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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, 2013

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, 2013, was approximately $955,552,315.

         As of February 3, 2014, 43,093,133 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 May 1, 2014
  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

  7

 

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

  30

 

Rate Matters

  38

 

Markets and Transmission

  39

 

Liquidity and Capital Resources

  39

 

Contractual Obligations

  44

 

Dividends

  45

 

Off-Balance Sheet Arrangements

  46

 

Critical Accounting Policies

  46

 

Recently Issued Accounting Standards

  49

ITEM 7A

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  50

ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  53

ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

  117

ITEM 9A.

 

CONTROLS AND PROCEDURES

  117

ITEM 9B.

 

OTHER INFORMATION

  117

PART III

ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

  118

ITEM 11.

 

EXECUTIVE COMPENSATION

  118

ITEM 12.

 

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

  118

ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

  118

ITEM 14.

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES

  118

PART IV

ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

  119

 

SIGNATURES

  125

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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, 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 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 and fuel and purchased power costs, including any regulatory disallowances that could result from prudency reviews;

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

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

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

    costs and activities associated with markets and transmission, including the Southwest Power Pool (SPP) Energy Imbalance Services Market, SPP regional transmission organization (RTO) transmission development, and SPP Day-Ahead Market;

    the impact of energy efficiency and alternative energy sources;

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

    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;

    volatility in the credit, equity and other financial markets and the resulting impact on 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;

    our exposure to the credit risk of our hedging counterparties;

    performance of acquired businesses;

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    the cost and availability of purchased power and fuel, including costs and activities associated with the transition to the SPP Day-Ahead Market, 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;

    changes in accounting requirements;

    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 I

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 2013 were derived as follows:

Electric segment sales*

    90.3 %

Gas segment sales

    8.4  

Other segment sales

    1.3  

*
Sales from our electric segment include 0.4% 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, 2013, our electric operations served approximately 168,800 customers.

        Our retail electric revenues for 2013 by jurisdiction were derived as follows:

Missouri

    89.8 %

Kansas

    4.8  

Arkansas

    2.5  

Oklahoma

    2.9  

        We supply electric service at retail to 119 incorporated communities as of December 31, 2013, 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 49% of our electric operating revenues in 2013 were derived from incorporated communities with franchises having at least ten years remaining and approximately 21% 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 42.6%, 30.4%, and 15.1%, respectively, of our electric operating revenues in 2013.

        Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2013 accounted for approximately 2.7% of electric revenues. No single retail customer accounted for more than 1.6% of electric revenues in 2013.

        Our gas operations serve customers in northwest, north central and west central Missouri. As of December 31, 2013, our gas operations served approximately 44,000 customers. We provide natural gas distribution to 48 communities and 377 transportation customers as of December 31, 2013. 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. Eighteen of the

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franchises have 10 years or more remaining on their term and 26 of the franchises have less than 10 years 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 2013 were derived as follows:

Residential

    63.1 %

Commercial

    27.3  

Industrial

    1.0  

Miscellaneous

    8.6  

        No single retail customer accounted for more than 1% of gas revenues in 2013.

        Our other segment consists of our fiber optics business. As of December 31, 2013, we have 118 fiber customers.


Electric Generating Facilities and Capacity

        At December 31, 2013, our generating plants consisted of:

Plant
  Capacity
(megawatts)(1)
  Primary Fuel

Asbury

    189 (2) Coal

Riverton — Natural Gas

    279   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

    1,377    
         
         

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

(2)
Does not include Asbury unit 2 (14 megawatts) which was retired at the end of 2013.

(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 — Markets and Transmission."

        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.

        We have a long-term (30 year) agreement for the purchase of 50 megawatts of capacity from the Plum Point Energy Station (Plum Point), a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We began receiving purchased power under this agreement on September 1, 2010. We also own, through

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an undivided interest, 50 megawatts of the unit's capacity. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the Missouri Public Service Commission (MPSC) in mid-2013. While it is not currently our intention to exercise this option in 2015, we will continue to evaluate this purchase option through the exercise date as well as explore other options with the purchase power agreement holder, Plum Point Energy Associates (PPEA), related to this option.

        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, 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
 

2014

    62     1377     1439 (2)

2015

    62     1381     1443 (3)

2016

    62     1384     1446 (4)

2017

    62     1384     1446  

2018

    62     1384     1446  

(1)
Includes 7 megawatts for the Elk River Windfarm, LLC and 5 megawatts for the Cloud County Windfarm, LLC.

(2)
Reflects the retirement of Asbury Unit 2.

(3)
Reflects the Asbury turbine retrofit and added pollution control equipment.

(4)
Reflects the retirement of Riverton Units 7, 8 and 9 and conversion of Riverton Unit 12 to a combined cycle.

        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.


Gas Facilities

        At December 31, 2013, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,160 miles of distribution mains.

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        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.


Construction Program

        Total property additions (including construction work in progress but excluding AFUDC) for the three years ended December 31, 2013, totaled $397.7 million and retirements during the same period totaled $39.3 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 $155.4 million in 2013 and for the next three years are estimated for planning purposes to be as follows:

 
  Estimated Capital Expenditures
(amounts in millions)
 
 
  2014   2015   2016   Total  

New electric generating facilities:

                         

Riverton Unit 12 combined cycle conversion

  $ 79.9   $ 62.5   $ 16.1   $ 158.5  

Additions to existing electric generating facilities:

                         

Asbury

    16.1     3.4     8.9     28.4  

Environmental upgrades — Asbury

    24.2     12.4         36.6  

Other

    9.9     12.9     8.0     30.8  

Electric transmission facilities

    25.9     29.3     27.5     82.7  

Electric distribution system additions

    36.9     39.9     36.6     113.4  

General and other additions

    11.3     9.3     6.7     27.3  

Gas system additions

    7.7     4.1     4.0     15.8  

Non-regulated additions

    1.8     2.1     2.3     6.2  
                   

TOTAL

  $ 213.7   $ 175.9   $ 110.1   $ 499.7  
                   
                   

        Our estimated total capital expenditures (excluding AFUDC) for 2017 and 2018 are $99.2 million and $95.9 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 beyond routine capital expenditures.

        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 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 — Markets and Transmission."

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Fuel and Natural Gas Supply

Electric Segment

        Our total system output for 2013 and 2012, based on kilowatt-hours generated, was as follows:

 
  2013   2012  

Steam generation units — coal

    47.0 %   48.0 %

Steam generation units — natural gas

    0.0     0.2  

Combustion turbine generation units — natural gas

    24.3     24.9  

Hydro generation

    1.0     1.0  

Purchased power — windfarms

    14.8     15.0  

Purchased power — other

    12.9     10.9  

        Below are the total fuel requirements for our generating units in 2013 and 2012 (based on kilowatt-hours generated):

 
  2013   2012  

Coal

    65.9 %   65.6 %

Natural gas

    34.0     34.3  

Fuel oil

    0.1     0.1  

        Our Asbury Plant is fueled primarily by coal with oil being used as start-up fuel. In 2013, Asbury burned a coal blend consisting of approximately 92.4% Western coal (Powder River Basin) and 7.6% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2013, we had sufficient coal on hand to supply full load requirements at Asbury for 38-59 days, as compared to 102-107 days as of December 31, 2012, depending on the actual blend ratio. The inventory decreased during 2013 as Asbury readjusted back to target levels following the 2012 transition of Riverton Units 7 and 8 to natural gas.

        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  

2014

    97 %

2015

    39 %

2016

    19 %

        All of the Western coal used at our Asbury plant is shipped by rail, a distance of approximately 800 miles. We have a coal transportation agreement with the Burlington Northern and Santa Fe Railway Company (BNSF) and the Kansas City Southern Railway Company which runs 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 70% of Iatan's requirements for 2014 and approximately 30% for 2015 and 15% for 2016. Coal is transported to Iatan by rail. In 2013, KCP&L and KCP&L Greater Missouri Operations entered into agreements with the railroads for transportation services through December 31, 2018.

        The Plum Point Energy Station is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the plant's capacity. North America

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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 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 and another 15-year lease agreement, expiring in 2025, for an additional 54 railcars associated with our Plum Point purchased power agreement.

        Since its transition from coal in 2012, our Riverton Plant is fueled primarily by natural gas with oil available as backup for Units 9, 10 and 11. Units 7 and 8, along with Unit 12, are fueled 100% by natural gas. Based on kilowatt hours generated during 2013, Riverton's generation was 100% natural gas.

        Our Energy Center and State Line Unit No.1 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 2013, 100% of the Energy Center generation was produced from natural gas and 89% of the State Line Unit 1 generation came from natural gas with the remainder being fuel oil. As of December 31, 2013, 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.

        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.

        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.

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        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
  2013   2012   2011  

Coal — Iatan

  $ 1.756   $ 1.760   $ 1.603  

Coal — Asbury

    2.432     2.395     2.315  

Coal — Riverton(1)

    0.000     2.541     2.314  

Coal — Plum Point

    2.123     1.804     1.858  

Natural Gas

    4.952     4.493     5.475  

Oil

    21.870     20.291     21.304  
               

Weighted average cost of fuel burned per kilowatt-hour generated

  $ 2.8074   $ 2.6742   $ 2.9558  

(1)
Reflects the September 2012 transition of Riverton Units 7 and 8 from operation on coal to full operation on natural gas.

Gas Segment

        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   2013   2012   2011  

South

  Southern Star Central Gas Pipeline   $ 5.4998   $ 6.4329   $ 6.1619  

North

  Panhandle Eastern Pipe Line Company     5.9746     6.8990     6.1449  

Northwest

  ANR Pipeline Company     4.7589     5.0898     5.4230  

  Weighted average cost per mcf   $ 5.4949   $ 6.3305   $ 6.0542  


Employees

        At December 31, 2013, we had 751 full-time employees, including 50 employees of EDG. 328 of the EDE employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW). On December 10, 2013, the Local 1474 IBEW voted to ratify a new five-year agreement, effective December 2, 2013, which will extend through October 31, 2018. At December 31, 2013, 33 EDG employees were members of Local 1464 of the IBEW. In May 2013, Local 1464 of the IBEW ratified a four-year agreement with EDG, effective June 1, 2013.

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ELECTRIC OPERATING STATISTICS(1)

 
  2013   2012   2011   2010   2009  

Electric Operating Revenues (000's):

                               

Residential

  $ 227,656   $ 214,526   $ 221,687   $ 204,900   $ 180,404  

Commercial

    162,444     158,837     157,435     146,310     135,800  

Industrial

    80,497     78,786     78,925     69,684     65,983  

Public authorities(2)

    14,707     13,755     13,653     12,099     11,411  

Wholesale on-system

    20,036     18,555     19,140     19,254     18,199  

Miscellaneous(3)

    13,223     8,520     8,194     7,573     6,814  

Interdepartmental

    229     197     201     199     178  
                       

Total system

    518,792     493,176     499,235     460,019     418,789  

Wholesale off-system

    15,488     15,687     23,271     22,891     14,344  
                       

Total electric operating revenues(4)

    534,280     508,863     522,506     482,910     433,133  
                       
                       

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

                               

Steam

    2,813,441     2,865,037     2,805,744     2,650,042     2,259,304  

Hydro

    57,449     57,719     48,898     88,104     76,733  

Combustion turbine

    1,452,936     1,486,643     1,484,472     1,566,074     926,934  
                       

Total generated

    4,323,826     4,409,399     4,339,114     4,304,220     3,262,971  

Purchased

    1,660,193     1,545,327     1,870,901     2,085,550     2,516,702  
                       

Total generated and purchased

    5,984,019     5,954,726     6,210,015     6,389,770     5,779,673  

Interchange (net)

    432     (87 )   (1,298 )   (1,716 )   (568 )
                       

Total system output

    5,984,451     5,954,639     6,208,717     6,388,054     5,779,105  

Transmission by others losses(5)

    (15,817 )   (17,300 )   (16,597 )   (5,688 )    
                       

Total system input

    5,968,634     5,937,339     6,192,120     6,382,366     5,779,105  
                       
                       

Maximum hourly system demand (Kw)

    1,080,000     1,142,000     1,198,000     1,199,000     1,085,000  

Owned capacity (end of period) (Kw)

    1,377,000     1,391,000     1,392,000     1,409,000     1,257,000  

Annual load factor (%)

    56.18     52.17     51.95     53.17     55.38  
                       

Electric sales (000's of kWh):

                               

Residential

    1,936,603     1,850,813     1,982,704     2,060,368     1,866,473  

Commercial

    1,541,717     1,558,297     1,576,342     1,644,917     1,579,832  

Industrial

    1,015,492     1,028,416     1,022,765     1,007,033     992,165  

Public authorities(2)

    127,370     122,369     126,724     124,554     121,816  

Wholesale on-system

    343,045     353,075     364,866     355,807     332,061  
                       

Total system

    4,964,227     4,912,970     5,073,401     5,192,679     4,892,347  

Wholesale off-system

    653,996     704,028     740,009     798,084     515,899  
                       

Total Electric Sales

    5,618,223     5,616,998     5,813,410     5,990,763     5,408,246  
                       

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

    9,049     9,066     9,371     9,598     9,088  

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

    341,362     311,275     369,339     382,005     361,771  
                       

Total System Input

    5,968,634     5,937,339     6,192,120     6,382,366     5,779,105  
                       
                       

Customers (average number):

                               

Residential

    141,376     140,602     139,641     141,693     141,206  

Commercial

    24,080     24,036     24,155     24,505     24,412  

Industrial

    345     353     357     358     355  

Public authorities(2)

    2,214     2,124     2,021     2,003     1,995  

Wholesale on-system

    4     4     4     4     4  
                       

Total System

    168,019     167,119     166,178     168,563     167,972  

Wholesale off-system

    22     22     25     22     19  
                       

Total

    168,041     167,141     166,203     168,585     167,991  
                       
                       

Average annual sales per residential customer (kWh)

    13,698     13,163     14,199     14,541     13,218  

Average annual revenue per residential customer

  $ 1,610   $ 1,526   $ 1,588   $ 1,446   $ 1,278  

Average residential revenue per kWh

    11.76 ¢   11.59 ¢   11.18 ¢   9.94 ¢   9.67 ¢

Average commercial revenue per kWh

    10.54 ¢   10.19 ¢   9.99 ¢   8.89 ¢   8.60 ¢

Average industrial revenue per kWh

    7.93 ¢   7.66 ¢   7.72 ¢   6.92 ¢   6.65 ¢
                       
                       

(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)
2012 includes the effect of our unbilled revenue adjustment.

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GAS OPERATING STATISTICS(1)

 
  2013   2012   2011   2010   2009  

Gas Operating Revenues (000's):

                               

Residential

  $ 31,561   $ 24,744   $ 28,999   $ 32,245   $ 36,176  

Commercial

    13,673     10,797     12,506     13,336     15,552  

Industrial

    515     464     682     812     2,066  

Public authorities

    342     247     324     342     365  
                       

Total retail sales revenues

    46,091     36,252     42,511     46,735     54,159  

Miscellaneous(2)

    435     400     464     436     221  

Transportation revenues

    3,515     3,197     3,455     3,714     2,934  
                       

Total Gas Operating Revenues

    50,041     39,849     46,430     50,885     57,314  
                       
                       

Maximum Daily Flow (mcf)

    60,118     58,281     67,789     73,280     70,046  
                       
                       

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

                               

Residential

    2,744     2,012     2,560     2,675     2,687  

Commercial

    1,349     1,050     1,268     1,265     1,278  

Industrial

    72     58     102     108     218  

Public authorities

    35     23     33     33     30  
                       

Total retail sales

    4,200     3,143     3,963     4,081     4,213  

Transportation sales

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

Total gas operating and transportation sales

    8,728     7,392     8,491     8,910     8,543  
                       

Company use(3)

    2     2     4     4     3  

Transportation sales (cash outs)

                     

Mcf losses

    96     27     (47 )   70     36  
                       

Total system sales

    8,826     7,421     8,448     8,984     8,582  
                       
                       

Customers (average number):

                               

Residential

    37,777     37,897     38,051     38,277     38,621  

Commercial

    4,917     4,921     4,951     4,968     5,038  

Industrial

    24     23     26     26     25  

Public authorities

    140     138     136     137     131  
                       

Total retail customers

    42,858     42,979     43,164     43,408     43,815  

Transportation customers

    340     326     311     313     296  
                       

Total gas customers

    43,198     43,305     43,475     43,721     44,111  
                       
                       

(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, 2013, 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
12/31/13
  Positions With the Company   With the
Company
Since
  Officer
Since
 

Bradley P. Beecher

    48  

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

    58  

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

    2002     2005  

Ronald F. Gatz

    63  

Vice President and Chief Operating Officer — Gas (2006)

    2001     2001  

Blake Mertens

    36  

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(1)

    57  

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

    1986     2001  

Martin O. Penning

    58  

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

    1980     2011  

Kelly S. Walters

    48  

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

    2001     2006  

Janet S. Watson

    61  

Secretary — Treasurer (1995)

    1994     1995  

Robert W. Sager

    39  

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

    2006     2011  

(1)
Michael E. Palmer will retire from his position as Vice-President — Transmission Policy and Corporate Services effective March 31, 2014.


Regulation

Electric Segment

        General.    As a public utility, our electric segment operations are subject to the jurisdiction of the Missouri Public Service Commission (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 — Markets and Transmission."

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        Electric operating revenues received during 2013 were comprised of the following:

Retail customers

    90.9 %

Sales subject to FERC jurisdiction

    8.3  

Miscellaneous sources

    0.8  

        The percentage of retail regulated revenues derived from each state follows:

Missouri

    89.8 %

Kansas

    4.8  

Oklahoma

    2.9  

Arkansas

    2.5  

        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)

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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, 2013, would permit us to issue approximately $599.1 million of 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, 2013, we had retired bonds and net property additions which would enable the issuance of at least $856.7 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2013, 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, 2013, this test would allow us to issue approximately $15.8 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) 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. 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; inability to attract and retain management and other key personnel; 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, physical 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. The cost allocation methodology applied to these transmission infrastructure projects will increase our operating expenses.

        The SPP RTO expects to implement a Day-Ahead Market, or Integrated Marketplace, in March 2014. The SPP Integrated Marketplace will function as a centralized dispatch, where we and other members will submit offers to sell power and bids to purchase power. The SPP will match offers and bids to supply our and other members' next day generation needs. It is expected that 90% – 95% of all next day generation needed throughout the SPP territory will be cleared through this Integrated Marketplace. This change could impact our fuel costs, however, the net financial effect of these Integrated Marketplace transactions will be processed through our fuel adjustment mechanisms.

        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.

        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.


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

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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*   Baa1   BBB

EDE First Mortgage Bonds

  BBB+   A2   A-

Senior Notes

  BBB   Baa1   BBB

Commercial Paper

  F3   P-2   A-2

Outlook

  Stable   Stable   Stable

*
Not rated.

        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.

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The cost and schedule of construction projects may materially change.

        Our capital expenditure budget for the next three years is estimated to be $499.7 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.


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 $213.7 million in 2014. 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. Financial market disruptions can also cause reductions in investment value in our pension plan assets, which could lead to increased funding obligations. We expect to fund approximately $15.0 million during 2014 for pension and OPEB liabilities. Although positive asset performance in 2013 led to decreased liabilities in 2013, 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

        Our generating facilities consist of three coal-fired generating plants, two natural gas generating plants and one hydroelectric generating plant. At December 31, 2013, we owned generating facilities with an aggregate generating capacity of 1,377 megawatts. We retired the 14-megawatt Unit 2 at our Asbury Plant on December 31, 2013, as required by the addition of air quality control equipment being installed at our Asbury plant (discussed below) in order to comply with forthcoming environmental regulations.

        The Asbury Plant, located near Asbury, Missouri, is a coal-fired generating station. The plant consisted of two steam turbine generating units with 203 megawatts of generating capacity until the end of 2013 when we retired Unit 2. In 2013, the plant accounted for approximately 14% of our owned generating capacity and accounted for approximately 29.9% of the energy generated by us. As part of our environmental Compliance Plan, discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8, we are in the process of installing 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 in early 2015 and required the retirement of Asbury Unit 2 at the end of 2013, reducing the plant's capacity to 189 megawatts. This reduces our owned generating facilities aggregate generating capacity to 1,377 megawatts in 2014. 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

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power and fuel expenditures associated with replacement energy, which is likely to be recovered through our fuel adjustment clauses.

        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.

        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 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 mid-2016.

        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. We are the operator of the Combined Cycle Unit and Westar reimburses us for a percentage of the operating costs per our joint ownership agreement. 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 was 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 will 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 September 16, 2010, we received a $26.6 million payment from the SWPA, which was deferred and recorded as a noncurrent liability. The SWPA payment, net of taxes, is being used to reduce fuel expense for our customers in all our jurisdictions. It is our understanding that the lake level change for Bull Shoals was implemented in July of 2013.

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        At December 31, 2013, 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 6,882 miles of line at December 31, 2013 and December 31, 2012.

        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.

        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, 2013, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,160 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 3, 2014, there were 4,379 record holders and 28,500 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 2013 and 2012.

 
  High   Low   Close   Dividends Paid
Per Share
 

2013 Quarter Ended:

                         

March 31

  $ 22.41   $ 20.57   $ 22.40   $ 0.250  

June 30

    23.35     21.26     22.31     0.250  

September 30

    24.32     20.77     21.66     0.250  

December 31

    23.26     21.27     22.69     0.255  

2012 Quarter Ended:

   
 
   
 
   
 
   
 
 

March 31

  $ 21.34   $ 19.55   $ 20.35   $ 0.250  

June 30

    21.24     19.51     21.10     0.250  

September 30

    21.94     21.02     21.55     0.250  

December 31

    22.04     19.59     20.38     0.250  

        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 the fourth quarter of 2013, the Board of Directors increased the dividend by 2%, from $0.25 per share on common stock to $0.255 per share. In the first quarter of 2014, the Board of Directors declared a quarterly dividend of $0.255 per share on common stock payable on March 17, 2014 to holders of record as of March 3, 2014. As of December 31, 2013, our retained earnings balance was $67.6 million, compared to $47.1 million at December 31, 2012. 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 2013, 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 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.

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        The following graph and table indicates the value at the end of the specified years of a $100 investment made on December 31, 2008, 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
  12/31/2008   12/31/2009   12/31/2010   12/31/2011   12/31/2012   12/31/2013  

The Empire District Electric Company

  $ 100.00   $ 114.96   $ 145.53   $ 142.70   $ 144.79   $ 168.77  

S&P Electric Utilities Index

  $ 100.00   $ 103.38   $ 106.93   $ 129.35   $ 128.63   $ 138.66  

S&P 500 Index

  $ 100.00   $ 126.46   $ 145.51   $ 148.59   $ 172.37   $ 228.19  

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

 
  2013   2012   2011   2010   2009  

Operating revenues

  $ 594,330   $ 557,097   $ 576,870   $ 541,276   $ 497,168  

Operating income

  $ 99,663   $ 96,221   $ 96,934   $ 80,495   $ 74,495  

Total allowance for funds used during construction

  $ 5,940   $ 1,928   $ 512   $ 10,174   $ 14,133  

Net income

  $ 63,445   $ 55,681   $ 54,971   $ 47,396   $ 41,296  

Weighted average number of common shares outstanding — basic

   
42,781
   
42,257
   
41,852
   
40,545
   
34,924
 

Weighted average number of common shares outstanding — diluted

    42,803     42,284     41,887     40,580     34,956  

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

  $ 1.48   $ 1.32   $ 1.31   $ 1.17   $ 1.18  

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

  $ 1.48   $ 1.32   $ 1.31   $ 1.17   $ 1.18  

Cash dividends per share

  $ 1.005   $ 1.00   $ 0.64   $ 1.28   $ 1.28  

Common dividends paid as a percentage of net income

   
67.8

%
 
75.9

%
 
48.6

%
 
109.7

%
 
108.5

%

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

    9.4 %   3.5 %   0.9 %   21.5 %   34.2 %

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

 
$

17.43
 
$

16.90
 
$

16.53
 
$

15.82
 
$

15.75
 

Capitalization:

   
 
   
 
   
 
   
 
   
 
 

Common equity

  $ 750,124   $ 717,798   $ 693,989   $ 657,624   $ 600,150  

Long-term debt

  $ 743,428   $ 691,626   $ 692,259   $ 693,072   $ 640,156  

Ratio of earnings to fixed charges

    2.97X     2.89X     2.87X     2.63X     2.15X  

Total assets

  $ 2,145,045   $ 2,126,369   $ 2,021,835   $ 1,921,311   $ 1,839,846  

Plant in service at original cost

  $ 2,332,341   $ 2,284,022   $ 2,176,650   $ 2,108,115   $ 1,718,584  

Capital expenditures (including AFUDC)

  $ 160,196   $ 146,287   $ 101,177   $ 108,157   $ 148,804  

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 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

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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. We expect our electric customer and sales growth to be less than 1.0% annually over the next several years. Our electric customer growth for the year ended December 31, 2013 was 0.5%. We define electric sales growth to be growth in kWh sales period over period excluding the estimated 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, 2013 was 0.1%, 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.

Earnings

        For the year ended December 31, 2013, basic and diluted earnings per weighted average share of common stock were $1.48 on $63.4 million of net income compared to $1.32 on $55.7 million of net income for the year ended December 31, 2012. Increased electric gross margins (defined as electric revenues less fuel and purchased power costs) positively impacted net income for 2013 as compared to 2012, reflecting an increase in electric revenues of approximately $25.7 million, mainly due to increased electric rates for our Missouri customers effective April 1, 2013. Improved electric customer counts, favorable winter weather and increased AFUDC due to higher levels of construction activity during 2013 also positively

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impacted results. Increased regulatory operating expense and depreciation and amortization expense negatively impacted 2013 results.

        The table below sets forth a reconciliation of basic and diluted earnings per share between 2012 and 2013, 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, including segment revenues and operating expenses, on a per share basis before the impact of additional stock issuances. The dilutive effect of additional shares issued included in the table reflects the estimated impact of all shares issued during the period.

        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 the previous year's EPS. 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.

        In addition, although a non-GAAP presentation, we believe the presentation of gross margin (in the table below and elsewhere in this report) 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. This reconciliation and margin information may not be comparable to other companies' presentations or more useful than the GAAP presentation included in the statements of income or elsewhere in this report. 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.

Earnings Per Share — 2012

  $ 1.32  

Revenues

   
 
 

Electric segment

    0.38  

Gas segment

    0.15  

Other segment

    0.02  
       

Total Revenue

    0.55  

Electric fuel and purchased power

    0.05  

Cost of natural gas sold and transported

    (0.11 )
       

Gross Margin

    0.49  

Operating — electric segment

   
(0.15

)

Operating — gas segment

    (0.01 )

Operating — other segment

    (0.01 )

Maintenance and repairs

    (0.01 )

Depreciation and amortization

    (0.13 )

Loss on plant disallowance

    (0.03 )

Other taxes

    (0.05 )

AFUDC

    0.06  

Change in effective income tax rates

    0.02  

Other income and deductions

    (0.02 )
       

Earnings Per Share — 2013

  $ 1.48  
       
       

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Fourth Quarter Results

        Earnings for the fourth quarter of 2013 were $15.2 million, or $0.35 per share, as compared to $9.6 million, or $0.23 per share, in the fourth quarter of 2012. Electric segment gross margins increased during the quarter ending December 31, 2013 compared to the 2012 quarter, reflecting the impact of colder weather experienced during the fourth quarter of 2013 as compared to the same period in 2012 and the April 2013 Missouri electric rate increase, partially offset by increased electric operating and maintenance expenses.


2013 Activities

Regulatory Matters

        On December 3, 2013, we filed a request with the Arkansas Public Service Commission for changes in rates for our Arkansas electric customers. We are seeking an annual increase in total revenue of approximately $2.2 million, or approximately 18%. The rate increase was requested to recover costs incurred to ensure continued reliable service for our customers, including capital investments, operating systems replacement costs and ongoing increases in other operation and maintenance expenses and capital costs.

        On February 22, 2013, we filed a Nonunanimous Stipulation and Agreement (Agreement) with the Missouri Public Service Commission (MPSC) which issued an order approving the Agreement on February 27, 2013, effective March 6, 2013. The Agreement provided for an annual increase in base revenues for our Missouri electric customers in the amount of approximately $27.5 million, effective April 1, 2013, and the continuation of the current fuel adjustment mechanism.

        On May 18, 2012, we filed a request with the Federal Energy Regulatory Commission (FERC) to implement a cost-based transmission formula rate (TFR). On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement includes a TFR that establishes an ROE of 10.0%. The FERC conditionally approved the Agreement on November 18, 2013, and we made a compliance filing with the FERC on December 18, 2013 in connection with this conditional approval. Final FERC action on our compliance filing is pending.

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

Integrated Resource Plan

        We filed our Integrated Resource Plan (IRP) with the MPSC on July 1, 2013. The IRP analysis of future loads and resources is normally conducted once every three years. Our IRP supports our Compliance Plan discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8.

        As part of our IRP, we agreed to introduce additional demand-side management programs to help our customers use energy more efficiently. On October 30, 2013 we filed a request with the MPSC to implement a portfolio of demand-side management programs under the Missouri Energy Efficiency Investment Act (MEEIA). The request, subject to regulatory approval, would implement new energy efficiency programs for customers in 2014. The request also includes a Demand-Side Program Investment Mechanism (DSIM) that would be added to monthly customer bills if approved by the MPSC. The DSIM charge is designed to offset the financial costs associated with the programs. On January 14, 2014, the MPSC granted a motion to suspend the procedural schedule to allow the parties to the case more time to hold additional technical conferences and perform additional financial analysis on our proposed demand-side management portfolio.

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Financings

        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 May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. The delayed settlement of both series of bonds occurred on May 30, 2013. Interest is payable semi-annually on the bonds on each May 30 and November 30, commencing November 30, 2013.

        A portion of the proceeds from the above sale of bonds was used to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013. The remaining proceeds were used for general corporate purposes.

        For additional information, see Note 6 of "Notes to Consolidated Financial Statements" under Item 8.


RESULTS OF OPERATIONS

        The following discussion analyzes significant changes in the results of operations for the years 2013, 2012 and 2011.

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

 
  2013   2012   2011  

Electric

  $ 58.6   $ 52.6   $ 50.6  

Gas

    2.3     1.3     2.7  

Other

    2.5     1.8     1.6  
               

Net income

  $ 63.4   $ 55.7   $ 54.9  
               
               

Electric Segment

Overview

        Our electric segment income for 2013 was $58.6 million as compared to $52.6 million and $50.6 million for 2012 and 2011, respectively.

        Electric operating revenues comprised approximately 89.9% of our total operating revenues during 2013. Electric operating revenues for 2013, 2012, and 2011 were comprised of the following:

 
  2013   2012   2011  

Residential

    42.6 %   42.2 %   42.4 %

Commercial

    30.4     31.2     30.1  

Industrial

    15.1     15.5     15.1  

Wholesale on-system

    3.7     3.6     3.7  

Wholesale off-system

    2.9     3.1     4.5  

Miscellaneous sources*

    2.8     2.7     2.6  

Other electric revenues

    2.5     1.7     1.6  

*
Primarily other public authorities

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Gross Margin

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

 
  2013   2012   2011  

Electric segment revenues

  $ 536.4   $ 510.7   $ 524.3  

Fuel and purchased power

    175.4     178.9     200.3  
               

Electric segment gross margins

  $ 361.0   $ 331.8   $ 324.0  
               
               

Margin as % of total electric segment revenues

    67.3 %   65.0 %   61.8 %

        As shown in the table above, electric segment gross margin, defined as electric revenues less fuel and purchased power costs, increased approximately $29.2 million during 2013 as compared to 2012. Increased electric rates for our Missouri customers, an increase in average electric customer counts and colder weather in the first and fourth quarters of 2013 positively impacted revenues and gross margin during 2013. These increases were partially offset by a change in our unbilled revenue estimate in the third quarter of 2012.

        The electric gross margin increased approximately $7.8 million during 2012 as 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 in 2011, 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. The 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 2011.


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
  2013   2012   % Change(1)   2012   2011   % Change(1)  

Residential

    1,936.6     1,850.8     4.6 %   1,850.8     1,982.7     (6.7 )%

Commercial

    1,541.7     1,558.3     (1.1 )   1,558.3     1,576.3     (1.1 )

Industrial

    1,015.5     1,028.4     (1.3 )   1,028.4     1,022.8     0.6  

Wholesale on-system

    343.1     353.1     (2.8 )   353.1     364.9     (3.2 )

Other(2)

    129.4     124.2     4.2     124.2     128.7     (3.5 )
                               

Total on-system sales

    4,966.3     4,914.8     1.0     4,914.8     5,075.4     (3.2 )

Off-system

    654.0     704.0     (7.1 )   704.0     740.0     (4.9 )
                               

Total KWh Sales

    5,620.3     5,618.8     0.0     5,618.8     5,815.4     (3.4 )

(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 increased slightly during 2013 as compared to 2012 primarily due to increased demand due to colder temperatures in the first and fourth quarters of 2013 as compared to the same periods in 2012. Residential kWh sales, the most weather sensitive class, increased 4.6% primarily due to these weather impacts and an increase in the average residential customer count.

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Commercial sales decreased 1.1% primarily due to a net unbilled sales adjustment recorded in 2012. Industrial sales decreased 1.3% during 2013 as compared to 2012 due to operating reductions by several large industrial customers. On-system wholesale kWh sales decreased during 2013 as compared to 2012 reflecting the closure of a large dairy facility in Monett, Missouri. 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 2013 were 31.7% more than 2012 and 5.0% more than the 30-year average. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65° F) for 2013 were 19.7% less than 2012 although they were 2.1% more than the 30-year average. The weather was unseasonably hot in June and July of 2012.

        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 winter 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.

        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
  2013   2012   % Change(1)   2012   2011   % Change(1)  

Residential

  $ 227.7   $ 214.5     6.1 % $ 214.5   $ 221.7     (3.2 )%

Commercial

    162.4     158.8     2.3     158.8     157.4     0.9  

Industrial

    80.5     78.8     2.2     78.8     78.9     (0.2 )

Wholesale on-system

    20.0     18.6     8.0     18.6     19.1     (3.1 )

Other(2)

    15.0     14.0     7.0     14.0     13.9     0.7  
                               

Total on-system revenues

    505.6     484.7     4.3     484.7     491.0     (1.3 )

Off-system

    15.5     15.7     (1.3 )   15.7     23.3     (32.6 )
                               

Total revenues from KWh sales

    521.1     500.4     4.1     500.4     514.3     (2.7 )

Miscellaneous revenues(3)

    13.2     8.5     55.2     8.5     8.2     4.0  
                               

Total electric operating revenues

  $ 534.3   $ 508.9     5.0   $ 508.9   $ 522.5     (2.6 )

Water revenues

    2.1     1.8     19.2     1.8     1.8     1.2  
                               

Total Electric Segment Operating Revenues

  $ 536.4   $ 510.7     5.0   $ 510.7   $ 524.3     (2.6 )

(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 increased approximately $20.9 million (4.3%) during 2013 as compared to 2012. Rate changes, primarily the April 2013 Missouri rate increase, contributed an estimated $24.6 million to revenues. Weather and other related factors increased revenues an estimated $3.1 million in 2013 as compared to 2012. Improved customer counts increased revenues an estimated $2.7 million. These revenue increases were partially offset by a $6.1 million decrease in fuel recovery revenue (and corresponding reduction in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during 2013 as compared to 2012. The change in our unbilled revenue estimate recorded in the third quarter of 2012, as mentioned below, negatively impacted revenues as compared to 2012, making up the remainder of the change.

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        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 in 2011. 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 $3.4 million period over period change in our estimate of unbilled revenues during the third quarter of 2012 contributed $3.0 million to revenues.

        On-system revenues increased in all classes during 2013 primarily due to the April 2013 Missouri rate increase.

        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.


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 "— Markets and Transmission" 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 our on-system customers and has little effect on net income.

        Off-system sales and revenues decreased during 2013 as compared to 2012 mainly due to low third quarter demand in the SPP market.

        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.


Miscellaneous Revenues

        Our miscellaneous revenues increased approximately $4.7 million during 2013 as compared to 2012 and approximately $0.3 million in 2012 as compared to 2011, primarily due to increased Southwest Power Pool (SPP) transmission revenues. These miscellaneous revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

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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 2013, 2012 and 2011.

(in millions)
  2013   2012   2011  

Actual fuel and purchased power expenditures

  $ 182.1   $ 173.6   $ 196.5  

Missouri fuel adjustment recovery(1)

    (2.7 )   3.4     7.3  

Missouri fuel adjustment deferral(2)

    (0.6 )   5.3     (2.7 )

Kansas and Oklahoma regulatory adjustments(2)

    (0.3 )   1.0     (0.6 )

SWPA amortization(3)

    (2.8 )   (2.8 )   (1.5 )

Unrealized (gain)/loss on derivatives

    (0.3 )   (1.6 )   1.3  
               

Total fuel and purchased power expense per income statement

  $ 175.4   $ 178.9   $ 200.3  
               
               

(1)
A positive amount indicates costs recovered from customers from under recovery in prior deferral periods. A negative amount indicates costs refunded to customers from over recovery in prior deferral periods.

(2)
A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.

(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 increases/(decreases) during 2013 as compared to 2012 and during 2012 as compared to 2011.

(in millions)
  2013 vs. 2012   2012 vs. 2011  

Transmission and distribution expense(1)

  $ 4.8   $ 1.7  

General labor expense

    2.0     0.4  

Regulatory reversal of gain on prior period sale of assets(2)

    1.2     0.0  

Customer accounts expense

    0.9     (0.5 )

Steam power other operating expense

    0.6     2.0  

Regulatory commission expense

    0.5     (0.5 )

Other power supply expense

    0.7     0.1  

Employee pension expense

    0.5     1.4  

Employee health care expense

    0.2     2.4  

Property insurance

    0.5     0.6  

Customer assistance expense

    0.4     0.0  

Injuries and damages expense

    0.0     (0.7 )

Professional services

    (0.5 )   2.1  

Banking fees

    (0.7 )   (0.6 )

Other miscellaneous accounts (netted)

    0.0     0.4  
           

TOTAL

  $ 11.1   $ 8.8  
           
           

(1)
Mainly due to increased SPP transmission charges.

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(2)
Regulatory reversal of a prior period gain on the sale of our Asbury unit train as part of our 2013 rate case Agreement with the MPSC.

        The table below shows maintenance and repairs expense increases/(decreases) during 2013 as compared to 2012 and during 2012 as compared to 2011.

(in millions)
  2013 vs. 2012   2012 vs. 2011  

Distribution maintenance expense

  $ 0.4   $ (1.1 )

Transmission maintenance expense

    0.7     (0.3 )

Maintenance and repairs expense at the Asbury plant

    (0.9 )   0.9  

Maintenance and repairs expense to SLCC

    (1.1 )   0.6  

Maintenance and repairs expense at the State Line plant

    0.5     (0.2 )

Maintenance and repairs expense at the Iatan plant

    0.4     (0.8 )

Maintenance and repairs expense at the Plum Point plant

    0.4     (0.1 )

Maintenance and repairs expense at the Riverton plant — steam

    (0.2 )   (0.1 )

Maintenance and repairs expense at the Riverton plant — gas

    (0.5 )   0.5  

Iatan deferred maintenance expense

    0.5     (0.1 )

Other miscellaneous accounts (netted)

    0.2     0.1  
           

TOTAL

  $ 0.4   $ (0.6 )
           
           

        Depreciation and amortization expense increased approximately $8.3 million (15.1%) during 2013 as compared to 2012, primarily due to increased depreciation rates resulting from our recent Missouri rate case settlement and increased plant in service.

        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.

        Other taxes increased approximately $3.3 million in 2013 and $0.9 million in 2012 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)
  2013   2012   % Change   2012   2011   % Change  

Residential

    2.74     2.01     36.4 %   2.01     2.56     (21.4 )%

Commercial

    1.35     1.05     28.5     1.05     1.27     (17.2 )

Industrial

    0.07     0.06     23.9     0.06     0.10     (42.9 )

Other(1)

    0.04     0.02     44.8     0.02     0.03     (29.5 )
                               

Total retail sales

    4.20     3.14     33.6     3.14     3.96     (20.7 )

Transportation sales(1)

    4.53     4.25     6.6     4.25     4.53     (6.2 )
                               

Total gas operating sales

    8.73     7.39     18.1     7.39     8.49     (13.0 )

(1)
Other includes other public authorities and interdepartmental usage.

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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)
  2013   2012   % Change   2012   2011   % Change  

Residential

  $ 31.6   $ 24.7     27.6 % $ 24.7   $ 29.0     (14.7 )%

Commercial

    13.7     10.8     26.6     10.8     12.5     (13.7 )

Industrial

    0.5     0.5     11.0     0.5     0.7     (31.9 )

Other(1)

    0.3     0.3     38.7     0.3     0.3     (23.9 )
                               

Total retail revenues

  $ 46.1   $ 36.3     27.1   $ 36.3   $ 42.5     (14.7 )

Other revenues

    0.4     0.3     7.5     0.3     0.4     (13.4 )

Transportation revenues(1)

    3.5     3.2     10.0     3.2     3.5     (7.5 )
                               

Total gas operating revenues

  $ 50.0   $ 39.8     25.6   $ 39.8   $ 46.4     (14.2 )

Cost of gas sold

    25.8     18.6     38.4     18.6     22.8     (18.1 )
                               

Gas segment gross margins

  $ 24.2   $ 21.2     14.3   $ 21.2   $ 23.6     (10.4 )

(1)
Other includes other public authorities and interdepartmental usage.

        Gas retail sales and revenues increased during 2013 as compared to 2012 reflecting colder weather in 2013 as compared to 2012. Heating degree days were 38.1% higher in 2013 than 2012 and 8.3% higher than the 30-year average. Sales increased in all classes during 2013, reflecting the colder weather. As a result, our gas gross margin (defined as gas operating revenues less cost of gas in rates) for 2013 increased $3.0 million compared to 2012.

        Gas retail sales and revenues decreased during 2012 as compared to 2011 reflecting mild weather in 2012 and customer contraction of 0.2%. 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. As a result, our gas gross margin for 2012 decreased $2.4 million compared to 2011.

        We have a PGA clause in place that 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, 2013, we had unrecovered purchased gas costs of $1.0 million recorded as a current regulatory asset and $1.2 million recorded as a non-current regulatory liability as compared to 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 of December 31, 2012.


Operating Revenue Deductions

        The table below shows regulated operating expense increases/(decreases) for the years ended December 31:

(in millions)
  2013 vs. 2012   2012 vs. 2011  

Distribution operation expense

  $ 0.2   $ 0.1  

Transmission operation expense

    (0.1 )   0.0  

Customer accounts expense(1)

    0.3     0.0  

Miscellaneous

    0.1     0.0  
           

TOTAL

  $ 0.5   $ 0.1  
           
           

(1)
Primarily uncollectible accounts.

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        Depreciation and amortization expense increased approximately $0.1 million (3.1%) during 2013 and increased approximately $0.1 million (3.0%) during 2012.

        Our gas segment had net income of $2.3 million in 2013 as compared to $1.3 million in 2012 and $2.7 million in 2011.

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:

 
  2013   2012   2011  

Consolidated provision for income taxes

  $ 37.5   $ 34.2   $ 34.3  

Consolidated effective federal and state income tax rates

    37.1 %   38.0 %   38.4 %

        The effective tax rate for 2013 is lower than 2012 and 2011 primarily due to higher equity AFUDC income in 2013 compared with 2012 and 2011.

        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 2013 as compared to 2012 and 2011 reflecting the environmental retrofit project at our Asbury plant. See Note 1 of "Notes to Consolidated Financial Statements" under Item 8.

($ in millions)
  2013   2012   2011  

Allowance for equity funds used during construction

  $ 3.8   $ 1.1   $ 0.3  

Allowance for borrowed funds used during construction

    2.1     0.8     0.2  
               

Total AFUDC

  $ 5.9   $ 1.9   $ 0.5  

        Total interest charges on long-term and short-term debt for 2013, 2012 and 2011 are shown below. The change in long-term debt interest for 2013 reflects the issuance, on May 30, 2013, of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. We used a portion of the proceeds from the sale of these bonds to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013.

        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 an issuance of $88.0 million aggregate principal amount of 3.58% First Mortgage

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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.

 
  Interest Charges
($ in millions)
 
 
  2013   2012   Change   2012   2011   Change  

Long-term debt interest

  $ 40.3   $ 40.2     0.4 % $ 40.2   $ 42.6     (5.6 )%

Short-term debt interest

    0.1     0.2     (68.2 )   0.2     0.1     >100.0  

Other interest*

    1.1     1.1     (2.1 )   1.1     (1.2 )   >(100.0 )
                               

Total interest charges

  $ 41.5   $ 41.5     0.0   $ 41.5   $ 41.5     (0.1 )

*
Includes deferred Iatan 1and Iatan 2 carrying charges to reflect construction accounting in accordance with our agreement with the MPSC. Deferral ended when the plants were placed in rates. The Iatan 1 environmental upgrade 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 routinely 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.

        The following table sets forth information regarding electric and water rate increases since January 1, 2011:

Jurisdiction
  Date
Requested
  Annual
Increase
Granted
  Percent
Increase
Granted
  Date
Effective

Missouri — Electric

  July 6, 2012   $ 27,500,000     6.78 % April 1, 2013

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

Kansas — Electric

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

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

Arkansas — Electric

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

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

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MARKETS AND TRANSMISSION

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 expects to 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 SPP Integrated Marketplace will function as a centralized dispatch, where we and other members will submit offers to sell power and bids to purchase power. The SPP will match offers and bids to supply our and other members' next day generation needs. It is expected that 90% — 95% of all next day generation needed throughout the SPP territory will be cleared through this Integrated Marketplace. This change could impact our fuel costs, however, the net financial effect of these Integrated Marketplace transactions will be processed through our fuel adjustment mechanisms. 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.


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 45% of the funds required in 2014 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 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.

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Summary of Cash Flows

 
  Fiscal Year  
(in millions)
  2013   2012   2011  

Cash provided by/(used in):

                   

Operating activities

  $ 157.5   $ 159.1   $ 134.6  

Investing activities

    (153.3 )   (136.9 )   (105.1 )

Financing activities

    (4.1 )   (24.2 )   (34.6 )
               

Net change in cash and cash equivalents

  $ 0.1   $ (2.0 ) $ (5.1 )


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, the effects of deferred fuel recoveries and the size and timing of pension contributions. The increase or decrease in natural gas prices directly impacts the cost of gas stored in inventory.

        2013 compared to 2012.    In 2013, our net cash flows provided from operating activities remained relatively the same, decreasing only $1.6 million or 1.0% from 2012. This decrease was primarily a result of:

    Increase in net income — $7.8 million.

    Non-cash loss on regulatory plant disallowance as a result of our 2013 Missouri electric rate case — $2.4 million.

    Regulatory reversal of a prior period gain on the sale of assets as a result of our 2013 Missouri electric rate case — $1.2 million.

    Working capital changes for accounts receivable, accounts payable and other current assets and liabilities — $7.2 million.

    Pension contributions increased $5.1 million, partially offset by changes in pension expense accruals of $1.5 million — $(3.6) million net.

    Tax timing differences mostly related to depreciation and amortizations — $(3.6) million.

    Increase in equity AFUDC mostly attributable to higher construction work in progress balances — $(2.7) million.

    Changes in non-cash loss on derivatives — $(4.2) million.

    Long-term regulatory fuel adjustment deferrals — $(5.9) million.

    Deferred revenues — $(1.4) million.

        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.

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    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.


Capital Requirements and Investing Activities

        Our net cash flows used in investing activities increased $16.4 million from 2012 to 2013. 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 increased $31.8 million from 2011 to 2012, primarily due to an increase in electric plant additions and replacements resulting from the environmental retrofit in progress at our Asbury plant.

        Our capital expenditures totaled approximately $160.2 million, $146.3 million, and $101.1 million in 2013, 2012 and 2011, respectively.

        A breakdown of these capital expenditures for 2013, 2012 and 2011 is as follows:

 
  Capital Expenditures  
(in millions)
  2013   2012   2011  

Distribution and transmission system additions

  $ 58.5   $ 63.3   $ 46.5  

Additions and replacements — electric plant

    61.8     46.9     13.4  

New generation — Iatan 2

    0.0     0.0     4.5  

New generation — Riverton 12 combined cycle

    13.2     0.6     0.0  

Storms

    1.0     5.0     15.9  

Transportation

    4.5     3.7     3.9  

Gas segment additions and replacements

    4.1     3.3     3.9  

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

    14.7     20.7     9.2  
               

Subtotal

  $ 157.8   $ 143.5   $ 97.3  

Non-regulated capital expenditures (primarily fiber optics)

    2.4     2.8     3.8  
               

Subtotal capital expenditures incurred(2)

  $ 160.2   $ 146.3   $ 101.1  
               

Adjusted for capital expenditures payable(3)

    (5.4 )   (9.3 )   1.4  
               

Total cash outlay

  $ 154.8   $ 137.0   $ 102.5  
               
               

(1)
Other includes equity AFUDC of $(3.9) million, $(1.1) million and $(0.3) million for 2013, 2012 and 2011, respectively. Also included are insurance proceeds of $(7.8) million for 2013.

(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.

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(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 74%, 85% and 100% of our cash requirements for capital expenditures for 2013, 2012 and 2011, respectively, were satisfied from internally generated funds (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 2014, 2015 and 2016 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
  2014   2015   2016   Total  

Asbury environmental upgrades

  $ 24.2   $ 12.4   $   $ 36.6  

Riverton Unit 12 combined cycle conversion

    79.9     62.5     16.1     158.5  

Electric distribution system additions

    36.9     39.9     36.6     113.4  

Electric transmission facilities

    25.9     29.3     27.5     82.7  

Other

    46.8     31.8     29.9     108.5  
                   

Total

  $ 213.7   $ 175.9   $ 110.1   $ 499.7  
                   
                   

        Our estimated total capital expenditures (excluding AFUDC) for 2017 and 2018 are $99.2 million and $95.9 million, respectively.

        We estimate that internally generated funds will provide approximately 45% of the funds required in 2014 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 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

2013 compared to 2012.

        Our net cash flows used in financing activities was $4.1 million in 2013, a decrease of $20.1 million as compared to 2012, primarily due to the following:

    Issuance of $150.0 million of first mortgage bonds offset by repayment of $98.0 million of senior notes in 2013 compared to no cash impact from $88.0 million in bond refinancing in 2012.

    Repayment of $20.0 million in short-term debt in 2013 as compared to borrowing $12.0 million in 2012, which resulted in an $8.0 million net use of cash when comparing 2013 to 2012.

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.

    Borrowings of $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.

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

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Shelf Registration.

        On December 13, 2013, we filed a $200.0 million shelf registration statement on Form S-3 with the SEC covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. This shelf registration statement will be effective for a three-year period beginning with the date of filing. We plan to use the proceeds under this shelf to fund capital expenditures, refinance existing debt or general corporate needs during the effective period. The issuance of securities under this shelf is subject to the receipt of state regulatory approvals. We have filed applications for such approvals in all four state jurisdictions in our electric service territory.

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. This agreement extended the termination date of the revolving credit facility from January 26, 2013 to January 17, 2017. The agreement also removed the letter of credit facility and includes a swingline loan facility with a $15 million swingline loan sublimit. The aggregate amount of the revolving credit commitments remains $150 million, inclusive of the $15 million swingline loan sublimit. There were no outstanding borrowings under this agreement at December 31, 2013. However $4.0 million was used to back up our outstanding commercial paper. 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, 2013 would permit us to issue approximately $599.1 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, 2013, we had retired bonds and net property additions which would enable the issuance of at least $856.7 million principal amount of bonds if the annual interest requirements are met. However, based on the $1 billion limit on the principal amount of first mortgage bonds outstanding set forth by the EDE mortgage, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $417 million of new first mortgage bonds. As of December 31, 2013, 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, 2013, this test

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would allow us to issue approximately $15.8 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*   Baa1   BBB

EDE First Mortgage Bonds

  BBB+   A2   A-

Senior Notes

  BBB   Baa1   BBB

Commercial Paper

  F3   P-2   A-2

Outlook

  Stable   Stable   Stable

*
Not rated.

        On January 30, 2014, Moody's upgraded our corporate credit rating to Baa1 from Baa2, senior secured debt to A2 from A3, senior unsecured debt to Baa1 from Baa2 and affirmed our commercial paper rating at P-2. Moody's outlook for Empire is stable. On March 6, 2013, Standard & Poor's upgraded our corporate credit rating to BBB from BBB-, senior secured debt to A- from BBB+, senior unsecured debt to BBB from BBB- and our commercial paper rating to A-2 from A-3. Standard & Poor's outlook for Empire is stable. On March 24, 2011, 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 24, 2013, 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, 2013. 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 2014 – 2018 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)

  $ 740.0   $   $ 25.0   $ 90.0   $ 625.0  

Interest on long-term debt

    666.1     39.2     78.2     70.9     477.8  

Short-term debt

    4.0     4.0              

Capital lease obligations

    6.4     0.6     1.1     1.1     3.6  

Operating lease obligations(2)

    4.0     0.8     1.4     1.3     0.5  

Electric purchase obligations(3)

    469.8     49.2     66.7     59.5     294.4  

Gas purchase obligations(4)

    91.5     11.3     17.8     17.8     44.6  

Open purchase orders

    188.7     31.7     157.0          

Postretirement benefit obligation funding

    11.7     2.2     4.2     5.3      

Pension benefit funding

    48.9     12.0     21.0     15.9      

Other long-term liabilities(5)

    3.1     0.1     0.3     0.3     2.4  
                       

TOTAL CONTRACTUAL OBLIGATIONS

  $ 2,234.2   $ 151.1   $ 372.7   $ 262.1   $ 1,448.3  
                       
                       

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

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(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 2014 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.


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.

        The following table shows our diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance for the years ended December 31, 2013, 2012 and 2011:

(in millions, except per share amounts)
  2013   2012   2011  

Diluted earnings per share

  $ 1.48   $ 1.32   $ 1.31  

Dividends paid per share(1)

  $ 1.005   $ 1.00   $ 0.64  

Total dividends paid

  $ 43.0   $ 42.3   $ 26.7  

Retained earnings year-end balance

  $ 67.6   $ 47.1   $ 33.7  

(1)
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.

        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

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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.


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 and OPEB 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 and OPEB costs that are 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 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

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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.

        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.

        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.

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        As of December 31, 2013, we have recorded $177.1 million in regulatory assets and $137.7 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. 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 established a base cost in rates for the recovery of fuel and purchased power expenses used to supply energy. The fuel adjustment clause permits the distribution to our Missouri 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 2013, 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, 2013 and 2012 was $4.0 million and $4.2 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, 2013, 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.

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        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 negative changes occurred to one or more key assump