Plains Energy had 2,3822,470 employees. Consolidated KCP&L had 2,0782,140 employees, including 1,3351,364 represented by three local unions of the International Brotherhood of Electrical Workers (IBEW). KCP&L has labor agreements with Local 1613, representing clerical employees (expires March 31, 2008), with Local 1464, representing transmission and distribution workers (expires January 31, 2009), and with Local 412, representing power plant workers (expires February 28, 2007)2007, with contract negotiations currently ongoing).

Officers
All of the individuals in the following table have been officers or employees in a responsible position with the Company for the past five years except as noted in the footnotes. The term of office of each officer commences with his or her appointment by the Board of Directors and ends at such time as the Board of Directors may determine. There are no family relationships between any of the executive officers, nor any arrangement or understanding between any executive officer and any other person involved in officer selection.
 
Officers of Great Plains Energy
 
Name
Age
Current Position(s)
Year First Assumed An Officer Position
    
Michael J. Chesser (a)*
 
58Chairman of the Board and Chief Executive Officer2003
William H. Downey (b)*
 
62President and Chief Operating Officer2000
Terry Bassham (c)*
46
Executive Vice President, Finance and Strategic
Development and Chief Financial Officer
 
2005
Michael W. Cline (d)
 
45Treasurer and Chief Risk Officer2003
Barbara B. Curry (e)*
52
Senior Vice President, Corporate Services
and Corporate Secretary
 
2005
Michael L. Deggendorf (f)
 
45Vice President, Public Affairs2005
Stephen T. Easley (g)*
 
51Senior Vice President, Supply - KCP&L2000
Mark G. English (h)
 
55General Counsel and Assistant Secretary2003
Todd A. Kobayashi (i)
 
39Vice President, Strategy and Investor Relations2005
Shahid Malik (j)*
46
Executive Vice President
President and Chief Executive Officer - Strategic
Energy
 
2004
John R. Marshall (k)*
 
57Senior Vice President, Delivery - KCP&L2005
Victoria L. Schatz (l)
 
37Assistant General Counsel and Assistant Secretary2006
Lori A. Wright (m)*
 
44Controller2002
12
 
Officers of Great Plains Energy
 
Name
Age
Current Position(s)
Year First Assumed
An Officer Position
    
Michael J. Chesser (a)*
57Chairman of the Board and Chief Executive Officer2003
William H. Downey (b)*
61President and Chief Operating Officer2000
Terry Bassham (c)*
45Executive Vice President, Finance and Strategic Development and Chief Financial Officer2005
Michael W. Cline (d)
44Treasurer and Chief Risk Officer2003
Barbara B. Curry (e)*
51Senior Vice President, Corporate Services and Corporate Secretary2005
Michael L. Deggendorf (f)
44Vice President, Public Affairs2005
Stephen T. Easley (g)*
50Senior Vice President, Supply - KCP&L2000
Mark G. English (h)*
54General Counsel and Assistant Secretary2003
Chris B. Giles (i)*
52Vice President, Regulatory Affairs - KCP&L2005
Todd A. Kobayashi (j)
38Vice President, Strategy and Investor Relations2005
Shahid Malik (k)*
45
Executive Vice President
President and Chief Executive Officer - Strategic Energy
2004
John R. Marshall (l)*
56Senior Vice President, Delivery - KCP&L2005
William G. Riggins (m)*
47Vice President, Legal and Environmental Affairs and General Counsel - KCP&L2000
Lori A. Wright (n)*
43Controller2002
John J. DeStefano (o)*
56
President - Great Plains Power Incorporated
President - Home Service Solutions Inc.
1989

13
Officers of KCP&L
 
Name
Age
Current Position(s)
Year First Assumed An Officer Position
    
Michael J. Chesser (a)*
 
58Chairman of the Board2003
William H. Downey (b)*
 
62President and Chief Executive Officer2000
Terry Bassham (c)*
 
46Chief Financial Officer2005
Kevin E. Bryant (n)
 
 
31Vice President, Energy Solutions2006
Lora C. Cheatum (o)
 
50Vice President, Administrative Services2005
Michael W. Cline (d)
 
45Treasurer2003
F. Dana Crawford (p)
 
56Vice President, Plant Operations2005
Barbara B. Curry (e)*
 
52Secretary2005
Stephen T. Easley (g)*
 
51Senior Vice President, Supply2000
Mark G. English (h)
 
55Assistant Secretary2003
Chris B. Giles (q)
 
53Vice President, Regulatory Affairs2005
William P. Herdegen III
 
52Vice President, Customer Operations2001
John R. Marshall (k)*
 
57Senior Vice President, Delivery2005
William G. Riggins (r)
48
Vice President, Legal and Environmental Affairs and
General Counsel
 
2000
Marvin L. Rollison (s)
54
Vice President, Corporate Culture and Community
Strategy
 
2005
Victoria L. Schatz (l)
 
 
37
Assistant General Counsel and Assistant Secretary
 
2006
Richard A. Spring
 
52Vice President, Transmission1994
Lori A. Wright (m)*
 
44Controller2002
Officers of KCP&L
 
Name
Age
Current Position(s)
Year First Assumed
An Officer Position
    
Michael J. Chesser (a)*
57Chairman of the Board2003
William H. Downey (b)*
61President and Chief Executive Officer2000
Terry Bassham (c)*
45Chief Financial Officer2005
Lora C. Cheatum (p)*
49Vice President, Administrative Services2005
Michael W. Cline (d)
44Treasurer2003
F. Dana Crawford (q)*
55Vice President, Plant Operations2005
Barbara B. Curry (e)*
51Secretary2005
Stephen T. Easley (g)*
50Senior Vice President, Supply2000
Mark G. English (h)
54Assistant Secretary2003
Chris B. Giles (i)*
52Vice President, Regulatory Affairs2005
William P. Herdegen III (r)*
51Vice President, Customer Operations2001
John R. Marshall (l)*
56Senior Vice President, Delivery2005
William G. Riggins (m)*
47Vice President, Legal and Environmental Affairs and General Counsel2000
Marvin L. Rollison (s)
53Vice President, Corporate Culture and Community Strategy2005
Richard A. Spring *
51Vice President, Transmission1994
Lori A. Wright (n)*
43Controller2002
*Designated an executive officer.
(a)
Mr. Chesser was previously Chief Executive Officer of United Water (2002-2003) and President and Chief Executive Officer of GPU Energy (2000-2002).
(b)
Mr. Downey was previously Executive Vice President of Great Plains Energy (2001- 2003) and Executive Vice President of KCP&L (2000-2002) and President - KCP&L Delivery Division (2000-2002).
(c)
Mr. Bassham was previously Executive Vice President, Chief Financial and Administrative Officer (2001-2005) and Executive Vice President and General Counsel (2000-2001) of El Paso Electric Company.
(d)
Mr. Cline was previously Treasurer of Great Plains Energy (2005), Assistant Treasurer of Great Plains Energy and KCP&L (2003-2005), and Director, Corporate Finance (2001-2002), and Assistant Treasurer-Corporate Finance of Corning Inc. (2001).
Great Plains Energy.
(e)
Ms. Curry was previously Senior Vice President, Retail Operations (2003-2004), and Executive Vice President, Global Human Resources (2001-2003) and Executive Vice President, Corporate Services (1997-2001) of TXU Corporation.
(f)
Mr. Deggendorf was previously Senior Director, Energy Solutions of KCP&L (2002-2005), Senior Vice President of Everest Connections, a cable services company (2000-2002) and Vice President of UtiliCorp Communications (2000-2002).
(g)
Mr. Easley was previously Vice President, Generation Services (2002-2005), and President and CEO of GPP (2001-2002) and Vice President - Business Development of KCP&L Power Division (2000-2001). He was promoted to Senior Vice President, Supply of KCP&L in March 2005.
(i) 
(h)
Mr. GilesEnglish was previously Senior Director, Regulatory AffairsCorporate Counsel and Business Planning (2004-2005)Assistant Secretary (2003-2005) and Director, Regulatory AffairsCorporate Counsel (2001-2003) of KCP&L (1993-2004).Great Plains Energy.
14
(j)
(i)
Mr. Kobayashi was previously Investor Relations Officer (2002-2005) and Director-Investor Relations and Corporate Development of Lante Corporation, a technology consulting firm (2000-2002).
13
(k)
(j)
Mr. Malik was appointed as President and Chief Executive Officer of Strategic Energy effective November 10, 2004 and was appointed Executive Vice President of Great Plains Energy effective January 1, 2006. Mr. Malik was previously a partner of Sirius Solutions LLP, a consulting company, (2002-2004) and President of Reliant Energy Wholesale Marketing Group (1999-2002).
(l)
(k)
Mr. Marshall was previously President of Coastal Partners, Inc., a strategy consulting company (2001-2005), and Senior Vice President, Customer Service of Tennessee Valley Authority (2002-2004), and President of Duquesne Light Company (1999-2001).
(m)
(l)
Mr. RigginsMs. Schatz was previously General CounselManaging Attorney (2003-2006) and Senior Attorney (2002-2003) of Great Plains Energy (2000-2005)KCP&L, and in private practice with the Levy & Craig law firm (1999-2002).
(n)
(m)
Ms. Wright served as Assistant Controller of KCP&L from 2001 until named Controller in 20022002.
(n)
Mr. Bryant was previously Manager, Corporate Finance (2005-2006) and was DirectorSenior Financial Analyst, Corporate Finance (2003-2005) of AccountingGreat Plains Energy. Previously he served in successive positions as Senior Treasury Analyst and Reporting of American Electric Power Company,Manager, Strategic Planning for THQ, Inc. (2000-2001), a software company, (2002-2003).
(o)
Mr. DeStefano retired December 31, 2005.
(p)Ms. Cheatum was previously Interim Vice President, Human Resources (2004-2005) and Director, Human Resources (2001-2004) of KCP&L, and Regional Human Resources Director (1999-2001) of McLane Distribution, a division of Wal-Mart.&L.
(q)
(p)
Mr. Crawford was previously Plant Manager (1994-2005) of KCP&L’s LaCygne Generating Station.
(r)
(q)
Mr. HerdegenGiles was Chief Operating Officer of Laramore, Douglasspreviously Senior Director, Regulatory Affairs and Popham, an engineering consulting company, (2001) and Vice PresidentBusiness Planning (2004-2005) and Director, Regulatory Affairs of Utilities Practice of System Development Integration, a consulting company, (1999-2001)KCP&L (1993-2004).
(r)Mr. Riggins was previously General Counsel of Great Plains Energy (2000-2005).
(s)Mr. Rollison was previously Supervisor-Engineering of KCP&L (2000-2005).
 
Available Information
Great Plains Energy’s website is www.greatplainsenergy.com and KCP&L’s website is www.kcpl.com. Information contained on the companies’ websites is not incorporated herein. Both companies make available, free of charge, on or through their websites, their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act as soon as reasonably practicable after the companies electronically file such material with, or furnish it to, the SEC. In addition, the companies make available on or through their websites all other reports, notifications and certifications filed electronically with the SEC.
The public may read and copy any materials that the companies file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC, 20549. For information on the operation of the Public Reference Room, please call the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site at http://www.sec.gov that contains reports, proxy statements and other information regarding the companies.
 
ITEM 1A. RISK FACTORS
 
Actual results in future periods for Great Plains Energy and 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. 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 risk factors described below, as well as the other information included in this Annual Report and in the other documents filed with the SEC, should be carefully considered before making an investment in the Company’s securities. Risk factors of consolidated KCP&L are also risk factors for Great Plains Energy.
 
The Company has Regulatory Risks
The Company is subject to extensive federal and state regulation, as described below. Failure to obtain adequate rates or regulatory approvals, in a timely manner, adoption of new regulations by federal or state agencies, or changes to current regulations and interpretations of such regulations may materially affect the Company’s business and its results of operations and financial position. The Energy Policy Act of 2005 repealed the Public Utility Holding Company Act of 1935, as amended, and provided certain utility customer protection authority to FERC and the states. The Energy Policy Act of 2005, among other things, also requires FERC to perform a study of competition in wholesale and retail electricity markets and authorizes the creation of an Electric Reliability Organization (ERO) to establish
 
15
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The outcome of KCP&L’s pending and enforce mandatory reliability standardsfuture retail rate proceedings could have a material impact on its business and are largely outside its control.
The rates, which 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 FERC oversight. The final rule for ERO developmentthe determination, in large part, of governmental entities outside of KCP&L’s control, including the MPSC, KCC and processes for insuring reliable grid operations was issued in February 2006. Management has not yet determined theFERC. Decisions made by these entities could have a material impact of this final rule. FERC is in the process of establishing rules implementing the Energy Policy Act of 2005, and there is the risk that the rules may adversely affect operations, theon KCP&L’s business including its results of operations and financial conditionposition.
In February 2007, KCP&L filed a request with the MPSC to increase the annual rates charged to its retail customers in Missouri by approximately $45 million. KCP&L has also committed to file a request to increase the rates it is permitted to charge its Kansas retail customers with KCC by March 1, 2007. The requested rate increases are subject to the approval of the Company.

MPSC and KCC, which are expected to rule on the requests within eleven and nine months, respectively, of the filing dates. 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. Additionally, the December 2006 order of the MPSC authorizing an increase in annual rates of approximately $51 million has been appealed in the Missouri courts. It is regulatedpossible that the MPSC order could be vacated and the proceedings remanded to the MPSC. Management cannot predict or provide any assurances regarding the outcome of these proceedings.
As a part of the Missouri and Kansas stipulations approved by the MPSC and KCC with respectin 2005, KCP&L began implementation of its comprehensive energy plan. Under the comprehensive energy plan, KCP&L agreed to retail rates,undertake certain accounting matters, standardsprojects, including building and owning a portion of serviceIatan No. 2, installing a new wind-powered generating facility, installing environmental upgrades to certain existing plants, infrastructure improvements and demand management, distributed generation, and customer efficiency and affordability programs. A reduction or rejection by the MPSC or KCC of rate increase requests may result in certain cases,increased financing requirements for KCP&L. This could have a material impact on its results of operations and financial position.
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 designed to spread the issuanceimpact of securities and certificationrate increases over an extended period of facilities and service territories. Failure to obtain adequate and timely rate relief may adversely affecttime for the benefit of customers. Any or all of these could have a significant adverse effect on KCP&L’s results of operations and financial condition. KCP&L is also subjectposition.
The ability of Strategic Energy to regulationcompete in states offering retail choice may be materially affected by FERC with respect to the issuance of short-term debt, wholesale electricity salesstate regulations and transmission matters and the NRC as to nuclear operations.

host public utility rates.
Strategic Energy is a participant in the wholesale electricity and transmission markets, and is subject to FERC regulation with respect to wholesale electricity sales and transmission matters. Additionally, Strategic Energy is subject to regulation by state regulatory agencies in states where it has retail customers. Each state has a public utility commission and rules related to retail choice. Each state's rules are distinct and may conflict. These rules do not restrict the amount Strategic Energy can charge for its services, but can have an impact on Strategic Energy's ability to provide retail electricity servicescompete in each state.any jurisdiction. Additionally, each state regulates the rates of the host public utility, and the timing and amount of changes in host public utility rates can materially affect Strategic Energy’s results of operations and financial position.

The Company has Financial Market and Ratings Risks
The Company relies on access to both short-term money markets and longer-termlong-term capital markets as a significant sourcesources of liquidity for capital requirements not satisfied by cash flows from operations. The Company also relies on the financial markets for credit support, such as letters of credit, to support Strategic Energy and KCP&L operations. KCP&L’s capital requirements are expected to increase substantially over the next several years as it implements the generation and environmental projects in
15
its comprehensive energy plan. The amount of credit support required for Strategic Energy operations varies with a number of factors, including the amount and price of power purchased for its customers. The Company’s management believes that it will maintain sufficient access to these financial markets at a reasonable cost based upon current credit ratings and market conditions. However, changes in financial or other market conditions or credit ratings could adversely affect its ability to access financial markets at a reasonable cost, impact the rate treatment provided KCP&L, or both, and therefore materially affect its results of operations and financial position.
 
Great Plains Energy, KCP&L and certain of their securities are rated by Moody's Investors Service and Standard & Poor's. These ratings impact the Company’s cost of funds and Great Plains Energy’s ability to provide credit support for its subsidiaries.
 
Great Plains Energy is subject to business and regulatory uncertainties as a result of the anticipated acquisition of Aquila, Inc., which could adversely affect its business.
On February 7, 2007, Great Plains Energy announced that it had entered into definitive agreements under which it would acquire all the outstanding shares of Aquila, Inc. (Aquila). Immediately prior to this acquisition, Black Hills Corporation would acquire from Aquila its electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa. These transactions are complex, and are subject to Great Plains Energy and Aquila shareholder approvals, numerous regulatory approvals and other conditions. The timing of, and the conditions imposed by, regulatory approvals may delay, or give rise to the ability to terminate, the transactions. In the event of termination, the Company would be required to write-off its deferred transactions costs, which could be material. The conditions imposed by regulatory approvals could increase the costs, or decrease the benefits, anticipated by the Company from the transaction.
While it is anticipated that Great Plains Energy, KCP&L and Aquila will be rated investment grade after the transactions close, Great Plains Energy and KCP&L credit ratings have been negatively affected after the announcement of the proposed acquisition, and may be further negatively affected. Credit rating downgrades could result in higher financing costs and potentially limit the companies’ access to the capital and credit markets, impact the rate treatment provided KCP&L, or both.
Great Plains Energy entered into the transaction agreements with the expectation that the acquisition would result in various benefits to it and KCP&L including, among other things, synergies, cost savings and operating efficiencies. Although the Company expects to achieve the anticipated benefits of the acquisition, achieving them cannot be assured. The Company expects to propose to regulators that the benefits resulting from the transaction be shared between retail electric customers and Company shareholders, and will request certain other regulatory assurances. There is no assurance regarding the amount of benefit-sharing, or other regulatory treatment, in rate cases occurring after the closing of the transactions.
Additionally, Aquila's utility operations are subject to regulation by numerous government entities, including the MPSC and FERC, and have pending MPSC rate cases, the outcome of which are subject to uncertainty.  As such, a successful acquisition of Aquila will subject Great Plains Energy to additional regulatory risk.
The Company’s Financial Statements Reflect the Application of Critical Accounting Policies
The application of the Company’s critical accounting policies reflects complex judgments and estimates. These policies include industry-specific accounting applicable to regulated public utilities, accounting for pensions long-lived and intangible assets, goodwill and derivative instruments. The adoption of new Generally Accepted Accounting Principles (GAAP) or changes to current accounting policies or interpretations of such policies may materially affect the Company’s results of operations and financial position.
 
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The Company is Subject to Environmental Laws and the Incurrence of Environmental Liabilities
The Company is subject to regulation by federal, state and local authorities with regard to air quality 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, which 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
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fines, injunctive relief and other sanctions. KCP&L regularly conducts environmental audits designed to ensure compliance with governmental regulations and to detect contamination. Failure to comply with these laws and regulations could have a material adverse effect on Great Plains Energy and consolidated KCP&L results of operations and financial position.
 
New environmental laws and regulations affecting KCP&L’s operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to KCP&L or its facilities, which may substantially increase its environmental expenditures in the future. New facilities, or modifications of existing facilities, may require new environmental permits or amendments to existing permits. Delays in the environmental permitting process, denials of permit applications, or conditions imposed in permits and the outcome of the appeal of KCP&L’s Iatan Station air permit may materially affect the cost and timing of the generation and environmental retrofit projects included in the comprehensive energy plan, among other projects, and thus materially affect KCP&L’s results of operations and financial position. In addition, KCP&L may not be able to recover all of its costs for environmental expenditures through rates in the future. Under current law, KCP&L is also generally responsible for any on-site liabilities associated with the environmental condition of its facilities that it has previously owned or operated, regardless of whether the liabilities arose before, during or after the time it owned or operated the facilities. The incurrence of material environmental costs or liabilities, without related rate recovery, could have a material adverse effect on KCP&L’s results of operations and financial position. See Note 13 to the consolidated financial statements for additional information regarding environmental matters.
 
Great Plains Energy’s Ability to Pay Dividends and Meet Financial Obligations Depends on its Subsidiaries
Great Plains Energy is a holding company with no significant operations of its own. The primary source of funds for payment of dividends to its shareholders and its financial obligations is dividends paid to it by its subsidiaries, particularly KCP&L. The ability of Great Plains Energy’s subsidiaries to pay dividends or make other distributions, and accordingly Great Plains Energy’s ability to pay dividends on its common stock and meet its financial obligations, will depend on the actual and projected earnings and cash flow, capital requirements and general financial position of its subsidiaries, as well as on regulatory factors, financial covenants, general business conditions and other matters.
 
KCP&L and Strategic Energy are Affected by Demand, Seasonality and Weather
The results of operations of KCP&L and Strategic Energy can be materially affected by changes in weather and customer demand. KCP&L and Strategic Energy estimate customer demand based on historical trends, to procure fuel and purchased power. Differences in customer usage from these estimates due to weather or other factors could materially affect KCP&L’s and Strategic Energy’s results of operations.
 
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. KCP&L is significantly impacted by seasonality with approximately one-third of its retail revenues recorded in the third quarter. Strategic Energy is impacted by seasonality, but to a much lesser extent. In addition, severe weather, including but not limited to tornados, snow, rain and ice storms can be destructive causing outages and property damage that can potentially result in additional expenses and lower revenues. KCP&L’s Iatan and Hawthorn stations use water from the Missouri River for cooling purposes. Low water and flow levels, which have been experienced in recent years,
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can increase KCP&L’s maintenance costs at these stations and, if these levels were to get low enough, could cause KCP&L to modify plant operations.
 
KCP&L and Strategic Energy have Commodity Price Risks
KCP&L and Strategic Energy engage in the wholesale and retail marketing of electricity and accordingly, are exposed to risks associated with the price of electricity. Strategic Energy routinely
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enters into contracts to purchase and sell electricity in the normal course of business. KCP&L generates, purchases and sells electricity in the retail and wholesale markets.

Fossil Fuel and Transportation Prices Impact KCP&L’s Costs
Less than 1% of KCP&L's rates contain an automatic fuel adjustment clause, exposing KCP&L to risk from changes in the market prices of coal and natural gas used to generate power and in the cost of coal and natural gas transportation. Changes in KCP&L’s fuel mix due to electricity demand, plant availability, transportation issues, fuel prices and other factors can also adversely affect KCP&L’s fuel costs.

KCP&L does not hedge its entire exposure from fossil fuel and transportation price volatility. As a consequence,Consequently, its results of operations and financial position may be materially impacted by changes in these prices until increased costs are recovered in rates.

Wholesale Electricity Prices Affect Costs and Revenues
KCP&L's ability to maintain or increase its level of wholesale sales depends on the wholesale market price, transmission availability and the availability of KCP&L’s generation for wholesale sales, among other factors. A substantial portion of KCP&L’s wholesale sales are made in the spot market, and thus KCP&L has immediate exposure to wholesale price changes. Declines in wholesale market price or availability of generation or transmission constraints in the wholesale markets, could reduce KCP&L's wholesale sales and adversely affect KCP&L’s results of operations and financial position.

KCP&L is also exposed to price risk because at times it purchases power to meet its customers’ needs. The cost of these purchases may be affected by the timing of customer demand and/or unavailability of KCP&L’s lower-priced generating units. Wholesale power prices can be volatile and generally increase in times of high regional demand and high natural gas prices.

Strategic Energy operates in competitive retail electricity markets, competing against the host utilities and other retail suppliers. Wholesale electricity costs, which account for a significant portion of its operating expenses, can materially affect Strategic Energy’s ability to attract and retain retail electricity customers at profitable prices.customers. There is also a regulatory lag that slows the adjustment of host public utility rates in response to changes in wholesale prices. This lag can negatively affect Strategic Energy’s ability to compete in a rising wholesale price environment. Strategic Energy manages wholesale electricity risk by establishing risk limits and entering into contracts to offset some of its positions to balance energy supply and demand; however, Strategic Energy does not hedge its entire exposure to electricity price volatility. As a consequence,Consequently, its results of operations and financial position may be materially impacted by changes in the wholesale price of electricity.
 
KCP&L has Operations Risks
The operation of KCP&L’s electric generation, transmission and distribution systems involves many risks, including breakdown or failure of equipment or processes; operating limitations that may be imposed by equipment conditions, environmental or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; transmission scheduling; and catastrophic events such as fires, explosions, severe weather or other similar occurrences.
 
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These and other operating events may reduce KCP&L’s revenues or increase its costs, or both, and may materially affect KCP&L’s results of operations and financial position.
 
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
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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, the scope and timing of projects may change, and other events beyond KCP&L’s control may occur that may materially affect the schedule, budget and performance of these projects.  
The anticipated acquisition of Aquila will increase Great Plains Energy’s ownership of Iatan Nos. 1 and 2. Aquila owns 18% of both Iatan generating units. Great Plains Energy’s post-acquisition ownership percentages of the Iatan generating units would be 88% of Iatan No. 1 and 72.71% of Iatan No. 2.

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.
KCP&L’s estimated capital expenditures for its comprehensive energy plan have increased. The primary driver of the increased cost estimate is the environmental retrofit of two 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 estimated cost and completion times for environmental retrofits, as well as for the other comprehensive energy plan projects. 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. 
These and other risks may increase the estimated costs of these construction projects, delay the in-service dates of these projects, or 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.
Failure of one or more generation plant co-owners to pay their share of construction, operations and maintenance costs could increase KCP&L’s costs and capital requirements.

KCP&L owns 47% of Wolf Creek, 50% of LaCygne Station, 70% of Iatan No. 1 and 55% of Iatan No. 2. The remaining portions of these facilities are owned by other utilities that are contractually obligated to pay their proportionate share of capital and other costs and, in the case of Iatan No. 2, construction costs.
While the ownership agreements provide that a defaulting co-owner’s share of the electricity generated can be sold by the non-defaulting co-owners, there is no assurance that the revenues received will recover the increased costs borne by the non-defaulting co-owners. Further, the Iatan No. 2 agreements provide during the construction period for re-allocations of part or all of a defaulting co-owner’s share of the facility to the non-defaulting owners, which would increase the capital, operations and maintenance costs of the non-defaulting owners. While management considers these matters to be unlikely, their occurrence could materially increase KCP&L’s costs and capital requirements.
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KCP&L has Retirement-Related Risks
Through 2010, approximately 30%20% 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 postretirementpost-retirement 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 its investments, or if interest rates materially fall, KCP&L’s pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump sum payment option could result in pension settlement charges that could materially affect KCP&L’s results of operations. 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. Proposed legislation pending
The Pension Protection Act of 2006 alters the manner in Congress onwhich pension reformplan assets and liabilities are valued for purposes of calculating required pension contributions and changes the timing of required contributions to underfunded plans. The funding rules, which become effective in 2008, could result in increased pensionsignificantly affect the Company’s funding requirements. TheIn addition, the Financial Accounting Standards Board (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.expense.

KCP&L has Nuclear Exposure
KCP&L owns 47% (548 MW) of Wolf Creek. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including Wolf Creek. In the event of non-compliance, the NRC has the authority to impose fines, shut down the facilities, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Any revised safety requirements promulgated by the NRC could result in substantial capital expenditures at Wolf Creek.
 
Wolf Creek has the lowest fuel cost per MWh of any of KCP&L's generating units. Although not expected, an extended outage of Wolf Creek, whether resulting from NRC action, an incident at the plant or otherwise, could have a substantial adverse effect on KCP&L's results of operations and financial position in the event KCP&L incurs higher replacement power and other costs that are not recovered through rates. If a long-term outage occurred, the state regulatory commissions could reduce rates by excluding the Wolf Creek investment from rate base.
 
Ownership and operation of a nuclear generating unit exposes KCP&L to risks regarding decommissioning costs at the end of the unit's life. KCP&L contributes annually to a tax-qualified trust fund to be used to decommission Wolf Creek. The funding level assumes a projected level of return on trust assets. If the actual return on trust assets is below the anticipated level, KCP&L could be responsible for the balance of funds required. If returns are lower than the expected level,required; however, should this happen, management believes a rate increase would be allowed ensuring full recovery of decommissioning costs over the remaining life of the unit.
 
KCP&L is also exposed to other risks associated with the ownership and operation of a nuclear generating unit, including, but not limited to, potential liability associated with the potential harmful effects on the environment and human health resulting from the operation of a nuclear generating unit and the
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storage, handling and disposal of radioactive materials, and to potential retrospective assessments and losses in excess of insurance coverage.
 
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KCP&L’s participation in the SPP could increase costs, reduce revenues, and reduce KCP&L’s control over its transmission assets.
Functional control of the KCP&L transmission systems was transferred to the SPP during the third quarter of 2006. KCP&L may be required to incur expenses or expand its transmission systems, which it would seek recovery for through rate increases, according to decisions made by the SPP rather than according to its internal planning process.
The SPP Energy Imbalance Service (EIS) Market, which began operation on February 1, 2007, is designed to improve transparency of power pricing and efficiency in generation dispatch. This is a new and complex market, which may result in significant price volatility and suboptimal dispatching of power plants. In addition, the sale of power in this market-based environment may result in unanticipated transmission congestion and other settlement charges.
Until KCP&L achieves a greater degree of operational experience participating in the SPP, including the SPP EIS Market, there is uncertainty as to the impact of its participation. In addition, there is uncertainty regarding the impact of ongoing RTO developments at FERC. KCP&L is unable to predict the impact these issues could have on its results of operations and financial position.
Strategic Energy Operates in Competitive Retail Electricity Markets
Strategic Energy has several competitors that operate in most or all of the same states in which it serves customers. Some of these competitors also operate in states other than where Strategic Energy has operations. It also faces competition in certain markets from regional suppliers and deregulated utility affiliates formed by holding companies affiliated with regulated utilities to provide retail load in their home market territories. Strategic Energy's competitors vary in size from small companies to large corporations, some of which have significantly greater financial, marketing and procurement resources than Strategic Energy. Additionally, Strategic Energy as well as its other competitors, must compete with the host utility in order to convince customers to switch from the host utility.utility to Strategic Energy as their electric service provider. Strategic Energy’s results of operations and financial position are impacted by the success Strategic Energy has in attracting and retaining customers in these markets.
 
Strategic Energy has Wholesale Electricity Supplier Credit Risk
Strategic Energy has credit risk exposure in the form of the loss that it could incur if a counterparty failed to perform under its contractual obligations. Strategic Energy enters into forward contracts with multiple suppliers. In the event of supplier non-delivery or default, Strategic Energy’s results of operations couldmay 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. Strategic Energy’s results of operations couldmay 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. Additionally, Strategic Energy’s results of operations may be affected by increased bad debt expense if retail customers failed to satisfy their contractual obligations to pay Strategic Energy for electricity.
 
ITEM 1B. UNRESOLVED STAFF COMMENTS
 
None.
 
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ITEM 2. PROPERTIES
 
KCP&L Generation Resources
                   
   
Year
 
Estimated 2006
 
Primary
   
Year
 
Estimated 2007
 
Primary
 
Unit
 
Completed
 
MW Capacity
 
Fuel
 
Unit
 
Completed
 
MW Capacity
 
Fuel
Base LoadBase LoadWolf Creek 1985  548
(a)
 Nuclear Base LoadWolf Creek 1985  548
(a)
 Nuclear 
 Iatan No. 1 1980  456
(a) (b)
 Coal  Iatan No. 1 1980  460
(a) (b)
 Coal 
 LaCygne No. 2 1977  341
(a)
 Coal  LaCygne No. 2 1977  341
(a)
 Coal 
 LaCygne No. 1 1973  370
(a)
 Coal  LaCygne No. 1 1973  368
(a)
 Coal 
 
Hawthorn No. 5 (c)
 1969  563  Coal  
Hawthorn No. 5 (c)
 1969  563  Coal 
 Montrose No. 3 1964  176  Coal  Montrose No. 3 1964  176  Coal 
 Montrose No. 2 1960  164  Coal  Montrose No. 2 1960  164  Coal 
 Montrose No. 1 1958  170  Coal  Montrose No. 1 1958  170  Coal 
Peak LoadPeak Load
West Gardner Nos. 1, 2, 3 and 4 (e)
2003  308  Natural GasPeak Load
West Gardner Nos. 1, 2, 3 and 4 (d)
2003  308  Natural Gas
 
Osawatomie (e)
 2003  77  Natural Gas 
Osawatomie (d)
 2003  77  Natural Gas
 
Hawthorn No. 9 (d)
 2000  130  Natural Gas 
Hawthorn No. 9 (e)
 2000  130  Natural Gas
 
Hawthorn No. 8 (e)
 2000  77  Natural Gas 
Hawthorn No. 8 (d)
 2000  77  Natural Gas
 
Hawthorn No. 7 (e)
 2000  77  Natural Gas 
Hawthorn No. 7 (d)
 2000  77  Natural Gas
 
Hawthorn No. 6 (e)
 1997  136  Natural Gas 
Hawthorn No. 6 (d)
 1997  136  Natural Gas
 
Northeast Nos. 17 and 18 (e)
 1977  117  Oil  
Northeast Nos. 17 and 18 (e)
 1977  117  Oil 
 
Northeast Nos. 15 and 16 (e)
 1975  116  Oil  
Northeast Nos. 15 and 16 (e)
 1975  116  Oil 
 
Northeast Nos. 13 and 14 (e)
 1976  114  Oil  
Northeast Nos. 13 and 14 (e)
 1976  114  Oil 
 
Northeast Nos. 11 and 12 (e)
 1972  111  Oil  
Northeast Nos. 11 and 12 (e)
 1972  111  Oil 
 Northeast Black Start Unit 1985  2  Oil  Northeast Black Start Unit 1985  2  Oil 
WindWind
Spearville Wind Energy Facility(f)
2006  -  Wind 
TotalTotal     4,053    Total    4,055  
(a)
KCP&L's share of a jointly owned unit.         
(b)(a)
The Iatan No. 2 air permit limits KCP&L's accredited capacity of Iatan No. 1 to 456 MWs from 469 MWsKCP&L's share of a jointly owned unit.       
until the air quality control equipment included in the comprehensive energy plan is operational.
(b)
The Iatan No. 2 air permit limits KCP&L's accredited capacity of Iatan No. 1 to 460 MWs from 469 MWs
(c)
The Hawthorn Generating Station returned to commercial operation in 2001 with a new boiler, air qualityuntil the air quality control equipment included in the comprehensive energy plan is operational. 
(c)control equipment and an uprated turbine following a 1999 explosion.The Hawthorn Generating Station returned to commercial operation in 2001 with a new boiler, air quality
(d)
Heat Recovery Steam Generator portion of combined cycle.
control equipment and an uprated turbine following a 1999 explosion.   
(e)(d)
Combustion turbines.Combustion turbines.       
(e)
Heat Recovery Steam Generator portion of combined cycle.     
(f)
In 2006, KCP&L completed the 100.5 MW Spearville Wind Energy Facility in Spearville, KS. Wind is not
currently eligible for accredited capacity under SPP reliability standards.   
 
KCP&L owns the Hawthorn Station (Jackson County, Missouri), Montrose Station (Henry County, Missouri), Northeast Station (Jackson County, Missouri), West Gardner Station (Johnson County, Kansas) and, Osawatomie Station (Miami County, Kansas) and Spearville Wind Energy Facility (Ford County, Kansas). KCP&L also owns 50% of the 740736 MW LaCygne No. 1 and 682 MW LaCygne No. 2 (Linn County, Kansas), 70% of the 651657 MW Iatan No. 1 (Platte County, Missouri) and 47% of the 1,166 MW Wolf Creek Unit (Coffey County, Kansas). See Note 56 to the consolidated financial statements for information regarding KCP&L’s comprehensive energy plan and the proposed additionconstruction of new generation capacity.
 
KCP&L Transmission and Distribution Resources
KCP&L’s electric transmission system interconnects with systems of other utilities for reliability and to permit wholesale transactions with other electricity suppliers. KCP&L owns over 1,700 miles of
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transmission lines, approximately 9,000 miles of overhead distribution lines and over 3,7003,800 miles of underground distribution lines in Missouri and Kansas. KCP&L has all the franchises necessary to sell electricity within the territories from which substantially all of its gross operating revenue is derived.
retail service territory. KCP&L’s transmission and distribution systems are continuously monitored for adequacy to meet customer needs. Management believes the current systems are adequate to serve its customers.
 
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KCP&L General
KCP&L’s principal plants and properties, insofar as they constitute real estate, are owned in fee simple.simple except for the Spearville Wind Energy Facility, which is on land held under easements. Certain other facilities are located on premises held under leases, permits or easements. KCP&L electric transmission and distribution systems are for the most part located over or under highways, streets, other public places or property owned by others for which permits, grants, easements or licenses (deemed satisfactory but without examination of underlying land titles) have been obtained.
 
Substantially all of the fixed property and franchises of KCP&L, which consists principally of electric generating stations, electric transmission and distribution lines and systems, and buildings subject to exceptions and reservations, are subject to a General Mortgage Indenture and Deed of Trust dated as of December 1, 1986. General mortgage bonds totaling $159.3 million were outstanding at December 31, 2005.2006.
 
ITEM 3. LEGAL PROCEEDINGS
 
KCP&L Missouri Rate Cases
On February 1, 2007, KCP&L filed a retail rate case with the MPSC, requesting an annual rate increase effective January 1, 2008, of approximately $45 million over current levels. Hearings on this case are expected to begin in the fall of 2007, with a decision expected in December 2007.
On February 1, 2006, KCP&L filed a request with the MPSC to increase annual rates $55.8 million for customers served in Missouri. The amount of the request was based, among other things, on a return on equity of 11.5% and an adjusted equity ratio of 53.8%. On December 21, 2006, the MPSC issued its order with an effective date of December 31, 2006. The order approved an approximate $51 million increase in annual revenues, reflecting an authorized return on equity of 11.25%. Approximately $22 million of the rate increase results from additional amortization to help maintain cash flow levels. The rates established by the order reflect an annual offset of approximately $69 million ($39 million Missouri jurisdiction) related to annual non-firm wholesale electric sales margin. The amount by which the actual margin amount is higher than this level will be recorded as a regulatory liability and reflected in KCP&L’s next rate case. The order established, for regulatory purposes, annual pension cost recovery for the period beginning January 1, 2007, of approximately $35 million ($19 million Missouri jurisdiction), which excludes allocations to the other joint owners of generation facilities and capitalized amounts. The order also established, effective January 1, 2006, a regulatory asset or liability as appropriate for amounts 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. The rates set by the order also reflect the MPSC’s decisions on various other accounting and regulatory matters. Appeals of the December 21, 2006, order of the MPSC authorizing an increase in annual rates of approximately $51 million were filed in February 2007 with the Circuit Court of Cole County, Missouri, by the Office of Public Counsel, Praxair, Inc., and Trigen-Kansas City Energy Corporation. The appeals seek to set aside or remand the order to the MPSC. Although subject to the appeals, the MSPC order remains in effect pending the court's decision.
KCP&L Kansas Rate Case
On February 1, 2006, KCP&L filed a request with KCC to increase annual rates $42.3 million for customers served in Kansas. KCP&L reached a negotiated settlement of its request with certain
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parties to the rate proceedings, and filed a Stipulation and Agreement (Agreement) on September 29, 2006, containing the settlement with KCC. On December 4, 2006, KCC issued its order approving the Agreement in its entirety. The order approved a $29 million increase in annual revenues effective January 1, 2007, with $4 million of that amount resulting from additional depreciation to help maintain cash flow levels. The order also approved various accounting and other matters, 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 amounts 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; (iii) setting at 8.5% the equity rate for the equity component of the allowance for funds used during construction rate calculation for Iatan No. 2; and (iv) the filing by KCP&L of an ECA clause in its next rate case, to be filed no later than March 1, 2007.
KCP&L Regulatory Plan Appeals
On March 28, 2005, and April 27, 2005, KCP&L filed Stipulations and Agreements with the MPSC and KCC, respectively, containing a regulatory plan and other provisions. Parties to the MPSC Stipulation and Agreement are KCP&L, the Staff of the MPSC, the City of Kansas City, Missouri, Office of Public Counsel, Praxair, Inc., Missouri Industrial Energy Consumers, Ford Motor Company, Aquila, Inc., The Empire District Electric Company, Missouri Joint Municipal Electric Utility Commission and the Missouri Department of Natural Resources. Parties to the KCC Stipulation and Agreement are KCP&L, the Staff of the KCC, Sprint Nextel Corporation and the Kansas Hospital Association.
The MPSC issued its Report and Order, approving the Stipulation and Agreement, on July 28, 2005, and KCC issued its Order Approving Stipulation and Agreement on August 5, 2005. On September 22, 2005, the Sierra Club and Concerned Citizens of Platte County, two nonprofit corporations, filed a petition for review in the Circuit Court of Cole County, Missouri, seeking to review and set aside the MPSC Report and Order. On March 13, 2006, the Circuit Court affirmed the MPSC Report and Order, and the Sierra Club and Concerned Citizens of Platte County appealed to the Missouri Court of Appeals for the Western District. On October 21, 2005, the Sierra Club filed a petition for review in the District Court of Shawnee County, Kansas, seeking to set aside or remand KCC order. On May 1, 2006, the District Court denied the petition, and the Sierra Club appealed to the Kansas Court of Appeals. Although subject to the appeals, the MPSC and KCC orders remain in effect pending the courts’ decisions.
Kansas City Power & Light Company v. Union Pacific Railroad Company
On October 12, 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 instituted a rulemaking to address issues regarding the cost test used in rail rate cases and the proper calculation of rail rate relief. As part of that order, the STB delayed hearing KCP&L’s case pending the outcome of the rulemaking, and declared that the results of the rulemaking would apply to KCP&L’s test. On October 30, 2006, the STB issued its decision, adopting the proposals set out in its rulemaking. This decision has been appealed by other parties to the Federal Circuit Court of Appeals for the District of Columbia. In July 2006, the STB directed KCP&L and Union Pacific to file comments in September 2006 on whether KCP&L’s complaint is within the STB’s jurisdiction. If the STB determines it does have jurisdiction, KCP&L anticipates a ruling on its case in
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the second half of 2008. Until the STB case is decided, KCP&L is paying the higher tariff rates subject to refund.
Hawthorn No. 5 Litigation
In 1999, there was a boiler explosion at KCP&L’s Hawthorn No. 5 generating unit, which was subsequently reconstructed and returned to service. National Union Fire Insurance Company of Pittsburgh, Pennsylvania (National Union) and Reliance National Insurance had issued a $200 million primary insurance policy and Travelers Indemnity Company of Illinois (Travelers) had issued a $100 million secondary insurance policy covering Hawthorn No. 5. A dispute arose among KCP&L, National Union and Travelers regarding the amount payable under these insurance policies for the reconstruction of Hawthorn No. 5 and replacement power expenses. KCP&L filed suit against these two insurers, which was settled with the payment of the policy limit of the primary insurance policy (less the deductible amount), and with a $10 million payment by Travelers under its insurance policy.
KCP&L also filed suit in 2001 against multiple defendants who were alleged to have responsibility for the Hawthorn No. 5 boiler explosion. 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. Various defendants settled with KCP&L, and KCP&L received a judgment against the final remaining defendant in 2006. In 2005, Travelers filed suit against National Union in the U.S. District Court for the Eastern District of Missouri, asserting that it was entitled to reimbursement or subrogation for the $10 million it paid to KCP&L from money recovered by KCP&L and National Union in the subrogation case. On June 19, 2006, KCP&L was added as a defendant to this case. The case was subsequently transferred to, and is pending in, the U.S. District Court for the Western District of Missouri.
Iatan Station Air Permit
On January 31, 2006, the Missouri Department of Natural Resources issued an air permit to KCP&L for the construction of Iatan No. 2 and modifications to Iatan No. 1. The Sierra Club appealed the issuance of this permit to the Missouri Air Conservation Commission, and on September 29, 2006, filed a motion requesting that construction work on Iatan No. 2 be stayed during the pendency of the appeal. The motion was denied on October 18, 2006. A hearing on this appeal has been scheduled for March 2007. The permit remains in effect pending the outcome of the appeal.

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. KLT Telecom denied that Weinstein has any remaining rights or claims pursuant to the put optionexercise, and denied any obligation to pay Weinstein any amount under the put option. Subsequent to KLT Telecom’s rejection of his notice of exercise, 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 has 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 have been held and the case is pending the decision of the court. The $15 million reserve has not been reversed pending the outcome of the appeal process, which management expects will conclude in early 2006.
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 Fire Insurance Company of Pittsburgh, Pennsylvania (National Union) 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 have been dismissed from the suit and various defendants settled, with KCP&L receiving a total of $38.2 million under the terms of the subrogation allocation agreement. 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. 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), the verdict would have resulted in an award against the defendant of approximately $97.6 million (of which KCP&L would have received $33 million pursuant to the subrogation allocation agreement after payment of attorney’s fees). In response to post-trial pleadings filed by the defendant, in May 2004, the trial judge reduced the award against the defendant to $0.2 million. Both KCP&L and the defendant have appealed this case to the Court of Appeals for the Western District of Missouri. Oral arguments are expected in the first quarter of 2006.process.
 
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25
KCP&L Stipulations and Agreements
On March 28, 2005, and April 27, 2005, KCP&L filed Stipulations and Agreements with the MPSC and KCC, respectively, containing a regulatory plan and other provisions. The Stipulations and Agreements are discussed in Note 5 to the consolidated financial statements, which is incorporated herein by reference. Parties to the MPSC Stipulation and Agreement are KCP&L, the Staff of the MPSC, the City of Kansas City, Missouri, Office of Public Counsel, Praxair, Inc., Missouri Industrial Energy Consumers, Ford Motor Company, Aquila, Inc., The Empire District Electric Company, Missouri Joint Municipal Electric Utility Commission and the Missouri Department of Natural Resources. Parties to the KCC Stipulation and Agreement are KCP&L, the Staff of the KCC, Sprint Nextel Corporation and the Kansas Hospital Association.
The MPSC issued its Report and Order, approving the Stipulation and Agreement, on July 28, 2005, and the KCC issued its Order Approving Stipulation and Agreement on August 5, 2005. On September 22, 2005, the Sierra Club and Concerned Citizens of Platte County, two nonprofit corporations, filed a petition for review in the Circuit Court of Cole County, Missouri, seeking to review and set aside the MSPC Report and Order. On October 21, 2005, the Sierra Club filed a petition for review in the District Court of Shawnee County, Kansas, seeking to set aside or remand the KCC order. Although subject to the appeal, the MPSC and KCC orders remain in effect pending the court’s decision. The appeals are expected to be decided by the courts in 2006.
KCP&L Rate Cases
On February 1, 2006, KCP&L filed retail rate 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. Hearings on these cases are expected to begin in September 2006 and the decisions of the MPSC and KCC are expected in December 2006.
Kansas City Power & Light Company v. Union Pacific Railroad Company
On October 12, 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. Management anticipates filing opening evidence by mid-year 2006 and the STB issuing its decision toward the end of 2007. Until the STB case is finalized, KCP&L is paying tariff rates subject to refund.
Tech Met, Inc., et al. v. Strategic Energy
On November 21, 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 five named plaintiffs purportedly represent the interests of customers in Pennsylvania who entered into Power Supply Coordination Service Agreements (Agreement) for electricity service. The complaint seeks monetary damages, attorney fees and costs and a declaration that the customers may terminate their Agreement with Strategic Energy. In response to Strategic Energy’s preliminary objections, the plaintiffs have filed an amended complaint. Strategic Energy has filed preliminary objections asking the courtbeen granted an indefinite period of time to order plaintiffsrespond to file anthis amended complaint that conforms to applicable court rules.complaint.
 
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 5, 13 and 15 to the consolidated financial statements. Such descriptions are incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
During the fourth quarter of 2005,2006, no matter was submitted to a vote of security holders through the solicitation of proxies or otherwise for either Great Plains Energy or KCP&L.
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PART II
 
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
GREAT PLAINS ENERGY
Great Plains Energy common stock is listed on the New York Stock Exchange under the symbol GXP. At February 28, 2006,21, 2007, Great Plains Energy’s common stock was held by 14,18613,249 shareholders of record. Information relating to market prices and cash dividends on Great Plains Energy's common stock is set forth in the following table.
  
  
Common Stock Price Range
 
Common Stock
 
  
2006
 
2005
 
Dividends Declared
 
Quarter
 
High
 
Low
 
High
 
Low
 
2007
2006
 
2005
 
First $29.32 $27.89 $31.61 $29.56 $
0.415 (a)
$0.415 $0.415 
Second  28.99  27.33  32.25  29.77    0.415  0.415 
Third  31.43  27.70  32.63  29.82    0.415  0.415 
Fourth  32.80  31.13  30.23  27.27     0.415  0.415 
(a) Declared February 6, 2007.
                  
  
Common Stock Price Range
 
Common Stock
 
  
2005
 
2004
 
Dividends Declared
 
Quarter
 
High
 
Low
 
High
 
Low
 
2006
 
2005
2004
 
First $31.61 $29.56 $35.29 $31.66 $0.415 (a)   $0.415 $0.415 
Second  32.25  29.77  34.36  29.23      0.415  0.415 
Third  32.63  29.82  31.71  28.62      0.415  0.415 
Fourth  30.23  27.27  30.71  28.17      0.415  0.415 
(a) Declared February 7, 2006.
              

Regulatory Restrictions
Under stipulations with the MPSC and KCC, Great Plains Energy has committed to maintain consolidated common equity of not less than 30%.
 
Dividend Restrictions
Great Plains Energy's Articles of Incorporation contain certain restrictions on the payment of dividends on Great Plains Energy's common stock in the event common equity falls to 25% of total capitalization. If preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock
26
dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect members to the Board of Directors.
24
Equity Compensation Plan
The Company’s Long-Term Incentive Plan is an equity compensation plan approved by its shareholders. The Long-Term Incentive Plan permits the grant of restricted stock, stock options, limited stock appreciation rights and performance shares to officers and other employees of the Company and its subsidiaries. The following table provides information, as of December 31, 2005,2006, regarding the number of common shares to be issued upon exercise of outstanding options, warrants and rights, their weighted average exercise price, and the number of shares of common stock remaining available for future issuance under the Long-Term Incentive Plan. The table excludes shares issued or issuable under Great Plains Energy’s defined contribution savings plans.
 
           
Number of securities
           
remaining available
           
for future issuance
  
Number of securities to
Weighted-average
 
under equity
  
be issued upon exercise
exercise price of
 
compensation plans
  
of outstanding options,
outstanding options,
 
(excluding securities
  
warrants and rights
warrants and rights
 
reflected in column (a))
Plan Category
 
(a)
 
(b)
 
(c)
Equity compensation plans            
  approved by security holders
  364,183
(1)
  $ 25.52
(2)
  1,878,929 
Equity compensation plans not            
      approved by security holders -  -  - 
      Total 364,183  $ 25.52  1,878,929 
(1)  Includes 254,711 performance shares at target performance levels and options for 109,472 shares of Great Plains
    Energy common stock outstanding at December 31, 2006.
(2)  The 254,711 performance shares have no exercise price and therefore are not reflected in the weighted average
    exercise price.
 
              
           
Number of securities
           
remaining available
           
for future issuance
  
Number of securities to
Weighted-average
 
under equity
  
be issued upon exercise
exercise price of
 
compensation plans
  
of outstanding options,
outstanding options,
 
(excluding securities
  
warrants and rights
warrants and rights
 
reflected in column (a))
Plan Category
 
(a)
 
(b)
 
(c)
Equity compensation plans            
 approved by security holders  284,216(1)  $ 25.56
(2)
  2,014,496 
Equity compensation plans not            
 approved by security holders  -   -   - 
 Total  284,216  $ 25.56   2,014,496 
(1)
Includes 172,761 performance shares at target performance levels and options for 111,455 shares of Great Plains
 Energy common stock outstanding at December 31, 2005.
(2)
The 172,761 performance shares have no exercise price and therefore are not reflected in the weighted average
 exercise price.
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Purchases of Equity Securities
The following table provides information regarding purchases by the Company of its equity securities during the fourth quarter of 2005.
2006.
              
Issuer Purchases of Equity Securities
           
Maximum Number
        
Total Number of
(or Approximate
        
Shares (or Units)
Dollar Value) of
  
Total
   
Purchased as
Shares (or Units)
  
Number of
 Average
Part of Publicly
that May Yet Be
  
Shares
 Price Paid
Announced
Purchased Under
  
(or Units)
per Share
Plans or
the Plans or
Month
Purchased
(or Unit)
Programs
Programs
October 1 - 31 5,862
(1)
 $30.12  -  N/A 
November 1 - 30 1,390
(1)
 28.54  -  N/A 
December 1 - 31 -  -  -  N/A 
  Total
 7,252 $29.82  -  N/A 
(1)
Represents shares of common stock surrendered to the Company by certain officers to pay taxes
 related to the vesting of restricted common stock.
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Issuer Purchases of Equity Securities
            
Maximum Number
        
Total Number of
 
(or Approximate
        
Shares (or Units)
 
Dollar Value) of
  
Total
   
Purchased as
 
Shares (or Units)
  
Number of
 Average
Part of Publicly
 
that May Yet Be
  
Shares
 Price Paid
Announced
 
Purchased Under
  
(or Units)
per Share
Plans or
 
the Plans or
Month
Purchased
(or Unit)
Programs
 
Programs
October 1 - 31 4,777
(1)
 $31.12  -   N/A 
November 1 - 30 3,042
(1)
 32.18  -   N/A 
December 1 - 31 -  -  -   N/A 
Total 7,819  $31.53  -   N/A 
(1)
Represents shares of common stock surrendered to the Company by certain officers to pay taxes
 related to the vesting of restricted common stock.      
 
KCP&L
KCP&L is a wholly owned subsidiary of Great Plains Energy, which holds the one share of issued and outstanding KCP&L common stock.
 
Regulatory Restrictions
Under the Federal Power Act, KCP&L can pay dividends only out of retained or current earnings. Under stipulations with the MPSC and KCC, KCP&L has committed to maintain consolidated common equity of not less than 35%.
 
Equity Compensation Plan
KCP&L does not have an equity compensation plan; however, KCP&L officers participate in Great Plains Energy’s Long-Term Incentive Plan.
 
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ITEM 6. SELECTED FINANCIAL DATA
            
Year Ended December 31
 
2005
 
2004
 
2003
 
2002
 
2001
 
Great Plains Energy (a)
 (dollars in millions except per share amounts)
Operating revenues $2,605 $2,464 $2,148 $1,802 $1,399 
Income (loss) from continuing operations (b)
 $164 $174 $190 $137 $(28)
Net income (loss) $162 $181 $145 $126 $(24)
Basic and diluted earnings (loss) per common            
share from continuing operations $2.18 $2.39 $2.72 $2.16 $(0.49)
Basic and diluted earnings (loss) per                
common share $2.15 $2.49 $2.07 $1.99 $(0.42)
Total assets at year end $3,834 $3,799 $3,682 $3,517 $3,464 
Total redeemable preferred stock, mandatorily                
redeemable preferred securities and long-                
term debt (including current maturities) $1,143 $1,296 $1,347 $1,332 $1,342 
Cash dividends per common share $1.66 $1.66 $1.66 $1.66 $1.66 
SEC ratio of earnings to fixed charges  3.61  3.51  4.23  2.99  (c)
                 
Consolidated KCP&L (a)
                
Operating revenues $1,131 $1,092 $1,057 $1,013 $1,287 
Income from continuing operations (d)
 $144 $143 $126 $103 $116 
Net income $144 $143 $117 $96 $120 
Total assets at year end $3,339 $3,337 $3,303 $3,139 $3,146 
Total redeemable preferred stock, mandatorily                
redeemable preferred securities and long-                
term debt (including current maturities) $976 $1,126 $1,336 $1,313 $1,311 
SEC ratio of earnings to fixed charges  3.87  3.34  3.69  2.88  2.07 
 
   
 As Adjusted
As Adjusted
As Adjusted
As Adjusted
Year Ended December 31
 
2006
 2005 (d)
2004 (d)
2003(d)
2002(d)
Great Plains Energy (a)
 (dollars in millions except per share amounts) 
Operating revenues $2,675 $2,605 $2,464 $2,148 $1,802 
Income from continuing operations (b)
 $128 $164 $175 $189 $136 
Net income $128 $162 $183 $144 $125 
Basic earnings per common                
share from continuing operations $1.62 $2.18 $2.41 $2.71 $2.15 
Basic earnings per common share $1.62 $2.15 $2.51 $2.06 $1.98 
Diluted earnings per common                
share from continuing operations $1.61 $2.18 $2.41 $2.71 $2.15 
Diluted earnings per common share $1.61 $2.15 $2.51 $2.06 $1.98 
Total assets at year end $4,336 $3,842 $3,796 $3,694 $3,521 
Total redeemable preferred stock, mandatorily            
redeemable preferred securities and long-                
term debt (including current maturities) $1,142 $1,143 $1,296 $1,347 $1,332 
Cash dividends per common share $1.66 $1.66 $1.66 $1.66 $1.66 
SEC ratio of earnings to fixed charges  3.20  3.60  3.54  4.22  2.98 
                 
Consolidated KCP&L (a)
                
Operating revenues $1,140 $1,131 $1,092 $1,057 $1,013 
Income from continuing operations (c)
 $149 $144 $145 $125 $102 
Net income $149 $144 $145 $116 $95 
Total assets at year end $3,859 $3,340 $3,335 $3,315 $3,143 
Total redeemable preferred stock, mandatorily            
redeemable preferred securities and long-                
term debt (including current maturities) $977 $976 $1,126 $1,336 $1,313 
SEC ratio of earnings to fixed charges  4.11  3.87  3.37  3.68  2.87 
(a)  Great Plains Energy’s and KCP&L’s consolidated financial statements include results for all subsidiaries in operation for the periods presented. KCP&L’s consolidated financial statements include its wholly owned subsidiary HSS. In addition, KCP&L’s consolidated results of operations include KLT Inc. and GPP for all periods prior to the October 1, 2001, formation of Great Plains Energy.
(b)  This amount is before discontinued operations of $(1.9), $7.3, $(44.8), and $(7.5) and $4.3 million in 2005 through 2001,2002, respectively. In 2002, this amount is before a $3.0 million cumulative effect of a change in accounting principle.
(c)  An $87.1 million deficiency in earnings caused the ratio of earnings to fixed charges to be less than a one-to-one coverage. A $195.8 million net write-off before income taxes related to the bankruptcy filing of DTI was recorded in 2001.
(d)  This amount is before discontinued operations of $(8.7), and $(4.0) and $3.6 million in 2003 through 2001, respectively.and 2002. In 2002, this amount is before a $3.0 million cumulative effect of a change in accounting principle.
(d) See Note 5 to the consolidated financial statements for information regarding Wolf Creek refueling outage costs and an associated change in accounting principle
 
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ITEM 7. 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. It should be read in conjunction with the accompanying consolidated financial statements and related notes. See Item 1A. Risk Factors for further discussion of the companies’ risk factors.
 
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.
 
Executive Summary
Great Plains Energy’s 2006 earnings were characterized by higher fuel costs, lower prices for wholesale sales and coal conservation in the first half of the year, partially offset by lower purchased power expense and higher retail revenue at KCP&L, as well as higher average retail gross margins per MWh without the impact of unrealized fair value gains and losses at Strategic Energy. Earnings for 2006 also reflect the absence of tax benefits experienced at KCP&L in 2005 and lower delivered volumes at Strategic Energy.
In 2006, KCP&L completed the Spearville Wind Energy Facility and received rate orders from the MPSC and KCC. KCP&L began construction of Iatan No.2, continued to make progress on environmental upgrades at existing facilities and implemented customer affordability and efficiency programs.
Anticipated Acquisition of Aquila, Inc.
In February 2007, Great Plains Energy entered into an agreement to acquire Aquila. Immediately prior to Great Plains Energy’s acquisition of Aquila, Black Hills Corporation will acquire Aquila’s electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa plus associated liabilities for a total of $940 million in cash, subject to closing adjustments. Each of the two transactions is conditioned on the completion of the other transaction and is expected to close in 2008. Management believes the anticipated acquisition will allow Great Plains Energy to expand its operations in a manner consistent with its strategic intent. Great Plains Energy entered into the transaction agreements with the expectation that the acquisition would result in various benefits to it and KCP&L including, among other things, synergies, cost savings and operating efficiencies. Assuming that such efficiencies are achieved and taking into account the anticipated cost of achieving such synergies, the transaction is expected to be modestly dilutive to earnings per share in 2008 and accretive beginning in 2009. See Note 3 to the consolidated financial statements for additional information.
EXECUTING ON STRATEGIC INTENT
During 2005, the Company initiated several important steps in executing on its Strategic Intent.
 
KCP&L’s Comprehensive Energy Plan
KCP&L continues to make progress in implementing its comprehensive energy plan andunder orders received orders from the MPSC and KCC in 2005. The orders were on agreements reached among KCP&L, the Commissions’ staffs and certain key parties in the respective jurisdictions. The Sierra Club and Concerned Citizens of Platte County have appealed the MPSC order, and the Sierra Club has appealed the KCC order. These appeals are expected to be decided in 2006. Although subject to these appeals, the MPSC and KCC orders remain in effect pending the applicable court’s decision.
In FebruaryDuring 2006, KCP&L filed requests withcompleted the MPSC and KCC for annual rate increases of $55.8 million or 11.5% and $42.3 million or 10.5%, respectively. Iatan No. 2 detailed project engineering and design has begun and plant construction is expected to start in 2006. KCP&L has selected a developer and contractor for the construction ofSpearville Wind Energy Facility, a 100.5 MW wind project in Kansaswestern Kansas. KCP&L also entered into certain procurement and management expects the project to be completed in timeengineering agreements for inclusion in rates in 2007.other comprehensive energy plan projects, and further refined its cost estimates and schedules as contracting and engineering progressed. See Note 56 to the consolidated financial statements for more information on the comprehensive energy plan.
Strategic Energy’s Business Plan
Strategic Energy is addressing the rising electricity price environmentplan estimated capital expenditures by focusing on four key areas.project.
·  Positioning - Strategic Energy is focused on retail choice markets where host utility electricity prices adjust quickly to changes in the wholesale markets and a consultative sales approach to provide value to customers.
·  Procurement - Strategic Energy is focused on strategies to gain price improvement through load aggregation to increase the volume purchased from certain suppliers. Strategic Energy has continued to invest in talent to improve procurement practices as well as identify and take advantage of opportunities to manage retail portfolio load requirements.
·  Products - Strategic Energy is focused on designing and marketing products to address customers’ needs in a high price environment. In 2005, over half of Strategic Energy’s new sales were attributable to the introduction of new products or product extensions into new customer classes. In 2006, management expects to introduce additional new and innovative products and services in each of Strategic Energy’s customer classes. The introduction of these products and services will strive to meet customers’ expectations in challenging and dynamic retail choice markets.
 
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The estimated capital expenditures include prices for labor and materials that reflect current and expected market conditions. They also include contingencies that reflect, among other things, the currently foreseen risks of those future market conditions as well as risks associated with global sourcing of materials. 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 of, and extension of scheduled completion times for, environmental retrofits. Because of the magnitude of the comprehensive energy plan projects and the length of the implementation period, the actual expenditures, scope and timing of any or all of these projects that have not been completed may differ materially from these estimates.
Construction of Iatan No. 2 is underway and on schedule for completion in 2010. KCP&L has approximately 50% of the total estimated cost of the project under firm contracts. The estimated range of capital expenditures for Iatan No. 2 includes items that are customarily excluded in calculating the installed cost per KW of a generating plant such as rail cars, substation expansion, interconnection upgrades, off-site improvements, solid waste landfill and operating spare parts. Excluding these items, the currently estimated installed cost for Iatan No. 2 ranges from approximately $1,700/KW to $1,875/KW, which KCP&L management believes is competitive with other similar projects to be built in the same timeframe.
 
The first phase of environmental upgrades at LaCygne No. 1, installation of selective catalytic reduction equipment, began in late 2005 and is expected to be in-service for the summer of 2007. KCP&L has almost all of the total estimated cost for the first phase under firm contract. The second phase of environmental upgrades at LaCygne No. 1 is expected to start design in 2007, and the market conditions noted above could impact the scope and timing. Iatan No. 1 environmental upgrades are on schedule with approximately 70% of the total estimated costs under firm contract.
·  Productivity - New systems are in the process of being implemented and are anticipated to improve operational scalability. Focusing on dynamic markets also enhances productivity by enabling Strategic Energy to maximize general and administrative resources.
In 2006, KCP&L implemented several pilot affordability, energy efficiency and demand response programs in Missouri and Kansas as well as distribution automation system improvements. Results from the implemented pilot programs have demonstrated an ability to manage KCP&L’s customers’ retail load requirements and by the end of 2006, KCP&L had developed the capability to effect a 60 MW reduction in retail load requirements. These results are evidenced by the success of KCP&L’s Energy Optimizer (a residential air conditioning cycling program), MPower (a commercial/industrial curtailment program) and distribution automation investments such as dynamic voltage control. Additionally in 2006, KCC initiated a general investigation into strategies for improving energy efficiency. The general issues that KCC is investigating relates 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 policies and regulations in Kansas designed to promote energy efficiency.
KCP&L Regulatory Proceedings
In December 2006, KCP&L received rate orders from the MPSC and KCC authorizing annual rate increases of $51 million and $29 million, respectively. The ordered rates were implemented January 1, 2007. See Note 6 to the consolidated financial statements for additional information. In February 2007, KCP&L filed a request with the MPSC for an annual rate increase of approximately $45 million. KCP&L is required to file a rate request with KCC on March 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 approximately 500,000over 505,000 customers in the states of
31
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 patterns areis 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 decreasedwas 83% in 2006 compared to 82% in 2005 from 84% in 2004, reflecting scheduled and forced plant outages. The 176 MW Montrose No. 3 generator step-up transformer (GSU) failed in late May 2005. KCP&L leased a spare GSU until the failed GSU was repaired and installed during the fourth quarter of 2005. In August 2005, Hawthorn No. 5’s GSU failed, which resulted in a 32-day outage. A spare GSU was installed in September; however, the size of the spare GSU limits the output of the unit to net 500 MW. The 65 MW decrease in Hawthorn No. 5 capability will continue until a new transformer is installed, currently expected in June 2006. The outage to install the repaired GSU is expected to be completed in 14 days.
 
KCP&L’s nuclear unit, Wolf Creek, accounts for approximately 20% of its base load capacity and overcapacity. In 2006, WCNOC submitted an application for a three-year period averaged over 20% of KCP&L’s MWhs generated.new operating license for Wolf Creek with the NRC, which would extend Wolf Creek’s availabilityoperating period to 2045. The NRC may take up to two years to rule on the application. Wolf Creek’s most recent refueling outage was approximately 13% lower in 2005 comparedOctober 2006 and lasted 35 days. The next refueling outage is scheduled to 2004 due to its scheduled spring 2005 refueling outage. Replacement power costsbegin in March 2008. In 2006, KCP&L changed the method of accounting for scheduledthe Wolf Creek outages are accrued evenly overrefueling outage and retrospectively adjusted prior periods. See Note 5 to the unit’s 18-month operating cycle. KCP&L expects its cost of nuclear fuel to remain relatively stable through 2009 because of contracts in place.consolidated financial statements for additional information.
 
The fuel cost per MWh generated and the purchased power cost per MWh hashave 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 generally 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.
 
KCP&LManagement expects its cost of nuclear fuel expense to increase significantlyremain relatively stable through 2009 because of contracts in 2006 due to projected increases inplace. Between 2010 and 2018, management anticipates the cost of coalnuclear fuel to increase approximately 30% to 50% due to higher contracted prices and coal transportation. Themarket conditions. Even with this anticipated increase, in delivered coal prices is expectedmanagement expects nuclear fuel cost per MWh generated to affect most regional utilities; therefore,remain less than the increase is not expected to materially erode KCP&L’s position as a low cost regional electricity generator.of other fuel sources.
 
Rail companies have experienced longer cycle times for coal deliveries to utilities across the country since the third quarter of 2004. Western rail service further deteriorated in 2005 due to two train derailments that occurred on the primary rail line serving the PRB. 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. Approximately 98% of KCP&L’s coal requirements come from the PRB
28
and originateare transported on the Burlington Northern Santa Fe and the Union Pacific railroads, both of which have been affected by the current rail situation. As a result, most utilities, includinghad experienced longer cycle times for coal deliveries in 2004 and 2005. In 2006, KCP&L’s coal shipments improved significantly, inventory levels improved and KCP&L have coal inventories that are below desired levels. KCP&L implementedsuspended its coal conservation measures by reducing coal generationimplemented in 2005 and expects2005. Management continues to continue these measures for at least the first half of 2006. This reduction in coal generation in the marketplace caused upward pressure on both pricing for next power generation fuel sources (natural gas and/or oil) and wholesale electricity prices in 2005 and is expected to continue into 2006. The rail companies have indicated that they expect the impact related to the 2006 maintenance program to be less than the 10% to 15% reduction in deliveries experienced in 2005, but have offered no estimate on the likely reduction. Management cannot predict with any certainty the 2006 impact of the situation; however, an inability to obtain timely delivery of coal to meet generation requirements could materially impact KCP&L’s results of operations. Management is monitoringmonitor 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 just under 100% of the indirect interest in 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, Illinois, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas. Strategic Energy has begun expansion into Connecticut.
 
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In addition to competitive retail electricity supply services, Strategic Energy records insignificant wholesale revenues and purchased power expense incidental to the retail services provided. Strategic Energy also provides strategic planning, consulting and billing and scheduling services in the natural gas and electricity markets. The cost of supplying electricityelectric 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 51,00088,200 commercial, institutional and small manufacturing accounts for approximately 10,30025,000 customers including numerous Fortune 500 companies, smaller companies and governmental entities. In response to marketplace trends, Strategic Energy has designed and introduced new products tailored for specific market conditions and segments. 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 in evolving markets.including fixed price, index-based and month-to-month renewal products. Strategic Energy’s volume-based customer retention rate, excluding month-to-month customers on market-based rates for 20052006 was 76%61%. The corresponding volume-based customer retention raterates including month-to-month customers on market-based rates was 86%71%.
In some markets, wholesale power prices Retention rates for 2006 were lower than Strategic Energy has experienced in 2005 rose faster than host utility rates. In marketsrecent years. The decline is attributable to customer contract expirations in midwestern states where this occurred, the savings competitive suppliers couldcan offer to customers were reducedare limited or in some markets were unavailable. Additionally, in those markets where wholesale power prices were lower thancases 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 faced strong competition from otherexpire. Management expects to have continued difficulty competing in these states until more competitive suppliers. These factors, among others, contributed to reductionsmarket-driven pricing mechanisms are in MWhs delivered and average retail gross margin per MWh in 2005 compared to 2004.place or market prices for power decrease below host utility rates.
 
At the end of 2005,Management has focused sales and marketing efforts on states that currently provide a more competitive pricing environment in relation to host utility default rates. In these states, Strategic Energy experiencedcontinues to experience improvement in certain key metrics, including strong backlogforecasted future MWh commitments (backlog) growth and longer contract durations and higher retention rates. Management believes a combination of factors contributed to the improved metrics, including successful focus on positioning, procurement, products and productivity, as well as a changing market environment. Customer perceptions about the longer-term price of electricity may be changing asdurations. As a result, total backlog grew to 32.8 million MWh at December 31, 2006, compared to 18.3 million MWh at December 31, 2005. Average contract durations grew to 18 months in 2006 from 17 months in 2005. Based solely on expected MWh usage under current signed contracts, Strategic Energy has backlog of 14.7 million MWh, 8.9 million MWh and 4.1 million MWh for the prolonged
29
period of highyears 2007 through 2009, respectively, and volatile power prices seen5.1 million MWh over the years 2010 through 2012. Strategic Energy’s projected MWh deliveries for 2007 are in the last few yearsrange of 18 to 22 million MWhs. Strategic Energy expects to deliver additional MWhs above amounts currently in backlog through new and customers may be more willingrenewed term contracts and MWh deliveries to enter into long-term contracts in order to achieve price certainty. Also, a decrease in near-term power prices at the end of 2005 may have provided a catalyst for some customers to convert from month-to-month service to term contracts. Management believes, but cannot assure, that these trends may continue into 2006.customers.
 
Strategic Energy currently expects the average retail gross margin per MWh (retail revenues less retail purchased power divided by retail MWhs delivered) delivered in 20062007 to average $4.25$4.35 to $4.75$5.35. 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. Actual retail gross margin per MWh on new customer contracts entered into in 2006 to averagemay differ from $3.00 to $4.00. Strategic Energy expects to realize additional retail gross margin on fixed price contracts of up to $0.50 per MWh over the life of the contract. 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 executing on favorable transmission paths. MWhs delivered in 2006 are projected to range from 16 to 18 million. Based solely on expected usage under current signed contracts, Strategic Energy has forecasted future MWh commitments (backlog) of 10.4 million, 4.3 million and 2.3 million for the years 2006 through 2008, respectively. Strategic Energy expects to deliver additional MWhs in these years through new and renewed term contracts and MWh deliveries to month-to-month customers.
LOWER EARNINGS EXPECTED IN 2006
Great Plains Energy’s projected net income is expected to decrease in 2006. The decrease in projected net income for 2006 is due to a significant increase in fuel cost and related transportation expenses at KCP&L, lower volume and lower anticipated average retail gross margins at Strategic Energy and the absence of certain tax benefits recorded in 2005. These factors are expected to more than offset projected operational efficiencies at both KCP&L and Strategic Energy, KCP&L’s retail load growth, higher wholesale volume and higher allowance for equity funds used during construction related to the comprehensive energy plan.
Through 2010, approximately 30% 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 settlement charges that could materially affect KCP&L’s 2006 results of operations.estimates.
 
RELATED PARTY TRANSACTIONS
 
See Note 12 to the consolidated financial statements for information regarding related party transactions.
 
CRITICAL ACCOUNTING POLICIES
 
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures. Management considers an accounting estimate to be critical if it requires assumptions to be made that were
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uncertain at the time the estimate was made and changes in the estimate or different estimates that could have been used could have a material impact on the results of operations and financial position. Management has identified the following accounting policies deemed critical to the understanding of the companies’ results of operations and financial position. Management has discussed the development and selection of these critical accounting policies with the Audit Committee of the Board of Directors for Great Plains Energy and KCP&L.Directors.
 
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Pensions
The companies incur significant costs in providing non-contributory defined pension benefits. The costs are measured using actuarial valuations that are dependent upon numerous factors derived from actual plan experience and assumptions of future plan experience.
 
Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plan, earnings on plan assets and plan amendments. In addition, pension costs are also affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.
 
These actuarial assumptions are updated annually in accordance with Statementat the beginning of Financial Accounting Standards (SFAS) No. 87, “Employers’ Accounting for Pensions.”the plan year. In selecting an assumed discount rate, the prevailing market rate of fixed income debt instruments with maturities matching the expected timing of the benefit obligation was considered. The assumed rate of return on plan assets was developed based on the weighted average of long-term returns forecast for the expected portfolio mix of investments held by the plan. These assumptions are based on management’s best estimates and judgment; however, material changes may occur if these assumptions differ from actual events. See Note 98 to the consolidated financial statements for information regarding the assumptions used to determine benefit obligations and net costs.
 
The following table reflects the sensitivities associated with a 0.5% increase or a 0.5% decrease in key actuarial assumptions. Each sensitivity reflects the impact of the change based solely on a change in that assumption only.
           
     
Impact on
   
Impact on
      
Impact on
 
Impact on
 
     
Projected
 
Impact on
 
2005
      
Projected
 
2006
 
 
Change in
 
Benefit
 
Pension
 
Pension
  
Change in
 
Benefit
 
Pension
 
Actuarial assumption
 
Assumption
 
Obligation
 
Liability
 
Expense
  
Assumption
 
Obligation
 
Expense
 
     (millions)      (millions) 
Discount rate  0.5% increase $(32.9)$(18.1)$(2.3)  0.5% increase $(34.1)$(2.9)
Rate of return on plan assets  0.5% increase  -  -  (1.9)  0.5% increase  - (1.8)
Discount rate  0.5% decrease  35.1  19.8  2.5   0.5% decrease  36.2 3.0
Rate of return on plan assets  0.5% decrease  -  -  1.9   0.5% decrease  - 1.8
         
KCP&L recorded pension expense reflecting orders from the MPSC and KCC that established annual pension costs at $22 million reducing 2005for 2006 and 2005. Expected 2007 pension expense.expense will approximate $35 million after allocations to the other joint owners of generation facilities and capitalized amounts consistent with the December 2006 MPSC and KCC rate orders. The difference between pension costs under SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and the amount allowed for ratemaking is recorded as a regulatory asset or liability for future ratemaking recovery or refunds, as appropriate. See discussion of Regulatory Matters below and Note 98 to the consolidated financial statements for additional information.
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Market conditions and interest rates significantly affect the future assets and liabilities of the plan. It is difficult to predict future pension costs, changes in pension liability and cash funding requirements due to volatile market conditions.
 
Regulatory Matters
As a regulated utility, KCP&L is subject to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Accordingly, KCP&L has recorded assets and liabilities on its balance sheet resulting from the effects of the ratemaking process, which would not otherwise be recorded under GAAP if KCP&L were not regulated.GAAP. Regulatory assets represent incurred costs incurred that have been deferred becauseare probable of recovery from future recovery in customer rates is probable.revenues. Regulatory liabilities generally represent probable future reductions in revenue oramounts imposed by rate actions of KCP&L’s regulators that may require refunds to customers.customers, represent amounts provided in current rates that are intended to recover costs that are expected to be incurred in the future for which KCP&L remains accountable, or represent a gain or other reduction of allowable costs to be given to customers over future periods. Future recovery of regulatory assets is
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not assured, but is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Future reductions in revenue or refunds for regulatory liabilities generally are not mandated, pending future rate proceedings or actions by the regulators. Management regularly assesses whether regulatory assets and liabilities are probable of future recovery or refund by considering factors such as decisions by the MPSC, KCC or FERC on KCP&L’s rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedenceprecedent on matters applicable to KCP&L; and changes in laws and regulations. If recovery or refund of regulatory assets or liabilities is not approved by regulators or is no longer deemed probable, these regulatory assets or liabilities are recognized in the current period results of operations. KCP&L’s continued ability to meet the criteria for application of SFAS No. 71 may be affected in the future by restructuring and deregulation in the electric industry. In the event that SFAS No. 71 no longer applied to a deregulated portion of KCP&L’s operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment on utility plant assets as determined pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” See Note 56 to the consolidated financial statements for more information.
Impairment of Assets, Intangible Assets and Goodwill
Long-lived assets and intangible assets subject to amortization are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under SFAS No. 144.
Goodwill is tested for impairment at least annually and more frequently when indicators of impairment exist as prescribed under SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 142 requires that if the fair value of a reporting unit is less than its carrying value including goodwill, the implied fair value of the reporting unit goodwill must be compared with its carrying value to determine the amount of impairment.
Impairment analyses require management to make assumptions about future sales, operating costs and discount rates over the life of the related asset, or in some cases over an indefinite life. Potential impairment indicators include such factors as current period losses combined with a history of losses, or a projection of continuing losses or a significant decrease in the market price of the asset under review. Management’s assumptions about these factors require significant judgment and under different assumptions, the fair value of an asset could be materially different.
Accounting standards require a company to recognize an impairment in the current period results of operations if the sum of the undiscounted expected future cash flows from the company’s asset is less than the carrying value of the asset. The impairment recognized is the difference between the fair value and book value of the asset.
 
Energy and Energy-Related Contract Accounting
Strategic Energy generally purchases power under forward physical delivery contracts to supply electricity to its retail energy customers under full requirement sales contracts. The full requirements sales contracts and the forward physical delivery contracts meet the accounting definition of a derivative; however, Strategic Energy applies the normal purchases and normal sales (NPNS) exception accounting treatment on full requirement sales contracts. Derivative contracts designated as NPNS are accounted for by accrual accounting, which requires the effects of the derivative to be recorded when the underlying contract settles.
 
Strategic Energy has historically designated the majority of the forward physical delivery contracts as NPNS; however, as certain markets continue to develop, some derivative instruments may no longer qualify for the NPNS exception. As such, Strategic Energy is designating these forward physical
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delivery contracts as cash flow hedges, which could result in future increased volatility in derivative assets and liabilities, other comprehensive income (OCI) and net income. Under cash flow hedge accounting, the fair value of the contract is recorded as a current or long-term derivative asset or liability. Subsequent changes in the fair value of the derivative assets and liabilities are recorded on a net basis in OCI and subsequently reclassified to purchased power expense in Great Plains Energy’s consolidated statement of income as the power is delivered and/or the contract settles. Accordingly, the increase in derivatives accounted for as cash flow hedges and the corresponding decrease in derivatives accounted for as NPNS transactions may affect the timing and nature of accounting recognition, but does not change the underlying economics of the transactions.economic results.
 
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The fair value of forward purchase derivative contracts that do not meet the requirements for the NPNS exception or cash flow hedge accounting are recorded as current or long-term derivative assets or liabilities. Changes in the fair value of these contracts could result in operating income volatility as changes in the associated derivative assets and liabilities are recorded in purchased power expense in Great Plains Energy’s consolidated statement of income.
 
Strategic Energy’s derivative assets and liabilities consist of a combination of energy and energy-related contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices. The market prices used to determine fair value reflect management's best estimate considering time, volatility and historical trends. Future market prices may vary from those used in recording energy assets and liabilities at fair value and such variations could be significant.
 
Market prices for energy and energy-related commodities vary based upon a number of factors. Changes in market prices will affect the recorded fair value of energy contracts. Changes in the fair value of energy contracts will affect operating income in the period of the change for contracts under fair value accounting and OCI in the period of change for contracts under cash flow hedge accounting, while changes in forward market prices related to contracts under accrual accounting will affect operating income in future periods to the extent those prices are realized. Management cannot predict whether, or to what extent, the factors affecting market prices may change, but those changes could be material and could be either favorable or unfavorable.
 
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GREAT PLAINS ENERGY RESULTS OF OPERATIONS
 
The following table summarizes Great Plains Energy’s comparative results of operations.
        
    
As Adjusted
 
As Adjusted
 
  
2006
 
2005
 
2004
 
  (millions) 
Operating revenues $2,675.3 $2,604.9 $2,464.0 
Fuel  (229.5) (208.4) (176.8)
Purchased power  (1,516.7) (1,429.7) (1,300.0)
Skill set realignment costs  (9.4) -  - 
Other operating expenses  (524.4) (527.2) (510.5)
Depreciation and amortization  (160.5) (153.1) (150.1)
Gain (loss) on property  0.6  (3.5) (5.1)
Operating income  235.4  283.0  321.5 
Non-operating income (expenses)  13.2  2.7  (8.4)
Interest charges  (71.2) (73.8) (83.0)
Income taxes  (47.9) (39.5) (55.5)
Minority interest in subsidiaries  -  (7.8) 2.1 
Loss from equity investments  (1.9) (0.4) (1.5)
Income from continuing operations  127.6  164.2  175.2 
Discontinued operations  -  (1.9) 7.3 
Net income  127.6  162.3  182.5 
Preferred dividends  (1.6) (1.6) (1.6)
Earnings available for common shareholders $126.0 $160.7 $180.9 
 
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2005
 
2004
 
2003
 
  (millions) 
Operating revenues $2,604.9 $2,464.0 $2,148.0 
Fuel  (207.9) (179.4) (160.3)
Purchased power  (1,429.7) (1,300.0) (1,022.1)
Other operating expenses  (527.5) (510.6) (479.2)
Depreciation and amortization  (153.1) (150.1) (142.8)
Gain (loss) on property  (3.5) (5.1) 23.7 
    Operating income  283.2  318.8  367.3 
Non-operating income (expenses)  2.7  (8.4) (13.0)
Interest charges  (73.8) (83.0) (76.2)
Income taxes  (39.7) (54.5) (78.6)
Minority interest in subsidiaries  (7.8) 2.1  (7.8)
Loss from equity investments  (0.4) (1.5) (2.0)
    Income from continuing operations  164.2  173.5  189.7 
Discontinued operations, net of income taxes  (1.9) 7.3  (44.8)
    Net income  162.3  180.8  144.9 
Preferred dividends  (1.6) (1.6) (1.6)
    Earnings available for common shareholders $160.7 $179.2 $143.3 
2006 compared to 2005
Great Plains Energy’s 2006 earnings available for common shareholders decreased to $126.0 million, or $1.61 per diluted share, from $160.7 million, or $2.15 per share, in 2005. A higher average number of common shares, primarily due to the issuance of 5.2 million shares in May 2006, diluted 2006 earnings per share by $0.08.
Consolidated KCP&L’s net income increased $5.6 million in 2006 compared to 2005 due to increased retail revenues and decreased purchase power expense. These increases to net income were partially offset by costs related to skill set realignments, increased fuel expense and 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 $9.9 million in 2006 compared to net income of $28.2 million in 2005. The net loss was primarily the result of the after tax impact of $33.4 million in changes in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness. Additionally, retail MWhs delivered decreased 15% in 2006 compared to 2005 but the impact to net income was partially offset by higher average retail gross margins per MWh without the impact of unrealized fair value gains and losses.
2005 compared to 2004
Great Plains Energy’s 2005 earnings available for common shareholders decreased to $160.7 million, or $2.15 per share, from $179.2$180.9 million, or $2.49$2.51 per share in 2004. A higher average number of common shares diluted 2005 EPS by $0.08 primarily due to the issuance of 5.0 million shares in June 2004.
 
Consolidated KCP&L’s net income represented approximately 90% of Great Plains Energy’s 2005 earnings and was relatively unchanged in 2005 compared to 2004. KCP&L’s net income decreased $4.8$6.5 million primarily due to higher fuel costs and purchased power prices, as well as the effects of plant outages and coal conservation on fuel mix. Higher other operating expenses were partially offset by the regulatory accounting treatment of pension expense. These decreases to net income were offset by retail revenues increasing 6% as a result of significantly warmer summer weather in 2005 compared to an unusually mild summer in 2004. Additionally, the favorable impact of sustained audit positions on the 2005 composite tax rates lowered income taxes. KCP&L’s decrease was more thanpartially offset by $5.2 million in reduced losses at HSS primarily due to a 2004 impairment charge related to the 2005 sale of Worry Free.
 
Strategic Energy’s net income decreased $14.3 million in 2005 compared to 2004. Retail MWhs delivered decreased 4% in 2005 compared to 2004. The average retail gross margin per MWh declined 14% to $5.19 in 2005. The decline in average retail gross margin per MWh in 2005 compared to 2004 was primarily due to an environment of higher and less volatile energy prices, flat to higher forward electricity prices and 2005 SECA charges in excess of recoveries. The negative impacts on average retail gross margin per MWh were partially offset by two significant opportunities to manage retail portfolio load requirements, the favorable reduction of a gross receipts tax contingency and a favorable change in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness. Strategic Energy’s 2005 income taxes decreased due to lower taxable income partially offset by $3.2 million in lower tax benefits allocated from the holding company.
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Higher reductions in affordable housing investments and lower related tax credits decreased other non-regulated operations net income in 2005 compared to 2004 by $5.5 million. Discontinued operations decreased net income $9.2 million in 2005 compared to 2004, primarily due to a 2004 gain on the sale of the majority of the KLT Gas natural gas properties (KLT Gas portfolio). This gain was partially offset by 2004 losses from the wind down operations and a loss due to the write down of the KLT Gas portfolio to its estimated net realizable value. See Note 8 to the consolidated financial statements for information regarding the discontinued operations.
2004 compared to 2003
Great Plains Energy’s 2004 earnings increased to $179.2 million, or $2.49 per share, from $143.3 million, or $2.07 per share in 2003. A higher average number of common shares diluted 2004 EPS by $0.10 primarily due to the issuance of 5.0 million shares in June 2004.
Consolidated KCP&L’s income from continuing operations increased $17.4 million in 2004 compared to 2003. Wholesale revenues increased as a result of increased generation, bundling transmission with energy and lower than expected retail loads during the summer months. An increase in operating expenses more than offset these factors primarily due to the increase in MWhs generated, including higher coal and coal transportation costs, higher administrative expenses, an impairment charge related to the first quarter 2005 sale of Worry Free and the significant positive impact on 2003 of the Hawthorn No. 5 litigation settlements. Income taxes decreased due to the favorable impact of state tax planning on the composite tax rate and the allocation of tax benefits from holding company losses pursuant to the Company’s intercompany tax allocation agreement. The change in consolidated KCP&L's discontinued operations was due to a $7.1 million loss on the June 2003 disposition of HSS’ interest in RSAE and continuing losses through the date of disposition of $1.6 million.
Strategic Energy’s net income increased $2.9 million in 2004 compared to 2003. Retail MWhs delivered increased 22% in 2004 compared to 2003. Great Plains Energy, through IEC, completed the purchase of an additional 11.45% indirect interest in Strategic Energy resulting in a $1.8 million increase in net income. The increase to net income was partially offset by a 16% decline in the average retail gross margin per MWh to $6.01 in 2004. The decline in average retail gross margin was primarily due to the roll-off of older, higher margin contracts, price discounts driven by a more competitive market and persistently higher commodity prices and a $4.2 million increase in tax reserves. The negative impacts on average retail gross margin per MWh were partially offset by a $1.7 million change in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness. Strategic Energy’s income taxes decreased $5.9 million in 2004 compared to 2003 reflecting lower taxable income and additional tax benefits allocated from the holding company.

Lower reductions in affordable housing investments and lower interest charges increased other non-regulated operations net income in 2004 compared to 2003 by $3.1 million. KLT Gas discontinued operations increased $43.4 million in 2004 compared to 2003 primarily due to the gain on the sale of the majority of KLT Gas portfolio in 2004 combined with the 2003 impairment related to the exit of the KLT Gas business.
 
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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, inIn the discussion that follows, references to KCP&L reflect only the operations of the utility. The following table summarizes consolidated KCP&L's comparative results of operations.
        
    
As Adjusted
 
As Adjusted
 
  
2006
 
2005
 
2004
 
  (millions) 
Operating revenues $1,140.4 $1,130.9 $1,091.6 
Fuel  (229.5) (208.4) (176.8)
Purchased power  (26.4) (61.3) (52.5)
Skill set realignment costs  (9.3) -  - 
Other operating expenses  (452.1) (460.5) (442.2)
Depreciation and amortization  (152.7) (146.6) (145.2)
Gain (loss) on property  0.6  (4.6) (5.1)
Operating income  271.0  249.5  269.8 
Non-operating income (expenses)  9.6  11.8  (1.9)
Interest charges  (61.0) (61.8) (74.2)
Income taxes  (70.3) (48.0) (53.8)
Minority interest in subsidiaries  -  (7.8) 5.1 
Net income $149.3 $143.7 $145.0 
           
        
  
2005
 
2004
 
2003
 
  (millions) 
Operating revenues $1,130.9 $1,091.6 $1,057.0 
Fuel  (207.9) (179.4) (160.3)
Purchased power  (61.3) (52.5) (53.2)
Other operating expenses  (460.8) (442.3) (422.6)
Depreciation and amortization  (146.6) (145.2) (141.0)
Gain (loss) on property  (4.6) (5.1) 1.6 
    Operating income  249.7  267.1  281.5 
Non-operating income (expenses)  11.8  (1.9) (3.1)
Interest charges  (61.8) (74.2) (70.3)
Income taxes  (48.2) (52.8) (83.5)
Minority interest in subsidiaries  (7.8) 5.1  1.3 
    Income from continuing operations  143.7  143.3  125.9 
Discontinued operations, net of income taxes  -  -  (8.7)
    Net income $143.7 $143.3 $117.2 
Consolidated KCP&L Sales Revenues and MWh Sales
            
    
%
  
%
  
  
2005
Change
2004
Change
2003
Retail revenues (millions) 
   Residential $380.0  9 $347.1  (4)$361.5 
   Commercial  434.6  3  421.1  1  417.6 
   Industrial  100.9  5  96.2  1  95.0 
   Other retail revenues  8.6  (2) 8.7  1  8.7 
      Total retail  924.1  6  873.1  (1) 882.8 
Wholesale revenues  192.4  (4) 200.2  27  157.5 
Other revenues  14.3  (15) 16.8  15  14.6 
   KCP&L electric revenues  1,130.8  4  1,090.1  3  1,054.9 
Subsidiary revenues  0.1  (93) 1.5  (25) 2.1 
   Consolidated KCP&L revenues $1,130.9  4 $1,091.6  3 $1,057.0 
             
   
%
  
%
     
% 
   
% 
   
 
2005
Change
2004
Change
2003
 
2006
 
Change
 
2005
 
Change
 
2004
 
Retail MWh sales  (thousands)
Retail revenues     (millions)     
Residential  5,383  10  4,903  (3) 5,047  $384.3  1 $380.0  9 $347.1 
Commercial  7,292  4  6,998  1  6,933   442.6  2  434.6  3  421.1 
Industrial  2,165  5  2,058  1  2,035   99.8  
(1)
  100.9  5  96.2 
Other retail MWh sales  82  (3) 85  -  85 
Other retail revenues  8.8  3  8.6  
(2)
  8.7 
Total retail  14,922  6  14,044  -  14,100   935.5  1  924.1  6  873.1 
Wholesale MWh sales  4,608  (30) 6,603  14  5,777 
KCP&L electric MWh sales  19,530  (5) 20,647  4  19,877 
Wholesale revenues  190.4  
(1)
  192.4  
(4)
  200.2 
Other revenues  14.5  1  14.3  
(15)
  16.8 
KCP&L electric revenues  1,140.4  1  1,130.8  4  1,090.1 
Subsidiary revenues  -  NM  0.1  
(93)
  1.5 
Consolidated KCP&L revenues $1,140.4  - $1,130.9  4 $1,091.6 
 
36
38
 
 
    
% 
   
%
   
  
2006
 
Change
 
2005
 
Change
 
2004
 
Retail MWh sales     (thousands)     
Residential  5,413  1  5,383   10  4,903 
Commercial  7,403  2  7,292   4  6,998 
Industrial  2,148  (1) 2,165   5  2,058 
Other retail MWh sales  86  4  82  
(3)
  85 
Total retail  15,050  1  14,922   6  14,044 
Wholesale MWh sales  4,676  1  4,608  
(30)
  6,603 
KCP&L electric MWh sales  19,726  1  19,530  
(5)
  20,647 
Retail revenues increased $11.4 million in 2006 compared to 2005 primarily due to weather normalized load growth of over 1% slightly offset by the impact of weather with favorable summer weather being more than offset by mild winter weather.   
Retail revenues increased $51.0 million in 2005 compared to 2004. The increase was driven by significantly warmer summer weather in 2005 compared to an unusually mild summer in 2004 and continued weather normalized load growth of approximately 2%, adjusted for weather for 2005 and 2004. in 2005. Residential usage per customer increased 9% in 2005, driven by a 45% increase in cooling degree-days,degree days, which was 19% above normal.
 
RetailThe following table provides cooling degree days (CDD) and heating degree days (HDD) for the last three years at Kansas City International Airport. CDD and HDD are used to reflect the demand for energy to cool or heat homes and buildings.
      
 
2006
%
Change
2005
%
Change
2004
      
CDD
1,72461,626451,118
HDD
4,052(15)4,78014,741
      
Wholesale revenues decreased $9.7$2.0 million in 20042006 compared to 20032005 due to an 11% decrease in the average market price per MWh to $42.52 partially offset by a 1% increase in wholesale MWh sales. The decrease in average market price per MWh was primarily due to a $14.4 million reductionlower gas prices in residential revenues. Residential usage per customer decreased 4% in 20042006 compared to 20032005, as a result of significantly cooler summer weather in 2004. The Kansas City area experienced one ofwell as the coolest summerseffects on 2005 average prices from coal conservation in the past 30 years, which resultedregion. Additionally, wholesale revenues for 2006 include $2.5 million in cooling degree-days 18% below normal. The impactlitigation recoveries for the loss of the cooler summer weather was partially offset by load growth in 2004. The average numberuse of residential and commercial customers continues to grow; both increased 1% to 2% in 2005 and 2004 compared to the respective prior years.Hawthorn No. 5 from a 1999 boiler explosion.
 
Wholesale revenues decreased $7.8 million in 2005 compared to 2004 due to a 30% decrease in MWhs sold, which was significantly offset by an increase in the average market price per MWh. The decrease in MWhs sold was driven by a 5% decrease in net MWhs generated as a result of coal conservation and plant outages. Additionally, retail MWh sales increased 6% in 2005 compared to 2004, which resulted in less MWhs available for wholesale sales. Average market price per MWh increased 56% to $47.82 in 2005 compared to 2004 due to warmer summer weather in 2005, higher natural gas prices, transmission constraints and coal conservation in the region.
Wholesale revenues increased $42.7 million in 2004 compared to 2003. Wholesale MWhs sold increased 14%, primarily due to increased generation, bundling transmission with energy and lower than expected retail loads during the summer months, combined with successful marketing efforts. Average market prices per MWh increased 13% to $30.72 in 2004 compared to 2003, primarily due to more sales made during periods of higher natural gas prices and bundling transmission with energy to provide a delivered product. Additionally, wholesale revenues were affected by the partial settlements of the Hawthorn No. 5 litigation.
As described in Item 3. Legal Proceedings, KCP&L filed suit against multiple defendants who are alleged to have responsibility for the 1999 Hawthorn No. 5 boiler explosion. Various defendants settled with KCP&L in this litigation, resulting in KCP&L recording $2.4 million and $35.8 million in 2004 and 2003, respectively. A portion of the settlements, $1.2 million and $17.3 million for 2004 and 2003, respectively, was recorded as a recovery of capital expenditures. The following table summarizes the income statement impact related to the remainder of the settlements for loss of use of Hawthorn No. 5.
      
  
2004
 
2003
 
  (millions) 
Wholesale revenues $0.2 $2.7 
Fuel  0.2  4.0 
Purchased power  0.8  11.8 
    Operating income  1.2  18.5 
Income taxes  (0.5) (7.2)
    Net income $0.7 $11.3 
39
37
Consolidated KCP&L Fuel and Purchased Power
            
Net MWhs Generated
   
%
   
%
  
by Type
 
2006
 
Change
 
2005
 
Change
 
2004
 
      (thousands)     
Coal  15,056  -  14,994  (4) 15,688 
Nuclear  4,395  6  4,146  (13) 4,762 
Natural gas and oil  564  19  473  206  155 
Wind  106  N/A  -  -  - 
Total Generation  20,121  3  19,613  (5) 20,605 
                 
            
Net MWhs Generated
   
%
  
%
  
by Fuel Type
 
2005
Change
2004
Change
2003
  (thousands)
Coal  14,994  (4) 15,688  5  15,011 
Nuclear  4,146  (13) 4,762  14  4,178 
Natural gas and oil  473  206  155  (43) 270 
   Total Generation  19,613  (5) 20,605  6  19,459 
Fuel expense increased $28.5$21.1 million in 2006 compared to 2005 due to a 2% increase in MWhs generated, excluding wind generation, which has no fuel cost, increased coal and coal transportation costs and more natural gas generation in the fuel mix, which has higher costs compared to other fuel types. These increases were partially offset by lower natural gas prices and $3.7 million in Hawthorn No. 5 litigation recoveries. KCP&L’s current coal and coal transportation contracts include higher tariff rates being charged by Union Pacific. 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.
Fuel expense increased $31.6 million in 2005 compared to 2004 despite a 5% decrease in MWhs generated due to a combination of changes in the fuel mix to higher cost generation, increased coal and coal transportation costs and increased natural gas prices. The changes in fuel mix were driven by the number and duration of plant outages as well as coal conservation measures. KCP&L’s 2005 coal and coal transportation contracts were entered into at higher average prices than related 2004 contracts.
 
FuelPurchased power expense increased $19.1decreased $34.9 million in 20042006 compared to 20032005. The decreases were primarily due to a 6% increaserecording $10.8 million in MWhs generated, higher coal and coal transportation costs, higher natural gas costs and the net effect of $3.8 million from the Hawthorn No. 5 partial litigation settlements.recoveries as a reduction in purchased power expense and a 40% reduction in MWhs purchased. The increasereduction in MWhs purchased was partially offset by changes in the fuel mix to lower cost generation due to uneconomical purchased power prices and increased coal and nuclear fuel and less natural gasnet MWhs generated. In addition, capacity payments decreased $5.1 million in the fuel mix. The change in fuel mix was primarily2006 due to the 2003 refueling outage at Wolf Creek andexpiration of two large contracts in the cooler 2004 summer weather, which allowed coal and nuclearsecond quarter of 2005. KCP&L entered into new capacity to supply a greater percentage of the reduced retail load.contracts in June 2006.
 
Purchased power expense increased $8.8 million in 2005 compared to 2004. The average price per MWh purchased increased 61% in 2005 compared to 2004 partially offset by an 8% decline in MWhs purchased. The increased prices were driven by purchases during higher priced peak hours as a result of warmer weather, plant outages and overall higher average prices due to higher natural gas prices combined with transmission constraints, coal conservation and outages in the region.
 
Purchased power expense decreased $0.7 million in 2004 compared to 2003. MWhs purchased decreased 31% in 2004 compared to 2003 primarily due to lower retail customer demand and a 2% increase in the coal fleet equivalent availability factor in 2004 compared to 2003. The decrease in MWhs purchased was partially offset by an 11% increase in the average price per MWh purchased in 2004 compared to 2003 primarily due to higher natural gas market prices and increased market demand. Another offset includes the net effect of the Hawthorn No. 5 partial litigation settlements, which impacted purchased power expense by $11.0 million in 2004 compared to 2003.
Consolidated KCP&L Other Operating Expenses (including other operating, maintenance and general taxes)
Consolidated KCP&L's other operating expenses decreased $8.4 million in 2006 compared to 2005 primarily due to the following:
·  decreased severance and incentive compensation expense of $6.3 million,
·  decreased restoration expenses of $5.1 million due to expenses that were incurred for a January 2005 ice storm and a June 2005 wind storm,
·  deferring $6.2 million of expenses in accordance with MPSC and KCC orders.
Partially offsetting the decrease in other operating expenses was:
40
·  increased maintenance expenses of $2.6 million for facilities, software and communication equipment and
·  increased property taxes of $2.7 million primarily due to increases in assessed property valuations and mill levies.
Consolidated KCP&L's other operating expenses increased $18.5$18.3 million in 2005 compared to 2004 primarily due to the following:
 
·  increased employee relatedemployee-related expenses of $4.7 million including severance and incentive compensation,
 
·  increased expenses of $2.4 million due to higher legal reserves,
 
·  increased regulatory expenses of $1.2 million including expenses related to the comprehensive energy plan,
 
·  increased general taxes of $5.9 million mostlyprimarily due to increases in gross receipts tax, assessed property valuations and mill levies,
 
38
·  increased expenses of $4.2 million due to higher restoration costs for a January 2005 ice storm and June 2005 wind storms compared to the 2004 wind storm restoration costs and
 
·  increased production operations and maintenance expenses of $4.3$4.1 million primarily due to scheduled and forced plant maintenance in 2005 and the reversal of an environmental accrual in 2004.
 
Partially offsetting the increase in other operating expenses was:
 
·  decreased pension expense of $4.7 million due to the regulatory accounting treatment of pension expense in accordance with MPSC and KCC orders and
 
·  decreased transmission service expense of $5.7 million primarily due to lower wholesale MWhs sold.
 
Consolidated KCP&L's other operating expenses increased $19.7&L Skill Set Realignment Costs
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 $9.3 million in 2004 compared2006 related to 2003 primarily duethis workforce realignment process reflecting severance, benefits and related payroll taxes provided by KCP&L to the following:employees. In its 2007 rate cases, KCP&L is requesting to establish a regulatory asset for these costs and amortize them over five years effective with new rates on January 1, 2008.
·  increased pension expense of $3.5 million primarily due to lower discount rates, the amortization of investment losses from prior years and plan settlement losses,
·  increased other employee-related costs of $3.5 million including higher medical costs and incentive compensation costs,
·  increased property taxes of $4.3 million primarily due to increases in assessed property valuations and mill levies,
·  increased outside services of $4.4 million including costs associated with Sarbanes-Oxley compliance,
·  increased transmission and distribution expenses including $2.5 million primarily due to increased transmission usage charges as a result of the increased wholesale MWh sales, $2.3 million related to SPP administration and $1.3 million in storm related expenses and
·  increased office expense including $2.1 million expenditure to buy out computer equipment operating leases.
Partially offsetting the increase in other operating expenses was:
·  decreased plant maintenance expense of $1.3 million primarily due to differences in timing and scope of outages and $0.9 million in lower gross receipts taxes as a result of lower retail revenues and
·  decreased expenses due to the reversal of an environmental accrual and the establishment of a regulatory asset for the probable recovery in the Kansas jurisdiction of enhanced security costs.
 
Consolidated KCP&L Gain (loss) on Property
Consolidated KCP&L's gain (loss) on property remained relatively unchanged in 2005 compared to 2004, due to offsetting losses. During 2005, KCP&L wrote off $3.6 million of plant operating system development costs at Wolf Creek as a result of vendor non-performance. See Note 15 to the consolidated financial statements for related legal proceedings. Consolidated KCP&L's gain (loss) on property increased operating expenses $6.7In 2004, HSS recorded a $7.3 million in 2004 compared to 2003 primarily due to the 2004 impairment charge related to the 2005 sale of its subsidiary Worry Free.
 
Consolidated KCP&L Interest Charges
Consolidated KCP&L's interest charges decreased $12.4 million in 2005 compared to 2004 primarily due to $10.1 million of interest related to the IRS 1995-1999 audit settlement in 2004. Consolidated KCP&L's interest charges increased $3.9 million in 2004 compared to 2003. The increase was primarily due to the $10.1 million of interest discussed above, partially offset by a $6.3 million decrease primarily due to the 2004 redemption of KCP&L’s $154.6 million 8.3% Junior Subordinated Deferred Interest Bonds.
 
39
Consolidated KCP&L Income Taxes
Consolidated KCP&L's income taxes increased $22.3 million in 2006 compared to 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.
41
Consolidated KCP&L's income taxes decreased $4.6$5.8 million in 2005 compared to 2004. Several factors contributed to the decreased taxes including lower taxable income in 2005. The favorable impact of sustained audit positions on the composite tax rate decreased income taxes $6.3 million, including $3.1 million reflecting thea composite tax rate change on deferred tax balances, and thebalances. The domestic manufacturers’ deduction provided for under the American Jobs Creation Act of 2004 contributed $1.5 million to the decrease in taxes. TheseWhen compared to 2004, these 2005 decreases to income taxes were partially offset when compared to 2004 due to the 2004 release of $10.1 million 2004in tax reserves release discussed below.
Consolidated KCP&L's income taxes decreased $30.7 million in 2004 compared to 2003. Several factors contributed to the decreased taxes including lower taxable income in 2004. The favorable impact of state tax planning on the composite tax rate decreased income taxes $10.1 million, including $8.6 million reflecting the composite tax rate change on deferred tax balances resulting from book to tax temporary differences. An additional $10.1 million decrease is attributable to the reserves for the interest component of the IRS 1995-1999 audit settlement, as discussed under consolidated KCP&L interest charges, which offset interest expense and hadresulted in no impact on income from continuing operations. Income taxes also decreased by $5.9 million due to the allocation of tax benefits from holding company losses pursuant to the Company's intercompany tax allocation agreement.2004 net income.
 
STRATEGIC ENERGY RESULTS OF OPERATIONS
 
The following table summarizes Strategic Energy's comparative results of operations.
              
 
2005
 
2004
 
2003
  
2006
 
2005
 
2004
 
 (millions)  (millions) 
Operating revenues $1,474.0 $1,372.4 $1,091.0  $1,534.9 $1,474.0 $1,372.4 
Purchased power  (1,368.4) (1,247.5) (968.9)  (1,490.3) (1,368.4) (1,247.5)
Other operating expenses  (53.4) (51.3) (42.1)  (61.5) (53.4) (51.3)
Depreciation and amortization  (6.4) (4.8) (1.7)  (7.8) (6.4) (4.8)
Gain (loss) on property  (0.1) - - 
Operating income  45.7 68.8 78.3 
Gain on property  -  (0.1) - 
Operating income (loss)  (24.7) 45.7  68.8 
Non-operating income (expenses)  2.5 1.7 1.0   4.2  2.5  1.7 
Interest charges  (3.4) (0.7) (0.4)  (2.1) (3.4) (0.7)
Income taxes  (16.6) (24.3) (30.2)  12.7  (16.6) (24.3)
Minority interest in subsidiaries  - (3.0) (9.1)  -  -  (3.0)
Net income $28.2 $42.5 $39.6 
Net income (loss) $(9.9)$28.2 $42.5 
          
Strategic Energy’s 2006 net loss was primarily the result of the after tax impact of $33.4 million in changes in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness. Retail MWhs delivered decreased 15% to 16.6 million in 2006 compared to 2005 due to the effect of market conditions in midwestern states and competition in other markets where Strategic Energy serves customers. The impact to net income was partially offset by average retail gross margin per MWh without fair value impacts that increased to $5.93 in 2006 compared to $5.07 in 2005. Additionally, Strategic Energy’s other operating expenses increased primarily due to increased incentive compensation and bad debt expense.
 
Retail MWhs delivered decreased 4% to 19.5 million in 2005 compared to 2004. The average retail gross margin per MWh declined 14% to $5.19 in 2005. The decline in average retail gross margin per MWh in 2005 compared to 2004 was primarily due to an environment of higher and less volatile energy prices, flat to higher forward electricity prices and $8.3 million in 2005 SECA charges in excess of recoveries. The negative impacts on average retail gross margin per MWh were partially offset by $6.8 million for two significant opportunities to manage retail portfolio load requirements, a $2.5 million favorable reduction of a gross receipts tax contingency and an $0.8 million change in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness.
 
Retail
42
      
  
2006
 
2005
 
2004
 
Average retail gross margin per MWh $2.52 $5.19 $6.01 
Change in fair value related to non-hedging energy          
contracts and from cash flow hedge ineffectiveness  (3.41) 0.12  0.08 
Average retail gross margin per MWh without          
fair value impacts $5.93 $5.07 $5.93 
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 deliveredunder 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 22%to $5.93 in 20042006 compared to 2003. In 2004, Great Plains Energy, through IEC, purchased an additional 11.45% indirect interest$5.07 in Strategic Energy resulting in a $1.8 million increase in net income.2005. The increase was primarily due to the net income was partially offsetimpact of SECA recoveries and charges as compared to 2005. The net SECA impact increased average retail gross margin per MWh by a 16% decline$0.06 in 2006 and decreased average retail gross margin per MWh by $0.42 in 2005. Additional impacts to the average retail gross margin per MWh to $6.01 in 2004. The decline in average retail gross margin isincluded increases primarily due to the roll-offmanagement of older, higher margin contracts, price discounts driven by a more competitive marketretail portfolio load requirements, favorable product mix and persistently higher commodity prices and a $4.2 million increase in tax
40
reserves.settlements of supplier contracts. The negative impacts on average retail gross margin per MWhincreases were partially offset by a $1.7 million changehigher customer acquisition costs in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness.2006.
 
Strategic Energy Purchased Power
Purchased power is the cost component of Strategic Energy’s average retail gross margin. Strategic Energy purchases blocks of electricity from power suppliers based on forecasted peak demand for its retail customers. Actual customer demand does not always equate to the volume included in blocks of purchased power.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, and 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 $181.2$80.0 million, $158.5 million and $173.3 million in 2006, 2005 and $91.2 million in 2005, 2004, and 2003, respectively. Additionally, in certain markets, load-serving entities areStrategic Energy is 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 reducedincreased purchased power expenses by $56.7 million in 2006 and reduced expenses by $2.5 million in 2005 and $1.7 million in 2004 and were insignificant2004. The change is a result of decreases in the forward market prices for 2003.power combined with Strategic Energy designating more derivative instruments as cash flow hedges
43
that no longer qualify for the NPNS election. See Note 2122 to the consolidated financial statements for more information.
 
Strategic Energy Other Operating Expenses
Strategic Energy’s other operating expenses increased $8.1 million in 2006 compared to 2005 primarily due to a $4.5 million increase for incentive compensation and a $4.3 million increase in bad debt expense due to the charge off of smaller customers, which have a higher default rate than Strategic Energy’s larger customers. Since 2005, Strategic Energy has significantly expanded its small customer business with approximately 25% of new sales in 2006 to small customers. Strategic Energy’s other operating expenses increased $2.1 million in 2005 compared to 2004 primarily due to increased employee related expenses including increased severance and incentive compensation, partially offset by aan 11% decrease in full time employees to 240 in 2005. Strategic Energy’s other operating expenses increased $9.2 million in 2004 compared to 2003; a 22% increase driven mainly by higher staffing levels associated with the continued growth of Strategic Energy. Additionally, higher consulting expenses associated with new software development initiatives and higher general tax expenses primarily due to higher capital stock and franchise tax rates increased 2004 other operating expenses compared to 2003.
 
Strategic Energy Income Taxes
Strategic Energy had a tax benefit of $12.7 million in 2006 compared to tax expense of $16.6 million in 2005 due to a pre-tax loss in 2006 compared to pre-tax income in 2005. The change was driven by a $23.3 million deferred tax benefit in 2006 related to the net changes in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness. Strategic Energy’s income taxes decreased $7.7 million in 2005 compared to 2004 reflecting lower taxable income partially offset by a net $3.2 million decrease in the allocation of tax benefits from holding company losses pursuant to the Company's intercompanyinter-company tax allocation agreement. Strategic Energy’s income taxes decreased $5.9 million in 2004 compared to 2003 reflecting lower taxable income and additional tax benefits. The additional benefits included $3.1 million due to the allocation of tax benefits from holding company losses pursuant to the Company's intercompany tax allocation agreement and a slight decrease due to the favorable impact of state tax planning on the composite tax rate.
 
OTHER NON-REGULATED ACTIVITESACTIVITIES
 
Investment in Affordable Housing Limited Partnerships - KLT Investments
KLT Investments Inc.’s (KLT Investments) net income in 20052006 totaled $4.3 million (including an after-tax reduction of $0.8 million in its affordable housing investment) compared to net income of $5.7 million in 2005 (including an after tax reduction of $6.2 million in its affordable housing investment) compared toand net income of $11.2 million
41
in 2004 (including an after tax reduction of $4.6 million in its affordable housing investment) and net income of $8.1 million in 2003 (including an after tax reduction of $6.7 million in its affordable housing investment).
 
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 reduced its investments in affordable housing limited partnerships by $1.2 million, $10.0 million and $7.5 million in 2006, 2005 and $11.0 million in 2005, 2004 and 2003, respectively.2004. Pre-tax reductions in affordable housing investments are estimated to be $1 million in 2006 and $2 million infor 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. The properties underlying the partnership investment are subject to certain risks inherent in real estate ownership and management. Even after these estimated reductions, net income from the investments in affordable housing is expected to be positive for 2006 through2007 and 2008. The properties underlying the partnership investment are subject to certain risks inherent in real estate ownership and management.
 
KLT Investments accrued tax credits related to its investments in affordable housing limited partnerships of $9.1 million, $15.4 million and $18.3 million in 2006, 2005 and $19.1 million in 2005, 2004, and 2003, respectively. Management estimates tax credits will be $9 million, $5 million and $2 million for 2006 through2007 and 2008, respectively.
 
KLT Gas Discontinued Operations
Discontinued operations decreased net income $9.2 million in 2005 compared to 2004 primarily due to a gain on the 2004 sale of the KLT Gas portfolio, partially offset by losses from the wind down operations and for an arbitration settlement in 2005. KLT Gas’ discontinuedGas had no active operations loss in 2003 was $36.1 million including impairments and operating losses. See Note 8 to the consolidated financial statements for additional information.2006.
 
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GREAT PLAINS ENERGY AND CONSOLIDATED KCP&L SIGNIFICANT BALANCE SHEET CHANGES (DECEMBER(December 31, 2005 COMPARED TO DECEMBER2006 compared to December 31, 2004)2005)
 
·  Great Plains Energy’s restricted cash and supplier collateral decreased $5.8consolidated KCP&L’s receivables increased $80.4 million and $44.0 million, respectively. KCP&L’s receivables increased $39.7 million due to certainadditional receivables from joint owners of comprehensive energy plan projects. Strategic Energy suppliers posting letters of creditEnergy’s receivables increased $38.9 million primarily due to satisfy collateral requirements rather than cash.more customers billed on higher index-based rates.
 
·  Great Plains Energy’s and consolidated KCP&L’s fuel inventories decreased $4.0increased $10.7 million primarily due to $9.3a $7.0 million increase in fewer coal deliveriesinventory resulting from railroad performance issues partially offset by an increase in the average days coal burn in inventory as a result of planned plant outages and improved railroad performance in delivering coal. Additionally, coal and coal transportation costs increased fuel inventories.
·  Great Plains Energy’s combined refundable income taxes and accrued taxes of a net current liability of $14.3 million at December 31, 2006, decreased $22.9 million from December 31, 2005. This decrease was primarily due to physical inventory adjustments.Strategic Energy’s $7.9 million payment of accrued gross receipts taxes and a decrease at consolidated KCP&L. Consolidated KCP&L’s combined refundable income taxes and accrued taxes of a net current liability of $10.9 million at December 31, 2006, decreased $16.5 million from December 31, 2005, primarily due to a $7.8 million receivable for estimated income taxes paid and $5.3 million of 2005 income tax true ups.
 
·  Great Plains Energy’s combined deferred income taxes - current assets and deferred income taxes - current liabilities changed from an asseta liability of $13.1$7.8 million at December 31, 2004,2005, to a liabilityan asset of $1.3$39.6 million. The temporary differences due to the change in the fair value of Strategic Energy’s energy-related derivative instruments increased the liability $10.1asset $42.9 million. Consolidated KCP&L’s deferred income taxes - current assets decreased $3.9 million partially due to a lower nuclear fuel outage reserve resulting from the completion of the scheduled spring 2005 refueling. Consolidated KCP&L’s deferred income taxes - current assets were reclassified to a current liability during consolidation with Great Plains Energy.
 
·  Great Plains Energy’s derivative instruments, -including current and deferred assets increased $32.8and liabilities, decreased $188.0 million from a net asset in 2005, to a net liability in 2006, primarily due to an increasea $188.1 million decrease in the fair value of Strategic Energy’s energy-related derivative instruments of $33.2 million due to additional contract volume and an increase in fair value as a result of changesdecreases in the forward market prices for power.power combined with Strategic Energy designating more derivative instruments as cash flow hedges in 2006 than in 2005.
 
·  Great Plains Energy’s affordable housing limited partnerships decreased $13.1 million due to reductions in the valuation of the properties held by KLT Investments.
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·  Great Plains Energy’s other - nonutility property and investments decreased $15.4 million primarily due to a $2.3 million decrease related to the sale and write off of investments and a decrease at consolidated KCP&L. Consolidated KCP&L’s other - nonutility property and investments decreased $12.9 million primarily due to KCP&L receiving a return of its net investment from the Central Interstate Low Level Radioactive Waste Compact Commission.
 
·  Great Plains Energy’s and consolidated KCP&L’s combined electric utility plant and construction work in progress increased $47.1$422.5 million primarily due to $25.3$298.7 million in contract payments related to KCP&L’s comprehensive energy plan, including $163.6 million for wind generation, and$56.8 million for environmental equipment upgrades and normal construction activity.$78.3 million related to Iatan No. 2
 
·  Great Plains Energy’s and consolidated KCP&L’s regulatory assets increased $35.6$254.5 million primarily due to new regulatory assets of $190.0 million for the regulatory accounting treatmentadoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” and $21.9 million for pension expensesettlement charges pursuant to orders received from the MPSC and KCC. Additionally, new regulatory assets of $11.9 million were established under the change in Wolf Creek depreciable life for Missouri regulatory purposes in accordance with2006 MPSC and KCC rate orders. Additionally, adopting FASB Interpretation (FIN) No. 47, “AccountingSee Notes 6 and 8 to the consolidated financial statements for Conditional Asset Retirement Obligations” during 2005 increased regulatory assets $13.2 million.additional information.
 
·  Great Plains Energy’s derivative instruments - deferred charges and other assets increased $19.5 million primarily dueconsolidated KCP&L’s prepaid pension costs were reduced to a $20.2 million increase in Strategic Energy’s energy-related derivative instruments due to additional contract volume and an increase in fair value as a resultzero upon the adoption of changes in forward market prices for power.SFAS No. 158.
 
·  Great Plains Energy’s other - deferred charges and other assets decreased $8.6$22.4 million primarily due to IEC’s intangible asset amortization of $15.0$10.5 million for the intangible assets related to the 2004 purchase of an additional indirect interest in Strategic Energy partially offset byand a decrease at consolidated KCP&L. Consolidated KCP&L’s other - deferred charges and other assets increased $7.0decreased $14.3 million primarily due to a reclass from accrued taxesthe reduction to zero of an $8.8 million income tax refund receivable that management expects to be delayed until the related IRS audit cycle can be completed.intangible pension asset upon adoption of SFAS No. 158.
 
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·  Great Plains Energy’s and consolidated KCP&L’s commercial paper increased $31.9$124.5 million primarily due to $25.3 million in contract paymentssupport expenditures related to wind generation and environmental equipment upgrades and timing of cash payments.the comprehensive energy plan.
 
·  Great Plains Energy’s and consolidated KCP&L’s accounts payable increased $31.5$91.2 million and $21.9$75.8 million, respectively, primarily due to timing of cash payments.a $66.1 million increase in payables related to the comprehensive energy plan.
 
·  Great Plains Energy’s accrued taxesand consolidated KCP&L’s asset retirement obligations decreased $9.9$54.1 million primarilydue to a $65.0 million decrease for the decommissioning of Wolf Creek as a result of the anticipated new operating license. This decrease was partially offset by a $3.1 million addition for the Spearville Wind Energy Facility and $7.8 million for accretion.
·  Great Plains Energy’s and consolidated KCP&L’s pension liability - deferred credits and other liabilities increased $55.8 million and $46.9 million, respectively, due to the timingadoption of tax paymentsSFAS No. 158.
·  Great Plains Energy’s and Strategic Energy’s payment of accrued gross receipts taxes and the reversal of a reserve related to an audit settlement. Consolidatedconsolidated KCP&L’s accrued taxes decreased $7.0regulatory liabilities increased $45.0 million due to the timing of tax payments partially offset by ana $31.0 million increase in KCP&L’s regulatory liability related to the asset retirement obligation for decommissioning of Wolf Creek as a reclassresult of the anticipated new operating license and amortization of $10.3 million related to the change in Wolf Creek depreciable life for regulatory purposes in accordance with an $8.8 million income tax refund receivable to other deferred charges and other assets.MPSC order.
 
·  Great Plains Energy’s and consolidated KCP&L’s AROother - deferred credits and other liabilities increased $32.2$16.3 million and $27.3 million, respectively, primarily due to a $17.6 million impact of adoption of SFAS No. 158. Consolidated KCP&L also increased due to an intercompany payable to Services of $5.7 million related to unrecognized pension expense.
·  Great Plains Energy’s accumulated other comprehensive loss increased $39.0 million primarily due to $11.3a $74.0 million related to revised decommissioning cost estimates for Wolf Creek, $7.5 million of accretion and a $15.4 million additionincrease due to adopting FINchanges in the fair value of Strategic Energy’s energy related derivative instruments partially offset by activity at consolidated KCP&L. Consolidated KCP&L’s accumulated other comprehensive loss at December 31, 2005, decreased $36.6 million resulting in accumulated other comprehensive income at December 31, 2006, due to the adoption of SFAS No. 47 during 2005.158 and the related deferral of unrecognized pension expense to a regulatory asset.
 
·  
Great Plains Energy’s andlong-term debt decreased $533.4 million primarily to reflect FELINE PRIDESSM Senior Notes, consolidated KCP&L’s regulatory liabilities increased $65.5$225.0 million primarily due to KCP&L’s regulatory treatment of SO2 emission allowance sales totaling $61.0 million6.00% Senior Notes and $4.3$144.7 million of additional Wolf Creek amortizationEnvironmental Improvement Revenue Refunding (EIRR) bonds as current maturities. Current maturities of long-term debt for Missouri regulatory purposes. See Note 5 to the consolidated financial statements.
·  Great Plains Energy’s derivative instruments - deferred credits and other liabilitiesrespective companies increased $7.6 million primarily due to Strategic Energy’s derivative instruments increasing $5.0 million related to an increase in fair value as a result of changes in forward market prices for power. Consolidated KCP&L’s derivative instruments - deferred credits and other liabilities increased 
these classifications.
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$2.6 million due to a change in the fair value of KCP&L’s interest rate swaps on its 1998 Series A, B and D EIRR bonds.
·  Great Plains Energy’s other - deferred credits and other liabilities decreased $18.5 million primarily due to IEC’s $11.6 million amortization of the liability for the fair value of acquired retail contracts related to the 2004 purchase of an additional indirect interest in Strategic Energy. Consolidated KCP&L’s other - deferred credits and other liabilities decreased $4.4 million primarily due to KCP&L receiving a return of its net investment from the Central Interstate Low Level Radioactive Waste Compact Commission.
·  Great Plains Energy’s accumulated other comprehensive loss decreased $33.3 million primarily due to the increase in fair value as a result of changes in forward market prices for power of Strategic Energy’s energy-related cash flow hedges. Consolidated KCP&L’s accumulated other comprehensive loss decreased $10.4 million primarily due to the fair values of the Treasury Locks (T-Locks), which were entered into and settled during 2005. See Note 21 to the consolidated financial statements.
·  Great Plains Energy’s long-term debt increased $184.4 million. Consolidated KCP&L’s long-term debt increased $186.1 million primarily due to a $250.0 million issuance of senior notes and an $85.9 million issuance of Series 2005 EIRR bonds partially offset by the $145.3 million redemption of debt related to the buyout of the Combustion Turbine Synthetic Lease. EIRR bonds classified as current and current maturities decreased as a result of the repayment and remarketing of the respective bonds.
 
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 December 31, 2005,2006, consisted of $103.1$61.8 million of cash and cash equivalents on hand, including $3.0$1.8 million at consolidated KCP&L, and $739.7$806.4 million of unused bank lines of credit. The unused lines consisted of $218.1$234.9 million from KCP&L's revolving credit facility, $59.8$75.2 million from Strategic Energy’s revolving credit facility and $461.8 $496.3 million from Great Plains
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Energy's revolving credit facility. See the Debt Agreements section below for more information on these agreements. At February 28, 2006,20, 2007, Great Plains Energy’s and consolidated KCP&L’s unused bank lines of credit had increased $16.3decreased $55.2 million and $9.3$39.2 million, respectively, from the amounts at December 31, 2005.2006, primarily due to support expenditures for comprehensive energy plan projects. See the Debt Agreements section below for more information on these agreements.
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 equity issuances, 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 mightmay 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.
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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 new equity financing and 2004 FELINE PRIDESSM equity in 2007, new debt financing, and internally generated funds.
 
Strategic Energy expects to meet day-to-day cash flow requirements including interest payments, credit support fees and capital expenditures and dividends to its indirect interest holders with internally generated funds. Strategic Energy mightmay 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.
 
In February 2007, Great Plains Energy entered into an agreement to acquire Aquila.  See Note 3 to the consolidated financial statements for additional information.
Cash Flows from Operating Activities
Great Plains Energy and consolidated KCP&L generated positive cash flows from operating activities for the periods presented. CashThe changes in cash flows from operating activities for Great Plains Energy and consolidated KCP&L increased duringin 2006 compared to 2005 and in 2005 compared to 2004 primarily due toreflect KCP&L’s sales of SO2emission allowances totalingduring 2005 resulting in proceeds of $61.0 million and KCP&L’s $12.0 million cash settlement on the T-Locks, discussedof Treasury Locks (T-Locks) in significant financing activities. KCP&L’s net income after consideration of non-cash items decreased primarily due to the decrease in operating income discussed in consolidated KCP&L’s results of operations section.2005. The timing of the Wolf Creek outage affects the deferred refueling outage accrual,costs, deferred income taxes and amortization of nuclear fuel. Additionally, Great Plains Energy’s cash flows from operating activities reflects a decrease in Strategic Energy’s net income due to fewer MWhs delivered and a decline in average retail gross margin per MWh.
The decrease in cash flows from operating activities for Great Plains Energy in 2004 compared to 2003 was primarily due to theOther changes in working capital detailed in Note 2 to the consolidated financial statements.statements also impacted operating cash flows. The individual components of working capital vary with normal business cycles and operations. In addition, the timing of the Wolf Creek outage affects the refueling outage accrual, deferred income taxes and amortization of nuclear fuel. Consolidated KCP&L’s cash flow from operating activities increased in 2004 compared to 2003 partially due to a $26.1 million increase in net income and the changes in working capital detailed in Note 2 to the consolidated financial statements.
 
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 $148.6 million and $143.8 million, respectively, in 2006 compared to 2005 due to KCP&L’s cash utility capital expenditures, including $234.3 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 partially offset by 2005 investing activities discussed below. Additionally in
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2006, KCP&L received $15.8 million of litigation recoveries related to Hawthorn No. 5, compared to $10.0 million of insurance recoveries received in 2005.
Great Plains Energy’s and consolidated KCP&L’s utility capital expenditures increased $136.7 million and $141.6 million, respectively, during 2005 compared to 2004. In 2005, KCP&L exercised its early termination option in the Combustion Turbine Synthetic Lease and subsequently paid $154.0 million to purchase the leased property and made contract payments totaling $25.3 million related to wind generation and environmental equipment upgrades. These payments were partially offset by the $28.5 million buyout of KCP&L’s operating lease for vehicles and heavy equipment in 2004. The increases in capital expenditures were partially offset by KCP&L’s receipt of $10.0 million for insurance recoveries related to Hawthorn No. 5 during 2005.
Great Plains Energy’s and consolidated KCP&L’s utility capital expenditures increased $41.9 million in 2004 compared to 2003 primarily due to the $28.5 million buyout of KCP&L’s operating lease for vehicles and heavy equipment in 2004. Insurance recoveries and litigation settlements related to Hawthorn No. 5 in 2004 of $31.9 million, a $10.7 million increase over 2003 recoveries, offset cash used in investing activities. Additionally, Great Plains Energy paid $90.0 million to acquire an additional indirect interest in Strategic Energy during 2004.
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Cash Flows from Financing Activities
The change in Great Plains Energy’s cash flows from financing activities in 2006 compared to 2005 reflects Great Plains Energy’s proceeds of $144.3 million from the issuance of 5.2 million shares of common stock at $27.50 per share in May 2006. 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 a $23.7 million decrease in dividends paid to Great Plains Energy.
The changes in Great Plains Energy’s and consolidated KCP&L’s cash flows from financing activities in 2005 compared to 2004 and in 2004 compared to 2003 reflect KCP&L’s retirement of $54.5 million of its medium-term notes and its redemption of $154.6 million of 8.3% Junior Subordinated Deferred Interest Bonds from KCPL Financing I during 2004. KCPL Financing I used those proceeds to redeem the $4.6 million common securities held by KCP&L and the $150.0 million of 8.3% Trust Preferred Securities. These 2004 financing activities at consolidated KCP&L were offset by $225.0 million in equity contributions from Great Plains Energy. Great Plains Energy’s 2004 financing activities reflect proceeds of $150.0 million from the June 2004 issuance of 5.0 million shares of common stock at $30 per share and proceeds of $163.6 million from the issuance of 6.5 million FELINE PRIDES. Great Plains Energy used the proceeds to repay short-term borrowings and to fund the equity contributions to KCP&L. Fees related to these issuances were $10.2 million. See Note 19 to the consolidated financial statements for additional information.
 
DuringIn 2005, KCP&L redeemed its secured 1994 series EIRR bonds totaling $35.9 million by issuing secured EIRR Bonds Series 2005 also totaling $35.9 million: $14.0 million at a fixed rate of 4.05% until maturity at March 1, 2015, and $21.9 million at a fixed rate of 4.65% until maturity at September 1, 2035. KCP&L also redeemed its unsecured Series C EIRR bonds totaling $50.0 million by issuing unsecured EIRR Bonds Series 2005 also totaling $50.0 million at a fixed rate of 4.65% until maturity at September 1, 2035. The previous interest rate periods on these two series, with interest rates of 2.25% and 2.38%, respectively, expired on August 31, 2005. Both of the redeemed series were classified as current liabilities at December 31, 2004. Both of the new EIRR Bonds Series 2005 are covered by municipal bond insurance policies issued by XL Capital Assurance Inc. (XLCA). The insurance agreements between KCP&L and XLCA provide for reimbursement by KCP&L for any amounts that XLCA pays under the municipal bond insurance policies. The insurance policies are in effect for the term of the bonds. The insurance agreements contain a covenant that the indebtedness to total capitalization ratio of KCP&L and its consolidated subsidiaries will not be greater than 0.68 to 1.00. At December 31, 2005, KCP&L was in compliance with this covenant. KCP&L is also restricted from issuing additional bonds under its General Mortgage Indenture if, after giving effect to such additional bonds, the proportion of secured debt to total indebtedness would be more than 75%, or more than 50% if the long term rating for such bonds by Standard & Poor’s or Moody’s Investors Service would be at or below A- or A3, respectively. The insurance agreement covering the unsecured EIRR Bond Series 2005 also requires KCP&L to provide XLCA with $50 million of general mortgage bonds as collateral for KCP&L’s obligations under the insurance agreement in the event KCP&L issues general mortgage bonds (other than refundings of outstanding general mortgage bonds) resulting in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization. In the event of a default under the insurance agreements, XLCA may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.
KCP&L had $625.0 million of outstanding unsecured senior notes at December 31, 2005 and 2004. During 2005, KCP&L completed a private placement of $250.0 million of 6.05% unsecured senior notes, maturing in 2035.$35.9 million of secured EIRR bonds Series 2005 and $50.0 million of unsecured EIRR bonds Series 2005. The proceeds from the issuancethese issuances were used to repay the$250.0 million of 7.125% unsecured senior notes, that matured in 2005. Pursuant to its obligations under a registration rights agreement entered into in connection with the private placement, KCP&L plans to file in 2006 an S-4 registration statement for the exchange$35.9 million of registered 6.05% unsecured senior notes for the $250.0secured 1994 Series EIRR bonds and $50.0 million privately placed notes. The registered notes will carry the same terms and conditions as the privately placed issue without, except in limited circumstances, transfer restrictions and payment of additional interest provisions.Series C EIRR bonds.
 
Significant Financing Activities
KCP&L’s long-term financing activities areGreat Plains Energy filed a shelf registration statement with the SEC in 2006 relating to Senior Debt Securities, Subordinated Debt Securities, shares of Common Stock, Warrants, Stock Purchase Contracts and Stock Purchase Units. In 2006, Great Plains Energy issued 5.2 million shares of common stock at $27.50 per share under the shelf registration statement with $144.3 million in gross proceeds and issuance costs of $5.2 million.
In 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 authorizationprovisions of the MPSC.forward sale agreement, Great Plains Energy will receive an amount equal to $26.6062 per share, plus
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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 solely by delivering shares of common stock. In November 2005,most circumstances, Great Plains Energy also has the MPSC authorized KCP&Lright, in lieu of physical settlement, to issue upelect cash or net physical settlement. Great Plains Energy currently expects to $635net cash settle the forward sale agreement. 
In 2006, Great Plains Energy entered into a T-Lock with a notional principal amount of $77.6 million to hedge against interest rate fluctuations on future issuances of long-term debt anddebt. See Note 22 to enter intothe consolidated financial statements for more information.
 
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In February 2007, Great Plains Energy exercised its rights to redeem its $163.6 million FELINE PRIDES senior notes in full satisfaction of each holder’s obligation to purchase the Company’s common stock under the purchase contracts and issued 5.2 million shares of common stock to the holders of the FELINE PRIDES purchase contracts.
 
interest rate hedging instruments in connection with such debt through December 31, 2009. Under stipulations with the MPSC and the KCC, Great Plains Energy and KCP&L maintain common equity at not less than 30% and 35%, respectively, of total capitalization. KCP&L’s long-term financing activities are subject to the authorization of the MPSC. In 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.
 
In FebruaryDuring 2006, FERC authorized KCP&L to issue up to $300.0a total of $600.0 million in outstanding short-term debt instruments through February 2008. The authorization isauthorizations 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.
 
DuringIn January 2007, KCP&L received authorization from FERC, as part of its $600.0 million short-term debt FERC authorization, to issue an aggregate of $150 million of short-term debt in connection with participation in the first quarterGreat Plains Energy money pool for a period of three years. There will be three participants in the Great Plains Energy money pool: KCP&L, Great Plains Energy and Strategic Energy. The money pool is an internal financing arrangement in which up to $150 million of funds deposited into the money pool by Great Plains Energy and Strategic Energy may be lent on a short-term basis to KCP&L.
During 2006, KCP&L entered into atwo Forward Starting SwapSwaps (FSS) with a combined notional principal amount of $110$225.0 million to hedgeeffectively remove most of the interest rate volatility on the first $110 million ofand credit spread uncertainty with respect to the anticipated refinancing of KCP&L’s $225$225.0 million senior notes that mature in March 2007.
During 2005, KCP&L entered into two T-Locks to hedge against interest rate fluctuations on the U.S. Treasury rate component of the $250.0 million 30-year long-term debt that KCP&L issued in 2005. The T-Locks settled simultaneously with the issuance of the long-term fixed rate debt and KCP&L received $12.0 million in cash for the settlement. See Note 21 to the consolidated financial statements.
During 2005, KCP&L entered into a revolving agreement to sell all of its retail electric accounts receivable to Receivables Company, which sold an undivided percentage ownership interest in the accounts receivable to an outside investor. Receivables Company received $70 million in cash from the outside investor, which was forwarded to KCP&L as consideration for its sale. KCP&L’s accounts receivable agreement is an additional source of liquidity with an all-in borrowing cost generally equal to or lower than KCP&L’s other sources of short-term borrowings including the revolving credit facility and commercial paper. See Note 322 to the consolidated financial statements for additionalmore 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.
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Debt Agreements
During 2006, Great Plains Energy hasentered 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 that expires in December 2009. The facility contains a Material Adverse Change (MAC) clause that requires Great Plains Energy to represent, prior to receiving funding, that no MAC has occurred. The clause does, however, permit the Company to access the facility even in the event of a MAC in order to repay maturing commercial paper. Available liquidity under this facility is not impacted by a decline in credit ratings unless the downgrade results in a MAC or occurs in the context of a merger, consolidation or sale.banks. A default by Great Plains Energy or any of its significant subsidiaries ofon other indebtedness totaling more than $25.0 million is a default under the current 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 December 31, 2005,2006, the Company was in compliance with this covenant. At December 31, 2005,2006, Great Plains Energy had $6.0 million of outstandingno cash borrowings with an interest rate of 4.98% and had issued letters of credit totaling $38.5$103.7 million under the credit facility as credit support for Strategic Energy.
 
During 2006, KCP&L hasentered into a $250five-year $400 million revolving credit facility with a group of banks that expires in December 2009 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 containsreplaced a MAC clause that requires KCP&L to represent, prior to receiving funding, that no MAC has occurred. The clause does, however, permit KCP&L to access the$250 million revolving credit facility even in the eventwith a group of a MAC in order to repay maturing commercial paper. Available liquidity under this facility is not impacted by a
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decline in credit ratings unless the downgrade results in a MAC or occurs in the context of a merger, consolidation or sale.banks. A default by KCP&L on other indebtedness totaling more than $25.0 million is a default under the current 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 December 31, 2005,2006, KCP&L was in compliance with this covenant. At December 31, 2005,2006, KCP&L had $31.9$156.4 million of commercial paper outstanding, at a weighted-average interest rate of 5.38%, issued $8.7 million of letters of credit and had no cash borrowings under the facility. The weighted-average interest rate of the commercial paper was 4.35%. 
 
During 2005, Strategic Energy entered into an amendment to its $125has a $135 million revolving credit facility with a group of banks. The amendment extends the expiration of the facility frombanks that expires in June 2007 to June 2009 and increases the aggregate revolving loan commitment from $125 million to $135 million. So2009. As long as thereStrategic Energy is no default or unmatured default, Strategic Energyin 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, has currently guaranteed $25.0 millionas permitted by the terms of the agreement, requested and received a reduction in its guarantee of this facility.facility from $25 million to $12.5 million. Under this facility, Strategic Energy’s maximum it may loan to Great Plains Energy is $20 million. The facility contains a MACMaterial Adverse Change (MAC) clause that requires Strategic Energy to represent, prior to receiving funding, that no MAC has occurred. A default by Strategic Energy ofon other indebtedness, as defined in the facility, totaling more than $7.5 million is a default under the facility. Under the terms of this amended 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 amended 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 December 31, 2005,2006, Strategic Energy was in compliance with these covenants. At December 31, 2005, $75.22006, $59.8 million in letters of credit had been issued and there were no cash borrowings under the agreement, leaving $59.8 million of capacity available for loans and additional letters of credit.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
50
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 December 31, 2005,2006, KLT Investments had $2.6$0.9 million in outstanding notes, including current maturities.
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KCP&L Projected Utility Capital Expenditures
KCP&L’s utility capital expenditures, excluding allowance for funds used to finance construction, were $475.9 million, $332.1 million and $190.5 million in 2006, 2005 and $148.7 million in 2005, 2004, and 2003, respectively. Utility capital expenditures projected for the next three years, excluding allowance for funds used during construction, are detailed in the following table.
       
 
2006
 
2007
 
2008
 
 (millions) 
Generating facilities      
Iatan No. 2 (a)
$30.7 $120.4 $274.5 
Wind generation (a)
 143.0  -  - 
Environmental (a)
 43.3  124.8  101.3 
Other 49.3  53.1  53.9 
   Total generating facilities 266.3  298.3  429.7 
Distribution and transmission facilities         
Customer programs & asset management (a)
 5.6  9.1  14.9 
Other 93.4  83.9  84.4 
   Total distribution and transmission facilities 99.0  93.0  99.3 
Nuclear fuel 20.9  25.2  1.1 
General facilities 30.6  20.5  11.8 
Total$416.8 $437.0 $541.9 
(a) Comprehensive energy plan
 
 
 2007
2008
2009
Generating facilities (millions)
Iatan No. 2 (a)
 $200.5$352.5$ 239.0 
Wind generation (a)
 2.9 - - 
Environmental (a)
 102.1 163.3 
 64.0
 
Other 64.9 73.6 
 82.6
 
Total generating facilities 370.4 589.4 
 385.6
 
Distribution and transmission facilities      
Iatan No. 2 (a)
 0.3 6.1 
 5.5
 
Customer programs & asset management (a)
 11.3 14.4 
 15.2
 
Other 111.6 99.6 
 100.7
 
Total distribution and transmission facilities 123.2 120.1 
 121.4
 
Nuclear fuel 24.3 17.1 
 17.9
 
General facilities 22.6 15.4 
 19.2
 
Total $540.5$ 742.0$ 544.1 
(a)  Comprehensive energy plan
 
This 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. See Note 56 to the consolidated financial statements.statements for the total comprehensive energy plan estimated capital expenditures by project.  If the proposed acquisition of Aquila is completed, Great Plains Energy expects to increase its utility capital expenditures.  See Note 3 to the consolidated financial statements for additional information.
 
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,All 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 furtherwith additional contributions may be made when deemed financially advantageous.
 
The Company contributed $14.5$19.8 million to the plans in 2006, all paid by KCP&L. The contributions included $14.0 million of funding above the minimum ERISA funding requirements. In 2005, the Company contributed $14.5 million to the plans, which included $10.0 million of funding above the minimum ERISA funding requirements. In 2004, the Company contributed $39.1 million to the plans, which included $4.1 million for minimum ERISA funding requirements and $35.0 million of additional funding. KCP&L contributedpaid $13.8 million and $32.7 million of the contributions in 2005 and 2004, respectively.contributions.
 
The Company expects to contribute $20.0$33.6 million to the plans in 2006, which includes $6.0 million2007 to meet ERISA funding requirements, all of which will be paid by KCP&L. Management believes the CompanyKCP&L has adequate access to capital resources through cash flows from operations or through existing lines of credit to support the funding requirements.
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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 affect the Company’s future funding requirements.
Participants in the plans may request a lump-sum cash payment upon termination of their employment. A change in payment assumptions could result in increased cash requirements from pension plan assets with the Company being required to accelerate future funding.
Legislative changes have been proposed that would alter the manner in which pension plan assets and liabilities are valued for purposes of calculating required pension contributions and change the timing
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and manner in which required contributions to underfunded plans are made. If these proposals are adopted, the funding requirements could be significantly affected.
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. See Note 98 to the consolidated financial statements for additional information.
 
Credit Ratings
At December 31, 2005,2006, the major credit rating agencies rated the companies’ securities as detailed in the following table.
    
 
Moody's
 
Standard
 
Investors Service
 
and& Poor's
Great Plains Energy
   
OutlookNegativeStable Stable
Corporate Credit Rating- BBB
Preferred StockBa1 BB+
Senior Unsecured DebtBaa2 BBB-
    
KCP&L
   
OutlookStable Stable
Senior Secured DebtA2 BBB
Senior Unsecured DebtA3 BBB
Commercial PaperP-2 A-2
The ratings presented reflect the current views of these rating agencies and are subject to change. The companies view maintenance of strong credit ratings as being extremely important and to that end an active and ongoing dialogue is maintained with the agencies with respect to the companies’ results of operations, financial position, and future prospects.
On February 7, 2007, Standard & Poor’s Rating Services placed Great Plains Energy and KCP&L on credit watch with negative implications after the announcement that Great Plains Energy entered into an agreement to acquire Aquila, Inc. At the same time, Standard & Poor’s Rating Services also lowered KCP&L’s commercial paper credit rating to A-3 from A-2. See Note 3 to the consolidated financial statements for additional information. Also, on February 7, 2007, Moody’s Investors Service affirmed the ratings and outlook of Great Plains Energy and KCP&L.
 
None of the companies’ outstanding debt, except for the notes associated with affordable housing investments, requires the acceleration of interest and/or principal payments in the event of a ratings downgrade, unless the downgrade occurs in the context of a merger, consolidation or sale. In the event of a downgrade, the companies and/or their subsidiaries may be subject to increased interest costs on their credit facilities. Additionally, in KCP&L’s bond insurance policies on its secured 1992 series EIRR bonds totaling $31.0 million, its Series 1993A and 1993B EIRR bonds totaling $79.5 million and its secured and unsecured EIRR Bonds Series 2005 totaling $35.9 million and $50.0 million, respectively, KCP&L has agreed to limits on its ability to issue additional mortgage bonds based on the mortgage bond’s credit ratings. See Note 19 to the consolidated financial statements.
 
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Strategic Energy Supplier Concentration and Credit
Strategic Energy enters into forward physical contracts with multiple suppliers. At December 31, 2005,2006, Strategic Energy’s five largest suppliers under forward supply contracts represented 76%72% 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.grade. 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
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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, as ofat December 31, 2005.2006.
            
        
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 $  2.8 $- $2.8  2 $2.4 
Non-Investment Grade    7.6  6.1  1.5  1  1.5 
Internal rating                
Investment Grade    0.1  -  0.1  -  - 
Non-Investment Grade    2.5  -  2.5  1  2.5 
Total $13.0 $6.1 $6.9  4 $6.4 
                 
            
      
Number Of
Net Exposure Of
      
Counterparties
Counterparties
Exposure
    
Greater Than
Greater Than
Maturity Of Credit Risk Exposure Before Credit Collateral
Maturity Of Credit Risk Exposure Before Credit Collateral
 
Before Credit
Credit
Net
10% Of Net
10% of Net
 
Less Than
   
Total
 
Rating
Collateral
Collateral
Exposure
Exposure
Exposure
 
2 Years
 
2 - 5 Years
 
Exposure
 
External rating
(millions)    (millions) (millions) 
Investment Grade$205.3 $88.5 $116.8  3 $84.5  $2.8 $- $  2.8 
Non-Investment Grade 37.3  31.2  6.1  - -   2.5  5.1    7.6 
Internal rating
                        
Investment Grade 3.0  -  3.0  - -   0.1  -    0.1 
Non-Investment Grade 9.7  5.7  4.0  - -   1.3  1.2    2.5 
Total$255.3 $125.4 $129.9  3 $84.5  $6.7 $6.3 $13.0 
          
        
Maturity Of Credit Risk Exposure Before Credit Collateral
 
  
Less Than
  
Total
Rating
 
2 Years
2 - 5 Years
Exposure
External rating
 (millions) 
   Investment Grade $205.9 $(0.6)$205.3 
   Non-Investment Grade  30.9  6.4  37.3 
Internal rating
          
   Investment Grade  2.9  0.1  3.0 
   Non-Investment Grade  7.8  1.9  9.7 
Total $247.5 $7.8 $255.3 
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
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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.
In December 2005, Calpine Energy Services filed a motion in bankruptcy court seeking to reject a power sales agreement with Strategic Energy. A district court held that FERC, not the court, had jurisdiction over the agreement. The matter is currently pending at FERC. Strategic Energy has adequate supply in its existing portfolio to cover its position in the event the agreement is rejected and any rejection is not expected to materially affect its results of operations.
 
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At December 31, 2005,2006, Strategic Energy had exposure before collateral to non-investment grade counterparties totaling $47.0 million, of which 82% is scheduled to mature in less than two years.$10.1 million. In addition, Strategic Energy held collateral totaling $36.9$6.1 million limiting its exposure to these non-investment grade counterparties to $10.1$4.0 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 information in the following tables is provided to summarize cash obligations and commercial commitments.
 
Great Plains Energy Contractual Obligations Great Plains Energy Contractual Obligations
Great Plains Energy Contractual Obligations
           
               
Payment due by period
 
2006
2007
2008
2009
2010
After 2010
Total
 
2007
 
2008
 
2009
 
2010
 
2011
 
After 2011
 
Total
 
Long-term debt (millions)  (millions) 
Principal $1.7 $226.1 $0.3 $163.6 $- $755.3 $1,147.0  $389.6 $0.3 $- $- $150.0 $605.3 $1,145.2 
Interest  67.4  51.2  47.6  47.6  47.6  541.1 802.5   47.0  42.6  42.5  42.5  41.3  520.8  736.7 
Lease obligations  17.1  15.4  14.9  10.7  8.4  91.0 157.5   16.7  16.4  11.9  9.0  8.1  82.3  144.4 
Pension plans  20.0  -  -  -  -  - 20.0   33.6  -  -  -  -  -  33.6 
Purchase obligations                                    
Fuel  107.9  99.9  91.5  46.0  32.3  37.7 415.3   130.9  121.4  65.7  65.7  11.4  185.3  580.4 
Purchased capacity  5.4  6.8  7.8  8.2  5.4  18.6 52.2   6.8  7.8  8.2  5.4  4.3  14.3  46.8 
Purchased power  423.4  135.6  46.4  21.8  18.0  - 645.2   741.8  330.5  223.2  165.2  82.1  13.3  1,556.1 
Comprehensive energy plan  498.8  361.0  130.1  15.2  -  -  1,005.1 
Other  33.6  5.6  2.9  -  -  - 42.1   34.3  20.9  4.1  9.9  3.3  -  72.5 
Total contractual obligations $676.5 $540.6 $211.4 $297.9 $111.7 $1,443.7 $3,281.8  $1,899.5 $900.9 $485.7 $312.9 $300.5 $1,421.3 $5,320.8 
               
 Consolidated KCP&L Contractual Obligations
                
Payment due by period
 
2006
2007
2008
2009
2010
After 2010
Total
Long-term debt (millions) 
Principal $- $225.5 $- $- $- $755.3 $980.8 
Interest  54.2  43.4  40.6  40.6  40.6  541.1  760.5 
Lease obligations  15.9  14.4  14.0  10.5  8.4  91.0  154.2 
Pension plans  20.0  -  -  -  -  -  20.0 
Purchase obligations                      
Fuel  107.9  99.9  91.5  46.0  32.3  37.7  415.3 
Purchased capacity  5.4  6.8  7.8  8.2  5.4  18.6  52.2 
Other  33.6  5.6  2.9  -  -  -  42.1 
Total contractual obligations $237.0 $395.6 $156.8 $105.3 $86.7 $1,443.7 $2,425.1 
Consolidated KCP&L Contractual Obligations
           
Payment due by period
 
2007
 
2008
 
2009
 
2010
 
2011
 
After 2011
 
Total
 
Long-term debt (millions) 
Principal $225.5 $- $- $- $150.0 $605.3 $980.8 
Interest  45.3  42.5  42.5  42.5  41.3  520.8  734.9 
Lease obligations  15.5  15.4  11.7  9.0  8.1  82.3  142.0 
Pension plans  33.6  -  -  -  -  -  33.6 
Purchase obligations               
Fuel  130.9  121.4  65.7  65.7  11.4  185.3  580.4 
Purchased capacity  6.8  7.8  8.2  5.4  4.3  14.3  46.8 
Comprehensive energy plan  498.8  361.0  130.1  15.2  -  -  1,005.1 
Other  34.3  20.9  4.1  9.9  3.3  -  72.5 
Total contractual obligations $990.7 $569.0 $262.3 $147.7 $218.4 $1,408.0 $3,596.1 
                
Long-term debt includes current maturities. Long-term debt principal excludes $1.8$1.6 million discountof discounts on senior notes and the $2.6a $1.8 million liability for the fair value adjustment to the EIRR bonds related to
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interest rate swaps. FELINE PRIDES senior notes totaling $163.6 million mature in 2009, but must be remarketed between August 16, 2006 and February 16, 2007. Variable rate interest obligations are based on rates as of December 31, 2005.2006. See Note 19 to the consolidated financial statements for additional information.
 
Lease obligations include capital and operating lease obligations; capital lease obligations are $0.2 million per year for the years 20062007 through 20102011 and total $3.9$3.7 million after 2010.2011. Lease obligations also include railcars to serve jointly-owned generating units where KCP&L is the managing partner.
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KCP&L will be reimbursed by the other owners for approximately $2.0 million per year ($22.721.4 million total) of the amounts included in the table above. See Note 13 to the consolidated financial statements for additional information regarding contractual commitments.
 
The Company expects to contribute $20.0$33.6 million to the pension plans in 2006, which includes $6.0 million2007 to meet ERISA funding requirements, all of which will be paid by KCP&L. MinimumAdditional contributions to the plans are expected beyond 2007 in amounts sufficient to meet ERISA funding requirements for future periods after 2006 arerequirements; however, these amounts have not yet known.been determined.
 
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.
 
KCP&L purchases capacity from other utilities and nonutility suppliers. Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable. KCP&L has capacity sales agreements not included above that total $11.4 million for 2006, $11.2 million per year for 2007 through 2010, $6.9 million in 2011 and $12.3$3.8 million after 2010.2011.
 
Purchased power represents Strategic Energy’s agreements to purchase electricity at various fixed prices to meet estimated supply requirements. Strategic Energy has firm energy sales contracts not included above for 2006 and 2007 totaling $41.1 million and $4.2 million, respectively.$172.4 million.
 
Comprehensive energy plan represents KCP&L’s contractual commitments for projects included in its comprehensive energy plan. KCP&L expects to be reimbursed by other owners for their respective share of Iatan No. 2 and environmental retrofit costs included in the comprehensive energy plan commitments.  Other purchase obligations represent individual commitments entered into in the ordinary course of business.
 
Strategic Energy has entered into financial swaps in certain markets to limit the unfavorable effect that future price increases will have on future electricity purchases. These financial swaps settle during the same period as power flows to the retail customer and could result in a cash obligation or a cash receipt. Due to the uncertainty of the future cash flows, these financial swaps have been omitted from the table above.
 
Great Plains Energy and consolidated KCP&L have long-term liabilities recorded on their consolidated balance sheets at December 31, 2005, under GAAP2006, that do not have a definitive cash payout date and are not included in the table above.
 
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.
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The information in the following table is provided to summarize these agreements.
Other Commercial Commitments Outstanding
           
                
  
Amount of commitment expiration per period
 
  
2006
2007
2008
2009
2010
After 2010
Total
  (millions) 
Great Plains Energy Guarantees $123.0 $1.0 $1.0 $0.9 $- $- $125.9 
Consolidated KCP&L Guarantees  1.0  1.0  1.0  0.9  -  -  3.9 
                
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Other Commercial Commitments Outstanding
           
  
Amount of commitment expiration per period
 
  
2007
 
2008
 
2009
 
2010
 
2011
 
After 2011
 
Total
 
  (millions) 
Great Plains Energy Guarantees $247.2 $1.0 $13.4 $- $- $- $261.6 
Consolidated KCP&L Guarantees  1.0  1.0  0.9  -  -  -  2.9 
                
KCP&L is contingently liable for guaranteed energy savings under an agreement with a customer, guaranteeing an aggregate value of approximately $3.9$2.9 million over theoverthe next fourthree years. A subcontractor would indemnify KCP&L for any payments made by KCP&L under this guarantee. Great Plains Energy has provided $122.0$258.7 million of guarantees to support certain Strategic Energy power purchases and regulatory requirements. At December 31, 2005,2006, guarantees related to Strategic Energy are as follows:
 
·  Great Plains Energy direct guarantees to counterparties totaling $58.0$142.0 million, which expire in 2006,2007,
 
·  Great Plains Energy provides indemnifications to thesurety bond issuers of surety bonds totaling $0.5 million, which expire in 2006,2007,
 
·  Great Plains Energy guarantees related to lettersguarantee of Strategic Energy’s revolving credit facility totaling $25.0$12.5 million, which expireexpires in 20062009 and
 
·  Great Plains Energy letters of credit totaling $38.5 million.$103.7 million, which expire in 2007.
 
The table above does not include guarantees related to bond insurance policies that KCP&L has as a credit enhancement to its secured 1992 series EIRR bonds totaling $31.0 million, its Series 1993A and 1993B EIRR bonds totaling $79.5 million and EIRR Bond Series 2005 totaling $85.9 million. The insurance agreement between KCP&L and the issuer of the bond insurance policies provides for reimbursement by KCP&L for any amounts the insurer pays under the bond insurance policies.
 
New Accounting Standards
See Note 24 to the consolidated financial statements for information regarding new accounting standards.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
In the normal course of business, Great Plains Energy and consolidated KCP&L face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, operations and credit risks and are not represented in the following analysis. See Item 1A. Risk Factors and Item. 7 MD&A for further discussion of the companies’ risk factors.
 
Great Plains Energy and consolidated KCP&L are exposed to market risks associated with commodity price and supply, interest rates and equity prices. Management has established risk management policies and strategies to reduce the potentially adverse effects the volatility of the markets may have on its operating results. During the normal course of business, under the direction and control of internal risk management committees, the companies’ hedging strategies are reviewed to determine the hedging approach deemed appropriate based upon the circumstances of each situation. Though management believes its risk management practices to be effective, it is not possible to identify and eliminate all risk. The companies could experience losses, which could have a material adverse effect on its results of operations or financial position, due to many factors, including unexpectedly large or
56
rapid movements or disruptions in the energy markets, from regulatory-driven market rule changes and/or bankruptcy or non-performance of customers or counterparties.
 
Derivative instruments are frequently utilized to execute risk management and hedging strategies. Derivative instruments, such as futures, forward contracts, swaps or options, derive their value from underlying assets, indices, reference rates or a combination of these factors. These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives and instruments listed and traded on an exchange. The companies maintain commodity-price risk management strategies that use derivative instruments to minimize significant, unanticipated net income fluctuations caused by commodity price volatility.
 
54
Interest Rate Risk
Great Plains Energy and consolidated KCP&L manage interest expense and short and long-term liquidity through a combination of fixed and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly rated financial institutions may also be used to achieve the desired combination. Using outstanding balances and annualized interest rates as of December 31, 2005,2006, a hypothetical 10% increase in the interest rates associated with long-term variable rate debt would result in an increase of less than $1.1$1.2 million in interest expense for 2006.2007. Additionally, interest rates impact the fair value of long-term debt. Also, KCP&L had $31.9$156.4 million of commercial paper outstanding at December 31, 2005.2006. The principal amount, which will vary during the year, of the commercial paper will drive KCP&L’s commercial paper interest expense. Assuming that $31.9$156.4 million of commercial paper was outstanding for all of 2006,2007, a hypothetical 10% increase in commercial paper rates would result in an increase of less than $0.2$0.9 million in interest expense for 2006.2007. A change in interest rates would impact the Company to the extent it redeemed any of its outstanding long-term debt. Great Plains Energy’s and consolidated KCP&L’s book values of long-term debt were 1% below fair values at December 31, 2005.2006.
 
Commodity Risk
KCP&L and Strategic Energy engage in the wholesale and retail marketing of electricity and are exposed to risk associated with the price of electricity.
 
KCP&L's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity and long, intermediate and short-term capacity or power purchase agreements. The agreements contain penalties for non-performance to limit KCP&L’s energy price risk on the contracted energy. KCP&L also enters into additional power purchase agreements with the objective of obtaining the most economical energy to meet its physical delivery obligations to customers. KCP&L is required to maintain a capacity margin of at least 12% of its peak summer demand. This net positive supply of capacity and energy is maintained through its generation assets and capacity and power purchase agreements to protect it from the potential operational failure of one of its power generating units. KCP&L continually evaluates the need for additional risk mitigation measures in order to minimize its financial exposure to, among other things, spikes in wholesale power prices during periods of high demand.
 
KCP&L's sales include the sales of electricity to its retail customers and bulk power sales of electricity in the wholesale market. KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply, the availability and cost of purchased power and the requirements of other electric systems; therefore, the impact of the hypothetical amounts that follow could be significantly reduced depending on the system requirements and market prices at the time of the increases. A hypothetical 10% increase in the market price of power could result in a $5.3$4.0 million decrease in operating income for 20062007 related to purchased power. In 2006,2007, approximately 77%74% of KCP&L’s net MWhs generated are expected to be coal-fired. KCP&L currently has all of its coal requirements for 20062007 under contract. A hypothetical 10% increase in the market price of coal could
57
result in less than a $1.0 million increase in fuel expense for 2006.2007. KCP&L has also implemented price risk mitigation measures to reduce its exposure to high natural gas prices. A hypothetical 10% increase in natural gas and oil market prices could result in an increase of $2.4$1.1 million in fuel expense for 2006.2007. At December 31, 2005,2006, KCP&L had hedged approximately 30% and 9% of its 2007 and 2008, respectively, projected natural gas usage for generation requirements to serve retail load and firm MWh sales. KCP&L did not have any of its 2006 projected natural gas usage for generation requirements to serve retail load and firm MWh sales hedged. KCP&L had slightly under half of its 2005 projected natural gas usage for generation requirements to serve retail load and firm MWh sales hedged at December 31, 2004.2005.
 
Strategic Energy maintains a commodity-price risk management strategy that uses derivative instruments including forward physical energy purchases, to minimize significant, unanticipated net income fluctuations caused by commodity-price volatility. In certain markets where Strategic Energy
55
operates, entering into forward fixed price contracts is cost prohibitive. Financial derivative instruments, including swaps, 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. A hypothetical 10% increase in the costmarket price of purchased power could result in less thana $2.2 million increase in purchased power expense for 2006.2007.
 
Strategic Energy has historically utilized certain derivative instruments to protect against significant price volatility for purchased power that have qualified for the NPNS exception, in accordance with SFAS No. 133, as amended. However, as certain markets continue to develop, some derivative instruments may no longer qualify for the NPNS exception. As such, Strategic Energy is designating these derivative instruments as cash flow hedges, where appropriate, which could result in future increased volatility in derivative assets and liabilities, OCI and net income above levels historically experienced. Derivative instruments that were designated as NPNS are accounted for by accrual accounting, which requires the effects of the derivative to be recorded when the derivative contract settles. Accordingly, the increase in derivatives accounted for as cash flow hedges, and the corresponding decrease in derivatives accounted for as NPNS transactions, may affect the timing and nature of accounting recognition, but does not change the underlying economics of the transactions.
 
Investment Risk
KCP&L maintains trust funds, as required by the NRC, to fund its share of decommissioning the Wolf Creek nuclear power plant. As of December 31, 2005,2006, these funds were invested primarily in domestic equity securities and fixed income securities and are reflected at fair value on KCP&L’s balance sheets. The mix of securities is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs; however, the equity securities in the trusts are exposed to price fluctuations in equity markets and the value of fixed rate fixed income securities are exposed to changes in interest rates. A hypothetical increase in interest rates resulting in a hypothetical 10% decrease in the value of the fixed income securities would have resulted in a $4.2$5.0 million reduction in the value of the decommissioning trust funds at December 31, 2005.2006. A hypothetical 10% decrease in equity prices would have resulted in a $4.4$5.1 million reduction in the fair value of the equity securities at December 31, 2005.2006. KCP&L's exposure to investment risk associated with the decommissioning trust funds is in large part mitigated due to the fact that KCP&L is currently allowed to recover its decommissioning costs in its rates.
 
KLT Investments has affordable housing notes that require the greater of 15% of the outstanding note balances or the next annual installment to be held as cash, cash equivalents or marketable securities. A hypothetical 10% decrease in market prices of the securities held as collateral could result in a decrease of less than $1.0 million inwould have an insignificant impact on pre-tax net income for 2006.2007.
 
56
58
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS
 
GREAT PLAINS ENERGY
 
Consolidated Statements of Income
 
        
    As Adjusted As Adjusted 
Year Ended December 31
 
2006
 2005 2004 
Operating Revenues
 (thousands, except per share amounts) 
Electric revenues - KCP&L 
$
1,140,357
 $1,130,792 $1,090,067 
Electric revenues - Strategic Energy  
1,532,106
  1,471,490  1,370,760 
Other revenues  
2,886
  2,600  3,191 
Total  
2,675,349
  2,604,882  2,464,018 
Operating Expenses
          
Fuel  
229,469
  208,431  176,806 
Purchased power - KCP&L  
26,418
  61,263  52,533 
Purchased power - Strategic Energy  
1,490,246
  1,368,419  1,247,522 
Skill set realignment costs (Note 8)  
9,448
  -  - 
Other  
327,917
  327,801  323,663 
Maintenance  
83,844
  89,983  84,057 
Depreciation and amortization  
160,549
  153,080  150,071 
General taxes  
112,601
  109,436  102,756 
(Gain) loss on property  
(565
)
 3,544  5,133 
Total  
2,439,927
  2,321,957  2,142,541 
Operating income  
235,422
  282,925  321,477 
Non-operating income  
19,885
  19,505  6,799 
Non-operating expenses  
(6,702
)
 (16,745) (15,184)
Interest charges  
(71,221
)
 (73,787) (83,030)
Income from continuing operations before income taxes, minority          
interest in subsidiaries and loss from equity investments  
177,384
  211,898  230,062 
Income taxes  
(47,822
)
 (39,462) (55,391)
Minority interest in subsidiaries  
-
  (7,805) 2,131 
Loss from equity investments, net of income taxes  
(1,932
)
 (434) (1,531)
Income from continuing operations  
127,630
  164,197  175,271 
Discontinued operations, net of income taxes (Note 11)  
-
  (1,899) 7,276 
Net income  
127,630
  162,298  182,547 
Preferred stock dividend requirements  
1,646
  1,646  1,646 
Earnings available for common shareholders 
$
125,984
 $160,652 $180,901 
           
Average number of basic common shares outstanding  
78,003
  74,597  72,028 
Average number of diluted common shares outstanding  
78,170
  74,743  72,068 
           
Basic earnings (loss) per common share          
Continuing operations 
$
1.62
 $2.18 $2.41 
Discontinued operations  
-
  (0.03) 0.10 
Basic earnings per common share 
$
1.62
 $2.15 $2.51 
           
Diluted earnings (loss) per common share          
Continued operations 
$
1.61
 $2.18 $2.41 
Discontinued operations  -  (0.03) 0.10 
Diluted earnings per common share 
$
1.61
 $2.15 $2.51 
           
Cash dividends per common share 
$
1.66
 $1.66 $1.66 
 
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
59
GREAT PLAINS ENERGY
 
Consolidated Balance Sheets
 
      
    As Adjusted 
  
December 31
 December 31 
  
2006
 2005 
ASSETS
 (thousands) 
Current Assets
     
Cash and cash equivalents 
$
61,823
 $103,068 
Restricted cash  
-
  1,900 
Receivables, net  
339,399
  259,043 
Fuel inventories, at average cost  
27,811
  17,073 
Materials and supplies, at average cost  
59,829
  57,017 
Deferred refueling outage costs  
13,921
  8,063 
Refundable income taxes  
9,832
  - 
Deferred income taxes  
39,566
  - 
Assets of discontinued operations  
-
  627 
Derivative instruments  
6,884
  39,189 
Other  
11,717
  13,001 
Total  
570,782
  498,981 
Nonutility Property and Investments
       
Affordable housing limited partnerships  
23,078
  28,214 
Nuclear decommissioning trust fund  
104,066
  91,802 
Other  
15,663
  17,291 
Total  
142,807
  137,307 
Utility Plant, at Original Cost
       
Electric  
5,268,485
  4,959,539 
Less-accumulated depreciation  
2,456,199
  2,322,813 
Net utility plant in service  
2,812,286
  2,636,726 
Construction work in progress  
214,493
  100,952 
Nuclear fuel, net of amortization of $103,381 and $115,240  
39,422
  27,966 
Total  
3,066,201
  2,765,644 
Deferred Charges and Other Assets
       
Regulatory assets  
434,392
  179,922 
Prepaid pension costs  
-
  98,295 
Goodwill  
88,139
  87,624 
Derivative instruments  
3,544
  21,812 
Other  
29,795
  52,204 
Total  
555,870
  439,857 
Total 
$
4,335,660
 $3,841,789 
       
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
60
GREAT PLAINS ENERGY
 
Consolidated Balance Sheets
 
      
    As Adjusted 
  
December 31
 December 31 
  
2006
 2005 
LIABILITIES AND CAPITALIZATION
 (thousands) 
Current Liabilities
     
Notes payable 
$
-
 $6,000 
Commercial paper  
156,400
  31,900 
Current maturities of long-term debt  
389,634
  1,675 
EIRR bonds classified as current  
144,742
  - 
Accounts payable  
322,724
  231,496 
Accrued taxes  
24,106
  37,140 
Accrued interest  
14,082
  13,329 
Accrued payroll and vacations  
33,266
  36,024 
Pension and post retirement liability  
1,037
  - 
Deferred income taxes  
-
  7,757 
Supplier collateral  
-
  1,900 
Liabilities of discontinued operations  
-
  64 
Derivative instruments  
91,482
  7,411 
Other  
25,520
  25,658 
Total  
1,202,993
  400,354 
Deferred Credits and Other Liabilities
       
Deferred income taxes  
622,847
  621,359 
Deferred investment tax credits  
28,458
  29,698 
Asset retirement obligations  
91,824
  145,907 
Pension liability  
143,170
  87,355 
Regulatory liabilities  
114,674
  69,641 
Derivative instruments  
61,146
  7,750 
Other  
82,122
  65,787 
Total  
1,144,241
  1,027,497 
Capitalization
       
Common shareholders' equity       
Common stock-150,000,000 shares authorized without par value       
80,405,035 and 74,783,824 shares issued, stated value  
896,817
  744,457 
Retained earnings  
493,399
  498,632 
Treasury stock-53,499 and 43,376 shares, at cost  
(1,614
)
 (1,304)
Accumulated other comprehensive loss  
(46,686
)
 (7,727)
Total  
1,341,916
  1,234,058 
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 19)  
607,510
  1,140,880 
Total  
1,988,426
  2,413,938 
Commitments and Contingencies (Note 13)
     
Total 
$
4,335,660
 $3,841,789 
       
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
61
GREAT PLAINS ENERGY
 
Consolidated Statements of Cash Flows
 
        
    As Adjusted As Adjusted 
Year Ended December 31
 
2006
 2005 2004 
Cash Flows from Operating Activities
   (thousands)   
Net income 
$
127,630
 $162,298 $182,547 
Adjustments to reconcile income to net cash from operating activities:      
Depreciation and amortization  
160,549
  153,080  150,090 
Amortization of:          
Nuclear fuel  
14,392
  13,374  14,159 
Other  
9,271
  10,580  11,827 
Deferred income taxes, net  
(10,983
)
 (23,250) 31,259 
Investment tax credit amortization  
(1,240
)
 (3,889) (3,984)
Loss from equity investments, net of income taxes  
1,932
  434  1,531 
(Gain) loss on property  
(565
)
 3,295  (9,686)
Minority interest in subsidiaries  
-
  7,805  (2,131)
Fair value impacts from energy contracts  
56,757
  (2,452) (1,734)
Other operating activities (Note 2)  
(48,761
)
 95,616  (19,808)
Net cash from operating activities  
308,982
  416,891  354,070 
Cash Flows from Investing Activities
          
Utility capital expenditures  
(475,931
)
 (327,283) (190,548)
Allowance for borrowed funds used during construction  
(5,686
)
 (1,598) (1,498)
Purchases of investments  
-
  (14,976) (35,003)
Purchases of nonutility property  
(4,205
)
 (6,853) (6,108)
Proceeds from sale of assets and investments  
433
  17,369  67,457 
Purchases of nuclear decommissioning trust investments  
(49,667
)
 (34,607) (49,720)
Proceeds from nuclear decommissioning trust investments  
46,005
  31,055  46,167 
Purchase of additional indirect interest in Strategic Energy  
(700
)
 -  (90,033)
Hawthorn No. 5 partial insurance recovery  
-
  10,000  30,810 
Hawthorn No. 5 partial litigation recoveries  
15,829
  -  1,139 
Other investing activities  
(1,785
)
 (930) (7,081)
Net cash from investing activities  
(475,707
)
 (327,823) (234,418)
Cash Flows from Financing Activities
          
Issuance of common stock  
153,649
  9,061  153,662 
Issuance of long-term debt  
-
  334,417  163,600 
Issuance fees  
(6,172
)
 (4,522) (14,496)
Repayment of long-term debt  
(1,675
)
 (339,152) (213,943)
Net change in short-term borrowings  
118,500
  17,900  (67,000)
Dividends paid  
(132,653
)
 (125,484) (120,806)
Other financing activities  
(6,169
)
 (5,975) (7,309)
Net cash from financing activities  
125,480
  (113,755) (106,292)
Net Change in Cash and Cash Equivalents
  
(41,245
)
 (24,687) 13,360 
Less: Net Change in Cash and Cash Equivalents from
          
Discontinued Operations
  
-
  (626) 458 
Cash and Cash Equivalents at Beginning of Year
  
103,068
  127,129  114,227 
Cash and Cash Equivalents at End of Year
 
$
61,823
 $103,068 $127,129 
 
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
62
GREAT PLAINS ENERGY
 
Consolidated Statements of Common Shareholders' Equity
 
  
      As Adjusted As Adjusted 
Year to Date December 31
 
2006
 2005 2004 
  
Shares
 
Amount
 Shares Amount Shares Amount 
Common Stock
 (thousands, except share amounts) 
Beginning balance  
74,783,824
 
$
744,457
  74,394,423 $731,977  69,259,203 $602,551 
Issuance of common stock  
5,574,385
  
153,649
  313,026  9,400  5,121,887  153,662 
Issuance of restricted common stock 
46,826
  
1,320
  76,375  2,334  13,333  396 
Common stock issuance fees     
(5,198
)
    -     (5,434)
Equity compensation expense     
2,592
     1,394     181 
Unearned Compensation                   
Issuance of restricted common stock     
(1,355
)
    (2,434)    (396)
Forfeiture of restricted common stock     
56
     324     - 
Compensation expense recognized     
1,265
     1,415     636 
FELINE PRIDESSM purchase contract
                   
adjustment, allocated fees and expenses     
-
     -     (19,603)
Other    
31
     47     (16)
Ending balance  
80,405,035
  
896,817
  74,783,824  744,457  74,394,423  731,977 
Retained Earnings
                   
Beginning balance     
498,632
     462,134     391,750 
Net income     
127,630
     162,298     182,547 
Loss on reissuance of treasury stock     
-
     -     (193)
Cumulative effect of a change in accounting principle (Note 5) 
-
     -     8,907 
Dividends:                   
Common stock     
(130,959
)
    (123,838)    (119,160)
Preferred stock - at required rates     
(1,646
)
    (1,646)    (1,646)
Performance shares     
(258
)
    (260)    - 
Options     
-
     (56)    (71)
Ending balance    
493,399
    498,632    462,134 
Treasury Stock
                   
Beginning balance  
(43,376
)
 
(1,304
)
 (28,488) (856) (3,265) (121)
Treasury shares acquired  
(11,338
)
 
(346
)
 (18,385) (553) (54,683) (1,645)
Treasury shares reissued  
1,215
  
36
  3,497  105  29,460  910 
Ending balance  
(53,499
)
 
(1,614
)
 (43,376) (1,304) (28,488) (856)
Accumulated Other Comprehensive Loss
                   
Beginning balance     
(7,727
)
    (41,018)    (36,886)
Derivative hedging activity, net of tax     
(74,721
)
    28,397     931 
Minimum pension obligation, net of tax     
15,961
     4,894     (5,063)
Adjustment to initially apply SFAS No. 158, net of tax
(Note 8) 
(170,218
)
    -     - 
Regulatory adjustment     
190,019
     -     - 
Ending balance    
(46,686
)
   (7,727)   (41,018)
Total Common Shareholders' Equity
   
$
1,341,916
   $1,234,058   $1,152,237 
 
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
63

GREAT PLAINS ENERGY
 
Consolidated Statements of Comprehensive Income
 
  
    As Adjusted As Adjusted 
Year Ended December 31
 
2006
 2005 2004 
  (thousands) 
Net income 
$
127,630
 $162,298 $182,547 
Other comprehensive income          
Gain (loss) on derivative hedging instruments  
(181,597
)
 84,070  2,649 
Income taxes  
75,044
  (34,718) (1,126)
Net gain (loss) on derivative hedging instruments  
(106,553
)
 49,352  1,523 
Reclassification to expenses, net of tax  
31,832
  (20,955) (592)
Derivative hedging activity, net of tax  
(74,721
)
 28,397  931 
Change in minimum pension obligation  
25,579
  8,722  (7,624)
Income taxes  
(9,618
)
 (3,828) 2,561 
Net change in minimum pension obligation  
15,961
  4,894  (5,063)
Comprehensive income 
$
68,870
 $195,589 $178,415 
 
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
64
KANSAS CITY POWER & LIGHT COMPANY
 
Consolidated Statements of Income
 
        
    As Adjusted As Adjusted 
Year Ended December 31
 
2006
 2005 2004 
Operating Revenues
 (thousands) 
Electric revenues 
$
1,140,357
 $1,130,792 $1,090,067 
Other revenues  
-
  113  1,568 
Total  
1,140,357
  1,130,905  1,091,635 
Operating Expenses
          
Fuel  
229,469
  208,431  176,806 
Purchased power  
26,418
  61,263  52,533 
Skill set realignment costs (Note 8)  
9,347
  -  - 
Other  
260,281
  265,759  259,125 
Maintenance  
83,833
  89,954  83,989 
Depreciation and amortization  
152,714
  146,610  145,246 
General taxes  
107,858
  104,823  98,984 
(Gain) loss on property  
(572
)
 4,613  5,133 
Total  
869,348
  881,453  821,816 
Operating income  
271,009
  249,452  269,819 
Non-operating income  
14,965
  16,104  5,402 
Non-operating expenses  
(5,363
)
 (4,281) (7,407)
Interest charges  
(60,988
)
 (61,841) (74,170)
Income before income taxes and minority          
interest in subsidiaries  
219,623
  199,434  193,644 
Income taxes  
(70,302
)
 (47,984) (53,703)
Minority interest in subsidiaries  
-
  (7,805) 5,087 
Net income 
$
149,321
 $143,645 $145,028 
 
The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
 
Statements are an integral part of these statements.
 
 
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS
        
GREAT PLAINS ENERGY
Consolidated Statements of Income
        
        
Year Ended December 31
 
2005
20042003
Operating Revenues
 (thousands, except per share amounts) 
   Electric revenues - KCP&L 
$
1,130,792
 $1,090,067 $1,054,900 
   Electric revenues - Strategic Energy  
1,471,490
  1,370,760  1,089,663 
   Other revenues  
2,600
  3,191  3,482 
      Total  
2,604,882
  2,464,018  2,148,045 
Operating Expenses
          
   Fuel  
207,875
  179,362  160,327 
   Purchased power - KCP&L  
61,263
  52,533  53,163 
   Purchased power - Strategic Energy  
1,368,419
  1,247,522  968,967 
   Other  
327,749
  324,237  295,383 
   Maintenance  
90,350
  83,603  85,416 
   Depreciation and amortization  
153,080
  150,071  142,763 
   General taxes  
109,436
  102,756  98,461 
   (Gain) loss on property  
3,544
  5,133  (23,703)
      Total  
2,321,716
  2,145,217  1,780,777 
Operating income  
283,166
  318,801  367,268 
Non-operating income  
19,505
  6,799  7,414 
Non-operating expenses  
(16,745
)
 (15,184) (20,462)
Interest charges  
(73,787
)
 (83,030) (76,171)
Income from continuing operations before income taxes, minority          
   interest in subsidiaries and loss from equity investments  
212,139
  227,386  278,049 
Income taxes  
(39,691
)
 (54,451) (78,565)
Minority interest in subsidiaries  
(7,805
)
 2,131  (7,764)
Loss from equity investments, net of income taxes  
(434
)
 (1,531) (2,018)
Income from continuing operations  
164,209
  173,535  189,702 
Discontinued operations, net of income taxes (Note 8)  
(1,899
)
 7,276  (44,779)
Net income  
162,310
  180,811  144,923 
Preferred stock dividend requirements  
1,646
  1,646  1,646 
Earnings available for common shareholders 
$
160,664
 $179,165 $143,277 
           
Average number of common shares outstanding  
74,597
  72,028  69,206 
           
Basic and diluted earnings (loss) per common share          
   Continuing operations 
$
2.18
 $2.39 $2.72 
   Discontinued operations  
(0.03
)
 0.10  (0.65)
Basic and diluted earnings per common share 
$
2.15
 $2.49 $2.07 
           
Cash dividends per common share 
$
1.66
 $1.66 $1.66 
           
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
65

KANSAS CITY POWER & LIGHT COMPANY
 
Consolidated Balance Sheets
 
  
    As Adjusted 
  
December 31
 December 31 
  
2006
 2005 
ASSETS
 (thousands) 
Current Assets
     
Cash and cash equivalents 
$
1,788
 $2,961 
Receivables, net  
114,294
  70,264 
Fuel inventories, at average cost  
27,811
  17,073 
Materials and supplies, at average cost  
59,829
  57,017 
Deferred refueling outage costs  
13,921
  8,063 
Refundable income taxes  
7,229
  - 
Deferred income taxes  
52
  2,538 
Prepaid expenses  
9,673
  11,292 
Derivative instruments  
179
  - 
Total  
234,776
  169,208 
Nonutility Property and Investments
       
Nuclear decommissioning trust fund  
104,066
  91,802 
Other  
6,480
  7,694 
Total  
110,546
  99,496 
Utility Plant, at Original Cost
       
Electric  
5,268,485
  4,959,539 
Less-accumulated depreciation  
2,456,199
  2,322,813 
Net utility plant in service  
2,812,286
  2,636,726 
Construction work in progress  
214,493
  100,952 
Nuclear fuel, net of amortization of $103,381 and $115,240  
39,422
  27,966 
Total  
3,066,201
  2,765,644 
Deferred Charges and Other Assets
       
Regulatory assets  
434,392
  179,922 
Prepaid pension costs  
-
  98,002 
Other  
13,584
  27,905 
Total  
447,976
  305,829 
Total 
$
3,859,499
 $3,340,177 
 
The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
 
Statements are an integral part of these statements.
 
66
KANSAS CITY POWER & LIGHT COMPANY
 
Consolidated Balance Sheets
 
  
    As Adjusted 
  
December 31
 December 31 
  
2006
 2005 
LIABILITIES AND CAPITALIZATION
 (thousands) 
Current Liabilities
     
Notes payable to Great Plains Energy 
$
550
 $500 
Commercial paper  
156,400
  31,900 
Current maturities of long-term debt  
225,500
  - 
EIRR bonds classified as current  
144,742
  - 
Accounts payable  
181,805
  106,040 
Accrued taxes  
18,165
  27,448 
Accrued interest  
12,461
  11,549 
Accrued payroll and vacations  
24,641
  27,520 
Pension and post retirement liability  
841
  - 
Derivative instruments  
2,687
  - 
Other  
8,469
  8,600 
Total  
776,261
  213,557 
Deferred Credits and Other Liabilities
       
Deferred income taxes  
660,046
  627,048 
Deferred investment tax credits  
28,458
  29,698 
Asset retirement obligations  
91,824
  145,907 
Pension liability  
132,216
  85,301 
Regulatory liabilities  
114,674
  69,641 
Derivative instruments  
39
  2,601 
Other  
65,651
  38,387 
Total  
1,092,908
  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  
354,802
  294,481 
Accumulated other comprehensive income (loss)  
6,685
  (29,909)
Total  
1,383,143
  1,151,613 
Long-term debt (Note 19)  
607,187
  976,424 
Total  
1,990,330
  2,128,037 
Commitments and Contingencies (Note 13)
     
Total 
$
3,859,499
 $3,340,177 
       
The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
 
Statements are an integral part of these statements.      
 
67

KANSAS CITY POWER & LIGHT COMPANY
 
Consolidated Statements of Cash Flows
 
        
    As Adjusted As Adjusted 
Year Ended December 31
 
2006
 2005 2004 
Cash Flows from Operating Activities
 (thousands) 
Net income 
$
149,321
 $143,645 $145,028 
Adjustments to reconcile income to net cash from operating activities:      
Depreciation and amortization  
152,714
  146,610  145,246 
Amortization of:          
Nuclear fuel  
14,392
  13,374  14,159 
Other  
6,617
  7,681  7,719 
Deferred income taxes, net  
17,411
  (33,637) 11,801 
Investment tax credit amortization  
(1,240
)
 (3,889) (3,984)
(Gain) loss on property  
(572
)
 4,613  5,133 
Minority interest in subsidiaries  
-
  7,805  (5,087)
Other operating activities (Note 2)  
(39,408
)
 79,284  (3,756)
Net cash from operating activities  
299,235
  365,486  316,259 
Cash Flows from Investing Activities
        
Utility capital expenditures  
(475,931
)
 (332,055) (190,548)
Allowance for borrowed funds used during construction  
(5,686
)
 (1,598) (1,498)
Purchases of nonutility property  
(62
)
 (127) (254)
Proceeds from sale of assets  
433
  469  7,465 
Purchases of nuclear decommissioning trust investments  
(49,667
)
 (34,607) (49,720)
Proceeds from nuclear decommissioning trust investments  
46,005
  31,055  46,167 
Hawthorn No. 5 partial insurance recovery  
-
  10,000  30,810 
Hawthorn No. 5 partial litigation recoveries  
15,829
  -  1,139 
Other investing activities  
(983
)
 (930) (7,100)
Net cash from investing activities  
(470,062
)
 (327,793) (163,539)
Cash Flows from Financing Activities
        
Issuance of long-term debt  
-
  334,417  - 
Repayment of long-term debt  
-
  (335,922) (209,140)
Net change in short-term borrowings  
124,550
  32,376  (21,959)
Dividends paid to Great Plains Energy  
(89,000
)
 (112,700) (119,160)
Equity contribution from Great Plains Energy  
134,615
  -  225,000 
Issuance fees  
(511
)
 (4,522) (2,362)
Net cash from financing activities  
169,654
  (86,351) (127,621)
Net Change in Cash and Cash Equivalents
  
(1,173
)
 (48,658) 25,099 
Cash and Cash Equivalents at Beginning of Year
  
2,961
  51,619  26,520 
Cash and Cash Equivalents at End of Year
 
$
1,788
 $2,961 $51,619 
       
The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
 
Statements are an integral part of these statements.         
68

KANSAS CITY POWER & LIGHT COMPANY
 
Consolidated Statements of Common Shareholder's Equity
 
  
        
      As Adjusted As Adjusted 
Year to Date December 31
 
2006
 2005 2004 
  
Shares
 
Amount
 Shares Amount Shares Amount 
Common Stock
 (thousands, except share amounts) 
Beginning balance  
1
 
$
887,041
  1 $887,041  1 $662,041 
Equity contribution from Great Plains Energy
-
  
134,615
  -  -  -  225,000 
Ending balance  
1
  
1,021,656
  1  887,041  1  887,041 
Retained Earnings
                  
Beginning balance     
294,481
     263,536    228,761 
Net income     
149,321
     143,645    145,028 
Cumulative effect of a change in accounting principle (Note 5) 
-
     -    8,907 
Dividends:                  
Common stock held by Great Plains Energy   
(89,000
)
    (112,700)   (119,160)
Ending balance    
354,802
    294,481    263,536 
Accumulated Other Comprehensive Income (Loss)
              
Beginning balance     
(29,909
)
    (40,334)   (35,244)
Derivative hedging activity, net of tax     
(741
)
    7,571    (233)
Minimum pension obligation, net of tax     
15,913
     2,854    (4,857)
Adjustment to initially apply SFAS No. 158 (Note 8) 
(168,597
)
    -    - 
Regulatory adjustment     
190,019
     -    - 
Ending balance    
6,685
    (29,909)   (40,334)
Total Common Shareholder's Equity
   
$
1,383,143
   $1,151,613   $1,110,243 
 
The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial  
Statements are an integral part of these statements.
69

KANSAS CITY POWER & LIGHT COMPANY
 
Consolidated Statements of Comprehensive Income
 
        
    As Adjusted As Adjusted 
Year Ended December 31
 
2006
 2005 2004 
  (thousands) 
Net income 
$
149,321
 $143,645 $145,028 
Other comprehensive income          
Gain (loss) on derivative hedging instruments  
(788
)
 12,650  280 
Income taxes  
296
  (4,759) (111)
Net gain (loss) on derivative hedging instruments  
(492
)
 7,891  169 
Reclassification to expenses, net of tax  
(249
)
 (320) (402)
Derivative hedging activity, net of tax  
(741
)
 7,571  (233)
Change in minimum pension obligation  
25,502
  5,410  (7,321)
Income taxes  
(9,589
)
 (2,556) 2,464 
Net change in minimum pension obligation  
15,913
  2,854  (4,857)
Comprehensive income 
$
164,493
 $154,070 $139,938 
           
The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial
 
Statements are an integral part of these statements.
 
 
5770

GREAT PLAINS ENERGY
Consolidated Balance Sheets
      
  
December 31
  
2005
2004
ASSETS
 (thousands) 
Current Assets
     
   Cash and cash equivalents 
$
103,068
 $127,129 
   Restricted cash  
1,900
  7,700 
   Receivables, net  
259,043
  247,184 
   Fuel inventories, at average cost  
17,073
  21,121 
   Materials and supplies, at average cost  
57,017
  54,432 
   Deferred income taxes  
-
  13,065 
   Assets of discontinued operations  
627
  749 
   Derivative instruments  
39,189
  6,372 
   Other  
13,001
  14,485 
      Total  
490,918
  492,237 
Nonutility Property and Investments
       
   Affordable housing limited partnerships  
28,214
  41,317 
   Nuclear decommissioning trust fund  
91,802
  84,148 
   Other  
17,291
  32,739 
      Total  
137,307
  158,204 
Utility Plant, at Original Cost
       
   Electric  
4,959,539
  4,841,355 
   Less-accumulated depreciation  
2,322,813
  2,196,835 
      Net utility plant in service  
2,636,726
  2,644,520 
   Construction work in progress  
100,952
  53,821 
   Nuclear fuel, net of amortization of $115,240 and $127,631  
27,966
  36,109 
      Total  
2,765,644
  2,734,450 
Deferred Charges and Other Assets
       
   Regulatory assets  
179,922
  144,345 
   Prepaid pension costs  
98,295
  119,811 
   Goodwill  
87,624
  86,767 
   Derivative instruments  
21,812
  2,275 
   Other  
52,204
  60,812 
      Total  
439,857
  414,010 
      Total 
$
3,833,726
 $3,798,901 
        
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
58

GREAT PLAINS ENERGY
Consolidated Balance Sheets
December 31
2005
2004
LIABILITIES AND CAPITALIZATION
(thousands)
Current Liabilities
   Notes payable
$
6,000
$20,000
   Commercial paper
31,900
-
   Current maturities of long-term debt
1,675
253,230
   EIRR bonds classified as current
-
85,922
   Accounts payable
231,496
199,952
   Accrued taxes
37,140
46,993
   Accrued interest
13,329
11,598
   Accrued payroll and vacations
36,024
32,462
   Accrued refueling outage costs
8,974
13,180
   Deferred income taxes
1,351
-
   Supplier collateral
1,900
7,700
   Liabilities of discontinued operations
64
2,129
   Derivative instruments
7,411
2,434
   Other
25,658
22,497
      Total
402,922
698,097
Deferred Credits and Other Liabilities
   Deferred income taxes
621,359
632,160
   Deferred investment tax credits
29,698
33,587
   Asset retirement obligations
145,907
113,674
   Pension liability
87,355
95,805
   Regulatory liabilities
69,641
4,101
   Derivative instruments
7,750
112
   Other
65,787
84,311
      Total
1,027,497
963,750
Capitalization
   Common shareholders' equity
      Common stock-150,000,000 shares authorized without par value
         74,783,824 and 74,394,423 shares issued, stated value
777,216
765,482
      Unearned compensation
(2,088
)
(1,393)
      Capital stock premium and expense
(30,671
)
(32,112)
      Retained earnings
488,001
451,491
      Treasury stock-43,376 and 28,488 shares, at cost
(1,304
)
(856)
      Accumulated other comprehensive loss
(7,727
)
(41,018)
         Total
1,223,427
1,141,594
   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 19)
1,140,880
956,460
         Total
2,403,307
2,137,054
Commitments and Contingencies (Note 13)
      Total
$
3,833,726
$3,798,901
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
59
GREAT PLAINS ENERGY
 
Consolidated Statements of Cash Flows
 
        
    Revised Revised 
Year Ended December 31
 
2005
 2004 2003 
Cash Flows from Operating Activities
   (thousands)   
Net income 
$
162,310
 $180,811 $144,923 
Adjustments to reconcile income to net cash from operating activities:      
      Depreciation and amortization  
153,080
  150,090  143,712 
      Amortization of:          
         Nuclear fuel  
13,374
  14,159  12,334 
         Other  
10,580
  11,827  11,626 
      Deferred income taxes, net  
(23,021
)
 
30,319
  17,058 
      Investment tax credit amortization  
(3,889
)
 (3,984) (3,994)
      Loss from equity investments  
434
  1,531  2,018 
      (Gain) loss on property  
3,295
  (9,686)  30,797 
      Minority interest in subsidiaries  
7,805
  (2,131) 7,764 
Other operating activities (Note 2)  
92,923
  (18,866)  20,857 
            Net cash from operating activities  
416,891
  354,070  387,095 
Cash Flows from Investing Activities
          
Utility capital expenditures  
(327,283
)
 (190,548) (148,675)
Allowance for borrowed funds used during construction  
(1,598
)
 (1,498) (1,368)
Purchases of investments  
(14,976
)
 (35,003) - 
Purchases of nonutility property  
(6,853
)
 (6,108) (22,746)
Proceeds from sale of assets and investments  
17,369
  67,457  33,277 
Purchases of nuclear decommissioning trust investments  
(34,607
)
 (49,720) (111,699)
Proceeds from nuclear decommissioning trust investments  
31,055
  46,167  108,179 
Purchase of additional indirect interest in Strategic Energy  
-
  (90,033) - 
Hawthorn No. 5 partial insurance recovery  
10,000
  30,810  3,940 
Hawthorn No. 5 partial litigation settlements  
-
  1,139  17,263 
Other investing activities  
(930
)
 (7,081) (1,220)
           Net cash from investing activities  
(327,823
)
 (234,418) (123,049)
Cash Flows from Financing Activities
          
Issuance of common stock  
9,061
  153,662  - 
Issuance of long-term debt  
334,417
  163,600  - 
Issuance fees  
(4,522
)
 (14,496) (266)
Repayment of long-term debt  
(339,152
)
 (213,943) (133,181)
Net change in short-term borrowings  
17,900
  (67,000) 42,320 
Dividends paid  
(125,484
)
 (120,806) (116,527)
Other financing activities  
(5,975
)
 (7,309) (7,598)
           Net cash from financing activities  
(113,755
)
 (106,292) (215,252)
Net Change in Cash and Cash Equivalents
  
(24,687
)
 13,360  48,794 
Less: Net Change in Cash and Cash Equivalents from
          
          Discontinued Operations
  
(626
)  458  73 
Cash and Cash Equivalents at Beginning of Year  127,129  114,227  65,506 
Cash and Cash Equivalents at End of Year
 
$
103,068
 $127,129 $114,227 
           
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.  
60
GREAT PLAINS ENERGY
Consolidated Statements of Common Shareholders' Equity
              
  
2005
 2004 2003 
  
Shares
 
Amount
 Shares Amount Shares Amount 
Common Stock
 (thousands, except share amounts)
Beginning balance  
74,394,423
 
$
765,482
  69,259,203 $611,424  69,196,322 $609,497 
Issuance of common stock  
313,026
  
9,400
  5,121,887  153,662  -  - 
Issuance of restricted common stock  
76,375
  
2,334
  13,333  396  62,881  1,927 
   Ending balance  
74,783,824
  
777,216
  74,394,423  765,482  69,259,203  611,424 
Unearned Compensation
                   
Beginning balance     
(1,393
)
    (1,633)    - 
Issuance of restricted common stock     
(2,434
)
    (396)    (1,927)
Forfeiture of restricted common stock 
324
     -     - 
Compensation expense recognized     
1,415
     636     294 
   Ending balance    
(2,088
)
   (1,393)   (1,633)
Capital Stock Premium and Expense
               
Beginning balance     
(32,112
)
    (7,240)    (7,744)
Issuance of common stock     
-
     (5,434)    - 
Equity compensation expense     
1,394
     181     443 
FELINE PRIDESSM purchase contract 
       
   adjustment, allocated fees and expenses 
-
     (19,603)    - 
Other     
47
     (16)    61 
   Ending balance    
(30,671
)
   (32,112)   (7,240)
Retained Earnings
                   
Beginning balance     
451,491
     391,750     363,579 
Net income     
162,310
     180,811     144,923 
Loss on reissuance of treasury stock     
-
     (193)    - 
Dividends:                   
   Common stock     
(123,838
)
    (119,160)    (114,881)
   Preferred stock - at required rates     
(1,646
)
    (1,646)    (1,646)
   Performance shares     
(260
)
    -     - 
   Options     
(56
)
    (71)    (225)
      Ending balance    
488,001
    451,491    391,750 
Treasury Stock
                   
Beginning balance  
(28,488
)
 
(856
)
 (3,265) (121) (152) (4)
Treasury shares acquired  
(18,385
)
 
(553
)
 (54,683) (1,645) (85,000) (2,332)
Treasury shares reissued  
3,497
  
105
  29,460  910  81,887  2,215 
   Ending balance  
(43,376
)
 
(1,304
)
 (28,488) (856) (3,265) (121)
Accumulated Other Comprehensive Loss
               
Beginning balance     
(41,018
)
    (36,886)    (25,858)
Derivative hedging activity, net of tax     
28,397
     931     (598)
Minimum pension obligation, net of tax 
4,894
     (5,063)    (10,430)
   Ending balance    
(7,727
)
   (41,018)   (36,886)
Total Common Shareholders' Equity
$
1,223,427
   $1,141,594   $957,294 
                    
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
61

GREAT PLAINS ENERGY
 
Consolidated Statements of Comprehensive Income
 
  
        
Year Ended December 31
 
2005
 2004 2003 
  (thousands) 
Net income 
$
162,310
 $180,811 $144,923 
Other comprehensive income          
   Gain on derivative hedging instruments  
84,070
  2,649  7,712 
   Income taxes  
(34,718
)
 (1,126) (3,359)
      Net gain on derivative hedging instruments  
49,352
  1,523  4,353 
   Reclassification to expenses, net of tax  
(20,955
)
 (592) (4,951)
         Derivative hedging activity, net of tax  
28,397
  931  (598)
   Change in minimum pension obligation  
8,722
  (7,624) (17,100)
   Income taxes  
(3,828
)
 2,561  6,670 
         Net change in minimum pension obligation  
4,894
  (5,063) (10,430)
Comprehensive income 
$
195,601
 $176,679 $133,895 
           
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
62

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Income
        
        
Year Ended December 31
 
2005
20042003
Operating Revenues
 (thousands) 
   Electric revenues 
$
1,130,792
 $1,090,067 $1,054,900 
   Other revenues  
113
  1,568  2,101 
      Total  
1,130,905
  1,091,635  1,057,001 
Operating Expenses
          
   Fuel  
207,875
  179,362  160,327 
   Purchased power  
61,263
  52,533  53,163 
   Other  
265,707
  259,699  241,701 
   Maintenance  
90,321
  83,535  85,391 
   Depreciation and amortization  
146,610
  145,246  140,955 
   General taxes  
104,823
  98,984  95,590 
   (Gain) loss on property  
4,613
  5,133  (1,603)
      Total  
881,212
  824,492  775,524 
Operating income  
249,693
  267,143  281,477 
Non-operating income  
16,104
  5,402  5,251 
Non-operating expenses  
(4,281
)
 (7,407) (8,280)
Interest charges  
(61,841
)
 (74,170) (70,294)
Income from continuing operations before          
   income taxes and minority interest in subsidiaries  
199,675
  190,968  208,154 
Income taxes  
(48,213
)
 (52,763) (83,572)
Minority interest in subsidiaries  
(7,805
)
 5,087  1,263 
Income from continuing operations  
143,657
  143,292  125,845 
Discontinued operations, net of income taxes (Note 8)  
-
  -  (8,690)
Net income 
$
143,657
 $143,292 $117,155 
           
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
63

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
      
  
December 31
  
2005
2004
ASSETS
 (thousands) 
Current Assets
     
   Cash and cash equivalents 
$
2,961
 $51,619 
   Receivables, net  
70,264
  63,366 
   Fuel inventories, at average cost  
17,073
  21,121 
   Materials and supplies, at average cost  
57,017
  54,432 
   Deferred income taxes  
8,944
  12,818 
   Prepaid expenses  
11,292
  12,511 
   Derivative instruments  
-
  363 
      Total  
167,551
  216,230 
Nonutility Property and Investments
       
   Nuclear decommissioning trust fund  
91,802
  84,148 
   Other  
7,694
  20,576 
      Total  
99,496
  104,724 
Utility Plant, at Original Cost
       
   Electric  
4,959,539
  4,841,355 
   Less-accumulated depreciation  
2,322,813
  2,196,835 
      Net utility plant in service  
2,636,726
  2,644,520 
   Construction work in progress  
100,952
  53,821 
   Nuclear fuel, net of amortization of $115,240 and $127,631  
27,966
  36,109 
      Total  
2,765,644
  2,734,450 
Deferred Charges and Other Assets
       
   Regulatory assets  
179,922
  144,345 
   Prepaid pension costs  
98,002
  116,024 
   Derivative instruments  
-
  674 
   Other  
27,905
  20,947 
      Total  
305,829
  281,990 
      Total 
$
3,338,520
 $3,337,394 
        
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are
an integral part of these statements.
64

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets
      
  
December 31
  
2005
2004
LIABILITIES AND CAPITALIZATION
 (thousands) 
Current Liabilities
     
   Notes payable to Great Plains Energy 
$
500
 $24 
   Commercial paper  
31,900
  - 
   Current maturities of long-term debt  
-
  250,000 
   EIRR bonds classified as current  
-
  85,922 
   Accounts payable  
106,040
  84,105 
   Accrued taxes  
27,448
  34,497 
   Accrued interest  
11,549
  9,800 
   Accrued payroll and vacations  
27,520
  22,870 
   Accrued refueling outage costs  
8,974
  13,180 
   Other  
8,600
  8,327 
      Total  
222,531
  508,725 
Deferred Credits and Other Liabilities
       
   Deferred income taxes  
627,048
  654,055 
   Deferred investment tax credits  
29,698
  33,587 
   Asset retirement obligations  
145,907
  113,674 
   Pension liability  
85,301
  90,491 
   Regulatory liabilities  
69,641
  4,101 
   Derivative instruments  
2,601
  - 
   Other  
38,387
  42,832 
      Total  
998,583
  938,740 
Capitalization
     
   Common shareholder's equity       
      Common stock-1,000 shares authorized without par value       
                                       1 share issued, stated value  
887,041
  887,041 
      Retained earnings  
283,850
  252,893 
      Accumulated other comprehensive loss  
(29,909
)
 (40,334)
         Total  
1,140,982
  1,099,600 
   Long-term debt (Note 19)  
976,424
  790,329 
      Total  
2,117,406
  1,889,929 
Commitments and Contingencies (Note 13)
      Total 
$
3,338,520
 $3,337,394 
        
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are
an integral part of these statements.
65
KANSAS CITY POWER & LIGHT COMPANY
 
Consolidated Statements of Cash Flows
 
        
      Revised 
Year Ended December 31
 
2005
 2004 2003 
Cash Flows from Operating Activities
 (thousands) 
Net income 
$
143,657
 $143,292 $117,155 
Adjustments to reconcile income to net cash from operating activities:      
      Depreciation and amortization  
146,610
  145,246  140,955 
      Amortization of:          
         Nuclear fuel  
13,374
  14,159  12,334 
         Other  
7,681
  7,719  9,350 
      Deferred income taxes, net  
(33,408
)
 10,861  34,285 
      Investment tax credit amortization  
(3,889
)
 (3,984) (3,994)
      (Gain) loss on property  
4,613
  5,133  (1,603)
      Minority interest in subsidiaries  
7,805
  (5,087) (1,263)
Other operating activities (Note 2)  
79,043
  (1,080) (24,627)
            Net cash from operating activities  
365,486
  316,259  282,592 
Cash Flows from Investing Activities
        
Utility capital expenditures  
(332,055
)
 (190,548) (148,675)
Allowance for borrowed funds used during construction  
(1,598
)
 (1,498) (1,368)
Purchases of nonutility property  
(127
)
 (254) (147)
Proceeds from sale of assets  
469
  7,465  4,135 
Purchases of nuclear decommissioning trust investments  
(34,607
)
 (49,720) (111,699)
Proceeds from nuclear decommissioning trust investments  
31,055
  46,167  108,179 
Hawthorn No. 5 partial insurance recovery  
10,000
  30,810  3,940 
Hawthorn No. 5 partial litigation settlements  
-
  1,139  17,263 
Other investing activities  
(930
)
 (7,100) (4,045)
            Net cash from investing activities  
(327,793
)
 (163,539) (132,417)
Cash Flows from Financing Activities
        
Issuance of long-term debt  
334,417
  -  - 
Repayment of long-term debt  
(335,922
)
 (209,140) (124,000)
Net change in short-term borrowings  
32,376
  (21,959) (1,867)
Dividends paid to Great Plains Energy  
(112,700
)
 (119,160) (98,000)
Equity contribution from Great Plains Energy  
-
  225,000  100,000 
Issuance fees  
(4,522
)
 (2,362) (266)
            Net cash from financing activities  
(86,351
)
 (127,621) (124,133)
Net Change in Cash and Cash Equivalents
  
(48,658
)
 25,099  26,042 
Less: Net Change in Cash and Cash Equivalents from         
          Discontinued Operations -  -  (307) 
Cash and Cash Equivalents  at Beginning of Year 
 
51,619
  26,520  171 
Cash and Cash Equivalents at End of Year
 
$
2,961
 $51,619 $26,520 
        
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
66

KANSAS CITY POWER & LIGHT COMPANY
 
Consolidated Statements of Common Shareholder's Equity
 
              
  
2005
 2004 2003 
  
Shares
 
Amount
 Shares Amount Shares Amount 
Common Stock
 (thousands, except share amounts) 
Beginning balance  
1
 
$
887,041
  1 $662,041  1 $562,041 
Equity contribution from Great Plains Energy  
-
  
-
  -  225,000  -  100,000 
   Ending balance  
1
  
887,041
  1  887,041  1  662,041 
Retained Earnings
                   
Beginning balance     
252,893
     228,761     209,606 
Net income     
143,657
     143,292     117,155 
Dividends:                   
   Common stock held by Great Plains Energy 
(112,700
)
    (119,160)    (98,000)
      Ending balance   
283,850
    252,893    228,761 
Accumulated Other Comprehensive Loss
               
Beginning balance     
(40,334
)
    (35,244)    (26,614)
Derivative hedging activity, net of tax     
7,571
     (233)    (83)
Minimum pension obligation, net of tax     
2,854
     (4,857)    (8,547)
   Ending balance    
(29,909
)
   (40,334)   (35,244)
Total Common Shareholder's Equity
   
$
1,140,982
   $1,099,600   $855,558 
                    
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these
statements.
67

KANSAS CITY POWER & LIGHT COMPANY
 
Consolidated Statements of Comprehensive Income
 
        
Year Ended December 31
 
2005
 2004 2003 
  (thousands) 
Net income 
$
143,657
 $143,292 $117,155 
Other comprehensive income          
   Gain on derivative hedging instruments  
12,650
  280  657 
   Income taxes  
(4,759
)
 (111) (256)
      Net gain on derivative hedging instruments  
7,891
  169  401 
   Reclassification to expenses, net of tax  
(320
)
 (402) (484)
         Derivative hedging activity, net of tax  
7,571
  (233) (83)
   Change in minimum pension obligation  
5,410
  (7,321) (14,012)
   Income taxes  
(2,556
)
 2,464  5,465 
         Net change in minimum pension obligation  
2,854
  (4,857) (8,547)
Comprehensive income 
$
154,082
 $138,202 $108,525 
           
The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
68
GREAT PLAINS ENERGY INCORPORATED
KANSAS CITY POWER & LIGHT COMPANY
Notes to Consolidated Financial Statements
 
The notes to consolidated financial statements that follow are a combined presentation for Great Plains Energy Incorporated and Kansas City Power & Light Company, both registrants under this filing. The terms “Great Plains Energy,” “Company,” “KCP&L” and “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 wholly owned 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’s&L has two wholly owned subsidiary,subsidiaries, Kansas City Power & Light Receivables Company (Receivables Company) and Home Service Solutions Inc. (HSS) sold its wholly owned subsidiary, Worry Free Service, Inc. (Worry Free) in February 2005 and completed the disposition of its interest in R.S. Andrews Enterprises, Inc. (RSAE) in June 2003. See Note 8 for additional information concerning the June 2003 disposition of RSAE. After these sales,. HSS has no active operations.
 
·  KLT Inc. is an intermediate holding company that primarily holds directly or indirectly,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 holds investments in affordable housing limited partnerships. KLT Inc. also wholly owns KLT Gas Inc. (KLT Gas). See Note 8 for additional information regarding KLT Gas discontinued, which has no active operations.
 
·  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 just under 100% of the indirect interest in 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 the operations of HSS, Services, all KLT Inc. operationsactivity other than Strategic Energy, and holding company operations.
 
Cash and Cash Equivalents
Cash equivalents consist of highly liquid investments with original maturities of three months or less.less at acquisition. For Great Plains Energy, this includes Strategic Energy’s cash held in trust of $21.9$8.8 million and $21.0$21.9 million at December 31, 20052006 and 2004,2005, 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
69
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.
71
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’sEnergy held no restricted cash collateral wasat December 31, 2006, and $1.9 million and $7.7 million at December 31, 2005 and 2004, respectively.2005.
 
Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value.
 
Nonutility property and investments - Consolidated KCP&L's investments and nonutility property includes the nuclear decommissioning trust fund assets recorded at fair value. Fair value is based on quoted market prices of the investments held by the fund. In addition to consolidated KCP&L’s investments, Great Plains Energy’s investments and nonutility property include KLT Investments Inc.’s (KLT Investments) affordable housing limited partnerships. The fair value of KLT Investments' affordable housing limited partnership total portfolio, based on the discounted cash flows generated by tax credits, tax deductions and sale of properties, approximates book value. The fair values of other various investments are not readily determinable and the investments are therefore stated at cost.
 
Long-term debt - The incremental borrowing rate for similar debt was used to determine fair value if quoted market prices were not available. Great Plains Energy’s and consolidated KCP&L’s book values of long-term debt were 1% below fair values at December 31, 2005.2006.
 
Derivative instruments - The fair value of derivative instruments is estimated using market quotes, over-the-counter forward price and volatility curves and correlation among power and fuel prices, net of estimated credit risk.
 
Derivative Instruments
The Company accounts for derivative instruments in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. This statement generally requires derivative instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships. The Company enters into derivative contracts to manage its exposure to commodity price fluctuations and interest rate risk. Derivative instruments designated as normal purchases and normal sales (NPNS) and cash flow hedges are used solely for hedging purposes and are not issued or held for speculative reasons.
 
The Company considers various qualitative factors, such as contract and market place attributes, in designating derivative instruments at inception. The Company may elect the NPNS exception, which requires the effects of the derivative to be recorded as the underlying contract settles.
 
The Company accounts for derivative instruments that are not designated as NPNS as cash flow hedges or non-hedging derivatives, which are recorded as assets or liabilities on the consolidated balance sheets at fair value. At the inception of a derivative instrument, the Company designates its derivative instrument as NPNS, a cash flow hedge or a non-hedging derivative under the requirements of SFAS No. 133. In addition, if a derivative instrument is designated as a cash flow hedge, the Company documents its method of determining hedge effectiveness and measuring ineffectiveness. See Note 2122 for additional information regarding derivative financial instruments and hedging activities.
7072
Investments in Affordable Housing Limited Partnerships
At December 31, 2005,2006, KLT Investments had $28.2$23.1 million of investments in affordable housing limited partnerships. Approximately 59%67% 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 the 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, $16.2$15.1 million exceed this 5% level but were made before May 19, 1995. Management does not anticipate making significant additional investments in affordable housing limited partnerships at this time.
 
On a quarterly basis, KLT Investments compares the cost of those 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 reduced its investments in affordable housing limited partnerships by $1.2 million, $10.0 million and $7.5 million in 2006, 2005 and $11.0 million in 2005, 2004, and 2003, respectively. These amounts are included in Non-operating expenses on Great Plains Energy’s consolidated statements of income. The properties underlying the partnership investments are subject to certain risks inherent in real estate ownership and management.
 
Other Nonutility Property
Great Plains Energy’s and consolidated KCP&L’s other nonutility property includes land, buildings, vehicles, general office equipment and software and is recorded at historical cost, net of accumulated depreciation, and has a range of estimated useful lives of 3 to 43 years.
 
Utility Plant
KCP&L's utility plant is stated at historical costs of construction.cost. These costs include taxes, an allowance for the cost of borrowed and equity funds used to finance construction and payroll-related costs, including pensions and other fringe benefits. Replacements, improvements and additions to units of property are capitalized. Repairs of property and replacements of items not considered to be units of property are expensed as incurred (except as discussed under AccruedDeferred Refueling Outage Costs). When property units are retired or otherwise disposed, the original cost, net of salvage, is charged to accumulated depreciation. Substantially all utility plant is pledged as collateral for KCP&L’s mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented.
 
As prescribed by the Federal Energy Regulatory Commission (FERC), Allowance for Funds used During Construction (AFDC) is charged to the cost of the plant. AFDC is included in the rates charged to customers by KCP&L over the service life of the property. AFDC equity funds are included as a non-cash item in non-operating income and AFDC borrowed funds are a reduction of interest charges. The rates used to compute gross AFDC are compounded semi-annually and averaged 7.8% in 2006, 7.1% in 2005 and 8.6% in 2004 and 8.2% in 2003.2004.
7173
The balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following table.
      
December 31
 
2006
 
2005
 
Utility Plant, at original cost (millions) 
Production (23 - 42 years) $3,135.6 $2,970.1 
Transmission (27 - 76 years)  364.3  331.2 
Distribution (8 - 75 years)  1,465.7  1,377.3 
General (5 - 50 years)  302.9  280.9 
Total (a)
 $5,268.5 $4,959.5 
(a) Includes $40.3 million and $80.4 million of land and other assets that are not
    depreciated.
 
December 31
 
2005
 
2004
 
Utility Plant, at original cost (millions)
   Production (23 - 42 years) $2,970.1 $2,938.5 
   Transmission (27 - 76 years)  331.2  315.5 
   Distribution (8 - 75 years)  1,377.3  1,320.0 
   General (5 - 50 years)  280.9  267.4 
Total (a)
 $4,959.5 $4,841.4 
(a) Includes $80.4 million and $66.6 million of land and other assets for
    which depreciation was not recorded in 2005 and 2004, respectively.
Depreciation Depletion and Amortization
Depreciation and amortization of KCP&L’s utility plant other than nuclear fuel is computed using the straight-line method over the estimated lives of depreciable property based on rates approved by state regulatory authorities. Annual depreciation rates average approximately 3%. Nuclear fuel is amortized to fuel expense based on the quantity of heat produced during the generation of electricity.
 
Depreciation of nonutility property is computed using the straight-line method. Consolidated KCP&L’s nonutility property annual depreciation rates for 2006, 2005 and 2004 were 11.5%, 11.2% and 2003 were 11.2%, 11.8% and 11.1%, respectively. Other Great Plains Energy nonutility property annual depreciation rates for 2006, 2005 and 2004 were 23.4%, 20.4% and 2003 were 20.4%, 24.2% and 21.2%, respectively. Other Great Plains Energy’s nonutility property includes Strategic Energy’s depreciable assets, which are primarily software costs and are amortized over a shorter period, three years, resulting in a higher annual depreciation rate.
 
As part of the 2004an acquisition of an additional interest in Strategic Energy, IEC recorded intangible assets that havewith finite lives and are subject to amortization.lives. These intangible assets include the fair value of acquired supply contracts, customer relationships and asset information systems whichthat are being amortized over 28, 72 and 44 months, respectively.  See Note 7An intangible asset for additional discussionthe fair value of the May 2004 acquisition of an additional indirect interest in Strategic Energy.
Depletion, depreciation and amortization of natural gas properties were calculated using the units of production method. After deciding to exit the gas business, the Company ceased recording depletion and as such, thereacquired supply contracts was no significant depletion recorded since 2003. The depletion per mmBtu was $2.78 in 2003.fully amortized at December 31, 2006. 
 
AccruedDeferred Refueling Outage Costs
KCP&L accrues anticipated incremental costsuses the deferral method to beaccount for operations and maintenance expenses incurred duringin support of the scheduled Wolf Creek refueling outages monthlyand amortizes them evenly (monthly) over the unit'sunit’s operating cycle normally theof 18 months precedinguntil the next scheduled outage. Estimated incrementalReplacement power costs which include operating, maintenance and replacement power expenses,during an outage 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.expensed as incurred.
 
Nuclear Plant Decommissioning Costs
Nuclear plant decommissioning cost estimates are based on the immediate dismantlement method and include the costs of decontamination, dismantlement and site restoration. Based on these cost estimates, KCP&L contributes to a tax-qualified trust fund to be used to decommission Wolf Creek.Creek Generating Station (Wolf Creek). Related liabilities for decommissioning are included on KCP&L’s balance sheet in Asset Retirement Obligations (AROs). As a result of the authorized regulatory treatment and related regulatory accounting, differences between the decommissioning trust fund asset and the related ARO are recorded as a regulatory asset or liability. See Note 16 for discussion of AROs including those associated with nuclear plant decommissioning costs.
72
Regulatory Matters
KCP&L, an integrated, regulated electric utility, is subject to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Pursuant to SFAS No. 71, KCP&L defers items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded if KCP&L were not regulated. See Note 56 for additional information concerning regulatory matters.
 
74
Revenue Recognition
KCP&L and Strategic Energy recognize revenues on sales of electricity when the service is provided. Revenues recorded include electric services provided but not yet billed by KCP&L and Strategic Energy. Unbilled revenues are recorded for kWh usage in the period following the customers’ billing cycle to the end of the month. The estimate is based on net system kWh usage less actual billed kWhs, adjusted for weather.kWhs. Estimated unbilled kWhs are allocated and priced by state across the rate classes based on the following month budget.
 
As a public utility, KCP&L collects from customers gross receipts taxes levied by state and local governments. These taxes are recorded gross in operating revenues and general taxes on Great Plains Energy’s and consolidated KCP&L’s consolidated statements of income. KCP&L’s gross receipts taxes collected were $34.1 million, $39.3 million and $37.6 million in 2006, 2005 and $38.3 million in 2005, 2004, and 2003, respectively.
 
Strategic Energy purchases blocks of electricity from power suppliers based on forecasted peak demand for its retail customers. Actual customer demand does not always equate to the volume included in blocks of purchased power.based on forecasted peak demand. Consequently, Strategic Energy sells any excess retail electricity supply over actual customer requirements back into the wholesale market. 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 $181.2$80.0 million, $158.5 million and $173.3 million in 2006, 2005 and $91.2 million in 2005, 2004, and 2003, respectively.
 
KCP&L and Strategic Energy record sale and purchase activity on a net basis in purchased power when RTO/ISO markets require them to sell and purchase power from the RTO/ISO rather than directly transact with suppliers and end-use customers.
KCP&L collects sales taxes from customers and remits to state and local governments. These taxes are presented on a net basis on Great Plains Energy’s and consolidated KCP&L’s statements of income.
 
Allowance for Doubtful Accounts
This reserve represents estimated uncollectible accounts receivable and is based on management’s judgment considering historical loss experience and the characteristics of existing accounts. Provisions for losses on receivables are charged to income to maintain the allowance at a level considered adequate to cover losses. Receivables are charged off against the reserve when they are deemed uncollectible.
 
Property Gains and Losses
Net gains and losses from the sales of assets, businesses and asset impairments are recorded in operating expenses.
 
Asset Impairments
Long-lived assets and finite lived intangible assets subject to amortization are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” SFAS No. 144 requires that if the sum of the undiscounted expected future cash flows from an asset to be held and used is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. The amount of impairment recognized is the excess of the carrying value of the asset over its fair value.
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Goodwill and indefinite lived intangible assets are tested for impairment at least annually and more frequently when indicators of impairment exist as prescribed under SFAS No. 142, “Goodwill and Other
75
Intangible Assets.” The annual test must be performed at the same time each year. SFAS No. 142 requires that if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, the implied fair value of the reporting unit goodwill would be compared with its carrying value. See Note 67 for additional information.
 
Income Taxes
In accordance with SFAS No. 109, “Accounting for Income Taxes,” Great Plains Energy has recognized deferred taxes for temporary book to tax differences using the liability method. The liability method requires that deferred tax balances be adjusted to reflect enacted tax rates that are anticipated to be in effect when the temporary differences reverse. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized.
 
Great Plains Energy and its subsidiaries file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss. In accordance with the Company’s intercompany tax allocation agreement, the holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive taxable income of each company in the consolidated federal or combined state returns. Consistent with its ratemaking treatment, KCP&L uses the separate return method, adjusted for the allocation of parent company tax benefits, to compute its income tax provision.
 
KCP&L has established a net regulatory asset for the additional future revenues to be collected from customers for deferred income taxes. Tax credits are recognized in the year generated except for certain KCP&L investment tax credits that have been deferred and amortized over the remaining service lives of the related properties.
 
Environmental Matters
Environmental costs are accrued when it is probable a liability has been incurred and the amount of the liability can be reasonably estimated.
 
Stock Options
The Company has an equity compensation plan, which is described more fully in Note 10. The Company adopted the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” for its stock options as of January 1, 2003. The Company elected to use the modified prospective method of adoption; therefore, stock option compensation cost recognized beginning January 1, 2003, was the same as if the fair value recognition provisions of SFAS No. 123 had been applied to all stock options granted after October 1, 1995.
In December 2004, FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” which the Company adopted as of January 1, 2006. Management determined that this statement will not have a significant impact on the Company’s results of operations or financial position.
Basic and Diluted Earnings per Common Share Calculation
There was no significant dilutive effect on Great Plains Energy’s EPS from other securities in 2005, 2004 and 2003. 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
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method, assumes the issuance of common shares applicable to stock options, performance shares, restricted stock, a forward sale agreement and FELINE PRIDES.PRIDESSM.
 
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The following table reconciles Great Plains Energy’s basic and diluted EPS from continuing operations.EPS.
          
      
As Adjusted
 
As Adjusted
 
    
2006
 
2005
 
2004
 
Income
        (millions, except per share amounts)
Income from continuing operations    $127.6 $164.2 $175.2 
Less: preferred stock dividend requirements     1.6  1.6  1.6 
Income available to common stockholders   $126.0 $162.6 $173.6 
Common Shares Outstanding
             
Average number of common shares outstanding     78.0  74.6  72.0 
Add: effect of dilutive securities     0.2  0.1  0.1 
Diluted average number of common shares outstanding 78.2  74.7  72.1 
Basic EPS from continuing operations
    $1.62 $2.18 $2.41 
Diluted EPS from continuing operations
   $1.61 $2.18 $2.41 
       
 
2005
 
2004
 
2003
 
Income
(millions, except per share amounts)
Income from continuing operations$164.2 $173.5 $189.7 
Less: preferred stock dividend requirements 1.6  1.6  1.6 
Income available to common stockholders$162.6 $171.9 $188.1 
Common Shares Outstanding
         
Average number of common shares outstanding 74.6  72.0  69.2 
Add: effect of dilutive securities 0.1  0.1  - 
Diluted average number of common shares outstanding 74.7  72.1  69.2 
          
Basic and diluted EPS from continuing operations
$2.18 $2.39 $2.72 
At December 31, 2005, there were 20,493The computation of diluted EPS excludes anti-dilutive shares applicable tofor 2006 of 96,601 performance shares and 116,469 restricted stock shares. The computation of diluted EPS excludes anti-dilutive shares for 2005 of 20,493 performance shares. At December 31,Additionally, for 2006, 2005 and 2004, 6.5 million of anti-dilutive FELINE PRIDES were excluded from the computation of diluted EPS and 2003, there were no anti-dilutive shares applicable to stock options performance shares or FELINE PRIDES.a forward sale agreement.
 
In February 2006,2007, 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 March 20, 2006,2007, to shareholders of record as of February 27, 2006.2007. The Board of Directors also declared regular dividends on Great Plains Energy’s preferred stock, payable June 1, 2006,2007, to shareholders of record as of May 10, 2006.2007.
 
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2.  
SUPPLEMENTAL CASH FLOW INFORMATION
 
Great Plains Energy Other Operating Activities
      
   
As Adjusted
 
As Adjusted
 
 
2006
 
2005
 
2004
 
Cash flows affected by changes in:(millions)
Receivables$(80.8)$6.6 $(37.5)
Fuel inventories (10.7) 4.9  1.8 
Materials and supplies (2.8) (2.6) 2.2 
Accounts payable 68.1  12.4  9.6 
Accrued taxes (22.5) (23.1) 15.3 
Accrued interest 0.7  1.6  (1.0)
Deposits with suppliers -  0.1  0.8 
Deferred refueling outage costs (5.9) (4.0) 8.7 
Pension and postretirement benefit assets and obligations 3.6  8.4  (10.4)
Allowance for equity funds used during construction (5.0) (1.8) (2.1)
Proceeds from the sale of SO2 emission allowances
 0.8  61.0  0.3 
Proceeds from T-Locks -  12.0  - 
Other 5.7  20.1  (7.5)
Total other operating activities$(48.8)$95.6 $(19.8)
Cash paid during the period:         
Interest$67.7 $68.9 $84.1 
Income taxes$77.7 $84.4 $38.6 
Non-cash investing activities:         
Liabilities assumed for capital expenditures$38.7 $13.4 $- 
          
Consolidated KCP&L Other Operating Activities
      
     
As Adjusted
 
 
As Adjusted
 
 
 
2006
 
 
2005
 
 
2004
 
Cash flows affected by changes in: (millions)
Receivables$(44.7)$(8.5)$1.6 
Fuel inventories (10.7) 4.9  1.8 
Materials and supplies (2.8) (2.6) 2.2 
Accounts payable 52.4  16.3  1.8 
Accrued taxes (16.5) (17.2) (6.6)
Accrued interest 0.9  1.7  (2.0)
Deferred refueling outage costs (5.9) (4.0) 8.7 
Pension and postretirement benefit assets and obligations 0.7  4.6  (8.0)
Allowance for equity funds used during construction (5.0) (1.8) (2.1)
Proceeds from the sale of SO2 emission allowances
 0.8  61.0  0.3 
Proceeds from T-Locks -  12.0  - 
Other (8.6) 12.9  (1.5)
Total other operating activities$(39.4)$79.3 $(3.8)
Cash paid during the period:         
Interest$57.9 $57.6 $73.8 
Income taxes$70.9 $104.1 $64.9 
Non-cash investing activities:         
Liabilities assumed for capital expenditures$38.2 $12.8 $- 
          
Great Plains Energy Other Operating Activities
       
  
2005
2004
2003
Cash flows affected by changes in: (millions) 
   Receivables $6.6 $(37.5)$(15.6)
   Fuel inventories  4.9  1.8  (0.8)
   Materials and supplies  (2.6) 2.2  (5.8)
   Accounts payable  
12.4
  
9.6
  17.0 
   Accrued taxes  (23.1) 
15.3
  25.5 
   Accrued interest  1.6  (1.0) (4.5)
Accrued refueling outage costs  (4.2) 11.4  (6.5)
Pension and postretirement benefit assets and obligations  8.4  (10.4) (20.6)
Allowance for equity funds used during construction  (1.8) (2.1) (1.4)
Proceeds from the sale of SO2 emission allowances
  61.0  0.3  0.2 
Proceeds from T-Locks  12.0  -  - 
Other  17.7   (8.5) 33.4 
      Total other operating activities $92.9 $(18.9)$20.9 
Cash paid during the period:          
   Interest $68.9 $84.1 $78.0 
   Income taxes $84.4 $38.6 $42.4 
Consolidated KCP&L Other Operating Activities
       
  
2005
2004
2003
Cash flows affected by changes in: (millions) 
   Receivables $(8.5)$1.6 $(2.9)
   Fuel inventories  4.9  1.8  (0.8)
   Materials and supplies  (2.6) 2.2  (5.8)
   Accounts payable  16.3  1.8  7.8 
   Accrued taxes  (17.2) (6.6) (2.8)
   Accrued interest  1.7  (2.0) (3.7)
Accrued refueling outage costs  (4.2) 11.4  (6.5)
Pension and postretirement benefit assets and obligations  4.6  (8.0) (20.3)
Allowance for equity funds used during construction  (1.8) (2.1) (1.4)
Proceeds from the sale of SO2 emission allowances
  61.0  0.3  0.2 
Proceeds from T-Locks  12.0  -  - 
Other  12.8  (1.5) 11.6  
      Total other operating activities $79.0 $(1.1)$(24.6)
Cash paid during the period:          
   Interest $57.6 $73.8 $71.4 
   Income taxes $104.1 $64.9 $68.1 
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Discontinued Operations
In 2005, the companies changed the presentation of their 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 and retroactively revised the consolidated statements of cash flows for the years ended December 31, 2004 and 2003, as applicable.
      
Great Plains Energy
 
2004
 
2003
 
  (millions) 
Net cash flows from operating activities as previously reported $377.1 $366.7 
Change in net cash flows  (23.0) 20.4 
Net cash flows from operating activities as currently reported  354.1  387.1 
Net cash flows from investing activities as previously reported  (257.9) (104.3)
Change in net cash flows  23.5  (18.7)
Net cash flows from investing activities as currently reported  (234.4) (123.0)
Net cash flows from financing activities as previously reported  (106.3) (213.7)
Change in net cash flows  -  (1.5)
Net cash flows from financing activities as currently reported $(106.3)$(215.2)
        
    
Consolidated KCP&L
 
2003
 
  (millions) 
Net cash flows from operating activities as previously reported $281.4 
Change in net cash flows  1.2 
Net cash flows from operating activities as currently reported  282.6 
Net cash flows from investing activities as previously reported  (132.4)
Change in net cash flows  - 
Net cash flows from investing activities as currently reported  (132.4)
Net cash flows from financing activities as previously reported  (122.6)
Change in net cash flows  (1.5)
Net cash flows from financing activities as currently reported $(124.1)
     
Significant Non-Cash Items
Asset Retirement Obligations
In 2006, Wolf Creek Nuclear Operating Corporation (WCNOC) submitted an application to the Nuclear Regulatory Commission (NRC) for a new operating license for Wolf Creek, which would extend Wolf Creek’s operating period to 2045. Due to the effect of computing the present value of the asset retirement obligation (ARO) at the end of the extended operating period, 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 was established to recognize funding of the related decommissioning trust 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 2006 cash flows.
During 2005, KCP&L recorded AROs totaling $26.7 million, increased net utility plant by $13.0 million and increased regulatory assets by $13.7 million. This activity had no impact on Great Plains Energy and consolidated KCP&L’s 2005 net income and had no effect on 2005 cash flows. See Note 16 for additional information.
 
During 2003, KCP&LUnrecognized Pension Expense
In December 2006, the Company adopted SFAS No. 143, “Accounting158, “Employers’ Accounting for AssetDefined Benefit Pension and Other Post Retirement Obligation,Plans.” and accordingly, recorded AROs totaling $99.2 million, reversedSee Note 8 for the decommissioning liabilityeffect of $64.6 million previously accrued and increased net utility plant by $18.3 million. The $16.3 million net cumulative effect was recorded as a regulatory asset and therefore, had no impact on net income.applying SFAS No. 158 to the Company’s balance sheet at December 31, 2006. The adoption of SFAS No. 143158 had no effect on Great Plains Energy and consolidated KCP&L’s 2003 cash flows.
FIN No. 46
KCP&L consolidated a lease trust and de-consolidated KCPL Financing I in 2003, as required by FASB Interpretation (FIN) No. 46, “Consolidation of Variable Interest Entities,” as amended. As a result of the consolidation of the lease trust, Great Plains Energy’s and consolidated KCP&L’s long-term debt increased $143.8 million. The consolidation of the lease trust had no effectimpact on Great Plains Energy’s and consolidated KCP&L’s 2003 cash flows. See Note 13 for additional information concerning the consolidation of the lease trust.
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Prior to the de-consolidation of KCPL Financing I, Great Plains Energy and consolidated KCP&L reflected $150 million of 8.3% preferred securities issued by KCPL Financing I on their respective balance sheets. As a result of the de-consolidation, Great Plains Energy’s and consolidated KCP&L’s other nonutility property and investments increased $4.6 million representing the investment in the common securities of KCPL Financing I, and long-term debt increased $154.6 million representing the 8.3% Junior Subordinated Deferrable Interest Debentures issued by KCP&L and held by KCPL Financing I. The de-consolidation of KCPL Financing I had no effect on Great Plains Energy’s and consolidated KCP&L’s 20032006 cash flows.
 
Minimum Pension Liability
The Company reduced its minimum pension liability $9.9 million primarily due to an increase in the market value of plan assets. This was offset by a $1.2 million reduction of an intangible asset and OCI of $8.7 million ($4.9 million net of tax) in 2005. In 2004, primarily as a result of lower discount rates and historical losses in the market value of plan assets, the Company recorded an additional minimum pension liability of $5.8 million and a reduction to an intangible asset of $1.8 million offset by OCI of $7.6 million ($5.1 million net of tax). Recording the minimum pension liabilities had no effect on Great Plains Energy’s and consolidated KCP&L’s cash flows.
RSAE Disposition
In 2003, HSS completed the disposition of its interest in RSAE. See Note 8 for additional information concerning the disposition of RSAE. The following table summarizes Great Plains Energy’s and consolidated KCP&L’s loss from discontinued operations as a result of this transaction.
   
 
2003
 (millions)
Cash repayment of supported bank line$(22.1)
Write-off of intercompany balance and investment 4.8 
Accrued transaction costs (1.6)
Income tax benefit 11.8 
Loss on disposition (7.1)
Pre-disposition operating losses (1.6)
Discontinued operations$(8.7)
DTI Bankruptcy
The following table summarizes Great Plains Energy’s gain on the sale of DTI assets. See Note 15 for a KLT Telecom related legal proceeding.
   
DTI
2003
 (millions)
Cash proceeds from bankruptcy estates$19.2 
Cash proceeds from sale of office building 1.2 
Receivables 1.3 
Total proceeds 21.7 
Book basis of office building sold (2.7)
DIP financing accrual reversal 5.0 
Accounts payable (1.9)
Income tax (9.8)
Reversal of tax valuation allowance 15.8 
Gain on sale of assets$28.1 
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3.  
RECEIVABLESANTICIPATED ACQUISITION OF AQUILA, INC.

On February 7, 2007, Great Plains Energy entered into an agreement to acquire Aquila, Inc. (Aquila). Immediately prior to Great Plains Energy’s acquisition of Aquila, Black Hills Corporation will acquire Aquila’s electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa plus associated liabilities for a total of $940 million in cash, subject to closing adjustments. Each of the two transactions is conditioned on the completion of the other transaction and is expected to close in 2008. Following closing, Great Plains Energy will own Aquila and its Missouri-based utilities consisting of the Missouri Public Service and St. Joseph Light & Power divisions as well as Aquila’s merchant service operations, which primarily consists of the 340MW Crossroads power generating facility and residential natural gas contracts.
Great Plains Energy will acquire all outstanding shares of Aquila for $1.80 in cash plus 0.0856 of a share of Great Plains Energy common stock for each share of Aquila common stock in a transaction valued at approximately $1.7 billion, or $4.54 per share, based on Great Plains Energy’s closing stock price on February 6, 2007. In addition, Great Plains Energy will assume approximately $1 billion of Aquila’s debt. The proceeds from the asset sale to Black Hills Corporation will be used to fund the cash portion of the consideration to Aquila shareholders and to reduce existing Aquila debt.
Great Plains Energy’s acquisition of Aquila was unanimously approved by both Great Plains Energy’s and Aquila’s Boards of Directors and is subject to the approval of both Great Plains Energy and Aquila shareholders; regulatory approvals from the Public Service Commission of the State of Missouri (MPSC), The State Corporation Commission of the State of Kansas (KCC), and FERC; Hart-Scott-Rodino antitrust review; as well as other customary conditions.
The transaction will add about 300,000 electric utility customers and approximately 1,800 MW of generating capacity. Aquila is a partner with KCP&L in the jointly owned generating units Iatan Nos. 1 and 2, owning 18% of each Iatan generating unit. Direct costs of the acquisition incurred by Great
79
Plains Energy of $2.8 million at December 31, 2006, are deferred and will be included in purchase accounting treatment upon consummation of the acquisition.
4.  RECEIVABLES
 
The Company’s receivables are detailed in the following table.
    
  
December 31
 
  
2006
 
2005
 
Consolidated KCP&L
 (millions) 
Customer accounts receivable (a)
 $35.2 $34.0 
Allowance for doubtful accounts  (1.1) (1.0)
Other receivables  80.2  37.3 
Consolidated KCP&L receivables  114.3  70.3 
Other Great Plains Energy
       
Other receivables  229.2  193.0 
Allowance for doubtful accounts  (4.1) (4.3)
Great Plains Energy receivables $339.4 $259.0 
 (a)Customer accounts receivable included unbilled receivables of $32.0 million and $31.4
     million at December 31, 2006 and 2005, respectively.
     
 
December 31
 
2005
 2004
Consolidated KCP&L
(millions) 
Customer accounts receivable (a)
$34.0 $21.6 
Allowance for doubtful accounts (1.0) (1.7)
Other receivables 37.3  43.5 
    Consolidated KCP&L receivables 70.3  63.4 
Other Great Plains Energy
      
Other receivables 193.0  188.5 
Allowance for doubtful accounts (4.3) (4.7)
    Great Plains Energy receivables$259.0 $247.2 
(a) Customer accounts receivable included unbilled receivables of $31.4
million and $31.2 million at December 31, 2005 and 2004, respectively.
Consolidated KCP&L’s other receivables at December 31, 2006 and 2005, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables. At December 31, 2004, the balance consisted primarily of receivables from partners in jointly owned electric utility plants, wholesale sales receivables and accounts receivable held by Worry Free. Great Plains Energy’s other receivables at December 31, 2005,2006 and December 31, 2004,2005, consisted primarily of accounts receivable held by Strategic Energy, including unbilled receivables of $99.9$95.0 million and $103.0$99.9 million, respectively.
 
During 2005, KCP&L entered into a new three-year revolving agreement to sellsells all of its retail electric accounts receivable to its wholly owned subsidiary, Kansas City Power & Light Receivables Company, (Receivables Company), which in turn soldsells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor. In accordance with SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,” the agreements qualify as a sale under which the creditors of Receivables Company are entitled to be satisfied out of the assets of Receivables Company prior to any value being returned to KCP&L or its creditors. Accounts receivable sold by Receivables Company to the outside investor under this revolving agreement totaled $70 million at December 31, 2005. The proceeds of this sale were forwarded to KCP&L as consideration for its sale. The new agreement allows for a maximum outstanding principal amount sold to the outside investor of $100 million during the period June 1 through October 31, and $70 million during the period November 1 through May 31 of each year.
Under the agreement, 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 sincebecause management determined the collection agent fee earned by KCP&L approximates market value.
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Information regarding KCP&L’s sale of accounts receivable to Receivables Company under the new agreement is reflected in the following table.
tables.
       
   
Receivables
Consolidated
2005
KCP&L
Company
KCP&L
 (millions)
Receivables (sold) purchased$(605.8)$535.8 $(70.0)
Collections 499.3  (499.3) - 
(Gain) loss on sale of accounts receivable (a)
 6.0  (5.0) 1.0 
Servicing fees 1.4  (1.4) - 
Fees to outside investor -  (1.5) (1.5)
          
Cash flows during the period
         
Cash proceeds from sale of receivables (b)
$569.3 $(499.3)$70.0 
Servicing fees 1.4  (1.4) - 
(a) The net 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 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.
        
    
Receivables
 
Consolidated
 
2006
 
KCP&L
 
Company
 
KCP&L
 
  (millions) 
Receivables (sold) purchased $(977.9)$977.9 $- 
Gain (loss) on sale of accounts receivable (a)
  (9.9) 9.9  - 
Servicing fees  2.9  (2.9) - 
Fees to outside investor  -  (3.8) (3.8)
Cash flows during the period
          
Cash from customers transferred to          
Receivables Company  (980.7) 980.7  - 
Cash paid to KCP&L for receivables purchased  974.6  (974.6) - 
Servicing fees  2.9  (2.9) - 
Interest on intercompany note  2.4  (2.4) - 
 
KCP&L had a revolving agreement, which expired in January 2005, to sell all of its right, title and interest in the majority of its customer accounts receivable to Receivables Company, which in turn sold most of the receivables to independent outside investors. The expired agreement was structured as a true sale under which the creditors of Receivables Company were entitled to be satisfied out of the assets of Receivables Company prior to any value being returned to KCP&L or its creditors. Accounts receivable sold under the expired revolving agreement totaled $84.9 million at December 31, 2004. As a result of the sale to the outside investors, Receivables Company received up to $70 million in cash, which was forwarded to KCP&L as consideration for its sale. At December 31, 2004, Receivables Company had received $65.0 million in cash.
           
     
Receivables
  
Consolidated
 
2005
  
KCP&L
 
 
Company
 
 
KCP&L
 
   (millions) 
Receivables (sold) purchased $(599.7)$599.7 $- 
Gain (loss) on sale of accounts receivable (a)
  (6.0) 5.0  (1.0)
Servicing fees  1.4  (1.4) - 
Fees to outside investor  -  (1.4) (1.4)
Cash flows during the period
       
Cash from customers transferred to       
Receivables Company  (499.3) 499.3  - 
Cash paid to KCP&L for receivables purchased  (494.3) 494.3  - 
Servicing fees  1.4  (1.4) - 
Funds from outside investors (b)
  70.0  -  70.0 
Interest on intercompany note  0.9  (0.9) - 
Information regarding KCP&L’s sale of accounts receivable to Receivables Company under the expired agreement is reflected in the following table.
       
 
2005
2004
2003
Gross proceeds on sale of(millions)
    accounts receivable$46.1 $929.1 $939.5 
Collections 44.3  928.0  949.5 
Loss on sale of accounts receivable -  2.5  3.7 
Late fees 0.1  2.2  2.3 
(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 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. 

4.5.  
NUCLEAR PLANT
 
KCP&L owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC),WCNOC, the operating company for Wolf Creek, Generating Station (Wolf Creek), its only nuclear generating unit. Wolf Creek is regulated by the Nuclear Regulatory Commission (NRC),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
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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, no later than June 30, 2008. The DOE is currentlyalso announced that if requested legislative changes are enacted, the repository could be able to accept spent nuclear fuel and high-level waste starting in the process of preparing an application to obtain the NRC license to proceed with construction of the repository.early
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2017. Management cannot predict when this site may be available.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 oldestolder spent fuel. Wolf Creek has completed an on-site storage facility that is designed to hold all spent fuel generated at the plant through 2025. If the endDOE meets its revised timetable for accepting spent fuel for disposal by 2017, management expects that the DOE could begin accepting some of Wolf Creek’s spent fuel by 2025. Management can make no assurance that the DOE will meet its 40-year licensed life in 2025.revised timetable and will continue to monitor this activity. See Note 15 for a related legal proceeding.
 
Nuclear Plant Decommissioning Costs
The Public Service Commission of the State of Missouri (MPSC)MPSC and The State Corporation Commission of the State of Kansas (KCC)KCC require KCP&L and the other owners of Wolf Creek to submit an updated decommissioning cost study every three years and to propose funding levels.
The most recent study was submitted to the MPSC and KCC in 2005 and is the basis for the current cost of decommissioning estimates in the following table. The MPSC issued an order effective January 20,In December 2006, continuing the Missouri jurisdictional funding at the previously ordered level. The MPSC order did not explicitly approve or disapprove the 2005 decommissioning cost study submitted by KCP&L. The KCC has not yet ruled on the study but has set a procedural schedule in 2006 to address it.
The Missouri funding schedule previously approved by&L received orders from the MPSC assumes funding throughand KCC, approving the expiration of Wolf Creek’s current NRC operating license (2025). In 2005, the MPSC order regarding the comprehensive energy plan increased Wolf Creek’s depreciable life for Missouri regulatory purposes from 40 to 60 years and assumes funding through 2045. The Kansas funding schedule previously approved by KCC assumes that Wolf Creek will be granted a 20-year license extension and, thus, assumes funding through 2045. WCNOC has filed with the NRC a letter of intent to file an application for a license extension. Management anticipates that WCNOC will file that application with the NRC in 2006. As such, it is likely that any future decommissioning cost study and funding levels will be based on the assumed extended life.
Nuclear decommissioning cost and the associated nuclear decommissioning trust funding levels were addressed in the general rate cases filed in February 2006. KCP&L proposed cost estimates, assumptions and related funding schedules for nuclear plant decommissioning in its general rate cases as provided inthis cost estimate based on an anticipated extension of the following table. KCP&L’s proposal will be considered by the MPSC and KCC; however, the outcome could differ from the proposal.
operating period to 2045.
     
 
Total
KCP&L's
 
Station
47% Share
 (millions)
Current cost of decommissioning (in 2005 dollars)$518 $243 
Future cost of decommissioning (in 2045 dollars) 2,897  1,362 
       
Annual escalation factor4.40%
Annual return on trust assets (a)
6.48%
(a) The 6.48% rate of return is thru 2025. The rate then systematically decreases
through 2045 to 4.04% based on the assumption that the fund's investment mix
will become increasingly more conservative as the decommissioning date
approaches.
     
   
 Total
 
KCP&L's
   
Station
 
47% Share
   (millions)
Current cost of decommissioning (in 2005 dollars) $ 518 $ 243
Future cost of decommissioning (in 2045-2053 dollars) (a)
3,327 1,564
 
Annual escalation factor 4.40%
Annual return on trust assets (b)
 6.48%
(a) 
Total future cost over an eight year decommissioning period.  
(b) 
The 6.48% rate of return is thru 2025. The rate then systematically decreases through 2053 to
 2.82% based on the assumption that the fund's investment mix will become increasingly more
 conservative as the decommissioning period approaches. 
KCP&L currently contributes approximately $3.6$3.7 million annually to a tax-qualified trust fund to be used to decommission Wolf Creek. If KCP&L’s proposal is accepted by the MPSC and KCC, total annual funding would not change. Amounts funded are charged to other operating expense and recovered in billings to customers.customers’ rates. If the actual return on trust assets is below the anticipated level, management
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believes a rate increase would be allowed ensuring full recovery of decommissioning costs over the remaining life of the station.
 
The following table summarizes the change in Great Plains Energy’s and consolidated KCP&L’s decommissioning trust fund.
     
December 31
2006
 
2005
 
Decommissioning Trust
(millions) 
Beginning balance$91.8 $84.1 
Contributions 3.7  3.6 
Realized gains 6.0  3.9 
Unrealized gains 2.6  0.2 
Ending balance$104.1 $91.8 
     
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December 31
2005
2004
Decommissioning Trust
(millions)
Beginning balance$84.1 $75.0 
Contributions 3.6  3.6 
Realized gains 3.9  3.6 
Unrealized gains 0.2  1.9 
    Ending balance$91.8 $84.1 
The decommissioning trust is reported at fair value on the balance sheets and is invested in assets as detailed in the following table.
     
  
December 31
Asset Category
 
2006
 
2005
Equity securities 43% 48%
Debt securities 54% 46%
Other 3% 6%
Total 100% 100%
     
  
December 31
Asset Category
 
2005
 
2004
Equity securities 48% 46%
Debt securities 46% 50%
Other 6% 4%
    Total 100% 100%
Nuclear Liability and Insurance
The owners of Wolf Creek a nuclear generating station, (Owners) maintain nuclear insurance for Wolf Creek in fourthree areas: nuclear liability, worker radiation,nuclear 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%
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share) per incident per year effective with the Energy Policy Act of 2005.year. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. This assessment is in addition 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.
 
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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 $26.5$26.1 million ($12.412.3 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.
 
On December 18, 1998,After many years of effort, Nebraska regulators denied the application for a license to construct this project was denied. After the license denial, WCNOC, the Compact Commission (Commission) and others filed a lawsuit in federal court contending Nebraska officials acted in bad faith while handling the license application. In September 2002, the U.S. District Court Judge presiding over the lawsuit issued his decision in the case finding that the State of Nebraska acted in bad faith in processing thefacility developer’s license application forin December 1998, a low-level radioactive waste disposal site inprolonged lawsuit ensued, and Nebraska and rendered a judgment on behalf of the Commission in the amount of $151.4 million against the state. After the U.S. Court of Appeals affirmed the decision, Nebraska and the Commissioneventually settled the case by Nebraska agreeing to paypaying the Compact Commission a one-time amount of $145.8 million. At the requestmillion in damages. The Compact Commission then paid pro rata portions of the Commission,settlement money to the various parties who originally funded the project. To date, WCNOC along with other members of the Compact, filed with the Commission their claims for refund. In 2005, WCNOChas received a return of its investment of $19.6refunds totaling $21.3 million (KCP&L’s 47% share being $10 million), including $1.7 million ($9.20.8 million, KCP&L’s 47% share), including pre-judgment interest and attorney’s fees. received in 2006. The Compact Commission continues to explore alternative long-term waste disposal capability and has retained aan insignificant portion of the settlement abovemoney. 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 amounts retained amount plus interest. In January 2007, the court denied this claim stating the Compact Commission is still in existence, will continue to exist for the foreseeable future and has an arguable need for money.
Deferred Refueling Outage Costs
In September 2006, the 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. Management has elected to early adopt the provisions and accordingly has retrospectively adjusted prior periods. Prior to adoption, KCP&L utilized the accrue-in-advance method for incremental costs to be incurred during scheduled Wolf Creek refueling outages. KCP&L adopted the deferral method to account for operations and maintenance expenses incurred for scheduled refueling outages to be amortized evenly (monthly) over the unit’s operating cycle of 18 months until the next scheduled outage. Replacement power costs during the outage will be expensed as incurred.
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returned, until it determines what role it will take in the developmentThe overall impact to Great Plains Energy’s and consolidated KCP&L’s consolidated statements of alternative disposal capability. In February 2006, the Commission decidedincome was no change to refund an additional2005 net income or earnings per share and a $1.7 million ($0.8 million, KCP&L’s 47% share) to WCNOC.increase in 2004 net income, or $0.02 per share. The remaining insignificant amount will be retainedfollowing line items within the consolidated statements of income were impacted by the Commission for future operations. At December 31,change.
      
  
As
     
As
     
  
Originally
     
Originally
     
  
Reported
 
As
 
Effect of
 
Reported
 
As
 
Effect of
 
  
2005
 
Adjusted
 
Change
 
2004
 
Adjusted
 
Change
 
Great Plains Energy
 (millions) 
Fuel $207.9 $208.4 $0.5 $179.4 $176.8 $(2.6)
Other  327.7  327.7  -  324.2  323.6  (0.6)
Maintenance  90.3  90.0  (0.3) 83.6  84.1  0.5 
Income taxes  (39.7) (39.5) 0.2  (54.5) (55.5) (1.0)
Consolidated KCP&L
          
Fuel $207.9 $208.4 $0.5 $179.4 $176.8 $(2.6)
Other  265.7  265.7  -  259.7  259.1  (0.6)
Maintenance  90.3  90.0  (0.3) 83.5  84.0  0.5 
Income taxes  (48.2) (48.0) 0.2  (52.8) (53.8) (1.0)
              
The overall impact to Great Plains Energy’s and consolidated KCP&L’s 2005 KCP&L’s balance sheet no longer reflectswas an investmentincrease in retained earnings of $10.6 million. For Great Plains Energy, this was a result of an increase in current and total assets of $8.1 million for the Compact.addition of deferred refueling outage costs and a decrease in current and total liabilities of $2.5 million for the elimination of accrued refueling outage costs (net of a $6.4 million increase in deferred income taxes). For consolidated KCP&L's net investment&L, this was a result of an increase in current and total assets of $1.7 million for the Compact was $7.4addition of deferred refueling outage costs (net of a $6.4 million at December 31, 2004.
decrease in deferred income taxes) and a decrease in current and total liabilities of $8.9 million for the elimination of accrued refueling outage costs.
 
Wolf Creek continuesAs a result of the accounting change, Great Plains Energy’s retained earnings as of January 1, 2005, increased to dispose$462.1 million and consolidated KCP&L’s retained earnings increased to $263.5 million. There were no overall impacts to the 2005 and 2004 statements of its low-level radioactive waste at the reopened disposal facility at Barnwell, South Carolina. South Carolina intends to gradually decrease the amount of waste it allows from outside its compact until around 2008 when it intends to no longer accept waste from generators outside its compact. Wolf Creek remains able to dispose of some of its radioactive waste at a facility in Utah. Although management is unable to predict when a permanent disposal facilitycash flows for Wolf Creek low-level radioactive waste might become available, this issue is not expected to affect continued operation of Wolf Creek.Great Plains Energy and consolidated KCP&L.
 
5.6.  
REGULATORY MATTERS
 
KCP&L’s Comprehensive Energy Plan
KCP&L continues to make progress in implementing its comprehensive energy plan andunder orders received orders from the MPSC and KCC in 2005. The orders were on agreements reached among KCP&L, the Commissions’ staffs and certain key parties in the respective jurisdictions. The Sierra Club and Concerned Citizens of Platte County have appealed the MPSC order, and the Sierra Club has appealed the KCC order. These appeals are expectedIn March 2006, the Circuit Court of Cole County, Missouri, affirmed the MPSC order and the Sierra Club has appealed the decision to be decidedthe Missouri Court of Appeals. The Kansas District Court denied the Sierra Club’s appeal in 2006.May 2006 and the Sierra Club has appealed to the Kansas Court of Appeals. Although subject to thesethe appeals, the MPSC and KCC orders remain in effect pending the applicable court’s decision.
 
·  KCP&L will make energy infrastructure investments as detailed in the orders and summarized in the table below.
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Estimated
    
Capital
Project
 
Details
Expenditures
    (millions)
Iatan No. 2 (a)
 Building and owning 465 MW of an 850 MW coal fired   
       plant with an estimated completion date of June 2010 $ 733 
Wind Generation Installation of 100.5 MW of wind generation in 2006 166 
Environmental Retrofit of selected existing coal plants 272 
Asset Management Enhanced system performance and reliability 42 
Customer Programs Various demand management, distributed generation and   
       efficiency programs 53 
Total (b)
  
$
1,266
 
(a)
MW based on current estimates.   
(b)
These amounts are estimates. Because of the magnitude of these investments and the length of time
 to implement the comprehensive energy plan, actual expenditures may differ from these estimates.
During 2006, KCP&L entered into certain procurement and engineering agreements for comprehensive energy plan projects, and further refined its cost estimates and schedules as contracting and engineering progressed. The following table summarizes the comprehensive energy plan estimated capital expenditures.
·  
Ownership agreements are being finalized with Iatan No. 2 partners. KCP&L has awarded a contract for detailed engineering design services and project and construction management support. Detailed project engineering and design has begun and plant construction is expected to start in 2006. KCP&L has received an air permit from the Missouri Department of Natural Resources, which is being appealed by the Sierra Club. KCP&L anticipates issuances of a wetlands permit, a permit for the construction of a temporary barge slip and an Environmental Assessment with a finding of No Significant Impact toward mid-year 2006.
      
   
Estimated
   
Capital
Project
 
Expenditures (a)
   (millions)
Iatan No. 2 (b)
 $ 837-$ 914
 
Environmental Retrofit Projects (c)
    423-443
 
Wind Generation(d)
 164
 
Asset Management 42
 
Customer Programs 53
      
Total $1,519-$1,616
(a)
KCP&L share of costs, exclusive of AFDC.   
(b)
KCP&L's 54.71% ownership (approximately 465MW) of an estimated 850MW plant.
(c)
These projects are the Iatan No. 1 air quality control project, the LaCygne No. 1 selective catalytic reduction project and baghouse and scrubber project.
 
(d)
The Spearville Wind Energy Facility went into service in September 2006.
 
The cost estimates for Iatan No. 2 and the environmental retrofits include a range for contingencies on those projects that reflect, among other factors, the current level of contracting. Specific comprehensive energy plan project management and other risk mitigation practices result in varying uncertainty and therefore a range of contingency allowance has been provided. The upper end of each range reflects a contingency allowance that management believes is consistent with industry practice and market conditions for projects of these types, sizes and degree of completion.
Because of the magnitude of the comprehensive energy plan projects and the length of the implementation period, the actual expenditures, scope and timing of any or all of these projects that have not been completed may differ materially from these estimates.
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 requests were based on a return on equity of 11.5% and an adjusted equity ratio of 53.8%. KCP&L received rate orders from the MPSC and KCC in December 2006. The ordered rates were implemented January 1, 2007.
·  
KCP&L has selected a developer and contractor for the construction of a 100.5 MW wind project in Kansas. Construction will begin in the first half of 2006 and management expects the project
The MPSC ordered an approximate $51 million increase in annual revenues effective January 1, 2007, reflecting an authorized return on equity of 11.25%. Approximately $22 million of the rate increase results from additional amortization to help maintain cash flow levels. The MPSC order established, for regulatory purposes, annual pension cost recovery for the period beginning January 1, 2007, of approximately $19 million on a Missouri jurisdictional basis, after allocations to the other joint owners of generation facilities and capitalized amounts, through the creation of a regulatory asset or liability. The order also established, effective January 1, 2006, a regulatory asset or liability as appropriate for amounts 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.  
 
8486
to be completed in time for inclusion in rates in 2007. The orders also include the possible addition of another 100 MW of wind generation in 2008 if supported by a detailed evaluation.
·  KCP&L has awarded a contract to install a Selective Catalytic Reduction (SCR) system at LaCygne No. 1 scheduled for completion in May 2007. Additional environmental upgrades at LaCygne No. 1 are scheduled for 2009. Other planned environmental investments include a similar SCR upgrade and the addition of a wet scrubber and baghouse at Iatan No. 1 expected to be completed in 2008.
·  Several demand management efficiency and affordability programs are being implemented to help customers manage usage and costs including online energy analysis, air conditioner cycling and low-income weatherization.
·  KCP&L’s current rates will remain in place until 2007 in accordance with the orders. On February 1, 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 are for recovery of increasing operating costs including fuel, transportation and pensions as well as investments in wind generation and customer programs. The request is based on a return on equity of 11.5% and an adjusted equity ratio of 53.8%. KCP&L anticipates that approved rate adjustments will go into effect January 1, 2007. The last rate case required by the orders is expected to be filed in 2009, with rates effective near the time Iatan No. 2 is placed in service. Two additional rate cases could be filed in 2007 and 2008 at KCP&L’s discretion.
·  The KCC order allows KCP&L to request recovery, on a dollar-for-dollar basis with no profit to the company, of actual fuel and purchased power expense incurred through an energy cost adjustment. Similarly, an interim energy charge, based on forecasted costs and subject to customer refund, is contained in the MPSC order. The rate requests filed with the MPSC and KCC on February 1, 2006, do not include the fuel clauses; however, fuel clauses still could be proposed and implemented based on developments during the proceedings.
·  
KCP&L may sell SO2 emission allowances during the term of the orders. The sales proceeds are recorded as a regulatory liability for ratemaking purposes and will be amortized in accordance with the last rate case filed under the orders. In 2005, KCP&L sold $60.3 million of SO2 emission allowances.
·  The rate increase requests filed with the MPSC and the KCC on February 1, 2006, include pension costs of approximately $46 million calculated consistently with the methodology established in the orders. The orders established KCP&L’s annual pension costs for regulatory purposes at $22 million until 2007 through the creation of regulatory assets or liabilities, as appropriate. See Note 9 for additional information.
·  Wolf Creek’s depreciable life for Missouri regulatory purposes has been increased from 40 to 60 years. The MPSC order calls for $10.3 million, on an annual jurisdictional basis, of additional amortization expense to be recorded to offset the reduction in depreciation expense due to the change in depreciable life. The 60-year Missouri depreciable life matches the current Kansas regulatory depreciable life. In 2005, KCP&L began recording depreciation and amortization expense in accordance with the order.
·  
The orders are intended to provide KCP&L with regulatory mechanisms to be able to recover the prudent costs of its investments as they are placed in service and an ability to maintain targeted credit ratios over the five-year term of the orders.
The orders provide regulatory clarity on certain items; however, normal regulatory risk will continue to exist as the commissions establish rates in the rate cases, including, but not limited to, the actual amount of costs to be recovered through rates, the return on equity, the capital structure utilized and expenses to be recovered.
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The KCC ordered a $29 million increase in annual revenues effective January 1, 2007, including $4 million of accelerated depreciation to maintain cash flow levels.  The KCC order 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 ordered rates were implemented January 1, 2007. The KCC order established, for regulatory purposes, annual pension costs beginning January 1, 2007, of approximately $19 million on a Kansas jurisdictional basis through the creation of a regulatory asset or liability. The order also established, effective January 1, 2006, a regulatory asset or liability as appropriate for amounts 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.
See Regulatory Assets and Liabilities below for information regarding various regulatory assets established at December 31, 2006, in accordance with these rate orders.
Regulatory Assets and Liabilities
KCP&L is subject to the provisions of SFAS No. 71 and has recorded assets and liabilities on its balance sheet resulting from the effects of the ratemaking process, which would not otherwise be recorded under GAAP for non-regulated entities.GAAP. Regulatory assets represent incurred costs incurred that have been deferred becauseare probable of recovery from future recovery in customer rates is probable.revenues. Regulatory liabilities generally represent probable future reductions in revenue oramounts imposed by rate actions of KCP&L’s regulators that may require refunds to customers.customers, represent amounts provided in current rates that are intended to recover costs that are expected to be incurred in the future for which KCP&L remains accountable, or represent a gain or other reduction of allowable costs to be given to customers over future periods. Future recovery of regulatory assets is not assured, but is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Future reductions in revenue or refunds for regulatory liabilities generally are not mandated, pending future rate proceedings or actions by the regulators. Management regularly assesses whether regulatory assets and liabilities are probable of future recovery or refund by considering factors such as decisions by the MPSC, KCC or FERC on KCP&L’s rate case filings; decisions in other regulatory proceedings, including decisions
related to other companies that establish precedenceprecedent on matters applicable to KCP&L; and changes in laws and regulations. If recovery or refund of regulatory assets or liabilities is not approved by regulators or is no longer deemed probable, these regulatory assets or liabilities are recognized in the current period results of operations. KCP&L’s continued ability to meet the criteria for application of SFAS No. 71 may be affected in the future by restructuring and deregulation in the electric industry. In the event that SFAS No. 71 no longer applied to a deregulated portion of KCP&L’s operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment of utility plant assets if the cost of the assets could not be expected to be recovered in customer rates. Whether an asset has been impaired is determined pursuant to the requirements of SFAS No. 144.
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December 31
 
  
2006
 
2005
 
Regulatory Assets
 (millions) 
Taxes recoverable through future rates $81.7 $85.7 
Decommission and decontaminate federal uranium       
enrichment facilities  0.6  1.3 
Loss on reacquired debt  6.4  7.1 
January 2002 incremental ice storm costs (Missouri)  0.4  4.9 
Change in depreciable life of Wolf Creek  45.4  27.4 
Cost of removal  8.2  9.3 
Asset retirement obligations  16.9  23.6 
Pension and post-retirement costs  256.9  15.6 
Surface Transportation Board litigation expenses  1.7  - 
Deferred customer programs  5.9  0.3 
2006 rate case expenses  2.6  0.2 
Other  7.7  4.5 
Total $434.4 $179.9 
Regulatory Liabilities
       
Emission allowances $64.5 $64.3 
Pension costs  -  1.0 
Asset retirement obligations  35.6  - 
Additional Wolf Creek amortization (Missouri)  14.6  4.3 
Total $114.7 $69.6 
        
       
 
Amortization
December 31
 
ending period
2005
2004
Regulatory Assets
  (millions)
Taxes recoverable through future rates   $85.7 $81.0 
Decommission and decontaminate federal uranium         
  enrichment facilities 2007  1.3  2.0 
Loss on reacquired debt 2037  7.1  7.7 
January 2002 incremental ice storm costs (Missouri) 2007  4.9  9.5 
Change in depreciable life of Wolf Creek 2045  27.4  15.5 
Cost of removal    9.3  13.9 
Asset retirement obligations    23.6  11.4 
Future recovery of pension costs    15.6  - 
Other Various  5.0  3.3 
     Total Regulatory Assets    $179.9   $144.3  
Regulatory Liabilities
         
Emission allowances   $64.3 $4.1 
Pension accounting method difference    1.0  - 
Additional Wolf Creek amortization (Missouri)   4.3  - 
   Total Regulatory Liabilities  $69.6 $4.1 
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.costs. 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 regulatory asset for pension and post-retirement costs at December 31, 2006, includes $25.0 million, net of related liabilities, for the adoption of SFAS No. 158 representing the difference between funding and expenses recognized of the pension and post-retirement plans that are not included in rate base. The regulatory asset for pension and post-retirement costs at December 31, 2006, includes $11.6 million of amounts arising from defined benefit plan settlements and curtailments that are not included in rate base to be amortized over a five-year period beginning with the effective date of rates approved in KCP&L’s next rate case. The regulatory asset for pension and post-retirement costs at December 31, 2006, includes $9.0 million representing an accounting method difference (which may be either a regulatory asset or liability) and certainis not included in rate base. Certain insignificant items in Regulatory Assets - Other are also not included in rate base.
Great Plains Energy and consolidated KCP&L recognized several new regulatory assets in accordance with the 2006 rate orders received from the MPSC and KCC including, but not limited to, amounts arising from defined benefit plan settlements and curtailments, litigation costs related to the KCP&L rate complaint case filed with the Surface Transportation Board (STB), deferred costs incurred in relation to various demand response, efficiency and affordability customer programs, and 2006 Missouri & Kansas rate case expenses.
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Southwest Power Pool Regional Transmission Organization
Under FERC Order 2000, KCP&L as an investor-owned utility, is strongly encouraged to join a FERC approved RTO. RTOs combine transmission operationsmember of utility businesses into regional organizations that schedule transmission services and monitor the energy market to ensure regional transmission reliability and non-discriminatory access. The Southwest Power Pool (SPP), of which is a FERC approved Regional Transmission Organization (RTO). In July 2006, KCC granted interim approval for KCP&L is a member, obtained approval from FERC as an RTO in a January 24, 2005, order.to take SPP network integration transmission service for its retail customers. During 2006, KCC and MPSC both issued orders approving KCP&L intends on participating&L’s participation in the SPP RTO, and during 2005, KCP&L filed applications withwhich also made final the MPSC andpreviously
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granted KCC seeking authorizationinterim approval. In May 2006, SPP made a compliance filing in response to participate ina previously issued FERC order on the SPP RTO. In these applications, KCP&L requested authorization be granted by May 1, 2006. In February 2006, KCP&L reached an agreement with the MPSC staff and interveners regarding interim approval to turn over functional control of KCP&L’s transmission facilities to the SPP RTO and participate in the energy imbalance market scheduled to start May 1, 2006. KCC has held workshops seeking additional information on the request to participate.
During 2005, a cost/benefit analysis was completed under the direction of the SPP Regional State Committee (composed of state commissioners from the states where the SPP RTO operates). The analysis indicates that implementation of an energy imbalance market within the SPP region would provide net benefits of approximately $373 million over a 10-year period to the transmission-owning members of the SPP RTO; however, there was no significant documented impact for KCP&L over the 10-year period. During 2005, SPP RTO filed its plans for the energy imbalance market with FERC. These plans include a May 1,service market. In July 2006, start date for the energy imbalance market. Subsequently, FERC issued an order on the compliance filing accepting in part, as modified, and rejecting this filing.in part the filing, permitting the start of the SPP RTO madeenergy 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. In December 2006, the SPP Board voted to file the certification of SPP’s market readiness for a revisedFebruary 1, 2007, start. FERC issued an order concerning the December market readiness filing on January 4,26, 2007. In this order, FERC accepted the market readiness filing and authorized the SPP to start the energy imbalance service market on February 1, 2007. KCP&L is participating in this market.
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, addressingFERC 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 issues. 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 have petitioned to appeal and move for further rehearing of the FERC order. Management is unable to predict the outcome of any appeals or further requests for rehearing.
 
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, LLC (PJM) and the Midwest Independent Transmission System Operator, Inc. (MISO)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 arewere allocated a portion of the SECA based on transmission services provided to that zone during 2002 and 2003.
In 2005, PJM and MISO began invoicing2006, Strategic Energy recorded a reduction of purchased power expense of $2.4 million for these charges, based on allocationsSECA recoveries from suppliers, which offset $2.7 million of expense recorded in compliance filings made by transmission owners and accepted by FERC, subject to refund and adjustment.the first quarter. During 2005, Strategic Energy recorded purchased power expenses totaling $13.6 million for these charges covering billings for theSECA transition period. The compliance filings allocate approximately $1 million of charges per month, through March 2006.charges. Strategic Energy began to bill a portionrecovered $1.3 million and $5.4 million in 2006 and 2005, respectively, of its SECA costs through
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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 the 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 2006, FERC held hearings on the justness and reasonableness of the SECA rate and on attempts by suppliers to shift SECA to wholesale counterparties and subsequently, 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.
 
6.7.  
GOODWILL AND INTANGIBLE PROPERTY
 
Goodwill reported on Great Plains Energy’s consolidated balance sheets reflect goodwill associated with the Company’s ownership in Strategic Energy was $87.6of $88.1 million and $86.8$87.6 million at December 31, 2005
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2006 and 2004,2005, respectively. The increase in goodwill in 2006 reflects Great Plains Energy’s acquisition of the remaining indirect interest in Strategic Energy as part of a litigation settlement. See Note 15 for additional information. Annual impairment tests, conducted September 1, have been completed and there were no impairments of goodwill in 2006, 2005 2004 or 2003. See Note 7 for additional information regarding the 2004 acquisition of an additional indirect interest in Strategic Energy.2004.
 
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Other Intangible Assets and Related Liabilities
Great Plains Energy and consolidated KCP&L’s intangible assets and related liabilities are detailed in the following table.
            
  
               December 31, 2006
  
December 31, 2005
 
  
Gross Carrying
 
Accumulated
   
Gross Carrying
 
Accumulated
 
  
Amount
 
Amortization
   
Amount
 
Amortization
 
Consolidated KCP&L
 (millions)
Computer software (a)
 $100.4 $(76.2)  $92.9 $(68.8)
            
Other Great Plains Energy
           
Computer software (a)
  15.0  (8.4)   12.0  (5.2)
Acquired intangible assets           
Supply contracts  26.5  (26.5)   26.5  (19.3)
Customer relationships  17.0  (7.6)   17.0  (4.7)
Asset information systems  1.9  (1.4)   1.9  (0.9)
Unamortized intangible assets           
Strategic Energy trade name  0.7      0.7   
Total intangible assets $161.5 $(120.1)  $151.0 $(98.9)
Amortized related liabilities           
Retail contracts $26.5 $(26.5)  $26.5 $(19.3)
          
 
December 31, 2005
 
December 31, 2004
 
Gross Carrying
Accumulated
 
Gross Carrying
Accumulated
 
Amount
Amortization
 
Amount
Amortization
Consolidated KCP&L
 (millions)
Computer software (a)
$92.9 $(68.8) $88.7 $(61.3)
              
Other Great Plains Energy
             
Computer software (a)
 12.0  (5.2)  5.4  (3.4)
Acquired intangible assets             
 Supply contracts 26.5  (19.3)  26.5  (7.7)
 Customer relationships 17.0  (4.7)  17.0  (1.9)
 Asset information systems 1.9  (0.9)  1.9  (0.3)
Unamortized intangible assets             
 Strategic Energy trade name 0.7      0.7    
Total intangible assets$151.0 $(98.9) $140.2 $(74.6)
Amortized related liabilities             
Retail contracts$26.5 $(19.3) $26.5 $(7.7)
(a) Computer software is included in electric utility plant or other nonutility property, as applicable, on the
    consolidated balance sheets.
(a)
Computer software is included in electric utility plant or other nonutility property, as applicable, on the consolidated balance sheets.
The fair value of acquired supply (intangible asset) and retail (liability) contracts is beingwere amortized over approximately 28 months. Other intangible assets recorded that have finite lives and are subject to amortization include customer relationships and asset information systems, which are being amortized over 72 and 44 months, respectively. A $0.7 million intangible asset for the Strategic Energy trade name was also recorded and deemed to have an indefinite life, and as such, is not being amortized. See Note 7 for more information.
 
Amortization expense for the acquired share of intangible assets and related liabilities is detailed in the following table.
               
     
Estimated Amortization Expense
 
2005
2004
2006
2007
2008
2009
2010
 (millions)
Intangible assets$15.0 $9.9 $10.6 $3.3 $2.8 $2.9 $0.9 
Related liabilities (11.6) (7.7) (7.2) -  -  -  - 
    Net amortization expense$3.4 $2.2 $3.4 $3.3 $2.8 $2.9 $0.9 

7. 
ACQUISITION OF ADDITIONAL INDIRECT INTEREST IN STRATEGIC ENERGY
In May 2004, Great Plains Energy, through IEC, purchased an additional 11.45% indirect interest in Strategic Energy. The Company paid cash of $90.0 million, including $1.2 million of transaction costs. In accordance with the purchase terms, the Company also recorded a $0.9 million liability for 2004 fractional dividends to the previous owner for its share of 2004 budgeted Strategic Energy dividends. See Note 15 for discussion of a related legal proceeding.
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Estimated Amortization Expense
 
  
2006
 
2005
 
2004
   
2007
 
2008
 
2009
 
2010
 
    (millions) 
Intangible assets $10.6 $15.0 $9.9   $3.3 $2.8 $2.9 $0.9 
Related liabilities  (7.2) (11.6) (7.7) -  -  -  - 
Net amortization expense $3.4 $3.4 $2.2  $3.3 $2.8 $2.9 $0.9 
                  
A third party valuation was prepared to assist in the Company’s determination of the purchase price allocation. The acquired share of identifiable intangible assets and liabilities were recorded by IEC at fair value as part of the purchase price allocation. The purchase price allocation for the net assets acquired is detailed in the following table. See Note 6 for more information.
   
 
2004
 (millions)
Other non-utility property and investments$10.6 
Goodwill 60.7 
Other deferred charges 46.1 
    Total assets 117.4 
Accounts payable 0.9 
Other deferred credits and liabilities 26.5 
    Net assets acquired$90.0 

8.
DISCONTINUED OPERATIONS
KLT Gas
In February 2004, the Board of Directors approved the sale of the KLT Gas natural gas properties (KLT Gas portfolio) and discontinuation of the gas business. Since the approval, the KLT Gas portfolio has been reported as discontinued operations in accordance with SFAS No. 144. During 2004, KLT Gas completed sales of substantially all of the KLT Gas portfolio. At December 31, 2005 and 2004, KLT Gas had $0.6 million and $0.7 million of current assets and $0.1 million and $2.1 million of current liabilities recorded in assets and liabilities from discontinued operations, respectively. The following table summarizes the discontinued operations.
       
 
2005
2004
2003
   
Revenues$- $1.6 $1.5 
Gain (loss) from operations, including         
impairments, before income taxes (2.9) (4.5) (59.1)
Gain on sales of assets -  16.8  - 
Discontinued operations before income taxes (2.9) 12.3  (59.1)
Income taxes 1.0  (5.0) 23.0 
Discontinued operations, net of income taxes$(1.9)$7.3 $(36.1)
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RSAE
In 2003, HSS completed the disposition of its interest in RSAE. The financial statements reflect RSAE as discontinued operations for 2003 in accordance with SFAS No. 144. The following table summarizes the discontinued operations.
   
 
2003
 (millions)
Revenues$31.8 
    
Loss from operations before income taxes (1.6)
Loss on disposal before income taxes (18.9)
Total loss on discontinued operations before income taxes (20.5)
Income tax benefit 11.8 
Discontinued operations, net of income taxes$(8.7)
9.8.  
PENSION PLANS, AND OTHER EMPLOYEE BENEFITS AND SKILL SET REALIGNMENT COSTS 
 
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 funding policy for the pension plans is to contribute amounts sufficient to meet the minimum funding requirements under the Employee Retirement Income Security Act of 1974 (ERISA) plus additional amounts as considered appropriate.
 
The MPSC and KCC issued orders in 2005 orders establish KCP&L’s annual pension costs at $22 million through the creation ofestablishing regulatory assets and liabilities for future recovery from or refundthe difference between KCP&L’s pension costs for ratemaking and SFAS No. 87 pension costs. In 2006, the Commissions issued orders granting equivalent treatment for SFAS No. 88 charges retroactive to customers, as appropriate. As a result, pension cost for KCP&L was reduced by $14.6 million and a corresponding regulatory asset and liability were established.
For defined benefit pension plans sponsored by Great Plains Energy, contributions and expense are allocated to KCP&L and Services based on labor costs of plan participants. Any additional minimum pension liability is allocated based on the Company’s funded status per plan.January 1, 2006.
 
In addition to providing pension benefits, the Company provides certain postretirementpost-retirement health care and life insurance benefits for substantially all retired employees of KCP&L, Services and WCNOC. The
91
cost of postretirementpost-retirement benefits charged to KCP&L are accrued during an employee's years of service and recovered through rates.
In September 2006, SFAS No. 158 was issued which requires the recognition of the funded status of defined pension plans and other post-retirement plans on the balance sheet with any changes in funded status recognized through comprehensive income in the year the changes occur and is effective for fiscal years ending after December 15, 2006, with retrospective application not permitted. SFAS No. 158 also requires an employer to measure the funded status of a plan as of the date of its year-end balance sheet effective for fiscal years ending after December 15, 2008. Under the standard, overfunded plans are recognized as an asset and underfunded plans are recognized as a liability with any unrecognized amounts recorded in accumulated other comprehensive income (OCI). The recognition of any additional minimum pension liability and related intangible asset are no longer required. The Company fundsadopted the portionrecognition requirements of SFAS No. 158 on December 31, 2006, and established a regulatory asset in accordance with SFAS No. 71 for the amounts KCP&L recorded in accumulated OCI. Prior to the adoption of SFAS No. 158, the Company decreased the minimum pension liability adjustment, intangible asset and OCI, net periodic postretirement benefit costs that areof tax deductible. For post-retirement health care plans sponsored by $27.8 million, $2.3 million and $16.0 million, respectively.
The following table summarizes the effects of implementing SFAS No. 158 on Great Plains Energy, contributionsEnergy’s and expense are allocated toconsolidated KCP&L and Services based upon the number of plan participants.
&L’s balance sheets at December 31, 2006.
        
  
Prior to
   
Post
 
December 31, 2006
 
SFAS No. 158
 
Adjustments
 
SFAS No. 158
 
  (millions) 
Prepaid benefit cost $46.8 $(46.8)$- 
Current liability  -  (1.0) (1.0)
Accrued benefit cost  (31.4) 31.4  - 
Pension liability  -  (143.2) (143.2)
Postretirement liability  -  (33.0) (33.0)
Minimum pension liability adjustment  (46.5) 46.5  - 
Intangible asset  12.1  (12.1) - 
Accumulated OCI, net of tax  -  1.6  1.6 
Regulatory asset  34.3  155.7  190.0 
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The following pension benefits tables provide information relating to the funded status of all defined benefit pension plans on an aggregate basis as well as the components of net periodic benefit costs. The plan measurement date for the majority of plans is September 30. In 2006, contributions of $1.2 million and $4.6 million were made to the pension and post-retirement benefit plans, respectively, after the measurement date and in 2005, contributions of $0.2 million and $3.8 million were made to the pension plan and postretirementpost-retirement benefit plans, respectively, after the measurement date and in 2004, contributions of $20.7 million were made to the pension plans after the measurement date. Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with joint-owners of power plants.
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Pension Benefits
 
Other Benefits
 
  
2006
 
2005
 
2006
 
2005
 
Change in projected benefit obligation (PBO)
 (millions)
PBO at beginning of year $554.6 $515.7 $53.0 $49.1 
Service cost  18.8  17.3  0.9  0.9 
Interest cost  30.9  29.8  3.0  2.9 
Contribution by participants  -  -  1.3  1.2 
Amendments  -  0.6  -  - 
Actuarial loss (gain)  6.5  33.0  (1.8) 3.6 
Benefits paid  (17.9) (41.2) (4.2) (4.1)
Benefits paid by Company  (0.4) (0.6) (0.7) (0.6)
Settlements  (83.7) -  -  - 
PBO at end of plan year $508.8 $554.6 $51.5 $53.0 
Change in plan assets
         
Fair value of plan assets at beginning of year $412.2 $370.5 $12.2 $14.7 
Actual return on plan assets  34.3  47.8  0.6  0.3 
Contributions by employer and participants  18.8  35.1  4.8  1.3 
Benefits paid  (17.9) (41.2) (4.2) (4.1)
Settlements  (82.9) -  -  - 
Fair value of plan assets at end of plan year $364.5 $412.2 $13.4 $12.2 
Funded status at end-of-year
         
Funded status $(144.3)$(142.4)$(38.1)$(40.8)
Unrecognized actuarial loss  -  195.0  -  14.1 
Unrecognized prior service cost  -  32.6  -  0.8 
Unrecognized transition obligation  -  0.3  -  8.2 
Contributions and changes after measurement date  0.6  0.2  4.6  3.8 
Net amounts recognized  (143.7) 85.7  (33.5) (13.9)
Regulatory asset, net  -  14.6  -  - 
Net amount recognized at December 31 $(143.7)$100.3 $(33.5)$(13.9)
Amounts recognized in the consolidated balance sheets
      
Prepaid benefit cost $- $98.3 $- $- 
Current pension liability  (0.5) -  (0.5) - 
Accrued benefit cost  -  (12.8) -  (17.7)
Pension liability  (143.8) -  (37.6) - 
Minimum pension liability adjustment  -  (74.3) -  - 
Intangible asset  -  14.4  -  - 
Contributions and changes after measurement date  0.6  0.2   4.6  3.8 
Net amount recognized before regulatory treatment  (143.7) 25.8  (33.5)   (13.9)
Accumulated OCI  2.3  59.9  0.3  - 
Regulatory asset, net  238.0  14.6  18.9  - 
Net amount recognized at December 31 $96.6 $100.3 $(14.3)$(13.9)
Amounts in accumulated OCI or regulatory asset not
         
yet recognized as a component of net periodic cost:
         
Unrecognized actuarial loss $144.8 $- $11.6 $- 
Unrecognized prior service cost  28.3  -  0.6  - 
Unrecognized transition obligation  0.3  -  7.0  - 
Other  66.9  -  -  - 
Net amount recognized at December 31 $240.3 $- $19.2 $- 
          
  
Pension Benefits
 
Other Benefits
 
  
2005
 
2004
 
2005
 
2004
 
Change in projected benefit obligation (PBO)
 (millions) 
PBO at beginning of year $515.7
 
$501.5
 
$49.1
 
$52.1 
Service cost  17.3  16.7  0.9  0.9 
Interest cost  29.8  30.1  2.9  3.1 
Contribution by participants  -  -  1.2  1.1 
Amendments  0.6  -  -  - 
Actuarial loss (gain)  33.0  25.1  3.6  (3.2)
Benefits paid  (41.2) (54.7) (4.1) (4.3)
Benefits paid by Company  (0.6) (0.3) (0.6) (0.6)
Settlements  -  (2.7) -  - 
      PBO at end of plan year
 
$554.6
 
$515.7
 
$53.0
 
$49.1 
Change in plan assets
             
Fair value of plan assets at beginning of year $370.5
 
$341.0
 
$14.7
 
$8.3 
Actual return on plan assets  47.8  33.9  0.3  0.3 
Contributions by employer and participants  35.1  50.3  1.3  10.4 
Benefits paid  (41.2) (54.7) (4.1) (4.3)
      Fair value of plan assets at end of plan year $412.2
 
$370.5
 
$12.2
 
$14.7 
Prepaid (accrued) benefit cost
             
Funded status $(142.4)$(145.2)$(40.8)$(34.4)
Unrecognized actuarial loss  195.0  195.9  14.1  10.5 
Unrecognized prior service cost  32.6  36.3  0.8  1.0 
Unrecognized transition obligation  0.3  0.4  8.2  9.4 
Net prepaid (accrued) benefit cost  85.5  87.4  (17.7) (13.5)
Regulatory asset, net  14.6  -  -  - 
      Net amount recognized at December 31 $100.1 $87.4 $(17.7)$(13.5)
Amounts recognized in the consolidated balance sheets
         
Prepaid benefit cost $98.3 $89.2 $- $- 
Accrued benefit cost  (12.8) (1.8) (17.7) (13.5)
Minimum pension liability adjustment  (74.3) (84.2) -  - 
Intangible asset  14.4  15.6  -  - 
Accumulated other comprehensive income  59.9  68.6  -  - 
Regulatory asset, net  14.6  -  -  - 
   Net amount recognized in balance sheets  100.1  87.4  (17.7) (13.5)
Contributions and changes after             
   measurement date  0.2  20.7  3.8  - 
      Net amount recognized at December 31 $100.3 $108.1 $(13.9)$(13.5)
             
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Pension Benefits
 
Other Benefits
 
  
2005
2004
2003
2005
2004
2003
Components of net periodic benefit cost
 (millions) 
Service cost $17.3 $16.7 $15.0 $0.9 $0.9 $0.9 
Interest cost  29.8  30.1  29.9  2.9  3.1  3.2 
Expected return on plan assets  (32.4) (31.7) (27.7) (0.6) (0.6) (0.6)
Amortization of prior service cost  4.3  4.3  4.3  0.2  0.2  0.2 
Recognized net actuarial loss (gain)  18.6  7.7  1.3  0.5  0.7  0.6 
Transition obligation  0.1  0.1  0.1  1.2  1.2  1.2 
Amendment  -  -  -  -  -  0.1 
Net settlements  -  1.8  -  -  -  - 
   Net periodic benefit cost before                   
      regulatory adjustment  37.7  29.0  22.9  5.1  5.5  5.6 
Regulatory adjustment  (14.6) -  -  -  -  - 
   Net periodic benefit cost $23.1
 
$29.0
 
$22.9
 
$5.1
 
$5.5
 
$5.6 
                    

              
  
Pension Benefits
Other Benefits
Year to Date December 31
 
2006
 
2005
 
2004
 
2006
 
2005
 
2004
 
Components of net periodic benefit cost
 (millions)
Service cost $18.8 $17.3 $16.7 $0.9 $0.9 $0.9 
Interest cost  30.9  29.8  30.1  3.0  2.9  3.1 
Expected return on plan assets  (32.7) (32.4) (31.7) (0.6) (0.6) (0.6)
Amortization of prior service cost  4.3  4.3  4.3  0.2  0.2  0.2 
Recognized net actuarial loss  31.8  18.6  7.7  0.9  0.5  0.7 
Transition obligation  0.1  0.1  0.1  1.2  1.2  1.2 
Settlement charges  23.1  -  1.8  -  -  - 
Net periodic benefit cost before                   
regulatory adjustment  76.3  37.7  29.0  5.6  5.1  5.5 
Regulatory adjustment  (52.3) (14.6) -  -  -  - 
Net periodic benefit cost $24.0 $23.1 $29.0 $5.6 $5.1 $5.5 
                    
The estimated prior service cost, net loss and transition costs for the defined benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2007 are $4.3 million, $35.2 million and $0.1 million, respectively. The estimated prior service cost, net loss, and transition costs for the other post-retirement benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2007 are $0.2 million, $0.6 million and $1.2 million, respectively. Net actuarial gains and losses are recognized on a rolling five-year average basis.
The accumulated benefit obligation (ABO) for all defined benefit pension plans was $469.9$427.1 million and $445.4$469.9 million at December 31, 20052006 and 2004,2005, respectively. The PBO, ABO and the fair value of plan assets at plan year-end are aggregated by funded and under funded plans in the following table.
          
 
2005
 
2004
  
2006
 
2005
 
Pension plans with the ABO in excess of plan assets
 (millions)  (millions)
Projected benefit obligation $337.8 $309.8  $323.9 $337.8 
Accumulated benefit obligation  280.6  266.1   268.5  280.6 
Fair value of plan assets  204.1  180.0   193.4  204.1 
Pension plans with plan assets in excess of the ABO
Pension plans with plan assets in excess of the ABO
   
Pension plans with plan assets in excess of the ABO
  
Projected benefit obligation $216.8 $205.9  $184.9 $216.8 
Accumulated benefit obligation  189.3  179.3   158.6  189.3 
Fair value of plan assets  208.1  190.5   171.1  208.1 
       
The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns of various asset classes. Based on the target asset allocation for each asset class, the overall expected rate of return for the portfolio was developed and adjusted for the effect of projected benefits paid from plan assets and future plan contributions.
 
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The following tables provide the weighted-average assumptions used to determine benefit obligations and net costs.
         
Weighted average assumptions used to determine
Pension Benefits
 
Other Benefits
 
the benefit obligation at plan year-end
2006
 
2005
 
2006
 
2005
 
Discount rate5.87% 5.62% 5.89% 5.62% 
Rate of compensation increase3.81% 3.57% 3.90% 3.60% 
          
Weighted average assumptions used to determine
 
Pension Benefits
Other Benefits
   the benefit obligation at plan year-end
 
2005
2004
2005
2004
Discount rate  5.62% 5.82% 5.62% 5.82%
Rate of compensation increase  3.57% 3.06% 3.60% 3.05%
              
         
Weighted average assumptions used to determine
Pension Benefits
 
Other Benefits
 
net costs for years ended at December 31
2006
 
2005
 
2006
 
2005
 
Discount rate5.62% 5.82% 5.62% 5.82% 
Expected long-term return on plan assets8.25% 8.75% 4.23%*4.26%*
Rate of compensation increase3.57% 3.06% 3.60% 3.05% 
* after tax        
92
          
Weighted average assumptions used to determine
 
Pension Benefits
Other Benefits
   net costs for years ended at December 31
 
2005
2004
2005
2004
Discount rate  5.82% 6.00% 5.82% 6.00%
Expected long-term return on plan assets  8.75% 9.00% 4.26% * 6.62% *
Rate of compensation increase  3.06% 3.30% 3.05% 3.25%
* after tax             
              
Primarily as a result of lower discount rates and historical losses in the market value of plan assets, the Company has a minimum pension liability offset by an intangible asset and OCI. The amounts recognized in Great Plains Energy’s and consolidated KCP&L’s balance sheets related to the minimum pension liability are detailed in the following table.
          
  
 Great Plains Energy
 Consolidated KCP&L
  
December 31
December 31
  
2005
2004
2005
2004
  (millions) 
Additional minimum pension liability $74.3 $84.2 $73.5 $79.8 
Intangible asset  14.4  15.6  13.7  14.6 
Deferred taxes  22.5  26.3  22.5  25.0 
OCI, net of tax  37.4  42.3  37.3  40.2 
              
Pension plan assets are managed in accordance with “prudent investor” guidelines contained in the ERISAEmployee Retirement Income Security Act (ERISA) requirements. The investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets within a reasonable and prudent level of risk. Investments are diversified across classes and within each class to minimize risks. At December 31, 20052006 and 2004,2005, respectively, the fair value of plan assets was $412.2$364.5 million, not including a $0.2$1.2 million contribution made after the plan year-end, and $370.5$412.2 million, not including a $20.7$0.2 million subsequent contribution. The asset allocation for the Company’s pension plans at the end of 20052006 and 2004,2005, and the target allocation for 20062007 are reported in the following table. The portfolio is periodically rebalanced to generally meet target allocation percentages.
             
   
Plan Assets at
   
Plan Assets at
 
Target
December 31
 
Target
 
December 31
Asset Category
 
Allocation
2005
2004
 
Allocation
 
2006
 
2005
Equity securities  61% 61% 59% 62% 67% 61%
Debt securities  27% 26% 31% 28% 22% 26%
Real estate  7% 7% 8% 6% 6% 7%
Other  5% 6% 2% 4% 5% 6%
Total  100% 100% 100% 100% 100% 100%
               
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The cost trend assumed for 20052006 was 10%9% and is 9%8% for 2006.2007. The cost trend rate will continue to decline through 2010 to the ultimate cost trend rate of 5%. The health care plan requires retirees to make monthly contributions on behalf of themselves and their dependents in an amount determined by the Company.
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The effects of a one-percentage point change in the medicalassumed health care cost trend rates, holding all other assumptions constant, at December 31, 2005,2006, are detailed in the following table.
      
  
Increase
 
Decrease
 
  (millions) 
Effect on total service and interest component $0.1 $(0.1)
Effect on postretirement benefit obligation  0.7  (0.6)
      
95
      
  
Increase
Decrease
  (millions)
Effect on total service and interest component $0.1 $(0.1)
Effect on postretirement benefit obligation  0.7  (0.7)
        
The Company expects to contribute $20.0$33.6 million to the plans in 2006, which includes $6.0 million2007 to meet ERISA funding requirements, all of which will be paid by KCP&L. The Company will also contribute $4.6$4.3 million to other postretirementpost-retirement benefit plans in 2006, $4.32007, $4.0 million of which will be paid by KCP&L. The Company’s funding policy is to contribute amounts sufficient to meet the ERISA minimum funding requirements plus additional amounts as considered appropriate; therefore, actual contributions may differ from expected contributions. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid through 2015.
2016.
          
 
Pension
 
Other
  
Pension
 
Other
 
 
Benefits
 
Benefits
  
Benefits
 
Benefits
 
 (millions)  (millions) 
2006 $43.8 $6.0 
2007  43.2  7.0  $37.2 $7.0 
2008  41.8  7.7   36.2  7.6 
2009  42.7  8.6   36.4  8.3 
2010  45.6  9.3   39.7  8.9 
2011-2015  230.3  57.1 
       
2011  38.6  9.6 
2012-2016  222.2  56.3 
Employee Savings Plans
Great Plains Energy has defined contribution savings plans that cover substantially all employees. The Company matches employee contributions, subject to limits. The annual cost of the plans was approximately $4.8 million $4.9 millionin 2006, 2005 and $4.7 million in 2005, 2004 and 2003, respectively.2004. Consolidated KCP&L’s annual cost of the plans was approximately $3.1$3.0 million for each of the last three years.
 
Strategic Energy Phantom Stock Plan
Strategic Energy had a phantom stock plan that provided incentive in the form of deferred compensation based upon the award of performance units, the value of which was related to the increase in profitability of Strategic Energy. The plan was terminated and an insignificant amount of costs were recorded in 2004. Strategic Energy’s annual cost for the plan was $4.6 million in 2003.
Cash-Based Long-Term Incentives
In 2005, Strategic Energy initiatedhas long-term incentives designed to reward officers and key members of management with Great Plains Energy restricted stock (issued under the Company’s Long-Term Incentive Plan) and a cash performance payment for achieving specific performance goals over stated periods of time, commencing January 1, 2005. The restricted stock compensation expense is discussed in Note 10.9. In 2006 and 2005, compensation expense of $3.8 million and $1.6 million, respectively, was recognized for the cash-based incentives.
 
Skill Set Realignment Costs
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. In 2006, Great Plains Energy and consolidated KCP&L recorded $9.4 million and $9.3 million, respectively, related to this process reflecting severance, benefits and related payroll taxes provided to employees.
10.9.  
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 in 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 and other employees of the Company and its subsidiaries. In accordance with the provisions of SFAS No. 123, compensation expense and 
94
accrued dividends related to equity compensation are recognized over the stated vesting period. Forfeitures of equity compensation are recognized when incurred and previously recorded compensation expense related to the forfeited shares is reversed. The maximum number of shares of Great Plains Energy common stock that can be issued under the plan is 3.0 million. At December 31, 2005, 2.0 millionCommon stock shares remained available fordelivered 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
96
laws. The Company has a policy of delivering newly issued shares, or shares surrendered by Long-Term Incentive Plan participants on account of withholding taxes and held in treasury, or both, to satisfy share option exercises and does not expect to repurchase common shares during 2007 to satisfy stock option exercises.
SFAS No. 123R requires forfeitures to be estimated. Forfeiture rates are based on historical forfeitures and future issuance.expectations and are reevaluated annually. The following table summarizes Great Plains Energy’s and KCP&L’s equity compensation expense and associated income tax benefits.
        
  
2006
 
2005
 
2004
 
Compensation expense
 (millions) 
Great Plains Energy $3.9 $2.8 $0.8 
KCP&L  2.4  1.7  0.6 
Income tax benefits
          
Great Plains Energy  1.2  1.1  0.4 
KCP&L  0.8  0.6  0.2 
 
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. Exercise prices range from $24.90 to $27.73 and the weighted-average remaining contractual life at December 31, 2005 was 6 years. In accordance with the provisions of SFAS No. 123, the Company recognized an insignificant amount of compensation expense in 2005, 2004 and 2003.
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. The option valuation model requiresCompensation expense and accrued dividends related to stock options are recognized over the inputstated vesting period. Exercise prices range from $24.90 to $27.73 and all stock options are fully vested and have a remaining weighted average contractual term of highly subjective assumptions, primarily stock price volatility, changes in which can materially affect the fair value estimate. The weighted-average assumptions used are detailed in the following table.
2003
Risk-free interest rate4.77%
Dividend yield6.88%
Stock volatility22.65%
Expected option life (in years)10
4.9 years at December 31, 2006. All stock option activity for the last three yearsin 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 December 31  109,472  25.52 
* weighted-average       
              
  
2005
2004
2003
  
Shares
Price*
Shares
Price*
Shares
Price*
Beginning balance  195,973 $25.48  241,898 $25.41  397,000 $25.21 
Granted  -  -  -  -  27,898  27.73 
Exercised  (68,000) 25.08  (26,000) 24.79  (16,000) 26.19 
Forfeited  (16,518) 26.57  (19,925) 25.50  (167,000) 25.26 
Ending balance  111,455 $25.56  195,973 $25.48  241,898 $25.41 
Exercisable at December 31  95,000 $25.19  75,000 $25.43  7,000 $21.67 
* weighted-average price                   
                    
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.
97
Performance share activity for the last three years2006 is summarized in the following table.
        
  
2005
2004
2003
Beginning balance  19,313  20,744  144,500 
Granted  182,130  -  20,744 
Cancelled  -  -  (144,500)
Forfeited  (28,682) (1,431) - 
Ending balance  172,761  19,313  20,744 
           
95
      
    
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        
Compensation expense for
At December 31, 2006, the remaining weighted-average contractual term was 1.1 years. The weighted-average grant-date fair value of shares granted was $28.20 and $30.34 in 2006 and 2005, respectively. There were no performance shares is recognized over the performance period. In 2005, the Company recognizedgranted during 2004. At December 31, 2006, there was $2.2 million of total unrecognized compensation expense, net of $1.2 million and reversed an insignificant amount related to forfeited shares. The Company recognized an insignificant amount of compensation expense in 2004 and $0.4 million in 2003. No compensation expense had been recordedforfeiture rates, related to performance shares cancelled in 2003.granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term.  The total fair value of shares issued was insignificant during 2006 and performances shares were not issued during 2005 and 2004.
 
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 grantissue date. Restricted stock shares issued in 2003 totaling 57,315 vested in 2003 and were issued out of treasury stock; however, 54,436 of these shares were restricted as to transfer until December 31, 2004, but were considered vested under SFAS No. 123 because the employee’s right to retain the shares of stock was not contingent upon remaining in the service of the Company and was not contingent upon achievement of performance conditions. All other restricted stock shares issued vest on a graded schedule 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 for the last three years2006 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  
Vested  (25,404) 30.49  
Forfeited  (2,000) 28.20  
Ending balance  140,603  29.75 
* weighted-average        
At December 31, 2006, the remaining weighted-average contractual term was 1.4 years. The weighted-average grant-date fair value of shares granted was $28.22, $30.47 and $29.71 during 2006, 2005 and 2004, respectively. At December 31, 2006, there was $1.5 million of total unrecognized compensation expense, net of forfeiture rates, related to nonvested restricted stock granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term.  The total fair value of shares vested was $0.8 million, $0.8 million and $1.5 million in 2006, 2005 and 2004, respectively.
98
        
  
2005
 
2004
 
2003
 
Beginning balance  76,214  62,881  - 
Granted (a)
  79,872  13,333  120,196 
Vested  (25,404) -  (57,315)
Forfeited  (10,716) -  - 
    Ending balance  119,966  76,214  62,881 
(a) Restricted stock shares granted in 2005 totaling 3,497 were issued out of
    treasury stock. Restricted stock shares issued in 2003 totaling 57,315
    vested in 2003 and were issued out of treasury stock.
 
Compensation expense for restricted stock is recognized over the vesting period. The Company recognized compensation expense of $1.4 million, $0.6 million and $1.8 million in 2005, 2004 and 2003, respectively and reversed an insignificant amount related to forfeited shares in 2005.

11.10.  
TAXES
 
Components of income taxes are detailed in the following tables.
        
    
As
 
As
 
    
Adjusted
 
Adjusted
 
Great Plains Energy
 
2006
 
2005
 
2004
 
Current income taxes (millions) 
Federal $59.2 $64.3 $19.9 
State  0.9  1.3  13.3 
Total  60.1  65.6  33.2 
Deferred income taxes          
Federal  (7.2) (4.2) 46.8 
State  (3.8) (19.0) (15.5)
Total  (11.0) (23.2) 31.3 
Investment tax credit amortization  (1.2) (3.9) (4.0)
Total income tax expense  47.9  38.5  60.5 
Less: taxes on discontinued operations          
Current tax (benefit) expense  -  (1.0) (5.0)
Deferred tax (benefit) expense  -  -  10.0 
Income taxes on continuing operations $47.9 $39.5 $55.5 
        
        
    
As
 
As
 
    
Adjusted
 
Adjusted
 
Consolidated KCP&L
 
2006
 
2005
 
2004
 
Current income taxes (millions)
Federal $49.3 $79.9 $39.2 
State  4.8  5.6  6.7 
Total  54.1  85.5  45.9 
Deferred income taxes          
Federal  15.6  (14.3) 23.2 
State  1.8  (19.3) (11.3)
Total  17.4  (33.6) 11.9 
Investment tax credit amortization  (1.2) (3.9) (4.0)
Total $70.3 $48.0 $53.8 
           
        
Great Plains Energy
 
2005
 
2004
 
2003
 
Current income taxes (millions) 
Federal $64.3 $19.9 $12.1 
State  1.3  13.3  8.9 
Total  65.6  33.2  21.0 
Deferred income taxes          
Federal  (4.2) 45.8  23.3 
State  (18.8) (15.5) 3.5 
Total  (23.0) 30.3  26.8 
Investment tax credit amortization  (3.9) (4.0) (4.0)
Total income tax expense  38.7  59.5  43.8 
Less: taxes on discontinued          
operations (Note 8)          
 Current tax benefit  (1.0) (5.0) (31.1)
Deferred tax (benefit) expense  -  10.0  (3.7)
Income taxes on continuing operations $39.7 $54.5 $78.6 
           
9699
        
Consolidated KCP&L
 
2005
2004
2003
Current income taxes (millions) 
Federal $79.9 $39.2 $26.1 
State  5.6  6.7  5.7 
Total  85.5  45.9  31.8 
Deferred income taxes          
Federal  (14.3) 22.2  37.1 
State  (19.1) (11.3) 6.8 
Total  (33.4) 10.9  43.9 
Investment tax credit amortization  (3.9) (4.0) (4.0)
Total income tax expense  48.2  52.8  71.7 
Less: taxes on discontinued          
operations (Note 8)          
  Current tax (benefit) expense  -  -  (21.5)
  Deferred tax expense  -  -  9.7 
Income taxes on continuing operations $48.2 $52.8 $83.5 
           
Income Tax Expense and Effective Income Tax Rates
Income tax expense and the effective income tax rates reflected in continuing operations in the financial statements and the reasons for their differences from the statutory federal rates are detailed in the following tables.
              
  
Income Tax Expense   
 
Income Tax Rate
 
    
As
 
As
   
As
 
As
 
    
Adjusted
 
Adjusted
   
Adjusted
 
Adjusted
 
Great Plains Energy
 
2006
 
2005
 
2004
 
2006
 
2005
 
2004
 
   (millions)           
Federal statutory income tax $61.4 $71.3 $80.8  35.0% 35.0% 35.0%
Differences between book and tax                   
depreciation not normalized  (0.3) 2.3  1.4  (0.2) 1.1  0.6 
Amortization of investment tax credits  (1.2) (3.9) (4.0) (0.7) (1.9) (1.7)
Federal income tax credits  (9.3) (10.0) (12.8) (5.3) (4.9) (5.5)
State income taxes  0.5  2.7  7.9  0.3  1.3  3.4 
Changes in uncertain tax positions, net  0.1  (7.9) (3.4) -  (3.9) (1.5)
Rate change on deferred taxes  -  (11.7) (8.6) -  (5.8) (3.7)
Valuation allowance  -  -  0.5  -  -  0.2 
Other  (3.3) (3.3) (6.3) (1.8) (1.5) (2.8)
Total $47.9 $39.5 $55.5  27.3% 19.4% 24.0%
                
  
Income Tax Expense
 
Income Tax Rate
 
Great Plains Energy
 
2005
2004
2003
2005
2004
2003
  (millions)        
Federal statutory income tax $71.4
 
$79.8
 
$93.9  35.0% 35.0% 35.0%
Differences between book and tax                   
depreciation not normalized  2.3  1.4  3.9  1.1  0.6  1.5 
Amortization of investment tax credits  (3.9) (4.0) (4.0) (1.9) (1.7) (1.5)
Federal income tax credits  (10.0) (12.8) (14.4) (4.9) (5.6) (5.4)
State income taxes  2.7  7.9  8.2  1.3  3.5  3.0 
Changes in uncertain tax positions, net  (7.9) (3.4) 12.0  (3.9) (1.5) 4.5 
Rate changes on deferred taxes  (11.7) (8.6) -  (5.8) (3.8) - 
Valuation allowance  -  0.5  (15.8) -  0.2  (5.9)
Other  (3.2) (6.3) (5.2) (1.4) (2.8) (1.9)
Total $39.7
 
$54.5
 
$78.6  19.5% 23.9% 29.3%
                    
                
  
Income Tax Expense
 
Income Tax Rate
 
Consolidated KCP&L
 
2005
 
2004
 
2003
 
2005
 
2004
 
2003
 
  (millions)         
Federal statutory income tax $67.1 $68.6
 
$73.3  35.0% 35.0% 35.0%
Differences between book and tax                   
depreciation not normalized  2.3  1.4  3.9  1.2  0.7  1.9 
Amortization of investment tax credits  (3.9) (4.0) (4.0) (2.0) (2.0) (1.9)
State income taxes  4.2  7.0  7.1  2.2  3.6  3.4 
Changes in uncertain tax positions, net  (1.7) (2.7) 3.9  (0.9) (1.4) 1.9 
Rate changes on deferred taxes  (11.7) (8.6) -  (6.1) (4.4) - 
Allocation of parent company tax benefits  (5.4) (5.9) -  (2.8) (3.0) - 
Other  (2.7) (3.0) (0.7) (1.5) (1.5) (0.4)
Total $48.2
 
$52.8
 
$83.5  25.1% 27.0% 39.9%
                    
97
              
  
Income Tax Expense 
 
Income Tax Rate 
 
    
As
 
As
   
As
 
As
 
    
Adjusted
 
Adjusted
   
Adjusted
 
Adjusted
 
Consolidated KCP&L
 
2006
 
2005
 
2004
 
2006
 
2005
 
2004
 
   (millions)           
Federal statutory income tax $76.9 $67.0 $69.6  35.0% 35.0% 35.0%
Differences between book and tax                   
depreciation not normalized  (0.3) 2.3  1.4  (0.2) 1.2  0.7 
Amortization of investment tax credits  (1.2) (3.9) (4.0) (0.6) (2.0) (2.0)
Federal income tax credits  (4.6) -  -  (2.1) -  - 
State income taxes  5.5  4.2  7.0  2.5  2.2  3.6 
Changes in uncertain tax positions, net  0.6  (1.7) (2.7) 0.3  (0.9) (1.4)
Parent company tax benefits  (4.7) (5.4) (5.9) (2.1) (2.8) (2.9)
Rate change on deferred taxes  -  (11.7) (8.6) -  (6.1) (4.3)
Other  (1.9) (2.8) (3.0) (0.8) (1.6) (1.7)
Total $70.3 $48.0 $53.8  32.0% 25.0% 27.0%
                    
During 2005, Great Plains Energy and consolidated KCP&L’s income tax expense decreased by $7.5 million and $6.3 million, respectively, due to the favorable impact of sustained audited positions on the companies’ composite tax rates. Great Plains Energy’s income tax expense was also reduced by $5.7 million due to events during 2005 that strengthened the probability of sustaining tax deductions taken on previously filed tax returns.
 
SFAS No. 109 requires the companies to adjust deferred tax balances to reflect tax rates that are anticipated to be in effect when the differences reverse. The largest component of the companies’ decreases in effective income tax rates in 2005 and 2004 was the result of adjusting KCP&L’s deferred tax balance to its lower composite tax rate due to the impact of sustained audited positions and state tax planning. The impact of the composite tax rate reductions on the deferred tax balances resulted in
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tax benefits for Great Plains Energy and consolidated KCP&L of $11.7 million in 2005 and $8.6 million in 2004.
 
Deferred Income Taxes
The tax effects of major temporary differences resulting in deferred income tax assets (liabilities) in the consolidated balance sheets are in the following tables.
          
  
Great Plains Energy
 
Consolidated KCP&L
 
December 31
 
2005
 
2004
 
2005
 
2004
 
Current deferred income taxes (millions) 
Nuclear fuel outage $3.4 $5.1 $3.4 $5.1 
Derivative instruments  (11.2) (1.2) -  0.1 
Accrued vacation  4.7  4.5  4.7  3.8 
Other  1.8  4.7  0.8  3.8 
Net current deferred income tax asset             
    (liability)  (1.3) 13.1  8.9  12.8 
Noncurrent deferred income taxes             
Plant related  (554.2) (556.5) (554.2) (556.5)
Income taxes on future regulatory recoveries  (85.7) (81.0) (85.7) (81.0)
Derivative instruments  (11.1) (0.5) (4.5) - 
Pension and postretirement benefits  (8.0) (9.0) (8.4) (9.2)
Storm related costs  (1.9) (3.7) (1.9) (3.7)
Debt issuance costs  (2.7) (2.8) (2.7) (2.8)
Gas properties related  (1.3) (3.4) -  - 
SO2 emission allowance sales
  24.2  1.3  24.2  1.3 
Tax credit carryforwards  16.0  23.7  -  - 
Alternative minimum tax credit carryforward  -  4.1  -  - 
State net operating loss carryforward  0.5  0.5  -  - 
Other  3.3  (4.4) 6.2  (2.1)
Net noncurrent deferred tax liability before             
valuation allowance  (620.9) (631.7) (627.0) (654.0)
Valuation allowance  (0.5) (0.5) -  - 
Net noncurrent deferred tax liability  (621.4) (632.2) (627.0) (654.0)
   Net deferred income tax liability $(622.7)$(619.1)$(618.1)$(641.2)
              
          
  
Great Plains Energy
 
Consolidated KCP&L
 
December 31
  
2005
  
2004
  
2005
  
2004
 
 (millions) 
Gross deferred income tax assets $120.3 $144.3 $100.3 $120.8 
Gross deferred income tax liabilities  (743.0) (763.4) (718.4) (762.0)
Net deferred income tax liability $(622.7)$(619.1)$(618.1)$(641.2)
              
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 Great Plains Energy  
 
Consolidated KCP&L
 
  
                         
 As
Adjusted
 
                               
As
Adjusted
 
December 31
 
2006
 
2005
 
2006
 
2005
 
Current deferred income taxes (millions) 
Nuclear fuel outage $(5.2)$(3.0)$(5.2)$(3.0)
Derivative instruments  34.1  (11.2) 0.2  - 
Accrued vacation  4.5  4.7  4.4  4.7 
Other  6.2  1.8  0.7  0.8 
Net current deferred income tax asset         
(liability)  39.6  (7.7) 0.1  2.5 
Noncurrent deferred income taxes         
Plant related  (566.3) (554.2) (566.3) (554.2)
Income taxes on future regulatory recoveries  (81.7) (85.7) (81.7) (85.7)
Derivative instruments  19.3  (11.1) (4.3) (4.5)
Pension and postretirement benefits  (28.9) (8.0) (31.2) (8.4)
Storm related costs  (0.1) (1.9) (0.1) (1.9)
Debt issuance costs  (2.5) (2.7) (2.5) (2.7)
Gas properties related  (1.1) (1.3) -  - 
SO2 emission allowance sales
  24.5  24.2  24.5  24.2 
Tax credit carryforwards  15.0  16.0  -  - 
State net operating loss carryforward  0.5  0.5  -  - 
Other  (0.8) 3.3  1.6  6.2 
Net noncurrent deferred tax liability before         
valuation allowance  (622.1) (620.9) (660.0) (627.0)
Valuation allowance  (0.5) (0.5) -  - 
Net noncurrent deferred tax liability  (622.6) (621.4) (660.0) (627.0)
Net deferred income tax liability $(583.0)$(629.1)$(659.9)$(624.5)
          
  
Great Plains Energy
 
Consolidated KCP&L
 
  
                               
As Adjusted
 
                             �� 
As Adjusted
 
December 31
 
2006
 
2005
 
2006
 
2005
 
  (millions) 
Gross deferred income tax assets $251.3 $116.9 $166.9 $96.9 
Gross deferred income tax liabilities  (834.3) (746.0) (826.8) (721.4)
Net deferred income tax liability $(583.0)$(629.1)$(659.9)$(624.5)
          
Tax Credit Carryforwards
At December 31, 2005,2006, the Company had $16.0$15.0 million of state income tax credit carryforwards. These credits relate primarily to the Company’s Missouri affordable housing investment portfolio, and the carryforwards expire in years 2008 to 2010.2011. Management believes the credits will be fully utilized within the carryforward period.
 
Net Operating Loss Carryforwards
At December 31, 2004, KLT Inc. and subsidiaries had Kansas state net operating loss carryforwards of $10.0 million primarily resulting from losses associated with DTI.DTI Holdings, Inc. and its subsidiaries,
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Digital Teleport, Inc. and Digital Teleport of Virginia, Inc. KLT Inc. and subsidiaries moved its corporate headquarters to Missouri in 2003, and as a result, will not have sufficient presence in Kansas to utilize the losses. The Kansas state net operating loss carryforwards expire in years 2011 to 2012. In 2004, management determined that the loss carryforwards will more likely than not expire unutilized and has provided a valuation allowance against the entire $0.5 million deferred state income tax benefit.
 
Uncertain Tax Positions 
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 December 31, 20052006 and 2004,2005, the Company had $4.6$4.7 million and $13.4$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 $1.2$1.8 million and $3.7$1.2 million at December 31, 20052006 and 2004,2005, 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 Companycompanies will reverse these tax provisions to net income. If the positions are not ultimately sustained, the Companycompanies may be required to make cash payments plus interest and/or utilize the Company’scompanies’ federal and state credit carryforwards. During 2005,
In 2006, the Company reversed $9.2 millionFASB issued FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes,” an interpretation of previously recorded liabilitiesSFAS No. 109, “Accounting for uncertainIncome Taxes.” FIN No. 48 establishes a “more-likely-than-not” recognition threshold that must be met before a tax positions primarily due to sustained auditedbenefit can be recognized in the financial statements and requires various disclosures such as the policy surrounding classification of interest and penalties, a reconciliation of unrecognized tax positionsbenefit activity and disclosure of significant changes expected in unrecognized benefits within twelve months of the occurrence of events that strengthen the probability of successfully defending deductions taken on its tax returns. During 2005,reporting date. Great Plains Energy and consolidated KCP&L reversed $2.0 millionare required to adopt the provisions of FIN No. 48 for periods beginning in 2007, although earlier adoption is permitted. The impact to the financial statements of Great Plains Energy and consolidated KCP&L upon adoption of FIN No. 48 is expected to be insignificant. In addition, Great Plains Energy and consolidated KCP&L will elect to recognize interest accrued related to unrecognized tax liabilities for uncertain tax positions.benefits in interest expense and penalties in operating expenses with the adoption of FIN No. 48.
 
Internal Revenue Service Settlement
In November 2002, KCP&L accepted a settlement offer related to the proposed disallowance of interest deductions on corporate-owned life insurance (COLI) loans. The offer allowed 20% of the interest originally deducted and taxed only 20% of the gain on surrender of the COLI policies. KCP&L surrendered the policies in February 2003. KCP&L paid $1.3 million to the IRS in 2003 to satisfy the liability associated with the surrender. In December 2004, KCP&L settled the 1995-1999 IRS audit and paid tax of $7.3 million and interest of $4.2 million related to the disallowed COLI interest deduction. KCP&L accrued for these payments in 2000.
 
In addition to COLI, as part of the settlement of the 1995-1999 IRS audit, consolidated KCP&L agreed to additional tax of $6.9 million and interest of $5.9 million related primarily to timing differences. This settlement did not have a significant impact on consolidated KCP&L’s net income because the liability had been previously recorded in the liabilities for uncertain tax positions or had offsetting impacts on deferred taxes.
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11.  
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 had no
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active operations. At December 31, 2005, KLT Gas had $0.6 million of current assets and $0.1 million of current liabilities recorded in assets and liabilities of discontinued operations. The following table summarizes the discontinued operations.
      
  
2005
 
2004
 
  (millions) 
Revenues $- $1.6 
Loss from operations, including     
impairments, before income taxes  (2.9) (4.5)
Gain on sales of assets  -  16.8 
Discontinued operations before income taxes  (2.9) 12.3 
Income taxes  1.0  (5.0)
Discontinued operations, net of income taxes $(1.9)$7.3 
      
12.  
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 $18.5 million, $42.6 million and $62.7 million for 2006, 2005 and $45.2 million for 2005, 2004, and 2003, respectively. These costs consisted primarily of employee compensation, benefits and fees associated with various professional services. At December 31, 20052006 and 2004,2005, consolidated KCP&L had a netshort-term intercompany payable to Services of $3.5$2.5 million and $9.2$3.5 million, respectively. In 2005, approximately 80% of Services’ employees were transferred to KCP&L to better align resources with the operating business. Also at December 31, 2006, consolidated KCP&L had a long-term intercompany payable to Services of $5.7 million related to unrecognized pension expense recorded under the provision of SFAS No. 158. At December 31, 2006 and 2005, consolidated KCP&L’s balance sheets reflect a note payable from HSS to Great Plains Energy of $0.5 million.
 
13.  
COMMITMENTS AND CONTINGENCIES
 
Environmental Matters
The Company is subject to regulation by federal, state and local authorities with regard to air quality 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.regulations. At December 31, 20052006 and 2004,2005, KCP&L had $0.3 million accrued for environmental remediation expenses. The accrual covers 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 continuouslycontinually introduced in Congress. Such legislation typically includes various compliance dates and compliance limits. Such legislation could have the potential for a significant financial impact on KCP&L, including the installation ofcost to install new pollution control equipment to achieve compliance. However, KCP&L would seek recovery of capital costs and expenses for such compliance
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through rates.rate increases; however, there can be no assurance that such rate increases would be granted. KCP&L will continue to monitor proposed legislation.
 
The change in political control of both chambers in Congress raises the possibility that legislation will be enacted to address global climate change and impose a national mandate to produce a set percentage of electricity from renewable forms of energy, such as wind. The probability and impact of such language is difficult to quantify at this time.
The following table contains current estimates of expenditures to comply with environmental laws and regulations described below. The ultimate cost of these regulations could be significantly different from the amounts estimated. The range of estimated expenditures increased significantly in 2006 primarily due to the demand for environmental projects increasing 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 $375-993$- $375-9932006 - 2015
Incremental BART  - 272-527272-5272006 - 2017
Incremental CAMR 11-155-616-212010 - 2018
Estimated required environmental expenditures $386-1,008$277-533$663-1,541 
            
          
Comprehensive Energy Plan Retrofits
 
Missouri
  
Kansas
  
Total
 
 (millions)
Total estimated environmental expenditures$255-264$168-179$423-443
Less: expenditures through December 31, 2006 25  31  56 
Remaining balance$230-239$137-148$367-387
          
              
Clean Air Estimated Required
            
Estimated
Environmental Expenditures
 
Missouri
 
Kansas
 
Total
Timetable
  (millions) 
CAIR $395-575 $ -  $395-5752005 - 2015
Incremental BART 55-85 225-325 280-4102005 - 2013
Incremental CAMR 48-70 4-6 52-762010 - 2018
Comprehensive energy plan retrofits (171) (101)  (272)2006 - 2008
Estimated required environmental expenditures in            
   excess of the comprehensive energy plan retrofits$327-559 $128-230 $455-789 
              
Expenditure estimates provided in the first table above include, but are not limited to, the accelerated environmental upgrade expenditures included in the MPSC and KCC orders discussed in Note 5.
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KCP&L’s comprehensive energy plan. These expenditures are expected to reduce SO2, NOx, mercury and air particulate matter. KCP&L’s expectation is that any such expenditures will be recovered through rates.matter emissions.

Clean Air Interstate Rule
The Environmental Protection Agency (EPA) Clean Air Interstate Rule (CAIR) requires reductions in SO2 and NOx emissions in 28 states, including Missouri, and became effective July 11, 2005.Missouri. The reduction in both SO2 and NOx emissions will be accomplished through establishment of permanent statewide caps for NOx effective January 1, 2009, and SO2 effective January 1, 2010. More restrictive caps will be effective on January 1, 2015. KCP&L’s coal-firedfossil fuel-fired plants located in Missouri are subject to CAIR, while its coal-firedfossil 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 will establishhas developed a State Implementation Plan (SIP) rule, which includes an emission allowance allocation mechanism, throughand has published, held a State Implementation Plan (SIP) that is expected to be issued by December 2006.hearing, received comments and approved the proposed rule. Facilities will demonstrate compliance with CAIR by holding sufficient allowances for each ton of SO2 and NOx emitted in any given year with SO2 emission allowances transferable among all regulated
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facilities nationwide and NOx 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 banked fromaccumulated during previous years of the Acid Rain Program to meet the more stringent CAIR requirements. At December 31, 2005,2006, KCP&L had over 125,000accumulated unused SO2 emission allowances sufficient to support just under 120,000 tons of SO2 emission allowances,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. During 2005, KCP&L sold SO2 emission allowances for proceeds of $61.0 million. See Note 5 for more information.
 
Analysis of the final CAIR rule indicates that selective catalytic reduction technology for NOx control and scrubbers for SO2 control will likely be required for KCP&L’s Montrose station,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. KCP&L continues to refine the preliminary cost estimates detailed in the table above and explore alternatives. The ultimate cost of these regulations could be significantly different from the amounts estimated. As discussed below, certain of the control technology for SO2 and NOx will also aid in the control of mercury.
 
Best Available Retrofit Technology Rule
In 2005, theThe EPA published regulations on best available retrofit technology rule (BART) that amended its July 1999 regional haze regulations regarding emission controls for industrial facilities emittingdirects state air pollutants thatquality 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 visibility. Theemissions. BART regulations applyapplies to specific eligible facilities and were effective September 6, 2005. KCP&L coal-fired plants on the BART eligible list includeincluding LaCygne Nos. 1 and 2 in Kansas and Iatan No. 1 and Montrose No. 3 in Missouri. The CAIR suggests that states in CAIR that meet the CAIR requirementrequirements may also meet BART requirements for individual sources. Missouri is consideringhas included this proposalunderstanding as part of the proposed CAIR SIP, but no final decision has been reached.SIP. Kansas is not a CAIR state and therefore BART will likely impact LaCygne Nos. 1 and 2. TheKCP&L is in discussions with the Kansas Department of Health and Environment and anticipates submitting a BART rule directs state air quality agencies to identify whether emissions from sources subject toanalysis for LaCygne Station in early 2007. Kansas is in the process of reviewing BART are below limits setanalysis and modeling completed by the state, or whether retrofit measures are needed to reduce emissions.utilities with impacted facilities in the state. 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. KCP&L continues to refine its preliminary cost estimates detailed in the tablerequired above and explore alternatives. The ultimate cost of these regulations could be significantly different from the amounts estimated. comprehensive energy plan upgrades.
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Mercury Emissions
In 2000, the National Research Council published its findings of a study under the Clean Air Act, which stated that power plants that burn fossil fuels, particularly coal, generate the greatest amount of mercury emissions from man-made sources. In 2005, the EPA reversed its December 2000 finding that it was “appropriate and necessary” to regulate fossil fuel-fired power plants under section 112 of the Clean Air Act, concluding that the earlier finding lacked foundation and that recent information demonstrates that it is not appropriate or necessary to regulate fossil fuel-fired power plants under section 112. The EPA therefore removed coal- and oil-fired power plants from the section 112(c) list. Under section 112 of the Clean Air Act, the EPA would have been required to issue Maximum Available Control Technology standards for affected facilities and would have been prohibited from using cap and trade provisions for achieving compliance.
In 2005, the EPA published the Clean Air Mercury Rule (CAMR), which 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 was effective July 18, 2005, and 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. In Missouri, the CAMR SIP is following the same process and schedule as the CAIR SIP previously described above. In Kansas, the CAMR SIP has been published for public review and comment, and a hearing is scheduled.
 
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
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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. The ultimate cost of this rule could be significantly different from the amounts estimated in the table above. KCP&L is a participantparticipated in the DOE National Energy Technology Laboratory project at the Sunflower Electric Holcomb plant to investigate control technology options for mercury removal from coal-fired plants burning sub-bituminous coal.
 
In 2005, the EPA agreed to reconsider certain aspects of the rule and to invite additional comments on certain aspects of the rule. However, in its reconsideration notice, the EPA reiterated its position that the methodology used for the risk analysis performed to justify the CAMR is sound and scientifically justified. Comments were due in December 2005. The EPA’s actions to de-list mercury under section 112 of the Clean Air Act and issue CAMR remain controversial and subject to challenge.
Carbon Dioxide
At a December 1997 meeting in Kyoto, Japan, delegates from 167 nations, including the U.S., agreed to a treaty (Kyoto Protocol) that would require a 7% reduction in U.S.Many legislative bills concerning CO2 emissions below 1990 levels, a nearly 30% cut from current levels. In 2001, the Bush administration announced it will not negotiate implementation of the Kyoto Protocol and it will not send the Kyoto Protocol toare being debated in the U.S. SenateCongress. There are various compliance dates and nationwide caps stipulated in the numerous legislative bills being debated. These bills have the potential for ratification.  
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In 2002, President Bush unveiled his Clear Skies Initiative, which included a climate change policy. The climate change policysignificant financial impact on KCP&L in connection with achieving compliance with the proposed new nationwide limits. However, the financial consequences to KCP&L cannot be determined until final legislation 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. The administration's strategy is intended to reduce the greenhouse gas intensity of the U.S. economy by 18% over the next 10 years. 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 wouldpassed. Management will continue to grow, although at a slower rate than they would have withoutmonitor the progress of 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.bills.
 
In 2002, KCP&L joinedis 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. In 2003, the EEI sent a letter to numerous Administration officials, in which the EEI committed to work with the government over the next decade to reduce the power sector’s CO2 emissions per kWh generated (carbon intensity) by the equivalent of 3% to 5% of the current level. In 2004, 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 consistent with the EEI commitment of 3%decade. Power Partners’ January 2007 annual report indicates it is on track to 5%.reach that goal.
 
Air Particulate Matter and Ozone
In 1997,The Missouri Department of Natural Resources and the EPA revised ozoneKansas Department of Health and particulate matter air quality standards creating a new eight-hour ozone standardEnvironment continue to develop Missouri and establishing a new standardKansas Maintenance Plans for particulate matter less than 2.5 microns (PM-2.5) in diameter. In 2004, the EPA designatedControl of Ozone for the Kansas City area as attainment with respect to the PM-2.5 National Ambient Air Quality Standards (NAAQS). In 2005, thearea. The EPA published a final rule that designated Jackson, Platte, Clay and Cass counties inwill require Missouri and Johnson, Linn, Miami and Wyandotte counties in 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 attainment with respect toa violation of the eight-hour ozone NAAQS effective June 2, 2005.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
In 2004, theThe EPA finalized the Phase II rule implementing Section 316(b) of the Clean Water Act establishingestablished standards for cooling water intake structures at existing facilities.structures. This final regulation is applicableapplies 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 Section 316(b) comprehensive demonstration study on each of its generating facilities’ intake structures by the end of 2007, the2007. 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 restorationoperational measures to achieve compliance. Compliance with the final rulethis regulation is expected to be achieved between 2011 and 2014. Until the Section 316(b) comprehensive demonstration studies are completed, the impact of this final ruleregulation cannot be quantified.
A recent Federal appeals court decision may ultimately impact this regulation. The court remanded much of the regulation to the EPA for further rulemaking. At this time, the EPA has not acted on the court’s decision. Management will continue to monitor the litigation and any subsequent rulemaking associated with this regulation.
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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 Commitments
Great Plains Energy’s and consolidated KCP&L’s expenses related to lease commitments are detailed in the following table.
        
  
2005
 
2004
 
2003
 
   (millions)
Consolidated KCP&L $19.4 $18.4 $23.1 
Other Great Plains Energy (a)
  1.4  1.9  1.0 
Total Great Plains Energy $20.8 $20.3 $24.1 
(a) Includes insignificant amounts related to discontinued operations.
 
       
  
2006
 
2005
 
2004
  (millions)
Consolidated KCP&L $17.6 $19.4 $18.4
Other Great Plains Energy (a)
  1.3  1.4  1.9
Total Great Plains Energy $18.9 $20.8 $20.3
Great Plains Energy’s and consolidated KCP&L’s contractual commitments at December 31, 2005,2006, excluding pensions and long-term debt are detailed in the following tables.
Great Plains Energy Contractual Commitments
           
  
2007
 
2008
 
2009
 
2010
 
2011
 
After 2011
 
Total
 
  (millions) 
Lease commitments $16.7 $16.4 $11.9 $9.0 $8.1 $82.3 $144.4 
Purchase commitments               
Fuel (a)
  130.9  121.4  65.7  65.7  11.4  185.3  580.4 
Purchased capacity  6.8  7.8  8.2  5.4  4.3  14.3  46.8 
Purchased power  741.8  330.5  223.2  165.2  82.1  13.3  1,556.1 
Comprehensive energy plan  498.8  361.0  130.1  15.2  -  -  1,005.1 
Other  36.3  22.6  4.7  10.5  3.9  22.5  100.5 
Total contractual commitments $1,431.3 $859.7 $443.8 $271.0 $109.8 $317.7 $3,433.3 
            
Great Plains Energy Contractual Commitments
           
  
2006
 
2007
 
2008
 
2009
 
2010
 
After 2010
 
Total
 
  (millions) 
Lease commitments $17.1 $15.4 $14.9 $10.7 $8.4 $91.0 $157.5 
Purchase commitments                      
Fuel (a)
  107.9  99.9  91.5  46.0  32.3  37.7  415.3 
Purchased capacity  5.4  6.8  7.8  8.2  5.4  18.6  52.2 
Purchased power  423.4  135.6  46.4  21.8  18.0  -  645.2 
Other  33.6  5.6  2.9  -  -  -  42.1 
Total contractual commitments $587.4 $263.3 $163.5 $86.7 $64.1 $147.3 $1,312.3 
(a)Fuel commitments consists of commitments for nuclear fuel, coal and coal transportation costs.
(a)
Fuel commitments consists of commitments for nuclear fuel, coal, coal transportation costs and natural gas.
 
           
Consolidated KCP&L Contractual Commitments
Consolidated KCP&L Contractual Commitments
           
Consolidated KCP&L Contractual Commitments
           
 
2006
 
2007
 
2008
 
2009
 
2010
 
After 2010
 
Total
  
2007
 
2008
 
2009
 
2010
 
2011
 
After 2011
 
Total
 
 (millions)  (millions) 
Lease commitments $15.9 $14.4 $14.0 $10.5 $8.4 $91.0 $154.2  $15.5 $15.4 $11.7 $9.0 $8.1 $82.3 $142.0 
Purchase commitments                            
Fuel (a)
  107.9 99.9 91.5 46.0 32.3 37.7 415.3   130.9  121.4  65.7  65.7 11.4 185.3 580.4 
Purchased capacity  5.4 6.8 7.8 8.2 5.4 18.6 52.2   6.8  7.8  8.2  5.4 4.3 14.3 46.8 
Comprehensive energy plan  498.8  361.0  130.1  15.2 - - 1,005.1 
Other  33.6 5.6 2.9 - - - 42.1   36.3  22.6  4.7  10.5 3.9 22.5 100.5 
Total contractual commitments $162.8 $126.7 $116.2 $64.7 $46.1 $147.3 $663.8  $688.3 $528.2 $220.4 $105.8 $27.7 $304.4 $1,874.8 
(a)Fuel commitments consists of commitments for nuclear fuel, coal and coal transportation costs.
(a)
Fuel commitments consists of commitments for nuclear fuel, coal, coal transportation costs and natural gas.
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Lease commitments end in 2028 and include insignificant amounts for capital leases. As the managing partner of three jointly owned generating units, KCP&L has entered into leases for railcars to serve those units. Consolidated KCP&L has reflected theThe entire lease commitment is reflected in the above amounts, although the other owners will reimburse KCP&L approximately $2.0 million per year ($22.721.4 million total).
 
KCP&L purchases capacity from other utilities and nonutility suppliers. Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable. KCP&L has capacity sales agreements not included above that total $11.4 million for 2006, $11.2 million per year for 2007 through 2010, $6.9 million in 2011 and $12.3$3.8 million after 2010.2011.
 
Purchased power represents Strategic Energy’s agreements to purchase electricity at various fixed prices to meet estimated supply requirements. Strategic Energy has energy sales contracts not included above for 2006 and 2007 totaling $41.1 million and $4.2 million, respectively. 
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Synthetic Lease
In 2001, KCP&L entered into a synthetic lease arrangement with a Lease Trust (Lessor) to finance the purchase, installation, assembly and construction of five combustion turbines and related property and equipment that added 385 MWs of peaking capacity. Rental payments under the lease, which reflects interest payments only, began in 2004 and were to end in October 2006. KCP&L exercised its early termination option in 2005 and purchased the leased property for $154.0$172.4 million. KCP&L’s expense for the synthetic lease was $2.0 million and $1.9 million in 2005 and 2004, respectively.
 
The Lease Trust, a special purpose entity, acting as LessorComprehensive energy plan represents KCP&L’s contractual commitment for projects included in its comprehensive energy plan. KCP&L expects to be reimbursed by other owners for their respective share of Iatan No. 2 and environmental retrofit costs included in the synthetic lease arrangement discussed above, was considered a variable interest entity under FIN No. 46. Because KCP&L had variable interestscomprehensive energy plan contractual commitments.  See Note 6 for estimated capital expenditures by major project. Other represents individual commitments entered into in the Lease Trust, including among other things, a residual value guarantee provided to the Lessor, KCP&L was the primary beneficiaryordinary course of the Lease Trust. The Lease Trust was consolidated in 2003, as required by FIN No. 46. As a result, Great Plains Energy’s and consolidated KCP&L’s depreciation expense increased $1.9 million, $5.1 million and $1.3 million in 2005, 2004 and 2003, respectively, with offsetting recognition of minority interest.business.
 
14.  
GUARANTEES
 
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 and indemnification of 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. The majority of these agreements guarantee the Company’s own future performance, so a liability for the fair value of the obligation is not recorded. Great Plains Energy has provided $258.7 million of guarantees to support certain Strategic Energy power purchases and regulatory requirements. At December 31, 2006, guarantees related to Strategic Energy are as follows:
·  Great Plains Energy direct guarantees to counterparties totaling $142.0 million, which expire in 2007,
·  Great Plains Energy indemnifications to surety bond issuers totaling $0.5 million, which expire in 2007,
·  Great Plains Energy guarantee of Strategic Energy’s revolving credit facility totaling $12.5 million, which expires in 2009 and
·  Great Plains Energy letters of credit totaling $103.7 million, which expire in 2007.
 
At December 31, 2005,2006, KCP&L had guaranteed, with a maximum potential of $3.9$2.9 million, energy savings under an agreement with a customer that expires over the next fourthree years. A subcontractor would indemnify KCP&L for any payments made by KCP&L under this guarantees.guarantee. This guarantee was entered into before December 31, 2002; therefore, a liability was not recorded in accordance with FIN No. 45, “Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Guarantees of Indebtedness of Others.”
 
15.  
LEGAL PROCEEDINGS
 
Union Pacific
In 2005, KCP&L filed a rate complaint case with the Surface Transportation Board (STB)STB charging that Union Pacific Railroad Company’s (Union Pacific) rates for transporting coal from the PRB in Wyoming to KCP&L’s Montrose
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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. Management anticipates filing opening evidence by mid-yearIn February 2006, the STB instituted a rulemaking to address issues regarding the cost test used in rail rate cases and the proper calculation of rail rate relief. As part of that order, the STB issuingdelayed hearing KCP&L’s case pending the outcome of the rulemaking, and declared that the results of the rulemaking would apply to KCP&L’s test. In October 2006, the STB issued its decision, towardadopting the endproposal set out in its rulemaking. This decision has been appealed by other parties to the Federal Circuit Court of 2007.Appeals for the District of Columbia. In July 2006, the STB directed KCP&L and Union Pacific to file comments in September 2006 on whether KCP&L’s complaint is within the STB’s jurisdiction. If the STB determines 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 finalized,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 allegesalleged various claims against Framatome related to the proposed design, licensing and installation of a digital control system. The suit seekssought recovery of approximately $16 million in damages from Framatome. Framatome removed the case to U.S. District Court for the  
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District of Kansas. Thereafter, the plaintiffs filed a motioncounterclaim against the three Wolf Creek owners seeking recovery of damages alleged to remandbe in excess of $20 million. In May 2006, the case back to Coffey County District Court.parties settled this case. The federal court has not yet decided that motion. Framatome has not yet filed its answer in the lawsuit.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. CertainPrior to 2006, certain defendants have beenwere 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-trial settlements with other defendants and an amount for KCP&L’s comparative fault (as determined by the jury), the verdict would have resultedKCP&L received proceeds of $38.9 million in an award against the defendant of approximately $97.6 million (of which KCP&L would have received $33 million2006 pursuant to the subrogation allocation agreement after payment of attorney’s fees)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). In response to post-trial pleadingsTravelers filed bysuit in the U.S. District Court for the Eastern District of Missouri in November 2005, against National Union, and KCP&L was added as a defendant in 2004,June 2006. The case was subsequently transferred to, and is pending in, the trial judge reduced the award against the defendant to $0.2 million. Both KCP&L and the defendant have appealed this case to theU.S. District Court of Appeals for the Western District of Missouri. Oral arguments are expectedTravelers seeks recovery of
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$10 million that KCP&L recovered in the first quarterApril 2001 lawsuit described in the preceding paragraph. Management is unable to predict the outcome of 2006.this litigation.
 
Emergis Technologies, Inc.
In March 2006, Emergis Technologies, Inc. f/k/a BCE Emergis Technologies, Inc. (Emergis) filed suit against KCP&L has received $204.8 million in insurance recoveries relatedFederal District Court for the Western District of Missouri, alleging infringement of a patent, entitled “Electronic Invoicing and Payment System.” This patent relates to property destroyedautomated 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 1999 explosion atcase was not resolved. Management does not expect the Hawthorn No. 5 generating unit. Recoveries received relatedoutcome of this litigation to property destroyedhave a significant impact on Great Plains Energy's or consolidated KCP&L's results of operations and subrogation settlements recorded as a recovery of capital expenditures have been recorded as an increase in accumulated depreciation.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 court has stayed the Wolf Creek case is on a court-ordered stay until at least October 2006further order of the court to allow for some of the earlier cases to be decided first.first by an appellate court. Another federalFederal 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 thethis 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 intoPower 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 have begun settlement discussions. Management believes the ultimate outcome of this matter will not have a significant 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. Mr. Haberstroh claims that he acquired an equity interest in Partners under the terms of his employment agreement and that through a series of transactions, Mr. Haberstroh’s equity interest became an equity interest in SE Holdings. In 2001, Mr. Haberstroh’s employment was terminated and SE Holdings redeemed his equity interest. Mr. Haberstroh is seeking the loss of his non-equity compensation (including salary, bonus and benefits) and equity compensation and associated distributions (his equity interest in SE Holdings).
Strategic Energy has filed a counterclaim against Mr. Haberstroh for breach of contract. SE Holdings, and its direct and indirect owners, have agreed to indemnify Strategic Energy and IEC against any judgment or settlement of Mr. Haberstroh’s claim that relates to his alleged equity interest in SE  
106110
Holdings, up to approximately $8 million plus any dividends or
County, Pennsylvania. In 2006, the suit was settled and as part of the settlement, Great Plains Energy acquired the remaining indirect interest received in relation to his alleged interest.Strategic Energy for an insignificant amount.
 
Class Action Complaint
In 2005, a class action complaint for breach of contract was filed against Strategic Energy. The plaintiffs purportedly represent the interests of customers in Pennsylvania who entered intoPower Supply Coordination Service Agreements (Agreement) for the bundled product in Pennsylvania. The complaint seeks monetary damages, attorney fees and costs and a declaration that the customers may terminate their Agreement with Strategic Energy. Strategic Energy has filed preliminary objections asking the court to order plaintiffs to file an amended complaint that conforms to applicable court rules.
Weinstein v. KLT Telecom
On December 31, 2001, a subsidiary ofRichard 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) and its subsidiaries Digital Teleport Inc. (Digital Teleport) and Digital Teleportin February 2001 through the purchase of Virginia, Inc., filed separate voluntary petitions in the Bankruptcy Court for the Eastern District of Missouri for reorganization under Chapter 11approximately two-thirds of the U.S. Bankruptcy Code. DTI Holdings and its two subsidiaries are collectively called “DTI.” In 2003, the Bankruptcy Court confirmed the plan of reorganization for these three companies, which included the sale of substantially all assets. KLT Telecom received $19.2 million in 2003 related to the confirmation of the DTI bankruptcy.
KLT Telecom originally acquired a 47% interest in DTI in 1997. On February 8, 2001, KLT Telecom acquired control of DTIstock held by purchasing shares from another Holdings shareholder, Richard D. Weinstein (Weinstein), increasing its ownership to 83.6%.Weinstein. In connection with thisthat purchase, KLT Telecom entered into a put option in favor of Weinstein, which granted Weinstein a put option.an option to sell to KLT Telecom his remaining shares of Holdings stock. The put option provided for the sale by Weinstein of his remaining shares in Holdings to KLT Telecom during a period beginning September 1, 2003, and ending August 31, 2005. The put option provides for an aggregate exercise price for thesethe remaining shares equal to their fair market value with an aggregate floor amount of $15 million. The floor amount of the put optionmillion and was fully reserved during 2001. Onexercisable between September 2,1, 2003, Weinstein delivered to KLT Telecom notice of the exercise of his put option. KLT Telecom declined to pay Weinstein any amount under the put option because, among other things,and August 31, 2005. In June 2003, the stock of Holdings had beenwas cancelled and extinguished pursuant to the joint Chapter 11 plan confirmed by the Bankruptcy Court. In September 2003, Weinstein has sueddelivered a notice of exercise of his claimed rights under the put option. KLT Telecom for allegedly breachingrejected the put optionnotice of exercise, and seeksWeinstein filed suit, alleging breach of contract. Weinstein sought damages of at least $15 million, plus statutory interest. In April 2005, summary judgment in the Weinstein litigation was granted in favor of KLT Telecom, and Weinstein has appealed this judgment to the Missouri Court of Appeals for the Eastern District. In May 2006, the Court of Appeals affirmed the judgment. In July 2006, Weinstein filed an application for transfer of this case to the Missouri Supreme Court, which was granted. Oral arguments were presented to the Supreme Court in December 2006. The $15 million reserve has not been reversed pending the outcome of the appeal process, which management expects will conclude in early 2006.process.
 
16.  
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 2006, KCP&L incurred an ARO for decommissioning and site remediation of 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 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 was established to recognize funding of the related decommissioning trust in excess of the ARO due to the extended operating period.
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In 2005, FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” FIN No. 47 clarifies the term conditional ARO, as used in SFAS No. 143.143, “Accounting for Asset Retirement Obligations.” Conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Under FIN No. 47, an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. Great Plains Energy and consolidated KCP&L adopted the provisions of FIN No. 47 for the year ended December 31,in 2005.
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KCP&L management determined AROs exist for asbestos in certain fossil fuel plants and for an ash pond and landfill. The additional AROs at December 31,recorded in 2005 totaled $8.4 million for remediation of asbestos and $7.0 million for the remediation of the ash pond and landfill. In recording these AROs, net utility plant was increased $2.2 million and the $13.2 million net effect of adopting FIN No. 47 was recorded as a regulatory asset and had no impact on net income. The AROs were derived from third party and internal engineering estimates. To estimate the AROs, KCP&L used a credit-adjusted risk free discount rate of 5.6% for 12.5-year assets, 5.89% for 19.5-year asset and 6.12% for 29.5-year assets. The estimated rate was based on the rate KCP&L could issue bonds for the specific period.
 
In recording the AROs, net utility plant was increased by $2.2 million. KCP&L is a regulated utility subject to the provisions of SFAS No. 71 and management believes it is probable that any differences between expenseexpenses under FIN No. 47 or SFAS No. 143 and expense recovered currently in rates will be recoverable in future rates. As a result, the $13.2 million net effect of adopting FIN No. 47 was recorded as a regulatory asset; therefore, it had no impact on net income.
During 2005, KCP&L also recorded an addition to its ARO to decommission Wolf Creek of $11.3 million, which reflects a 2005 update to the decommissioning study cost estimates. To estimate the additional ARO, KCP&L used a credit-adjusted risk free discount rate of 5.89%. In recording the ARO addition, net utility plant was increased by $10.8 million. A related $0.5 million for accretion expense and depreciation was recorded as a regulatory asset; therefore, it had no impact on net income.
Revisions to the estimated liabilities of KCP&L could occur due to changes in the decommissioning or other cost estimates, extension of the nuclear operating license or changes in federal or state regulatory requirements.
The following table summarizes the change in Great Plains Energy’s and consolidated KCP&L’s AROs.
       
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  7.8  7.5 
Ending balance $91.8 $145.9 

      
      
December 31
 
2005
 
2004
 
  (millions) 
Beginning balance $113.7 $106.7 
Additions  26.7  - 
Settlements  (2.0) - 
Accretion  7.5  7.0 
   Ending balance $145.9 $113.7 
        
The following table illustrates the effect of FIN No. 47 related AROs if the provisions of FIN No. 47 had been applied beginning January 1, 2003. Pro forma amounts for the periods prior to adoption of FIN No. 47 were measured using assumptions consistent with the period of adoption.
        
December 31
 
2005
 
2004
 
2003
 
  (millions) 
Beginning balance $14.6 $13.8 $13.0 
Accretion  0.8  0.8  0.8 
Ending balance $15.4 $14.6 $13.8 
           
17.  
SEGMENTSEGMENTS 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,
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regulated electric utility, and Strategic Energy, a competitive electricity supplier. Other includes the operations of HSS, Services, all KLT Inc. operationsactivity other than Strategic Energy, unallocated corporate charges, consolidating entries and intercompany eliminations. Intercompany eliminations include insignificant amounts of intercompany financing relatedfinancing-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.
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The following tables reflect summarized financial information concerning Great Plains Energy’s reportable segments.
            
    
Strategic
   
Great Plains
 
2006
 
KCP&L
 
Energy
 
Other
 
Energy
 
  (millions) 
Operating revenues $1,140.4 $1,534.9 $-    $2,675.3 
Depreciation and amortization  (152.7) (7.8) -     (160.5)
Interest charges  (60.9) (2.1) (8.2)    (71.2)
Income taxes  (71.6) 12.7  11.0     (47.9)
Loss from equity investments  -  -  (1.9)    (1.9)
Net income (loss)  149.6  (9.9) (12.1)   127.6 
 
As Adjusted
    
Strategic
   
Great Plains
2005
  
KCP&L
  
Energy
  
Other
 
Energy
  (millions)
Operating revenues $1,130.8 $1,474.0 $0.1    $2,604.9 
Depreciation and amortization  (146.5) (6.4) (0.2)    (153.1)
Interest charges  (61.8) (3.4) (8.6)    (73.8)
Income taxes  (49.1) (16.6) 26.2     (39.5)
Loss from equity investments  -  -  (0.4)    (0.4)
Discontinued operations  -  -  (1.9)    (1.9)
Net income (loss)  145.2  28.2  (11.1)  162.3 
 
As Adjusted
    
Strategic
   
Great Plains
2004
  
KCP&L
  
Energy
  
Other
 
 Energy
  (millions)
Operating revenues $1,090.1 $1,372.4 $1.5    $2,464.0 
Depreciation and amortization  (144.3) (4.8) (1.0)    (150.1)
Interest charges  (73.7) (0.7) (8.6)    (83.0)
Income taxes  (56.7) (24.3) 25.5     (55.5)
Loss from equity investments  -  -  (1.5)    (1.5)
Discontinued operations  -  -  7.3     7.3 
Net income (loss)  151.7  42.5  (11.7)  182.5 
            
    
Strategic
   
Great Plains
 
  
KCP&L
 
Energy
 
Other
 
Energy
 
2006
 (millions) 
Assets $3,858.0 $459.6 $18.1    $4,335.7 
Capital expenditures  476.0  3.9  0.2   480.1 
As Adjusted
                
2005
                
Assets $3,336.3 $441.8 $63.7    $3,841.8 
Capital expenditures  332.2  6.6  (4.7)  334.1 
As Adjusted
                
2004
                
Assets $3,327.7 $407.7 $61.0    $3,796.4 
Capital expenditures  190.8  2.6  3.3   196.7 
                 
          
    
Strategic
  
Great Plains
2005
 
KCP&L
Energy
Other
Energy
  (millions) 
Operating revenues $1,130.8 $1,474.0 $0.1 $2,604.9 
Depreciation and amortization  (146.5) (6.4) (0.2) (153.1)
Interest charges  (61.8) (3.4) (8.6) (73.8)
Income taxes  (49.3) (16.6) 26.2  (39.7)
Loss from equity investments  -  -  (0.4) (0.4)
Discontinued operations, net of income taxes  -  -  (1.9) (1.9)
Net income (loss)  145.2  28.2  (11.1) 162.3 
              
   
 Strategic 
  
 Great Plains
2004
 
 KCP&L
 Energy
 Other
 Energy
 (millions) 
Operating revenues $1,090.1 $1,372.4 $1.5 $2,464.0 
Depreciation and amortization  (144.3) (4.8) (1.0) (150.1)
Interest charges  (73.7) (0.7) (8.6) (83.0)
Income taxes  (55.7) (24.3) 25.5  (54.5)
Loss from equity investments  -  -  (1.5) (1.5)
Discontinued operations, net of income taxes  -  -  7.3  7.3 
Net income (loss)  150.0  42.5  (11.7) 180.8 
              
   
 Strategic
  
 Great Plains
2003
 
 KCP&L
 Energy
 Other
 Energy
 (millions) 
Operating revenues $1,054.9 $1,091.0 $2.1 $2,148.0 
Depreciation and amortization  (139.9) (1.7) (1.2) (142.8)
Interest charges  (69.9) (0.4) (5.9) (76.2)
Income taxes  (84.4) (30.2) 36.0  (78.6)
Loss from equity investments  -  -  (2.0) (2.0)
Discontinued operations, net of income taxes  -  -  (44.8) (44.8)
Net income (loss)  127.2  39.6  (21.9) 144.9 
              
109113
          
    
Strategic
  
Great Plains
  
KCP&L
Energy
Other
Energy
2005
 (millions) 
Assets $3,334.6 $441.8 $57.3 $3,833.7 
Capital expenditures  332.2  6.6  (4.7) 334.1 
2004
             
Assets $3,330.2 $407.7 $61.0 $3,798.9 
Capital expenditures  190.8  2.6  3.3  196.7 
2003
             
Assets $3,293.5 $283.0 $105.5 $3,682.0 
Capital expenditures  148.8  3.1  -  151.9 
              
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 relatedfinancing-related activities.
         
      
Consolidated
 
2006
 
KCP&L
 
Other
 
KCP&L
 
  (millions) 
Operating revenues $1,140.4 $- $1,140.4 
Depreciation and amortization  (152.7) -  (152.7)
Interest charges  (60.9) (0.1) (61.0)
Income taxes  (71.6) 1.3  (70.3)
Net income (loss)  149.6  (0.3) 149.3 
           
As Adjusted
      
Consolidated
 
2005
  
KCP&L
  
Other
  
KCP&L
 
  (millions)
Operating revenues $1,130.8 $0.1 $1,130.9 
Depreciation and amortization  (146.5) (0.1) (146.6)
Interest charges  (61.8) -  (61.8)
Income taxes  (49.1) 1.1  (48.0)
Net income (loss)  145.2  (1.5) 143.7 
           
As Adjusted
      
Consolidated
 
2004
  
KCP&L
  
Other
  
KCP&L
 
  (millions)
Operating revenues $1,090.1 $1.5 $1,091.6 
Depreciation and amortization  (144.3) (0.9) (145.2)
Interest charges  (73.7) (0.5) (74.2)
Income taxes  (56.7) 2.9  (53.8)
Net income (loss)  151.7  (6.7) 145.0 
        
      
Consolidated
2005
 
KCP&L
Other
KCP&L
  (millions) 
Operating revenues $1,130.8 $0.1 $1,130.9 
Depreciation and amortization  (146.5) (0.1) (146.6)
Interest charges  (61.8) -  (61.8)
Income taxes  (49.3) 1.1  (48.2)
Net income (loss)  145.2  (1.5) 143.7 
           
     
 Consolidated
2004
 
 KCP&L
 Other
 KCP&L
 (millions) 
Operating revenues $1,090.1 $1.5 $1,091.6 
Depreciation and amortization  (144.3) (0.9) (145.2)
Interest charges  (73.7) (0.5) (74.2)
Income taxes  (55.7) 2.9  (52.8)
Net income (loss)  150.0  (6.7) 143.3 
           
     
 Consolidated
2003
 
 KCP&L
 Other
 KCP&L
  (millions) 
Operating revenues $1,054.9 $2.1 $1,057.0 
Depreciation and amortization  (139.9) (1.1) (141.0)
Interest charges  (69.9) (0.4) (70.3)
Income taxes  (84.4) 0.9  (83.5)
Discontinued operations, net of income taxes  -  (8.7) (8.7)
Net income (loss)  127.2  (10.0) 117.2 
           
         
      
Consolidated
 
  
KCP&L
 
Other
 
KCP&L
 
2006
 (millions) 
Assets $3,858.0 $1.5 $3,859.5 
Capital expenditures  476.0  -  476.0 
As Adjusted
          
2005
  
Assets $3,336.3 $3.9 $3,340.2 
Capital expenditures  332.2  -  332.2 
As Adjusted
          
2004
          
Assets $3,327.7 $7.2 $3,334.9 
Capital expenditures  190.8  -  190.8 
110
        
      
Consolidated
  
KCP&L
Other
KCP&L
2005
 (millions) 
Assets $3,334.6 $3.9 $3,338.5 
Capital expenditures  332.2  -  332.2 
2004
          
Assets $3,330.2 $7.2 $3,337.4 
Capital expenditures  190.8  -  190.8 
2003
          
Assets $3,293.5 $9.1 $3,302.6 
Capital expenditures  148.8  -  148.8 
           

18.  
SHORT-TERM BORROWINGS AND SHORT-TERM BANK LINES OF CREDIT
 
During 2006, Great Plains Energy hasentered 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 that expires in December 2009.banks. A default by Great Plains Energy or any of its significant subsidiaries ofon other indebtedness totaling more than $25.0 million is a default under the facility. Under the terms of this agreement, Great Plains
114
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 December 31, 2005,2006, the Company was in compliance with this covenant. At December 31, 2006, Great Plains Energy had no cash borrowings and had issued letters of credit totaling $103.7 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. At December 31, 2004, Great Plains Energy had $20.0 million of outstanding borrowings with an interest rate of 3.04% and had issued letters of credit totaling $8.0 million under the credit facility as credit support for Strategic Energy.
 
During 2006, KCP&L hasentered into a $250five-year $400 million revolving credit facility with a group of banks that expires in December 2009, 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 December 31, 2005,2006, KCP&L was in compliance with this covenant. At December 31, 2006, KCP&L had $156.4 million of commercial paper outstanding, at a weighted-average interest rate of 5.38%, issued $8.7 million of letters of credit and had 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. The weighted-average interest rate of the commercial paper was 4.35%. At December 31, 2004, KCP&L had no cash borrowings or commercial paper outstanding.
 
During 2005, Strategic Energy entered into an amendment to its $125has a $135 million revolving credit facility with a group of banks. The amendment extends the expiration of the facility frombanks that expires in June 2007 to June 2009 and increases the aggregate revolving loan commitment from $125 million to $135 million. So2009. As long as thereStrategic Energy is no default or unmatured default, Strategic Energyin 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, has currently guaranteedas permitted by the terms of the agreement, requested and received a reduction in its guarantee of this facility from $25.0 million ofto $12.5 million. Under this facility.facility, Strategic Energy’s maximum it may loan to Great Plains Energy is $20 million. A default by Strategic Energy ofon other indebtedness, as defined in the facility, totaling more than $7.5 million is a default under the facility. Under the terms of this amended 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 amended 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 December 31, 2005,
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2006, Strategic Energy was in compliance with these covenants. At December 31, 2005, $75.22006, $59.8 million in letters of credit had been issued and there were no cash borrowings under the agreement. At December 31, 2004, $69.22005, $75.2 million in letters of credit had been issued and there were no cash borrowings under the agreement.
 
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19.  
LONG-TERM DEBT AND EIRR BONDS CLASSIFIED AS CURRENT LIABILITIES
 
Great Plains Energy and consolidated KCP&L’s long-term debt is detailed in the following table.
                
   
December 31
    
December 31
 
 
Year Due
 
2005
 
2004
  
Year Due
   
2006
 
2005
 
Consolidated KCP&L
   (millions)      (millions) 
General Mortgage Bonds                
7.95% Medium-Term Notes  2007 $0.5 $0.5   2007    $0.5 $0.5 
3.45%* EIRR bonds  2012-2035 158.8 158.8 
3.84%* EIRR bonds  2012-2035     158.8  158.8 
Senior Notes                    
7.125%  2005 - 250.0 
6.00%  2007 225.0 225.0   2007     225.0  225.0 
6.50%  2011 150.0 150.0   2011     150.0  150.0 
6.05%  2035 250.0 -   2035     250.0  250.0 
Unamortized discount    (1.8) (0.6)       (1.6) (1.8)
EIRR bonds                    
4.75% Series A & B  2015 104.6 107.0   2015     105.2  104.6 
2.38% Series C    - 50.0 
4.75% Series D  2017 39.3 40.2   2017     39.5  39.3 
4.65% Series 2005  2035 50.0 -   2035     50.0  50.0 
2.10% Combustion Turbine Synthetic Lease    - 145.3 
Current liabilities                     
Current maturities        (225.5) - 
EIRR bonds classified as current    - (85.9)        (144.7) - 
Current maturities     - (250.0)
Total consolidated KCP&L excluding current liabilities    976.4 790.3 
Total consolidated KCP&L excluding current maturities        607.2  976.4 
                     
Other Great Plains Energy
                     
7.70%* Affordable Housing Notes  2006-2008 2.6 5.8 
7.74% Affordable Housing Notes  2007-2008     0.9  2.6 
4.25% FELINE PRIDES Senior Notes  2009 163.6 163.6   2007     163.6  163.6 
Current maturities   (1.7) (3.2)      (164.2) (1.7)
Total consolidated Great Plains Energy excluding current maturities Total consolidated Great Plains Energy excluding current maturities$1,140.9 $956.5 Total consolidated Great Plains Energy excluding current maturities  $607.5 $1,140.9 
* Weighted-average interest rates as of December 31, 2005        
        
* Weighted-average interest rates at December 31, 2006.* Weighted-average interest rates at December 31, 2006.           
Amortization of Debt Expense
Great Plains Energy’s and consolidated KCP&L’s amortization of debt expense is detailed in the following table.
        
  
2006
 
2005
 
2004
 
    (millions)   
Consolidated KCP&L $1.9 $2.3 $2.1 
Other Great Plains Energy  0.7  0.7  1.8 
Total Great Plains Energy $2.6 $3.0 $3.9 
        
  
2005
 
2004
 
2003
 
    (millions)   
Consolidated KCP&L $2.3 $2.1 $2.1 
Other Great Plains Energy  0.7  1.8  1.4 
   Total Great Plains Energy $3.0 $3.9 $3.5 
           
KCP&L General Mortgage Bonds
KCP&L has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented. The Indenture creates a mortgage lien on substantially all utility plant. Mortgage bonds secure $159.3 million of medium-term notes and Environmental Improvement
112
Revenue Refunding (EIRR) bonds at December 31, 20052006 and 2004. In 2004, KCP&L redeemed $54.5 million of its medium-term notes at maturity.
2005.
 
DuringIn 2005, KCP&L redeemed its secured 1994 series EIRR bonds totaling $35.9 million by issuing secured EIRR Bonds Series 2005 also totaling $35.9 million: $14.0 million at a fixed rate of 4.05% until maturity at March 1, 2015, and $21.9 million at a fixed rate of 4.65% until maturity at September 1, 2035. The previous interest rate periods on this series, with an interest rate of 2.25%, expired on August 31, 2005. This series was classified as a current liability at December 31, 2004. The new EIRR Bonds Series 2005 is covered by a municipal bond insurance policy issued by XL Capital Assurance Inc. (XLCA). The insurance agreement between KCP&L and XLCA is described below.
 
In 2004, KCP&L secured a municipal bond insurance policy as a credit enhancement to its secured 1992 series EIRR bonds totaling $31.0 million. This municipal bond insurance policy replaced a 364-day credit facility with a bank, which expired in August 2004 and previously supported full liquidity of these bonds. These variable-rate secured EIRR bonds with a final maturity in 2017 are remarketed on a weekly basis through a Dutch auction process. The insurance agreement between KCP&L and XLCA is described below.
116
KCP&L Unsecured Notes
KCP&L had $625.0 million of outstanding unsecured senior notes at December 31, 2006 and 2005. 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 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.
KCP&L had $196.5 million of unsecured EIRR bonds outstanding excluding the fair value of interest rate swaps of a $1.8 million and a $2.6 million liability in 2006 and $0.7 million asset at December 31, 2005, and 2004, respectively. The interest rates swaps resulted in an effective rate of 5.43%5.85% for the Series A, B and D EIRR bonds at December 31, 2005.in 2006. During 2005, KCP&L redeemed its unsecured Series C EIRR bonds totaling $50.0 million by issuing unsecured EIRR Bonds Series 2005 also totaling $50.0 million at a fixed rate of 4.65% until maturity at September 1, 2035. The previous interest rate period on this series, with an interest rate of 2.38%, expired on August 31, 2005. The Series C EIRR bonds were classified as current liabilities at December 31, 2004. The new EIRR Bonds Series 2005 is covered by a municipal bond insurance policy issued by XLCA. The insurance agreement between KCP&L and XLCA is described below.
 
KCP&L had $625.0 million of outstanding unsecured senior notes at December 31, 2005 and 2004. Forward Starting Swaps
During 2005, KCP&L privately issued $250.0 million of 6.05% unsecured senior notes, maturing in 2035. The proceeds from the issuance were used to repay the 7.125% unsecured senior notes that matured in 2005.2006, KCP&L entered into two Treasury Locks (T-Locks)Forward Starting Swaps (FSS) with a combined notional principal amount of $225.0 million to hedge against interest rate fluctuationsvolatility on the U.S. Treasury rate componentanticipated refinancing of this issuance. As a result, the effective interest rate on theseKCP&L’s $225.0 million senior notes was 5.78% at December 31, 2005.that mature in March 2007. See Note 2122 for more information about the T-Locks.additional information.
KCP&L exercised its early termination option in the Combustion Turbine Synthetic Lease and purchased the leased property during 2005.

Municipal Bond Insurance Policies
The insurance agreements between KCP&L and XLCA provide for reimbursement by KCP&L for any amounts that XLCA pays under the municipal bond insurance policies. The insurance policies are in effect for the term of the bonds. The insurance agreements contain a covenant that the indebtedness to total capitalization ratio of KCP&L and its consolidated subsidiaries will not be greater than 0.68 to 1.00. At December 31, 2005,2006, KCP&L was in compliance with this covenant. KCP&L is also restricted from issuing additional bonds under its General Mortgage Indenture if, after giving effect to such additional bonds, the proportion of secured debt to total indebtedness would be more than 75%, or more than 50% if the long term rating for such bonds by Standard & Poor’s or Moody’s Investors Service would be at or below A- or A3, respectively. The insurance agreement covering the unsecured EIRR Bond Series 2005 also requires KCP&L to provide XLCA with $50.0 million of general mortgage
113
bonds as collateral for KCP&L’s obligations under the insurance agreement in the event KCP&L issues general mortgage bonds (other than refundings of outstanding general mortgage bonds) resulting in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization. In the event of a default under the insurance agreements, XLCA may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.
 
Other Great Plains Energy Long-Term Debt
Great Plains Energy filed a registration statement, which became effective in April 2004, for the issuance of an aggregate amount up to $500.0 million of any combination of senior debt securities, subordinated debt securities, trust preferred securities and related guarantees, common stock, warrants, stock purchase contracts or stock purchase units. The prospectus filed with this registration statement also included $148.2 million of securities remaining available to be offered under a prior registration statement providing for an aggregate amount of availability of $648.2 million.
In June 2004, Great Plains Energy issued $163.6 million of FELINE PRIDES under this registration statement. After this transaction and the stock issuance discussed in Note 20, $171.0 million remains available under the registration statement. FELINE PRIDES, each with a stated amount of $25, initially consist of an interest in a senior note due February 16, 2009, and a contract requiring the holder to purchase the Company’s common stock on February 16, 2007. Each purchase contract obligates the holder of the purchase contract to purchase, and Great Plains Energy to sell, on February 16, 2007, for $25 in cash, newly issued shares of the Company’s common stock equal to the settlement rate. The settlement rate will vary according to the applicable market value of the Company’s common stock at the settlement date. Applicable market value will be measured by the average of the closing price per share of the Company’s common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding February 16, 2007. The settlement rate will be applied to the 6.5 million FELINE PRIDES at the settlement date to issue a number of common shares determined as described in the following table.
Applicable
Settlement rate
Market value
market value
(in common shares)
per common share (a)
$35.40 or greater0.7062 to 1Greater than $25 per common share
$35.40 to $30.00$25 divided by the applicableEqual to $25 per common share
market value to 1
$30.00 or less0.8333 to 1Less than $25 per common share
(a) Assumes that the market price of the Company’s common stock on February 16, 2007, is the
    same as the applicable market value.
Great Plains Energy makes quarterly contract adjustment payments at the rate of 3.75% per year and interest payments at the rate of 4.25% per year both payable in February, May, August and November of each year. Great Plains Energy must attempt to remarket the senior notes, in whole but not in part. If the senior notes are not successfully remarketed between August 16, 2006 and February 16, 2007, Great Plains Energy will exercise its rights as a secured party to dispose of the senior notes in accordance with applicable law and satisfy in full each holder’s obligation to purchase the Company’s common stock under the purchase contracts.
The June 2004 fair value of the contract adjustment payments of $15.4 million was recorded as a liability in other deferred credits and other liabilities with a corresponding amount recorded as capital stock premium and expense on Great Plains Energy’s consolidated balance sheet. Expenses incurred with the offering were allocated between the senior notes and the purchase contracts. Expenses allocated to the senior notes of $1.2 million have been deferred and are being recognized as interest   
114
expense over the term of the notes. Expenses allocated to the purchase contracts of $4.2 million were recorded as capital stock premium and expense. Great Plains Energy has the right to defer the contract adjustment payment on the purchase contracts, but not the interest payments on the senior notes. In the event Great Plains Energy exercises its option to defer the payment of contract adjustment payments, Great Plains Energy and its subsidiaries are not permitted to, with certain exceptions, declare or pay dividends on, make distributions with respect to, or redeem, purchase or acquire, or make a liquidation payment with respect to, any capital stock of Great Plans Energy until the deferred contract adjustment payments have been paid.
KLT Investments' affordable housing notes are collateralized by the affordable housing investments. Most of the notes also require the greater of 15% of the outstanding note balances or the next annual installment to be held as cash, cash equivalents or marketable securities. At December 31, 20052006 and 2004,2005, the collateral was held entirely as cash and totaled $0.6 million and $1.9 million, respectively.
In 2006, Great Plains Energy entered into a T-Lock with a notional principal amount of $77.6 million to hedge against interest rate fluctuation on future issuances of long-term debt. See Note 22 for additional information.
Great Plains Energy’s $163.6 million of FELINE PRIDES each with a stated amount of $25, initially consisted of an interest in a senior note due February 16, 2009, and $3.7a contract requiring the holder to purchase the Company’s common stock on February 16, 2007. Great Plains Energy made quarterly contract adjustment payments at the rate of 3.75% per year and interest payments at the rate of 4.25%
117
per year both payable in February, May, August and November of each year. Each purchase contract obligated the holder of the purchase contract to purchase, and Great Plains Energy to sell, on February 16, 2007, for $25 in cash, newly issued shares of the Company’s common stock equal to the settlement rate. The settlement rate was determined according to the applicable market value of the Company’s common stock at the settlement date. The applicable market value of $31.58 was measured by the average of the closing price per share of the Company’s common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding February 16, 2007. The settlement rate of 0.7915 was applied to the 6.5 million respectively.FELINE PRIDES at February 16, 2007, and Great Plains Energy issued 5.2 million shares of common stock. The $163.6 million FELINE PRIDES senior notes originally matured in 2009, but were to be remarketed between August 16, 2006 and February 16, 2007. Great Plains Energy exercised its rights to redeem the $163.6 million FELINE PRIDES senior notes in full satisfaction of each holder’s obligation to purchase the Company’s common stock under the purchase contracts.
 
Scheduled Maturities
Great Plains Energy's and consolidated KCP&L's long-term debt maturities for the next five years are detailed in the following table.
            
  
2006
 
2007
 
2008
 
2009
 
2010
 
      (millions)     
Consolidated KCP&L $- $225.5 $- $- $- 
Other Great Plains Energy (a)
  1.7  0.5  0.3  163.6  - 
    Total Great Plains Energy $1.7 $226.0 $0.3 $163.6 $- 
(a) FELINE PRIDES senior notes totaling $163.6 million mature in 2009, but must be remarketed
    between August 16, 2006 and February 16, 2007.
            
  
2007
 
2008
 
2009
 
2010
 
2011
 
   (millions) 
Consolidated KCP&L $225.5 $- $- $- $150.0 
Other Great Plains Energy  164.1  0.3  -  -  - 
Total Great Plains Energy $389.6 $0.3 $- $- $150.0 
                 
20.  
COMMON SHAREHOLDERS’ EQUITY AND PREFERRED STOCK
 
Great Plains Energy filed a shelf registration statement with the Securities and Exchange Commission (SEC) in 2006 relating to Senior Debt Securities, Subordinated Debt Securities, shares of Common Shareholders’ Equity
Stock, Warrants, Stock Purchase Contracts and Stock Purchase Units. In 2004,2006, Great Plains Energy issued 5.05.2 million shares of common stock at $30$27.50 per share under the shelf registration statement discussed in Note 19 with $150.0$144.3 million in gross proceeds. Issuanceproceeds and issuance costs of $5.4$5.2 million.
In 2006, Great Plains Energy also entered into a forward sale agreement with Merrill Lynch Financial Markets, Inc. (forward purchaser) for 1.8 million are reflected in capital stock premiumshares of Great Plains Energy common stock. The forward purchaser borrowed and expense onsold the same number of shares of Great Plains Energy’s consolidated balance sheet and statementcommon stock to hedge its obligations under the forward sale agreement. Great Plains Energy did not initially receive any proceeds from the sale of common shareholders’ equity.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 solely by delivering 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 currently expects to net cash settle the forward sale agreement.
 
Treasury shares are held for future distribution upon exerciseissuance of options issuedshares in conjunction with the Company’s equity compensation plan.Long-Term Incentive Plan.
 
In 2006, Great Plains Energy has 3.0registered an additional 1.0 million shares of common stock registered with the SEC for aits Dividend Reinvestment and Direct Stock Purchase Plan, (Plan).bringing the total number of shares registered under this plan to 4.0 million. The Planplan allows for the purchase of common shares by
118
reinvesting dividends or making optional cash payments. Great Plains Energy can issue new shares or purchase shares on the open market for the Plan. At December 31, 2005, 2.02006, 1.0 million shares remained available for future issuances.
 
In 2006, Great Plains Energy has 9.3registered an additional 1.0 million shares of common stock registered with the SEC for a defined contribution savings plan. The Company matches employee contributions, subjectplan, bringing the total number of shares registered under this plan to limits.10.3 million. Shares issued under the plans may be either newly issued shares or shares purchased in the open market. At December 31, 2005, 0.62006, 1.2 million shares remained available for future issuances.
 
Great Plains Energy’s Articles of Incorporation contain a restriction related to the payment of dividends in the event common equity falls to 25% of total capitalization. If preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of Directors necessary to constitute a majority of the full Board of Directors. Under stipulations
115
with the MPSC and KCC, Great Plains Energy and KCP&L have committed to maintain consolidated common equity of not less than 30% and 35%, respectively.
 
Great Plains Energy made capital contributions to KCP&L of $225$134.6 million in 2004.2006. These contributions were usedmade to pay down long-term debt.fund comprehensive energy plan projects. At December 31, 2005,2006, KCP&L’s capital contributions from Great Plains Energy totaled $400$534.6 million and are reflected in common stock in the consolidated KCP&L balance sheet.
 
Preferred Stock
21.  
PREFERRED STOCK
At December 31, 2005,2006, 1.6 million shares of Cumulative No Par Preferred Stock, 390,000 shares of Cumulative Preferred Stock, $100 par value and 11.0 million shares of no par Preference Stock were authorized under Great Plains Energy’s Articles of Incorporation. All of the authorized shares of Cumulative Preferred Stock are issued and outstanding. Great Plains Energy has the option to redeem the $39.0 million of issued Cumulative Preferred Stock at prices approximating par or stated value.
 
21.22.  
DERIVATIVE INSTRUMENTS
 
The Company is 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 Company’s 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 Company’s liability portfolio to optimize the mix of fixed and floating rate debt within an established range. In addition, the Company 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 Company 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. Derivative instruments, excluding those instruments that qualify for the NPNS election which are accounted for by accrual accounting, are recorded on the balance sheet at fair value as an asset or liability. Changes in the fair value are recognized currently in net income unless specific hedge accounting criteria are met.
 
119
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 2006, KCP&L entered into two FSS to hedge against interest rate fluctuations on future issuances of long-term debt. 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 - Treasury Locks
In 2006, Great Plains Energy entered into a T-Lock to hedge against interest rate fluctuations on future issuances of long-term debt. The T-Lock will be settled simultaneously with the issuance of the long-term fixed rate debt. The T-Lock effectively removes most of the interest rate uncertainty with respect to the debt to be issued, thereby enabling Great Plains Energy to predict with greater assurance what its future interest costs on that debt will be. The T-Lock 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 T-Lock. The pre-tax gain or loss on the T-Lock recorded to OCI will be reclassified to interest expense over the life of the future debt issuance.
In 2005, KCP&L entered into two T-Locks to hedge against interest rate fluctuations on the U.S. Treasury rate component of the $250.0 million 30-year long-term debt that KCP&L issued. The T-Locks settled simultaneously with the issuance of the long-term fixed rate debt. The T-Locks removed the uncertainty with respect to the U.S. Treasury rate component of the debt to be issued, thereby enabling KCP&L to predict with greater assurance what its future interest costs on that debt would be. The T-Locks were accounted for as cash flow hedges and no ineffectiveness was recorded on the T-Locks. A pre-tax gain of $12.0 million on the T-Locks was recorded to OCI and is being reclassified to interest expense over the life of the issued 30-year debt. An insignificant amount was reclassified fromAt December 31, 2006, KCP&L had $11.5 million recorded in OCI to interest expense subsequent tofor the debt issuance.  
2005 T-Locks.
116
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. AtAs of December 31, 2005,2006, KCP&L did not have anyhad hedged 30% and 9% of its 2007 and 2008 projected natural gas usage hedged for retail load and firm MWh sales. The hedging instruments in place at December 31, 2004, were designated as cash flow hedges.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 2006, 2005 2004 or 2003. When the natural gas is purchased, the amounts in OCI are reclassified to fuel expense in the consolidated income statement.and 2004.
 
120
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 5.05.5 years and 3.15.0 years at December 31, 20052006 and 2004,2005, respectively.
 
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 2006, 2005 and 2004 included gainsa loss of $26.7 million, a gain of $3.3 million, and a gain of $3.2 million, respectively, due to ineffectiveness of the cash flow hedges. Strategic Energy did not record any gains or losses due to ineffectiveness during 2003.
In 2003, Strategic Energy terminated an agreement with a swap counterparty due to credit and performance concerns. Strategic Energy received a $4.8 million fair value settlement. The swap was designated as a cash flow hedge of a forecasted transaction and Strategic Energy management believed the forecasted transaction would occur. Accordingly, the $4.8 million settlement was reclassified to purchased power expense over the remaining term of the underlying transaction, which was completed in 2003.
 
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 as a component of purchased power expense were alosses of $30.0 million, $0.8 million loss, aand $1.5 million lossfor 2006, 2005 and an insignificant gain for 2005, 2004, and 2003, respectively.
 
The fair value of non-hedging derivatives at December 31, 2005,2006, 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. 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. In 2006 and 2005, Strategic Energy amortized $5.1 million and an insignificant amount, 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 after the amendment as a component ofto purchased power expense.
 
117121
The notional and recorded fair values of the Company’scompanies’ derivative instruments are summarized in the following table. The fair values of these derivatives are recorded on the consolidated balance sheets.
          
  
December 31
 
  
2006
 
2005
 
  
Notional
   
Notional
   
  
Contract
 
Fair
 
Contract
 
Fair
 
  
Amount
 
Value
 
Amount
 
Value
 
Great Plains Energy
 (millions) 
Swap contracts         
Cash flow hedges $477.5 $(38.9)$180.1 $27.2 
Non-hedging derivatives  37.1  (6.8) 35.5  - 
Forward contracts             
Cash flow hedges  871.5  (69.7) 106.5  17.6 
Non-hedging derivatives  250.7  (24.8) 178.3  3.6 
Anticipated debt issuance             
Forward starting swap  225.0  (0.4) -  - 
Treasury lock  77.6  0.2  -  - 
Interest rate swaps             
Fair value hedges  146.5  (1.8) 146.5  (2.6)
Consolidated KCP&L
             
Forward contracts             
Cash flow hedges  6.1  (0.5) -  - 
Anticipated debt issuance             
Forward starting swap  225.0  (0.4) -  - 
Interest rate swaps             
Fair value hedges  146.5  (1.8) 146.5  (2.6)
              
          
  
December 31
 
  
2005
 
2004
 
  
Notional
  
Notional
  
  
Contract
Fair
 
Contract
Fair
  
Amount
Value
 
Amount
Value
Great Plains Energy
 (millions) 
Swap contracts             
   Cash flow hedges $164.7 $23.8 $92.4 $4.5 
   Non-hedging derivatives  35.5  -  2.3  0.7 
Forward contracts             
   Cash flow hedges  121.9  21.0  23.0  1.6 
   Non-hedging derivatives  178.3  3.6  5.5  (2.2)
Interest rate swaps             
   Fair value hedges  146.5  (2.6) 146.5  0.7 
Consolidated KCP&L
             
Swap contracts             
   Cash flow hedges  -  -  6.3  (0.3)
Interest rate swaps             
   Fair value hedges  146.5  (2.6) 146.5  0.7 
              
The amounts recorded in accumulated OCI related to the cash flow hedges are summarized in the following table.
            
  
Great Plains Energy
 
Consolidated KCP&L
 
  
December 31
 
December 31
 
  
2006
   
2005
 
2006
 
2005
 
  (millions) 
Current assets $12.7    $35.8 $12.0 $11.9 
Other deferred charges  1.7     11.8  -  - 
Other current liabilities  (56.3)    1.6  (1.3) - 
Deferred income taxes  32.1     (20.5) (4.0) (4.5)
Other deferred credits  (35.3)  1.0  -  - 
Total $(45.1) $29.7 $6.7 $7.4 
    
  
Great Plains Energy
Consolidated KCP&L
  
December 31
December 31
  
2005
2004
2005
2004
  (millions)
Current assets $35.8 $2.5 $11.9 $(0.3)
Other deferred charges  11.8  0.9  -  - 
Other current liabilities  1.6  (0.5) -  - 
Deferred income taxes  (20.5) (0.8) (4.5) 0.2 
Other deferred credits  1.0  (0.9) -  - 
Total $29.7 $1.2 $7.4 $(0.1)
              
The amounts recorded in current assets and liabilities reflected inGreat Plains Energy's accumulated OCI in the table above at December 31, 2005, are2006, includes $54.3 million that is expected to be reclassified to expenses duringover the next twelve months for Great Plains Energy and consolidatedmonths.  Consolidated KCP&L.&L's accumulated OCI includes an insignificant amount that is expected to be reclassified to expense over the next twelve months.
118122
The amounts reclassified to expenses are summarized in the following table.
        
  
2006
 
2005
 
2004
 
Great Plains Energy
 (millions) 
Fuel expense $- $(0.5)$(0.7)
Purchased power expense  54.6  (35.6) (0.6)
Interest expense  (0.4) -  - 
Minority interest  -  -  0.2 
Income taxes  (22.4) 15.1  0.5 
OCI $31.8 $(21.0)$(0.6)
Consolidated KCP&L
          
Fuel expense $- $(0.5)$(0.7)
Interest expense  (0.4) -  - 
Income taxes  0.2  0.2  0.3 
OCI $(0.2)$(0.3)$(0.4)
           
        
  
2005
2004
2003
Great Plains Energy
     
Fuel expense $(0.5)$(0.7)$(0.8)
Purchased power expense  (35.6) (0.6) (9.0)
Minority interest  -  0.2  1.0 
Income taxes  15.1  0.5  3.8 
   OCI $(21.0)$(0.6)$(5.0)
Consolidated KCP&L
      
Fuel expense $(0.5)$(0.7)$(0.8)
Income taxes  0.2  0.3  0.3 
   OCI $(0.3)$(0.4)$(0.5)
           

22.23.  
JOINTLY OWNED ELECTRIC UTILITY PLANTS
KCP&L’s share of jointly owned electric utility plants in service at December 31, 2005,2006, is detailed in the following table.
           
   
Wolf Creek
LaCygne
Iatan No. 1
 
Wolf Creek
 
LaCygne
 
Iatan No. 1
 
   
Unit
Units
Unit
 
Unit
 
Units
 
Unit
 
   (millions, except MW amounts) (millions, except MW amounts) 
KCP&L's shareKCP&L's share 47 % 50%  70  % 47% 50% 70% 
                  
Utility plant in serviceUtility plant in service$1,414 $337 $263  $1,378 $346 $268 
Accumulated depreciationAccumulated depreciation 712 244 190   734  253  195 
Nuclear fuel, netNuclear fuel, net 28       39  -  - 
KCP&L's accredited capacity--MWs 548 711 456 (a)
(a)The Iatan No. 2 air permit limits KCP&L's accredited capacity of Iatan No. 1
to 456 MWs from 469 MWs until the air quality control equipment included
in the comprehensive energy plan is operational.
 
KCP&L's 2007 accredited capacity-MWs  548  709  
460 (a
)
(a)
The Iatan No. 2 air permit limits KCP&L's accredited capacity of Iatan No. 1 to 460 MWs from
469 MWs until the air quality control equipment included in the comprehensive energy plan is
operational.
Each owner must fund its own portion of the plant's operating expenses and capital expenditures. KCP&L’s share of direct expenses is included in the appropriate operating expense classifications in Great Plains Energy’s and consolidated KCP&L’s financial statements.
24.  
NEW ACCOUNTING STANDARDS
SFAS No. 157
In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP) and expands disclosures about fair value measurements. The statement does not require any new fair value measurements but provides guidance on how to measure fair value when required. SFAS No. 157 also emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. The provisions of this statement are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years and generally are to be applied prospectively as of the beginning of the fiscal year in which initially applied. Management is currently evaluating the impact of SFAS No. 157 and has not yet determined the impact on Great Plains Energy's and consolidated KCP&L's financial statements.
119123
FIN No. 48
In July 2006, the FASB issued FIN No. 48. See Note 10 for additional information.

23.25.  
QUARTERLY OPERATING RESULTS (UNAUDITED)
          
  
Quarter
 
Great Plains Energy
 
1st
 
2nd
 
3rd
 
4th
 
As Adjusted
 (millions, except per share amounts) 
2006
         
Operating revenue $559.2 $642.1 $818.5 $655.5 
Operating income  7.6  73.3  93.6  60.9 
Net income (loss)  (1.1) 38.4  55.9  34.4 
Basic and diluted earnings (loss) per common share  (0.02) 0.49  0.69  0.42 
As Adjusted
         
2005
  
Operating revenue $545.1 $631.7 $782.9 $645.2 
Operating income  42.4  59.6  126.5  54.5 
Income from continuing operations  20.5  23.7  89.9  30.1 
Net income  20.5  20.1  91.7  30.0 
Basic and diluted earnings per common         
share from continuing operations  0.27  0.31  1.20  0.40 
Basic and diluted earnings per common share  0.27  0.26  1.22  0.40 
         
  
Quarter
 
Great Plains Energy
 
1st
 
2nd
 
3rd
 
4th
 
2005
 (millions, except per share amounts) 
Operating revenue $545.1 $631.7 $782.9 $645.2 
Operating income  41.8  62.6  125.5  53.3 
Income from continuing operations  20.2  25.5  89.1  29.4 
Net income  20.2  21.9  90.9  29.3 
Basic and diluted earning per common             
   share from continuing operations  0.27  0.34  1.19  0.39 
Basic and diluted earning per common share  0.27  0.29  1.21  0.39 
2004
  
Operating revenue $541.5 $613.5 $714.8 $594.2 
Operating income  62.6  82.3  125.5  48.4 
Income from continuing operations  29.5  41.4  67.9  34.7 
Net income  27.3  41.6  75.9  36.0 
Basic and diluted earning per common             
   share from continuing operations  0.42  0.59  0.91  0.46 
Basic and diluted earning per common share  0.39  0.59  1.02  0.48 
              
          
  
Quarter
 
Consolidated KCP&L
 
1st
 
2nd
 
3rd
 
4th
 
As Adjusted
 (millions) 
2006
   
Operating revenue $240.4 $290.9 $359.3 $249.8 
Operating income  31.7  69.2  118.4  51.7 
Net income  13.0  36.6  69.5  30.2 
As Adjusted
         
2005
  
Operating revenue $233.3 $272.1 $353.0 $272.5 
Operating income  25.2  56.0  101.1  67.2 
Net income  10.6  27.2  69.7  36.2 
          
 
  
Quarter
 
Consolidated KCP&L
 
1st
 
2nd
 
3rd
 
4th
 
2005
 (millions) 
Operating revenue $233.3 $272.1 $353.0 $272.5 
Operating income  24.6  59.0  100.1  66.0 
Net income  10.3  29.0  68.9  35.5 
2004
  
Operating revenue $247.0 $275.0 $323.7 $245.9 
Operating income  49.7  68.3  111.3  37.8 
Net income  21.2  32.3  63.9  25.9 
              

Quarterly data is subject to seasonal fluctuations with peak periods occurring in the summer months.
120124
As a result of the retrospective application of FSP No. AUG AIR-1 discussed in Note 5, the following tables provide information to reconcile the quarterly operating results above to amounts originally reported.
          
  
Quarter
 
Great Plains Energy
 
1st
 
2nd
 
3rd
 
4th
 
2006
 (millions, except per share amounts) 
Operating income as previously reported $6.0 $72.0 $92.4  N/A 
Adjustment  1.6  1.3  1.2  N/A 
              
Net income (loss) as previously reported  (2.1) 37.6  55.2  N/A 
Adjustment  1.0  0.8  0.7  N/A 
              
Basic and diluted EPS as previously reported  (0.03) 0.48  0.68  N/A 
Adjustment  0.01  0.01  0.01  N/A 
2005
             
Operating income as previously reported $41.8 $62.6 $125.5 $53.3 
Adjustment  0.6  (3.0) 1.0  1.2 
              
Income from continuing operations             
as previously reported  20.2  25.5  89.1  29.4 
Adjustment  0.3  (1.8) 0.8  0.7 
              
Net income as previously reported  20.2  21.9  90.9  29.3 
Adjustment  0.3  (1.8) 0.8  0.7 
              
Basic and diluted EPS from continuing             
operations as previously reported  0.27  0.34  1.19  0.39 
Adjustment  -  (0.03) 0.01  0.01 
              
Basic and diluted EPS as previously reported  0.27  0.29  1.21  0.39 
Adjustment  -  (0.03) 0.01  0.01 
       ��      
          
  
Quarter
 
Consolidated KCP&L
 
1st
 
2nd
 
3rd
 
4th
 
2006
 (millions) 
Operating income as previously reported $30.1 $67.9 $117.2  N/A 
Adjustment  1.6  1.3  1.2  N/A 
              
Net income as previously reported  12.0  35.8  68.8  N/A 
Adjustment  1.0  0.8  0.7  N/A 
2005
             
Operating income as previously reported $24.6 $59.0 $100.1 $66.0 
Adjustment  0.6  (3.0) 1.0  1.2 
              
Net income as previously reported  10.3  29.0  68.9  35.5 
Adjustment  0.3  (1.8) 0.8  0.7 
              
125
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
Great Plains Energy Incorporated
Kansas City, Missouri
 
We have audited the accompanying consolidated balance sheets of Great Plains Energy Incorporated and subsidiaries (the “Company”) as of December 31, 20052006 and 2004,2005, and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005.2006.  Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Great Plains Energy Incorporated and subsidiaries as of December 31, 20052006 and 2004,2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005,2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects, the information set forth therein.
 
As discussed in Note 8 to the consolidated financial statements, the Company adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, on December 31, 2006. As discussed in Note 5 to the consolidated financial statements, the Company adopted FASB Staff Position (FSP) No. AUG AIR-1, Accounting for Planned Major Maintenance Activities, in 2006and retroactively revised the consolidated balance sheet as of December 31, 2005 and the consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for the years ended December 31, 2005 and 2004, for the change. As discussed in Note 16 to the consolidated financial statements, effective December 31, 2005, the Company changed its method of accounting for conditional asset retirement obligations to adopt FIN 47, “Accounting for Conditional Asset Retirement Obligations”.Obligations As discussed in Note 2 to the consolidated financial statements, in 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 of the Company and retroactively revised the statements of cash flows for the years ended December 31, 2004 and 2003, for the change..
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005,2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2006,February 27, 2007 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
 
/s/DELOITTE & TOUCHE LLP
 
Kansas City, Missouri
March 8, 2006February 27, 2007
 

121126
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors of
Kansas City Power & Light Company
Kansas City, Missouri
 
We have audited the accompanying consolidated balance sheets of Kansas City Power & Light Company and subsidiaries (the “Company”) as of December 31, 20052006 and 2004,2005, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005.2006. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Kansas City Power & Light Company and subsidiaries as of December 31, 20052006 and 2004,2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005,2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
 
As discussed in Note 8 to the consolidated financial statements, the Company adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, on December 31, 2006. As discussed in Note 5 to the consolidated financial statements, the Company adopted FASB Staff Position (FSP) No. AUG AIR-1, Accounting for Planned Major Maintenance Activities, in 2006 and retroactively revised the consolidated balance sheet as of December 31, 2005, and the consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for the years ended December 31, 2005 and 2004, for the change. As discussed in Note 16 to the consolidated financial statements, effective December 31, 2005, the Company changed its method of accounting for conditional asset retirement obligations to adopt FIN 47, “Accounting for Conditional Asset Retirement Obligations”Obligations. As discussed in Note 2 to the consolidated financial statements, in 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 of the Company and retroactively revised the statement of cash flows for the year ended December 31, 2003, for the change.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005,2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2006,February 27, 2007, expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
 
/s/DELOITTE & TOUCHE LLP
 
Kansas City, Missouri
March 8, 2006February 27, 2007
 
122127
ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.
 
ITEM 9A. 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). 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 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 internal control over financial reporting that occurred during the quarterly period ended December 31, 2005, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting, other than the implementation by Strategic Energy of a new energy supply-side management system, which converted manual controls to electronic controls with no change to control objectives.
There has been no change in KCP&L’s internal control over financial reporting that occurred during the quarterly period ended December 31, 2005,2006, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
 
Management’s Report on Internal Control Over Financial Reporting
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Great Plains Energy
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended) for Great Plains Energy. Under the supervision and with the participation of Great Plains Energy’s chief executive officer and chief financial officer, management evaluated the effectiveness of Great Plains Energy’s internal control over financial reporting as of December 31, 2005.2006. Management used for this evaluation the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. Management has concluded that, as
123
of December 31, 2005,2006, Great Plains Energy’s internal control over financial reporting is effective based on the criteria set forth in the COSO framework. Deloitte & Touche LLP, the independent registered public accounting firm that audited the financial statements included in this annual report on
Form 10-K, has issued its audit report on this assessment, which is included below.
 
128
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
Great Plains Energy Incorporated
Kansas City, Missouri
 
We have audited management's assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Great Plains Energy Incorporated and subsidiaries (the “Company”“ Company”) maintained effective internal control over financial reporting as of December 31, 2005,2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company'sCompany’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing, and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinions.
 
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005,2006, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
124
Organizations of the Treadway Commission.  Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005,2006, based on
129
the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2005,2006 of the Company and our report dated March 8, 2006,February 27, 2007 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company’s adoption of a new accounting standard and revisions made to the consolidated statements of cash flows for the years ended December 31, 2004 and 2003.standards.
 
/s/DELOITTE & TOUCHE LLP
 
Kansas City, Missouri
March 8, 2006February 27, 2007
 
KCP&L
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 15d-15(f) under the Securities Exchange Act of 1934, as amended) for KCP&L. Under the supervision and with the participation of KCP&L’s chief executive officer and chief financial officer, management evaluated the effectiveness of KCP&L’s internal control over financial reporting as of December 31, 2005.2006. Management used for this evaluation the framework in Internal Control - Integrated Framework issued by the COSO of the Treadway Commission. Management has concluded that, as of December 31, 2005,2006, KCP&L’s internal control over financial reporting is effective based on the criteria set forth in the COSO framework. Deloitte & Touche LLP, the independent registered public accounting firm that audited the financial statements included in this annual report on Form 10-K, has issued its audit report on this assessment, which is included below.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors of
Kansas City Power & Light Company
Kansas City, Missouri
 
We have audited management's assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Kansas City Power & Light Company and subsidiaries (the “Company”“ Company”) maintained effective internal control over financial reporting as of December 31, 2005,2006, based on criteria established in Internal Control - Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company'sCompany’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing, and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinions.
125
 
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar
130
functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005,2006, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005,2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statementstatements schedules as of and for the year ended December 31, 2005,2006 of the Company and our report dated March 8, 2006,February 27, 2007 expressedan unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company’s adoption of a new accounting standard and revisions made to the consolidated statement of cash flows for the year ended December 31, 2003.  standards.
 
/s/DELOITTE & TOUCHE LLP
 
Kansas City, Missouri
March 8, 2006February 27, 2007
 
ITEM 9B. OTHER INFORMATION
 
None.

PART III
 
ITEM 10. DIRECTORS, AND EXECUTIVE OFFICERS OF THE REGISTRANTSAND CORPORATE GOVERNANCE
 
Great Plains Energy Directors
The following information required by this item is incorporated by reference from the Great Plains Energy 20062007 Proxy Statement, which will be filed with the SEC no later than March 31, 2006April 30, 2007 (Proxy Statement):
126
 
·  Information regarding the directors of Great Plains Energy required by this item is contained in the Proxy Statement section titled “Election of Directors”.Directors.”
131
·  Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934 required by this item is contained in the Proxy Statement section titled “Section 16(a) Beneficial Ownership Reporting Compliance.”
 
·  Information regarding the Audit Committee of Great Plains Energy required by this item is contained in the sectionsProxy Statement section titled “Corporate Governance”, “Election of Directors” and “Director Independence”.Governance.”
KCP&L Directors
Great Plains Energy, as the sole shareholder of KCP&L, elects the directors of KCP&L. The directors of KCP&L are also directors of Great Plains Energy, and the Board committees of Great Plains Energy function as the Board committees of KCP&L. The nine individuals listed below are all of the current directors of KCP&L and have consented to stand for election to the Board of Great Plains Energy. If they are elected at the annual shareholders meeting on May 2, 2006, to serve on the Great Plains Energy Board, they will also be elected to the KCP&L Board to serve as directors until the next annual shareholders meeting and until their successors are elected and qualified. The committee information listed for each director refers to the Great Plains Energy Board committees, which function as the KCP&L Board committees.
David L. Bodde                                 Director since 1994
Dr. Bodde, 63, is the Senior Fellow and Professor, Arthur M. Spiro Center for Entrepreneurial Leadership at Clemson University (since 2004). He previously held the Charles N. Kimball Professor of Technology and Innovation (1996-2004) at the University of Missouri-Kansas City. He also serves on the board of The Commerce Funds. Dr. Bodde served as a member of the Executive, Audit and Governance committees during 2005.

Michael J. Chesser                              Director since 2003
Mr. Chesser, 57, is Chairman of the Board and Chief Executive Officer - Great Plains Energy and Chairman of the Board - KCP&L (since October 2003). Previously he served as Chief Executive Officer of United Water (2002-2003); and President and Chief Executive Officer of GPU Energy (2000-2002). Mr. Chesser served as a member of the Executive committee in 2005.
William H. Downey                              Director since 2003
Mr. Downey, 61, is President and Chief Operating Officer - Great Plains Energy and President and Chief Executive Officer - KCP&L (since October 2003). Mr. Downey joined the Company in 2000 as Executive Vice President - Kansas City Power & Light Company and President - KCPL Delivery Company. Mr. Downey also serves on the board of Enterprise Financial Services Corp.
Mark A. Ernst                                 Director since 2000
Mr. Ernst, 47, is Chairman of the Board, President and Chief Executive Officer of H&R Block, Inc., a global provider of tax preparation, investment, mortgage and accounting services. He was elected Chairman of the Board in 2002, Chief Executive Officer in 2001 and President in 1999. Mr. Ernst also serves on the board of Knight Ridder, Inc. Mr. Ernst served on the Executive, Audit and Compensation and Development committees during 2005.
Randall C. Ferguson, Jr.                           Director since 2002
Mr. Ferguson, 54, is the Senior Partner for Business Development for Tshibanda & Associates, LLC (since March 2005), a consulting and project management services firm committed to assisting clients to improve operations and achieve long-lasting, measurable results. Previously he served as Senior Vice President Business Growth &
127
Member Connections with the Greater Kansas City Chamber of Commerce (2003-2005) and the retired Senior Location Executive (1998-2003) for the IBM Kansas City Region. Mr. Ferguson served on the Audit and Governance committees during 2005.
Luis A. Jimenez                                Director since 2001
Mr. Jimenez, 61, is Senior Vice President and Chief Strategy Officer (since 2001) of Pitney Bowes Inc., a global provider of integrated mail and document management solutions. He served as Vice President, Global Growth and Future Strategy (1999-2001). Mr. Jimenez served on the Governance and Compensation and Development committees during 2005.
James A. Mitchell                               Director since 2002
Mr. Mitchell, 64, is the Executive Fellow-Leadership, Center for Ethical Business Cultures (since 1999), a not-for-profit organization, assisting business leaders in creating ethical and profitable cultures. Mr. Mitchell served on the Compensation and Development and Governance committees during 2005.
William C. Nelson                             Director since 2000
Mr. Nelson, 68, is Chairman (since 2001) of George K. Baum Asset Management, a provider of investment management services to individuals, foundations and institutions. He also serves on the board of DST Systems. Mr. Nelson served on the Executive, Audit and Compensation and Development committees during 2005.
Linda H. Talbott                            Director since 1983
Dr. Talbott, 65, is President of Talbott & Associates (since 1975), consultants in strategic planning, philanthropic management and development to foundations, corporations, and nonprofit organizations. She is also Chairman of the Center for Philanthropic Leadership. Dr. Talbott served as the Advising Director for Corporate Social Responsibility and on the Governance and Compensation and Development committees during 2005.
KCP&L Audit Committee
The KCP&L Board has designated the Audit Committee of the Great Plains Energy Board as the KCP&L Audit Committee for purposes of Section 10A of the Securities Exchange Act of 1934, as amended, and related rules. The members of the Audit Committee are Mark A. Ernst, David L. Bodde, Randall C. Ferguson, Jr., William K. Hall, William C. Nelson and Robert H. West. The Boards identified Messrs. Ernst, Hall, Nelson and West as “audit committee financial experts”, as that term is defined by the SEC pursuant to Section 407 of the Sarbanes-Oxley Act of 2002, and determined that those individuals are independent.
 
Great Plains Energy and KCP&L Executive Officers
Information required by this item regarding the executive officers of Great Plains Energy and KCP&L is contained in this report in the Part I, Item 1 sections titled “Officers of Great Plains Energy” and “Officers of KCP&L”.
 
Great Plains Energy and KCP&L Code of Ethics
The Company has adopted a Code of Business Conduct and Ethics (Code), which applies to all directors, officers and employees of Great Plains Energy, KCP&L and their subsidiaries. The Code is posted on the investor relations page of our Internet websites at www.greatplainsenergy.com and www.kcpl.com. A copy of the Code is available, without charge, upon written request to Corporate Secretary, Great Plains Energy Incorporated, 1201 Walnut, Kansas City, Missouri 64106. Great Plains Energy and KCP&L intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or a waiver from, a provision of the Code that applies to the principal executive officer, principal financial officer, principal accounting officer or controller of those companies by posting such information on the investor relations page of their Internet websites.
 
128
Section 16(a) Beneficial Ownership Reporting ComplianceOther KCP&L Information
The other information required by this item regarding compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, containedKCP&L has been omitted in the section titled “Security Ownership of Directors and Officers” of the Proxy Statement is incorporated by reference.reliance on General Instruction (I).
 
ITEM 11. EXECUTIVE COMPENSATION
 
GREAT PLAINS ENERGY
The information required by this item regarding compensation of Great Plains Energy directors and named executive officers contained in the sections titled “Corporate Governance”,Governance,” “Executive Compensation”,Compensation,” “Director Compensation,” “Compensation Discussion and DevelopmentAnalysis” and “Compensation Committee Report on Executive Compensation”, and “Stock Performance Graph”Report” of the Proxy Statement is incorporated by reference.
 
KCP&L
Summary Compensation Table
The following table contains compensation data forinformation required by this item regarding KCP&L executive officers named below, for fiscal years ended December 31, 2005, 2004 and 2003. The compensation shown for some executive officers is also includedhas been omitted in the Summary Compensation Table in the Proxy Statement.
         
  
Annual Compensation
Long Term Compensation
 
     
Awards
Payouts
 
Name and Principal Position
(a)
 
 
Year
(b)
Salary
($)
(c)
Bonus
($)
(d)
Other Annual Compensation ($) (1)
(e)
Restricted Stock
Award(s)
($)(2)
(f)
Securities Underlying Options/
SARs (#)
(g)
LTIP Payouts
($) (3)
(h)
All Other Compensation
($)(4)
(i)
Michael J. Chesser
   Chairman of the Board
2005
2004
2003
610,000
550,000
137,500
555,707
495,535
123,750
-
311,436
-
-
-
1,115,813
-
-
-
-
-
-
27,710
8,734
1,403
William H. Downey
   President and Chief
   Executive Officer
2005
2004
2003
440,000
400,000
325,000
395,292
270,292
219,375
-
-
-
-
-
1,001,998
-
-
5,249
85,947
-
-
39,210
27,562
20,764
Terry Bassham
   Chief Financial Officer
2005
2004
2003
210,069
-
-
141,998
-
-
76,119
-
-
275,942
-
-
-
-
-
-
-
-
3,228
-
-
Stephen T. Easley
   Senior Vice President-
   Supply
2005
2004
2003
250,000
225,000
210,000
147,798
116,684
94,500
-
-
-
302,000
-
128,378
-
-
2,449
40,086
-
-
14,381
11,972
10,737
John R. Marshall
   Senior Vice President-
   Delivery
2005
2004
2003
192,222
-
-
347,657
-
-
157,315
-
-
636,635
-
-
-
-
-
-
-
-
8,338
-
-
(1)The executive officers named above received certain perquisites from the Company, which may include relocation costs, transportation allowances, a tax and financial planning allowance of up to $1,500, dues for one club and in limited situations, the expenses of spouses accompanying the executive officers. With the exception of Messrs. Marshall and Bassham in 2005 and Mr. Chesser in 2004, perquisites did not reach in any of the reported years the threshold for reporting of the lesser of either $50,000 or ten percent of salary and bonus set forth in the applicable rules of the Securities and Exchange Commission.
For 2005, amounts include:
Marshall
·  Relocation Costs: $151,115
·  Transportation Allowance: $4,200
·  Club Dues: $500
·  Tax/Financial Planning: $1,500
Bassham
·  Relocation Costs: $69,173
·  Transportation Allowance: $5,400
·  Club Dues: $875
·  Spouse Travel: $671
129
For 2004, amounts include:
Chesser
·  Relocation Costs: $299,292
·  Transportation Allowance: $7,200
·  Club Dues: $1,150
·  Spouse Travel: $3,794
(2)  At Year-End 2005, amounts include:
   Restricted Stock: The dollar value of the restricted stock awards shown in Column (f) above is calculated by multiplying the number of shares awarded by the closing market price of the Great Plains Energy common stockreliance on the date of the grant. The grants of restricted stock vest over time. Unvested grants of restricted stock are forfeited in the event the executive’s employment with the Company is terminated (except in the events of retirement, disability or death, in which cases the grants would be prorated for service during the restriction period)General Instruction (I).
Chesser
12,135 shares vested October 1, 2005. 12,135 shares each vest on October 1, 2006 and October 1, 2007. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the remaining restricted stock was $678,589.
Downey
8,825 shares vested October 1, 2005. 8,825 shares vest on October 1, 2006, and 8,826 shares vest on October 1, 2007. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the remaining restricted stock was $493,522.
Bassham
9,083 shares vest March 28, 2008. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the restricted stock was $253,961.
Easley
10,000 shares vest on February 1, 2008. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the restricted stock was $279,600.
Marshall
20,275 shares of restricted stock were granted in 2005, vesting May 25, 2008. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the restricted stock was $566,889.
(3)The LTIP Payouts for 2005 represent the value of common stock and cash dividends paid under 2003 Performance Shares for the period ended 2005. The value of the payouts are calculated as of February 7, 2006, the date the payouts were approved by the Board.
(4)
    For 2005, amounts include:    
Chesser
·  Contribution under the Great Plains Energy Employee Savings Plus Plan: $6,300
·  Contribution under the Great Plains Energy Employee Savings Plus Plan accruing to the Great Plains Energy Non-Qualified Deferred Compensation Plan: $12,000
·  Flex dollars under the Great Plains Energy Flexible Benefits Plan: $6,835
·  Deferred flex dollars: $1,582
·  Above-market interest paid on compensation deferred pursuant to the Great Plains Energy Non-Qualified Deferred Compensation Plan: $993
Downey
·  Contribution under the Great Plains Energy Employee Savings Plus Plan: $6,300
·  Contribution under the Great Plains Energy Employee Savings Plus Plan accruing to the Great Plains Energy Non-Qualified Deferred Compensation Plan: $6,900
·  Flex dollars under the Great Plains Energy Flexible Benefits Plan: $6,253
·  Deferred flex dollars: $214
·  Above-market interest paid on compensation deferred pursuant to the Great Plains Energy Non-Qualified Deferred Compensation Plan: $19,543
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Bassham
·  Flex Dollars Under the Great Plains Energy Flexible Benefits Plan: $3,228
Easley
·  Contribution under the Great Plains Energy Employee Savings Plus Plan: $6,300
·  Contribution under the Great Plains Energy Employee Savings Plus Plan accruing to the Great Plains Energy Non-Qualified Deferred Compensation Plan: $1,200
·  Flex dollars under the Great Plains Energy Flexible Benefits Plan: $4,192
·  Above-market interest paid on compensation deferred pursuant to the Great Plains Energy Non-Qualified Deferred Compensation Plan: $2,689
Marshall
·  Contribution under the Great Plains Energy Employee Savings Plus Plan accruing to the Great Plains Energy Non-Qualified Deferred Compensation Plan: $5,200
·  Flex dollars under the Great Plains Energy Flexible Benefits Plan: $2,714
·  Above-market interest paid on compensation deferred pursuant to the Great Plains Energy Non-Qualified Deferred Compensation Plan: $424
Long-Term Incentive Plans - Awards in Last Fiscal Year
Name
(a)
Number of
Shares, Units or Other Rights (#)
(b)(1)
Performance or Other Period Until Maturation or Payout (c)
Estimated Future Payouts Under
Non-Stock Price-Based Plans
Threshold
($ or #)
(d)
Target
($ or #)
(e)
Maximum
($ or #)
(f)
Michael J. Chesser30,233 shares2 years ending 2006030,233 shares60,466 shares
30,233 shares3 years ending 2007030,233 shares60,466 shares
William H. Downey16,719 shares2 years ending 2006016,719 shares33,438 shares
16,719 shares3 years ending 2007016,719 shares33,438 shares
Terry Bassham6,358 shares3 years ending 200706,358 shares12,716 shares
John R. Marshall7,096 shares3 years ending 200707,096 shares14,192 shares
Stephen T. Easley5,782 shares2 years ending 200605,782 shares11,564 shares
5,782 shares3 years ending 200705,782 shares11,564 shares

(1)  The awards of performance shares to Messrs. Chesser and Bassham are based on the following weightings of Great Plains Energy objectives during the applicable performance period: 50% total shareholder return compared to other Edison Electric Institute companies; 25% earnings per share; and 25% return on invested capital. The awards of performance shares to Messrs. Downey, Marshall and Easley are based 60%, 20% and 20%, respectively, on the Great Plains Energy objectives, with the remainder based on the following weightings of KCP&L objectives during the applicable performance period: 25% earnings; 25% return on invested capital; 25% on regulatory/build plan on schedule and budget; and 25% distributed utility goal. Payment of performance shares will range from 0% to 200% of the target amount of performance shares, depending on performance. Payment will be made in an amount equal to the number of performance shares earned, multiplied by the fair market value of common stock at the end of the applicable performance period and divided by the fair market value of common stock at the time of grant.
Aggregated Option/SAR Exercises in the Last Fiscal Year and Fiscal Year-End Option/SAR Values
       
Name
(a)
Shares
Acquired
on
Exercise
(#)
(b)
Value
Realized
($)
(c)
Number of Securities Underlying Unexercised Options/SARs at Fiscal Year End
(#)
Value of Unexercised In-the-Money Options/SARs at Fiscal Year End
($)
Exercisable
(1)(d)
Unexercisable
(d)
Exercisable(1)
(e)
Unexercisable
(e)
Michael J. Chesser- -----
William H. Downey--40,0005,249109,4001,207
Terry Bassham------
Stephen T. Easley--19,0002,44954,240563
John R. Marshall------
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Pension Plans
Great Plains Energy has a non-contributory pension plan (Great Plains Energy Pension Plan) providing for benefits upon retirement, normally at age 65. In addition, a supplemental retirement benefit is provided for selected executive officers based on the number of years such persons were officers. The following table shows examples of single life option pension benefits (including unfunded supplemental retirement benefits) payable upon retirement at age 65 to the named executive officers, assuming that the person was covered by the supplemental retirement benefit for all years of service.
   
Average Annual Base Salary
 
Annual Pension for Years of Service Indicated
for Highest 36 Months
 
15
 
20
 
25
 
30 or more
150,000 45,000 60,000 75,000 90,000
200,000 60,000 80,000 100,000 120,000
250,000 75,000 100,000 125,000 150,000
300,000 90,000 120,000 150,000 180,000
350,000 105,000 140,000 175,000 210,000
400,000 120,000 160,000 200,000 240,000
450,000 135,000 180,000 225,000 270,000
500,000 150,000 200,000 250,000 300,000
550,000 165,000 220,000 275,000 330,000
600,000 180,000 240,000 300,000 360,000
650,000 195,000 260,000 325,000 390,000
700,000 210,000 280,000 350,000 420,000
750,000 225,000 300,000 375,000 450,000
Each eligible employee with 30 or more years of credited service, or whose age and years of service add up to 85, is entitled under the Great Plains Energy Pension Plan to a total monthly annuity equal to 50% of their average base monthly salary for the period of 36 consecutive months in which their earnings were highest. The monthly annuity will be proportionately reduced if their years of credited service are less than 30 or if their age and years of service do not add up to 85. The compensation covered by the Great Plains Energy Pension Plan -- base monthly salary -- excludes any bonuses and other compensation. The Great Plains Energy Pension Plan provides that pension amounts are not reduced by Social Security benefits. The estimated years of credited service under the Great Plains Energy Pension Plan for the named executive officers in the Summary Compensation table are as follows.
Officer
Years of
Credited Service
Michael J. Chesser(a)
2.5
William H. Downey5.5
Terry Bassham0.5
John R. Marshall(a)
0
Stephen T. Easley9
(a)  Pursuant to the terms of employment agreements, Messrs.
    Chesser and Marshall will be credited with two years of
    service for every one year of service earned. The additional
    year of service will be paid as a supplemental retirement 
    benefit.
Eligibility for supplemental retirement benefits is limited to executive officers selected by the Compensation and Development Committee of the Board; all the named executive officers are participants. The total retirement benefit payable at the normal retirement date is equal to 1 2/3% of highest average annual base salary over the thirty-six consecutive month period when base salary was highest (highest average annual base salary), as shown above, for each year of credited service, plus
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an additional 1/3% of highest average annual base salary for each year of credited service when the executive was eligible for supplemental retirement benefits, up to 30 years (or a maximum of 60% of highest average annual base salary in the situation where the executive was eligible for supplemental retirement benefits for at least 30 years). A liability accrues each year to cover the estimated cost of future supplemental benefits.
The Internal Revenue Code imposes certain limitations on pensions that may be paid under tax qualified pension plans. In addition to the supplemental retirement benefits, the amount by which pension benefits exceed the limitations will be paid outside the qualified plan and accounted for by Great Plains Energy as an operating expense.
Severance Agreements
Great Plains Energy has severance agreements (Severance Agreements) with certain of its executive officers, including the named executive officers, to ensure their continued service and dedication and their objectivity in considering on behalf of Great Plains Energy any transaction that would change the control of the Company. Under the Severance Agreements, an executive officer would be entitled to receive a lump-sum cash payment and certain insurance benefits during the three-year period after a Change in Control (or, if later, the three-year period following the consummation of a transaction approved by Great Plains Energy’s shareholders constituting a Change in Control) if the officer's employment was terminated by:
·  Great Plains Energy other than for cause or upon death or disability;
·  the executive officer for Good Reason (as defined in the Severance Agreements); and
·  the executive officer for any reason during a 30-day period commencing one year after the Change in Control or, if later, commencing one year following consummation of a transaction approved by Great Plains Energy’s shareholders constituting a change in control (a Qualifying Termination).
A Change in Control is defined as:
·  an acquisition by a person or group of 20% or more of the Great Plains Energy common stock (other than an acquisition from or by Great Plains Energy or by a Great Plains Energy benefit plan);
·  a change in a majority of the Board; and
·  approval by the shareholders of a reorganization, merger or consolidation (unless shareholders receive 60% or more of the stock of the surviving Company) or a liquidation, dissolution or sale of substantially all of Great Plains Energy’s assets.
Upon a Qualifying Termination, a lump-sum cash payment will be made to the executive officer of:
·  the officer's base salary through the date of termination;
·  a pro-rated bonus based upon the average of the bonuses paid to the officer for the last five fiscal years;
·  any accrued vacation pay;
·  two or three times the officer's highest base salary during the prior 12 months;
·  two or three times the average of the bonuses paid to the officer for the last five fiscal years;
·  the actuarial equivalent of the excess of the officer's accrued pension benefits 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; and
·  the value of any unvested Great Plains Energy contributions for the benefit of the officer under the Great Plains Energy Employee Savings Plus Plan.
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In addition, Great Plains Energy must offer health, disability and life insurance plan coverage to the officer and his dependents on the same terms and conditions that existed immediately prior to the Qualifying Termination for two or three years, or, if earlier, until the executive officer is covered by equivalent plan benefits. Great Plains Energy must make certain "gross-up" payments regarding tax obligations relating to payments under the Severance Agreements as well as provide reimbursement of certain expenses relating to possible disputes that might arise.
In the following circumstances, termination of the officer’s employment prior to a Change in Control (or, if later, prior to the consummation of a transaction approved by shareholders that constitutes a Change in Control) will be treated as a Qualifying Termination:
·  the officer’s employment was terminated without Cause (as defined in the Severance Agreement) and the termination was at the request or direction of the other party to the agreement;
·  the officer terminates his employment for Good Reason; or
·  the officer’s employment is terminated without Cause and such termination is otherwise in connection with or in anticipation of a Change in Control that actually occurs.
Payments and other benefits under the Severance Agreements are in addition to balances due under the Great Plains Energy Long-Term Incentive Plan and Annual Incentive Plan. Upon a Change in Control (as defined in the Great Plains Energy Long-Term Incentive Plan), all stock options granted in tandem with limited stock appreciation rights will be automatically exercised.
Other Employment Arrangements
Pursuant to the terms of an employment arrangement, Mr. Chesser is entitled to receive three times annual salary and bonus if he is terminated without cause prior to his reaching age 63. After age 63, any benefit for termination without cause will be one times annual salary and bonus until age 65. Messrs. Chesser and Marshall will receive two credited years of service for every one year of service earned. The additional year of service will be paid as a supplemental retirement benefit.
Director Compensation
The directors of KCP&L receive the following compensation for serving on the Boards of Great Plains Energy and KCP&L:
An annual retainer of $50,000 was paid in 2005 ($25,000 of which was used to acquire shares of common stock through the Dividend Reinvestment and Direct Stock Purchase Plan on behalf of each non-employee member of the Board). An additional retainer of $10,000 was paid annually to the lead director. Also, a retainer of $6,000, $5,000 and $5,000 was paid to the non-employee director serving as chair of the Audit Committee, the Compensation and Development Committee and the Governance Committee, respectively. Attendance fees of $1,000 for each Board meeting and $1,000 for each committee and other meeting attended were also paid in 2005. Directors may defer the receipt of all or part of the cash retainers and meeting fees.
Great Plains Energy provides life and medical insurance coverage for each non-employee member of the Board. The total premiums paid by Great Plains Energy for this coverage for all non-employee directors in 2005 was $32,789. Great Plains Energy pays or reimburses directors for travel, lodging and related expenses they incur in attending Board and committee meetings, including the expenses incurred by directors’ spouses in accompanying the directors to one Board meeting in 2005. It also matches up to $2,000 per year of charitable donations made by a director to 501(c)(3) organizations that meet our strategic giving priorities and are located in the service territory.
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Compensation and Development Committee Report on KCP&L Executive Compensation

The Committee’s Responsibilities
The Compensation and Development Committee of the Board of Great Plains Energy (Committee) is composed of six non-employee directors, each of whom is independent under applicable standards of the New York Stock Exchange. The Committee is responsible for setting the executive compensation structure and administering the policies and plans that govern compensation for the executive officers. The purpose of this report is to summarize the Committee’s compensation philosophy, identify key elements of the executive compensation programs and describe the process and practices applied by the Committee in making compensation decisions for fiscal year 2005.
Compensation Philosophy
The Committee has adopted a compensation philosophy intended to:
·  Attract and retain highly qualified and experienced executives;
·  Emphasize a significant alignment between pay and Great Plains Energy’s and/or the executive’s performance;
·  Motivate executives to achieve strong short-term and long-term financial and operational results;
·  Provide variable compensation opportunities that recognize and reward outstanding performance;
·  Align management interests with those of the shareholders; and
·  Provide a significant portion of total pay in the form of stock-based incentives, correspondingly requiring target levels of stock ownership.
Compensation Methodology
Each year the Committee reviews data from market surveys, proxy statements, and other information provided by independent compensation consultants relating to an assessment of Great Plains Energy’s competitive position with respect to base salaries, annual incentives, long-term incentives, and other specific aspects of executive compensation. The Committee reviews the alignment between executive pay and performance on a regular basis. In the most recent assessment of its compensation practices by the compensation consultant retained by the Committee, it was reported that analyses demonstrated a strong relationship between pay and performance. The Committee also considers in its assessment individual performance, level of responsibility, internal comparisons, and skills and experience. Certain of Great Plains Energy’s executive officers serve as officers and/or directors of various subsidiaries. The total compensation of officers is designed to cover the full range of services they provide to Great Plains Energy and its subsidiaries.
Components of Compensation
Base Salary
The Committee reviews executive officer base salaries annually and concurrent with an evaluation of the executive’s performance for the prior year. Base salaries are based upon job responsibilities, level of experience, individual performance, comparisons of the salaries of executives in similar positions obtained from market surveys, internal comparisons and competitive data provided by compensation consultants retained by the Committee. The goal for the base salary component is to compensate executives at a level, which approximates the median salaries of individuals in comparable positions in companies of similar size within the industry and general industry, as appropriate. Base salary increases for Messrs. Chesser, Downey and Easley were effective January 1, 2005. Messrs. Bassham and Marshall were not employed by Great Plains Energy until March 28, 2005 and May 25, 2005, respectively.
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Annual Incentives
Annual cash incentives are provided to executive officers based upon the achievement of pre-established corporate and business unit objectives, and also provide the ability to recognize individual performance. In 2005, the Committee administered the Great Plains Energy Annual Incentive Plan (the Plan) that permitted the award of annual cash incentives to executive officers, including the Named Executive Officers set forth in the Summary Compensation Table. Target incentives under the Plan are established as a percentage of base pay, using survey data for individuals in comparable positions and markets and internal comparisons. The Committee has established total target annual bonus levels intended to approximate the 50th percentile bonus levels in comparable positions and markets when target performance is achieved. Target annual incentives under the Plan for 2005 ranged from 30% to 60% of base pay. The total amount available for payment was determined by corporate earnings per share and subject to established threshold, target and maximum levels. The Plan will pay out at 100% at target. Fifty percent of the incentive is payable at the threshold level of performance and 150% of the incentive is payable at the maximum level of performance. If performance falls below target, but is above threshold, the amount of the award payable will be below the target award level. Similarly, performance above target will result in an award higher than target level. Individual awards will not be paid if the corporate EPS performance falls below the threshold level. The entire award is distributed proportionately among participants based on other corporate and business unit measures, such as return on invested capital, customer satisfaction, customer retention rate, reliability, and others. Individual performance is also taken into account. For 2005, discretion was used to exclude from Great Plains Energy reported earnings and Strategic Energy pre-tax income goals and results the applicable effects of mark-to-market gains and losses on energy contracts, SECA, certain compensation expenses and discontinued operations. As a result, corporate earnings per share were at the maximum level and individual awards were earned in the amounts set forth in the Summary Compensation Table.
The Annual Incentive Plan of Great Plains Energy Incorporated was amended in February of 2006. The amended Plan will continue to be based on achievement of pre-established company and business unit financial and operational metrics. For 2006, the measures for annual incentives are based 50% on core earnings, and 30% on financial ratios, production availability, achievement of comprehensive energy plan milestones, customer satisfaction, profitability, employee engagement and/or other specified business unit objectives. The Committee also takes into account individual performance to account for 20% of the target award. Individual Incentive amounts will range from 0% to 200% of target based on performance, and the Committee intends to target the 50th percentile or above as the basis for target annual bonus levels. Strategic Energy also revised the Strategic Energy L.L.C. Annual Incentive Plan in February of 2006 and has the same structure and terms as the Great Plains Energy Annual Incentive Plan.
Long-Term Incentive Compensation
The Committee has structured a long-term compensation element to more closely align the interests of management with the creation of long-term shareholder value. The Great Plains Energy Long-Term Incentive Plan was approved by shareholders in 2002, and provides for grants by the Committee of stock options, restricted stock, performance shares, and other stock-based awards. Each executive officer is assigned a long-term incentive target based on both internal comparisons and upon survey data for individuals in comparable positions in the markets in which Great Plains Energy competes for executive talent. Compliance with stock ownership guidelines is also taken into consideration in determining grants under the Long-Term Incentive Program. The Committee has established total target long-term incentive targets at the 50th percentile in comparable positions and markets. Targets range from 40% to 150% of base salary. Based on performance over the period, awards can pay out from 0% to 200%. However, since no long-term grants were made under the program in 2004, in 2005 executives received a two-year performance share grant for 2005-2006 performance, and a three-year performance share grant for 2005-2007 performance. Payouts, if any, will be made after the end of the
136
period based on performance during the period. Goals for both long-term grants were based on pre-approved corporate and business unit measures.
For 2006, the performance share component of long-term awards will be based on the Company’s Total Shareholder Return over a three-year period, as compared to the Total Shareholder Return of the Edison Electric Institute (EEI) Index of electric utilities. The Committee believes this measure ensures strong alignment of executive financial interests with the long-term interests of its shareholders.
KCP&L Chief Executive Officer Compensation
The Committee considers the assessment of the Chief Executive Officer’s (CEO) performance and determination of the CEO’s compensation as among its principal responsibilities. Its objective with regards to setting an appropriate level of compensation is to motivate and retain a CEO who is committed to delivering sustained superior performance for the Company’s shareholders.
In 2005, Mr. Downey received a base salary of $440,000, which is below the median for CEOs of comparably-sized companies in similar markets. In determining Mr. Downey’s base salary, the Committee considered the financial performance of the Company; the cost and quality of services provided; leadership in enhancing the long-term value of the Company; performance against other pre-established objectives; survey data; and consideration of length of service. Mr. Downey’s annual incentive compensation award was targeted at 45% of base pay, also considered to be somewhat below market levels. In 2005, Mr. Downey’s incentive award was based 80% on Great Plains Energy performance which included a balanced scorecard of financial, customer-related and internal/operational metrics, and 20% on individual performance. Funding for annual awards was based on corporate earnings per share. The Great Plains Energy scorecard resulted in overall performance between target and maximum levels for purposes of the annual incentive plan, and earnings performance allowed funding at the maximum level. Mr. Downey received two long-term performance share grants in 2005 since no awards were made in 2004. Awards were determined in the same manner as for other executive officers. Mr. Downey’s long-term incentive target was 115% of base pay, which is consistent with the 50th percentile for comparable CEO positions and markets.
It is the Committee’s intent that, when taken together, the components of Mr. Downey’s pay, including base salary, annual incentives and long-term incentives, would result in total compensation that would approximate the 50th percentile of the market when incentive plan performance measures are met and in compensation levels at the 75th percentile or higher when incentive plan performance is at superior levels.
Code Section 162(m)
Section 162(m) of the Internal Revenue Code precludes the Company from taking a deduction for compensation in excess of $1 million for any individual who, on the last day of that year, is the CEO or among the other four highest compensated officers unless that compensation qualifies as performance-based compensation under Section 162(m). With respect to incentive compensation, the Great Plains Energy Long-Term Incentive Plan was approved by shareholders in 2002 and offers vehicles, which are performance-based. It is the Committee’s intent to take reasonable steps to include the provisions necessary to qualify for exemptions from the limitations on such deductibility under Section 162(m) at the time the Plan is next taken for shareholder vote in May 2007. With respect to awards under the Great Plains Energy Annual Incentive Plan, the Committee believes that the interests of the Company’s shareholders are best served by not restricting the Committee’s and Company’s discretion and flexibility in developing compensation programs.
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COMPENSATION AND DEVELOPMENT COMMITTEE
William C. Nelson (Chairman)
Mark A. Ernst
Luis A. Jimenez
James A. Mitchell
Linda H. Talbott
Robert H. West
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 
GREAT PLAINS ENERGY
The information required by this item regarding security ownership of the directors and executive officers of Great Plains Energy contained in the section titled “Security Ownership of Certain Beneficial Owners, Directors and Officers” of the Proxy Statement is incorporated by reference.
 
KCP&L
Great Plains Energy is the sole shareholder of KCP&L. The following table shows beneficial ownership of Great Plains Energy’s common stockinformation required by the named executive officers, directors and all directors and executive officers ofthis item regarding KCP&L as of February 7, 2006, (with the exception of shares heldhas been omitted in the Employee Savings Plus Plan, which is reported as of January 31, 2006)reliance on General Instruction (I). The total of all shares owned by directors and executive officers represents less than 1% of Great Plains Energy’s common stock.
132
  
Name of Beneficial Owner
Shares of Common
Stock
Beneficially Owned (1)
Named Executive Officers
  
 Michael J. Chesser43,973 
 William H. Downey89,255 
 Terry Bassham11,721 
 Stephen T. Easley39,705 
 John R. Marshall25,761 
    
Non-management Directors
  
 David L. Bodde10,465(2)
 Mark A. Ernst8,663 
 Randall C. Ferguson, Jr.4,203 
 Luis A. Jimenez4,650 
 James A. Mitchell5,209 
 William C. Nelson5,069(3)
 Linda H. Talbott10,781 
All KCP&L Executive Officers and Directors As A Group (20 persons)
 
334,181
 
(1)  Includes restricted stock and exercisable non-qualified stock options.
·  
Restricted Stock: Chesser - 36,006 shares; Downey - 24,487 shares;
Bassham - 11,721 shares; Marshall - 23,567 shares; Easley - 12,593 shares; other executive officers - 15,886.
·  
Exercisable Non-Qualified Stock Options: Downey - 40,000 shares; Easley -
19,000 shares; other executive officers - 36,000.
(2)  The nominee disclaims beneficial ownership of 1,000 shares reported and held by nominee's mother.
(3)  The nominee disclaims beneficial ownership of 62 shares reported and held by nominee’s wife.
138
Equity Compensation Plan
The information required by this item regarding Great Plains Energy’s equity compensation plan is in Item 5,5. Market for the Registrants’ Common Equity and Related Shareholder Matters, of this report and is incorporated by reference.
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
GREAT PLAINS ENERGY
The information required by this item contained in the sectionsections titled “Security Ownership of Certain Beneficial Owners, Directors“Director Independence” and, Officers - Certainif applicable, “Certain Relationships and Related Transactions” of the Proxy Statement is incorporated by reference.
 
KCP&L
See Note 12 to the consolidated financial statements.The information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).
 
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
 
GREAT PLAINS ENERGY
The information required by this item regarding the independent auditors of Great Plains Energy and its subsidiaries contained in the section titled “Audit Committee Report” of the Proxy Statement is incorporated by reference.

KCP&L
The Audit Committee of the Great Plains Energy Board functions as the Audit Committee of KCP&L. The following table sets forth the aggregate fees billed by Deloitte & Touche LLP for audit services rendered in connection with the consolidated financial statements and reports for 20052006 and 20042005 and for other services rendered during 20052006 and 20042005 on behalf of the CompanyKCP&L and its subsidiaries, as well as all out-of-pocket costs incurred in connection with these services:
 
Fee Category
 
2006
 
2005
 
Audit Fees $984,256 $1,075,986 
Audit-Related Fees  44,200  62,251 
Tax Fees  21,831  24,307 
All Other Fees  -  21,100 
Total Fees $1,050,287 $1,183,644 
   
Fee Category
2005
2004
Audit Fees$1,075,986$    920,904
Audit-Related Fees62,251138,080
Tax Fees24,307373,730
All Other Fees21,100-
Total Fees$1,183,644$ 1,432,714

Audit Fees: Consists of fees billed for professional services rendered for the audits of the annual consolidated financial statements of the Company and its subsidiaries and reviews of the interim condensed consolidated financial statements included in quarterly reports. Audit fees also include: services provided by Deloitte & Touche LLP in connection with statutory and regulatory filings or engagements; audit reports on audits of the effectiveness of internal control over financial reporting and on management’s assessment of the effectiveness of internal control over financial reporting and other attest services, except those not required by statute or regulation; services related to filings with the Securities and Exchange Commission, including comfort letter, consents and assistance with and review of documents filed with the Securities and Exchange Commission; and accounting research in support of the audit.
 
Audit-Related Fees: Consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of consolidated financial statements of the CompanyKCP&L and its
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subsidiaries and are not reported under “Audit Fees”. These services include consultation concerning financial accounting and reporting standards and services in connection with the Company’s assessment of the effectiveness of its internal control over financial reporting (the fees in 2004 aggregated $131,980).
139
standards.
 
Tax Fees: Consists of fees billed for tax compliance and related support of tax returns and other tax services, including assistance with tax audits, and tax research and planning. Tax fees for 2004 included $372,040 of fees that became payable upon resolution of engagements entered into in prior years.
 
All Other Fees: Consists of fees for all other services other than those reported above. ThoseThese services included the development and facilitation of a group training course in 2005.
 
Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditors
The Audit Committee pre-approves all audit and permissible non-audit services provided by the independent auditor to the CompanyKCP&L and its subsidiaries. These services may include audit services, audit-related services, tax services and other services. The Audit Committee has adopted for the CompanyKCP&L and its subsidiaries policies and procedures for the pre-approval of services provided by the independent auditor. Under these policies and procedures, the Audit Committee may pre-approve certain types of services, up to aggregate fee levels established by the Audit Committee. The Audit Committee as well may specifically approve audit and permissible non-audit services on a case-by-case basis. Any proposed service within a pre-approved type of service that would cause the applicable fee level to be exceeded cannot be provided unless the Audit Committee either amends the applicable fee level or specifically approves the proposed service. Pre-approval is generally provided for up to one year, unless the Audit Committee specifically provides for a different period. The Audit Committee receives quarterly reports regarding the pre-approved services performed by the independent auditor. The Chairman of the Audit Committee may between meetings pre-approve audit and non-audit services provided by the independent auditor, and report such pre-approval at the next Audit Committee meeting.

PART IV
 
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 
Financial Statements
 
  
Page
No.
Great Plains Energy
Page No.
 
a.
 
Consolidated Statements of Income for the years ended December 31, 2006, 2005 2004 and 2003
572004
 
   59
b.
Consolidated Balance Sheets - December 31, 20052006 and 20042005
58   60
c.
 
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 2004 and 2003
602004
 
   62
d.
 
Consolidated Statements of Common Shareholders’ Equity for the years ended December 31, 2006, 2005 2004 and 2003
612004
 
   63
e.
 
Consolidated Statements of Comprehensive Income for the years ended December 31, 2006, 2005 2004 and 2003
622004
 
   64
f.
Notes to Consolidated Financial Statements
69   71
g.
Report of Independent Registered Public Accounting Firm
121 126
   
 140
134
KCP&L
 
h.
 
Consolidated Statements of Income for the years ended December 31, 2006, 2005 2004 and 2003
632004
 
   65
i.
Consolidated Balance Sheets - December 31, 20052006 and 20042005
64   66
j.
 
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 2004 and 2003
662004
 
   68
k.
 
Consolidated Statements of Common Shareholder’sShareholders’ Equity for the years ended December 31, 2006, 2005 2004 and 2003
672004
 
   69
l.
 
Consolidated Statements of Comprehensive Income for the years ended December 31, 2006, 2005 2004 and 2003
682004
 
   70
m.
Notes to Consolidated Financial Statements
69   71
n.
Report of Independent Registered Public Accounting Firm
122 127
   
Financial Statement Schedules
 
 
Great Plains Energy
 
a.
Schedule I - Parent Company Financial Statements
148 143
b.
Schedule II - Valuation and Qualifying Accounts and Reserves
152 147
 
KCP&L
 
c.
Schedule II - Valuation and Qualifying Accounts and Reserves
153 148

Exhibits
 
Great Plains Energy Documents
 
Exhibit
Number
 
 
Description of Document
 
2.12.1.1
 
*
 
Agreement and Plan of Merger among Kansas City Power & Light Company, Great Plains Energy Incorporated and KCP&L Merger Sub Incorporated dated as of October 1, 2001 (Exhibit 2 to Form 8-K dated October 1, 2001).
 
3.1.a2.1.2
*
Agreement and Plan of Merger among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp., and Black Hills Corporation dated as of February 6, 2007 (Exhibit 2.1 to Form 8-K dated February 7, 2007).
3.1.1
 
*
 
Articles of Incorporation of Great Plains Energy Incorporated dated as of February 26, 2001 (Exhibit 3.i to Form 8-K filed October 1, 2001).
 
3.1.b3.1.2
 
*
 
By-laws of Great Plains Energy Incorporated, as amended September 16, 2003 (Exhibit 3.1 to Form 10-Q for the periodquarter ended September 30, 2003).
 
4.1.a4.1.1
 
*
 
Resolution of Board of Directors Establishing 3.80% Cumulative Preferred Stock (Exhibit 2-R to Registration Statement, Registration No. 2-40239).
 
4.1.b4.1.2
 
*
 
Resolution of Board of Directors Establishing 4.50% Cumulative Preferred Stock (Exhibit 2-T to Registration Statement, Registration No. 2-40239).
 
135
4.1.c4.1.3
 
*
 
Resolution of Board of Directors Establishing 4.20% Cumulative Preferred Stock (Exhibit 2-U to Registration Statement, Registration No. 2-40239).
 
4.1.d4.1.4
 
*
 
Resolution of Board of Directors Establishing 4.35% Cumulative Preferred Stock (Exhibit 2-V to Registration Statement, Registration No. 2-40239).
 
 141
4.1.e4.1.5
 
*
 
Pledge Agreement, dated June 14, 2004, between Great Plains Energy Incorporated and BNY Midwest Trust Company, as Collateral Agent, Custodial Agent and Securities Intermediary and BNY Midwest Trust Company, as Purchase Contract Agent (Exhibit 4.2 to Form 8-A/A, dated June 14, 2004).
 
4.1.f4.1.6
 
*
 
Indenture, dated June 1, 2004, between Great Plains Energy Incorporated and BNY Midwest Trust Company, as Trustee (Exhibit 4.5 to Form 8-A/A, dated June 14, 2004).
 
4.1.g4.1.7
 
*
 
First Supplemental Indenture, dated June 14, 2004, between Great Plains Energy Incorporated and BNY Midwest Trust Company, as Trustee (Exhibit 4.5 to Form 8-A/A, dated June 14, 2004).
 
4.1.h4.1.8
 
*
 
Form of Income PRIDES (included in Exhibit 4.1 to Form 8-A/A, dated June 14, 2004, as Exhibit A thereto).
 
10.1.a4.1.9
*
Confirmation of Forward Stock Sale Transaction between Great Plains Energy Incorporated and Merrill Lynch Financial Markets, Inc., dated May 17, 2006 (Exhibit 1.2 to Form 8-K filed May 23, 2006).
10.1.1
 
*+
 
Amended Long-Term Incentive Plan, effective as of May 7, 2002 (Exhibit 10.1.a to Form 10-K for the year ended December 31, 2002).
 
10.1.b10.1.2
 
*+
 
Great Plains Energy Incorporated Long-Term Incentive Plan Awards Standards and Administration effective as of February 7, 2006.2006 (Exhibit 10.1.b to Form 10-K for the year ended December 31, 2005).
 
10.1.c10.1.3
 
*+
 
Form of Restricted Stock Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1 to Form 8-K dated February 4, 2005).
 
10.1.d10.1.4
 
*+
 
Form of Restricted Stock Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.2 to Form 8-K dated February 4, 2005).
 
10.1.5
*+
Form of Restricted Stock Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1.e to Form 10-K for the year ended December 31, 2005).
10.1.6
 
+
 
Form of Restricted Stock Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002.
 
10.1.f10.1.7
 
*+
 
Form of Performance Share Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1.b to Form 10-Q for the quarter ended March 31, 2005).
 
10.1.g10.1.8
 
*+
 
Form of Performance Share Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1.c to Form 10-Q for the quarter ended March 31, 2005).
 
10.1.9
*+
Form of Performance Share Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1.h to Form 10-K for the year ended December 31, 2005).
136
10.1.10
 
+
 
Form of Performance Share Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002.
 
10.1.i10.1.11
+
Form of Performance Share Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002.
10.1.12
 
*+
 
Strategic Energy, L.L.C. Long-Term Incentive Plan Grants 2005, Amended May 2, 2005 (Exhibit 10.1.f to Form 10-Q for the periodquarter ended March 31, 2005).
 
10.1.j10.1.13
 
*+
Strategic Energy, L.L.C. Long-Term Incentive Plan Grants 2005, as amended May 2, 2005 and October 31, 2006 (Exhibit 10.1.g to Form 10-Q for the quarter ended September 30, 2006).
10.1.14
*+
 
Strategic Energy, L.L.C. Executive Long-Term Incentive Plan 2006.2006 (Exhibit 10.1.j to Form 10-K for the year ended December 31, 2005).
 
10.1.k10.1.15
 
*+
 
Great Plains Energy Incorporated/Kansas City Power & Light Company Annual Incentive Plan 2005, Amended May 3, 2005 (Exhibit 10.1.c to Form 10-Q for the quarter ended March 31, 2005).
 
10.1.l10.1.16
 
*+
 
Great Plains Energy Incorporated Kansas City Power & Light Company Annual Incentive Plan amended as of January 1, 2006.2006 (Exhibit 10.1.l to Form 10-K for the year ended December 31, 2005).
 
10.1.m10.1.17
 
*+
 
Strategic Energy, L.L.C. Annual Incentive Plan dated January 1, 2006.2006 (Exhibit 10.1.m to Form 10-K for the year ended December 31, 2005).
 
10.1.n10.1.18
*+
Strategic Energy, L.L.C. Annual Incentive Plan 2006 goals as amended October 31, 2006 (Exhibit 10.1.h to Form 10-Q for the quarter ended September 30, 2006).
10.1.19
+
Great Plains Energy Incorporated Kansas City Power & Light Company Annual Incentive Plan amended effective as of January 1, 2007.
10.1.20
+
Strategic Energy, L.L.C. Executive Committee Annual Incentive Plan dated as of January 1, 2007.
10.1.21
+
Strategic Energy, L.L.C. Executive Committee Long-Term Incentive Plan dated as of January 1, 2007.
10.1.22
 
*+
 
Form of Indemnification Agreement with each officer and director (Exhibit 10-f to Form 10-K for year ended December 31, 1995).
 
 142
10.1.o10.1.23
 
*+
 
Form of Conforming Amendment to Indemnification Agreement with each officer and director (Exhibit 10.1.a to Form 10-Q for the periodquarter ended March 31, 2003).
 
10.1.p10.1.24
 
*+
 
Form of Indemnification Agreement with officers and directors.directors (Exhibit 10.1.p to Form 10-K for the year ended December 31, 2005).
 
10.1.q10.1.25
 
*+
 
Form of Restated Severance Agreement dated January 2000 with certain executive officers (Exhibit 10-e to Form 10-K for the year ended December 31, 2000).
 
10.1.r10.1.26
 
*+
 
Form of Conforming Amendment to Severance Agreements with certain executive officers (Exhibit 10.1.b to Form 10-Q for the periodquarter ended March 31, 2003).
 
10.1.s10.1.27
*+
Form of Change in Control Severance Agreement with Michael J. Chesser (Exhibit 10.1.a to Form 10-Q for the quarter ended September 30, 2006).
10.1.28
*+
Form of Change in Control Severance Agreement with John R. Marshall (Exhibit 10.1.c to Form 10-Q for the quarter ended September 30, 2006).
137
10.1.29
*+
Form of Change in Control Severance Agreement with Shahid Malik (Exhibit 10.1.d to Form 10-Q for the quarter ended September 30, 2006).
10.1.30
*+
Form of Change in Control Severance Agreement with other executive officers of Great Plains Energy Incorporated and Kansas City Power & Light Company (Exhibit 10.1.e to Form 10-Q for the quarter ended September 30, 2006).
10.1.31
 
*+
 
Great Plains Energy Incorporated Supplemental Executive Retirement Plan, as amended and restated effective October 1, 2003 (Exhibit 10.1.a to Form 10-Q for the periodquarter ended September 30, 2003).
 
10.1.t10.1.32
 
*+
 
Nonqualified Deferred Compensation Plan (Exhibit 10-b to Form 10-Q for the periodquarter ended March 31, 2000).
 
10.1.u10.1.33
 
+
 
Description of Compensation Arrangements with Directors and Certain Executive Officers.
 
10.1.v10.1.34
 
*+
 
Employment Agreement among Strategic Energy, L.L.C., Great Plains Energy Incorporated and Shahid J. Malik, dated as of November 10, 2004 (Exhibit 10.1.p to Form 10-K for the year ended December 31, 2004).
 
10.1.w10.1.35
 
*+
 
Severance Agreement among Strategic Energy, L.L.C., Great Plains Energy Incorporated and Shahid J. Malik, dated as of November 10, 2004 (Exhibit 10.1.q to Form 10-K for the year ended December 31, 2004).
 
10.1.x10.1.36
 
*
 
First Amended and Restated Joint Plan under Chapter 11 of the United States Bankruptcy Code dated March 31, 2003, of Digital Teleport Inc., DTI Holdings, Inc. and Digital Teleport of Virginia, Inc. (Exhibit 10.1.e to Form 10-Q for the periodquarter ended March 31, 2003).
 
10.1.y10.1.37
 
*
 
Credit Agreement dated as of December 15, 2004,May 11, 2006, among Great Plains Energy Incorporated, Bank of America, N.A., as Syndication Agent,JPMorgan Chase Bank, N.A., BNP Paribas, The Bank of Tokyo-Mitsubishi Ltd,UFJ, Limited, Chicago Branch, Wachovia Bank National Association and BNP Paribas, as Co-Documentation Agents, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of New York, KeyBankKeybank National Association, The Bank of Nova Scotia, U.S. Bank National Association, Merrill Lynch Bank USA, Morgan Stanley Bank, Mizuho Corporate Bank, UMB Bank, N.A., PNCand Commerce Bank, National Association, Bank Midwest, N.A. and UFJ Bank Limited (Exhibit 10.1.s to Form 10-K for the year ended December 31, 2004).
10.1.z
*
First Amendment, dated October 6, 2005, to the Credit Agreement dated as of December 15, 2004, among Great Plains Energy Incorporated, Bank of America, N.A., as Syndication Agent, The Bank of Tokyo-Mitsubishi, Ltd, Wachovia Bank, National Association and BNP Paribas, as Co-Documentation Agents, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of New York, KeyBank National Association, The Bank of Nova Scotia, U.S. Bank National Association, Merrill Lynch Bank USA, Morgan Stanley Bank, Mizuho Corporate Bank, UMB Bank, N.A., PNC Bank, National Association, Bank Midwest, N.A. and UFJ Bank LimitedN.A (Exhibit 10.1.a to Form 10-Q for the quarter ended SeptemberJune 30, 2005)2006).
 
 143
10.1.aa10.1.38
 
*
 
Amended and Restated Credit Agreement, dated as of July 2, 2004, by and among Strategic Energy, L.L.C., LaSalle Bank National Association, PNC Bank, National Association, Citizens Bank of Pennsylvania, Provident Bank, Fifth Third Bank and Sky Bank. (Exhibit 10.2 to Form 10-Q for the periodquarter ended June 30, 2004).
 
10.1.bb10.1.39
 
*
Amendment No. 1 dated as of December 20, 2005, to Amended and Restated Credit Agreement, dated as of July 2, 2004, by and among Strategic Energy, L.L.C., LaSalle Bank National Association, PNC Bank, National Association, Citizens Bank of Pennsylvania, Provident Bank, Fifth Third Bank, First National Bank of Pennsylvania and Sky Bank.Bank (Exhibit 10.1.bb to Form 10-K for the year ended December 31, 2005).
 
10.1.cc10.1.40
*
Consent dated as of May 31, 2006, to Amended and Restated Credit Agreement, dated as of July 2, 2004, by and among Strategic Energy, L.L.C., LaSalle Bank National Association, PNC Bank, National Association, Citizens Bank of Pennsylvania, National City Bank of Pennsylvania, Fifth Third Bank, Sky Bank and First National Bank of Pennsylvania (Exhibit 10.1.b to Form 10-Q for the quarter ended June 30, 2006).
138
10.1.41
Waiver and Amendment dated as of December 6, 2006, to Amended and Restated Credit Agreement, dated as of July 2, 2004, by and among Strategic Energy, L.L.C., LaSalle Bank National Association, PNC Bank, National Association, Citizens Bank of Pennsylvania, National City Bank of Pennsylvania, Fifth Third Bank, Sky Bank and First National Bank of Pennsylvania.
10.1.42
 
*
 
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. (Exhibit 10.3 to Form 10-Q for the periodquarter ended June 30, 2004).
 
10.1.dd10.1.43
*
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 (Exhibit 10.1.e to Form 10-Q for the quarter ended September 30, 2006).
10.1.44
 
*
 
General Agreement of Indemnity issued by Great Plains Energy Incorporated and Strategic Energy, L.L.C. in favor of Federal Insurance Company and subsidiary or affiliated insurers dated May 23, 2002 (Exhibit 10.1.a. to Form 10-Q for the periodquarter ended June 30, 2002).
 
10.1.ee10.1.45
 
*
 
Agreement of Indemnity issued by Great Plains Energy Incorporated and Strategic Energy, L.L.C. in favor of Federal Insurance Company and subsidiary or affiliated insurers dated May 23, 2002 (Exhibit 10.1.b. to Form 10-Q for the periodquarter ended June 30, 2002).
 
10.1.ff10.1.46
 
*
 
Agreement between Great Plains Energy Incorporated and Andrea F. Bielsker dated March 4, 2005 (Exhibit 10.1.jj to Form 10-K for the year ended December 31, 2004).
 
10.1.gg10.1.47
 
*
 
Agreement between Great Plains Energy Incorporated and Jeanie Sell Latz dated April 5, 2005 (Exhibit 10.1 to Form 8-K dated April 5, 2005).
 
10.1.48
*
Asset Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated, and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.1 to Form 8-K dated February 7, 2007).
10.1.49
* 
Partnership Interests Purchase Agreement by and among Aquila, Inc., Aquila Colorado, LLC, Black Hills Corporation, Great Plains Energy Incorporated, and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.2 to Form 8-K dated February 7, 2007).
10.1.50*+ Form of Conforming Amendment to Severance Agreements with William H. Downey (Exhibit 10.1.b to Form 10-Q for the quarter ended September 30, 2006).
12.1
 
 
Computation of Ratio of Earnings to Fixed Charges.
 
21.1
 
 
List of Subsidiaries of Great Plains Energy Incorporated.
 
23.1.a
 
 
Consent of Counsel.
 
23.1.b
 
 
Consent of Independent Registered Public Accounting Firm.
 
24.1
 
 
Powers of Attorney.
 
31.1.a
 
 
Rule 13a-14(a)/15d-14(a) Certifications of Michael J. Chesser.
 
139
31.1.b
 
 
Rule 13a-14(a)/15d-14(a) Certifications of Terry Bassham.
 
32.1
 
 
Section 1350 Certifications.
 
* Filed with the SEC as exhibits to prior registration statements (except as otherwise noted)SEC filings and are incorporated herein by reference and made a part hereof. The exhibit numberSEC filing and filethe exhibit number of the documents so filed, and incorporated herein by reference, are stated in parenthesis in the description of such exhibit.
 
+ 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.
144
Great Plains Energy agrees to furnish to the SEC upon request any instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of total assets of Great Plains Energy and its subsidiaries on a consolidated basis.
 
KCP&L DocumentsDOCUMENTS
 
Exhibit
Exhibit NumberNumber
 
 
Description of Document
 
2.2
 
*
 
Agreement and Plan of Merger among Kansas City Power & Light Company, Great Plains Energy Incorporated and KCP&L Merger Sub Incorporated dated as of October 1, 2001 (Exhibit 2 to Form 8-K dated October 1, 2001).
 
3.2.a3.2.1
 
*
 
Restated Articles of Consolidation of Kansas City Power & Light Company, as amended October 1, 2001 (Exhibit 3-(i) to Form 10-Q for the periodquarter ended September 30, 2001).
 
3.2.b3.2.2
 
*
By-laws of Kansas City Power & Light Company, as amended November 1, 2005.2005 (Exhibit 3.2.b to Form 10-K for the year ended December 31, 2005).
 
4.2.a4.2.1
 
*
 
General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, n.a. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4-bb to Form 10-K for the year ended December 31, 1986).
 
4.2.b4.2.2
 
*
 
Fourth Supplemental Indenture dated as of February 15, 1992, to Indenture dated as of December 1, 1986 (Exhibit 4-y to Form 10-K for the year ended December 31, 1991).
 
4.2.c4.2.3
 
*
 
Fifth Supplemental Indenture dated as of September 15, 1992, to Indenture dated as of December 1, 1986 (Exhibit 4-a to quarterly report on Form 10-Q for the periodquarter ended September 30, 1992).
 
4.2.d4.2.4
 
*
 
Seventh Supplemental Indenture dated as of October 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4-a to quarterly report on Form 10-Q for the periodquarter ended September 30, 1993).
 
4.2.e4.2.5
 
*
 
Eighth Supplemental Indenture dated as of December 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4 to Registration Statement, Registration No. 33-51799).
 
140
4.2.f4.2.6
 
*
 
Eleventh Supplemental Indenture dated as of August 15, 2005, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, n.a. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2005).
 
4.2.g4.2.7
 
*
 
Indenture for Medium-Term Note Program dated as of February 15, 1992, between Kansas City Power & Light Company and The Bank of New York (Exhibit 4-bb to Registration Statement, Registration No. 33-45736).
 
4.2.h4.2.8
 
*
 
Indenture for $150 million aggregate principal amount of 6.50% Senior Notes due November 15, 2011 and $250 million aggregate principal amount of 7.125% Senior Notes due December 15, 2005 dated as of December 1, 2000, between Kansas City Power & Light Company and The Bank of New York (Exhibit 4-a to Report on Form 8-K dated December 18, 2000).
 
4.2.i4.2.9
 
*
 
Indenture dated March 1, 2002 between The Bank of New York and Kansas City Power & Light Company (Exhibit 4.1.b. to Form 10-Q for the periodquarter ended March 31, 2002).
 
 145
4.2.j4.2.10
 
*
Supplemental Indenture No. 1 dated as of November 15, 2005, to Indenture dated March 1, 2002 between The Bank of New York and Kansas City Power & Light Company.Company (Exhibit 4.2.j to Form 10-K for the year ended December 31, 2005).
 
4.2.k4.2.11
 
*
Registration Rights Agreement dated as of November 17, 2005, among Kansas City Power & Light Company, and BNP Paribas Securities Corp. and J.P. Morgan Securities Inc. as representatives of the several initial purchasers.
10.2.a
*
Railcar Lease dated as of January 31, 1995, between First Security Bank of Utah, National Association, and Kansas City Power & Light Companypurchasers (Exhibit 10-o4.2.k to Form 10-K for the year ended December 31, 1994)2005).
 
10.2.b
*
Railcar Lease dated as of September 8, 1998, with CCG Trust Corporation (Exhibit 10(b) to Form 10-Q for the period ended September 30, 1998).
10.2.c10.2.1
 
*
 
Insurance agreement between Kansas City Power & Light Company and XL Capital Assurance Inc., dated December 5, 2002 (Exhibit 10.2.f to Form 10-K for the year ended December 31, 2002).
 
10.2.d10.2.2
 
*
 
Insurance Agreement dated as of August 1, 2004, between Kansas City Power & Light Company and XL Capital Assurance Inc. (Exhibit 10.2 to Form 10-Q for the periodquarter ended September 30, 2004).
 
10.2.e10.2.3
 
*
Insurance Agreement dated as of September 1, 2005, between Kansas City Power & Light Company and XL Capital Assurance Inc. (Exhibit 10.2.e to Form 10-K for the year ended December 31, 2005).
 
10.2.f10.2.4
 
*
Insurance Agreement dated as of September 1, 2005, between Kansas City Power & Light Company and XL Capital Assurance Inc. (Exhibit 10.2.e to Form 10-K for the year ended December 31, 2005).
 
10.2.g10.2.5
*
Iatan Unit 2 and Common Facilities Ownership Agreement, dated as of May 19, 2006, among Kansas City Power & Light Company, Aquila, Inc., The Empire District Electric Company, Kansas Electric Power Cooperative, Inc., and Missouri Joint Municipal Electric Utility Commission (Exhibit 10.2.a to Form 10-Q for the quarter ended June 30, 2006).
141
10.2.6
*
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 (Exhibit 10.2.a to Form 10-Q for the quarter ended September 30, 2006).
10.2.7
 
*
 
Credit Agreement dated as of December 15, 2004,May 11, 2006, among Kansas City Power & Light Company, Bank of America, N.A., as Syndication Agent,JPMorgan Chase Bank, N.A., BNP Paribas, The Bank of Tokyo-Mitsubishi Ltd,UFJ, Limited, Chicago Branch, Wachovia Bank National Association and BNP Paribas, as Co-Documentation Agents, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of New York, KeyBankKeybank National Association, The Bank of Nova Scotia, U.S. Bank National Association, Merrill Lynch Bank USA, Morgan Stanley Bank, Mizuho Corporate Bank, UMB Bank, N.A., PNCand Commerce Bank, National Association, Bank Midwest, N.A. and UFJ Bank LimitedN.A (Exhibit 10.2.h to Form 10-K for the year ended December 31, 2004).
10.2.h
*
First Amendment, dated October 6, 2005, to the Credit Agreement dated as of December 15, 2004, among Kansas City Power & Light Company, Bank of America, N.A., as Syndication Agent, The Bank of Tokyo-Mitsubishi, Ltd, Wachovia Bank, National Association and BNP Paribas, as Co-Documentation Agents, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of New York, KeyBank National Association, The Bank of Nova Scotia, U.S. Bank National Association, Merrill Lynch Bank USA, Morgan Stanley Bank, Mizuho Corporate Bank, UMB Bank, N.A., PNC Bank, National Association, Bank Midwest, N.A. and UFJ Bank Limited (Exhibit 10.2.a10.2.b to Form 10-Q for the quarter ended SeptemberJune 30, 2005)2006).
 
10.2.i10.2.8
 
*
 
Stipulation and Agreement dated March 28, 2005, among Kansas City Power & Light Company, Staff of the Missouri Public Service Commission, Office of the Public Counsel, Missouri Department of Natural Resources, Praxair, Inc., Missouri Independent Energy Consumers, Ford Motor Company, Aquila, Inc., The Empire District Electric Company, and Missouri Joint Municipal Electric Utility Commission (Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2005).
 
 146
10.2.j10.2.9
 
*
 
Stipulation and Agreement filed April 27, 2005, among Kansas City Power & Light Company, the Staff of the State Corporation Commission of the State of Kansas, Sprint, Inc., and the Kansas Hospital Association (Exhibit 10.2.a to Form 10-Q for the quarter ended June 30, 2005).
 
10.2.k10.2.10
*
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 (Exhibit 10.2.b to Form 10-Q for the quarter ended September 30, 2006).
10.2.11
 
*
 
Purchase and Sale Agreement dated as of July 1, 2005, between Kansas City Power & Light Company, as Originator, and Kansas City Power & Light Receivables Company, as Buyer (Exhibit 10.2.b to Form 10-Q for the quarter ended June 30, 2005).
 
10.2.l10.2.12
 
*
 
Receivables Sale Agreement dated as of July 1, 2005, among Kansas City Power & Light Receivables Company, as the Seller, Kansas City Power & Light Company, as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi, Ltd., New York Branch, as the Agent, and Victory Receivables Corporation (Exhibit 10.2.c to Form 10-Q for the quarter ended June 30, 2005).
 
12.2
 
 
Computation of Ratio of Earnings to Fixed Charges.
 
23.2.a
 
 
Consent of Counsel.
 
23.2.b
 
 
Consent of Independent Registered Public Accounting Firm.
 
24.2
 
 
Powers of Attorney.
 
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.
 
142
* Filed with the SEC as exhibits to prior registration statements (except as otherwise noted)SEC filings and are incorporated herein by reference and made a part hereof. The exhibit numberSEC filings and filethe exhibit number of the documents so filed, and incorporated herein by reference, are stated in parenthesis in the description of such exhibit.
 
Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from KCP&L upon written request.
 
KCP&L agrees to furnish to the SEC upon request any instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of total assets of KCP&L and its subsidiaries on a consolidated basis.
147
 
Schedule I - Parent Company Financial Statements
GREAT PLAINS ENERGY INCORPORATED
 
Income Statements of Parent Company
 
        
    As Adjusted As Adjusted 
Year Ended December 31
 
2006
 2005 2004 
Operating Expenses
 (millions) 
Other 
$
7.1
 $7.1 $8.5 
General taxes  
0.3
  0.3  0.2 
Total  
7.4
  7.4  8.7 
Operating loss  
(7.4
)
 (7.4) (8.7)
Equity from earnings in subsidiaries  
143.0
  178.2  200.9 
Non-operating income  
1.1
  1.6  2.3 
Non-operating expenses  
-
  (0.1) (0.2)
Interest charges  
(8.9
)
 (9.4) (8.1)
Income before income taxes  
127.8
  162.9  186.2 
Income taxes  
(0.2
)
 (0.6) (3.7)
Net income  
127.6
  162.3  182.5 
Preferred stock dividend requirements  
1.6
  1.6  1.6 
Earnings available for common shareholders 
$
126.0
 $160.7 $180.9 
           
Average number of basic common shares outstanding  
78.0
  74.6  72.0 
Average number of diluted common shares outstanding  
78.2
  74.7  72.1 
           
Basic earnings per common share 
$
1.62
 $2.15 $2.51 
Diluted earnings per common share 
$
1.61
 $2.15 $2.51 
           
Cash dividends per common share 
$
1.66
 $1.66 $1.66 
 
The accompanying Notes to Financial Statements of Parent Company are an integral part
of these statements.
143
GREAT PLAINS ENERGY INCORPORATED
 
Balance Sheets of Parent Company
 
      
    As Adjusted 
December 31
 
2006
 2005 
ASSETS
 (millions) 
Current Assets
     
Cash and cash equivalents 
$
5.8
 $2.0 
Accounts receivable from subsidiaries  
1.6
  1.0 
Notes receivable from subsidiaries  
2.3
  5.4 
Taxes receivable  
1.9
  1.8 
Other  
0.5
  0.5 
Total  
12.1
  10.7 
Nonutility Property and Investments
       
Investment in KCP&L  
1,383.1
  1,151.6 
Investments in other subsidiaries  
178.6
  288.0 
Total  
1,561.7
  1,439.6 
Deferred Charges and Other Assets
       
Deferred Income Taxes  
0.8
  - 
Other  
4.6
  2.0 
Total  
5.4
  2.0 
Total 
$
1,579.2
 $1,452.3 
 The accompanying Notes to Financial Statements of Parent Company are an integral part
 of these statements.
144
 GREAT PLAINS ENERGY INCORPORATED      
 
 Balance Sheets of Parent Company
 
      
     As Adjusted 
December 31
 
 2006
  2005 
 LIABILITIES AND CAPITALIZATION  (millions) 
Current Liabilities
       
Notes payable 
$
-
 $6.0 
Notes payable to subsidiaries  
13.2
  - 
Current maturities of long-term debt  
163.6
  - 
Accounts payable to subsidiaries  
15.6
  0.5 
Accounts payable  
-
  0.1 
Accrued interest  
1.6
  1.7 
Other  
1.9
  6.5 
Total  
195.9
  14.8 
Deferred Credits and Other Liabilities
       
Payable to subsidiaries  
2.1
  - 
Other  
0.3
  0.9 
Total  
2.4
  0.9 
Capitalization
       
Common shareholders' equity       
Common stock-150,000,000 shares authorized without par value       
80,405,035 and 74,783,824 shares issued, stated value  
896.8
  744.4 
Retained earnings  
493.4
  498.6 
Treasury stock-53,499 and 43,376 shares, at cost  
(1.6
)
 (1.3)
Accumulated other comprehensive loss  
(46.7
)
 (7.7)
Total  
1,341.9
  1,234.0 
Cumulative preferred stock $100 par value       
3.80% - 100,000 shares issued  
10.0
  10.0 
4.50% - 100,000 shares issued  
10.0
  10.0 
4.20% - 70,000 shares issued  
7.0
  7.0 
4.35% - 120,000 shares issued  
12.0
  12.0 
Total  
39.0
  39.0 
Long-term debt  
-
  163.6 
Total  
1,380.9
  1,436.6 
Commitments and Contingencies
Total 
$
1,579.2
 $1,452.3 
 
The accompanying Notes to Financial Statements of Parent Company are an integral part of these
 
statements.
 
 
GREAT PLAINS ENERGY INCORPORATED
 
Income Statements of Parent Company
 
        
        
Year Ended December 31
 
2005
20042003
Operating Expenses
 (millions)
   Other 
$
7.1
 $8.5 $5.3 
   General taxes   
0.3
  0.2  0.2 
      Total  
7.4
  8.7  5.5 
Operating loss  
(7.4
)
 (8.7) (5.5)
Equity from earnings in subsidiaries  
178.2
  199.2  149.5 
Non-operating income  
1.6
  2.3  3.1 
Non-operating expenses  
(0.1
)
 (0.2) (0.4)
Interest charges  
(9.4
)
 (8.1) (4.6)
Income before income taxes  
162.9
  184.5  142.1 
Income taxes  
(0.6
)
 (3.7) 2.8 
Net income  
162.3
  180.8  144.9 
Preferred stock dividend requirements  
1.6
  1.6  1.6 
Earnings available for common shareholders 
$
160.7
 $179.2 $143.3 
           
Average number of common shares outstanding  
74.6
  72.0  69.2 
           
Basic and diluted earnings per common share 
$
2.15
 $2.49 $2.07 
           
Cash dividends per common share 
$
1.66
 $1.66 $1.66 
           
The accompanying Notes to Financial Statements of Parent Company are an integral part of these
statements.
148145
GREAT PLAINS ENERGY INCORPORATED
 
Statements of Cash Flows of Parent Company
 
        
    As Adjusted As Adjusted 
Year Ended December 31
 
2006
 2005 2004 
Cash Flows from Operating Activities
 (millions) 
Net income 
$
127.6
 $162.3 $182.5 
Adjustments to reconcile income to net cash from operating activities:      
Amortization  
0.6
  0.6  1.8 
Deferred income taxes, net  
-
  -  0.6 
Equity in earnings from subsidiaries  
(143.0
)
 (178.2) (200.9)
Cash flows affected by changes in:          
Accounts receivable from subsidiaries  
(0.6
)
 (0.4) 4.3 
Taxes receivable  
(0.1
)
 2.6  (4.4)
Accounts payable to subsidiaries  
15.1
  0.5  (0.8)
Other accounts payable  
(0.1
)
 0.1  - 
Accrued taxes  
-
  -  (7.5)
Accrued interest  
(0.1
)
 0.1  0.8 
Cash dividends from subsidiaries  
118.0
  133.9  210.1 
Other  
1.7
  3.0  0.4 
Net cash from operating activities  
119.1
  124.5  186.9 
Cash Flows from Investing Activities
          
Equity contributions to subsidiaries  
(134.6
)
 -  (305.0)
Net change in notes receivable from subsidiaries  
3.1
  11.0  7.8 
Net cash from investing activities  
(131.5
)
 11.0  (297.2)
Cash Flows from Financing Activities
          
Issuance of common stock  
153.6
  9.1  153.7 
Issuance of long-term debt  
-
  -  163.6 
Issuance fees  
(5.7
)
 -  (12.1)
Net change in notes payable to subsidiaries  
13.2
  -  - 
Net change in short-term borrowings  
(6.0
)
 (14.0) (67.0)
Dividends paid  
(132.7
)
 (125.5) (120.8)
Other financing activities  
(6.2
)
 (5.9) (5.0)
Net cash from financing activities  
16.2
  (136.3) 112.4 
Net Change in Cash and Cash Equivalents
  
3.8
  (0.8) 2.1 
Cash and Cash Equivalents at Beginning of Year
  
2.0
  2.8  0.7 
Cash and Cash Equivalents at End of Year
 
$
5.8
 $2.0 $2.8 
           
The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.
 
 
GREAT PLAINS ENERGY INCORPORATED
 
Balance Sheets of Parent Company
 
      
  
December 31
  
2005
2004
ASSETS
 (millions)
Current Assets
     
   Cash and cash equivalents 
$
2.0
 $2.8 
   Accounts receivable from subsidiaries  1.0   0.8 
   Notes receivable from subsidiaries  
5.4
  19.3 
   Taxes receivable  
1.8
  4.4 
   Other  
0.5
  0.5 
      Total  
10.7
  27.8 
Nonutility Property and Investments
       
   Investment in KCP&L  
1,141.0
  1,099.6 
   Investments in other subsidiaries  
288.0
  248.7 
      Total  
1,429.0
  1,348.3 
Deferred Charges and Other Assets
       
      Total  
2.0
  2.5 
      Total 
$
1,441.7
 $1,378.6 
        
LIABILITIES AND CAPITALIZATION
       
Current Liabilities
       
   Notes payable 
$
6.0
 $20.0 
   Accounts payable to subsidiaries  
0.5
  - 
   Accounts payable  0.1   - 
   Accrued interest  
1.7
  1.6 
   Other  
6.5
  6.1 
      Total  
14.8
  27.7 
Deferred Credits and Other Liabilities
       
      Total  
0.9
  6.7 
Capitalization
       
   Common shareholders' equity       
      Common stock-150,000,000 shares authorized without par value   
         74,783,824 and 74,394,423 shares issued, stated value  
777.2
  765.5 
      Unearned compensation  
(2.1
)
 (1.4)
      Capital stock premium and expense  
(30.7
)
 (32.1)
      Retained earnings  
488.0
  451.5 
      Treasury stock-43,376 and 28,488 shares, at cost  
(1.3
)
 (0.9)
      Accumulated other comprehensive loss  
(7.7
)
 (41.0)
         Total  
1,223.4
  1,141.6 
   Cumulative preferred stock $100 par value       
      3.80% - 100,000 shares issued  
10.0
  10.0 
      4.50% - 100,000 shares issued  
10.0
  10.0 
      4.20% - 70,000 shares issued  
7.0
  7.0 
      4.35% - 120,000 shares issued  
12.0
  12.0 
         Total  
39.0
  39.0 
   Long-term debt  
163.6
  163.6 
         Total  
1,426.0
  1,344.2 
Commitments and Contingencies
        
      Total 
$
1,441.7
 $1,378.6 
        
The accompanying Notes to Financial Statements of Parent Company are an integral part of these
statements.
149
GREAT PLAINS ENERGY INCORPORATED
 
Statements of Cash Flows of Parent Company
 
        
Year Ended December 31
 
2005
20042003
Cash Flows from Operating Activities
   (millions)  
Net income 
$
162.3
 $180.8 $144.9 
Adjustments to reconcile income to net cash from operating activities:         
   Amortization  
0.6
  1.8  - 
   Deferred income taxes, net  
-
  0.6  (0.6)
   Equity in earnings from subsidiaries  
(178.2
)
 (199.2) (149.5)
Cash flows affected by changes in:          
   Accounts receivables from subsidiaries  
(0.4
)  4.3  (3.0)
   Taxes receivable  2.6   (4.4)   - 
   Accounts payable to subsidiaries  
0.5
  (0.8) (1.9) 
   Other accounts payable   0.1  -  (0.2) 
   Accrued and current taxes  
-
  (7.5) 1.2 
   Accrued interest  
0.1
  0.8  0.1 
Cash dividends from subsidiaries  
133.9
  210.1  98.0 
Other  
3.0
  0.4  0.7 
      Net cash from operating activities  
124.5
  186.9  89.7 
Cash Flows from Investing Activities
          
Equity contributions to subsidiaries  
-
  (305.0) (100.0)
Net change in notes receivable from subsidiaries  
11.0
  7.8  56.3 
      Net cash from investing activities  
11.0
  (297.2) (43.7)
Cash Flows from Financing Activities
          
Issuance of common stock  
9.1
  153.7  - 
Issuance of long-term debt  
-
  163.6  - 
Issuance fees  
-
  (12.1) - 
Net change in short-term borrowings  
(14.0
)
 (67.0) 68.3 
Dividends paid  
(125.5
)
 (120.8) (116.5)
Other financing activities  
(5.9
)
 (5.0) (0.4)
      Net cash from financing activities  
(136.3
)
 112.4  (48.6)
Net Change in Cash and Cash Equivalents
  
(0.8
)
 2.1  (2.6)
Cash and Cash Equivalents at Beginning of Year
  
2.8
  0.7  3.3 
Cash and Cash Equivalents at End of Year
 
$
2.0
 $2.8 $0.7 
           
The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Statements of Common Shareholders’ Equity of Parent Company
Statements of Comprehensive Income of Parent Company

Incorporated by reference is Great Plains Energy Consolidated Statements of Common Shareholders’ Equity and Consolidated Statements of Comprehensive Income.
 
150
146
GREAT PLAINS ENERGY INCORPORATED
NOTES TO FINANCIAL STATEMENTS OF PARENT COMPANY
 
The following are supplemental notes to the Great Plains Energy Incorporated Parent Company Financial Statements and should be read in conjunction with the Great Plains Energy Incorporated Notes to Consolidated Financial Statements in Part II, Item. 8.
1.  
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Item 8 should be read in conjunction with the 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.Incorporated Parent Company Financial Statements.
 
2.  
GUARANTEES
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 and indemnification of 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. The majority of these agreements guarantee the future performance of Great Plains Energy or its subsidiaries, so a liability for the fair value of the obligation is not recorded.
Great Plains Energy has provided $122.0 million of guarantees to support certain Strategic Energy power purchases and regulatory requirements. At December 31, 2005, guarantees related to Strategic Energy are as follows:
·  Great Plains Energy direct guarantees to counterparties totaling $58.0 million, which expire in 2006,
·  Great Plains Energy provides indemnifications to the issuers of surety bonds totaling $0.5 million, which expire in 2006,
·  Great Plains Energy guarantees related to letters of credit totaling $25.0 million, which expire in 2006 and
·  Great Plains Energy letters of credit totaling $38.5 million.
151
Schedule II - Valuation and Qualifying Accounts and Reserves

Great Plains Energy
 
Valuation and Qualifying Accounts
 
Years Ended December 31, 2005, 2004 and 2003
 
            
    
Additions
    
    
Charged
      
  
Balance At
To Costs
Charged
  
Balance
  
Beginning
And
To Other
  
At End
Description
 
Of Period
Expenses
Accounts
Deductions
Of Period
Year Ended December 31, 2005 (millions) 
Allowance for uncollectible accounts $6.4 $6.9 $5.0 (a)$11.4 (b)$6.9 
Legal reserves  3.2  4.5  -  1.8 (c) 5.9 
Environmental reserves  0.3  -  -  -  0.3 
Uncertain tax positions  13.4  1.2  -  10.0 (d) 4.6 
Year Ended December 31, 2004                
Allowance for uncollectible accounts $8.5 $5.4 $2.8 (a)$10.3 (b)$6.4 
Legal reserves  4.0  1.4  -  2.2 (c) 3.2 
Environmental reserves  1.8  -  -  1.5 (e) 0.3 
Uncertain tax positions  16.8  3.2  -  6.6 (d) 13.4 
Year Ended December 31, 2003                
Allowance for uncollectible accounts $8.8 $5.1 $2.8 (a)$8.2 (b)$8.5 
Legal reserves  3.8  3.3  -  3.1 (c) 4.0 
Environmental reserves  1.9  -  -  0.1 (f) 1.8 
Tax valuation allowance  15.8  (15.8
) (g)
 -  -  - 
Uncertain tax positions  2.5  12.0  3.6 (h) 1.3 (d) 16.8 
Discontinued operations  1.7  -  -  1.7 (i) - 
 
(a) Recoveries. Charged to other accounts for the year ended December 31, 2005, includes the establishment of an
   allowance of $1.6 million.
(b) Uncollectible accounts charged off. Deductions for the year ended December 31, 2004, includes a charge off of
   $1.4 million by Worry Free.
(c) Payment of claims.
(d)Reversal of uncertain tax positions. Deductions for the year ended December 31, 2005, includes a reclass of
 
   $0.8 million to franchise taxes payable. Deductions for the year ended December 31, 2003, includes taxes paid
   for an IRS settlement.
(e) Reversal of reserve for remediation of soil and groundwater. 
(f) Payment of expenses. 
(g)A tax valuation allowance of $15.8 million was recorded at KLT Telecom in 2001 to reduce the income tax benefits 
   arising primarily from DTI's 2002 abandonment of its $104 million of long-haul assets. The allowance was 
   necessary due to the uncertainty of recognizing future tax deductions while DTI was in the bankruptcy process. The 
   allowance was reversed in 2003 after confirmation of the DTI restructuring plan. 
(h) Establishment of liability for uncertain tax positions for prior years current tax expense in excess of taxes paid. 
(i) In 2003, HSS completed the disposition of its interest in RSAE.
 
Great Plains Energy
 
Valuation and Qualifying Accounts
 
Years Ended December 31, 2006,  2005 and 2004
 
 
    
Additions
    
    
Charged
      
  
Balance At
To Costs
Charged
  
Balance
  
Beginning
And
To Other
  
At End
Description
 
Of Period
Expenses
Accounts
Deductions
Of Period
Year Ended December 31, 2006 (millions) 
Allowance for uncollectible accounts $6.9 $12.3 $5.7 (a)$16.6 (b)$8.3 
Legal reserves  5.9  4.9  0.1  4.8 (c) 6.1 
Environmental reserves  0.3  -  -  -  0.3 
Uncertain tax positions  4.6  1.1  -  1.0 (d) 4.7 
Year Ended December 31, 2005                
Allowance for uncollectible accounts $6.4 $6.9 $5.0 (a)$11.4 (b)$6.9 
Legal reserves  3.2  4.5  -  1.8 (c) 5.9 
Environmental reserves  0.3  -  -  -  0.3 
Uncertain tax positions  13.4  1.2  -  10.0 (d) 4.6 
Year Ended December 31, 2004                
Allowance for uncollectible accounts $8.5 $5.4 $2.8 (a)$10.3 (b)$6.4 
Legal reserves  4.0  1.4  -  2.2 (c) 3.2 
Environmental reserves  1.8  -  -  1.5 (e) 0.3 
Uncertain tax positions
  16.8  3.2  -  6.6 (d) 13.4 
(a) Recoveries. Charged to other accounts for the year ended December 31, 2006 and 2005, respectively, includes the 
 
 
   establishmentof an allowance of $1.5 million and $1.6 million.
(b) Uncollectible accounts charged off. Deductions for the year ended December 31, 2004, includes a charge off of
 
 
   $1.4 million by Worry Free.
(c) Payment of claims.
(d)Reversal of uncertain tax positions. Deductions for the year ended December 31, 2005, includes a reclass of
 
 
   $0.8 million to franchise taxes payable. 
(e) Reversal of reserve for remediation of soil and groundwater.
 
 
 
152
147
Kansas city Power & Light Company
 
Valuation and Qualifying Accounts
 
Years Ended December 31, 2006, 2005 and 2004
 
            
    
Additions
    
    
Charged
      
  
Balance At
To Costs
Charged
  
Balance
  
Beginning
And
To Other
  
At End
Description
 
Of Period
Expenses
Accounts
Deductions
Of Period
Year Ended December 31, 2006 (millions) 
Allowance for uncollectible accounts $2.6 $4.5 $4.4 (a)$7.3 (b)$4.2 
Legal reserves  4.5  2.8  -  3.4 (c) 3.9 
Environmental reserves  0.3  -  -  -  0.3 
Uncertain tax positions  1.2  0.8  -  0.2 (d) 1.8 
Year Ended December 31, 2005                
Allowance for uncollectible accounts $1.7 $3.3 $4.6 (a)$7.0 (b)$2.6 
Legal reserves  3.2  3.1  -  1.8 (c) 4.5 
Environmental reserves  0.3  -  -  -   0.3 
Uncertain tax positions  3.7  0.3  -  2.8 (d) 1.2 
Year Ended December 31, 2004                
Allowance for uncollectible accounts $4.9 $2.6 $2.7 (a)$8.5 (b)$1.7 
Legal reserves  3.8  1.4  -  2.0 (c) 3.2 
Environmental reserves  1.8  -  -  1.5 (e) 0.3 
Uncertain tax positions  6.4  2.1  -   4.8 (d) 3.7 
(a) Recoveries. Charged to other accounts for the year ended December 31, 2006 and 2005, respectively, includes the
 
 
   establishment of an allowance of $1.5 million and $1.6 million.
(b) Uncollectible accounts charged off. Deductions for the year ended December 31, 2004, includes a charge off of
 
 
   $1.4 million by Worry Free.
(c) Payment of claims.
(d)Reversal of uncertain tax positions. Deductions for the year ended December 31, 2005, includes a reclass of
 
 
   $0.8 million to franchise taxes payable. 
(e) Reversal of reserve for remediation of soil and groundwater.
 
 
 
Kansas City Power & Light Company
 
Valuation and Qualifying Accounts
 
Years Ended December 31, 2005, 2004 and 2003
 
            
    
Additions
    
    
Charged
      
  
Balance At
To Costs
Charged
  
Balance
  
Beginning
And
To Other
  
At End
Description
 
Of Period
Expenses
Accounts
Deductions
Of Period
Year Ended December 31, 2005 (millions) 
Allowance for uncollectible accounts $1.7 $3.3 $4.6 (a)$7.0 (b)$2.6 
Legal reserves  3.2  3.1  -  1.8 (c) 4.5 
Environmental reserves  0.3  -  -  -  0.3 
Uncertain tax positions  3.7  0.3  -  2.8 (d) 1.2 
Year Ended December 31, 2004                
Allowance for uncollectible accounts $4.9 $2.6 $2.7 (a)$8.5 (b)$1.7 
Legal reserves  3.8  1.4  -  2.0 (c) 3.2 
Environmental reserves  1.8  -  -  1.5 (e) 0.3 
Uncertain tax positions  6.4  2.1  -  4.8 (d) 3.7 
Year Ended December 31, 2003                
Allowance for uncollectible accounts $5.6 $3.5 $2.7 (a)$6.9 (b)$4.9 
Legal reserves  3.8  3.1  -  3.1 (c) 3.8 
Environmental reserves  1.9  -  -  0.1 (f) 1.8 
Uncertain tax positions  2.5  3.9  1.2 (g) 1.2 (d) 6.4 
Discontinued operations  1.7  -  -  1.7 (h) - 
 
(a) Recoveries. Charged to other accounts for the year ended December 31, 2005, includes the establishment of an
   allowance of $1.6 million.
(b) Uncollectible accounts charged off. Deductions for the year ended December 31, 2004, includes a charge off of
   $1.4 million by Worry Free.
(c) Payment of claims.
(d)Reversal of uncertain tax positions. Deductions for the year ended December 31, 2005, includes a reclass of
 
   $0.8 million to franchise taxes payable. Deductions for the year ended December 31, 2003, includes taxes paid
   for an IRS settlement.
(e) Reversal of reserve for remediation of soil and groundwater. 
(f) Payment of expenses. 
(g) Establishment of liability for uncertain tax positions for prior years current tax expense in excess of taxes paid. 
(i) In 2003, HSS completed the disposition of its interest in RSAE.
 
 
153148

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
GREAT PLAINS ENERGY INCORPORATED
Date: March 8, 2006February 27, 2007                      By: /s/Michael J. Chesser
Michael J. Chesser
Chairman of the Board and
Chief Executive Officer
 
Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
Signature
Title
Date
/s/Michael J. Chesser
Michael J. Chesser
Chairman of the Board and Chief
Executive Officer
(Principal Executive Officer)
)
)
)
  )
 
/s/Terry Bassham
Terry Bassham
Executive Vice President - Finance
and Strategic Development and
Chief Financial Officer
(Principal Financial Officer)
)
)
)
)
  )
/s/Lori A. Wright
Lori A. Wright
Controller
(Principal Accounting Officer)
)
)
  )
David L. Bodde*Director)   March 8, 2006February 27, 2007
  )
/s/William H. Downey
William H. Downey
Director
)
)
  )
Mark A. Ernst*Director)
  )
Randall C. Ferguson, Jr.*Director)
  )
William K. Hall*Director)
  )
Luis A. Jimenez*Director)
  )
James A. Mitchell*Director)
  )
William C. Nelson*Director)
  )
Linda H. Talbott*Director)
  )
Robert H. West*Director)
*By/s/Michael J. Chesser
Michael J. Chesser
Attorney-in-Fact*

154

149
SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
KANSAS CITY POWER & LIGHT COMPANY
Date: March 8, 2006February 27, 2007         By: /s/ William H. Downey
William H. Downey
President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
Signature
Title
Date
/s/ William H. Downey
William H. Downey
President and Chief Executive
Officer and Director
(Principal Executive Officer)
)
)
)
  )
/s/Terry Bassham
Terry Bassham
Chief Financial Officer
(Principal Financial Officer)
)
)
  )
/s/Lori A. Wright
Lori A. Wright
Controller
(Principal Accounting Officer)
)
)
  )
David L. Bodde*Director)   March 8, 2006February 27, 2007
  )
/s/Michael J. Chesser
Michael J. Chesser
Chairman of the Board
)
)
  )
Mark A. Ernst*Director)
  )
Randall C. Ferguson, Jr.*Director)
  )
Luis A. Jimenez*Director)
  )
James A. Mitchell*Director)
  )
William C. Nelson*Director)
  )
Linda H. Talbott*Director)
  )
*By/s/Michael J. Chesser
Michael J. Chesser
Attorney-in-Fact*

155

Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act.
KCP&L did not send any annual report to security holders covering its last fiscal year, and did not send any proxy statement, form of proxy or other proxy soliciting material to its security holders with respect to any annual or other meeting of security holders.
 
156
150