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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, 2015

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, 2015, was approximately $952,425,061.

         As of February 1, 2016, 43,860,337 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 28, 2016
  Part of Item 10 of Part III
All of Item 11 of Part III
Part of Item 12 of Part III
All of Item 13 of Part III
All of Item 14 of Part III

   


Table of Contents


TABLE OF CONTENTS

 
   
  Page

 

Forward Looking Statements

  3

PART I

ITEM 1.

 

BUSINESS

  5

 

General

  5

 

Electric Generating Facilities and Capacity

  6

 

Gas Facilities

  8

 

Construction Program

  8

 

Fuel and Natural Gas Supply

  9

 

Employees

  11

 

Electric Operating Statistics

  12

 

Gas Operating Statistics

  13

 

Executive Officers and other Officers of Empire

  14

 

Regulation

  14

 

Environmental Matters

  15

 

Conditions Respecting Financing

  16

 

Our Web Site

  17

ITEM 1A.

 

RISK FACTORS

  17

ITEM 1B.

 

UNRESOLVED STAFF COMMENTS

  25

ITEM 2.

 

PROPERTIES

  25

 

Electric Segment Facilities

  25

 

Gas Segment Facilities

  27

 

Other Segment

  27

ITEM 3.

 

LEGAL PROCEEDINGS

  27

ITEM 4.

 

MINE SAFETY DISCLOSURES

  27

PART II

ITEM 5.

 

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

  28

ITEM 6.

 

SELECTED FINANCIAL DATA

  30

ITEM 7.

 

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

  30

 

Executive Summary

  30

 

Results of Operations

  36

 

Rate Matters

  43

 

Markets and Transmission

  44

 

Liquidity and Capital Resources

  44

 

Contractual Obligations

  50

 

Dividends

  50

 

Off-Balance Sheet Arrangements

  51

 

Critical Accounting Policies

  51

 

Recently Issued Accounting Standards

  54

ITEM 7A

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  54

ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  57

ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

  127

ITEM 9A.

 

CONTROLS AND PROCEDURES

  127

ITEM 9B.

 

OTHER INFORMATION

  127

PART III

ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

  128

ITEM 11.

 

EXECUTIVE COMPENSATION

  128

ITEM 12.

 

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

  128

ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

  129

ITEM 14.

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES

  129

PART IV

ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

  130

 

SIGNATURES

  136

Table of Contents

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 the pending acquisition of Empire by Liberty Utilities (Central) Co. (Liberty), a subsidiary of Algonquin Power & Utilities Corp. (APUC) (the Merger), 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 impact of energy efficiency and alternative energy sources, including solar;

    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;

    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;

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    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;

    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;

    other circumstances affecting anticipated rates, revenues and costs; and

    certain risks and uncertainties associated with the Merger, including, without limitation:

    the risk that Empire may be unable to obtain shareholder approval for the proposed transaction or that Liberty or Empire may be unable to obtain governmental and regulatory approvals required for the proposed transaction, or required governmental and regulatory approvals may delay the proposed transaction;

    the risk that any other condition to the closing of the proposed transaction may not be satisfied;

    the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement or could otherwise cause the failure of the Merger to close;

    the failure of Liberty or APUC to obtain any financing necessary to complete the merger;

    the outcome of any legal proceedings, regulatory proceedings or enforcement matters that may be instituted against Empire and others relating to the merger agreement;

    the receipt of an unsolicited offer from another party to acquire assets or capital stock of Empire that could interfere with the proposed Merger;

    the timing to consummate the proposed transaction;

    disruption from the proposed transaction making it more difficult to maintain relationships with customers, employees, regulators or suppliers;

    the diversion of management time and attention on the transaction;

    the amount of costs, fees, expenses, and charges related to the Merger; and

    the effect and timing of changes in laws or in governmental regulations (including environmental laws and regulations) that could adversely affect our participation in the Merger.

        All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. Additional risks and uncertainties will be discussed in the proxy statement and other materials that Empire will file with the SEC in connection with the Merger. 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 2015 were derived as follows:

Electric segment sales*

          91.7 %

On-system revenues

    86.6 %      

SPP IM revenues

    2.5        

Other revenues

    2.3        

Gas segment sales

          6.9  

Other segment sales

          1.4  

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

        On-system electric revenues consist of residential, commercial, industrial, wholesale on-system and other (which includes street lighting, other public authorities and interdepartmental usage).

        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, 2015, our electric operations served approximately 170,000 customers.

        Our retail electric revenues for 2015 by jurisdiction were derived as follows:

Missouri

    89.0 %

Kansas

    4.8  

Oklahoma

    2.8  

Arkansas

    3.4  

        We supply electric service at retail to 119 incorporated communities as of December 31, 2015, 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 39% of our electric operating revenues in 2015 were derived from incorporated communities with franchises having at least ten years remaining and approximately 31% 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 41.7%, 31.1%, and 15.9%, respectively, of our electric operating revenues in 2015.

        Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2015 accounted for approximately 2.4% of electric revenues. No single retail customer accounted for more than 1.9% of electric revenues in 2015.

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        Our gas operations serve customers in northwest, north central and west central Missouri. As of December 31, 2015, our gas operations served approximately 43,200 customers. We provide natural gas distribution to 48 communities and 434 transportation customers as of December 31, 2015. 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 franchises have 10 years or more remaining on their term and 27 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 2015 were derived as follows:

Residential

    63.0 %

Commercial

    25.6  

Industrial

    0.8  

Transportation

    8.9  

Miscellaneous

    1.7  

        No single retail customer accounted for more than 1% of gas revenues in 2015.

        Our other segment consists of our fiber optics business. As of December 31, 2015, we have 99 fiber customers.

Electric Generating Facilities and Capacity

        At December 31, 2015, our generating plants consisted of:

Plant
  Capacity
(megawatts)(1)
  Primary Fuel

State Line Combined Cycle (60% ownership)

    295 (2) Natural Gas

Riverton — Natural Gas

    177 (3) Natural Gas

Empire Energy Center

    257   Natural Gas

State Line Unit No. 1

    96   Natural Gas

Asbury

    198   Coal

Iatan (12% ownership)

    191 (2) Coal

Plum Point Energy Station (7.52% ownership)

    50 (2) Coal

Ozark Beach

    16   Hydro

TOTAL

    1,280    

(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)
Does not include the combined cycle portion of Riverton Unit 12 as it was not yet in operation as of December 31, 2015.

        Our generating capacity consists of 64.4% natural gas, 34.3% coal and 1.3% 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 agreement, which expires in 2039, 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

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also own, through an undivided interest, 50 megawatts of the unit's capacity. We had the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the Missouri Public Service Commission (MPSC) on July 1, 2013. We did not exercise this option by the March 2015 notification deadline in the contract.

        We have a long-term purchased power agreement, which expires in 2028, 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 long-term contract, which expires in 2025, 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
 

2016

    86     1374 (2)   1460 (2)

2017

    86     1374     1460  

2018

    86     1374     1460  

2019

    86     1374     1460  

2020

    86     1374     1460  

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

(2)
Reflects the 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.

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Gas Facilities

        At December 31, 2015, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,189 miles of distribution mains.

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

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

        Our all-time peak of 73,280 mcfs was established on January 7, 2010.

Construction Program

        Total property additions (including construction work in progress but excluding AFUDC) for the three years ended December 31, 2015, totaled $526.7 million and retirement expenditures during the same period totaled $23.0 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 $164.2 million in 2015 and for the next three years are estimated for planning purposes to be as follows:

 
  Estimated Capital Expenditures
(amounts in millions)
 
 
  2016   2017   2018   Total  

New electric generating facilities:

                         

Riverton Unit 12 combined cycle conversion

  $ 11.7   $ 0.0   $ 0.0   $ 11.7  

Additions to existing electric generating facilities:

                         

Asbury

    2.6     3.9     10.0     16.5  

Other

    13.7     17.8     25.2     56.7  

Electric transmission facilities

    23.3     29.6     26.2     79.1  

Electric distribution system additions

    46.7     40.5     62.0     149.2  

General and other additions

    10.9     8.3     28.9     48.1  

Gas system additions

    4.1     4.1     5.0     13.2  

Non-regulated additions

    2.1     2.1     2.1     6.3  

TOTAL

  $ 115.1   $ 106.3   $ 159.4   $ 380.8  

        Construction expenditures for additions to our transmission and distribution systems constitute the majority of the projected capital expenditures for the three-year period listed above beyond routine capital expenditures. Customer reliability, communication and efficiency projects comprise $15 million of the 2018 general and other additions projection. Our estimated total capital expenditures (excluding AFUDC) for 2019 and 2020 are $150.9 million and $114.1 million, respectively.

        Future capital expenditure needs are reviewed regularly and are subjected to our annual capital budget prioritization process, wherein projects are ranked by type and urgency based on a variety of factors culminating in a 5-year capital expenditure plan. (See Item 7, "Managements' Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources" for detail regarding our future estimated capital expenditures). Projects evaluated during the capital budget prioritization process include, but are not limited to, those for capacity needs, replacement of aged infrastructure and other projects to improve and/or enhance safety and reliability. 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

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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."

Fuel and Natural Gas Supply

Electric Segment

        Our total system output for 2015 and 2014, based on kilowatt-hours generated, was as follows:

 
  2015   2014  

Steam generation units — coal

    50.2 %   47.5 %

Combustion turbine generation units — natural gas

    26.6     26.5  

Hydro generation

    0.9     1.2  

Purchased power — wind

    16.7     18.2  

Purchased power — other

    5.6     6.6  

        Below are the total fuel requirements for our generating units in 2015 and 2014 (based on kilowatt-hours generated):

 
  2015   2014  

Coal

    65.0 %   63.7 %

Natural gas

    34.6     35.8  

Fuel oil

    0.3     0.4  

Tire derived fuel

    0.1     0.1  

        Our Asbury Plant is fueled primarily by coal with oil being used as start-up fuel. In 2015, Asbury burned a coal blend consisting of approximately 93.9% Western coal (Powder River Basin) and 6.1% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2015, we had sufficient coal on hand to supply full load requirements at Asbury for 112 – 135 days, as compared to 44 – 77 days as of December 31, 2014, depending on the actual blend ratio. The inventory increased during 2015 as low natural gas prices resulted in lower coal usage.

        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
 

2016

    100 %

2017

    46 %

2018

    23 %

        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 90% of Iatan's requirements

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for 2016, 60% for 2017, 35% for 2018 and 10% for 2019. 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. NRG Energy Services LLC is the operator of this plant. Plum Point Services Company, LLC (PPSC), the project management company acting on behalf of the joint owners, is responsible for arranging its fuel supply. PPSC has secured contracts for low sulfur Western coal in quantities sufficient to meet approximately 99% of Plum Point's requirements for 2016 and 47% 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.

        Our Riverton Plant is fueled primarily by natural gas with oil available as backup for Units 10 and 11. Unit 12 is fueled 100% by natural gas. Unit 7 was retired on June 30, 2014 and Unit 8 and Unit 9 were retired on June 30, 2015. Construction continued during the year to convert Unit 12 to a combined cycle unit. Based on kilowatt hours generated during 2015, 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 2015, 97.6% of the Energy Center generation was produced from natural gas and 99.4% of the State Line Unit 1 generation came from natural gas with the remainder being fuel oil. As of December 31, 2015, 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 and Westar Generating, Inc., a subsidiary of Westar Energy, Inc., share joint ownership of a nominal 500-megawatt combined cycle unit, SLCC, at the State Line Power Plant. We are responsible for the operation and maintenance of the SLCC Unit, and are entitled to 60% of the available capacity and are responsible for approximately 60% of its costs.

        We have firm transportation agreements with Southern Star Central Pipeline, Inc. which expire on July 30, 2017, for the transportation of natural gas to the SLCC. This date is adjusted for periods of contract suspension by us during SLCC outages. 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 on April 1, 2016. The reservation charge for this storage capacity is approximately $1.1 million annually. We currently have no plans to renew this contract.

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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
  2015   2014   2013  

Coal — Iatan

  $ 1.633   $ 1.738   $ 1.756  

Coal — Asbury

    2.229     2.363     2.432  

Coal — Plum Point

    2.124     2.314     2.123  

Natural Gas

    4.274     5.268     4.952  

Oil

    18.235     17.512     21.870  

Weighted average cost of fuel burned per kilowatt-hour generated

  $ 2.5460   $ 2.9700   $ 2.8074  

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   2015   2014   2013  

South

  Southern Star Central Gas Pipeline   $ 4.7267   $ 4.6986   $ 5.4998  

North

  Panhandle Eastern Pipe Line Company     5.2457     6.0201     5.9746  

Northwest

  ANR Pipeline Company     3.3223     4.8499     4.7589  

  Weighted average cost per mcf   $ 4.6065   $ 4.9564   $ 5.4949  

Employees

        At December 31, 2015, we had 749 full-time employees, including 49 employees of EDG. 320 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 ratified a new five-year agreement, effective December 2, 2013, which will extend through October 31, 2018. At December 31, 2015, 32 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)

 
  2015   2014   2013   2012   2011  

Electric Operating On-System Revenues (000's):

                               

Residential

  $ 230,571   $ 236,468   $ 227,656   $ 214,526   $ 221,687  

Commercial

    171,727     172,274     162,444     158,837     157,435  

Industrial

    88,185     84,734     80,497     78,786     78,925  

Public authorities(2)

    15,273     14,863     14,707     13,755     13,653  

Wholesale on-system

    18,032     22,326     20,036     18,555     19,140  

Interdepartmental

    444     388     229     197     201  

Total system

  $ 524,232   $ 531,053   $ 505,569   $ 484,656   $ 491,041  

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

                               

Steam

    2,478,188     2,407,914     2,813,441     2,865,037     2,805,744  

Hydro

    41,927     60,652     57,449     57,719     48,898  

Combustion turbine

    1,315,185     1,361,860     1,452,936     1,486,643     1,484,472  

Total generated

    3,835,300     3,830,426     4,323,826     4,409,399     4,339,114  

Purchased

    1,101,043     1,254,416     1,660,193     1,545,327     1,870,901  

Total generated and purchased

    4,936,343     5,084,842     5,984,019     5,954,726     6,210,015  

Interchange (net)

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

Total system output

    4,936,343     5,084,841     5,984,451     5,954,639     6,208,717  

Transmission by others losses(3)

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

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

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

Net (sales)/purchases(to)/from SPP IM(4)

    345,251     386,267              

Total native load

    5,281,594     5,370,950     5,314,638     5,233,311     5,452,111  

Maximum hourly system demand (Kw)

    1,149,000     1,162,000     1,080,000     1,142,000     1,198,000  

Owned capacity (end of period) (Kw)

    1,280,000     1,326,000     1,377,000     1,391,000     1,392,000  

Annual load factor (%)

    52.47     52.76     56.18     52.17     51.95  

Electric sales (000's of kWh):

                               

Residential

    1,836,255     1,950,416     1,936,603     1,850,813     1,982,704  

Commercial

    1,577,416     1,583,843     1,541,717     1,558,297     1,576,342  

Industrial

    1,064,481     1,031,555     1,015,492     1,028,416     1,022,765  

Public authorities(2)

    126,786     124,287     127,370     122,369     126,724  

Wholesale on-system

    330,787     336,314     343,045     353,075     364,866  

Total system

    4,935,725     5,026,415     4,964,227     4,912,970     5,073,401  

Wholesale off-system

            653,996     704,028     740,009  

SPP EIS Resettlements, Other(4)

        1,445              

Total Electric Sales

    4,935,725     5,027,860     5,618,223     5,616,998     5,813,410  

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

   
10,553
   
10,725
   
9,049
   
9,066
   
9,371
 

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

    335,316     332,365     341,362     311,275     369,339  

Wholesale off-system(4)

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

Total Native Load

    5,281,594     5,370,950     5,314,638     5,233,311     5,452,111  

Customers (average number):

                               

Residential

    142,555     141,838     141,376     140,602     139,641  

Commercial

    24,311     24,146     24,080     24,036     24,155  

Industrial

    352     346     345     353     357  

Public authorities(2)

    2,082     2,175     2,214     2,124     2,021  

Wholesale on-system

    4     4     4     4     4  

Total System

    169,304     168,509     168,019     167,119     166,178  

Wholesale off-system

    0     4     22     22     25  

Total

    169,304     168,513     168,041     167,141     166,203  

Average annual sales per residential customer (kWh)

    12,881     13,751     13,698     13,163     14,199  

Average annual revenue per residential customer

  $ 1,617   $ 1,667   $ 1,610   $ 1,526   $ 1,588  

Average residential revenue per kWh

    12.56 ¢   12.12 ¢   11.76 ¢   11.59 ¢   11.18 ¢

Average commercial revenue per kWh

    10.89 ¢   10.88 ¢   10.54 ¢   10.19 ¢   9.99 ¢

Average industrial revenue per kWh

    8.28 ¢   8.21 ¢   7.93 ¢   7.66 ¢   7.72 ¢

(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 sales and 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)

 
  2015   2014   2013   2012   2011  

Gas Operating Revenues (000's):

                               

Residential

  $ 26,282   $ 32,873   $ 31,561   $ 24,744   $ 28,999  

Commercial

    10,698     13,640     13,673     10,797     12,506  

Industrial

    315     537     515     464     682  

Public authorities

    287     365     342     247     324  

Total retail sales revenues

    37,582     47,415     46,091     36,252     42,511  

Miscellaneous(2)

    421     457     435     400     464  

Transportation revenues

    3,699     3,970     3,515     3,197     3,455  

Total Gas Operating Revenues

  $ 41,702   $ 51,842   $ 50,041   $ 39,849   $ 46,430  

Maximum Daily Flow (mcf)

    66,508     72,912     60,118     58,281     67,789  

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

                               

Residential

    2,219     2,760     2,744     2,012     2,560  

Commercial

    1,045     1,275     1,349     1,050     1,268  

Industrial

    38     62     72     58     102  

Public authorities

    28     37     35     23     33  

Total retail sales

    3,330     4,134     4,200     3,143     3,963  

Transportation sales

    4,453     4,918     4,528     4,249     4,528  

Total gas operating and transportation sales

    7,783     9,052     8,728     7,392     8,491  

Company use(3)

    2     2     2     2     4  

Transportation sales (cash outs)

                     

Mcf losses

    35     68     96     27     (47 )

Total system sales

    7,820     9,122     8,826     7,421     8,448  

Customers (average number):

                               

Residential

    37,484     37,572     37,777     37,897     38,051  

Commercial

    4,857     4,872     4,917     4,921     4,951  

Industrial

    20     22     24     23     26  

Public authorities

    143     138     140     138     136  

Total retail customers

    42,504     42,604     42,858     42,979     43,164  

Transportation customers

    434     422     340     326     311  

Total gas customers

    42,938     43,026     43,198     43,305     43,475  

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

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

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

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Executive Officers and Other Officers of Empire

        The names of our officers, their ages and years of service with Empire as of December 31, 2015, positions held during the past five years and effective dates of such positions are presented below. All of 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
12/31/15
  Positions With the Company   With the
Company
Since
  Officer
Since
 

Bradley P. Beecher

    50  

President and Chief Executive Officer (2011). Executive Vice President (2011)

    2001     2001  

Laurie A. Delano

    60  

Vice President — Finance and Chief Financial Officer, (2011)

    2002     2005  

Kelly S. Walters

    50  

Vice President and Chief Operating Officer — Electric (2011)

    2001     2006  

Ronald F. Gatz

    65  

Vice President and Chief Operating Officer — Gas (2006)

    2001     2001  

Blake Mertens

    38  

Vice President — Energy Supply and Delivery Operations (2015), Vice President — Energy Supply (2011)

    2001     2011  

Brent Baker(1)

    37  

Vice President — Customer Service, Transmission and Engineering (2015), Director of Customer Service (2011)

    2003     2015  

Robert W. Sager

    41  

Controller, Assistant Secretary, Assistant Treasurer and Principal Accounting Officer (2011)

    2006     2011  

Dale W. Harrington(2)

    54  

Corporate Secretary and Director of Investor Relations (2015), Director of Investor Relations and Assistant Secretary (2014), Director of Investor Relations (2014), Director of Financial Services (2011)

    2002     2014  

Mark T. Timpe(3)

    56  

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

    2014     2014  

(1)
Brent A. Baker was elected Vice-President — Customer Service, Transmission and Engineering effective March 1, 2015, succeeding Martin O. Penning who retired from his position as Vice-President — Commercial Operations effective February 28, 2015.

(2)
Dale W. Harrington was elected Secretary effective May 1, 2015, succeeding Janet S. Watson who retired from her position as Secretary effective April 30, 2015.

(3)
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.

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

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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 2015 were comprised of the following:

Retail customers

    91.5 %

Sales subject to FERC jurisdiction

    5.1  

SPP market revenues (not allocated to the jurisdictions)

    2.7  

Miscellaneous sources

    0.7  

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

Missouri

    89.0 %

Kansas

    4.8  

Oklahoma

    2.8  

Arkansas

    3.4  

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

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

Gas Segment

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

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

Environmental Matters

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

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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 $297.0 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. 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. The annual interest coverage requirement and retired bonds or 60% of net property additions tests would permit the issuance of more than $297.0 million of new first mortgage bonds; however, as discussed above, we are otherwise limited to the issuance of no more than $297.0 million of new first mortgage bonds. As of December 31, 2015, 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 Indenture of Mortgage and Deed of Trust of The Empire District Gas Company, 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, 2015, this test would allow us to issue approximately $19.5 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%. As of December 31, 2015, we are in compliance with all restrictive covenants of the EDG Mortgage.

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

        The primary drivers of our electric operating margin (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. Of the factors driving margin, 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 commitments 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 based upon operating and reliability considerations. The SPP reports that approximately 90% – 95% of all next day generation needed throughout the SPP territory is being cleared through the 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 wholly and jointly owned facilities, and those of the SPP and other SPP member companies, 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:

 
  Moody's   Standard & Poor's  

Corporate Credit Rating

    Baa1     BBB  

EDE First Mortgage Bonds

    A2     A-  

Senior Notes

    Baa1     BBB  

Commercial Paper

    P-2     A-2  

Outlook

    Stable     Negative  

        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 commercial paper program or 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), 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. 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 $380.8 million. This includes expenditures for environmental upgrades to our existing facilities and additions to our transmission and distribution systems. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than planned, the scope and timing of projects may change, and other events beyond our control may occur that may materially affect the schedule, budget, cost and performance of projects. To the extent the completion of projects is delayed, we expect that the timing of receipt of increases in base rates reflecting our investment in such projects will be correspondingly delayed.

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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 $115.1 million in 2016. 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 2015, our net pension and OPEB liability decreased $12.4 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.

Empire and its subsidiaries will be subject to business uncertainties and contractual restrictions while the Merger is pending that could adversely affect our financial results.

        Uncertainty about the effect of the Merger on employees or vendors and others may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair Empire and its subsidiaries' ability to attract, retain and motivate key personnel until the Merger is completed, and could cause vendors and others that deal with us to seek to change existing business relationships. Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as current employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key

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employees depart or fail to accept employment with Empire or its subsidiaries due to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our business operations and financial results could be adversely affected.

        We expect that matters relating to the Merger, including cooperation with APUC's financing and integration-related issues will place a significant burden on management, employees and internal resources, which could otherwise have been devoted to other business opportunities. The diversion of management time on Merger-related issues could materially affect our financial results.

        In addition, the Merger Agreement restricts Empire and its subsidiaries, without Liberty's prior written consent, from taking specified actions until the Merger occurs or the Merger Agreement is terminated, including, without limitation: (i) making certain material acquisitions and dispositions of assets or businesses; (ii) making any capital expenditures in excess of specified amounts; (iii) incurring indebtedness, subject to certain exceptions; (iv) issuing equity or equity equivalents; and (v) paying quarterly cash dividends in excess of current levels. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to consummation of the Merger or termination of the Merger Agreement.

Failure to complete the Merger could negatively impact Empire and/or the market price of our common stock.

        There can be no assurance that the Merger will occur. Failure to complete the Merger may negatively impact the future trading price of our common stock. If the Merger is not completed, the market price of our common stock may decline to the extent that the current market price of our common stock reflects a market assumption that there is a high probability that the Merger will be completed. Additionally, if the Merger is not completed, we will have incurred significant costs, as well as the diversion of the time and attention of management. A failure to complete the Merger may also result in negative publicity, litigation against Empire or our directors and officers, and a negative impression of us in the investment community. The occurrence of any of these events individually or in combination could have a material adverse effect on our financial condition, results of operations and our stock price.

Empire and Liberty may be unable to obtain the required shareholder, governmental, regulatory, and other consents and approvals required to complete the Merger or, in order to receive such consents or approvals, the governmental or regulatory entities may impose restrictions or conditions that could cause a termination of the Merger Agreement.

        The closing of the Merger is subject to certain conditions, including, among others, (i) approval of Empire shareholders representing a majority of the outstanding shares of Empire common stock, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period and receipt of all required regulatory approvals and consents, including from the Federal Energy Regulatory Commission, the Federal Communications Commission, the Arkansas Public Service Commission, the Kansas Corporation Commission, the Missouri Public Service Commission, the Oklahoma Corporation Commission and the Committee on Foreign Investment in the United States, which approvals and consents shall not, individually or in the aggregate, have or be reasonably likely to have a material adverse effect on the business, properties, financial condition or results of operations of Liberty Utilities Co. and its subsidiaries (including for such purpose, Empire and its subsidiaries), taken as a whole, (iii) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (iv) the absence of any material adverse effect with respect to Empire and (v) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement. The shareholder, governmental, regulatory, and other consents and approvals required to consummate the Merger may not be obtained at all, or may not be obtained on the proposed terms and schedules as contemplated by the parties. A substantial delay in obtaining the required shareholder, governmental, regulatory, and other consents and approvals or the imposition of unfavorable terms,

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conditions or restrictions contained in such approvals or consents could prevent or delay the completion of the Merger. Additionally, if certain closing conditions are not satisfied prior to the outside date specified in the Merger Agreement, either Empire or Liberty could be permitted to terminate the Merger Agreement and not consummate the Merger.

In the event that the Merger Agreement is terminated prior to the completion of the Merger, we could incur significant transaction costs that could materially impact our financial performance and results of operations.

        In connection with entering into the Merger Agreement, Empire has incurred approximately $0.2 million of transaction costs as of December 31, 2015. We expect that the total transaction costs will be approximately $15 to $17 million, with approximately 50% payable in 2016 (assuming a 2017 closing date), of which approximately $4.5 million will be incurred in the first quarter of 2016. The Merger Agreement provides that upon termination of the Merger Agreement under certain specified circumstances, we will be required to pay Liberty a termination fee of $53.0 million. Any fees due as a result of termination could have a material adverse effect on our results of operations, financial condition, and our stock price.

Potential future litigation against Empire and our directors challenging the Merger may prevent the Merger from being completed within the anticipated timeframe.

        Empire and/or our directors may potentially be named as defendants in lawsuits filed on behalf of public shareholders challenging the Merger and potentially seeking, among other things, to enjoin the defendants from consummating the Merger on the agreed-upon terms. We will incur significant transaction costs, including legal, filing, printing, and other costs relating to any litigation. If a plaintiff in a potential lawsuit or any other litigation that may be filed is successful in obtaining an injunction prohibiting the parties from completing the Merger on the terms contemplated by the Merger Agreement, the injunction will cause us to incur significant expense and may prevent the completion of the Merger in the expected timeframe or altogether.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

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, 2015, we owned generating facilities with an aggregate generating capacity of 1,280 megawatts, reflecting the retirement of Riverton Unit 7 on June 30, 2014 and the retirement of Riverton Unit 8 and Unit 9 on June 30, 2015, but not including the combined cycle portion of Riverton Unit 12, which was not yet in operation as of December 31, 2015.

        The Asbury Plant, located near Asbury, Missouri, is a coal-fired generating station with a current generating capacity of 198 megawatts. In 2015, the plant accounted for approximately 15.5% of our owned generating capacity and accounted for approximately 28.1% 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 in 2014. The addition of this air quality control system (AQCS) equipment was completed in December 2014. Routine plant maintenance, during which the entire plant is taken out of service, is scheduled annually, normally for approximately three to four weeks in the spring. Approximately every fifth year, the maintenance outage is scheduled to be extended to approximately six weeks to permit inspection of the Unit No. 1 turbine. When the Asbury Plant is out of service, we typically experience

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

        We own a 12% undivided interest in the coal-fired Unit No. 1 and Unit No. 2 at the Iatan Generating Station located near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. We are entitled to 12% of the units' available capacity, currently 85 megawatts for Unit No. 1 and 106 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 three gas-fired combustion turbine units (Units 10, 11 and 12) with an aggregate generating capacity of 177 megawatts. As part of our environmental Compliance Plan, discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8, we are currently completing the conversion of Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The tie-in outage for the Riverton Unit 12 Combined Cycle Project was completed in October 2015 and mechanical completion was achieved on December 15, 2015. Start-up and commissioning of the unit is currently in progress with contractual substantial completion expected by June 1, 2016. Riverton Unit 7 was permanently removed from service on June 30, 2014, and Unit 8 and Unit 9 were retired on June 30, 2015.

        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 96 megawatts and a Combined Cycle Unit with generating capacity of 495 megawatts of which we are entitled to 60%, or 295 megawatts. The Combined Cycle Unit consists of the combination of two combustion turbines, two heat recovery steam generators, a steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with Westar Generating Inc., a subsidiary of Westar Energy, Inc., which owns the remaining 40% of the unit. We are the operator of the Combined Cycle Unit and Westar reimburses us for a percentage of the operating costs per our joint ownership agreement. All units at our State Line Power Plant burn natural gas as a primary fuel with Unit No. 1 having the additional capability of burning oil.

        We have four combustion turbine peaking units at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 257 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 thirty -year license, effective March 1, 1992, from the FERC to operate this plant which forms Lake Taneycomo in southwestern Missouri. We are about to start the renewal process on this license, which expires in 2022.

        At December 31, 2015, our transmission system consisted of approximately 22 miles of 345 kV lines, 405 miles of 161 kV lines, 745 miles of 69 kV lines and 82 miles of 34.5 kV lines. Our distribution system consisted of approximately 6,932 miles of line at December 31, 2015 and 6,911 miles as of December 31, 2014.

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

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        We also own and operate water pumping facilities and distribution systems consisting of a total of approximately 96 miles of water mains in three communities in Missouri.

Gas Segment Facilities

        At December 31, 2015, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,189 miles of distribution mains.

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

Other Segment

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

ITEM 3.    LEGAL PROCEEDINGS

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

ITEM 4.    MINE SAFETY DISCLOSURES

        Not applicable.

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PART II

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

        Our common stock is listed on the New York Stock Exchange (ticker symbol: EDE). On February 1, 2016, there were 4,048 record holders and 26,258 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 2015 and 2014.

 
  High   Low   Close   Dividends Paid
Per Share
 

2015 Quarter Ended:

                         

March 31

  $ 31.49   $ 23.67   $ 24.82   $ 0.260  

June 30

    25.41     21.56     21.80     0.260  

September 30

    23.99     20.69     22.03     0.260  

December 31

    29.41     21.40     28.07     0.260  

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  

        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 first quarter of 2016, the Board of Directors declared a quarterly dividend of $0.26 per share on common stock payable on March 15, 2016 to holders of record as of March 1, 2016. As of December 31, 2015, our retained earnings balance was $101.4 million, compared to $90.3 million at December 31, 2014. 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 2015, no purchases of our common stock were made by us or on our behalf.

        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, 2010, 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
  12/31/2010   12/31/2011   12/31/2012   12/31/2013   12/31/2014   12/31/2015  

The Empire District Electric Company

  $ 100.00   $ 98.06   $ 99.50   $ 115.97   $ 158.30   $ 156.20  

S&P Electric Utilities Index

  $ 100.00   $ 120.97   $ 120.30   $ 129.68   $ 170.15   $ 160.95  

S&P 500 Index

  $ 100.00   $ 102.11   $ 118.45   $ 156.82   $ 178.28   $ 180.75  

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ITEM 6.    SELECTED FINANCIAL DATA

(in thousands, except per share amounts)
  2015   2014   2013   2012   2011  

Operating revenues(1)

  $ 605,573   $ 652,330   $ 594,330   $ 557,097   $ 576,870  

Operating income

  $ 96,301   $ 99,999   $ 99,663   $ 96,221   $ 96,934  

Total allowance for funds used during construction

  $ 7,695   $ 9,917   $ 5,940   $ 1,928   $ 512  

Net income

  $ 56,597   $ 67,103   $ 63,445   $ 55,681   $ 54,971  

Weighted average number of common shares outstanding — basic

   
43,671
   
43,291
   
42,781
   
42,257
   
41,852
 

Weighted average number of common shares outstanding — diluted

    43,718     43,314     42,803     42,284     41,887  

Total earnings per weighted average share of common stock — basic

  $ 1.30   $ 1.55   $ 1.48   $ 1.32   $ 1.31  

Total earnings per weighted average share of common stock — diluted

  $ 1.29   $ 1.55   $ 1.48   $ 1.32   $ 1.31  

Cash dividends per share

  $ 1.04   $ 1.025   $ 1.005   $ 1.00   $ 0.64  

Common dividends paid as a percentage of net income

   
80.3

%
 
66.1

%
 
67.8

%
 
75.9

%
 
48.6

%

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

    13.6 %   14.8 %   9.4 %   3.5 %   0.9 %

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

 
$

18.32
 
$

18.02
 
$

17.43
 
$

16.90
 
$

16.53
 

Capitalization:

   
 
   
 
   
 
   
 
   
 
 

Common equity

  $ 802,730   $ 783,298   $ 750,123   $ 717,798   $ 693,989  

Long-term debt

  $ 837,947   $ 803,189   $ 743,428   $ 691,626   $ 692,259  

Ratio of earnings to fixed charges

    2.65X     3.02X     2.97X     2.89X     2.87X  

Total assets

  $ 2,455,303   $ 2,371,056   $ 2,145,045   $ 2,126,369   $ 2,021,835  

Plant in service at original cost

  $ 2,601,592   $ 2,541,582   $ 2,332,341   $ 2,284,022   $ 2,176,650  

Capital expenditures (including AFUDC)

  $ 176,525   $ 222,852   $ 160,196   $ 146,287   $ 101,177  

(1)
Includes SPP IM net revenues of $15.0 million and $41.9 million in 2015 and 2014, respectively.

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 margin (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 regulatory lag that

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occurs between the time we incur costs and the time when we can start recovering the costs through rates has a negative impact on earnings. The effects of timing of rate relief are discussed in detail in Note 3 of "Notes to the Consolidated Financial Statements" under Item 8. Of the factors driving electric operating margin, 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, 2015 was 0.5%. We define electric sales growth to be growth in kWh sales period over period excluding the estimated impact of weather. The primary drivers of electric sales growth are customer growth, customer usage and general economic conditions.

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

Gas Segment

        The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and usage, (4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. The MPSC sets the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily commodity natural gas) and/or rate relief. We assess the need for rate relief and file for such relief when necessary. A Purchased Gas Adjustment (PGA) clause is included in our gas rates, which allows us to recover our actual cost of natural gas from customers through rate changes, which are made periodically (up to four times) throughout the year in response to weather conditions, natural gas costs and supply demands. Weather affects the demand for natural gas. Very cold winters increase demand for gas, while mild weather reduces demand. Due to the seasonal nature of the gas business, revenues and earnings are typically concentrated in the November through March period, which generally corresponds with the heating season.

        Customer growth, which is the growth in the number of customers, contributes to the demand for gas. Our annual customer growth is calculated by comparing the number of customers at the end of a year to the number of customers at the end of the prior year. Our gas segment customer count decreased 0.5% for the year ended December 31, 2015, 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, 2015, basic earnings per weighted average share of common stock were $1.30 and diluted earnings per weighted average share of common stock were $1.29 on $56.6 million of net income. For the year ended December 31, 2014, basic and diluted earnings per weighted average

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share of common stock were $1.55 on $67.1 million of net income. Increased electric gross margin positively impacted net income for 2015 as compared to 2014 mainly due to increased electric rates for our Missouri customers effective July 26, 2015 and improved customer counts. The impact of mild weather during the 2015 heating season, as well as increased regulatory operating and maintenance expense, property taxes, and depreciation and amortization expense negatively impacted 2015 results. These increased expenses were driven in large part by the completion of the Asbury Air Quality Control System (AQCS) environmental upgrade that went into service December 14, 2014. Due to regulatory lag, however, these higher costs did not begin to be recovered in electric rates until new Missouri rates took effect on July 26, 2015.

        The table below sets forth a reconciliation of basic and diluted earnings per share (EPS) between 2014 and 2015, which is a non-GAAP presentation. The economic substance behind our non-GAAP earnings per share 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 EPS 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

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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 — 2014

  $ 1.55  

Gross Margins

   
 
 

Electric segment

    0.12  

Gas segment

    (0.04 )

Other segment

    0.01  

Total Gross Margin

    0.09  

Operating expenses — electric segment

    (0.04 )

Operating expenses — gas segment

    0.00  

Operating expenses — other segment

    0.00  

Maintenance and repairs

    (0.03 )

Depreciation and amortization

    (0.11 )

Other taxes

    (0.03 )

AFUDC

    (0.03 )

Interest charges

    (0.05 )

Change in effective income tax rates

    (0.01 )

Other income and deductions

    (0.03 )

Dilutive effect on additional shares issues

    (0.01 )

Earnings Per Share — 2015

  $ 1.30  

Fourth Quarter Results

        Earnings for the fourth quarter of 2015 were $9.9 million, or $0.23 per share, as compared to $11.1 million, or $0.26 per share, in the fourth quarter of 2014. Electric segment gross margin increased during the quarter ending December 31, 2015 compared to the 2014 quarter, reflecting increased electric rates for our Missouri customers effective July 26, 2015 and improved customer counts. The impact of mild weather, as well as increased regulatory operating expense, property taxes, and depreciation and amortization expense and reduced AFUDC, negatively impacted 2015 fourth quarter results.

2015 Activities

Riverton Unit 12 Combined Cycle Project

        As part of our environmental Compliance Plan, discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8, we are currently completing the conversion of Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The tie-in outage for the Riverton Unit 12 Combined Cycle Project was completed in October 2015 and mechanical completion was achieved on December 15, 2015. Start-up and commissioning of the unit is currently in progress with contractual substantial completion by June 1, 2016.

Regulatory Matters

        On October 16, 2015, we filed a request with the Missouri Public Service Commission (MPSC) for changes in rates for our Missouri electric customers. We are seeking an annual increase in total revenue of approximately $33.4 million, or approximately 7.3%. The most significant factor driving the rate request is the cost associated with the conversion of the Riverton Unit 12 natural gas combustion turbine to combined cycle operation. (See Note 11 — New Construction of "Notes to Consolidated Financial Statements" under Item 8).

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        On June 24, 2015, the MPSC granted new rates for Missouri customers for our rate case filed on August 29, 2014. Rates were effective July 26, 2015. The order approved an annual increase in base revenues of about $17.1 million or 3.90%, which included a net reduction in base fuel and purchased power of $1.60 per MWh, and other items consistent with the non-unanimous stipulation and agreement filed April 8, 2015.

        On January 22, 2015, we filed an Application with the Kansas Corporation Commission (KCC) requesting approval of our Ad Valorem Tax Surcharge (AVTS). The request sought approval for an annual increase of $0.27 million related to increases in Ad Valorem taxes which exceed amounts currently included in base rates. On February 19, 2015, the KCC approved the request. The new rate was effective on and after February 23, 2015. On January 21, 2016, we filed an Application with the KCC requesting approval for a revision to the AVTS. The request sought approval for an annual increase of an additional $0.20 million related to increases in Ad Valorem taxes which exceed amounts currently included in our AVTS rider currently in effect.

        On June 8, 2015, the governor of the state of Oklahoma approved an administrative ruling that provides customer rate reciprocity to electric companies who serve less than 10% of total customers within the state of Oklahoma. As a result, future increases in Missouri customer rates approved by the MPSC will be effective for our Oklahoma customers, subject to Oklahoma Corporation Commission (OCC) approval. On October 26, 2015, we filed a request with the OCC to adopt the Missouri customer electric rates requested in our October 16, 2015 Missouri rate filing discussed above for our Oklahoma customers once approval is granted by the MPSC.

        On October 29, 2013, we filed an application with the MPSC seeking approval, pursuant to the Missouri Energy Efficiency Investment Act (MEEIA), of a new Missouri demand-side management (DSM) portfolio, including four new DSM programs, and for the authority to establish a Demand Side Management Investment Mechanism (DSIM). On July 24, 2015, we filed a motion to withdraw our MEEIA filing. We will continue our current portfolio of Energy Efficiency programs, with recovery through base rates. We will review the need for a future MEEIA filing in conjunction with our 2016 Integrated Resource Plan (IRP).

        On July 31, 2015, we filed a notice updating our most recent IRP, with the MPSC. In the notice we indicated that Riverton Units 8 and 9 were retired on June 30, 2015. The notice also provides additional information on our MEEIA application withdrawal mentioned above.

        On May 6, 2015, the MPSC approved tariffs we filed on May 5, 2015 to establish solar rebate payment procedures and revise our net metering tariffs to accommodate the payment of solar rebates mandated by the Missouri Clean Energy Initiative. The law provides a number of methods that may be utilized to recover the associated expenses. We expect these costs to be recoverable in rates. See Note 11 — Renewable Energy of "Notes to Consolidated Financial Statements" under Item 8 for information regarding the Clean Energy Initiative.

        On February 23, 2015, we filed a notice with the Arkansas Public Service Commission (APSC) to implement the Alternative Generation Environmental Recovery Rider (GER) pursuant to the provision of Act 310 of 1981. The GER recovers reasonably incurred costs and expenditures as a direct result of legislative or regulatory requirements relating to the protection of the public health, safety, or the environment. Our implemented GER recovers our Arkansas jurisdictional share of investment associated with the Asbury AQCS. The new GER was effective upon notice (February 23, 2015) subject to refund. On August 5, 2015, the APSC approved the GER.

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

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Financing Activities

        On June 11, 2015, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 3.59% First Mortgage Bonds due 2030. A delayed settlement occurred on August 20, 2015. Interest is payable semi-annually on the bonds on each February 20 and August 20, commencing February 20, 2016. We utilized the proceeds from the sale of the bonds for the Riverton combined cycle project and for general corporate purposes.

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

Subsequent Events

Pending Acquisition of Empire by Liberty Utilities (Central) Co.

        On February 9, 2016, Empire entered into an Agreement and Plan of Merger (the Merger Agreement) with Liberty Utilities (Central) Co., a Delaware corporation (Liberty), and Liberty Sub Corp., a Kansas corporation (Merger Sub), providing for the merger of Merger Sub with and into Empire, with Empire surviving the Merger as a wholly-owned subsidiary of Liberty (the Merger). Pursuant to the Merger Agreement, at the effective time of the Merger, each issued and outstanding share of Empire common stock (other than any shares owned by Empire or Algonquin Power & Utilities Corp. (APUC)) or any of their respective subsidiaries or any shares for which appraisal rights have been perfected) will be cancelled and converted automatically into the right to receive $34.00 in cash, without interest.

        The closing of the Merger is subject to certain conditions, including, among others, approval of Empire shareholders, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period and receipt of all required regulatory approvals and consents, including from the Federal Energy Regulatory Commission, the Federal Communications Commission, the Arkansas Public Service Commission, the Kansas Corporation Commission, the Missouri Public Service Commission, the Oklahoma Corporation Commission and the Committee on Foreign Investment in the United States, which approvals and consents shall not, individually or in the aggregate, have or be reasonably likely to have a material adverse effect on the business, properties, financial condition or results of operations of Liberty Utilities Co. and its subsidiaries (including Empire and its subsidiaries), taken as a whole.

        If Empire shareholders do not approve the Merger, or the Merger is not consummated by February 9, 2017, the Merger Agreement may terminate, although it may be extended six months in order to obtain certain required regulatory approvals. The Merger Agreement also provides for certain other termination rights for both Empire and Liberty. If either party terminates the Merger Agreement because Empire's board of directors changes its recommendation, or, if within nine months after the termination of the Merger Agreement under certain circumstances, Empire shall have entered into a definitive agreement with respect to, or consummated, an alternative transaction, Empire must pay Liberty a termination fee of $53.0 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, failure to consummate the Merger after all closing conditions have been satisfied and a financing failure has occurred or a breach by Liberty of its regulatory cooperation covenants, Liberty must pay Empire a termination fee of $65.0 million.

        Simultaneously with the execution of the Merger Agreement, Liberty delivered to Empire a guarantee agreement (the Guarantee Agreement) executed by APUC, the parent of Liberty Utilities Co. The Guarantee Agreement provides for an unconditional and irrevocable guarantee by APUC of the full and prompt payment and performance, when due, of all obligations of Liberty and Merger Sub under the Merger Agreement.

        In connection with entering into the Merger Agreement, Empire has incurred approximately $0.2 million of transaction costs as of December 31, 2015. We expect that the total transaction costs will be approximately $15 to $17 million, with approximately 50% payable in 2016 (assuming a 2017 closing date),

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of which approximately $4.5 million will be incurred in the first quarter of 2016. The foregoing description of the Merger, the Merger Agreement and the Guarantee is not a complete description thereof and is qualified in its entirety by reference to the full text of the Merger Agreement and the Guarantee. For more information regarding the terms of the Merger, including copies of the Merger Agreement and the Guarantee, see Empire's Current Report on Form 8-K filed with the SEC on February 9, 2016.

RESULTS OF OPERATIONS

        The following discussion analyzes significant changes in the results of operations for the years 2015, 2014 and 2013.

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

 
  2015   2014   2013  

Electric

  $ 52.2   $ 61.5   $ 58.6  

Gas

    1.3     2.9     2.3  

Other

    3.1     2.7     2.5  

Net income

  $ 56.6   $ 67.1   $ 63.4  

Electric Segment

Overview

        Our electric segment income for 2015 was $52.2 million as compared to $61.5 million and $58.6 million for 2014 and 2013, respectively.

        Electric on-system operating revenues for 2015, 2014, and 2013 were comprised of the following customer classes:

 
  2015   2014   2013  

Residential

    42.9 %   43.4 %   43.9 %

Commercial

    31.9     31.6     31.3  

Industrial

    16.4     15.5     15.5  

Wholesale on-system

    3.3     4.1     3.9  

Miscellaneous sources*

    2.9     2.8     2.9  

Other electric revenues

    2.6     2.6     2.5  

*
Primarily other public authorities

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Sales, Revenues and Gross Margin

KWh Sales

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

 
  kWh Sales  
Customer Class
  2015   2014   % Change(1)   2014   2013   % Change(1)  

Residential

    1,836.2     1,950.4     (5.9 )%   1,950.4     1,936.6     0.7 %

Commercial

    1,577.4     1,583.8     (0.4 )   1,583.8     1,541.7     2.7  

Industrial

    1,064.5     1,031.6     3.2     1,031.6     1,015.5     1.6  

Wholesale on-system

    330.8     336.3     (1.6 )   336.3     343.1     (2.0 )

Other(2)

    131.1     128.0     2.4     128.0     129.4     (1.1 )

Total on-system sales

    4,940.0     5,030.1     (1.8 )   5,030.1     4,966.3     1.3  

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

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

        KWh sales for our on-system customers decreased during 2015 as compared to 2014 primarily due to decreased demand due to weather impacts. Residential kWh sales, the more weather sensitive class, decreased 5.9% primarily due to the impacts of milder weather during the 2015 heating season as compared to 2014. Commercial kWh sales decreased only 0.4% due to increased customer growth offsetting the impact of mild weather. Industrial sales increased 3.2% during 2015 as compared to 2014 mainly due to increased usage. 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 2015 were 16.6% less than 2014 and 11.3% less 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 2015 were 5.8% more than 2014 and 12.0% more than the 30-year average.

        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 for 2014 were 1.2% more than 2013 and 6.3% more than the 30-year average. Total cooling degree days for 2014 were 3.7% more than 2013 and 5.8% more than the 30-year average.

Revenues and 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 $7.8 million during 2015 as compared to 2014. Electric segment gross margin was positively impacted by the new Missouri retail on-system rate increase effective July 26, 2015 and an increase in average electric customer counts. Electric segment gross margin 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 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
  2015   2014   % Change(1)   2014   2013   % Change(1)  

Residential

  $ 230.6   $ 236.5     (2.5 )% $ 236.5   $ 227.7     3.9 %

Commercial

    171.7     172.3     (0.3 )   172.3     162.4     6.1  

Industrial

    88.2     84.7     4.1     84.7     80.5     5.3  

Wholesale on-system

    18.0     22.3     (19.2 )   22.3     20.0     11.4  

Other(2)

    15.7     15.2     3.1     15.2     15.0     2.1  

Total on-system revenues

    524.2     531.0     (1.3 )   531.0     505.6     5.0  

Off-system wholesale(3)

        3.2     (100.0 )   3.2     15.5     (79.2 )

SPP IM net revenues(3)

    15.0     41.9     (64.1 )   41.9         100.0  

Total revenues from KWh sales

    539.2     576.1     (6.4 )   576.1     521.1     10.6  

Miscellaneous revenues(4)

    13.8     14.3     (3.9 )   14.3     13.2     8.2  

Total electric operating revenues

  $ 553.0   $ 590.4     (6.3 ) $ 590.4   $ 534.3     10.5  

Water revenues

    2.1     2.1     (0.3 )   2.1     2.1     (3.3 )

Total electric segment operating revenues

  $ 555.1   $ 592.5     (6.3 ) $ 592.5   $ 536.4     10.5  

Actual fuel and purchased power expenditures

  $ 141.0   $ 165.2     (14.7 ) $ 165.2   $ 182.1     (9.3 )

SPP IM net purchases(3)

    22.6     55.9     (59.6 )   55.9         100.0  

Net fuel recovery and deferral

    8.9     (3.8 )   (332.9 )   (3.8 )   (3.6 )   6.2  

SWPA amortization(5)

    (2.5 )   (2.6 )   (4.9 )   (2.6 )   (2.8 )   (5.4 )

Unrealized (gain)/loss on derivatives

    (0.1 )   0.4     (113.3 )   0.4     (0.3 )   (237.4 )

Total fuel and purchased power expense per income statement

    169.9     215.1     (21.0 )   215.1     175.4     22.6  

Total Gross Margin

  $ 385.2   $ 377.4     2.1   $ 377.4   $ 361.0     4.5  

(1)
Slight differences from actual results, including percentage changes, may occur which may not agree to the rounded amounts shown above due to rounding to millions and percentage change based on actual, not rounded amounts shown.

(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 $10.6 million of the Missouri portion remains to be amortized as of December 31, 2015.

        Revenues for our on-system customers decreased approximately $6.8 million (1.3%) during 2015 as compared to 2014. Increased revenues of $10.4 million, primarily due to the July 2015 increase in Missouri electric rates mentioned above, net of a $3.3 million decrease resulting from a lowering of Missouri base fuel recovery, contributed an estimated $7.1 million to revenues. Improved customer counts increased revenues an estimated $2.3 million. Weather and other volumetric related factors decreased revenues an estimated $10.3 million in 2015 as compared to 2014. Also negatively impacting revenues was a $1.3 million decrease in Missouri non-base fuel recovery revenue and a $3.2 million decrease in non-Missouri fuel

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recovery revenue (both of which were offset by a corresponding change in fuel expenses, resulting in no net effect on gross margin). Also decreasing revenues was a $1.4 million January 2015 refund to FERC wholesale customers, reflecting lower fuel costs from the SPP IM.

        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.

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 (IM), 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 (SPP IM net purchases) 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.

Operating Expenses — Other Than Fuel and Purchased Power

        The table below shows regulated operating expense increases/(decreases) during 2015 as compared to 2014 and during 2014 as compared to 2013 (in millions):

 
  2015 vs. 2014   2014 vs. 2013  

Regulated operating expense:

             

Transmission expense(1)

  $ 1.2   $ 5.0  

Distribution expense

    (0.2 )   1.1  

Power operation expense(2)

    2.2     0.4  

Customer accounts and assistance expense

    0.0     0.4  

Employee pension expense

    (0.2 )   (0.1 )

Employee health care expense

    1.0     (1.0 )

General office supplies and expense

    (0.5 )   2.2  

Administrative and general expense

    0.4     (0.4 )

Allowance for uncollectible accounts

    (1.1 )   (0.1 )

Regulatory reversal of gain on sale of assets

    0.0     (1.2 )

Other miscellaneous accounts (netted)

    0.0     (2.5 )

TOTAL

  $ 2.8   $ 3.8  

(1)
Mainly due to increased SPP transmission charges.

(2)
Mainly due to a $1.0 million increase in power operation expense for the Asbury plant.

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        The table below shows maintenance and repairs expense increases/(decreases) during 2015 as compared to 2014 and during 2014 as compared to 2013(in millions):

 
  2015 vs. 2014   2014 vs. 2013  

Maintenance and repairs expense:

             

Transmission and distribution maintenance expense

  $ (1.5 ) $ 3.1  

Maintenance and repairs expense at:

             

Energy Center

    (1.1 )   1.3  

Asbury plant

    0.0     1.2  

SLCC(1)

    3.1     (0.6 )

State Line plant

    (0.2 )   (0.3 )

Iatan plant

    0.5     0.3  

Plum Point plant

    (0.9 )   (0.1 )

Riverton plant(2)

    2.0     0.8  

Water plant

    (0.2 )   0.2  

Other miscellaneous accounts (netted)

    0.0     0.0  

TOTAL

  $ 1.7   $ 5.9  

(1)
Mainly due to a planned maintenance outage.

(2)
Mainly due to a new maintenance contract for the Riverton facility.

        Depreciation and amortization expense increased approximately $7.2 million (10.7%) during 2015 as compared to 2014 primarily due to increased plant in service reflecting the completion of the Asbury AQCS project and other additions to plant in service. Depreciation and amortization expense increased approximately $3.9 million (6.1%) during 2014 as compared to 2013, primarily due to increased depreciation rates resulting from our 2013 Missouri electric rate case settlement and increased plant in service.

        Other taxes increased approximately $2.3 million in 2015 and $1.8 million in 2014 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)
  2015   2014   % Change   2014   2013   % Change  

Residential

    2.22     2.76     (19.6 )%   2.76     2.74     0.6 %

Commercial(1)

    1.04     1.27     (18.1 )   1.27     1.35     (5.5 )

Industrial

    0.04     0.06     (38.8 )   0.06     0.07     (13.5 )

Other(2)

    0.03     0.04     (19.6 )   0.04     0.04     3.1  

Total retail sales

    3.33     4.13     (19.4 )   4.13     4.20     (1.6 )

Transportation sales(1)

    4.45     4.92     (9.5 )   4.92     4.53     8.6  

Total gas operating sales

    7.78     9.05     (14.0 )   9.05     8.73     3.7  

(1)
Several commercial customers transferred to transportation customers during 2014, reflecting the decrease in commercial sales and the increase in transportation sales during 2014 compared to 2013.

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

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

 
  Operating Revenues and Cost of Gas Sold  
($ in millions)
  2015   2014   % Change   2014   2013   % Change  

Residential

  $ 26.3   $ 32.9     (20.1 )% $ 32.9   $ 31.6     4.2 %

Commercial(1)

    10.7     13.6     (21.6 )   13.6     13.7     (0.2 )

Industrial

    0.3     0.5     (41.2 )   0.5     0.5     4.2  

Other(2)

    0.3     0.4     (21.6 )   0.4     0.3     6.8  

Total retail revenues

  $ 37.6   $ 47.4     (20.7 ) $ 47.4   $ 46.1     2.9  

Other revenues

    0.4     0.4     (7.0 )   0.4     0.4     5.0  

Transportation revenues(1)

    3.7     4.0     (6.8 )   4.0     3.5     12.9  

Total gas operating revenues

  $ 41.7   $ 51.8     (19.6 ) $ 51.8   $ 50.0     3.6  

Cost of gas sold

    19.5     27.0     (27.8 )   27.0     25.8     4.8  

Gas segment gross margin

  $ 22.2   $ 24.8     (10.5 ) $ 24.8   $ 24.2     2.4  

(1)
Several commercial customers transferred to transportation customers during 2014, reflecting the decrease in commercial revenues and the increase in transportation revenues during 2014 compared to 2013.

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

        Gas retail sales decreased 19.4% and gas retail revenues decreased 20.7% during 2015 as compared to 2014 primarily due to decreased demand from the impacts of milder weather during the 2015 heating season as compared to 2014. Weather in our gas territory in the fourth quarter of 2015 was the mildest in 34 years. Heating degree days were 19.1% lower in 2015 than 2014 and 10.8% lower than the 30-year average. Our gas segment gross margin (defined as gas operating revenues less cost of gas in rates) for 2015 decreased $2.6 million compared to 2014.

        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 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.

        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.

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Operating Revenue Deductions

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

(in millions)
  2015 vs. 2014   2014 vs. 2013  

Distribution operation expense

  $ 0.3   $ (0.2 )

Transmission operation expense

    0.1     0.1  

Customer accounts expense

    (0.5 )   (0.6 )

Miscellaneous

    0.2     (0.1 )

TOTAL

  $ 0.1   $ (0.8 )

        Our gas segment had net income of $1.3 million in 2015 as compared to $2.9 million in 2014 and $2.3 million in 2013.

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:

 
  2015   2014   2013  

Consolidated provision for income taxes

  $ 33.8   $ 39.2   $ 37.5  

Consolidated effective federal and state income tax rates

    37.4 %   36.9 %   37.1 %

        The effective tax rate for 2015 is higher than 2014 primarily due to lower equity AFUDC income in 2015 compared with 2014. The effective tax rate for 2014 is lower than 2013 primarily due to higher equity AFUDC income in 2014 compared with 2013.

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

Nonoperating Items

        The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended December 31. AFUDC decreased in 2015 as compared to 2014 reflecting the completion of the environmental retrofit project at our Asbury plant in December 2014. AFUDC increased in 2014 as compared to 2013 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)
  2015   2014   2013  

Allowance for equity funds used during construction

  $ 4.9   $ 6.4   $ 3.8  

Allowance for borrowed funds used during construction

    2.8     3.5     2.1  

Total AFUDC

  $ 7.7   $ 9.9   $ 5.9  

        Total interest charges on long-term and short-term debt for 2015, 2014 and 2013 are shown below. The change in long-term debt interest for 2015 compared to 2014 reflects the issuance on December 1, 2014, of $60.0 million of 4.27% First Mortgage Bonds due 2044 and the issuance of $60.0 million of 3.59% First Mortgage Bonds due 2030 on August 20, 2015. The proceeds from both bond issuances were used to refinance existing short-term indebtedness and for general corporate purposes.

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        The change in long-term debt interest for 2014 compared to 2013 reflects the issuance, on May 30, 2013, of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. We used a portion of the proceeds from the sale of these bonds to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013.

 
  Interest Charges
($ in millions)
 
 
  2015   2014   Change   2014   2013   Change  

Long-term debt interest

  $ 43.8   $ 40.6     7.8 % $ 40.6   $ 40.3     0.7 %

Short-term debt interest

    0.3     0.1     >100.0     0.1     0.1     90.5  

Other interest

    1.0     1.0     4.6     1.0     1.1     (7.1 )

Total interest charges

  $ 45.1   $ 41.7     8.1   $ 41.7   $ 41.5     0.6  

RATE MATTERS

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

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

        The following table sets forth information regarding electric and water rate increases since January 1, 2013:

Jurisdiction
  Date
Requested
  Annual
Increase
Granted
  Percent
Increase
Granted
  Date
Effective

Missouri — Electric

  August 29, 2014   $ 17,125,000     3.90 % July 26, 2015

Kansas — Electric

  December 5, 2014   $ 782,479     4.71 % June 1, 2015

Arkansas — Electric

  February 23, 2015   $ 457,000     3.35 % February 23, 2015

Kansas — Electric

  January 22, 2015   $ 273,455     1.08 % February 23, 2015

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

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

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MARKETS AND TRANSMISSION

Electric Segment

        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 commitment and dispatch of SPP members' generation resources. The SPP matches offers and bids based upon operating and reliability considerations. The SPP reports that approximately 90% – 95% of all next day generation needed throughout the SPP territory is being cleared through the IM. We also acquire Transmission Congestion Rights (TCR) through annual and monthly processes in an attempt to mitigate congestion costs associated with the power we purchase from the IM. When we sell more generation to the market than we purchase for a given settlement period, the net sale is included as part of electric revenues. When we purchase more generation from the market than we sell, 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.

        SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement and Plum Point Delivery:    Due to Plum Point's physical location and interconnection, transmission service from Entergy/MISO is required for delivery. On December 19, 2013, Entergy voluntarily integrated its generation, transmission, and load into the MISO regional transmission organization. Based on the current terms and conditions of MISO membership, Entergy's participation in MISO has increased transmission delivery costs for our Plum Point power station as well as utilizes our transmission system without compensation.

        As a result, we have participated with the SPP members and other impacted utilities in two separate FERC settlement proceedings in an effort to reduce the costs to our customers. On October 13, 2015, SPP members, SPP, MISO and MISO members filed a settlement at the FERC regarding MISO's unreserved and uncompensated use of the SPP members' systems. If approved by the FERC, the agreement will provide compensation and governance for the continued shared use of the transmission system among MISO, SPP and others impacted. However, the regional through and out transmission delivery rate (RTOR) dispute regarding Plum Point will go to hearing at the FERC. On May 20, 2015, we along with KCPL-GMO, AECI, and Southern Company filed a formal 206 complaint at the FERC that the ROTR rate was unjust and unreasonable. A procedural schedule was issued by the FERC on October 8, 2015 with hearings to commence on April 25, 2016 and an initial decision scheduled for August 10, 2016.

        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

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meet our needs for working capital, pension contributions, our continuing construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years. 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)
  2015   2014   2013  

Cash provided by/(used in):

                   

Operating activities

  $ 184.8   $ 151.2   $ 157.5  

Investing activities

    (185.5 )   (215.3 )   (153.3 )

Financing activities

    0.3     62.7     (4.1 )

Net change in cash and cash equivalents

  $ (0.4 ) $ (1.4 ) $ 0.1  

Cash flow from Operating Activities

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

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

        2015 compared to 2014.    In 2015, our net cash flows provided from operating activities was $184.8 million, an increase of $33.6 million, or 22.2%, from 2014. This change was primarily a result of:

    Increased plant depreciation based on additions — $7.7 million.

    Working capital changes for collections of accounts receivable and estimated unbilled revenues — $40.6 million.

    Regulatory fuel adjustment mechanism liabilities increased — $7.9 million.

    Adjustments to recognize non-cash losses for derivatives increased — $5.7 million.

    Lower refunds of customer advances in 2015 increased cash — $2.5 million.

    Decrease in net income — $(10.5) million.

    Changes in fuel related and other regulatory amortizations — $(2.3) million.

    Additional pension funding over last year — $(8.7) million.

    Tax timing differences lower during 2015 mostly related to bonus depreciation partially offset by expected utilization of 2014 tax net operating losses — $(5.1) million.

    Changes related to inventories, prepaid assets and accounts payable, net — $(3.0) million.

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        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.

Capital Requirements and Investing Activities

        Our net cash flows used in investing activities decreased $29.8 million from 2014 to 2015. The decrease was due to a $28.0 million decrease in total cash outlay for capital expenditures and a $1.8 million decrease in restricted cash.

        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 capital expenditures totaled approximately $176.0 million, $222.8 million, and $160.2 million in 2015, 2014 and 2013, respectively.

        A breakdown of these capital expenditures for 2015, 2014 and 2013 is as follows:

 
  Capital Expenditures  
(in millions)
  2015   2014   2013  

Distribution and transmission system additions

  $ 65.3   $ 57.7   $ 58.5  

New generation — Riverton 12 combined cycle

    75.8     77.5     13.2  

Additions and replacements — electric plant

    14.7     61.4     61.8  

Storms

    0.0     2.3     1.0  

Transportation

    3.8     3.6     4.5  

Gas segment additions and replacements

    4.8     7.1     4.1  

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

    9.9     11.0     14.7  

Subtotal

  $ 174.3   $ 220.6   $ 157.8  

Non-regulated capital expenditures (primarily fiber optics)

    2.2     2.2     2.4  

Subtotal capital expenditures incurred(2)

  $ 176.5   $ 222.8   $ 160.2  

Adjusted for capital expenditures payable(3)

    8.9     (9.4 )   (5.4 )

Total cash outlay

  $ 185.4   $ 213.4   $ 154.8  

(1)
Other includes equity AFUDC of $(4.9) million, $(6.4) million and $(3.9) million for 2015, 2014 and 2013, 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 75%, 50% and 74% of our cash requirements for capital expenditures for 2015, 2014 and 2013, 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 2016, 2017 and 2018 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
  2016   2017   2018   Total  

Riverton Unit 12 combined cycle conversion

  $ 11.7   $ 0.0   $ 0.0   $ 11.7  

Electric distribution system additions

    46.7     40.5     62.0     149.2  

Electric transmission facilities

    23.3     29.6     26.2     79.1  

Additions and replacements — electric plant

    16.4     21.7     35.2     73.3  

Other

    17.0     14.5     36.0     67.5  

Total

  $ 115.1   $ 106.3   $ 159.4   $ 380.8  

        Customer reliability, communication and efficiency projects comprise $15 million of the 2018 other estimate above. Our estimated total capital expenditures (excluding AFUDC) for 2019 and 2020 are $150.9 million and $114.1 million, respectively.

        We estimate that internally generated funds will provide approximately 100% of the funds required in 2016 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

2015 compared to 2014.

        Our net cash flows provided by financing activities was $0.3 million in 2015 as compared to $62.7 million in 2014, a decrease of $62.4 million, primarily due to the following:

    Net short-term repayments of $19.0 million in 2015 as compared to net short-term borrowings of $40.0 million in 2014.

    Proceeds from issuance of common stock of $5.5 million in 2015 as compared to $8.0 million in 2014.

    Dividends paid of $45.4 million in 2015 as compared to $44.4 million in 2014.

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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.

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, 2015, $200.0 million remains available for issuance under this shelf registration statement. However, as a result of our regulatory approvals, we may only issue up to $150.0 million of such securities in the form of first mortgage bonds, of which $30.0 million remains available after the issuance of $60.0 million in first mortgage bonds on August 20, 2015 and $60 million on December 1, 2014. Any proceeds from offerings made pursuant to this shelf would be used to fund capital expenditures, refinance existing debt or general corporate needs during the effective period through December 2016.

Credit Agreements.

        We have in place a $200 million 5-year Credit Agreement which expires in October 2019. This agreement replaced the former $150 million Third Amended and Restated Unsecured Credit Agreement that had a January 2017 expiration date. This 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. 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) are 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 $297.0 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. 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. The annual interest coverage requirement and retired bonds or 60% of net property additions tests would permit the issuance of more than $297.0 million of new first mortgage bonds; however, as discussed above, we are otherwise limited to the issuance of no more than $297.0 million of new first mortgage bonds. As of December 31, 2015, we are in compliance with all restrictive covenants of the EDE Mortgage.

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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 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, 2015, this test would allow us to issue approximately $19.5 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%. As of December 31, 2015, we are in compliance with all restrictive covenants of the EDG Mortgage.

Credit Ratings

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

 
  Moody's   Standard & Poor's

Corporate Credit Rating

  Baa1   BBB

EDE First Mortgage Bonds

  A2   A–

Senior Notes

  Baa1   BBB

Commercial Paper

  P-2   A-2

Outlook

  Stable   Negative

        On March 6, 2015, Moody's reaffirmed our credit ratings and outlook. On December 15, 2015, Standard & Poor's reaffirmed our credit ratings and revised our outlook to developing from stable in light of the December 13, 2015 announcement regarding our exploration of strategic alternatives. On February 10, 2016, Standard & Poor's reaffirmed our credit ratings and revised our outlook to negative from developing in light of the February 9, 2016 announcement regarding the proposed merger.

        On December 1, 2015, we cancelled our relationship with Fitch Ratings. At that time, Fitch's ratings for our securities were as follows: First Mortgage Bonds, BBB+; Senior Notes, BBB; Commercial Paper, F3; Outlook, Stable. Fitch did not provide a Corporate Credit Rating. They last affirmed the ratings described above on June 12, 2015.

        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, 2015. 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 2016 – 2020 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)

  $ 860.0   $ 25.0   $ 90.0   $ 100.0   $ 645.0  

Interest on long-term debt

    713.7     44.8     82.3     72.0     514.6  

Short-term debt

    25.0     25.0              

Capital lease obligations

    5.2     0.5     1.1     1.1     2.5  

Operating lease obligations(2)

    2.5     0.7     1.3     0.5      

Electric purchase obligations(3)

    426.5     47.1     70.1     45.3     264.0  

Gas purchase obligations(4)

    87.8     10.6     19.3     19.3     38.6  

Open purchase orders

    130.9     129.5     0.1     0.1     1.2  

Postretirement benefit obligation funding

    10.8     3.1     4.7     3.0      

Pension benefit funding

    35.5     10.4     14.5     10.6      

Other long-term liabilities(5)

    2.9     0.1     0.3     0.3     2.2  

TOTAL CONTRACTUAL OBLIGATIONS

  $ 2,300.8   $ 296.8   $ 283.7   $ 252.2   $ 1,468.1