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PART IV

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



FORM 10-K

(Mark One)    

ý

 

Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2012

or

o

 

Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                                to                                 .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)

Kansas
(State of Incorporation)
  44-0236370
(I.R.S. Employer Identification No.)

602 S. Joplin Avenue, Joplin, Missouri
(Address of principal executive offices)

 

64801
(zip code)

Registrant's telephone number: (417) 625-5100

Securities registered pursuant to Section 12(b) of the Act:

Title of each class   Name of each exchange on which registered
Common Stock ($1 par value)   New York Stock Exchange

         Securities registered pursuant to Section 12(g) of the Act: None

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

         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. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

         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 this Form 10-K. ý

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ý   Accelerated filer o   Non-accelerated filer o
(Do not check if a
smaller reporting company)
  Smaller reporting company o

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

         The aggregate market value of the registrant's voting common stock held by nonaffiliates of the registrant, based on the closing price on the New York Stock Exchange on June 30, 2012, was approximately $892,694,285.

         As of February 1, 2013, 42,535,367 shares of common stock were outstanding.

         The following documents have been incorporated by reference into the parts of the Form 10-K as indicated:

The Company's proxy statement, filed pursuant
to Regulation 14A under the Securities Exchange
Act of 1934, for its Annual Meeting of
Stockholders to be held on April 25, 2013
  Part of Item 10 of Part III
All of Item 11 of Part III
Part of Item 12 of Part III
All of Item 13 of Part III
All of Item 14 of Part III

   


Table of Contents


TABLE OF CONTENTS

 
   
  Page

 

Forward Looking Statements

  3

PART I

ITEM 1.

 

BUSINESS

  5

 

General

  5

 

Electric Generating Facilities and Capacity

  6

 

Gas Facilities

  8

 

Construction Program

  8

 

Fuel and Natural Gas Supply

  9

 

Employees

  11

 

Electric Operating Statistics

  12

 

Gas Operating Statistics

  13

 

Executive Officers and other Officers of Empire

  14

 

Regulation

  14

 

Environmental Matters

  15

 

Conditions Respecting Financing

  15

 

Our Web Site

  16

ITEM 1A.

 

RISK FACTORS

  17

ITEM 1B.

 

UNRESOLVED STAFF COMMENTS

  21

ITEM 2.

 

PROPERTIES

  21

 

Electric Segment Facilities

  21

 

Gas Segment Facilities

  23

 

Other Segment

  23

ITEM 3.

 

LEGAL PROCEEDINGS

  23

ITEM 4.

 

MINE SAFETY DISCLOSURES

  23

PART II

ITEM 5.

 

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

  24

ITEM 6.

 

SELECTED FINANCIAL DATA

  26

ITEM 7.

 

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

  26

 

Executive Summary

  26

 

Results of Operations

  31

 

Rate Matters

  39

 

Competition

  40

 

Liquidity and Capital Resources

  40

 

Contractual Obligations

  46

 

Dividends

  47

 

Off-Balance Sheet Arrangements

  48

 

Critical Accounting Policies

  48

 

Recently Issued Accounting Standards

  51

ITEM 7A

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  52

ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  55

ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

  129

ITEM 9A.

 

CONTROLS AND PROCEDURES

  129

ITEM 9B.

 

OTHER INFORMATION

  129

PART III

ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

  130

ITEM 11.

 

EXECUTIVE COMPENSATION

  130

ITEM 12.

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

  130

ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

  131

ITEM 14.

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES

  131

PART IV

ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

  132

 

SIGNATURES

  138

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FORWARD LOOKING STATEMENTS

        Certain matters discussed in this annual report are "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, impacts from the 2011 tornado, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like "anticipate", "believe", "expect", "project", "objective" or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:

    weather, business and economic conditions, recovery and rebuilding efforts relating to the 2011 tornado and other factors which may impact sales volumes and customer growth;

    the costs and other impacts resulting from natural disasters, such as tornados and ice storms;

    the amount, terms and timing of rate relief we seek and related matters;

    the results of prudency and similar reviews by regulators of costs we incur, including capital expenditures, fuel and purchased power costs and Southwest Power Pool (SPP) regional transmission organization (RTO) expansion costs, including any regulatory disallowances that could result from prudency reviews;

    legislation and regulation, including environmental regulation (such as NOx, SO2, mercury, ash and CO2) and health care regulation;

    competition and markets, including the SPP Energy Imbalance Services Market and SPP Day-Ahead Market;

    electric utility restructuring, including ongoing federal activities and potential state activities;

    volatility in the credit, equity and other financial markets and the resulting impact on our short term debt costs and our ability to issue debt or equity securities, or otherwise secure funds to meet our capital expenditure, dividend and liquidity needs;

    the effect of changes in our credit ratings on the availability and cost of funds;

    the performance of our pension assets and other post employment benefit plan assets and the resulting impact on our related funding commitments;

    the periodic revision of our construction and capital expenditure plans and cost and timing estimates;

    our exposure to the credit risk of our hedging counterparties;

    changes in accounting requirements (including the potential consequences of being required to report in accordance with IFRS rather than U. S. GAAP);

    unauthorized physical or virtual access to our facilities and systems and acts of terrorism, including, but not limited to, cyber-terrorism;

    the timing of accretion estimates, and integration costs relating to completed and contemplated acquisitions and the performance of acquired businesses;

    rate regulation, growth rates, discount rates, capital spending rates, terminal value calculations and other factors integral to the calculations utilized to test the impairment of goodwill, in addition to market and economic conditions which could adversely affect the analysis and ultimately negatively impact earnings;

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    the success of efforts to invest in and develop new opportunities;

    the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs;

    interruptions or changes in our coal delivery, gas transportation or storage agreements or arrangements;

    operation of our electric generation facilities and electric and gas transmission and distribution systems, including the performance of our joint owners;

    costs and effects of legal and administrative proceedings, settlements, investigations and claims; and

    other circumstances affecting anticipated rates, revenues and costs.

        All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us. Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

        We caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual results, performance or achievements to differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements.

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PART 1

ITEM 1.    BUSINESS

General

        We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary engaged in the distribution of natural gas in Missouri. Our other segment consists of our fiber optics business.

        Our gross operating revenues in 2012 were derived as follows:

Electric segment sales*

    91.7 %

Gas segment sales

    7.1  

Other segment sales

    1.2  

*
Sales from our electric segment include 0.3% from the sale of water.

        The territory served by our electric operations embraces an area of about 10,000 square miles, located principally in southwestern Missouri, and also includes smaller areas in southeastern Kansas, northeastern Oklahoma and northwestern Arkansas. The principal economic activities of these areas include light industry, agriculture and tourism. As of December 31, 2012, our electric operations served approximately 167,900 customers.

        Our retail electric revenues for 2012 by jurisdiction were derived as follows:

Missouri

    89.3 %

Kansas

    5.1  

Arkansas

    2.7  

Oklahoma

    2.9  

        We supply electric service at retail to 119 incorporated communities as of December 31, 2012, and to various unincorporated areas and at wholesale to four municipally owned distribution systems. The largest urban area we serve is the city of Joplin, Missouri, and its immediate vicinity, with a population of approximately 160,000. We operate under franchises having original terms of twenty years or longer in virtually all of the incorporated communities. Approximately 52% of our electric operating revenues in 2012 were derived from incorporated communities with franchises having at least ten years remaining and approximately 18% were derived from incorporated communities in which our franchises have remaining terms of ten years or less. Although our franchises contain no renewal provisions, in recent years we have obtained renewals of all of our expiring electric franchises prior to the expiration dates.

        Our three largest classes of on-system customers are residential, commercial and industrial, which provided 42.2%, 31.2%, and 15.5%, respectively, of our electric operating revenues in 2012.

        Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2012 accounted for approximately 2.8% of electric revenues. No single retail customer accounted for more than 1.7% of electric revenues in 2012.

        Our gas operations serve customers in northwest, north central and west central Missouri. As of December 31, 2012, our gas operations served approximately 44,000 customers. We provide natural gas distribution to 48 communities and 330 transportation customers as of December 31, 2012. The largest urban area we serve is the city of Sedalia with a population of over 20,000. We operate under franchises having original terms of twenty years in virtually all of the incorporated communities. Twenty of the

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franchises have 10 years or more remaining on their term. Although our franchises contain no renewal provisions, since our acquisition we have obtained renewals of all our expiring gas franchises prior to the expiration dates.

        Our gas operating revenues in 2012 were derived as follows:

Residential

    62.1 %

Commercial

    27.1  

Industrial

    1.2  

Miscellaneous

    9.6  

        No single retail customer accounted for more than 1% of gas revenues in 2012.

        Our other segment consists of our fiber optics business. As of December 31, 2012, we have 106 fiber customers.


Electric Generating Facilities and Capacity

        At December 31, 2012, our generating plants consisted of:

Plant
  Capacity
(megawatts)(1)
  Primary Fuel

Asbury

    203   Coal

Riverton — Coal

    0 (2) Coal

Riverton — Natural Gas

    279 (2) Natural Gas

Iatan (12% ownership)

    190 (3) Coal

Plum Point Energy Station (7.52% ownership)

    50 (3) Coal

State Line Combined Cycle (60% ownership)

    297 (3) Natural Gas

Empire Energy Center

    262   Natural Gas

State Line Unit No. 1

    94   Natural Gas

Ozark Beach

    16   Hydro
         

TOTAL

    1,391    
         

(1)
Based on summer rating conditions as utilized by Southwest Power Pool.

(2)
In September 2012, Riverton Units 7 and 8 transitioned from operation on coal to full operation on natural gas.

(3)
Capacity reflects our allocated shares of the capacity of these plants.

        See Item 2, "Properties — Electric Segment Facilities" for further information about these plants.

        We, and most other electric utilities with interstate transmission facilities, have placed our facilities under the Federal Energy Regulatory Commission (FERC) regulated open access tariffs that provide all wholesale buyers and sellers of electricity the opportunity to procure transmission services (at the same rates) that the utilities provide themselves. We are a member of the Southwest Power Pool Regional Transmission Organization (SPP RTO). See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Competition."

        We currently supplement our on-system generating capacity with purchases of capacity and energy from other sources in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council rules. The SPP requires its members to maintain a minimum 12% capacity margin. Our long-term contract with Westar Energy for the purchase of 162 megawatts of capacity and energy ended May 31, 2010. In order to replace this capacity and energy, we entered into contracts for energy and capacity from two new plants that became

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operational in 2010, Plum Point Energy Station and the Iatan 2 generating facility, each of which is described below.

        The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas which entered commercial operation on September 1, 2010. We own, through an undivided interest, 50 megawatts of the unit's capacity. We also have a long-term (30 year) agreement for the purchase of capacity from Plum Point. We began receiving purchased power under this agreement on September 1, 2010. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. At this time it is not our intention to exercise this option. Rather, we intend to continue to meet our demand and capacity requirements with the continuation of this long-term purchased power agreement. We will, however, continue to analyze this option during our 2013 Integrated Resource Plan (IRP) process, which we expect to file with the Missouri Public Service Commission (MPSC) in mid-2013.

        We also own an undivided ownership interest in the coal-fired Iatan 2 generating facility operated by Kansas City Power & Light Company (KCP&L) and located at the site of the existing 85-megawatt Iatan Generating Station (Iatan 1) near Weston, Missouri. We own 12%, or approximately 105 megawatts, of the 850-megawatt unit, which entered commercial operation on December 31, 2010.

        We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC (formerly Horizon Wind Energy), Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We also have a 20-year contract, which began on December 15, 2005, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. We do not own any portion of either windfarm.

        The following chart sets forth our purchase commitments and our anticipated owned capacity (in megawatts) during the indicated years. The capacity ratings we use for our generating units are based on summer rating conditions under SPP guidelines. The portion of the purchased power that may be counted as capacity from the Elk River Windfarm, LLC and the Cloud County Windfarm, LLC is included in this chart. Because the wind power is an intermittent, non-firm resource, SPP rating criteria does not allow us to count a substantial amount of the wind power as capacity. See Item 7, "Managements' Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources."

Year
  Purchased
Power
Commitment(1)
  Anticipated
Owned
Capacity
  Total
Megawatts
 

2013

    65     1391     1456  

2014

    65     1391     1456  

2015

    65     1377     1442 (2)

2016

    65     1383     1448 (3)

2017

    65     1383     1448  

(1)
Includes 7 megawatts for the Elk River Windfarm, LLC and 8 megawatts for the Cloud County Windfarm, LLC.

(2)
Reflects the planned retirement of Asbury Unit 2.

(3)
Reflects the planned retirement of Riverton Units 7, 8 and 9 and conversion of Riverton Unit 12 to a combined cycle.

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        The maximum hourly demand on our system reached a record high of 1,199 megawatts on January 8, 2010. Our previous winter peak of 1,100 megawatts was established on December 22, 2008. Our maximum hourly summer demand of 1,198 megawatts was set on August 2, 2011. Our previous summer record peak of 1,173 megawatts was established on August 15, 2007.


Gas Facilities

        At December 31, 2012, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,148 miles of distribution mains.

        The following table sets forth the three pipelines that serve our gas customers:

Service Area
  Name of Pipeline
South   Southern Star Central Gas Pipeline
North   Panhandle Eastern Pipe Line Company
Northwest   ANR Pipeline Company

        Our all-time peak of 73,280 mcfs was established on January 7, 2010, replacing the previous record of 70,820 mcfs which was set on January 4, 2010.


Construction Program

        Total property additions (including construction work in progress but excluding AFUDC) for the three years ended December 31, 2012, amounted to $343.6 million and retirements during the same period amounted to $36.8 million. Please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources" for more information.

        Our total capital expenditures, excluding AFUDC and expenditures to retire assets, were $142.6 million in 2012 and for the next three years are estimated for planning purposes to be as follows:

 
  Estimated Capital Expenditures
(amounts in millions)
 
 
  2013   2014   2015   Total  

New electric generating facilities:

                         

Riverton Unit 12 combined cycle conversion

  $ 15.1   $ 40.4   $ 65.3   $ 120.8  

Additions to existing electric generating facilities:

                         

Asbury

    11.1     16.7     8.1     35.9  

Environmental upgrades — Asbury

    55.8     24.8     12.1     92.7  

Other

    10.7     4.9     9.4     25.0  

Electric transmission facilities

    12.1     26.7     36.3     75.1  

Electric distribution system additions

    42.9     38.3     36.3     117.5  

General and other additions

    10.1     7.9     4.8     22.8  

Gas system additions

    4.1     4.1     4.1     12.3  

Non-regulated additions

    1.5     1.7     1.7     4.9  
                   

TOTAL

  $ 163.4   $ 165.5   $ 178.1   $ 507.0  
                   

        Our estimated total capital expenditures (excluding AFUDC) for 2016 and 2017 are $107.0 million and $108.2 million, respectively. Construction expenditures for additions to our transmission and distribution systems, the conversion of Riverton Unit 12 to a combined cycle unit and environmental upgrades at Asbury constitute the majority of the projected capital expenditures for the three-year period listed above.

        Estimated capital expenditures are reviewed and adjusted for, among other things, revised estimates of future capacity needs, the cost of funds necessary for construction, costs to recover from natural

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disasters and the availability and cost of alternative power. Actual capital expenditures may vary significantly from the estimates due to a number of factors including changes in customer requirements, construction delays, changes in equipment delivery schedules, ability to raise capital, environmental matters, the extent to which we receive timely and adequate rate increases, the extent of competition from independent power producers and cogenerators, other changes in business conditions and changes in legislation and regulation, including those relating to the energy industry. See "— Regulation" below and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Competition."


Fuel and Natural Gas Supply

Electric Segment

        Our total system output for 2012 and 2011, based on kilowatt-hours generated, was as follows:

 
  2012   2011  

Steam generation units — coal

    48.0 %   45.0 %

Steam generation units — natural gas

    0.2     2.3  

Combustion turbine generation units — natural gas

    24.9     23.9  

Hydro generation

    1.0     0.8  

Purchased power — windfarms

    15.0     13.4  

Purchased power — other

    10.9     14.6  

        Below are the total fuel requirements for our generating units in 2012 (based on kilowatt-hours generated):

Coal

    65.6 %

Natural gas

    34.3  

Fuel oil

    0.1  

        The amount and percentage of electricity generated by natural gas increased in 2012 as compared to 2011 while the amount of energy we purchased decreased, primarily reflecting that it was more economical to produce gas-fired generation than to purchase power during this period.

        During 2012, we utilized our remaining coal inventory at our Riverton Plant, completing our transition of Units 7 and 8 to natural gas. This was done as part of our environmental Compliance Plan, discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8. Riverton Unit 12, a Siemens V84.3A2 gas combustion turbine installed in 2007, and three other smaller units are also fueled by natural gas. Natural gas is now the primary fuel at our Riverton Plant.

        Our Asbury Plant is fueled primarily by coal with oil being used as start-up fuel. In 2012, Asbury burned a coal blend consisting of approximately 92.7% Western coal (Powder River Basin) and 7.3% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2012, we had sufficient coal on hand to supply full load requirements at Asbury for 102-107 days, as compared to 47-94 days as of December 31, 2011, depending on the actual blend ratio. The inventory increased during 2012 as coal destined for Riverton was diverted to Asbury to facilitate the conversion of Riverton Units 7 and 8 to natural gas.

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        The following table sets forth the percentage of our anticipated coal requirements we have secured through a combination of contracts and binding proposals for the following years:

Year
  Percentage secured  

2013

    100 %

2014

    58 %

2015

    26 %

        All of the Western coal used at our Asbury plant is shipped by rail, a distance of approximately 800 miles. We entered into an amended coal transportation contract on August 7, 2012, with the Burlington Northern and Santa Fe Railway Company (BNSF) and the Kansas City Southern Railway Company due to the reduction of coal usage resulting from Riverton's conversion to natural gas. The amendment reduces the annual minimum tons for the years 2013 through 2016 and extends the contract through 2019. We currently lease one aluminum unit train full time to deliver Western coal to the Asbury Plant.

        Unit 1 and Unit 2 at the Iatan Plant are coal-fired generating units which are jointly-owned by KCP&L, a subsidiary of Great Plains Energy, Inc., Missouri Joint Municipal Electric Utility Commission, Kansas Electric Power Cooperative (KEPCO) and us, with our share of ownership being 12% in each plant. KCP&L is the operator of these plants and is responsible for arranging their fuel supply. KCP&L has secured contracts for low sulfur Western coal in quantities sufficient to meet 100% of Iatan's requirements for 2013 and approximately 75% for 2014 and 20% for 2015. The coal is transported by rail under a contract with BNSF Railway, which expires on December 31, 2013. KCP&L and KCP&L Greater Missouri Operations are currently in negotiations with the railroads for transportation services beyond 2013.

        The Plum Point Energy Station is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. The plant began commercial operation on September 1, 2010. We own, through an undivided interest, 50 megawatts of the plant's capacity. North America Energy Services is the operator of this plant. Plum Point Services Company, LLC (PPSC), the project management company acting on behalf of the joint owners, is responsible for arranging its fuel supply. PPSC has secured contracts for low sulfur Western coal in quantities sufficient to meet approximately 86% of Plum Point's requirements for 2013, 86% for 2014, 86% for 2015 and 94% for 2016. We have a 15-year lease agreement, expiring in 2024, for 54 railcars for our ownership share of Plum Point. In December 2010, we entered into another 15-year lease agreement for an additional 54 railcars associated with our Plum Point purchased power agreement.

        Our Energy Center and State Line combustion turbine facilities (not including the State Line Combined Cycle (SLCC) Unit, which is fueled 100% by natural gas) are fueled primarily by natural gas with oil also available for use primarily as backup. Based on kilowatt hours generated during 2012, Energy Center generation was 99.0% natural gas with the remainder being fuel oil, and 100% of the State Line Unit 1 generation came from natural gas. As of December 31, 2012, oil inventories were sufficient for approximately 2 days of full load operation on Units No. 1, 2, 3 and 4 at the Energy Center and 5 days of full load operation for State Line Unit No. 1. As typical oil usage is minimal, these inventories are sufficient for our current requirements. Additional oil will be purchased as needed.

        We have firm transportation agreements with Southern Star Central Pipeline, Inc. with current expiration dates of June 24, 2017, for the transportation of natural gas to the SLCC. This date is adjusted for periods of contract suspension by us during outages of the SLCC. This transportation agreement can also supply natural gas to State Line Unit No.1, the Energy Center or the Riverton Plant, as elected by us on a secondary basis. We also have a precedent agreement with Southern Star, which provides additional transportation capability until 2022. This contract provides firm transport to the sites listed above that previously were only served on a secondary basis. We expect that these transportation agreements will serve nearly all of our natural gas transportation needs for our generating plants over the next several years. Any remaining gas transportation requirements, although small, will be met by utilizing capacity release on other holder contracts, interruptible transport, or delivered to the plants by others.

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        The majority of our physical natural gas supply requirements will be met by short-term forward contracts and spot market purchases. Forward natural gas commodity prices and volumes are hedged several years into the future in accordance with our Risk Management Policy in an attempt to lessen the volatility in our fuel expenditures and gain predictability. In addition, we have an agreement with Southern Star to purchase one million Dths of firm gas storage service capacity for a period of five years, expiring in 2016. The reservation charge for this storage capacity is approximately $1.1 million annually. This storage capacity enables us to better manage our natural gas commodity and transportation needs for our electric segment.

        The following table sets forth a comparison of the costs, including transportation and other miscellaneous costs, per million Btu of various types of fuels used in our electric facilities:

Fuel Type / Facility
  2012   2011   2010  

Coal — Iatan

  $ 1.760   $ 1.603   $ 1.193  

Coal — Asbury

    2.395     2.315     1.877  

Coal — Riverton

    2.541     2.314     1.833  

Coal — Plum Point

    1.804     1.858     1.799  

Natural Gas

    4.493     5.475     6.061  

Oil

    20.291     21.304     15.443  
               

Weighted average cost of fuel burned per kilowatt-hour generated

    2.6742     2.9558     2.9936  

Gas Segment

        We have 10,000 MMBtus per day of firm transportation from Cheyenne Plains Pipeline Company. This can provide us with up to 75% of our natural gas purchases from the Rocky Mountain gas area. Cheyenne Plains interconnects with all of the interstate pipelines listed below that feed our market area.

        We have agreements with many of the major suppliers in both the Midcontinent and Rocky Mountain regions that provide us with both supply and price diversity. We continue to expand our supplier base to enhance supply reliability as well as provide for increased price competition.

        The following table sets forth the current costs, including storage, transportation and other miscellaneous costs, per mcf of gas used in our gas operations:

Service Area
  Name of Pipeline   2012   2011   2010  

South

  Southern Star Central Gas Pipeline   $ 6.4329   $ 6.1619   $ 6.7068  

North

  Panhandle Eastern Pipe Line Company     6.8990     6.1449     6.1151  

Northwest

  ANR Pipeline Company     5.0898     5.4230     5.3216  

  Weighted average cost per mcf   $ 6.3305   $ 6.0542   $ 6.3745  


Employees

        At December 31, 2012, we had 756 full-time employees, including 51 employees of EDG. 331 of the EDE employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW). On October 17, 2011, the Local 1474 IBEW voted to ratify a new two-year agreement which will extend through October 31, 2013. At December 31, 2012, 34 EDG employees were members of Local 1464 of the IBEW. In June 2009, Local 1464 of the IBEW ratified a four-year agreement with EDG, which expires on June 1, 2013. Negotiations toward new contracts will occur during 2013 in advance of contract expiration with both Local 1474 and Local 1464.

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ELECTRIC OPERATING STATISTICS(1)

 
  2012   2011   2010   2009   2008  

Electric Operating Revenues (000's):

                               

Residential

  $ 214,526   $ 221,687   $ 204,900   $ 180,404   $ 179,293  

Commercial

    158,837     157,435     146,310     135,800     132,888  

Industrial

    78,786     78,925     69,684     65,983     67,353  

Public authorities(2)

    13,755     13,653     12,099     11,411     10,876  

Wholesale on-system

    18,555     19,140     19,254     18,199     19,229  

Miscellaneous(3)

    8,520     8,194     7,573     6,814     6,976  

Interdepartmental

    197     201     199     178     154  
                       

Total system

    493,176     499,235     460,019     418,789     416,769  

Wholesale off-system

    15,687     23,271     22,891     14,344     29,697  
                       

Total electric operating revenues(4)

    508,863     522,506     482,910     433,133     446,466  
                       

Electricity generated and purchased (000's of kWh):

                               

Steam

    2,865,037     2,805,744     2,650,042     2,259,304     2,228,716  

Hydro

    57,719     48,898     88,104     76,733     32,601  

Combustion turbine

    1,486,643     1,484,472     1,566,074     926,934     1,480,729  
                       

Total generated

    4,409,399     4,339,114     4,304,220     3,262,971     3,742,046  

Purchased

    1,545,327     1,870,901     2,085,550     2,516,702     2,440,246  
                       

Total generated and purchased

    5,954,726     6,210,015     6,389,770     5,779,673     6,182,292  

Interchange (net)

    (87 )   (1,298 )   (1,716 )   (568 )   (436 )
                       

Total system output

    5,954,639     6,208,717     6,388,054     5,779,105     6,181,856  

Transmission by others losses(5)

    (17,300 )   (16,597 )   (5,688 )        
                       

Total system input

    5,937,339     6,192,120     6,382,366     5,779,105     6,181,856  
                       

Maximum hourly system demand (Kw)

    1,142,000     1,198,000     1,199,000     1,085,000     1,152,000  

Owned capacity (end of period) (Kw)

    1,391,000     1,392,000     1,409,000     1,257,000     1,255,000  

Annual load factor (%)

    52.17     51.95     53.17     55.38     54.29  
                       

Electric sales (000's of kWh):

                               

Residential

    1,850,813     1,982,704     2,060,368     1,866,473     1,952,869  

Commercial

    1,558,297     1,576,342     1,644,917     1,579,832     1,622,048  

Industrial

    1,028,416     1,022,765     1,007,033     992,165     1,073,250  

Public authorities(2)

    122,369     126,724     124,554     121,816     122,375  

Wholesale on-system

    353,075     364,866     355,807     332,061     344,525  
                       

Total system

    4,912,970     5,073,401     5,192,679     4,892,347     5,115,067  

Wholesale off-system

    704,028     740,009     798,084     515,899     688,203  
                       

Total Electric Sales

    5,616,998     5,813,410     5,990,763     5,408,246     5,803,270  
                       

Company use (000's of kWh)(6)

    9,066     9,371     9,598     9,088     9,209  

kWh losses (000's of kWh)(7)

    311,275     369,339     382,005     361,771     369,377  
                       

Total System Input

    5,937,339     6,192,120     6,382,366     5,779,105     6,181,856  
                       

Customers (average number):

                               

Residential

    140,602     139,641     141,693     141,206     140,791  

Commercial

    24,036     24,155     24,505     24,412     24,532  

Industrial

    353     357     358     355     361  

Public authorities(2)

    2,124     2,021     2,003     1,995     1,935  

Wholesale on-system

    4     4     4     4     4  
                       

Total System

    167,119     166,178     168,563     167,972     167,623  

Wholesale off-system

    22     25     22     19     22  
                       

Total

    167,141     166,203     168,585     167,991     167,645  
                       

Average annual sales per residential customer (kWh)

    13,163     14,199     14,541     13,218     13,871  

Average annual revenue per residential customer

  $ 1,526   $ 1,588   $ 1,446   $ 1,278   $ 1,273  

Average residential revenue per kWh

    11.59 ¢   11.18 ¢   9.94 ¢   9.67 ¢   9.18 ¢

Average commercial revenue per kWh

    10.19 ¢   9.99 ¢   8.89 ¢   8.60 ¢   8.19 ¢

Average industrial revenue per kWh

    7.66 ¢   7.72 ¢   6.92 ¢   6.65 ¢   6.28 ¢
                       

(1)
See Item 6, "Selected Financial Data" for additional financial information regarding Empire.

(2)
Includes Public Street & Highway Lighting and Public Authorities.

(3)
Includes transmission service revenues, late payment fees, renewable energy credit sales, rent, etc.

(4)
Before intercompany eliminations.

(5)
Energy provided in-kind to third party transmission providers to compensate for transmission losses associated with delivery of capacity and energy under their transmission tariffs.

(6)
Includes kWh used by Company and Interdepartmental.

(7)
Includes the effect of our unbilled revenue adjustment.

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GAS OPERATING STATISTICS(1)

 
  2012   2011   2010   2009   2008  

Gas Operating Revenues (000's):

                               

Residential

  $ 24,744   $ 28,999   $ 32,245   $ 36,176   $ 39,639  

Commercial

    10,797     12,506     13,336     15,552     17,416  

Industrial

    464     682     812     2,066     5,069  

Public authorities

    247     324     342     365     416  
                       

Total retail sales revenues

    36,252     42,511     46,735     54,159     62,540  

Miscellaneous(2)

    400     464     436     221     231  

Transportation revenues

    3,197     3,455     3,714     2,934     2,667  
                       

Total Gas Operating Revenues

    39,849     46,430     50,885     57,314     65,438  
                       

Maximum Daily Flow (mcf)

    58,281     67,789     73,280     70,046     66,005  
                       

Gas delivered to customers (000's of mcf sales)(3)

                               

Residential

    2,012     2,560     2,675     2,687     2,949  

Commercial

    1,050     1,268     1,265     1,278     1,397  

Industrial

    58     102     108     218     553  

Public authorities

    23     33     33     30     35  
                       

Total retail sales

    3,143     3,963     4,081     4,213     4,934  

Transportation sales

    4,249     4,528     4,829     4,330     4,059  
                       

Total gas operating and transportation sales

    7,392     8,491     8,910     8,543     8,993  
                       

Company use(3)

    2     4     4     3     4  

Transportation sales (cash outs)

                     

Mcf losses

    27     (47 )   70     36     140  
                       

Total system sales

    7,421     8,448     8,984     8,582     9,137  
                       

Customers (average number):

                               

Residential

    37,897     38,051     38,277     38,621     39,159  

Commercial

    4,921     4,951     4,968     5,038     5,119  

Industrial

    23     26     26     25     26  

Public authorities

    138     136     137     131     127  
                       

Total retail customers

    42,979     43,164     43,408     43,815     44,431  

Transportation customers

    326     311     313     296     272  
                       

Total gas customers

    43,305     43,475     43,721     44,111     44,703  
                       

(1)
See Item 6, "Selected Financial Data" for additional financial information regarding Empire.

(2)
Primarily includes miscellaneous service revenue and late fees.

(3)
Includes mcf used by Company and Interdepartmental mcf.

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Executive Officers and Other Officers of Empire

        The names of our officers, their ages and years of service with Empire as of December 31, 2012, positions held during the past five years and effective dates of such positions are presented below. All of our officers have been employed by Empire for at least the last five years.

Name
  Age at
12/31/12
  Positions With the Company   With the
Company
Since
  Officer
Since
 

Bradley P. Beecher

    47  

President and Chief Executive Officer (2011). Executive Vice President (2011), Executive Vice President and Chief Operating Officer — Electric (2010), Vice President and Chief Operating Officer — Electric (2006)

    2001     2001  

Laurie A. Delano

    57  

Vice President — Finance and Chief Financial Officer, (2011), Controller, Assistant Secretary and Assistant Treasurer and Principal Accounting Officer (2005)

    2002     2005  

Ronald F. Gatz

    62  

Vice President and Chief Operating Officer — Gas (2006)

    2001     2001  

Blake Mertens

    35  

Vice President — Energy Supply (2011), General Manager — Energy Supply (2010), Director of Strategic Projects, Safety and Environmental Services (2010), Associate Director of Strategic Projects (2009), Manager of Strategic Projects (2006)

    2001     2011  

Michael E. Palmer

    56  

Vice President — Transmission Policy and Corporate Services (2011), Vice President — Commercial Operations (2001)

    1986     2001  

Martin O. Penning

    57  

Vice President — Commercial Operations, (2011), Director of Commercial Operations (2006)

    1980     2011  

Kelly S. Walters

    47  

Vice President and Chief Operating Officer — Electric (2011), Vice President — Regulatory and Services (2006)

    2001     2006  

Janet S. Watson

    60  

Secretary — Treasurer (1995)

    1994     1995  

Robert W. Sager

    38  

Controller, Assistant Secretary and Assistant Treasurer and Principal Accounting Officer (2011), Director of Financial Services (2006)

    2006     2011  


Regulation

Electric Segment

        General.    As a public utility, our electric segment operations are subject to the jurisdiction of the MPSC, the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC) and the Arkansas Public Service Commission (APSC) with respect to services and facilities, rates and charges, regulatory accounting, valuation of property, depreciation and various other matters. Each such Commission has jurisdiction over the creation of liens on property located in its state to secure bonds or other securities. The KCC also has jurisdiction over the issuance of all securities because we are a regulated utility incorporated in Kansas. Our transmission and sale at wholesale of electric energy in interstate commerce and our facilities are also subject to the jurisdiction of the FERC, under the Federal Power Act. FERC jurisdiction extends to, among other things, rates and charges in connection with such transmission and sale; the sale, lease or other disposition of such facilities and accounting matters. See discussion in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Competition."

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        During 2012, approximately 91.6% of our electric operating revenues was received from retail customers. Sales subject to FERC jurisdiction represented approximately 7.6% of our electric operating revenues during 2012 with the remaining 0.8% being from miscellaneous sources. The percentage of retail regulated revenues derived from each state follows:

Missouri

    89.3 %

Kansas

    5.1  

Oklahoma

    2.9  

Arkansas

    2.7  

        Rates.    See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Rate Matters" for information concerning recent electric rate proceedings.

        Fuel Adjustment Clauses.    Typical fuel adjustment clauses permit the distribution to customers of changes in fuel costs, subject to routine regulatory review, without the need for a general rate proceeding. Fuel adjustment clauses are presently applicable to our retail electric sales in Missouri, Oklahoma and Kansas and system wholesale kilowatt-hour sales under FERC jurisdiction. We have an Energy Cost Recovery Rider in Arkansas that adjusts for changing fuel and purchased power costs on an annual basis.

Gas Segment

        General.    As a public utility, our gas segment operations are subject to the jurisdiction of the MPSC with respect to services and facilities, rates and charges, regulatory accounting, valuation of property, depreciation and various other matters. The MPSC also has jurisdiction over the creation of liens on property to secure bonds or other securities.

        Purchased Gas Adjustment (PGA).    The PGA clause allows EDG to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage costs, including costs associated with our use of natural gas financial instruments to hedge the purchase price of natural gas and related carrying costs. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.


Environmental Matters

        See Note 11 of "Notes to Consolidated Financial Statements" under Item 8 for information regarding environmental matters.


Conditions Respecting Financing

        Our EDE Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the EDE Mortgage), and our Restated Articles of Incorporation (Restated Articles), specify earnings coverage and other conditions which must be complied with in connection with the issuance of additional first mortgage bonds or cumulative preferred stock, or the incurrence of unsecured indebtedness. The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1.0 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the year ended December 31, 2012, would permit us to issue approximately $609.2 million of

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new first mortgage bonds based on this test at an assumed interest rate of 5.5%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2012, we had retired bonds and net property additions which would enable the issuance of at least $776.7 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2012, we are in compliance with all restrictive covenants of the EDE Mortgage.

        Under our Restated Articles, (a) cumulative preferred stock may be issued only if our net income available for interest and dividends (as defined in our Restated Articles) for a specified twelve-month period is at least 11/2 times the sum of the annual interest requirements on all indebtedness and the annual dividend requirements on all cumulative preferred stock to be outstanding immediately after the issuance of such additional shares of cumulative preferred stock, and (b) so long as any preferred stock is outstanding, the amount of unsecured indebtedness outstanding may not exceed 20% of the sum of the outstanding secured indebtedness plus our capital and surplus. We have no outstanding preferred stock. Accordingly, the restriction in our Restated Articles does not currently restrict the amount of unsecured indebtedness that we may have outstanding.

        The EDG Indenture of Mortgage and Deed of Trust, dated as of June 1, 2006, as amended and supplemented (the EDG Mortgage) contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of December 31, 2012, this test would allow us to issue approximately $12.8 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.

        See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources."


Our Web Site

        We maintain a web site at www.empiredistrict.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on form 8-K and related amendments are available free of charge through our web site as soon as reasonably practicable after such reports are filed with or furnished to the SEC electronically. Our Corporate Governance Guidelines, our Code of Business Conduct and Ethics, our Code of Ethics for the Chief Executive Officer and Senior Financial Officers, the charters for our Audit Committee, Compensation Committee and Nominating/Corporate Governance Committee, our Procedures for Reporting Complaints on Accounting, Internal Accounting Controls and Auditing Matters, our Procedures for Communicating with Non-Management Directors and our Policy and Procedures with Respect to Related Person Transactions can also be found on our web site. All of these documents are available in print to any interested party who requests them. Our web site and the information contained in it and connected to it shall not be deemed incorporated by reference into this Form 10-K.

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ITEM 1A.    RISK FACTORS

        Investors should review carefully the following risk factors and the other information contained in this Form 10-K. The risks we face are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect our financial position, results of operations and liquidity.

        Readers are cautioned that the risks and uncertainties described in this Form 10-K are not the only ones facing Empire. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations (including our ability to pay dividends on our common stock) could suffer if the concerns set forth below are realized.


We are exposed to increases in costs and reductions in revenue which we cannot control and which may adversely affect our business, financial condition and results of operations.

        The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and usage and (4) general economic conditions. Of the factors driving revenues, weather has the greatest short-term effect on the demand for electricity for our regulated business. Mild weather reduces demand and, as a result, our electric operating revenues. In addition, changes in customer demand due to downturns in the economy or energy efficiency could reduce our revenues.

        The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expenses, (2) maintenance and repairs expense, including repairs following severe weather and plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. Although we generally recover these expenses through our rates, there can be no assurance that we will recover all, or any part of, such increased costs in future rate cases.

        The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth, (4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our natural gas service territory and a significant amount of our natural gas revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our natural gas operations have historically generated less revenues and income when weather conditions are warmer in the winter.

        The primary driver of our gas operating expense in any period is the price of natural gas.

        Significant increases in electric and gas operating expenses or reductions in electric and gas operating revenues may occur and result in a material adverse effect on our business, financial condition and results of operations.


We are exposed to factors that can increase our fuel and purchased power expenditures, including disruption in deliveries of coal or natural gas, decreased output from our power plants, failure of performance by purchased power counterparties and market risk in our fuel procurement strategy.

        Fuel and purchased power costs are our largest expenditures. Increases in the price of coal, natural gas or the cost of purchased power will result in increased electric operating expenditures. Given we have a fuel cost recovery mechanism in all of our jurisdictions, our net income exposure to the impact of the risks discussed above is significantly reduced. However, cash flow could still be impacted by these increased expenditures. We are also subject to prudency reviews which could negatively impact our net income if a regulatory commission would conclude our costs were incurred imprudently.

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        We depend upon regular deliveries of coal as fuel for our Asbury, Iatan and Plum Point plants. Substantially all of this coal comes from mines in the Powder River Basin of Wyoming and is delivered to the plants by train. Production problems in these mines, railroad transportation or congestion problems, or unavailability of trains could affect delivery cycle times required to maintain plant inventory levels, causing us to implement coal conservation and supply replacement measures to retain adequate reserve inventories at our facilities. These measures could include some or all of the following: reducing the output of our coal plants, increasing the utilization of our gas-fired generation facilities, purchasing power from other suppliers, adding additional leased trains to our supply system and purchasing locally mined coal which can be delivered without using the railroads. Such measures could result in increased fuel and purchased power expenditures.

        We have also established a risk management practice of purchasing contracts for future fuel needs to meet underlying customer needs and manage cost and pricing uncertainty. Within this activity, we may incur losses from these contracts. By using physical and financial instruments, we are exposed to credit risk and market risk. Market risk is the exposure to a change in the value of commodities caused by fluctuations in market variables, such as price. The fair value of derivative financial instruments we hold is adjusted cumulatively on a monthly basis until prescribed determination periods. At the end of each determination period, which is the last day of each calendar month in the period, any realized gain or loss for that period related to the contract will be reclassified to fuel expense and recovered or refunded to the customer through our fuel adjustment mechanisms. Credit risk is the risk that the counterparty might fail to fulfill its obligations under contractual terms.


We are subject to regulation in the jurisdictions in which we operate.

        We are subject to comprehensive regulation by federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility commissions in the states where we operate regulate many aspects of our utility operations, including the rates that we can charge customers, siting and construction of facilities, pipeline safety and compliance, customer service and our ability to recover costs we incur, including capital expenditures and fuel and purchased power costs.

        The FERC has jurisdiction over wholesale rates for electric transmission service and electric energy sold in interstate commerce. Federal, state and local agencies also have jurisdiction over many of our other activities.

        Information concerning recent filings requesting increases in rates and related matters is set forth under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Rate Matters."

        We are also subject to prudency and similar reviews by regulators of costs we incur, including capital expenditures, fuel and purchased power costs and other operating costs;

        We are unable to predict the impact on our operating results from the regulatory activities of any of these agencies, including any regulatory disallowances that could result from prudency reviews. Despite our requests, these regulatory commissions have sole discretion to leave rates unchanged, grant increases or order decreases in the base rates we charge our utility customers. They have similar authority with respect to our recovery of increases in our fuel and purchased power costs. If our costs increase and we are unable to recover increased costs through base rates or fuel adjustment clauses, or if we are unable to fully recover our investments in new facilities, our results of operations could be materially adversely affected. Changes in regulations or the imposition of additional regulations could also have a material adverse effect on our results of operations.

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Operations risks may adversely affect our business and financial results.

        The operation of our electric generation, and electric and gas transmission and distribution systems involves many risks, including breakdown or failure of expensive and sophisticated equipment, processes and personnel performance; workplace and public safety; operating limitations that may be imposed by workforce issues, equipment conditions, environmental or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; transmission scheduling constraints; unauthorized physical access to our facilities; and catastrophic events such as fires, explosions, severe weather, acts of terrorism or other similar occurrences. In addition, our power generation and delivery systems, information technology systems and network infrastructure may be vulnerable to internal or external cyber attack, unauthorized physical or virtual access, computer viruses or other attempts to harm our systems or misuse our confidential information.

        We have implemented training and preventive maintenance programs and have security systems and related protective infrastructure in place, but there is no assurance that these programs will prevent or minimize future breakdowns, outages or failures of our generation facilities or related business processes. In those cases, we would need to either produce replacement power from our other facilities or purchase power from other suppliers at potentially volatile and higher cost in order to meet our sales obligations, or implement emergency back-up business system processing procedures.

        The SPP RTO is mandated by the FERC to ensure a reliable power supply, an adequate transmission infrastructure and competitive wholesale electricity prices. The SPP RTO functions as reliability coordination, tariff administration and regional scheduler for its member utilities, including us. Essentially, the SPP RTO independently operates our transmission system as it interfaces and coordinates with the regional power grid. SPP RTO activities directly impact our control of owned generating assets and the development and cost of transmission infrastructure projects within the SPP RTO region. Information concerning recent and pending SPP RTO and other FERC activities can be found under Note 3 of "Notes to Consolidated Financial Statements" under Item 8.

        These and other operating events and conditions may reduce our revenues, increase costs, or both, and may materially affect our results of operations, financial position and cash flows.


We may be unable to recover increases in the cost of natural gas from our natural gas utility customers, or may lose customers as a result of any price increases.

        In our natural gas utility business, we are permitted to recover the cost of gas directly from our customers through the use of a purchased gas adjustment provision. Our purchased gas adjustment provision is regularly reviewed by the MPSC. In addition to reviewing our adjustments to customer rates, the MPSC reviews our costs for prudency as well. To the extent the MPSC may determine certain costs were not incurred prudently, it could adversely affect our gas segment earnings and cash flows. In addition, increases in natural gas costs affect total prices to our customers and, therefore, the competitive position of gas relative to electricity and other forms of energy. Increases in natural gas costs may also result in lower usage by customers unable to switch to alternate fuels. Such disallowed costs or customer losses could have a material adverse effect on our business, financial condition and results of operations.


Any reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.

        Currently, our corporate credit ratings and the ratings for our securities are as follows:

 
  Fitch   Moody's   Standard & Poor's

Corporate Credit Rating

  n/r*   Baa2   BBB-

EDE First Mortgage Bonds

  BBB+   A3   BBB+

Senior Notes

  BBB   Baa2   BBB-

Commercial Paper

  F3   P-2   A-3

Outlook

  Stable   Stable   Stable

*
Not rated.

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        The ratings indicate the agencies' assessment of our ability to pay the interest and principal of these securities. A rating is not a recommendation to purchase, sell or hold securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost of the securities when they are sold. In addition, a downgrade in our senior unsecured long-term debt rating would result in an increase in our borrowing costs under our bank credit facility. If any of our ratings fall below investment grade (investment grade is defined as Baa3 or above for Moody's and BBB- or above for Standard & Poor's and Fitch), our ability to issue short-term debt, commercial paper or other securities or to market those securities would be impaired or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on our business, financial condition and results of operations. In addition, any actual downgrade of our commercial paper rating from Moody's or Fitch, may make it difficult for us to issue commercial paper. To the extent we are unable to issue commercial paper, we will need to meet our short-term debt needs through borrowings under our revolving credit facilities, which may result in higher costs.

        We cannot assure you that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.


We are subject to environmental laws and the incurrence of environmental liabilities which may adversely affect our business, financial condition and results of operations.

        We are subject to extensive federal, state and local regulation with regard to air and other environmental matters. Failure to comply with these laws and regulations could have a material adverse effect on our results of operations and financial position. In addition, new environmental laws and regulations, and new interpretations of existing environmental laws and regulations, have been adopted and may in the future be adopted which may substantially increase our future environmental expenditures for both new facilities and our existing facilities. Compliance with current and potential future air emission standards (such as those limiting emission levels of sulfur dioxide (SO2), emissions of mercury, other hazardous pollutants (HAPS), nitrogen oxide (NOx), and carbon dioxide (CO2)) has required, and may in the future require, significant environmental expenditures. Although we have historically recovered such costs through our rates, there can be no assurance that we will recover all, or any part of, such increased costs in future rate cases. The incurrence of additional material environmental costs which are not recovered in our rates may result in a material adverse effect on our business, financial condition and results of operations.


The cost and schedule of construction projects may materially change.

        Our capital expenditure budget for the next three years is estimated to be $507.0 million. This includes expenditures for environmental upgrades to our existing facilities and additions to our transmission and distribution systems. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than planned, the scope and timing of projects may change, and other events beyond our control may occur that may materially affect the schedule, budget, cost and performance of projects. To the extent the completion of projects is delayed, we expect that the timing of receipt of increases in base rates reflecting our investment in such projects will be correspondingly delayed. Costs associated with these projects will also be subject to prudency review by regulators as part of future rate case filings and all costs may not be allowed recovery.

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Financial market disruptions may increase financing costs, limit access to the credit markets or cause reductions in investment values in our pension plan assets.

        We estimate our capital expenditures to be $163.4 million in 2013. Although we believe it is unlikely we will have difficulty accessing the markets for the capital needed to complete these projects (if such a need arises), financing costs could fluctuate. Our pension plan and Other Postretirement Benefits (OPEB) costs increased, resulting in an $8.2 million increase in our 2011 net pension and OPEB liability. During 2012, our net pension and OPEB liability increased $15.9 million. We expect to fund approximately $20.1 million in 2013 for pension and OPEB liabilities. Future market changes could result in increased pension and OPEB liabilities and funding obligations.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

ITEM 2.    PROPERTIES

Electric Segment Facilities

        At December 31, 2012, we owned generating facilities with an aggregate generating capacity of 1,391 megawatts.

        Our principal electric baseload generating plant is the Asbury Plant with 203 megawatts of generating capacity. The plant, located near Asbury, Missouri, is a coal-fired generating station with two steam turbine generating units. The plant presently accounts for approximately 14% of our owned generating capacity and in 2012 accounted for approximately 26.5% of the energy generated by us. Routine plant maintenance, during which the entire plant is taken out of service, is scheduled annually, normally for approximately three to four weeks in the spring. Approximately every fifth year, the maintenance outage is scheduled to be extended to approximately six weeks to permit inspection of the Unit No. 1 turbine. The next such outage is scheduled to take place in the fall of 2014. When the Asbury Plant is out of service, we typically experience increased purchased power and fuel expenditures associated with replacement energy, which is now likely to be recovered through our fuel adjustment clauses. The Unit No. 2 turbine is inspected approximately every 35,000 hours of operations and was last inspected in 2001. As of December 31, 2012, Unit No. 2 has operated approximately 3,393 hours since its last turbine inspection in 2001. As part of our environmental Compliance Plan, discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8, we have begun the installation of a scrubber, fabric filter and powder activated carbon injection system at our Asbury plant. The addition of this air quality control equipment is expected to be completed by early 2015 and will require the retirement of Asbury Unit 2.

        Our generating plant located at Riverton, Kansas, has four gas-fired combustion turbine units (Units 9, 10, 11 and 12) and two gas-fired steam generating units (Units 7 and 8) with an aggregate generating capacity of 279 megawatts. In September 2012, Units 7 and 8 were transitioned from operation on coal to full operation on natural gas. Unit 12 began commercial operation on April 10, 2007 and is scheduled to be converted from a simple cycle combustion turbine to a combined cycle unit, with scheduled completion in 2016.

        We own a 12% undivided interest in the coal-fired Unit No. 1 and Unit No. 2 at the Iatan Generating Station located near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. Unit No. 2 entered commercial operation on December 31, 2010. We are entitled to 12% of the units' available capacity, currently 85 megawatts for Unit No. 1 and 105 megawatts for Unit No. 2, and are obligated to pay for that percentage of the operating costs of the units. KCP&L operates the units for the joint owners.

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        We own a 7.52% undivided interest in the coal-fired Plum Point Energy Station located near Osceola, Arkansas. We are entitled to 50 megawatts, or 7.52% of the unit's available capacity. The Plum Point Energy Station entered commercial operation on September 1, 2010.

        Our State Line Power Plant, which is located west of Joplin, Missouri, consists of Unit No. 1, a combustion turbine unit with generating capacity of 94 megawatts and a Combined Cycle Unit with generating capacity of 495 megawatts of which we are entitled to 60%, or 297 megawatts. The Combined Cycle Unit consists of the combination of two combustion turbines, two heat recovery steam generators, a steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with Westar Generating Inc., a subsidiary of Westar Energy, Inc., which owns the remaining 40% of the unit. Westar reimburses us for a percentage of the operating costs per our joint ownership agreement. We are the operator of the Combined Cycle Unit. All units at our State Line Power Plant burn natural gas as a primary fuel with Unit No. 1 having the additional capability of burning oil.

        We have four combustion turbine peaking units at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 262 megawatts. These peaking units operate on natural gas, as well as oil.

        Our hydroelectric generating plant (FERC Project No. 2221), located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in southwestern Missouri. As part of the Energy and Water Development Appropriations Act of 2006 (the Appropriations Act), a new minimum flow pattern was established with the intent of increasing minimum flows on recreational streams in Arkansas. To accomplish this, the level of Bull Shoals Lake will be increased an average of 5 feet. The increase at Bull Shoals will decrease the net head waters available for generation at Ozark Beach by 5 feet and, thus, reduce our electrical output. We estimate the lost production to be up to 16% of our average annual energy production for this unit. The loss in this facility would require us to replace it with additional generation from our gas-fired and coal-fired units or with purchased power. The Appropriations Act required the Southwest Power Administration (SWPA), in coordination with us and our relevant public service commissions, to determine our economic detriment assuming a January 1, 2011 implementation date. On June 17, 2010, the SWPA posted a revised Final Determination that our customers' damages were $26.6 million. On September 16, 2010, we received a $26.6 million payment from the SWPA, which was deferred and recorded as a noncurrent liability. We originally increased our current tax liability by approximately $10.0 million recognizing that the $26.6 million payment might have been considered taxable income in 2010. During the first quarter of 2011, we submitted a pre-filing agreement with the Internal Revenue Service (IRS) requesting that a determination be made regarding whether or not the payment could be deferred under certain sections of the Internal Revenue code. The IRS accepted our position that the payment be deferred for tax purposes and recognized over the next twenty years. As such, we reduced the current tax liability in accordance with this deferral. The SWPA payment, net of taxes, is being used to reduce fuel expense for our customers in all our jurisdictions. In addition, it is our current understanding that the SWPA has delayed the implementation of the new minimum flows until 2016.

        At December 31, 2012, our transmission system consisted of approximately 22 miles of 345 kV lines, 441 miles of 161 kV lines, 745 miles of 69 kV lines and 81 miles of 34.5 kV lines. Our distribution system consisted of approximately 6,862 miles of line at December 31, 2012 as compared to 6,842 miles of line at December 31, 2011.

        Our electric generation stations, other than Plum Point Energy Station, are located on land owned in fee. We own a 3% undivided interest as tenant in common in the land for the Iatan Generating Station. We own a similar interest in 60% of the land used for the State Line Combined Cycle Unit. Substantially all of our electric transmission and distribution facilities are located either (1) on property leased or owned in fee; (2) over streets, alleys, highways and other public places, under franchises or other rights; or (3) over private property by virtue of easements obtained from the record holders of title. Substantially all of our electric segment property, plant and equipment are subject to the EDE Mortgage.

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        We also own and operate water pumping facilities and distribution systems consisting of a total of approximately 89 miles of water mains in three communities in Missouri.


Gas Segment Facilities

        At December 31, 2012, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,148 miles of distribution mains.

        Substantially all of our gas transmission and distribution facilities are located either (1) on property leased or owned in fee; (2) under streets, alleys, highways and other public places, under franchises or other rights; or (3) under private property by virtue of easements obtained from the record holders of title. Substantially all of our gas segment property, plant and equipment are subject to the EDG Mortgage.


Other Segment

        Our other segment consists of our leasing of fiber optics cable and equipment (which we also use in our own utility operations).

ITEM 3.    LEGAL PROCEEDINGS

        See Note 11 of "Notes to Consolidated Financial Statements" under Item 8, which description is incorporated herein by reference.

ITEM 4.    MINE SAFETY DISCLOSURES

        Not applicable.

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PART II

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

        Our common stock is listed on the New York Stock Exchange (ticker symbol: EDE). On February 1, 2013, there were 4,548 record holders and 29,051 individual participants in security position listings. The following table presents the high and low sales prices (and quarter end closing sales prices) for our common stock as reported by the New York Stock Exchange for composite transactions, and the amount per share of quarterly dividends declared and paid on the common stock for each quarter during 2012 and 2011.

 
  High   Low   Close   Dividends Paid
Per Share
 

2012 Quarter Ended:

                         

March 31

  $ 21.34   $ 19.55   $ 20.35   $ 0.25  

June 30

    21.24     19.51     21.10     0.25  

September 30

    21.94     21.02     21.55     0.25  

December 31

    22.04     19.59     20.38     0.25  

2011 Quarter Ended:

                         

March 31

  $ 22.40   $ 20.70   $ 21.79   $ 0.32  

June 30

    23.26     18.01     19.26     0.32  

September 30

    21.12     18.10     19.38     0.00  

December 31

    21.40     18.41     21.09     0.00  

        Holders of our common stock are entitled to dividends, if, as, and when declared by the Board of Directors, out of funds legally available therefore subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings, which is essentially our accumulated net income less dividend payouts. In response to the expected loss of revenues resulting from the May 22, 2011 tornado, our level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. On February 2, 2012, the Board of Directors re-established the dividend and declared a quarterly dividend of $0.25 per share on common stock payable on March 15, 2012 to holders of record as of March 1, 2012. As of December 31, 2012, our retained earnings balance was $47.1 million, compared to $33.7 million at December 31, 2011. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.

        See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation — Dividends" for information on limitations on our ability to pay dividends on our common stock.

        During 2012, no purchases of our common stock were made by or on behalf of us.

        Participants in our Dividend Reinvestment and Stock Purchase Plan may acquire, at a 3% discount, newly issued common shares with reinvested dividends. Participants may also purchase, at an averaged market price, newly issued common shares with optional cash payments on a weekly basis, subject to certain restrictions. We also offer participants the option of safekeeping for their stock certificates.

        Our shareholders rights plan, dated July 26, 2000, expired July 25, 2010, pursuant to its terms. See Note 5 of "Notes to Consolidated Financial Statements" under Item 8 for additional information. In addition, we have stock based compensation programs which are described in Note 4 of "Notes to Consolidated Financial Statements" under Item 8.

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        Our By-laws provide that K.S.A. Sections 17-1286 through 17-1298, the Kansas Control Share Acquisitions Act, will not apply to control share acquisitions of our capital stock.

        See Note 4 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding our common stock and equity compensation plans.

        The following graph and table indicates the value at the end of the specified years of a $100 investment made on December 31, 2007, in our common stock and similar investments made in the securities of the companies in the Standard & Poor's 500 Composite Index (S&P 500 Index) and the Standard & Poor's Electric Utilities Index (S&P Electric Utility). The graph and table assume that dividends were reinvested when received.


Total Return Performance

GRAPHIC

Total Return Analysis
  12/31/2007   12/31/2008   12/31/2009   12/31/2010   12/31/2011   12/31/2012  

The Empire District Electric Company

  $ 100.00   $ 82.37   $ 94.70   $ 119.87   $ 117.55   $ 119.27  

S&P Electric Utilities Index

  $ 100.00   $ 74.16   $ 76.66   $ 79.30   $ 95.92   $ 95.39  

S&P 500 Index

  $ 100.00   $ 63.00   $ 79.68   $ 91.68   $ 93.61   $ 108.59  

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ITEM 6.    SELECTED FINANCIAL DATA
(in thousands, except per share amounts)

 
  2012   2011   2010   2009   2008  

Operating revenues

  $ 557,097   $ 576,870   $ 541,276   $ 497,168   $ 518,163  

Operating income

  $ 96,221   $ 96,934   $ 80,495   $ 74,495   $ 71,012  

Total allowance for funds used during construction

  $ 1,928   $ 512   $ 10,174   $ 14,133   $ 12,518  

Income from continuing operations

  $ 55,681   $ 54,971   $ 47,396   $ 41,296   $ 39,722  

Net income

  $ 55,681   $ 54,971   $ 47,396   $ 41,296   $ 39,722  
                       

Weighted average number of common shares outstanding — basic

    42,257     41,852     40,545     34,924     33,821  

Weighted average number of common shares outstanding — diluted

    42,284     41,887     40,580     34,956     33,860  

Earnings from continuing operations per weighted average share of common stock — basic and diluted

  $ 1.32   $ 1.31   $ 1.17   $ 1.18   $ 1.17  

Total earnings per weighted average share of common stock — basic and diluted

  $ 1.32   $ 1.31   $ 1.17   $ 1.18   $ 1.17  

Cash dividends per share

  $ 1.00   $ 0.64   $ 1.28   $ 1.28   $ 1.28  
                       

Common dividends paid as a percentage of net income

    75.9 %   48.6 %   109.7 %   108.5 %   109.0 %

Allowance for funds used during construction as a percentage of net income

    3.5 %   0.9 %   21.5 %   34.2 %   31.5 %
                       

Book value per common share (actual) outstanding at end of year

  $ 16.90   $ 16.53   $ 15.82   $ 15.75   $ 15.56  
                       

Capitalization:

                               

Common equity

  $ 717,798   $ 693,989   $ 657,624   $ 600,150   $ 528,872  

Long-term debt

  $ 691,626   $ 692,259   $ 693,072   $ 640,156   $ 611,567  

Ratio of earnings to fixed charges

    2.89X     2.87X     2.63X     2.15X     2.19x  

Total assets

  $ 2,126,369   $ 2,021,835   $ 1,921,311   $ 1,839,846   $ 1,713,846  

Plant in service at original cost

  $ 2,284,022   $ 2,176,650   $ 2,108,115   $ 1,718,584   $ 1,586,152  

Capital expenditures (including AFUDC)

  $ 146,287   $ 101,177   $ 108,157   $ 148,804   $ 206,405  
                       

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

EXECUTIVE SUMMARY

Electric Segment

        As a traditional, vertically integrated regulated utility, the primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and usage and (4) general economic conditions. The utility commissions in the states in which we operate, as well as the Federal Energy Regulatory Commission (FERC), set the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily fuel and purchased power) and/or rate relief. We assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. The effects of timing of rate relief are discussed in detail in Note 3 of "Notes to the Consolidated Financial Statements" under Item 8. Of the

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factors driving revenues, weather has the greatest short-term effect on the demand for electricity for our regulated business. Very hot summers and very cold winters increase electric demand, while mild weather reduces demand. Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and by general economic conditions.

        Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. Our annual customer growth is calculated by comparing the number of customers at the end of a year to the number of customers at the end of the prior year. Due to the devastating EF-5 tornado that hit the Joplin, Missouri area on May 22, 2011, damaging or destroying thousands of homes and businesses (discussed below), our system-wide customer count was down by approximately 400 customers as of December 31, 2012 as compared to the customer count levels prior to the May 2011 tornado. We expect an average annual customer growth range of approximately 0.7% to 1.2% over the next several years. We expect the corresponding weather normalized sales growth to be approximately 1.5% in the near term as the Joplin area rebuilding activity continues. We then expect sales growth to flatten to a range of 0.4% to 0.9% over the next several years. We define electric sales growth to be growth in kWh sales period over period excluding the impact of weather. The primary drivers of electric sales growth are customer growth, customer usage and general economic conditions.

        The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) operating maintenance and repairs expense, including repairs following severe weather and plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. We have a fuel cost recovery mechanism in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel and purchased power costs on our net income.

Gas Segment

        The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and usage, (4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. The MPSC sets the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily commodity natural gas) and/or rate relief. We assess the need for rate relief and file for such relief when necessary. A Purchased Gas Adjustment (PGA) clause is included in our gas rates, which allows us to recover our actual cost of natural gas from customers through rate changes, which are made periodically (up to four times) throughout the year in response to weather conditions, natural gas costs and supply demands. Weather affects the demand for natural gas. Very cold winters increase demand for gas, while mild weather reduces demand. Due to the seasonal nature of the gas business, revenues and earnings are typically concentrated in the November through March period, which generally corresponds with the heating season. Customer growth, which is the growth in the number of customers, contributes to the demand for gas. Our annual customer growth is calculated by comparing the number of customers at the end of a year to the number of customers at the end of the prior year. Our gas segment customer contraction for the year ended December 31, 2012 was 0.2%, which we believe was due to depressed economic conditions. We expect gas customer growth to be flat during the next several years. We define gas sales growth to be growth in mcf sales excluding the impact of weather. The primary drivers of gas sales growth are customer growth and general economic conditions.

        The primary driver of our gas operating expense in any period is the price of natural gas. However, because gas purchase costs for our gas utility operations are normally recovered from our customers, any change in gas prices does not have a corresponding impact on income unless such costs are deemed imprudent or cause customers to reduce usage.

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Earnings

        For the year ended December 31, 2012, basic and diluted earnings per weighted average share of common stock were $1.32 on $55.7 million of net income compared to $1.31 on $54.9 million of net income for the year ended December 31, 2011. Increased electric gross margins (defined as electric revenues less fuel and purchased power costs) positively impacted net income for the twelve months ended December 31, 2012 as compared to the same period in 2011, reflecting a decrease in revenues of approximately $13.6 million and a decrease in electric fuel and purchased power expenses of approximately $21.4 million compared to 2011. Decreased depreciation, reflecting a decrease in regulatory amortization expense due to the termination of construction accounting as of June 15, 2011 also positively impacted net income for the twelve months ended December 31, 2012. Other operating and maintenance expenses increased during 2012, negatively impacting net income.

        The table below sets forth a reconciliation of basic and diluted earnings per share between 2011 and 2012, which is a non-GAAP presentation. The economic substance behind our non-GAAP earnings per share (EPS) measure is to present the after tax impact of significant items and components of the statement of income on a per share basis before the impact of additional stock issuances.

        We believe this presentation is useful to investors because the statement of income does not readily show the EPS impact of the various components, including the effect of new stock issuances. This could limit the readers' understanding of the reasons for the EPS change from previous years. This information is useful to management, and we believe this information is useful to investors, to better understand the reasons for the fluctuation in EPS between the prior and current years on a per share basis.

        This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of income. We also note that this presentation does not purport to be an alternative to earnings per share determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone. The dilutive effect of additional shares issued included in the table reflects the estimated impact of all shares issued during the period.

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Earnings Per Share — 2011

  $ 1.31  

Revenues

       

Electric segment

  $ (0.20 )

Gas segment

    (0.10 )

Other segment

    0.01  
       

Total Revenue

    (0.29 )

Electric fuel and purchased power

    0.31  

Cost of natural gas sold and transported

    0.06  
       

Margin

    0.08  

Operating — electric segment

    (0.13 )

Operating — gas segment

    0.00  

Operating — other segment

    (0.01 )

Maintenance and repairs

    0.01  

Depreciation and amortization

    0.05  

Other taxes

    (0.01 )

Interest charges

    0.00  

AFUDC

    0.02  

Change in effective income tax rates

    0.01  

Dilutive effect of additional shares issued

    (0.01 )

Other income and deductions

    0.00  
       

Earnings Per Share — 2012

  $ 1.32  
       

Fourth Quarter Results

        Earnings for the fourth quarter of 2012 were $9.6 million, or $0.23 per share, as compared to $8.7 million, or $0.21 per share, in the fourth quarter of 2011. Electric segment gross margins grew slightly during the quarter ending December 31, 2012 compared to the 2011 quarter, reflecting decreased revenues of approximately $3.9 million and a decrease in fuel and purchased power costs of approximately $4.4 million. The impact of milder weather experienced during the fourth quarter of 2012 was offset by improving electric customer counts. Depreciation and amortization expense increased approximately $0.8 million and other regulated operating expenses increased $0.8 million in the fourth quarter of 2012, primarily related to increased employee health care expense. These increases were offset by a $1.8 million decrease in maintenance and repairs expense.


2012 Activities

Financings

        During the year we took advantage of lower interest rates.

        On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due 2033 and $120.0 million of 4.32% First Mortgage Bonds due 2043. The delayed settlement is anticipated to occur on or about May 30, 2013, subject to customary closing conditions. We expect to use the proceeds from the sale of the bonds to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013 with the remaining proceeds to be used for general corporate purposes. The bonds will be issued under the EDE Mortgage.

        On April 1, 2012, we redeemed all $74.8 million aggregate principal amount of our First Mortgage Bonds, 7.00% Series due 2024. All $5.2 million of our First Mortgage Bonds, 5.20% Pollution Control Series due 2013 and all $8.0 million of our First Mortgage Bonds, 5.30% Pollution Control Series due 2013 were also redeemed with payment made to the trustee prior to March 31, 2012. To replace this financing, on April 2, 2012, we entered into a Bond Purchase Agreement for a private placement of $88.0 million

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aggregate principal amount of 3.58% First Mortgage Bonds due April 2, 2027. The first settlement of $38.0 million occurred on April 2, 2012 and the second settlement of $50.0 million occurred on June 1, 2012. All bonds of this new series will mature on April 2, 2027.

        For additional information, see Note 7 of "Notes to Consolidated Financial Statements" under Item 8.

Compliance Plan

        Our environmental Compliance Plan, discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8, continues on schedule. Construction is proceeding on the installation of a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant. Initial construction costs through December 31, 2012 were $29.0 million for 2012 and $30.3 million for the project to date, excluding AFUDC. This project is expected to be completed in early 2015 at a cost ranging from $112.0 million to $130.0 million, excluding AFUDC. The addition of this air quality control equipment will require the retirement of Asbury Unit 2, an 18 megawatt steam turbine that is currently used for peaking purposes.

        In September 2012, as part of the Compliance Plan, we completed the transition of our Riverton Units 7 and 8 from operation on coal to full operation on natural gas. These units, along with Riverton Unit 9, will be retired upon conversion of Riverton Unit 12, a simple cycle combustion turbine, to a combined cycle unit, with scheduled completion in 2016.

Regulatory Matters

        On July 6, 2012, we filed a rate increase with the Missouri Public Service Commission (MPSC) for changes in rates for our Missouri electric customers. We are seeking an annual increase in base rate revenues of approximately $30.7 million, or 7.56%. On February 15, 2013, the MPSC issued an order to delay the procedural schedule, indicating we reached an agreement in principle with the parties to our case. The order also indicated a joint stipulation is anticipated to be filed with the MPSC as early as February 22, 2013, and is still subject to final approval by the MPSC. Details of the stipulation are confidential until it is filed with the MPSC. We do not anticipate the outcome to have a materially negative impact on our financial statements.

        On May 21, 2012, we filed a rate increase request with the MPSC for an annual increase in revenues for our Missouri water customers in the amount of approximately $516,400, or 29.6%. On October 18, 2012, we, the MPSC staff and the Office of the Public Counsel filed a unanimous agreement with the MPSC for an increase of $450,000. The MPSC issued an order approving the agreement on October 31, 2012, with rates effective November 23, 2012.

        On May 18, 2012, we filed with the Federal Energy Regulatory Commission (FERC) proposed revisions to our Open Access Transmission Tariff to implement a cost-based transmission formula rate to be effective August 1, 2012. On July 31, 2012, the FERC suspended the rate for five months and set the filing for hearing and settlement procedures.

        For additional information on all these cases, see Note 3 of "Notes to Consolidated Financial Statements" under Item 8 for information regarding regulatory matters.

Tornado Recovery and Activity

        As of December 31, 2012, our system-wide customer count was down by approximately 400 as compared to the customer count levels prior to the May 2011 tornado. Joplin, Missouri continues to recover from the May 2011 tornado. During 2012, the city of Joplin approved an $800 million Master Development Plan, which includes several municipal and commercial projects, as well as 1,400 new homes in and around the area impacted by the May 2011 EF-5 tornado. These projects are expected to be funded

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through grants, tax credits, tax revenue (including such revenues from a city-approved Tax Increment Financing district encompassing over 3,000 acres within the city), and other private lending. Projects are expected to be completed by 2019. All our transmission lines and structures damaged in the storm have been repaired and the distribution system has been rebuilt to all customers able to receive power. We continue to extend services to customers as they rebuild. Our substation destroyed in the tornado has been rebuilt and is again providing service to our customers. We anticipate insurance proceeds of approximately $6.5 million will cover most of the cost of the substation rebuild. Total storm restoration costs were approximately $27.3 million as of December 31, 2012. The majority of these costs have been capitalized. We expect the loss of electric load and corresponding revenues to abate as customers rebuild.


RESULTS OF OPERATIONS

        The following discussion analyzes significant changes in the results of operations for the years 2012, 2011 and 2010.

        The following table represents our results of operations by operating segment for the applicable years ended December 31 (in millions):

 
  2012   2011   2010  

Electric

  $ 52.6   $ 50.6   $ 43.2  

Gas

    1.3     2.7     2.6  

Other

    1.8     1.6     1.6  
               

Net income

  $ 55.7   $ 54.9   $ 47.4  
               

Electric Segment

Overview

        Our electric segment income for 2012 was $52.6 million as compared to $50.6 million for 2011.

        Electric operating revenues comprised approximately 91.3% of our total operating revenues during 2012. Electric operating revenues for 2012, 2011, and 2010 were comprised of the following:

 
  2012   2011   2010  

Residential

    42.2 %   42.4 %   42.4 %

Commercial

    31.2     30.1     30.3  

Industrial

    15.5     15.1     14.4  

Wholesale on-system

    3.6     3.7     4.0  

Wholesale off-system

    3.1     4.5     4.7  

Miscellaneous sources*

    2.7     2.6     2.6  

Other electric revenues

    1.7     1.6     1.6  

*
Primarily other public authorities


Gross Margin

        As shown in the table below, electric segment gross margin, defined as electric revenues less fuel and purchased power costs, increased approximately $7.8 million during 2012 as compared to 2011, reflecting a decrease in revenues of approximately $13.6 million and a decrease in electric fuel and purchased power expenses of approximately $21.4 million compared to 2011. Decreased sales demand, resulting from mild winter weather in the first quarter of 2012 and less favorable weather in the third quarter of 2012 as compared to the same period last year, negatively impacted revenues and margins. This negative impact was partially offset by a full year of electric customer rate increases for our Missouri customers and improving electric customer counts as customers continued to return to the system following the May 2011 tornado. A change in our unbilled revenue estimate in the third quarter of 2012 also positively impacted gross margin. Decreases in non-volume fuel expenses also increased margin by approximately $4.3 million over last year.

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        The electric gross margin increased approximately $38.6 million during 2011 as compared to 2010 mainly due to the September 2010 Missouri rate increase, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase.

        The table below represents our electric gross margins for the years ended December 31 (in millions).

 
  2012   2011   2010  

Electric segment revenues

  $ 510.7   $ 524.3   $ 484.7  

Fuel and purchased power

    178.9     200.3     199.3  
               

Electric segment gross margins

  $ 331.8   $ 324.0   $ 285.4  
               

Margin as % of total electric segment revenues

    65.0 %   61.8 %   58.9 %

        Although a non-GAAP presentation, we believe the presentation of gross margin is useful to investors and others in understanding and analyzing changes in our electric operating performance from one period to the next, and have included the analysis as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be comparable to other companies' presentations or more useful than the GAAP information we provide elsewhere in this report.


Sales and Revenues

        The amounts and percentage changes from the prior periods in kilowatt-hour ("kWh") sales by major customer class for on-system and off-system sales were as follows:

 
  kWh Sales
(in millions)
 
Customer Class
  2012   2011   % Change(1)   2011   2010   % Change(1)  

Residential

    1,850.8     1,982.7     (6.7 )%   1,982.7     2,060.4     (3.8 )%

Commercial

    1,558.3     1,576.3     (1.1 )   1,576.3     1,644.9     (4.2 )

Industrial

    1,028.4     1,022.8     0.6     1,022.8     1,007.0     1.6  

Wholesale on-system

    353.1     364.9     (3.2 )   364.9     355.8     2.5  

Other(2)

    124.2     128.7     (3.5 )   128.7     126.5     1.8  
                               

Total on-system sales

    4,914.8     5,075.4     (3.2 )   5,075.4     5,194.6     (2.3 )

Off-system

    704.0     740.0     (4.9 )   740.0     798.1     (7.3 )
                               

Total KWh Sales

    5,618.8     5,815.4     (3.4 )   5,815.4     5,992.7     (3.0 )

(1)
Percentage changes are based on actual kWh sales and may not agree to the rounded amounts shown above.

(2)
Other kWh sales include street lighting, other public authorities and interdepartmental usage.

        KWh sales for our on-system customers decreased approximately 3.2% during 2012 as compared to 2011 primarily due to decreased demand due to milder temperatures in 2012 as compared to 2011 and a trend toward more efficient utilization of electric power by our customers. Residential and commercial kWh sales decreased primarily due to these weather impacts and efficient utilization of electric power. Industrial sales increased slightly during 2012 as compared to 2011. On-system wholesale kWh sales decreased during 2012 as compared to 2011 reflecting the milder weather in 2012. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65° F) for 2012 were 2.8% less than 2011 although they were 29.3% more than the 30-year average, mainly due to unseasonably hot weather in June and July of 2012. Total heating degree days (the sum of the number of degrees that the daily average temperature for each day during that period was below 65° F) for 2012 were 20.3% less than 2011 and 20.6% less than the 30-year average.

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        KWh sales for our on-system customers decreased approximately 2.3% during 2011 as compared to 2010 primarily due to the loss of customers due to damaged or destroyed structures resulting from the May 22, 2011 tornado, although some of the effect was offset by temporary housing units. Residential and commercial kWh sales decreased in 2011 primarily due to the loss of residences and businesses in the May 22, 2011 tornado. Industrial kWh sales increased 1.6% in 2011 as compared to 2010 when there was a slowdown created by economic uncertainty. On-system wholesale kWh sales increased during 2011 as compared to 2010 reflecting the warmer weather in the third quarter of 2011.

        The amounts and percentage changes from the prior period's electric segment operating revenues by major customer class for on-system and off-system sales were as follows:

 
  Electric Segment Operating Revenues
($ in millions)
 
Customer Class
  2012   2011   % Change(1)   2011   2010   % Change(1)  

Residential

  $ 214.5   $ 221.7     (3.2 )% $ 221.7   $ 204.9     8.2 %

Commercial

    158.8     157.4     0.9     157.4     146.3     7.6  

Industrial

    78.8     78.9     (0.2 )   78.9     69.7     13.3  

Wholesale on-system

    18.6     19.1     (3.1 )   19.1     19.2     (0.6 )

Other(2)

    14.0     13.9     0.7     13.9     12.3     12.7  
                               

Total on-system revenues

    484.7     491.0     (1.3 )   491.0     452.4     8.5  

Off-system

    15.7     23.3     (32.6 )   23.3     22.9     1.7  
                               

Total revenues from KWh sales

    500.4     514.3     (2.7 )   514.3     475.3     8.2  

Miscellaneous revenues(3)

    8.5     8.2     4.0     8.2     7.6     8.2  
                               

Total electric operating revenues

  $ 508.9   $ 522.5     (2.6 ) $ 522.5   $ 482.9     8.2  

Water revenues

    1.8     1.8     1.2     1.8     1.8     (1.9 )
                               

Total Electric Segment Operating Revenues

  $ 510.7   $ 524.3     (2.6 ) $ 524.3   $ 484.7     8.2  

(1)
Percentage changes are based on actual revenues and may not agree to the rounded amounts shown above.

(2)
Other operating revenues include street lighting, other public authorities and interdepartmental usage.

(3)
Miscellaneous revenues include transmission service revenues, late payment fees, renewable energy credit sales, rent, etc.

        Revenues for our on-system customers decreased approximately $6.4 million (1.3%) during 2012 as compared to 2011. Weather and other related factors decreased revenues an estimated $25.6 million in 2012 as compared to 2011, primarily due to mild weather in the first quarter of 2012 and less favorable weather in the third quarter of 2012 as compared to the same period last year. Rate changes, primarily the June 2011 Missouri rate increase, the March 2011 Oklahoma rate increase, the January 2012 Kansas rate increase and the April 2011 Arkansas rate increase, contributed an estimated $12.0 million to revenues. Improved customer counts increased revenues an estimated $4.2 million. Additionally, a change in our estimate of unbilled revenues during the third quarter of 2012 contributed $3.0 million to revenues.

        Residential revenues decreased during 2012 due to the milder weather and efficient utilization of electric power. Commercial revenues increased primarily due to the Missouri, Kansas, Oklahoma and Arkansas rate increases. Industrial revenues decreased slightly.

        Revenues for our on-system customers increased approximately $38.6 million (8.5%) during 2011 as compared to 2010. Rate changes, primarily the September 2010 Missouri rate increase, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase, contributed an estimated $49.2 million to revenues. We estimate the impact of the

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tornado, after adjusting for weather, was an approximate 2% reduction in kilowatt hour sales for 2011. This reduction is reflected in a $7.7 million reduction in revenues, which includes customer growth in the first quarter of 2011, offset by negative sales growth (contraction) for the second, third and fourth quarters of 2011, resulting from the loss of customers due to the loss of residences and businesses. Weather and other related factors decreased revenues an estimated $2.9 million in 2011 as compared to 2010, primarily due to mild weather in the first and fourth quarters of 2011.

        Residential, commercial and industrial revenues increased during 2011 primarily due to the rate increases discussed above. On-system wholesale kWh revenues decreased 0.6% primarily due to the portion of FERC revenues that were subject to refund while we were waiting on approval of the Settlement Agreement and Offer of Settlement filed with the FERC on May 24, 2011. We refunded approximately $1.3 million of these revenues, including interest, in November 2011 as a result of this settlement.


Off-System Electric Transactions

        In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power Pool (SPP) energy imbalance services (EIS) market. See "— Competition" below. The majority of our off-system sales margins are included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and our transmission rider in our Arkansas jurisdiction and generally adjust the fuel and purchased power expense. As a result, nearly all of the off-system sales margin flows back to the customer and has little effect on net income.

        Off-system sales and revenues decreased during 2012 as compared to 2011 primarily due to the milder weather in 2012 as compared to 2011, as well as lower gas and purchased power prices.

        Off-system sales decreased during 2011 as compared to 2010 primarily due to limited power available for sale during the third quarter of 2011 as the excessive heat required us to use our resources to serve our own load. Off-system revenues increased 1.7%. Total purchased power related expenses are included in our discussion of purchased power costs below.


Operating Revenue Deductions — Fuel and Purchased Power

        The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statements of income for 2012, 2011 and 2010. As shown below, fuel and purchased power costs decreased in 2012 as compared to 2011 mainly due to lower volumes, the Southwest Power Administration (SWPA) amortization and changes in derivative expenses not recovered in fuel adjustments. During 2011, total fuel and purchased power expenses increased approximately $1.0 million (0.5%) as compared to 2010.

(in millions)
  2012   2011   2010  

Actual fuel and purchased power expenditures

  $ 173.6   $ 196.5   $ 200.0  

Missouri fuel adjustment recovery(1)

    3.4     7.3     3.1  

Missouri fuel adjustment deferral(2)

    5.3     (2.7 )   (4.5 )

Kansas and Oklahoma regulatory adjustments(2)

    1.0     (0.6 )   (0.1 )

SWPA amortization(3)

    (2.8 )   (1.5 )    

Unrealized (gain)/loss on derivatives

    (1.6 )   1.3     0.8  
               

Total fuel and purchased power expense per income statement

  $ 178.9   $ 200.3   $ 199.3  
               

(1)
Recovered from customers from prior deferral period.

(2)
A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers. Missouri amount includes the deferral of additional costs due to construction accounting, which terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

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(3)
Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010.

Operating Revenue Deductions — Other Than Fuel and Purchased Power

        The table below shows regulated operating expense changes during 2012 as compared to 2011 and during 2011 as compared to 2010.

(in millions)
  2012 vs. 2011   2011 vs. 2010  

Employee pension expense

  $ 1.4   $ 3.1  

Steam power other operating expense(1)

    2.0     1.7  

Transmission and distribution expense

    1.7     2.4  

Regulatory commission expense

    (0.5 )   0.7  

Employee health care expense

    2.4     0.5  

Injuries and damages expense

    (0.7 )   0.5  

Property insurance

    0.6     0.3  

Other power supply expense

    0.1     0.2  

Uncollectible accounts

    (0.4 )   0.2  

General labor expense

    0.4     (1.6 )

Professional services(2)

    2.1     (1.2 )

Banking fees

    (0.6 )    

Other miscellaneous accounts (netted)

    0.3     0.6  
           

TOTAL

  $ 8.8   $ 7.4  
           

(1)
Reflects recognition of expenses of new plants (Iatan and Plum Point) after deferral ended June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

(2)
$0.9 million reflects the transfer of expenses from Professional Services in July 2011 to regulatory and capital assets per our 2010 Missouri rate case.

        The table below shows maintenance and repairs expense changes during 2012 as compared to 2011 and during 2011 as compared to 2010.

(in millions)
  2012 vs. 2011   2011 vs. 2010  

Distribution maintenance expense

  $ (1.1 ) $ 2.0  

Transmission maintenance expense

    (0.3 )   (0.1 )

Maintenance and repairs expense at the Asbury plant

    0.9     (0.1 )

Maintenance and repairs expense to SLCC(1)

    0.6     1.8  

Maintenance and repairs expense at the Iatan plant(2)

    (0.8 )   1.5  

Maintenance and repairs expense at the Plum Point plant

    (0.1 )   0.7  

Maintenance and repairs expense at the Riverton plant — coal units

    (0.1 )   (1.2 )

Maintenance and repairs expense at the Riverton plant — gas units

    0.5     (0.3 )

Iatan deferred maintenance expense

    (0.1 )   (0.3 )

Other miscellaneous accounts (netted)

    (0.1 )   0.3  
           

TOTAL

  $ (0.6 ) $ 4.3  
           

(1)
2011 vs. 2010 change mainly due to a transformer failure in December 2011.

(2)
2012 vs. 2011 change mainly due to an outage in 2011.

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        Depreciation and amortization expense decreased approximately $2.9 million (5.0%) during 2012 as compared to 2011. This reflects a decrease in regulatory amortization expense of $6.6 million during 2012 due to the termination of construction accounting as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case, offset by increased plant in service.

        Depreciation and amortization expense increased approximately $4.3 million (7.9%) during 2011 as compared to 2010. This reflects increased depreciation of $6.3 million due to increased plant in service during 2011 and the effect of ending deferred depreciation related to Iatan 2 as allowed in our regulatory agreements. This increase was partially offset by a decrease in regulatory amortization expense of $0.9 million due to the termination of construction accounting as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

        Other taxes increased approximately $0.9 million in 2012 and $3.0 million in 2011 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

Gas Operating Revenues and Sales

        The following table details our natural gas sales for the years ended December 31:

 
  Total Gas Delivered to Customers  
(bcf sales)
  2012   2011   % Change   2011   2010   % Change  

Residential

    2.01     2.56     (21.4 )%   2.56     2.68     (4.3 )%

Commercial

    1.05     1.27     (17.2 )   1.27     1.26     0.3  

Industrial(1)

    0.06     0.10     (42.9 )   0.10     0.11     (5.9 )

Other(2)

    0.02     0.03     (29.5 )   0.03     0.03     (0.9 )
                               

Total retail sales

    3.14     3.96     (20.7 )   3.96     4.08     (2.9 )

Transportation sales(1)

    4.25     4.53     (6.2 )   4.53     4.83     (6.2 )
                               

Total gas operating sales

    7.39     8.49     (13.0 )   8.49     8.91     (4.7 )

(1)
2012 percentage change reflects the transfer of customers from industrial sales to transportation during the first quarter of 2012. 2011 percentage change reflects three industrial customers switching to transportation during 2011.

(2)
Other includes other public authorities and interdepartmental usage.

        Gas retail sales decreased 20.7% during 2012 as compared to 2011 reflecting mild weather in 2012 and customer contraction of 0.2%. We expect gas customer growth to be flat during the next several years. Heating degree days were 22.9% lower in 2012 than 2011 and 23.2% lower than the 30-year average. Residential and commercial sales decreased during 2012 due to the mild weather and customer contraction. Industrial sales decreased 42.9% during 2012 reflecting the transfer of customers from industrial sales to transportation during the first quarter of 2012.

        Gas retail sales decreased 2.9% during 2011 as compared to 2010 reflecting both customer contraction of 0.9% and customers switching from sales service retail to transportation. Commercial sales increased slightly during 2011. Industrial sales decreased 5.9% during 2011 due to customer contraction and the transfer of the customers between classes mentioned above.

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        The following table details our natural gas revenues for the years ended December 31:

 
  Operating Revenues and Cost of Gas Sold  
($ in millions)
  2012   2011   % Change   2011   2010   % Change  

Residential

  $ 24.7   $ 29.0     (14.7 )% $ 29.0   $ 32.3     (10.1 )%

Commercial

    10.8     12.5     (13.7 )   12.5     13.3     (6.2 )

Industrial(1)

    0.5     0.7     (31.9 )   0.7     0.8     (16.0 )

Other(2)

    0.3     0.3     (23.9 )   0.3     0.4     (5.5 )
                               

Total retail revenues

  $ 36.3   $ 42.5     (14.7 ) $ 42.5   $ 46.8     (9.0 )

Other revenues

    0.3     0.4     (13.4 )   0.4     0.4     7.3  

Transportation revenues(1)

    3.2     3.5     (7.5 )   3.5     3.7     (7.0 )
                               

Total gas operating revenues

  $ 39.8   $ 46.4     (14.2 ) $ 46.4   $ 50.9     (8.8 )

Cost of gas sold

    18.6     22.8     (18.1 )   22.8     26.6     (14.5 )
                               

Gas operating revenues over cost of gas in rates

  $ 21.2   $ 23.6     (10.4 ) $ 23.6   $ 24.3     (2.5 )

(1)
2012 percentage change reflects the transfer of customers from industrial sales to transportation during the first quarter of 2012. 2011 percentage change reflects three industrial customers switching to transportation during 2011.

(2)
Other includes other public authorities and interdepartmental usage.

        During 2012, gas segment revenues were approximately $39.8 million as compared to $46.4 million in 2011, a decrease of 14.2%, mainly due to decreased sales resulting from mild weather during 2012. PGA revenue (which represents the cost of gas recovered from our customers) was approximately $18.6 million as compared to $22.8 million in 2011, a decrease of approximately $4.1 million (18.1%), representing a decrease in the cost of gas. Our margin (defined as gas operating revenues less cost of gas in rates) was $2.4 million less in 2012 as compared to 2011.

        During 2011, gas segment revenues were approximately $46.4 million as compared to $50.9 million in 2010, a decrease of 8.8%. This decrease was largely driven by a decrease in the PGA that went into effect November 2, 2010. During 2011, our PGA revenue was approximately $22.8 million as compared to $26.6 million in 2010, a decrease of approximately $3.8 million (14.5%), representing a decrease in the cost of gas. Our margin was $0.7 million less in 2011 as compared to 2010.

        Our PGA clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of December 31, 2012, we had unrecovered purchased gas costs of $1.7 million recorded as a current regulatory asset and $0.2 million recorded as a non-current regulatory liability as compared to unrecovered purchased gas costs of $0.2 million recorded as a current regulatory asset and $1.3 million recorded as a non-current regulatory asset as of December 31, 2011


Operating Revenue Deductions

        Total other operating expenses were $8.4 million during 2012 as compared to $8.3 million in 2011, primarily due to a $0.1 million increase in transmission operation expense.

        Depreciation and amortization expense increased approximately $0.1 million (3.0%) during 2012.

        Our gas segment had net income of $1.3 million in 2012 as compared to $2.7 million in 2011.

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        Total other operating expenses were $8.3 million during 2011 as compared to $9.5 million in 2010, primarily due to a $0.6 million decrease in customer accounts expense (mainly uncollectible accounts), a $0.3 million decrease in rent expense, a $0.2 million decrease in employee pension expense and a $0.2 million decrease in general labor costs.

        Depreciation and amortization expense increased approximately $0.5 million (15.2%) during 2011 due to increased depreciation rates resulting from our 2010 Missouri gas rate case.

        Our gas segment had net income of $2.7 million in 2011 as compared to $2.6 million in 2010.

Consolidated Company

Income Taxes

        The following table shows our consolidated provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable years ended December 31:

 
  2012   2011   2010  

Consolidated provision for income taxes

  $ 34.2   $ 34.3   $ 30.5  

Consolidated effective federal and state income tax rates

    38.0 %   38.4 %   39.2 %

        The effective tax rate for 2010 is higher than 2012 and 2011 primarily due to an adjustment made in 2010 as a result of the Patient Protection and Affordable Care Act, which became law on March 23, 2010. This legislation included a provision that removed the non-taxable status, for income tax purposes, of Medicare D subsidies received. Although the elimination of this tax benefit did not take effect until 2013, this change required us to recognize the full accounting impact in our financial statements in the period in which the legislation was enacted. As a result, in the first quarter of 2010, we recorded a one-time non-cash charge of approximately $2.1 million to income taxes to reflect the impact of this change, which increased our effective tax rate in 2010.

        As part of an agreement reached in our 2009 Missouri electric rate case, effective September 10, 2010, we agreed to commence an eighteen year amortization of a regulatory asset related to the tax benefits of cost of removal. These tax benefits were flowed through to customers from 1981-2008 and totaled approximately $11.1 million. We recorded the regulatory asset expecting to recover these benefits from customers in future periods. Based on the agreement, we estimated the portion of the amortization period from which we would not receive rate recovery for this item and wrote off approximately $1.2 million in the first quarter of 2010. Amortization resumed during 2011 and the remaining balance as of December 31, 2012 was approximately $9.6 million.

        See Note 9 of "Notes to Consolidated Financial Statements" under Item 8 for information and discussion concerning our income tax provision and effective tax rates.


Nonoperating Items

        The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended December 31. AFUDC increased in 2012 as compared to 2011 reflecting the environmental retrofit project at our Asbury plant. AFUDC decreased in 2011 as compared to 2010 reflecting the completion of Iatan 2 and the Plum Point Energy Station in 2010. See Note 1 of "Notes to Consolidated Financial Statements" under Item 8.

($ in millions)
  2012   2011   2010  

Allowance for equity funds used during construction

  $ 1.1   $ 0.3   $ 4.5  

Allowance for borrowed funds used during construction

    0.8     0.2     5.7  
               

Total AFUDC

  $ 1.9   $ 0.5   $ 10.2  

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        Total interest charges on long-term and short-term debt for 2012, 2011 and 2010 are shown below. The change in long-term debt interest for 2012 compared to 2011 reflects the redemption on April 1, 2012 of all $74.8 million aggregate principal amount of our First Mortgage Bonds, 7.00% Series due 2024 and the redemption of all $5.2 million of our First Mortgage Bonds, 5.20% Pollution Control Series due 2013, and all $8.0 million of our First Mortgage Bonds, 5.30% Pollution Control Series due 2013. These bonds were replaced by a private placement of $88.0 million aggregate principal amount of 3.58% First Mortgage Bonds due April 2, 2027. The first settlement of $38.0 million occurred on April 2, 2012 and the second settlement of $50.0 million occurred on June 1, 2012.

        The change in long-term debt interest for 2011 as compared to 2010 reflects the redemption of $48.3 million aggregate principal amount of our Senior Notes, 7.05% Series due 2022, which were redeemed on August 27, 2010, and replaced by $50.0 million principal amount 5.20% first mortgage bonds issued August 25, 2010. The changes also reflect the redemption of 6.5% first mortgage bonds on April 1, 2010 and the redemption of our 8.5% trust preferred securities on June 28, 2010, which were replaced by 4.65% first mortgage bonds issued May 28, 2010. The decreases in short-term debt interest for all periods presented primarily reflect lower levels of borrowing.

 
  Interest Charges
($ in millions)
 
 
  2012   2011   Change   2011   2010   Change  

Long-term debt interest

  $ 40.2   $ 42.6     (5.6 )% $ 42.6   $ 41.9     1.5 %

Short-term debt interest

    0.2     0.1     >100.0     0.1     0.6     (86.3 )

Trust preferred securities interest

                      2.1     (100.0 )

Iatan 1 and 2 carrying charges*

    0.1     (2.1 )   >100.0     (2.1 )   (3.2 )   31.8  

Other interest

    1.0     0.9     2.5     0.9     0.9     19.6  
                               

Total interest charges

  $ 41.5   $ 41.5     (0.1 ) $ 41.5   $ 42.3     (2.0 )

*
Beginning in the second quarter of 2009, we deferred Iatan 1 carrying charges to reflect construction accounting in accordance with our agreement with the MPSC that allowed deferral of certain costs until the environmental upgrades to Iatan 1 were included in our rate base. We began deferring Iatan 2 carrying charges in the third quarter of 2010. Deferral ended when the plant was placed in rates. Iatan 1 was placed in rates in September 2010. Iatan 2 was placed in rates June 15, 2011. See Note 3 of "Notes to Consolidated Financial Statements" under Item 8 for information regarding carrying charges.


RATE MATTERS

        We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.

        Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a "cost of service" basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on "rate base." "Rate base" is generally determined by reference to the original cost (net of accumulated depreciation and amortization) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, amortization and retirement of utility plant or write-off's as ordered by the utility commissions. In general, a request of new rates is made on the basis of a "rate base" as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag (commonly referred to as "regulatory lag") between the time we incur costs and the time when we can start recovering the costs through rates.

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        The following table sets forth information regarding electric and water rate increases since January 1, 2010:

Jurisdiction
  Date
Requested
  Annual
Increase
Granted
  Percent
Increase
Granted
  Date
Effective

Missouri — Water

  May 21, 2012   $ 450,000     25.5 % November 23, 2012

Missouri — Electric

  September 28, 2010   $ 18,700,000     4.70 % June 15, 2011

Missouri — Electric

  October 29, 2009   $ 46,800,000     13.40 % September 10, 2010

Kansas — Electric

  June 17, 2011   $ 1,250,000     5.20 % January 1, 2012

Kansas — Electric

  November 4, 2009   $ 2,800,000     12.40 % July 1, 2010

Oklahoma — Electric

  June 30, 2011   $ 240,000     1.66 % January 4, 2012

Oklahoma — Electric

  January 28, 2011   $ 1,063,100     9.32 % March 1, 2011

Oklahoma — Electric

  March 25, 2010   $ 1,456,979     15.70 % September 1, 2010

Arkansas — Electric

  August 19, 2010   $ 2,104,321     19.00 % April 13, 2011

Missouri — Gas

  June 5, 2009   $ 2,600,000     4.37 % April 1, 2010

        See Note 3 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding rate matters.


COMPETITION AND MARKETS

Electric Segment

        Energy Imbalance Services:    The Southwest Power Pool (SPP) regional transmission organization (RTO) energy imbalance services market (EIS) provides real time energy for most participating members within the SPP regional footprint. Imbalance energy prices are based on market bids and status/availability of dispatchable generation and transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO performs a real time security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native load.

        Day Ahead Market:    The SPP RTO will implement a Day-Ahead Market, or Integrated Marketplace, with unit commitment and co-optimized ancillary services market, in March 2014. As part of the Integrated Marketplace, the SPP RTO will create, prior to implementation of such market, a single NERC approved balancing authority to take over balancing authority responsibilities for its members, including Empire, which is expected to provide operational and economic benefits for our customers. The Integrated Marketplace would replace the existing EIS market described above.

        See Note 3 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding competition.


LIQUIDITY AND CAPITAL RESOURCES

        Overview.    Our primary sources of liquidity are cash provided by operating activities, short-term borrowings under our commercial paper program (which is supported by our credit facilities) and borrowings from our unsecured revolving credit facility. As needed, we raise funds from the debt and equity capital markets to fund our liquidity and capital resource needs.

        Our issuance of various securities, including equity, long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the SEC. We estimate that internally generated funds (funds provided by operating activities less dividends paid) will provide approximately 70% of the funds required in 2013 for our budgeted capital expenditures (as discussed in "Capital Requirements and Investing Activities" below). We believe the amounts available to us under our credit facilities and the issuance of debt and equity securities, together with the cash provided by operating activities, will allow us to meet our needs for

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working capital, pension contributions, our continuing construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years.

        We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the timing of our construction programs and other factors. See Item 1A, "Risk Factors" for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities for the last three years.


Summary of Cash Flows

 
  Fiscal Year  
(in millions)
  2012   2011   2010  

Cash provided by/(used in):

                   

Operating activities

  $ 159.1   $ 134.6   $ 135.9  

Investing activities

    (136.9 )   (105.1 )   (111.0 )

Financing activities

    (24.2 )   (34.6 )   (20.0 )
               

Net change in cash and cash equivalents

  $ (2.0 ) $ (5.1 ) $ 4.9  


Cash flow from Operating Activities

        We prepare our statement of cash flows using the indirect method. Under this method, we reconcile net income to cash flows from operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, pension costs, deferred income taxes, equity AFUDC, changes in commodity risk management assets and liabilities and changes in the consolidated balance sheet for working capital from the beginning to the end of the period.

        Year-over-year changes in our operating cash flows are attributable primarily to working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas and coal purchases and the effects of deferred fuel recoveries. The increase or decrease in natural gas prices directly impacts the cost of gas stored in inventory.

        2012 compared to 2011.    In 2012, our net cash flows provided from operating activities was $159.1 million, an increase of $24.5 million or 18.2% from 2011. This increase was primarily a result of:

    Changes in net income — $0.7 million.

    Reduced pension contributions net of expense accruals — $22.1 million.

    Changes in fuel and other inventory — $17.1 million.

    Changes in fuel adjustment deferrals and regulatory trackers and amortizations reflected in prepaid or other current assets — $13.9 million.

    Return of cash from energy trading margin accounts — $3.0 million.

    Changes in accruals related to interest, taxes and customer deposits — $1.9 million.

    Changes in depreciation and amortization, mostly reflecting lower regulatory amortization offset by increased plant in service and other amortizations — $(8.6) million.

    Lower deferrals of income tax due to reduced tax depreciation benefits — $(13.2) million.

    Changes in accounts receivable and accrued unbilled revenues — $(11.0) million.

    Changes in accounts payable partially offset by lower accrued taxes — $(1.0) million.

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        2011 compared to 2010.    In 2011, our net cash flows provided from operating activities was $134.6 million, a decrease of $1.3 million or 1.0% from 2010. This increase was primarily a result of:

    Changes in net income — $7.6 million.

    Changes in depreciation and amortization, reflecting increased plant in service and fuel deferral amortization — $8.7 million

    Increased deferrals for income taxes, reflecting positive impacts for accelerated tax depreciation and deferring taxability of the 2010 SWPA payment — $18.2 million.

    Lower equity AFUDC — $4.2 million

    Changes in receivables due to lower unbilled revenues, receipt of transmission credits and income tax refunds collected — $21.6 million.

    Changes in accounts payable partially due to lower prices for fuel purchases — $5.9 million.

    Changes in pension and other post retirement benefit costs due to the result of $20.2 million in additional pension contributions compared to 2010 — $(16.7) million.

    Increased natural gas purchases and supplies for new and existing generation plants — $(15.1) million.

    Changes in prepaid expenses and deferred charges mostly reflecting certain regulatory treatment of fuel charges and carrying costs — ($3.6) million.

    Changes reflecting the receipt of SWPA minimum flows payment in 2010 — $(26.6) million.


Capital Requirements and Investing Activities

        Our net cash flows used in investing activities increased $31.8 million from 2011 to 2012. The increase was primarily the result of an increase in electric plant additions and replacements, mainly due to the environmental retrofit in progress at our Asbury plant.

        Our net cash flows used in investing activities decreased $5.9 million from 2010 to 2011. The decrease was primarily the result of a decrease in new generation construction in 2011.

        Our capital expenditures totaled approximately $146.3 million, $101.1 million, and $108.2 million in 2012, 2011 and 2010, respectively.

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        A breakdown of these capital expenditures for 2012, 2011 and 2010 is as follows:

 
  Capital Expenditures  
(in millions)
  2012   2011   2010  

Distribution and transmission system additions

  $ 63.3   $ 46.5   $ 38.8  

Additions and replacements — electric plant

    46.7     13.4     7.2  

New generation — Iatan 2 and Plum Point Energy Station

    0.8     4.5     49.6  

Storms

    5.0     15.9     0.1  

Transportation

    3.7     3.9     1.3  

Gas segment additions and replacements

    3.3     3.9     5.0  

Other (including retirements and salvage — net)(1)

    20.7     9.2     3.4  
               

Subtotal

  $ 143.5   $ 97.3   $ 105.4  

Non-regulated capital expenditures (primarily fiber optics)

    2.8     3.8     2.8  
               

Subtotal capital expenditures incurred(2)

  $ 146.3   $ 101.1   $ 108.2  
               

Adjusted for capital expenditures payable(3)

    (9.3 )   1.4     3.8  
               

Insurance proceeds receivable

            (0.1 )
               

Capital lease, primarily Plum Point unit train

            (2.7 )
               

Total cash outlay

  $ 137.0   $ 102.5   $ 109.2  
               

(1)
Other includes equity AFUDC of $(1.1) million, $(0.3) million and $(4.5) million for 2012, 2011 and 2010, respectively.

(2)
Expenditures incurred represent the total cost for work completed for the projects during the year. Discussion of capital expenditures throughout this 10-K is presented on this basis. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

(3)
The amount of expenditures paid/(unpaid) at the end of the year to adjust to actual cash outlay reflected in the Investing Activities section of the Statement of Cash Flows.

        Approximately 85%, 100% and 75% of our cash requirements for capital expenditures for 2012, 2011 and 2010, respectively, were satisfied internally from operations (funds provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and debt securities discussed below.

        Our estimated capital expenditures (excluding AFUDC) for 2013, 2014 and 2015 are detailed below. See Item 1, "Business — Construction Program." We anticipate that we will spend the following amounts over the next three years for the following projects:

Project
  2013   2014   2015   Total  

Asbury environmental upgrades

  $ 55.8   $ 24.8   $ 12.1   $ 92.7  

Riverton Unit 12 combined cycle conversion

    15.1     40.4     65.3     120.8  

Electric distribution system additions

    42.9     38.3     36.3     117.5  

Electric transmission facilities

    12.1     26.7     36.3     75.1  

Other

    37.5     35.3     28.1     100.9  
                   

Total

  $ 163.4   $ 165.5   $ 178.1   $ 507.0  
                   

        Our estimated total capital expenditures (excluding AFUDC) for 2016 and 2017 are $107.0 million and $108.2 million, respectively.

        We estimate that internally generated funds will provide approximately 70% of the funds required in 2013 for our budgeted capital expenditures. We intend to utilize short-term debt to finance any additional amounts needed beyond those provided by operating activities for such capital expenditures. If additional financing is needed, we intend to utilize a combination of debt and equity securities. The estimates herein

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may be changed because of changes we make in our construction program, unforeseen construction costs, our ability to obtain financing, regulation and for other reasons. See further discussion under "Financing Activities" below.


Financing Activities

2012 compared to 2011.

        Our net cash flows used in financing activities was $24.2 million in 2012, a decrease of $10.4 million as compared to 2011, primarily due to the following:

    Cash used to pay dividends was $42.3 million, an increase in use of cash of $(15.5) million.

    We borrowed $12.0 million in short-term debt in 2012 as compared to repaying $12.0 million in 2011, which provided $24.0 million of cash when comparing 2012 to 2011.

    Proceeds from the issuance of common stock, primarily from the dividend reinvestment plan, increased $2.2 million.

    We refinanced $88.0 million of bonds in 2012 which had almost no impact on cash flow.

2011 compared to 2010.

        Our net cash flows used in financing activities was $34.6 million in 2011, an increase of $14.6 million as compared to 2010, primarily due to the following:

    A reduction in paid dividends provided $25.3 million of additional cash.

    We repaid $12.0 million in short-term debt in 2012 as compared to repaying $26.5 million in 2011. These activities provided $14.5 million of cash in 2011 compared to 2010.

    Proceeds from the issuance of common stock decreased $(54.4) million as 2010 included proceeds from an equity distribution program.

    We refinanced approximately $150.0 million of bonds and trust preferred securities in total in 2010 which had almost no impact on cash flow.

        On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due 2033 and $120.0 million of 4.32% First Mortgage Bonds due 2043. The delayed settlement is anticipated to occur on or about May 30, 2013, subject to customary closing conditions. We expect to use the proceeds from the sale of the bonds to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013 with the remaining proceeds to be used for general corporate purposes. The bonds will be issued under the EDE Mortgage.

Shelf Registration.

        We have a $400.0 million shelf registration statement with the SEC, effective February 7, 2011, covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. We have received regulatory approval for the issuance of securities under this shelf from all four states in our electric service territory, but we may only issue up to $250.0 million of such securities in the form of first mortgage bonds, of which $12.0 million would remain available after giving effect to the $150.0 million of new first mortgage bonds to be issued on or about May 30, 2013. We plan to use proceeds from offerings made pursuant to this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs during the three-year effective period.

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Credit Agreements.

        On January 17, 2012, we entered into the Third Amended and Restated Unsecured Credit Agreement which amended and restated our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010. See Note 7 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding this amendment and our unsecured line of credit.

EDE Mortgage Indenture.

        The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1.0 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the year ended December 31, 2012 would permit us to issue approximately $609.2 million of new first mortgage bonds based on this test with an assumed interest rate of 5.5%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2012, we had retired bonds and net property additions which would enable the issuance of at least $776.7 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2012, we are in compliance with all restrictive covenants of the EDE Mortgage.

EDG Mortgage Indenture.

        The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of December 31, 2012, this test would allow us to issue approximately $12.8 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.

        Corporate credit ratings and the ratings for our securities are as follows:

 
  Fitch   Moody's   Standard & Poor's

Corporate Credit Rating

  n/r*   Baa2   BBB-

EDE First Mortgage Bonds

  BBB+   A3   BBB+

Senior Notes

  BBB   Baa2   BBB-

Commercial Paper

  F3   P-2   A-3

Outlook

  Stable   Stable   Stable

*
Not rated.

        On May 27, 2011 Standard & Poor's revised our rating outlook to stable from positive after the May 2011 tornado. On March 23, 2012, Standard & Poor's reaffirmed our ratings. On May 26, 2011 after the May 2011 tornado, and again on April 25, 2012, Moody's reaffirmed all of our ratings. On March 24, 2011,

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Fitch revised our commercial paper rating from F2 to F3 and reaffirmed our other ratings. The rating action was not based on a specific action or event on our part, but reflected their traditional linkage of long-term and short-term Issuer Default Ratings. On May 29, 2012, Fitch reaffirmed our ratings.

        A security rating is not a recommendation to buy, sell or hold securities. Each rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.


CONTRACTUAL OBLIGATIONS

        Set forth below is information summarizing our contractual obligations as of December 31, 2012. Other pension and postretirement benefit plans are funded on an ongoing basis to match their corresponding costs, per regulatory requirements and have been estimated for 2013 – 2017 as noted below.

 
  Payments Due By Period
(in millions)
 
Contractual Obligations(1)
  Total   Less Than
1 Year
  1-3 Years   3-5 Years   More Than
5 Years
 

Long-term debt (w/o discount)

  $ 688.4   $ 98.4   $   $ 25.0   $ 565.0  

Interest on long-term debt

    532.1     34.9     65.7     63.8     367.7  

Short-term debt

    24.0     24.0              

Capital lease obligations

    6.9     0.6     1.1     1.1     4.1  

Operating lease obligations(2)

    4.8     0.8     1.5     1.4     1.1  

Electric purchase obligations(3)

    508.8     55.3     72.8     59.9     320.8  

Gas purchase obligations(4)

    36.3     9.4     13.1     9.7     4.1  

Open purchase orders

    161.8     45.2     33.3     83.3      

Postretirement benefit obligation funding

    20.8     4.9     8.8     7.1      

Pension benefit funding

    63.2     15.6     26.4     21.2      

Other long-term liabilities(5)

    3.3     0.1     0.3     0.3     2.6  
                       

TOTAL CONTRACTUAL OBLIGATIONS

  $ 2,050.4   $ 289.2   $ 223.0   $ 272.8   $ 1,265.4  
                       

(1)
Some of our contractual obligations have price escalations based on economic indices, but we do not anticipate these escalations to be significant.

(2)
Excludes payments under our Elk River Wind Farm, LLC and Cloud County Wind Farm, LLC agreements, as payments are contingent upon output of the facilities. Payments under the Elk River Wind Farm, LLC agreement can run from zero up to a maximum of approximately $16.9 million per year based on a 20 year average cost and an annual output of 550,000 megawatt hours. Payments under the Meridian Way Wind Farm agreement can range from zero to a maximum of approximately $14.6 million per year based on a 20-year average cost.

(3)
Includes a water usage contract for our SLCC facility, fuel and purchased power contracts and associated transportation costs, as well as purchased power for 2013 through 2039 for Plum Point.

(4)
Represents fuel contracts and associated transportation costs of our gas segment.

(5)
Other long-term liabilities primarily represent electric facilities charges paid to City Utilities of Springfield, Missouri of $11,000 per month over 30 years.

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DIVIDENDS

        Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.

        In response to the expected loss of revenues resulting from the May 22, 2011 tornado, our level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. On February 2, 2012, the Board of Directors re-established the dividend and declared a quarterly dividend of $0.25 per share on common stock payable on March 15, 2012 to holders of record as of March 1, 2012. Dividends were paid during all four quarters of 2012. As of December 31, 2012, our retained earnings balance was $47.1 million (compared to $33.7 million at December 31, 2011) after paying out $42.3 million in dividends during 2012.

        The following table shows our diluted earnings per share and dividends paid per share for the years ended December 31, 2012, 2011 and 2010:

 
  2012   2011   2010  

Diluted earnings per share

  $ 1.32   $ 1.31   $ 1.17  

Dividends paid per share

  $ 1.00   $ 0.64   $ 1.28  

        Under Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax. However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the Federal Power Act (FPA) prohibits the payment by a utility of dividends from any funds "properly included in capital account". There are no additional rules or regulations issued by the FERC under the FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive analysis of the specific facts and circumstances surrounding the utility and the dividend in question, with particular focus on the impact of the proposed dividend on the liquidity and financial condition of the utility.

        In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. On June 9, 2011, we amended the EDE Mortgage in order to provide us with additional flexibility to pay dividends to our shareholders by permitting the payment of any dividend or distribution on, or purchase of, shares of its common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1.

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OFF-BALANCE SHEET ARRANGEMENTS

        We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources, other than operating leases entered into in the normal course of business.


CRITICAL ACCOUNTING POLICIES

        Set forth below are certain accounting policies that are considered by management to be critical and that typically require difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain (other accounting policies may also require assumptions that could cause actual results to be different than anticipated results). A change in assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

        Pensions and Other Postretirement Benefits (OPEB).    We recognize expense related to pension and other postretirement benefits as earned during the employee's period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the accumulated benefit obligation. Our pension and OPEB expense or benefit includes amortization of previously unrecognized net gains or losses. Additional income or expense may be recognized when our unrecognized gains or losses as of the most recent measurement date exceed 10% of our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits and OPEB benefits, unrecognized net gains or losses as of the measurement date are amortized into actuarial expense over ten years.

        We have electric rate orders in Missouri, Kansas and Oklahoma that allow us to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate orders, we prospectively calculate the value of plan assets using a market related value method as allowed by the Accounting Standard Codification (ASC) guidance on defined benefit plans disclosure. In addition, our rate orders allow us to defer any pension cost that is different from those allowed recovery in rate cases.

        In our agreement with the MPSC regarding the purchase of Missouri Gas by EDG, we were allowed to adopt this pension cost recovery methodology for EDG, as well. Also, it was agreed that the effects of purchase accounting entries related to pension and other post-retirement benefits would be recoverable in future rate proceedings. Thus the fair value adjustment acquisition entries have been recorded as regulatory assets, as we believe these amounts are probable of recovery in future rates. The regulatory asset is reduced by an amount equal to the difference between the regulatory costs and the estimated GAAP costs. The difference between this total and the costs being recovered from customers is deferred as a regulatory asset or liability in accordance with the ASC guidance on regulated operations, and recovered over a period of 5 years.

        We expect future pension expense or benefits are probable of full recovery in our rates, thus lowering our sensitivity to accounting risks and uncertainties.

        We have rate orders in Missouri, Kansas and Oklahoma that allow us to defer any OPEB cost that is different from those allowed recovery in rate cases. This treatment is similar to treatment afforded pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into expense over ten years and the recognition of regulatory assets and liabilities as described in the immediately preceding paragraph.

        Based on the regulatory treatment of pension and OPEB recovery afforded in our jurisdictions, we record the amount of unfunded defined benefit pension and postretirement plan obligation as regulatory assets on our balance sheet rather than as reductions of equity through comprehensive income.

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        Our funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. The actual minimum pension funding requirements will be determined based on the results of the actuarial valuations and the performance of our pension assets during the current year. See Note 8 of "Notes to Consolidated Financial Statements" under Item 8.

        Risks and uncertainties affecting the application of our pension accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), demographic assumptions (i.e. mortality and retirement rates) and employee compensation trend rates. Factors that could result in additional pension expense and/or funding include: a lower discount rate than estimated, higher compensation rate increases, lower return on plan assets, and longer retirement periods.

        Risks and uncertainties affecting the application of our OPEB accounting policy and related funding include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), healthcare cost trend rates, Medicare prescription drug costs and demographic assumptions (i.e. mortality and retirement rates). See Note 1 and Note 8 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        Regulatory Assets and Liabilities.    In accordance with the ASC accounting guidance for regulated activities, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over us (Missouri, Kansas, Arkansas, Oklahoma and FERC).

        In accordance with accounting guidance for regulated activities, we record a regulatory asset for all or part of an incurred cost that would otherwise be charged to expense in accordance with the accounting guidance, which requires that an asset be recorded if it is probable that future revenue in an amount at least equal to the capitalized cost will be allowable for costs for rate making purposes and the current available evidence indicates that future revenue will be provided to permit recovery of the cost. Additionally, we follow the accounting guidance for regulated activities which says that a liability should be recorded when a regulator has provided current recovery for a cost that is expected to be incurred in the future. We follow this guidance for incurred costs or credits that are subject to future recovery from or refund to our customers in accordance with the orders of our regulators.

        Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory assets and liabilities are ratably eliminated through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC accounting guidance for regulated activities with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of ASC accounting guidance for regulated activities based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations.

        As of December 31, 2012, we have recorded $250.3 million in regulatory assets and $137.4 million as regulatory liabilities. See Note 3 of "Notes to Consolidated Financial Statements" under Item 8 for detailed information regarding our regulatory assets and liabilities.

        Risks and uncertainties affecting the application of this accounting policy include: regulatory environment, external regulatory decisions and requirements, anticipated future regulatory decisions and their impact of deregulation and competition on ratemaking process, unexpected disallowances, possible changes in accounting standards (including as a result of adoption of IFRS) and the ability to recover costs.

        Fuel Adjustment Clause.    Typical fuel adjustment clauses permit the distribution to customers of changes in fuel costs, subject to routine regulatory review, without the need for a general rate proceeding.

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Fuel adjustment clauses are presently applicable to our retail electric sales in Missouri, Oklahoma and Kansas and system wholesale kilowatt-hour sales under FERC jurisdiction. We have an Energy Cost Recovery Rider in Arkansas that adjusts for changing fuel and purchased power costs on an annual basis.

        The MPSC authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. A base cost is established in rates. The MPSC established a base cost for the recovery of fuel and purchased power expenses used to supply energy. The fuel adjustment clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, nearly all of the off-system sales margin flows back to the customer.

        Unbilled Revenue.    At the end of each period we estimate, based on expected usage, the amount of revenue to record for energy and natural gas that has been provided to customers but not billed. Risks and uncertainties affecting the application of this accounting policy include: projecting customer energy usage, estimating the impact of weather and other factors that affect usage (such as line losses) for the unbilled period and estimating loss of energy during transmission and delivery. Assumptions such as electrical load requirements, customer billing rates, and line loss factors are used in the estimation process and are evaluated periodically. Changes to certain assumptions during the evaluation process can lead to a change in the estimate.

        Contingent Liabilities.    We are a party to various claims and legal proceedings arising in the ordinary course of our business, which are primarily related to workers' compensation and public liability. We regularly assess our insurance deductibles, analyze litigation information with our attorneys and evaluate our loss experience. Based on our evaluation as of the end of 2012, we believe that we have accrued liabilities in accordance with ASC accounting guidance sufficient to meet potential liabilities that could result from these claims. This liability at December 31, 2012 and 2011 was $4.2 million and $4.5 million, respectively.

        Risks and uncertainties affecting these assumptions include: changes in estimates on potential outcomes of litigation and potential litigation yet unidentified in which we might be named as a defendant.

        Goodwill.    As of December 31, 2012, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and income approaches is used to estimate the fair value of goodwill.

        We use the market approach which estimates fair value of the gas reporting unit by comparing certain financial metrics to comparable companies. Comparable companies whose securities are actively traded in the public market are judgmentally selected by management based on operational and economic similarities. We utilize EBITDA (earnings before interest, taxes, depreciation, and amortization) multiples of the comparable companies in relation to the EBITDA results of the gas reporting unit to determine an estimate of fair value.

        We also utilize a valuation technique under the income approach which estimates the discounted future cash flows of operations. Our procedures include developing a baseline test and performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering those assumptions which are subjective in nature and inherent to a discounted cash flows calculation. Other qualitative factors and comparisons to industry peers are also used to further support the assumptions and ultimately the overall evaluation. A key qualitative assumption considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for the gas reporting unit. Some of the key quantitative assumptions included in our tests involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. If

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negative changes occurred to one or more key assumptions, an impairment charge could result. With the exception of the capital spending rate, the key assumptions noted are significantly determined by market factors and significant changes in market factors that impact the gas reporting unit would likely be mitigated by our current and future regulatory rate design to some extent. Other risks and uncertainties affecting these assumptions include: management's identification of impairment indicators, changes in business, industry, laws, technology and economic conditions. Actual results for the gas reporting unit indicate a slight decline in gas customer growth and demand, but this was anticipated in our assumptions for purposes of the discounted cash flow calculation. Our forecasts anticipate flat customer growth over the next several years.

        We weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of October 1, 2012 indicated the estimated fair market value of the gas reporting unit to be $5.0 million to $8.0 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future.

        Use of Management's Estimates.    The preparation of our consolidated financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to unbilled utility revenues, collectibility of accounts receivable, depreciable lives, asset impairment and goodwill evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation and tax provisions. Actual amounts could differ from those estimates.


RECENTLY ISSUED ACCOUNTING STANDARDS

        See Note 1 of "Notes to Consolidated Financial Statements" under Item 8 for further information regarding Recently Issued and Proposed Accounting Standards.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Our fuel procurement activities involve primary market risk exposures, including commodity price risk and credit risk. Commodity price risk is the potential adverse price impact related to the fuel procurement for our generating units. Credit risk is the potential adverse financial impact resulting from non-performance by a counterparty of its contractual obligations. Additionally, we are exposed to interest rate risk which is the potential adverse financial impact related to changes in interest rates.

        Market Risk and Hedging Activities.    Prices in the wholesale power markets can be extremely volatile. This volatility impacts our cost of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would attempt to purchase power from others. Such supplies are not always available. In addition, congestion on the transmission system can limit our ability to make purchases from (or sell into) the wholesale markets.

        We engage in physical and financial trading activities with the goals of reducing risk from market fluctuations. In accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions, we attempt to mitigate our commodity market risk. Derivatives are utilized to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 14 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        Commodity Price Risk.    We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations, including utilizing derivatives.

        We satisfied 65.6% of our 2012 generation fuel supply need through coal. This includes the remaining coal used at Riverton as part of its transition to natural gas. Approximately 96% of our 2012 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2015. These contracts satisfy approximately 100% of our anticipated fuel requirements for 2013, 58% for 2014 and 26% for 2015 for our Asbury coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

        We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of December 31, 2012, 58%, or 5.7 million Dths's, of our anticipated volume of natural gas usage for our electric operations for 2013 is hedged. See Note 14 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        Based on our expected natural gas purchases for our electric operations for 2013, if average natural gas prices should increase 10% more in 2013 than the price at December 31, 2012, our natural gas expenditures would increase by approximately $1.2 million based on our December 31, 2012 total hedged positions for the next twelve months. However, such an increase would be probable of recovery through fuel adjustment mechanisms in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs.

        We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of December 31, 2012, we have 1.3 million Dths in storage on the three pipelines that serve our customers. This represents 65% of our storage capacity. We have an additional 0.4 million Dths hedged through financial derivatives and physical contracts.

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        The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of December 31, 2012 (in thousands). However, due to purchased natural gas cost recovery mechanisms for our retail customers, fluctuations in the cost of natural gas have little effect on income.

Season
  Minimum %
Hedged
  Dth Hedged
Financial
  Dth Hedged
Physical
  Dth in Storage   Actual % Hedged  

Current

  50%     170,000     206,429     1,308,874     80 %

Second

  Up to 50%     160,000             2 %

Third

  Up to 20%                    

        Credit Risk.    In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. See Note 14 of "Notes to Consolidated Financial Statements" under Item 8 regarding agreements containing credit risk contingent features. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at December 31, 2012 and December 31, 2011. There were no margin deposit liabilities at these dates.

(in millions)
  2012   2011  

Margin deposit assets

  $ 4.2   $ 5.8  

        Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at December 31, 2012, reflecting that our counterparties are exposed to Empire for the net unrealized mark-to-market losses for physical forward and financial natural gas contracts carried at fair value.

(in millions)
   
 

Net unrealized mark-to-market losses for physical forward natural gas contracts

  $ 6.9  

Net unrealized mark-to-market losses for financial natural gas contracts

    7.0  
       

Net credit exposure

  $ 13.9  

        The $7.0 million net unrealized mark-to-market loss for financial natural gas contracts is comprised entirely of $7.0 million of exposure to counterparties of Empire for unrealized losses. We are holding no collateral from any counterparty since we are below the $10 million mark-to-market collateral threshold in our agreements. As noted above, as of December 31, 2012, we have $4.2 million on deposit for NYMEX contract exposure to Empire, of which $3.9 million represents our collateral requirement. If NYMEX gas prices decreased 25% from their December 31, 2012 levels, our collateral requirement would increase $7.2 million. If these prices increased 25%, our collateral requirement would decrease $2.7 million. Our other counterparties would not be required to post collateral with Empire.

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        We sell electricity and gas and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for purchases of energy-related commodities, including natural gas in our fuel procurement process.

        Interest Rate Risk.    We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit agreement) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates. See Notes 6 and 7 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        If market interest rates average 1% more in 2013 than in 2012, our interest expense would increase, and income before taxes would decrease by less than $0.6 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2012. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
of the Empire District Electric Company:

        In our opinion, the consolidated financial statements listed in the index appearing under Item 15 present fairly, in all material respects, the financial position of The Empire District Electric Company and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

        A company's internal control over financial reporting is a process designed 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP
St. Louis, Missouri
February 22, 2013

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

 
  December 31,  
 
  2012   2011  
 
  ($-000's)
 

Assets

             

Plant and property, at original cost:

             

Electric and water

  $ 2,176,188   $ 2,074,748  

Natural gas

    69,851     66,918  

Other

    37,983     34,984  

Construction work in progress

    56,347     24,141  
           

    2,340,369     2,200,791  

Accumulated depreciation and amortization

    682,737     637,139  
           

    1,657,632     1,563,652  
           

Current assets:

             

Cash and cash equivalents

    3,375     5,408  

Restricted cash

    4,357     4,357  

Accounts receivable — trade, net of allowance of $1,388 and $1,138, respectively

    38,874     42,296  

Accrued unbilled revenues

    23,254     20,326  

Accounts receivable — other

    13,277     16,269  

Fuel, materials and supplies

    61,870     62,239  

Prepaid expenses and other

    21,806     14,629  

Unrealized gain in fair value of derivative contracts

    96      

Regulatory assets

    6,377     11,839  
           

    173,286     177,363  
           

Noncurrent assets and deferred charges:

             

Regulatory assets

    243,958     227,807  

Goodwill

    39,492     39,492  

Unamortized debt issuance costs

    7,606     9,331  

Unrealized gain in fair value of derivative contracts

    191     2  

Other

    4,204     4,188  
           

    295,451     280,820  
           

Total assets

  $ 2,126,369   $ 2,021,835  
           

(Continued)

   

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

 
  December 31,  
 
  2012   2011  
 
  ($-000's)
 

Capitalization and liabilities

             

Common stock, $1 par value, 100,000,000 shares authorized, 42,484,363 and 41,977,725 shares issued and outstanding, respectively

 
$

42,484
 
$

41,978
 

Capital in excess of par value

    628,199     618,304  

Retained earnings

    47,115     33,707  
           

Total common stockholders' equity

    717,798     693,989  
           

Long-term debt (net of current portion)

             

Obligations under capital lease

    4,441     4,739  

First mortgage bonds and secured debt

    487,541     487,948  

Unsecured debt

    199,644     199,572  
           

Total long-term debt

    691,626     692,259  
           

Total long-term debt and common stockholders' equity

    1,409,424     1,386,248  
           

Current liabilities:

             

Accounts payable and accrued liabilities

    66,559     59,307  

Current maturities of long-term debt

    714     933  

Short-term debt

    24,000     12,000  

Regulatory liabilities

    3,089     3,150  

Customer deposits

    12,001     11,428  

Interest accrued

    5,902     5,958  

Unrealized loss in fair value of derivative contracts

    3,403     4,769  

Taxes accrued

    2,992     2,634  
           

    118,660     100,179  
           

Commitments and contingencies (Note 11)

             

Noncurrent liabilities and deferred credits:

             

Regulatory liabilities

    134,269     125,290  

Deferred income taxes

    301,967     263,933  

Unamortized investment tax credits

    18,897     19,226  

Pension and other postretirement benefit obligations

    120,808     103,371  

Unrealized loss in fair value of derivative contracts

    3,819     5,081  

Other

    18,525     18,507  
           

    598,285     535,408  
           

Total capitalization and liabilities

  $ 2,126,369   $ 2,021,835  
           

   

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

 
  Year Ended December 31,  
 
  2012   2011   2010  
 
  (000's, except per share amounts)
 

Operating revenues:

                   

Electric

  $ 510,653   $ 524,275   $ 484,715  

Gas

    39,849     46,430     50,885  

Other

    6,595     6,165     5,676  
               

    557,097     576,870     541,276  
               

Operating revenue deductions:

                   

Fuel and purchased power

    178,896     200,256     199,299  

Cost of natural gas sold and transported

    18,633     22,760     26,614  

Regulated operating expenses

    94,371     85,442     79,292  

Other operating expenses

    2,730     2,098     1,950  

Maintenance and repairs

    40,444     41,041     36,771  

Loss on plant disallowance

        150      

Depreciation and amortization

    60,447     63,537     58,656  

Provision for income taxes

    34,096     34,071     30,470  

Other taxes

    31,259     30,581     27,729  
               

    460,876     479,936     460,781  
               

Operating income

   
96,221
   
96,934
   
80,495
 

Other income and (deductions):

                   

Allowance for equity funds used during construction

    1,147     294     4,538  

Interest income

    972     555     176  

Provision for other income taxes

    (63 )   (227 )   (63 )

Other — non-operating expense, net

    (1,910 )   (1,283 )   (1,039 )
               

    146     (661 )   3,612  
               

Interest charges:

                   

Long-term debt

    40,192     42,581     41,959  

Trust preferred securities

            2,090  

Short-term debt

    187     86     631  

Allowance for borrowed funds used during construction

    (781 )   (218 )   (5,636 )

Other

    1,088     (1,147 )   (2,333 )
               

    40,686     41,302     36,711  
               

Net income

 
$

55,681
 
$

54,971
 
$

47,396
 
               

Weighted average number of common shares outstanding — basic

    42,257     41,852     40,545  
               

Weighted average number of common shares outstanding — diluted

    42,284     41,887     40,580  
               

Total earnings per weighted average share of common stock — basic and diluted

  $ 1.32   $ 1.31   $ 1.17  
               

Dividends declared per share of common stock

  $ 1.00   $ 0.64   $ 1.28  
               

   

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
  Year Ended December 31,  
 
  2012   2011   2010  
 
  ($-000's)
 

Net income

  $ 55,681   $ 54,971   $ 47,396  
               

Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability

            5,814  

Net change in fair market value of open derivative contracts for period

   
   
   
(6,362

)

Income taxes

   
   
   
209
 
               

Comprehensive income

  $ 55,681   $ 54,971   $ 47,057  
               

   

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

 
  Common
Stock
  Capital in
excess of Par
  Retained
earnings
  Accumulated
comprehensive
income/(loss)
  Total  
 
  ($-000's)
 

Balance at December 31, 2009

    38,112     551,631     10,068     339     600,150  

Net income

                47,396           47,396  

Stock/stock units issued through:

                               

Public offering

    2,871     48,325                 51,196  

Stock purchase and reinvestment plans

    594     10,623                 11,217  

Dividends declared

                (51,996 )         (51,996 )

Reclassification adjustment for losses included in net income

                      5,814     5,814  

Change in fair value of open derivative contracts for period

                      (6,362 )   (6,362 )

Income taxes

                      209     209  
                       

Balance at December 31, 2010

    41,577     610,579     5,468         657,624  

Net income

                54,971           54,971  

Stock/stock units issued through:

                               

Public offering

                               

Stock purchase and reinvestment plans

    401     7,725                 8,126  

Dividends declared

                (26,732 )         (26,732 )
                       

Balance at December 31, 2011

    41,978     618,304     33,707         693,989  

Net income

                55,681           55,681  

Stock/stock units issued through:

                               

Public offering

                               

Stock purchase and reinvestment plans

    506     9,895                 10,401  

Dividends declared

                (42,273 )         (42,273 )
                       

Balance at December 31, 2012

  $ 42,484   $ 628,199   $ 47,115   $  —   $ 717,798  
                       

   

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

 
  Year Ended December 31,  
 
  2012   2011   2010  
 
  ($-000's)
 

Operating activities: