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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, 2014

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

         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, 2014, was approximately $1,112,837,946.

         As of February 2, 2015, 43,517,285 shares of common stock were outstanding.

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

The Company's proxy statement, filed pursuant
to Regulation 14A under the Securities Exchange
Act of 1934, for its Annual Meeting of
Stockholders to be held on April 30, 2015
  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

  13

 

Regulation

  15

 

Environmental Matters

  16

 

Conditions Respecting Financing

  16

 

Our Web Site

  17

ITEM 1A.

 

RISK FACTORS

  17

ITEM 1B.

 

UNRESOLVED STAFF COMMENTS

  23

ITEM 2.

 

PROPERTIES

  24

 

Electric Segment Facilities

  24

 

Gas Segment Facilities

  25

 

Other Segment

  25

ITEM 3.

 

LEGAL PROCEEDINGS

  26

ITEM 4.

 

MINE SAFETY DISCLOSURES

  26

PART II

ITEM 5.

 

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

  27

ITEM 6.

 

SELECTED FINANCIAL DATA

  29

ITEM 7.

 

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

  29

 

Executive Summary

  29

 

Results of Operations

  33

 

Rate Matters

  41

 

Markets and Transmission

  42

 

Liquidity and Capital Resources

  42

 

Contractual Obligations

  48

 

Dividends

  48

 

Off-Balance Sheet Arrangements

  49

 

Critical Accounting Policies

  49

 

Recently Issued Accounting Standards

  52

ITEM 7A

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  53

ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  56

ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

  124

ITEM 9A.

 

CONTROLS AND PROCEDURES

  124

ITEM 9B.

 

OTHER INFORMATION

  124

PART III

ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

  125

ITEM 11.

 

EXECUTIVE COMPENSATION

  125

ITEM 12.

 

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

  125

ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

  126

ITEM 14.

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES

  126

PART IV

ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

  127

 

SIGNATURES

  133

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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) regional transmission organization (RTO) transmission development, and SPP Day-Ahead Market;

    the impact of energy efficiency and alternative energy sources;

    electric utility restructuring, including deregulation;

    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;

    the cost and availability of purchased power and fuel, including costs and activities associated with the SPP Day-Ahead Market, and the results of our activities (such as hedging) to reduce the volatility of such costs;

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    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;

    our potential inability to attract and retain an appropriately qualified workforce;

    changes in accounting requirements;

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

    performance of acquired businesses; 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 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 2014 were derived as follows:

Electric segment sales*

    90.8 %

Gas segment sales

    8.0  

Other segment sales

    1.2  

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

        The territory served by our electric operations embraces an area of about 10,000 square miles, located principally in southwestern Missouri, and also includes smaller areas in southeastern Kansas, northeastern Oklahoma and northwestern Arkansas. The principal economic activities of these areas include light industry, agriculture and tourism. As of December 31, 2014, our electric operations served approximately 170,000 customers.

        Our retail electric revenues for 2014 by jurisdiction were derived as follows:

Missouri

    89.7 %

Kansas

    4.8  

Oklahoma

    2.8  

Arkansas

    2.7  

        We supply electric service at retail to 119 incorporated communities as of December 31, 2014, 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 55% of our electric operating revenues in 2014 were derived from incorporated communities with franchises having at least ten years remaining and approximately 15% 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 40.0%, 29.2%, and 14.4%, respectively, of our electric operating revenues in 2014.

        Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2014 accounted for approximately 2.9% of electric revenues. No single retail customer accounted for more than 1.8% of electric revenues in 2014.

        Our gas operations serve customers in northwest, north central and west central Missouri. As of December 31, 2014, our gas operations served approximately 43,500 customers. We provide natural gas distribution to 48 communities and 422 transportation customers as of December 31, 2014. 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 2014 were derived as follows:

Residential

    63.4 %

Commercial

    26.3  

Industrial

    1.0  

Transportation

    7.7  

Miscellaneous

    1.6  

        No single retail customer accounted for more than 1% of gas revenues in 2014.

        Our other segment consists of our fiber optics business. As of December 31, 2014, we have 121 fiber customers.

Electric Generating Facilities and Capacity

        At December 31, 2014, our generating plants consisted of:

Plant
  Capacity
(megawatts)(1)
  Primary Fuel

State Line Combined Cycle (60% ownership)

    297 (2) Natural Gas

Riverton — Natural Gas

    226 (3) Natural Gas

Empire Energy Center

    260   Natural Gas

State Line Unit No. 1

    93   Natural Gas

Asbury

    194 (4) Coal

Iatan (12% ownership)

    190 (2) Coal

Plum Point Energy Station (7.52% ownership)

    50 (2) Coal

Ozark Beach

    16   Hydro

TOTAL

    1,326    

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

(2)
Capacity reflects our allocated shares of the capacity of these plants.

(3)
Reflects the retirement of Riverton Unit 7 on June 30, 2014

(4)
Includes additional auxiliary megawatts needed for AQCS and turbine retrofit.

        Our generating capacity consists of 66.1% natural gas, 32.7% coal and 1.2% hydro. 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 Southwest Power Pool (SPP) requires its members (including Empire) 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 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. It is not currently our intention to exercise this option in 2015.

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        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.

        Operationally, we participate in the SPP Integrated Marketplace (IM) to meet our energy and ancillary service requirements. Our generation resources are offered into the marketplace. The marketplace solution determines what offered resources are committed and dispatched to meet region-wide demand, energy, and ancillary service requirements. To the extent other resources offered to the marketplace are more economic than our resources they will be utilized for our load, lowering our cost compared to meeting requirements with only our resources.

        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."

        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
 

2015

    86     1326     1412  

2016

    86     1377 (2)   1463 (2)

2017

    86     1377     1463  

2018

    86     1377     1463  

2019

    86     1377     1463  

(1)
Includes 17 megawatts for the Elk River Windfarm, LLC and 19 megawatts for the Cloud County Windfarm, LLC.

(2)
Reflects the retirement of Riverton Units 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 maximum hourly summer demand of 1,198 megawatts was set on August 2, 2011.

Gas Facilities

        At December 31, 2014, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,175 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, 2014, totaled $505.1 million and retirements during the same period totaled $72.0 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 $207.2 million in 2014 and for the next three years are estimated for planning purposes to be as follows:

 
  Estimated Capital Expenditures
(amounts in millions)
 
 
  2015   2016   2017   Total  

New electric generating facilities:

                         

Riverton Unit 12 combined cycle conversion

  $ 62.5   $ 17.1   $ 0.0   $ 79.6  

Additions to existing electric generating facilities:

                         

Asbury

    4.5     2.2     1.8     8.5  

Environmental upgrades — Asbury

    2.3     0.0     1.1     3.4  

Other

    11.3     7.6     15.8     34.7  

Electric transmission facilities

    33.1     30.3     25.6     89.0  

Electric distribution system additions

    40.8     37.0     45.9     123.7  

General and other additions

    11.6     8.8     8.9     29.3  

Gas system additions

    4.1     4.1     4.1     12.3  

Non-regulated additions

    2.5     2.1     2.3     6.9  

TOTAL

  $ 172.7   $ 109.2   $ 105.5   $ 387.4  

        Construction expenditures for additions to our transmission and distribution systems and the conversion of Riverton Unit 12 to a combined cycle unit constitute the majority of the projected capital expenditures for the three-year period listed above beyond routine capital expenditures. Our estimated total capital expenditures (excluding AFUDC) for 2018 and 2019 are $157.5 million and $157.4 million, respectively.

        Estimated capital expenditures are reviewed and adjusted for, among other things, revised estimates of future capacity needs, the cost of funds necessary for construction, replacement of aged infrastructure, 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 2014 and 2013, based on kilowatt-hours generated, was as follows:

 
  2014   2013  

Steam generation units — coal

    47.5 %   47.0 %

Combustion turbine generation units — natural gas

    26.5     24.3  

Hydro generation

    1.2     1.0  

Purchased power — windfarms

    18.2     14.8  

Purchased power — other

    6.6     12.9  

        Below are the total fuel requirements for our generating units in 2014 and 2013 (based on kilowatt-hours generated):

 
  2014   2013  

Coal

    63.7 %   65.9 %

Natural gas

    35.8     34.0  

Fuel oil

    0.4     0.1  

Tire derived fuel

    0.1     0.0  

        Our Asbury Plant is fueled primarily by coal with oil being used as start-up fuel. In 2014, Asbury burned a coal blend consisting of approximately 91.4% Western coal (Powder River Basin) and 8.6% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2014, we had sufficient coal on hand to supply full load requirements at Asbury for 44 – 277 days, as compared to 38 – 59 days as of December 31, 2013, depending on the actual blend ratio. The inventory increased during 2014 as Asbury rebuilt its stockpile during the air quality control system (AQCS) outage.

        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
 

2015

    92 %

2016

    35 %

2017

    18 %

        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 BNSF Railway Company 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. Additional train capacity is leased on an as needed basis.

        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 85% of Iatan's requirements for 2015 and approximately 40% for 2016 and 10% for 2017. Coal is transported to Iatan by rail. Their rail contract provides 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 Energy Services is the operator of this plant. Plum Point Services Company, LLC (PPSC), the project

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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 87% of Plum Point's requirements for 2015, 87% for 2016 and 48% for 2017. 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 8 and 12 are fueled 100% by natural gas. Unit 7 was retired on June 30, 2014. Based on kilowatt hours generated during 2014, 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 2014, 96.1% of the Energy Center generation was produced from natural gas and 65% of the State Line Unit 1 generation came from natural gas with the remainder being fuel oil. As of December 31, 2014, oil inventories were sufficient for approximately 5 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 July 30, 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. We have reached agreement with Southern Star to replace these firm transportation agreements effective April 1, 2016 with a new agreement that runs through October 2022. We have additional firm transportation agreements that provide firm transportation to our Riverton plant sufficient to supply our Riverton Unit 12 through August, 2019. These transportation agreements can also supply natural gas to State Line Unit No.1, the Empire Energy Center or the Riverton Plant, as elected by us 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
  2014   2013   2012  

Coal — Iatan

  $ 1.738   $ 1.756   $ 1.760  

Coal — Asbury

    2.363     2.432     2.395  

Coal — Riverton(1)

    0.000     0.000     2.541  

Coal — Plum Point

    2.314     2.123     1.804  

Natural Gas

    5.268     4.952     4.493  

Oil

    17.512     21.870     20.291  

Weighted average cost of fuel burned per kilowatt-hour generated

  $ 2.9700   $ 2.8074   $ 2.6742  

(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   2014   2013   2012  

South

  Southern Star Central Gas Pipeline   $ 4.6986   $ 5.4998   $ 6.4329  

North

  Panhandle Eastern Pipe Line Company     6.0201     5.9746     6.8990  

Northwest

  ANR Pipeline Company     4.8499     4.7589     5.0898  

  Weighted average cost per mcf   $ 4.9564   $ 5.4949   $ 6.3305  

Employees

        At December 31, 2014, we had 751 full-time employees, including 50 employees of EDG. 327 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, 2014, 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)

 
  2014   2013   2012   2011   2010  

Electric Operating Revenues (000's):

                               

Residential

  $ 236,468   $ 227,656   $ 214,526   $ 221,687   $ 204,900  

Commercial

    172,274     162,444     158,837     157,435     146,310  

Industrial

    84,734     80,497     78,786     78,925     69,684  

Public authorities(2)

    14,863     14,707     13,755     13,653     12,099  

Wholesale on-system

    22,326     20,036     18,555     19,140     19,254  

Interdepartmental

    388     229     197     201     199  

Total system

  $ 531,053   $ 505,569   $ 484,656   $ 491,041   $ 452,446  

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

                               

Steam

    2,407,914     2,813,441     2,865,037     2,805,744     2,650,042  

Hydro

    60,652     57,449     57,719     48,898     88,104  

Combustion turbine

    1,361,860     1,452,936     1,486,643     1,484,472     1,566,074  

Total generated

    3,830,426     4,323,826     4,409,399     4,339,114     4,304,220  

Purchased

    1,254,416     1,660,193     1,545,327     1,870,901     2,085,550  

Total generated and purchased

    5,084,842     5,984,019     5,954,726     6,210,015     6,389,770  

Interchange (net)

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

Total system output

    5,084,841     5,984,451     5,954,639     6,208,717     6,388,054  

Transmission by others losses(3)

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

Total for resale — non-system (prior to SPP IM)(4)

    (100,158 )   (653,996 )   (704,028 )   (740,009 )   (798,084 )

Net (sales)/purchases to/from SPP IM compared to native load(4)

    386,267                  

Total native load

    5,370,950     5,314,638     5,233,311     5,452,111     5,584,282  

Maximum hourly system demand (Kw)

    1,162,000     1,080,000     1,142,000     1,198,000     1,199,000  

Owned capacity (end of period) (Kw)

    1,326,000     1,377,000     1,391,000     1,392,000     1,409,000  

Annual load factor (%)

    52.76     56.18     52.17     51.95     53.17  

Electric sales (000's of kWh):

                               

Residential

    1,950,416     1,936,603     1,850,813     1,982,704     2,060,368  

Commercial

    1,583,843     1,541,717     1,558,297     1,576,342     1,644,917  

Industrial

    1,031,555     1,015,492     1,028,416     1,022,765     1,007,033  

Public authorities(2)

    124,287     127,370     122,369     126,724     124,554  

Wholesale on-system

    336,314     343,045     353,075     364,866     355,807  

Total system

    5,026,415     4,964,227     4,912,970     5,073,401     5,192,679  

Wholesale off-system

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

SPP EIS Resettlements, Other(4)

    1,445                  

Total Electric Sales

    5,027,860     5,618,223     5,616,998     5,813,410     5,990,763  

Company use (000's of kWh)(5)

   
10,725
   
9,049
   
9,066
   
9,371
   
9,598
 

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

    332,365     341,362     311,275     369,339     382,005  

Wholesale off-system(4)

        (653,996 )   (704,028 )   (740,009 )   (798,084 )

Total Native Load

    5,370,950     5,314,638     5,233,311     5,452,111     5,584,282  

Customers (average number):

                               

Residential

    141,838     141,376     140,602     139,641     141,693  

Commercial

    24,146     24,080     24,036     24,155     24,505  

Industrial

    346     345     353     357     358  

Public authorities(2)

    2,175     2,214     2,124     2,021     2,003  

Wholesale on-system

    4     4     4     4     4  

Total System

    168,509     168,019     167,119     166,178     168,563  

Wholesale off-system

    4     22     22     25     22  

Total

    168,513     168,041     167,141     166,203     168,585  

Average annual sales per residential customer (kWh)

    13,751     13,698     13,163     14,199     14,541  

Average annual revenue per residential customer

  $ 1,667   $ 1,610   $ 1,526   $ 1,588   $ 1,446  

Average residential revenue per kWh

    12.12 ¢   11.76 ¢   11.59 ¢   11.18 ¢   9.94 ¢

Average commercial revenue per kWh

    10.88 ¢   10.54 ¢   10.19 ¢   9.99 ¢   8.89 ¢

Average industrial revenue per kWh

    8.21 ¢   7.93 ¢   7.66 ¢   7.72 ¢   6.92 ¢

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

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

(3)
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. (Prior to SPP IM).

(4)
As of March 1, 2014, off-system revenues were effectively replaced by SPP IM activity. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — SPP Integrated Marketplace (IM) and Off-System Electric Transactions" below for additional information.

(5)
Includes kWh used by Company and Interdepartmental.

(6)
2012 includes the effect of our unbilled revenue adjustment.

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GAS OPERATING STATISTICS(1)

 
  2014   2013   2012   2011   2010  

Gas Operating Revenues (000's):

                               

Residential

  $ 32,873   $ 31,561   $ 24,744   $ 28,999   $ 32,245  

Commercial

    13,640     13,673     10,797     12,506     13,336  

Industrial

    537     515     464     682     812  

Public authorities

    365     342     247     324     342  

Total retail sales revenues

    47,415     46,091     36,252     42,511     46,735  

Miscellaneous(2)

    457     435     400     464     436  

Transportation revenues

    3,970     3,515     3,197     3,455     3,714  

Total Gas Operating Revenues

  $ 51,842   $ 50,041   $ 39,849   $ 46,430   $ 50,885  

Maximum Daily Flow (mcf)

    72,912     60,118     58,281     67,789     73,280  

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

                               

Residential

    2,760     2,744     2,012     2,560     2,675  

Commercial

    1,275     1,349     1,050     1,268     1,265  

Industrial

    62     72     58     102     108  

Public authorities

    37     35     23     33     33  

Total retail sales

    4,134     4,200     3,143     3,963     4,081  

Transportation sales

    4,918     4,528     4,249     4,528     4,829  

Total gas operating and transportation sales

    9,052     8,728     7,392     8,491     8,910  

Company use(3)

    2     2     2     4     4  

Transportation sales (cash outs)

                     

Mcf losses

    68     96     27     (47 )   70  

Total system sales

    9,122     8,826     7,421     8,448     8,984  

Customers (average number):

                               

Residential

    37,572     37,777     37,897     38,051     38,277  

Commercial

    4,872     4,917     4,921     4,951     4,968  

Industrial

    22     24     23     26     26  

Public authorities

    138     140     138     136     137  

Total retail customers

    42,604     42,858     42,979     43,164     43,408  

Transportation customers

    422     340     326     311     313  

Total gas customers

    43,026     43,198     43,305     43,475     43,721  

(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.

Executive Officers and Other Officers of Empire

        The names of our officers, their ages and years of service with Empire as of December 31, 2014, positions held during the past five years and effective dates of such positions are presented below. All of

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our officers, other than Mark T. Timpe (whose biographical information is set forth below), have been employed by Empire for at least the last five years.

Name
  Age at
12/31/14
  Positions With the Company   With the
Company
Since
  Officer
Since
 

Bradley P. Beecher

    49  

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

    59  

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

    2002     2005  

Ronald F. Gatz

    64  

Vice President and Chief Operating Officer — Gas (2006)

    2001     2001  

Blake Mertens(1)

    37  

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)

    2001     2011  

Martin O. Penning(2)

    59  

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

    1980     2011  

Kelly S. Walters

    49  

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

    2001     2006  

Janet S. Watson(3)

    62  

Secretary (2014), Secretary — Treasurer (1995)

    1994     1995  

Mark T. Timpe(4)

    55  

Treasurer (2014), Director of Financial Services (2014)

    2014     2014  

Robert W. Sager

    40  

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

    2006     2011  

Dale W. Harrington(5)

    53  

Director of Investor Relations and Assistant Secretary (2014), Director of Investor Relations (2014), Director of Financial Services (2011), Assistant Director of Human Resources (2002)

    2002     2014  

(1)
Blake Mertens was elected Vice-President — Energy Supply and Delivery Operations effective March 1, 2015.

(2)
Martin O. Penning will retire from his position as Vice-President — Commercial Operations effective February 28, 2015. He will be succeeded by Brent A. Baker who was elected Vice-President — Customer Service, Transmission and Engineering effective March 1, 2015.

(3)
Janet S. Watson will retire from her position as Secretary effective April 30, 2015.

(4)
Mark T. Timpe was elected Treasurer effective October 30, 2014. He joined Empire on August 18, 2014, as Director of Financial Services. Prior to employment with Empire, Mr. Timpe spent over 21 years with Con-Way Truckload/CFI in Joplin where he served as CFI's Treasurer for 16 years, and, most recently, as Assistant Treasurer from 2008 to 2014 and Director of Billing and Credit from 2011 to 2014 for Conway Truckload after their acquisition of CFI in 2007.

(5)
Dale W. Harrington was elected Secretary effective May 1, 2015.

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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."

        Electric operating revenues received during 2014 were comprised of the following:

Retail customers

    92.7 %

Sales subject to FERC jurisdiction

    6.5  

Miscellaneous sources

    0.8  

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

Missouri

    89.7 %

Kansas

    4.8  

Oklahoma

    2.8  

Arkansas

    2.7  

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

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

Gas Segment

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

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

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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. 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 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. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $357.0 million of new first mortgage bonds. 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, 2014, would permit us to issue approximately $615.9 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, 2014, we had retired bonds and net property additions which would enable the issuance of at least $952.5 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2014, 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 principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Indenture of Mortgage and Deed of Trust, dated as of June 1, 2006, as amended and supplemented (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, 2014, this test would allow us to issue approximately $19.7 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."

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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.

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 margins in any period are: (1) rates we can charge our customers, including timing of new rates, (2) weather, (3) customer growth and usage and (4) general economic conditions. Of the factors driving margins, 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, energy efficiency or increased use of self-generation and distributed energy technologies 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.

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        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.

Energy conservation, energy efficiency, distributed generation and other factors that reduce energy demand could adversely affect our business, financial condition and results of operations.

        Regulatory and legislative bodies have proposed or introduced requirements and incentives to reduce energy consumption. Conservation and energy efficiency programs are designed to reduce energy demand. Unless there is a regulatory solution ensuring recovery, declining usage will result in an under-recovery of our fixed costs. Macroeconomic factors resulting in low economic growth or contraction within our service territories could also reduce energy demand. Any such reductions in energy demand could adversely affect our business, financial condition and results of operations

        In addition, significant technological advancements are taking place in the electric industry, including advancements related to self-generation and distributed energy technologies such as fuel cells, micro turbines, wind turbines and solar cells. Adoption of these technologies may increase because of advancements or government subsidies reducing the cost of generating electricity through these technologies to a level that is competitive with our current methods of generating electricity. There is also a perception that generating electricity through these technologies is more environmentally friendly than generating electricity with fossil fuels. Increased adoption of these technologies would reduce demand for our electricity but would not necessarily reduce our investment and operating requirements due to our obligation to serve customers, including those self-generation customers whose equipment has failed for any reason to provide the power they need. In addition, self-generating customers do not currently pay a share of the costs necessary to operate our transmission and distribution system. As a result, the pool of customers from whom fixed costs are recovered would be reduced, potentially resulting in under-recovery of our fixed costs and upward price pressure on our remaining customers. If we were unable to adjust our prices to reflect such reduced electricity demand and any related use of net energy metering (which allows self-generating customers to receive bill credits for surplus power), our business, financial condition and results of operations could be adversely affected. In addition, since a portion of our costs are recovered through charges based upon the volume of power delivered, reductions in electricity deliveries will affect the timing of our recovery of those costs and may require changes to our rate structures.

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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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.

        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.

        Natural gas is delivered to our generation fleet at Riverton, State Line, and Energy Center via Southern Star Central Gas Pipeline. Although we have firm transportation contracts in place for a limited volume of daily natural gas deliveries, the actual delivery of natural gas can still be uncertain during winter peaking weather. The inability to procure commodity or pipeline curtailments for non-firm delivery causes us to either rely on fuel oil as a back-up fuel for generation at State Line unit 1 or Energy Center units, and/or limit the generation offered into the SPP IM from State Line Combined Cycle and Riverton. As a result, we could incur higher fuel and purchased power costs than if the units were available for full commitment and dispatch.

        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, including the rates that we can charge customers.

        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.

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        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. Rate proceedings through which our prices and terms of service are determined typically involve numerous parties including customers, consumer advocates and governmental entities, some of whom take positions adverse to us. In addition, regulators' decisions may be appealed to the courts by us or other parties to the proceedings. These factors may lead to uncertainty and delays in implementing changes to our prices or terms of service. 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.

        In addition, 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. This may result in under-recovery of costs, failure to earn the authorized return on investment, or both.

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 (including tornadoes and ice storms), acts of terrorism or other similar occurrences.

        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. In addition, certain catastrophic events can inflict extensive damage to our equipment and facilities which can require us to incur additional operating and maintenance expense and additional capital expenditures. Our prices may not always be adjusted timely and adequately to reflect these higher costs.

        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.

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The regional power market in which we operate has changing market and transmission structures, which could have an adverse effect on our results of operations, financial position and cash flows.

        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 coordinator, tariff administrator 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 implemented a Day-Ahead Market, or IM, in March 2014. The SPP IM functions as a centralized dispatch, where we and other members submit offers to sell power and bids to purchase power. The SPP matches offers and bids to supply the next day generation needs of its members. It is expected that 90%-95% of all next day generation needed throughout the SPP territory will be cleared through this IM. This change could impact our fuel costs, however, the net financial effect of these IM 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.

Security breaches, criminal activity, terrorist attacks and other disruptions to our information technology infrastructure could directly or indirectly interfere with our operations, could expose us or our customers or employees to a risk of loss, and could expose us to liability, regulatory penalties, reputational damage and other harm to our business.

        We rely upon information technology networks and systems to process, transmit and store electronic information, and to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems to record, process and summarize financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal and tax requirements. Our technology networks and systems collect and store sensitive data including system operating information, proprietary business information belonging to us and third parties, and personal information belonging to our customers and employees.

        Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers or breaches due to employee error or malfeasance, or other disruptions during software or hardware upgrades, telecommunication failures or natural disasters or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems; could expose us, our customers or our employees to a risk of loss or misuse of information; and could result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business. We cannot accurately assess the probability that a security breach may occur, despite the measures that we take to prevent such a breach, and we are unable to quantify the potential impact of such an event. We can provide no assurance that we will identify and remedy all security or system vulnerabilities or that unauthorized access or error will be identified and remedied.

        Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. Our facilities could be direct targets or indirect casualties of such attacks. The effects of such attacks could include disruption to our generation, transmission and distribution systems or to the electrical grid in general, and could increase the cost of insurance coverage or result in a decline in the U.S. economy.

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

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

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

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

 
  Fitch   Moody's   Standard & Poor's  

Corporate Credit Rating

    n/r*     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.

The cost and schedule of construction projects may materially change.

        Our capital expenditure budget for the next three years is estimated to be $387.4 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

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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 $172.7 million in 2015. 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 and volatility in discount rates could lead to increased funding obligations due to reduced asset values and increased benefit obligations. During 2014, our net pension and OPEB liability increased $40.5 million. 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. Future market changes could result in increased pension and OPEB liabilities and funding obligations.

Failure to attract and retain an appropriately qualified workforce could adversely affect our business, financial condition and results of operations.

        Certain events, such as an aging workforce, mismatch of skill set or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the lengthy time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If we are unable to successfully attract and retain an appropriately qualified workforce, our business, financial condition and results of operations could be adversely affected.

We are subject to adverse publicity and reputational risks, which makes us vulnerable to negative customer perception and increased regulatory oversight or other sanctions.

        Like other utility companies, we have a large consumer customer base and, as a result, are subject to public criticism focused on the reliability of our distribution services and the speed with which we are able to respond to outages caused by storm damage or other unanticipated events. Adverse publicity of this nature may render legislatures, public utility commissions and other regulatory authorities and government officials, less likely to view public utility companies in a favorable light, and may cause us to be susceptible to less favorable legislative and regulatory outcomes or increased regulatory oversight. Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material adverse effect on our business, financial condition and results of operations.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

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ITEM 2.    PROPERTIES

Electric Segment Facilities

        Our generating facilities consist of three coal-fired generating plants, four natural gas generating plants and one hydroelectric generating plant. At December 31, 2014, we owned generating facilities with an aggregate generating capacity of 1,326 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 with a current generating capacity of 194 megawatts. 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 2014, the plant accounted for approximately 15% of our owned generating capacity and accounted for approximately 27.7% 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 installed a scrubber, fabric filter and powder activated carbon injection system at our Asbury plant. The addition of this air quality control system (AQCS) equipment was completed in December 2014 and required the retirement of Asbury Unit 2 at the end of 2013. 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. When the Asbury Plant is out of service, we typically experience increased purchased power and fuel expenditures associated with replacement energy, which is likely to be recovered through our fuel adjustment clauses. The Asbury Plant went on outage as planned on September 12, 2014 and remained on outage through October while the AQCS tie in work was completed. Asbury returned to service and began testing in early November. All in-service testing was completed and results verified for the Asbury AQCS by December 15, 2014. The MPSC staff determined that as of December 15, 2014, the Asbury AQCS had met the in-service criteria.

        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. 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.

        Our generating plant located at Riverton, Kansas, has four gas-fired combustion turbine units (Units 9, 10, 11 and 12) and one gas-fired steam generating unit (Unit 8) with an aggregate generating capacity of 226 megawatts. In September 2012, Units 7 and 8 were transitioned from operation on coal to full operation on natural gas. Riverton Unit 7 was permanently removed from service on June 30, 2014. Unit 12 is being 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 93 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

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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 260 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 the 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 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.

        At December 31, 2014, 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 6,911 miles of line at December 31, 2014 and 6,882 miles as of December 31, 2013.

        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 96 miles of water mains in three communities in Missouri.

Gas Segment Facilities

        At December 31, 2014, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,175 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).

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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 2, 2015, there were 4,198 record holders and 28,605 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 2014 and 2013.

 
  High   Low   Close   Dividends Paid
Per Share
 

2014 Quarter Ended:

                         

March 31

  $ 24.50   $ 22.04   $ 24.32   $ 0.255  

June 30

    25.70     23.23     25.68     0.255  

September 30

    26.00     24.00     24.15     0.255  

December 31

    31.20     24.09     29.74     0.260  

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  

        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 2014, the Board of Directors increased the dividend by 2%, from $0.255 per share on common stock to $0.26 per share. In the first quarter of 2015, the Board of Directors declared a quarterly dividend of $0.26 per share on common stock payable on March 16, 2015 to holders of record as of March 2, 2015. As of December 31, 2014, our retained earnings balance was $90.3 million, compared to $67.6 million at December 31, 2013. 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 2014, no purchases of our common stock were made by or on behalf of us.

        Participants in our Dividend Reinvestment and Direct Stock Purchase Plan may acquire newly issued common shares with reinvested dividends. Participants may also purchase, at an averaged market price, newly issued common shares with optional cash payments, 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 8 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, 2009, 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.

GRAPHIC

Total Return Analysis
  12/31/2009   12/31/2010   12/31/2011   12/31/2012   12/31/2013   12/31/2014  

The Empire District Electric Company

  $ 100.00   $ 126.59   $ 124.13   $ 125.95   $ 146.80   $ 200.39  

S&P Electric Utilities Index

  $ 100.00   $ 103.43   $ 125.12   $ 124.43   $ 134.13   $ 176.00  

S&P 500 Index

  $ 100.00   $ 115.06   $ 117.49   $ 136.30   $ 180.44   $ 205.14  

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

 
  2014   2013   2012   2011   2010  

Operating revenues(1)

  $ 652,330   $ 594,330   $ 557,097   $ 576,870   $ 541,276  

Operating income

  $ 99,999   $ 99,663   $ 96,221   $ 96,934   $ 80,495  

Total allowance for funds used during construction

  $ 9,917   $ 5,940   $ 1,928   $ 512   $ 10,174  

Net income

  $ 67,103   $ 63,445   $ 55,681   $ 54,971   $ 47,396  

Weighted average number of common shares outstanding — basic

   
43,291
   
42,781
   
42,257
   
41,852
   
40,545
 

Weighted average number of common shares outstanding — diluted

    43,314     42,803     42,284     41,887     40,580  

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

  $ 1.55   $ 1.48   $ 1.32   $ 1.31   $ 1.17  

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

  $ 1.55   $ 1.48   $ 1.32   $ 1.31   $ 1.17  

Cash dividends per share

  $ 1.025   $ 1.005   $ 1.00   $ 0.64   $ 1.28  

Common dividends paid as a percentage of net income

   
66.1

%
 
67.8

%
 
75.9

%
 
48.6

%
 
109.7

%

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

    14.8 %   9.4 %   3.5 %   0.9 %   21.5 %

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

 
$

18.02
 
$

17.43
 
$

16.90
 
$

16.53
 
$

15.82
 

Capitalization:

   
 
   
 
   
 
   
 
   
 
 

Common equity

  $ 783,298   $ 750,123   $ 717,798   $ 693,989   $ 657,624  

Long-term debt

  $ 803,189   $ 743,428   $ 691,626   $ 692,259   $ 693,072  

Ratio of earnings to fixed charges

    3.02X     2.97X     2.89X     2.87X     2.63X  

Total assets

  $ 2,390,256   $ 2,145,045   $ 2,126,369   $ 2,021,835   $ 1,921,311  

Plant in service at original cost

  $ 2,541,582   $ 2,332,341   $ 2,284,022   $ 2,176,650   $ 2,108,115  

Capital expenditures (including AFUDC)

  $ 222,852   $ 160,196   $ 146,287   $ 101,177   $ 108,157  

(1)
2014 includes $41.9 million of SPP IM net revenues.

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

EXECUTIVE SUMMARY

Electric Segment

        As a vertically integrated regulated utility, the primary drivers of our electric operating margins (defined as electric revenues less fuel and purchased power costs) in any period are: (1) rates we can charge our customers, including timing of new rates, (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 construction costs) 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

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relief are discussed in detail in Note 3 of "Notes to the Consolidated Financial Statements" under Item 8. Of the factors driving margins, weather has the greatest short-term effect on the demand for electricity for our regulated business. Very hot summers and very cold winters increase electric demand, while mild weather reduces demand. Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and by general economic conditions.

        Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. 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, 2014 was 0.3%. 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 count decreased 0.2% for the year ended December 31, 2014, which we believe was due to population losses in the rural communities we serve. 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, 2014, basic and diluted earnings per weighted average share of common stock were $1.55 on $67.1 million of net income compared to $1.48 on $63.4 million of net income for the year ended December 31, 2013. Increased electric gross margins positively impacted net income for 2014 as compared to 2013 mainly due to increased electric rates for our Missouri customers effective April 1, 2013 and for our wholesale on-system customers in June 2014. Favorable weather and increased

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AFUDC due to higher levels of construction activity during 2014 also positively impacted results. Increased regulatory operating and maintenance expense, property taxes, and depreciation and amortization expense negatively impacted 2014 results.

        The table below sets forth a reconciliation of basic and diluted earnings per share between 2013 and 2014, which is a non-GAAP presentation. The economic substance behind our non-GAAP earnings per share (EPS) measure is to present the after tax impact of significant items and components of the statement of income on a per share basis before the impact of additional stock issuances. 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 — 2013

  $ 1.48  

Gross Margins

   
 
 

Electric segment

    0.24  

Gas segment

    0.01  

Other segment

    0.00  

Total Gross Margin

    0.25  

Operating expenses — electric segment

   
(0.09

)

Operating expenses — gas segment

    0.01  

Operating expenses — other segment

    0.00  

Maintenance and repairs

    (0.09 )

Depreciation and amortization

    (0.05 )

Loss on plant disallowance

    0.03  

Other taxes

    (0.03 )

AFUDC

    0.06  

Change in effective income tax rates

    0.01  

Other income and deductions

    (0.01 )

Dilutive effect on additional shares issues

    (0.02 )

Earnings Per Share — 2014

  $ 1.55  

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Fourth Quarter Results

        Earnings for the fourth quarter of 2014 were $11.1 million, or $0.26 per share, as compared to $15.2 million, or $0.35 per share, in the fourth quarter of 2013. Electric segment gross margins decreased during the quarter ending December 31, 2014 compared to the 2013 quarter, reflecting decreased demand in the fourth quarter of 2014 due to milder weather as compared to the fourth quarter of 2013 and increased operating and maintenance expenses.

2014 Activities

Regulatory Matters

        On August 29, 2014, we filed a request with the MPSC for changes in rates for our Missouri electric customers. We are seeking an annual increase in total revenue of approximately $24.3 million, or approximately 5.5%. The main cost drivers in the rate increase are the costs associated with the environmental retrofit project at our Asbury power plant (See Note 11 — New Construction of "Notes to Consolidated Financial Statements" under Item 8) that were incurred to comply with the Environmental Protection Agency's (EPA) rules governing the continued operation of the plant, increases in property taxes, increases in ongoing maintenance expenses and increases in Regional Transmission Organization transmission fees.

        On May 20, 2014, we filed a settlement agreement with the Arkansas Public Service Commission (APSC) for an increase of $1.375 million, or approximately 11%. A hearing was held on the settlement agreement on July 22, 2014. On September 16, 2014, the APSC issued an order approving the settlement with a modification that reduced the overall revenue increase to $1.367 million. The new rates were effective September 26, 2014. We had filed a request on December 3, 2013 with the APSC 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 December 5, 2014, we filed a request with the Kansas Corporation Commission (KCC) to implement an Environmental Cost Recovery Rider for costs associated with the new environmental facilities installed at our Asbury generating unit. We have requested an effective date of March 1, 2015 for the recovery rider.

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

Asbury In-service Criteria

        As part of our environmental Compliance Plan, discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8, we installed a scrubber, fabric filter and powder activated carbon injection system at our Asbury plant. The addition of this air quality control system (AQCS) equipment was completed in December 2014. Testing began in early November and all in-service testing was completed and results verified for the Asbury AQCS by December 15, 2014. The MPSC staff determined that as of December 15, 2014, the Asbury AQCS had met the in-service criteria.

Financing Activities

        On October 15, 2014, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 4.27% First Mortgage Bonds due December 1, 2044. The delayed settlement occurred on December 1, 2014. The bonds were issued under the EDE Mortgage. We utilized the proceeds from the sale of the bonds to refinance existing short-term indebtedness and for general corporate purposes.

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        On October 20, 2014, we entered into a new $200 million 5-year Credit Agreement replacing the former $150 million Third Amended and Restated Unsecured Credit Agreement dated January 17, 2012. This new agreement may be used for working capital, commercial paper back-up and general corporate purposes. The credit facility includes a $20 million swingline loan sublimit, a $20 million sublimit for letters of credit issuance and, subject to bank approval, a $75 million accordion feature and two one-year extensions of the credit facility's maturity date.

        For additional information, see Notes 5 and 6 of "Notes to Consolidated Financial Statements" under Item 8.

Day-Ahead Market

        The Southwest Power Pool (SPP) regional transmission organization (RTO) implemented a Day-Ahead Market, or Integrated Marketplace, on March 1, 2014 in which market participants buy and sell wholesale energy and reserves in both day-ahead and real-time markets through the operation of a single, consolidated SPP balancing authority. Through the IM, the SPP is able to coordinate next-day generation across the region and provide participants, including Empire, with greater access to economical energy. For additional information, see Note 3 "— Markets and Transmission" of "Notes to Consolidated Financial Statements" under Item 8.

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. On March 12, 2014, the MPSC issued an order approving our IRP, effective March 12, 2014.

Subsequent Events

        On November 4, 2008, Missouri voters approved the Clean Energy Initiative (Proposition C) which currently requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas, and Elk River Windfarm, LLC, located in Butler County, Kansas. Proposition C also requires that 2% of the energy from renewable energy sources must be solar; however, we believed that we were exempted by statute from the solar requirement. On January 20, 2013 the Earth Island Institute, d/b/a Renew Missouri, and others challenged our solar exemption by filing a complaint with the MPSC. The MPSC dismissed the complaint and Renew Missouri filed a notice of appeal seeking review by the Missouri Supreme Court. On February 10, 2015 the Missouri Supreme Court issued an opinion holding that the legislature had the authority to adopt the statute providing the exemption but reversed the MPSC's holding that the two laws could be harmonized. The statute providing the exemption (which was enacted in August 2008) was impliedly repealed by the adoption of Proposition C because it conflicted with the latter law. We believe the matter will return to the MPSC for further action. While we are not in a position to accurately estimate the impact of this requirement, we expect any future costs to be recoverable in rates.

RESULTS OF OPERATIONS

        The following discussion analyzes significant changes in the results of operations for the years 2014, 2013 and 2012.

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

 
  2014   2013   2012  

Electric

  $ 61.5   $ 58.6   $ 52.6  

Gas

    2.9     2.3     1.3  

Other

    2.7     2.5     1.8  

Net income

  $ 67.1   $ 63.4   $ 55.7  

Electric Segment

Overview

        Our electric segment income for 2014 was $61.5 million as compared to $58.6 million and $52.6 million for 2013 and 2012, respectively.

        Electric on-system operating revenues for 2014, 2013, and 2012 were comprised of the following customer classes:

 
  2014   2013   2012  

Residential

    43.4 %   43.9 %   43.5 %

Commercial

    31.6     31.3     32.2  

Industrial

    15.5     15.5     16.0  

Wholesale on-system

    4.1     3.9     3.8  

Miscellaneous sources*

    2.8     2.9     2.8  

Other electric revenues

    2.6     2.5     1.7  

*
Primarily other public authorities

Gross Margin

        As shown in the Electric Segment Operating Revenues and Gross Margin table below, electric segment gross margin, defined as electric revenues less fuel and purchased power costs, increased approximately $16.4 million during 2014 as compared to 2013 due to a full twelve months of increased Missouri electric rates that were effective April 1, 2013, increased demand resulting from weather impacts, higher commercial demand and an increase in average electric customer counts.

        The electric gross margin 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.

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KWh Sales

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

 
  kWh Sales  
Customer Class
  2014   2013   % Change(1)   2013   2012   % Change(1)  

Residential

    1,950.4     1,936.6     0.7 %   1,936.6     1,850.8     4.6 %

Commercial

    1,583.8     1,541.7     2.7     1,541.7     1,558.3     (1.1 )

Industrial

    1,031.6     1,015.5     1.6     1,015.5     1,028.4     (1.3 )

Wholesale on-system

    336.3     343.1     (2.0 )   343.1     353.1     (2.8 )

Other(2)

    128.0     129.4     (1.1 )   129.4     124.2     4.2  

Total on-system sales

    5,030.1     4,966.3     1.3     4,966.3     4,914.8     1.0  

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

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

        KWh sales for our on-system customers increased during 2014 as compared to 2013 primarily due to increased demand due to weather impacts, increased commercial demand and increased customer counts. Residential and commercial kWh sales increased 0.7% and 2.7%, respectively, primarily due to these weather impacts and increased customer counts. Industrial sales increased 1.6% during 2014 as compared to 2013 due to increased usage. On-system wholesale kWh sales decreased during 2014 as compared to 2013 reflecting the closure of a large dairy facility in Monett, Missouri during the second half of 2013. 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 2014 were 1.2% more than 2013 and 6.3% 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 2014 were 3.7% more than 2013 and 5.8% more than the 30-year average.

        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. 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 during the second half of 2013. Total heating degree days for 2013 were 31.7% more than 2012 and 5.0% more than the 30-year average. Total cooling degree days 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.

Revenues and Gross Margin

        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, and the associated fuel and purchased power

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expense (including a reconciliation of our actual fuel and purchased power expenditures to the fuel and purchased power expense shown on our statements of income) were as follows (dollars in millions):

 
  Electric Segment Operating Revenues and Gross Margin  
Customer Class
  2014   2013   % Change(1)   2013   2012   % Change(1)  

Residential

  $ 236.5   $ 227.7     3.9 % $ 227.7   $ 214.5     6.1 %

Commercial

    172.3     162.4     6.1     162.4     158.8     2.3  

Industrial

    84.7     80.5     5.3     80.5     78.8     2.2  

Wholesale on-system

    22.3     20.0     11.4     20.0     18.6     8.0  

Other(2)

    15.2     15.0     2.1     15.0     14.0     7.0  

Total on-system revenues

    531.0     505.6     5.0     505.6     484.7     4.3  

Off-system wholesale(3)

    3.2     15.5     (79.2 )   15.5     15.7     (1.3 )

SPP IM net revenues(3)

    41.9         100.0              

Total revenues from KWh sales

    576.1     521.1     10.6     521.1     500.4     4.1  

Miscellaneous revenues(4)

    14.3     13.2     8.2     13.2     8.5     55.2  

Total electric operating revenues

  $ 590.4   $ 534.3     10.5   $ 534.3   $ 508.9     5.0  

Water revenues

    2.1     2.1     (3.3 )   2.1     1.8     19.2  

Total electric segment operating revenues

  $ 592.5   $ 536.4     10.5   $ 536.4   $ 510.7     5.0  

Actual fuel and purchased power expenditures

  $ 165.2   $ 182.1     (9.3 ) $ 182.1   $ 173.6     4.9  

SPP IM net purchases(3)

    55.9         100.0              

Net fuel recovery and deferral

    (3.8 )   (3.6 )   6.2     (3.6 )   9.7     (137.1 )

SWPA amortization(5)

    (2.6 )   (2.8 )   (5.4 )   (2.8 )   (2.8 )   0.0  

Unrealized (gain)/loss on derivatives

    0.4     (0.3 )   (237.4 )   (0.3 )   (1.6 )   81.3  

Total fuel and purchased power expense per income statement

    215.1     175.4     22.6     175.4     178.9     (2.0 )

Total Gross Margin

  $ 377.4   $ 361.0     4.5   $ 361.0   $ 331.8     8.8  

(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)
The SPP IM was implemented on March 1, 2014. As of December 31, 2014, off-system revenues were effectively replaced by SPP IM activity. See "— Markets and Transmission" below for more information.

(4)
Miscellaneous revenues include transmission service revenues, late payment fees, renewable energy credit sales, rent, etc.

(5)
Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010, of which $12.9 million of the Missouri portion remains to be amortized as of December 31, 2014.

        Revenues for our on-system customers increased approximately $25.5 million (5.0%) during 2014 as compared to 2013. Rate changes, primarily the April 2013 Missouri rate increase, contributed an estimated $12.5 million to revenues. Weather and other volumetric related factors increased revenues an estimated $4.6 million in 2014 as compared to 2013. Improved customer counts increased revenues an estimated $1.6 million. A $6.8 million increase in fuel recovery revenue (offset by a corresponding change included in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during 2014 as compared to 2013, positively impacted revenues.

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        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 volumetric 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 included 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.

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

SPP Integrated Marketplace (IM) and Off-System Electric Transactions.

        In the past, in addition to sales to our own customers, we also sold power to other utilities as available, including (since 2007) through the SPP Energy Imbalance Services (EIS) market. However, on March 1, 2014, the SPP RTO implemented a Day-Ahead Market, or Integrated Marketplace, which replaces the real-time EIS market. SPP IM activity is settled for each market participant in various time increments. When we sell more generation to the market than we purchase, based on the prescribed time increments, the net sale and corresponding net revenue is included as part of electric revenues. When we purchase more generation from the market than we sell, based on the prescribed time increments, the net purchase cost is recorded as a component of fuel and purchased power on the financial statements. See the Electric Segment Operating Revenues and Gross Margin table above and "— Markets and Transmission" below. The majority of our market activity sales margin is included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and our transmission rider in our Arkansas jurisdiction. As a result, nearly all of the market activity sales margin flows back to the customer and has little effect on gross margin or net income.

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Operating Revenue Deductions — Other Than Fuel and Purchased Power

        The table below shows regulated operating expense increases/(decreases) during 2014 as compared to 2013 and during 2013 as compared to 2012.

(in millions)
  2014 vs. 2013   2013 vs. 2012  

Transmission expense(1)

  $ 5.0   $ 4.4  

Distribution expense

    1.0     0.4  

General labor expense

    2.3     2.0  

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

    (1.2 )   1.2  

Customer accounts expense

    (0.3 )   0.9  

Steam power other operating expense

    0.2     0.6  

Regulatory commission expense

    (0.1 )   0.5  

Other power supply expense

    0.1     0.7  

Hydro power operating expense

    0.3     (0.4 )

Employee pension expense

    (0.1 )   0.5  

Employee health care expense

    (1.0 )   0.2  

Property insurance

    0.1     0.5  

Customer assistance expense

    0.7     0.4  

Professional services

    (0.3 )   (0.5 )

Banking fees

    (0.1 )   (0.7 )

Injuries and damages

    (0.1 )   0.0  

Other miscellaneous accounts (netted)

    (0.3 )   0.4  

TOTAL

  $ 6.2   $ 11.1  

(1)
Mainly due to increased SPP transmission charges.

(2)
Regulatory reversal of a prior period gain in 2013 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 2014 as compared to 2013 and during 2013 as compared to 2012.

(in millions)
  2014 vs. 2013   2013 vs. 2012  

Distribution maintenance expense

  $ 2.8   $ 0.4  

Transmission maintenance expense

    0.3     0.7  

Maintenance and repairs expense at the Energy Center

    1.3     0.0  

Maintenance and repairs expense at the Asbury plant

    1.2     (0.9 )

Maintenance and repairs expense to SLCC

    (0.6 )   (1.1 )

Maintenance and repairs expense at the State Line plant

    (0.3 )   0.5  

Maintenance and repairs expense at the Iatan plant

    0.2     0.4  

Maintenance and repairs expense at the Plum Point plant

    (0.1 )   0.4  

Maintenance and repairs expense at the Riverton plant — steam

    0.1     (0.2 )

Maintenance and repairs expense at the Riverton plant — gas

    0.7     (0.5 )

Iatan deferred maintenance expense

    0.1     0.5  

Hydro maintenance expense

    (0.1 )   0.2  

Other miscellaneous accounts (netted)

    0.3     0.0  

TOTAL

  $ 5.9   $ 0.4  

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        Depreciation and amortization expense increased approximately $3.9 million (6.1%) during 2014 as compared to 2013 and approximately $8.3 million (15.1%) during 2013 as compared to 2012, primarily due to increased depreciation rates resulting from our 2013 Missouri electric rate case settlement and increased plant in service.

        Other taxes increased approximately $1.8 million in 2014 and $3.3 million in 2013 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)
  2014   2013   % Change   2013   2012   % Change  

Residential

    2.76     2.74     0.6 %   2.74     2.01     36.4 %

Commercial(1)

    1.27     1.35     (5.5 )   1.35     1.05     28.5  

Industrial

    0.06     0.07     (13.5 )   0.07     0.06     23.9  

Other(2)

    0.04     0.04     3.1     0.04     0.02     44.8  

Total retail sales

    4.13     4.20     (1.6 )   4.20     3.14     33.6  

Transportation sales(1)

    4.92     4.53     8.6     4.53     4.25     6.6  

Total gas operating sales

    9.05     8.73     3.7     8.73     7.39     18.1  

(1)
Several commercial customers transferred to transportation customers during 2014, reflecting the decrease in commercial sales and the increase in transportation sales.

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

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

 
  Operating Revenues and Cost of Gas Sold  
($ in millions)
  2014   2013   % Change   2013   2012   % Change  

Residential

  $ 32.9   $ 31.6     4.2 % $ 31.6   $ 24.7     27.6 %

Commercial(1)

    13.6     13.7     (0.2 )   13.7     10.8     26.6  

Industrial

    0.5     0.5     4.2     0.5     0.5     11.0  

Other(2)

    0.4     0.3     6.8     0.3     0.3     38.7  

Total retail revenues

  $ 47.4   $ 46.1     2.9   $ 46.1   $ 36.3     27.1  

Other revenues

    0.4     0.4     5.0     0.4     0.3     7.5  

Transportation revenues(1)

    4.0     3.5     12.9     3.5     3.2     10.0  

Total gas operating revenues

  $ 51.8   $ 50.0     3.6   $ 50.0   $ 39.8     25.6  

Cost of gas sold

    27.0     25.8     4.8     25.8     18.6     38.4  

Gas segment gross margins

  $ 24.8   $ 24.2     2.4   $ 24.2   $ 21.2     14.3  

(1)
Several commercial customers transferred to transportation customers during 2014, reflecting the decrease in commercial revenues and the increase in transportation revenues.

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

        Gas retail sales decreased 1.6% during 2014 as compared to 2013 due to commercial and industrial customers transferring to transportation service. Gas retail revenues increased 2.9% reflecting increased usage by the weather sensitive residential class due to colder weather in 2014 as compared to 2013 and

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higher gas costs recovered in revenues. Heating degree days were 1.7% higher in 2014 than 2013 and 10.2% higher than the 30-year average. Our gas segment gross margin (defined as gas operating revenues less cost of gas in rates) for 2014 increased $0.6 million compared to 2013.

        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 margin for 2013 increased $3.0 million compared to 2012.

        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, 2014, we had unrecovered purchased gas costs of $0.6 million recorded as a non-current regulatory asset and $0.5 million recorded as a current regulatory liability as compared to 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 of December 31, 2013.

Operating Revenue Deductions

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

(in millions)
  2014 vs. 2013   2013 vs. 2012  

Distribution operation expense

  $ (0.2 ) $ 0.2  

Transmission operation expense

    0.1     (0.1 )

Customer accounts expense

    (0.6 )   0.3  

Miscellaneous

    (0.1 )   0.1  

TOTAL

  $ (0.8 ) $ 0.5  

        Depreciation and amortization expense increased approximately $0.1 million (1.4%) during 2014 and increased approximately $0.1 million (3.1%) during 2013.

        Our gas segment had net income of $2.9 million in 2014 as compared to $2.3 million in 2013 and $1.3 million in 2012.

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:

 
  2014   2013   2012  

Consolidated provision for income taxes

  $ 39.2   $ 37.5   $ 34.2  

Consolidated effective federal and state income tax rates

    36.9 %   37.1 %   38.0 %

        The effective tax rate for 2014 is lower than 2013 and 2012 primarily due to higher equity AFUDC income in 2014 compared with 2013 and 2012.

        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.

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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 2014 as compared to 2013 and 2012 reflecting construction for the environmental retrofit project at our Asbury plant and the Riverton 12 combined cycle project. See Note 1 of "Notes to Consolidated Financial Statements" under Item 8.

($ in millions)
  2014   2013   2012  

Allowance for equity funds used during construction

  $ 6.4   $ 3.8   $ 1.1  

Allowance for borrowed funds used during construction

    3.5     2.1     0.8  

Total AFUDC

  $ 9.9   $ 5.9   $ 1.9  

        Total interest charges on long-term and short-term debt for 2014, 2013 and 2012 are shown below. The changes in long-term debt interest for 2014 compared to 2013 and 2013 compared to 2012 reflect 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.

        Also, on October 15, 2014, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 4.27% First Mortgage Bonds due December 1, 2044. The delayed settlement occurred on December 1, 2014.

 
  Interest Charges
($ in millions)
 
 
  2014   2013   Change   2013   2012   Change  

Long-term debt interest

  $ 40.6   $ 40.3     0.7 % $ 40.3   $ 40.2     0.4 %

Short-term debt interest

    0.1     0.1     90.5     0.1     0.2     (68.2 )

Other interest

    1.0     1.1     (7.1 )   1.1     1.1     (2.1 )

Total interest charges

  $ 41.7   $ 41.5     0.6   $ 41.5   $ 41.5     0.0  

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.

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        The following table sets forth information regarding electric and water rate increases since January 1, 2012:

Jurisdiction
  Date
Requested
  Annual
Increase
Granted
  Percent
Increase
Granted
  Date
Effective

Arkansas — Electric

  December 3, 2013   $ 1,366,809     11.34 % September 26, 2014

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

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

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

MARKETS AND TRANSMISSION

Electric Segment

        Day Ahead Market:    On March 1, 2014, the SPP RTO implemented its Integrated Marketplace (IM) (or Day-Ahead Market), which replaced the Energy Imbalance Services (EIS) market. The SPP RTO created a single NERC-approved balancing authority (BA) that took over balancing authority responsibilities for its members, including Empire.

        As part of the IM, we and other SPP members submit generation offers to sell our power and bids to purchase power into the SPP market, with the SPP serving as a centralized dispatch of SPP members' generation resources. The SPP matches offers and bids based upon operating and reliability considerations. It is expected that 90% – 95% of all next day generation needed throughout the SPP territory will be cleared through this IM. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we will purchase from the IM. The activity for each market participant is settled in various time increments. When we sell more generation to the market than we purchase, based on the prescribed time increments, the net sale is included as part of electric revenues. When we purchase more generation from the market than we sell, based on the prescribed time increments, the net purchase is recorded as a component of fuel and purchased power on our financial statements. The net financial effect of these IM transactions is included in our fuel adjustment mechanisms and therefore has little impact on gross margin.

        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 unsecured revolving credit facility) and borrowings from our unsecured revolving credit facility. Historically, we have also successfully raised funds, as needed, 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 believe the cash provided by operating activities, together with the amounts available to us under our credit facilities and the issuance of debt and equity securities, 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

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needs through the next several years. See "— Capital Requirements and Investing Activities" below for further information.

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

Summary of Cash Flows

 
  Fiscal Year  
(in millions)
  2014   2013   2012  

Cash provided by/(used in):

                   

Operating activities

  $ 151.2   $ 157.5   $ 159.1  

Investing activities

    (215.3 )   (153.3 )   (136.9 )

Financing activities

    62.7     (4.1 )   (24.2 )

Net change in cash and cash equivalents

  $ (1.4 ) $ 0.1   $ (2.0 )

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.

        2014 compared to 2013.    In 2014, our net cash flows provided from operating activities was $151.2 million, a decrease of $6.2 million, or 4.0%, from 2013. This change was primarily a result of:

    Increase in net income — $3.7 million.

    Increased plant depreciation — $3.4 million due to additions.

    Changes in fuel adjustments and other regulatory amortizations — $8.4 million.

    Changes in pension amortizations — $3.9 million.

    Tax timing differences as a result of bonus depreciation being reinstated and tangible property regulation changes — $13.4 million.

    Working capital changes for accounts receivable, accounts payable and other current assets and liabilities — $(33.6) million.

    Increase in equity AFUDC mostly attributable to higher construction work in progress balances — $(2.6) million.

        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 change was primarily a result of:

    Increase in net income — $7.8 million.

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    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.

Capital Requirements and Investing Activities

        Our net cash flows used in investing activities increased $62.0 million from 2013 to 2014. The increase was primarily the result of an increase in new generation capital expenditures related to the Riverton 12 combined cycle construction.

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

        Our capital expenditures totaled approximately $222.8 million, $160.2 million, and $146.3 million in 2014, 2013 and 2012, respectively.

        A breakdown of these capital expenditures for 2014, 2013 and 2012 is as follows:

 
  Capital Expenditures  
(in millions)
  2014   2013   2012  

Distribution and transmission system additions

  $ 57.7   $ 58.5   $ 63.3  

New generation — Riverton 12 combined cycle

    77.5     13.2     0.6  

Additions and replacements — electric plant

    61.4     61.8     46.9  

Storms

    2.3     1.0     5.0  

Transportation

    3.6     4.5     3.7  

Gas segment additions and replacements

    7.1     4.1     3.3  

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

    11.0     14.7     20.7  

Subtotal

  $ 220.6   $ 157.8   $ 143.5  

Non-regulated capital expenditures (primarily fiber optics)

    2.2     2.4     2.8  

Subtotal capital expenditures incurred(2)

  $ 222.8   $ 160.2   $ 146.3  

Adjusted for capital expenditures payable(3)

    (9.4 )   (5.4 )   (9.3 )

Total cash outlay

  $ 213.4   $ 154.8   $ 137.0  

(1)
Other includes equity AFUDC of $(6.4) million, $(3.9) million and $(1.1) million for 2014, 2013 and 2012, respectively. Also included are insurance proceeds of $(7.8) million for 2013.

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

(3)
The amount of expenditures 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 50%, 74% and 85% of our cash requirements for capital expenditures for 2014, 2013 and 2012, 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 2015, 2016 and 2017 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
  2015   2016   2017   Total  

Riverton Unit 12 combined cycle conversion

  $ 62.5   $ 17.1   $ 0.0   $ 79.6  

Asbury environmental upgrades

    2.3     0.0     1.1     3.4  

Electric distribution system additions

    40.8     37.0     45.9     123.7  

Electric transmission facilities

    33.1     30.3     25.6     89.0  

Other

    34.0     24.8     32.9     91.7  

Total

  $ 172.7   $ 109.2   $ 105.5   $ 387.4  

        Our estimated total capital expenditures (excluding AFUDC) for 2018 and 2019 are $157.5 million and $157.4 million, respectively.

        We estimate that internally generated funds will provide approximately 78% of the funds required in 2015 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

2014 compared to 2013.

        Our net cash flows provided by financing activities was $62.7 million in 2014 as compared to $4.1 million used in financing activities in 2013, an increase of $66.7 million, primarily due to the following:

    Issuance of $40.0 million in short-term debt in 2014 as compared to repayment of $20.0 million in short-term debt in 2013.

    Issuance of $60.0 million of first mortgage bonds in 2014 compared to $150.0 million issued in 2013.

    No repayment of senior notes in 2014 compared to $98.0 million of senior notes repaid in 2013.

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.

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    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.

Shelf Registration.

        We have a $200.0 million shelf registration statement with the SEC, effective December 13, 2013, covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. As of December 31, 2014, $200.0 million remains available for issuance under this shelf registration statement. However, as a result of our regulatory approvals, of the original $200.0 million, $150.0 million was available for first mortgage bonds with $90.0 million remaining available after the issuance of $60 million in first mortgage bonds on December 1, 2014. We plan to use proceeds from offerings made pursuant to this shelf to fund capital expenditures, refinance existing debt or general corporate needs during the three-year effective period.

Credit Agreements.

        On October 20, 2014, we entered into a new $200 million 5-year Credit Agreement replacing the former $150 million Third Amended and Restated Unsecured Credit Agreement dated January 17, 2012. This new agreement may be used for working capital, commercial paper back-up and general corporate purposes. The credit facility includes a $20 million swingline loan sublimit, a $20 million sublimit for letters of credit issuance and, subject to bank approval, a $75 million accordion feature and two one-year extensions of the credit facility's maturity date. There were no outstanding borrowings under this agreement at December 31, 2014. However $44.0 million was used as of December 31, 2014 to back up our outstanding commercial paper. See Note 6 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding this agreement and our unsecured line of credit.

EDE Mortgage Indenture.

        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 principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $357.0 million of new first mortgage bonds. 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, 2014 would permit us to issue approximately $615.9 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, 2014, we had retired bonds and net property additions which would enable the issuance of at least $952.5 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2014, 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 Indenture of Mortgage and Deed of Trust of The Empire District Gas Company (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

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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, 2014, this test would allow us to issue approximately $19.7 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.

Credit Ratings

        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. Standard & Poor's and Fitch reaffirmed our ratings on March 20, 2014 and September 30, 2014, respectively.

        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.

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CONTRACTUAL OBLIGATIONS

        Set forth below is information summarizing our contractual obligations as of December 31, 2014. 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 2015 – 2019 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)

  $ 800.0   $   $ 25.0   $ 90.0   $ 685.0  

Interest on long-term debt

    703.5     41.7     81.5     70.3     510.0  

Short-term debt

    44.0     44.0              

Capital lease obligations

    5.8     0.6     1.1     1.1     3.0  

Operating lease obligations(2)

    3.2     0.7     1.4     1.1      

Electric purchase obligations(3)

    472.4     52.9     77.7     61.3     280.5  

Gas purchase obligations(4)

    90.7     13.5     19.3     19.3     38.6  

Open purchase orders

    114.9     29.5     85.4          

Postretirement benefit obligation funding

    17.2     5.0     7.1     5.1      

Pension benefit funding

    52.3     12.8     23.8     15.7      

Other long-term liabilities(5)

    3.0     0.1     0.3     0.3     2.3  

TOTAL CONTRACTUAL OBLIGATIONS

  $ 2,307.0   $ 200.8   $ 322.6   $ 264.2   $ 1,519.4  

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

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

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

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        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, 2014, 2013 and 2012:

(in millions, except per share amounts)
  2014   2013   2012  

Diluted earnings per share

  $ 1.55   $ 1.48   $ 1.32  

Dividends paid per share

  $ 1.025   $ 1.005   $ 1.00  

Total dividends paid

  $ 44.4   $ 43.0   $ 42.3  

Retained earnings year-end balance

  $ 90.3   $ 67.6   $ 47.1  

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

        In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. The EDE Mortgage permits the payment of any dividend or distribution on, or purchase of, shares of our 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.

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        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. See Note 1 and Note 7 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        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 obligations 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 7 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 coul