10-K

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TABLE OF CONTENTS
PART IV

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

		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

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, SO_2, 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;

3

•

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

6

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.

7

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

8

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

14

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.

15

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.

17

        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.

18

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.

19

        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.

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

(1)

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

(2)

Excludes payments under our Elk River Wind Farm, LLC and Cloud County Wind Farm, LLC agreements, as payments are contingent upon output of the facilities. For additional information, see Note 11 of "Notes to Consolidated Financial Statements" under Item 8.

Payments under the Elk River Wind Farm, LLC agreement can run from zero up to a maximum of approximately $16.9 million per year based on a 20 year average cost and an annual output of 550,000 megawatt hours. Payments under the Meridian Way Wind Farm agreement can range from zero to a maximum of approximately $14.6 million per year based on a 20-year average cost.

(3)

Includes a water usage contract for our SLCC facility, fuel and purchased power contracts and associated transportation costs, as well as purchased power for 2016 through 2039 for Plum Point.

(4)

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

(5)

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

DIVIDENDS

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

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        The following table shows our diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance for the years ended December 31, 2015, 2014 and 2013:

(in millions, except per share amounts)	2015		2014		2013
Diluted earnings per share	$	1.29	$	1.55	$	1.48
Dividends paid per share	$	1.04	$	1.025	$	1.005
Total dividends paid	$	45.4	$	44.4	$	43.0
Retained earnings year-end balance	$	101.4	$	90.3	$	67.6

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

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

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES

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

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        Pensions and Other Postretirement Benefits (OPEB).    We recognize expense related to pension and other postretirement benefits as earned during the employee's period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the accumulated benefit obligation. Our pension and OPEB expense or benefit includes amortization of previously unrecognized net gains or losses. Additional income or expense may be recognized when our unrecognized gains or losses as of the most recent measurement date exceed 10% of our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits and OPEB benefits, unrecognized net gains or losses as of the measurement date are amortized into actuarial expense over ten years. See Note 1 and Note 7 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

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

        Our funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. The actual minimum pension funding requirements will be determined based on the results of the actuarial valuations and the performance of our pension assets during the current year. See Note 7 of "Notes to Consolidated Financial Statements" under Item 8.

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

        Risks and uncertainties affecting the application of our OPEB accounting policy and related funding include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), healthcare cost trend rates, Medicare prescription drug costs and demographic assumptions (i.e. mortality and retirement rates). See Note 1 and Note 7 of "Notes to Consolidated Financial Statements" under Item 8 for further information. We expect future pension and OPEB expense or benefits are probable of full recovery in our rates, thus lowering our sensitivity to accounting risks and uncertainties.

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

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

        Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory assets and liabilities are ratably eliminated through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC accounting guidance for

52

regulated activities with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of ASC accounting guidance for regulated activities based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations.

        As of December 31, 2015, we have recorded $216.8 million in regulatory assets and $141.1 million as regulatory liabilities. See Note 3 of "Notes to Consolidated Financial Statements" under Item 8 for detailed information regarding our regulatory assets and liabilities.

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

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

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

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

        Contingent Liabilities.    We are a party to various claims and legal proceedings arising in the ordinary course of our business, which are primarily related to workers' compensation and public liability. We regularly assess our insurance deductibles, analyze litigation information with our attorneys and evaluate our loss experience. Based on our evaluation as of the end of 2015, we believe that we have accrued liabilities in accordance with ASC accounting guidance sufficient to meet potential liabilities that could result from these claims. This liability at December 31, 2015 and 2014 was 3.7 million and $3.6 million, respectively.

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

        Goodwill.    As of December 31, 2015, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our gas business acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and income approaches is used to estimate the fair value of goodwill.

53

        Our annual test performed as of October 2015 indicated the estimated fair market value of the gas reporting unit to be $18 – $22 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future. See Note 1 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

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

RECENTLY ISSUED ACCOUNTING STANDARDS

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

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

        Market Risk and Hedging Activities.    Prices in the wholesale power markets can be extremely volatile. This volatility impacts our cost of power purchased and our participation in energy trades. In addition, congestion on the transmission system can limit our ability to make purchases from (or sell into) the wholesale markets.

        We engage in physical and financial trading activities with the goals of reducing risk from market fluctuations. In accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions, we attempt to mitigate our commodity market risk. Derivatives are utilized to manage our gas commodity market risk. We also acquire Transmission Congestion Rights (TCR) in an attempt to lessen the cost of power we will purchase from the SPP IM due to congestion costs. See Note 14 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

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

        We satisfied 65.0% of our 2015 generation fuel supply need through coal. Approximately 97% of our 2015 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2017. These contracts satisfy approximately 100% of our anticipated fuel requirements for 2016, 46% for 2017 and 23% for 2018 for our Asbury coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

54

        We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of December 31, 2015, 61%, or 8.6 million Dths, of our anticipated volume of natural gas usage for our electric operations for 2016 is hedged. See Note 14 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        Based on our expected natural gas purchases for our electric operations for 2016, if average natural gas prices should increase 10% more in 2016 than the price at December 31, 2015, our natural gas expenditures would increase by approximately $1.1 million based on our December 31, 2015 total hedged positions for the next twelve months. However, such an increase would be probable of recovery through fuel adjustment mechanisms in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs.

        We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of December 31, 2015, we have 1.4 million Dths in storage on the three pipelines that serve our customers. This represents 70% of our storage capacity. We have an additional 0.4 million Dths hedged through financial derivatives and physical contracts for the balance of the 2015-2016 winter season.

        See Note 14 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        Credit Risk.    In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. See Note 14 of "Notes to Consolidated Financial Statements" under Item 8 regarding agreements containing credit risk contingent features. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at December 31, 2015 and December 31, 2014 (in millions).

	2015		2014
Margin deposit assets	$	11.2	$	9.1

        There were no margin deposit liabilities at these dates.

        Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at December 31, 2015, reflecting that our counterparties are exposed to Empire for the net unrealized

55

mark-to-market losses for physical forward and financial natural gas contracts carried at fair value (in millions).

Net unrealized mark-to-market losses for physical forward natural gas contracts	$	4.4
Net unrealized mark-to-market losses for financial natural gas contracts		8.6
Net credit exposure	$	13.0

        The $8.6 million net unrealized mark-to-market loss for financial natural gas contracts is comprised entirely of $8.6 million that our counterparties are exposed to Empire for unrealized losses. We are holding no collateral from any counterparty since we are below the $10 million mark-to-market collateral threshold in our agreements. As noted above, as of December 31, 2015, we have $11.2 million on deposit for NYMEX contract exposure to Empire, of which $10.0 million represents our collateral requirement. If NYMEX gas prices decreased 25% from their December 31, 2015 levels, our collateral requirement would increase $8.0 million. If these prices increased 25%, our collateral requirement would decrease $8.3 million. Our other counterparties would not be required to post collateral with Empire.

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

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

        If market interest rates average 1% more in 2016 than in 2015, our interest expense would increase, and income before taxes would decrease by less than $1.0 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2015. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

        In our opinion, the consolidated financial statements listed in the index appearing under Item 15 present fairly, in all material respects, the financial position of The Empire District Electric Company and its subsidiaries at December 31, 2015 and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

St. Louis, Missouri
February 26, 2016

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Balance Sheets

	December 31,
	2015		2014
	($-000's)
Assets
Plant and property, at original cost:
Electric	$	2,473,927	$	2,420,824
Gas		83,402		79,364
Other		44,263		41,394
Construction work in progress		183,689		112,097
		2,785,281		2,653,679
Accumulated depreciation and amortization		764,895		743,407
		2,020,386		1,910,272
Current assets:
Cash and cash equivalents		1,753		2,105
Restricted cash		4,726		4,726
Accounts receivable — trade, net of allowance of $623 and $1,021, respectively		40,162		45,444
Accrued unbilled revenues		20,653		25,945
Accounts receivable — other		28,320		41,256
Fuel, materials and supplies		60,950		57,799
Prepaid expenses and other		8,835		8,679
Unrealized gain in fair value of derivative contracts		1,295		3,901
Regulatory assets		7,052		10,752
		173,746		200,607
Noncurrent assets and deferred charges:
Regulatory assets		209,708		209,717
Goodwill		39,492		39,492
Unamortized debt issuance costs		8,658		8,821
Unrealized gain in fair value of derivative contracts		16		—
Other		3,297		2,147
		261,171		260,177
Total assets	$	2,455,303	$	2,371,056

(Continued)

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Balance Sheets (Continued)

	December 31,
	2015		2014
	($-000's)
Capitalization and liabilities
Common stock, $1 par value, 100,000,000 shares authorized, 43,820,726 and 43,479,186 shares issued and outstanding, respectively	$	43,821	$	43,479
Capital in excess of par value		657,466		649,543
Retained earnings		101,443		90,276
Total common stockholders' equity		802,730		783,298
Long-term debt (net of current portion)
Obligations under capital lease		3,580		3,875
First mortgage bonds and secured debt		732,653		697,615
Unsecured debt		101,714		101,699
Total long-term debt		837,947		803,189
Total long-term debt and common stockholders' equity		1,640,677		1,586,487
Current liabilities:
Accounts payable and accrued liabilities		66,946		83,420
Current maturities of long-term debt		25,310		292
Short-term debt		25,000		44,000
Regulatory liabilities		8,615		7,898
Customer deposits		14,623		13,747
Interest accrued		7,348		6,565
Unrealized loss in fair value of derivative contracts		4,472		6,469
Taxes accrued		2,832		3,380
Other current liabilities		323		206
		155,469		165,977
Commitments and contingencies (Note 11)
Noncurrent liabilities and deferred credits:
Regulatory liabilities		132,457		128,471
Deferred income taxes		396,542		358,252
Unamortized investment tax credits		18,487		18,517
Pension and other postretirement benefit obligations		82,144		93,863
Unrealized loss in fair value of derivative contracts		3,696		3,243
Other		25,831		16,246
		659,157		618,592
Total capitalization and liabilities	$	2,455,303	$	2,371,056

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Statements of Income

	Year Ended December 31,
	2015			2014			2013
	(000's, except per share amounts)
Operating revenues:
Electric	$	555,085		$	592,491		$	536,413
Gas		41,702			51,842			50,041
Other		8,786			7,997			7,876
		605,573			652,330			594,330
Operating revenue deductions:
Fuel and purchased power		169,860			215,086			175,406
Cost of natural gas sold and transported		19,502			27,025			25,795
Regulated operating expenses		113,551			110,691			105,333
Other operating expenses		3,309			2,987			3,142
Maintenance and repairs		48,522			46,775			40,873
Loss on plant disallowance		—			86			2,409
Depreciation and amortization		80,550			73,185			69,306
Provision for income taxes		34,800			39,398			37,465
Other taxes		39,178			37,098			34,938
		509,272			552,331			494,667
Operating income		96,301			99,999			99,663
Other income and (deductions):
Allowance for equity funds used during construction		4,850			6,420			3,853
Interest income		145			51			566
Benefit/(provision) for other income taxes		988			178			(27	)
Other — non-operating expense, net		(3,429	)		(1,302	)		(1,218	)
		2,554			5,347			3,174
Interest charges:
Long-term debt		43,802			40,637			40,354
Short-term debt		266			113			60
Allowance for borrowed funds used during construction		(2,845	)		(3,497	)		(2,087	)
Other		1,035			990			1,065
		42,258			38,243			39,392
Net income	$	56,597		$	67,103		$	63,445
Weighted average number of common shares outstanding — basic		43,671			43,291			42,781
Weighted average number of common shares outstanding — diluted		43,718			43,314			42,803
Total earnings per weighted average share of common stock — basic	$	1.30		$	1.55		$	1.48
Total earnings per weighted average share of common stock — Diluted	$	1.29		$	1.55		$	1.48
Dividends declared per share of common stock	$	1.04		$	1.025		$	1.005

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Statements of Common Stockholders' Equity

	Common Stock		Capital in excess of Par		Retained earnings			Total
	($-000's)
Balance at December 31, 2012	$	42,484	$	628,199	$	47,115		$	717,798
Net income						63,445			63,445
Stock/stock units issued through:
Stock purchase and reinvestment plans		560		11,326					11,886
Dividends declared						(43,006	)		(43,006	)
Balance at December 31, 2013		43,044		639,525		67,554			750,123
Net income						67,103			67,103
Stock/stock units issued through:
Stock purchase and reinvestment plans		435		10,018					10,453
Dividends declared						(44,381	)		(44,381	)
Balance at December 31, 2014		43,479		649,543		90,276			783,298
Net income						56,597			56,597
Stock/stock units issued through:
Stock purchase and reinvestment plans		342		7,923					8,265
Dividends declared						(45,430	)		(45,430	)
Balance at December 31, 2015	$	43,821	$	657,466	$	101,443		$	802,730

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2015			2014			2013
	($-000's)
Operating activities:
Net income	$	56,597		$	67,103		$	63,445
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items		88,801			82,754			71,734
Pension and other postretirement benefit costs, net of contributions		(9,184	)		1,973			(1,888	)
Deferred income taxes and unamortized investment tax credit, net		36,617			41,693			28,272
Allowance for equity funds used during construction		(4,850	)		(6,420	)		(3,853	)
Stock compensation expense		4,082			4,057			2,984
Loss on plant disallowance		—			86			2,409
Non-cash loss on derivatives		6,994			1,245			14
Regulatory reversal of gain on sale of assets		—			44			1,236
Other		(625	)		—			—
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues		16,514			(24,174	)		(14,312	)
Fuel, materials and supplies		(3,151	)		(8,121	)		10,891
Prepaid expenses, other current assets and deferred charges		(4,863	)		(6,051	)		689
Accounts payable and accrued liabilities		(8,630	)		1,141			(880	)
Asset retirement obligation		(73	)		(1,326	)		(734	)
Interest, taxes accrued and customer deposits		1,111			1,411			1,386
Other liabilities and other deferred credits		5,492			(4,192	)		(3,942	)
Net cash provided by operating activities		184,832			151,223			157,451

(Continued)

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Statements of Cash Flows (Continued)

	Year Ended December 31,
	2015			2014			2013
	($-000's)
Investing activities:
Capital expenditures — regulated	$	(183,206	)	$	(211,429	)	$	(152,524	)
Capital expenditures and other investments — non-regulated		(2,243	)		(1,998	)		(2,259	)
Restricted cash		—			(1,854	)		1,485
Total net cash used in investing activities		(185,449	)		(215,281	)		(153,298	)
Financing activities:
Proceeds from first mortgage bonds, net		60,000			60,000			150,000
Long-term debt issuance costs		(818	)		(651	)		(1,879	)
Proceeds from issuance of common stock, net of issuance costs		5,513			7,994			9,546
Redemption of senior notes		—			—			(98,000	)
Net short-term borrowings (repayments)		(19,000	)		40,000			(20,000	)
Dividends		(45,430	)		(44,381	)		(43,006	)
Other		—			(274	)		(714	)
Net cash provided by / (used) in financing activities		265			62,688			(4,053	)
Net increase (decrease) in cash and cash equivalents		(352	)		(1,370	)		100
Cash and cash equivalents, beginning of year		2,105			3,475			3,375
Cash and cash equivalents, end of year	$	1,753		$	2,105		$	3,475

	2015			2014		2013
Supplemental cash flow information:
Interest paid	$	42,858		$	40,127	$	39,033
Income taxes (refunded) paid, net of refund		(17,256	)		23,103		10,584
Supplementary non-cash investing activities:
Change in accrued additions to property, plant and equipment not reported above	$	(8,924	)	$	9,427	$	5,420
Capital lease obligations for purchase of new equipment	$	17			—		—

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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. See Note 12. 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.

        The utility portions of our business are subject to regulation by the Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). Our accounting policies are in accordance with the ratemaking practices of the regulatory authorities and conform to generally accepted accounting principles as applied to regulated public utilities.

        Our electric operations serve approximately 170,000 customers as of December 31, 2015, and the 2015 electric operating revenues were derived as follows:

Customer Class	% of revenue
Residential		41.7	%
Commercial		31.1
Industrial		15.9
Wholesale on-system		3.3
Wholesale off-system		2.7
Miscellaneous sources, primarily public authorities		2.8
Other electric revenues		2.5

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

Jurisdiction	% of revenue
Missouri		89.0	%
Kansas		4.8
Oklahoma		2.8
Arkansas		3.4

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

        Our gas operations serve approximately 43,200 customers as of December 31, 2015, and the 2015 gas operating revenues were derived as follows:

Customer Class	% of revenue
Residential		63.0	%
Commercial		25.6
Industrial		0.8
Transportation		8.9
Miscellaneous		1.7

Basis of Presentation

        The consolidated financial statements include the accounts of EDE, EDG, and our other subsidiaries. The consolidated entity is referred to throughout as "we" or the "Company". All intercompany balances and transactions have been eliminated in consolidation. See Note 12 for additional information regarding our three segments. Certain immaterial reclassifications have been made to prior year information to conform to the current year presentation.

Use of Estimates

        The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include unbilled utility revenues, collectability of accounts receivable, depreciable lives, asset impairment and goodwill impairment evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation, and tax provisions. Actual amounts could differ from those estimates.

Accounting for the Effects of Regulation

        In accordance with the Accounting Standard Codification (ASC) guidance for regulated operations, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the APSC and the FERC).

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

        Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory assets and liabilities are ratably amortized through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

recovered through future revenues. We generally include amortization of regulatory assets and liabilities in the depreciation and amortization line of our statement of cash flows. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC guidance for regulated operations with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of this guidance based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations. (See Note 3 for further discussion of regulatory assets and liabilities)

Revenue Recognition

        For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer classes.

Municipal Franchise Taxes

        Municipal franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other taxes in the Consolidated Statements of Income. Municipal franchise taxes of $11.4 million, $11.8 million and $11.2 million were recorded for each of the years ended December 31, 2015, 2014 and 2013, respectively.

Accounts Receivable

        Accounts receivable are recorded at the tariffed rates for customer usage, including applicable taxes and fees and do not bear interest. We review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered.

Property, Plant & Equipment

        The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material, an allocation of general and administrative costs, and an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of and the costs of removal are charged to accumulated depreciation, unless the removed property constitutes an operating unit or system. In this case a gain or loss is recognized upon the disposal of the asset. Maintenance expenditures and the removal of minor property items are charged to income as incurred. A liability is created for any additions to electric or gas utility property that are paid for by advances from developers. For a period of five years we refund to the developer a pro rata amount of the original cost of the extension for each new customer added to the extension. Nonrefundable payments at the end of the five year period are applied as a reduction to the cost of the plant in service. The liability as of December 31, 2015 and 2014 was $2.1 million and $1.9 million, respectively.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

Depreciation

        Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by regulatory authorities. These rates are applied to the various classes of utility assets on a composite basis. Provisions for depreciation for our other segment are computed at straight-line rates over the estimated useful life of the properties (See Note 2 for additional details regarding depreciation rates).

        As of December 31, 2015 and 2014, we had recorded accrued cost of removal of $85.4 million and $82.8 million, respectively, for our electric operating segment. This represents an estimated cost of dismantling and removing plant from service upon retirement, accrued as part of our depreciation rates. We accrue cost of removal in depreciation rates for mass property (including transmission, distribution and general plant assets). These accruals are not considered an asset retirement obligation under the guidance provided on asset retirement obligations within the ASC. We reclassify the accrued cost of dismantling and removing plant from service upon retirement from accumulated depreciation to a regulatory liability. We have a similar cost of removal regulatory liability for our gas operating segment. This amount at December 31, 2015 and 2014 was $8.8 million and $7.7 million, respectively. These amounts are net of our actual cost of removal expenditures.

Asset Retirement Obligation

        We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.

        We have identified asset retirement obligations associated with the future removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We also have a solid waste land fill at the Plum Point Energy Station, and asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. As a result of the fuel use transition from coal to natural gas at the Riverton Power Plant, the closure of the Riverton ash landfill was completed, and the related asset retirement obligation was settled during 2014 (Note 11). During 2015 the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs). As a result of these new rules, an asset retirement obligation of $5.4 million has been recorded for the final closure of the existing ash impoundment at our Asbury Power Plant. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station.

        In addition, we have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB) contaminants associated with our transformers and substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures for the removal of similar past liabilities. The potential costs of these future expenditures are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. This liability will be accreted over the period up to the estimated settlement date.

        All of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 4.5% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. During 2014

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

the liability for asbestos at the Riverton Power Plant was re-evaluated. Changes in the cost estimates and timing resulted in cash flow revisions for these liabilities.

        The balances at the end of 2015 and 2014 are shown below.

(000's)	Liability Balance 12/31/14		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/15
Asset Retirement Obligation	$	4,847	$	9,812	$	(73	)	$	486	$	—	$	15,072

(000's)	Liability Balance 12/31/13		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/14
Asset Retirement Obligation	$	4,190	$	—	$	(1,175	)	$	172	$	1,660	$	4,847

        Upon adoption of the standards on the retirement of long lived assets and conditional asset retirement obligations, we recorded a liability and regulatory asset because we expect to recover these costs of removal in electric and gas rates either through depreciation accruals or direct expenses. We also defer the liability accretion and depreciation expense as a regulatory asset. At December 31, 2015 and 2014, our regulatory assets relating to asset retirement obligations totaled $7.7 million and $5.1 million, respectively.

        Also as noted previously under property, plant and equipment, we reclassify the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset retirement obligation under this guidance, from accumulated depreciation to a regulatory liability. This balance sheet reclassification has no impact on results of operations.

Allowance for Funds Used During Construction

        As provided in the FERC regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction (AFUDC) when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds applicable to construction programs are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.

        AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation.

        In accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 5.5% for 2015, 6.6% for 2014, and 7.3% for 2013, compounded semiannually.

Asset Impairments (excluding goodwill)

        We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on undiscounted forecasted cash flows to assess the recoverability of the assets and, if necessary, the fair value is determined to measure the impairment amount. None of our assets were impaired as of December 31, 2015 and 2014.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

Goodwill

        As of December 31, 2015, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and income approaches is used to estimate the fair value of goodwill.

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

        We also utilize a valuation technique under the income approach which estimates the discounted future cash flows of operations. Our procedures include developing a baseline test and performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering those assumptions which are subjective in nature and inherent to a discounted cash flows calculation. Other qualitative factors and comparisons to industry peers are also used to further support the assumptions and ultimately the overall evaluation. A key qualitative assumption considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for the gas reporting unit. Some of the key quantitative assumptions included in our tests involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. If negative changes occurred to one or more key assumptions, an impairment charge could result. With the exception of the capital spending rate, the key assumptions noted are significantly determined by market factors and significant changes in market factors that impact the gas reporting unit would somewhat be mitigated by our current and future regulatory rate design. Other risks and uncertainties affecting these assumptions include: changes in business, industry, laws, technology and economic conditions. Actual results for the gas reporting unit indicate a slight decline in gas customer count and demand. A continued decline in customer count or demand coupled with an increase in the discount rate would have adverse impacts on the valuation and could result in an impairment charge in the future. Our forecasts anticipate relatively flat customer counts over the next several years.

        We weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of October 2015 indicated the estimated fair market value of the gas reporting unit to be $18 – $22 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future.

Fuel and Purchased Power

Electric Segment

        Fuel and purchased power costs are recorded at the time the fuel is used, or the power purchased. SPP Integrated Marketplace purchased power is also included in fuel and purchased power costs. The net effects of our SPP IM activity, including SPP IM net revenue and net purchased power costs, flow through our fuel recovery mechanisms in each state.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

        In our Missouri jurisdiction, the MPSC establishes a base cost for the recovery of fuel and purchased power expenses used to supply energy for our fuel adjustment clause (FAC). Beginning with our 2015 rate order, certain transmission costs are also included in the base cost. The FAC permits the distribution to customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, nearly the entire off-system sales margin flows back to the customer. Rates related to the fuel adjustment clause are modified twice a year subject to the review and approval by the MPSC. In accordance with the ASC guidance for regulated operations, 95% of the difference between the actual costs of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered from or refunded to our customers when the fuel adjustment clause is modified.

        In our Kansas jurisdiction, the costs of fuel are recovered from customers through a fuel adjustment clause, based upon estimated fuel costs and purchased power. The adjustments are subject to audit and final determination by regulators. The difference between the costs of fuel used and the cost of fuel recovered from our Kansas customers is recorded as a regulatory asset or a regulatory liability if the actual costs are higher or lower than the costs billed to customers, in accordance with the ASC guidance for regulated operations.

        Similar fuel recovery mechanisms are in place for our Oklahoma, Arkansas and FERC jurisdictions.

        At December 31, 2015 and 2014, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net over-recovered position by $5.9 million and a net under-recovered position of $3.1 million, respectively, which are reflected in our regulatory assets and liabilities.

        We receive the renewable attributes associated with the power purchased through our purchased power agreements with Elk River Windfarm LLC and Cloud County Windfarm, LLC. These renewable attributes are converted into renewable energy credits (REC), which are considered inventory, and recorded at zero cost (See Note 11). Revenue from the sale of RECs reduces fuel and purchased power expense.

        We have a Stipulation and Agreement with the MPSC granting us authority to manage our emissions allowance inventory in accordance with our Plan for Purchasing and Selling Emissions Allowances (PPSEMA). The PPSEMA allows us to purchase allowances needed for compliance, exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell allowances outright for monetary value. For compliance year 2015 we did not exchange or sell any allowances, and for compliance year 2014 we purchased 69 NOx annual allowances for compliance. We classify our allowances as inventory and they are recorded at cost, with allocated allowances being recorded at zero cost. The allowances are removed from inventory on a FIFO basis, and used allowances are considered to be a part of fuel expense (See Note 11). We had the following emissions allowances in inventory at December 31, 2015 and 2014:

Emission Allowances in Inventory	2015		2014
Acid Rain SO2		11,443		872
CSAPR SO2		5,861		—
CSAPR NOx (annual)		500		—
CSAPR NOx (seasonal)		241		—

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

Gas Segment

        Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery allowed in rates. A Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and related carrying costs associated with the Company's use of natural gas financial instruments to hedge the purchase price of natural gas. 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.

        We calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC. Elements considered part of the PGA factor include cost of gas supply, storage costs, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.

        Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and carrying costs associated with the use of financial instruments) are reflected as a regulatory asset or liability. The balance is amortized as amounts are reflected in customer billings.

Derivatives

        We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel in our electric business or sold in our natural gas business, on the spot market and to manage certain interest rate exposure. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we purchase from the SPP Integrated Marketplace (see Note 14).

Electric Segment

        Pursuant to the ASC guidance on accounting for derivative instruments and hedging activities, derivatives are required to be recognized on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability ("cash-flow" hedge); or (2) an instrument that is held for non-hedging purposes (a "non-hedging" instrument). We record the mark-to-market gains or losses on derivatives used to hedge our fuel and congestion costs as regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

        We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts, if they meet the definition of a derivative, are not subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions. If these transactions don't qualify for NPNS treatment, they would be marked to market for each reporting period through regulatory assets or liabilities.

Gas Segment

        Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because we have a commission approved natural gas cost recovery mechanism (PGA), we record the mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/liability account. The regulatory asset/liability account tracks the difference between revenues billed to

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

customers for natural gas costs and actual natural gas expense which is trued up at the end of August each year and included in the Actual Cost Adjustment (ACA) factor to be billed to customers during the next year. This is consistent with the ASC guidance on regulated operations, in that we will be recovering our costs after the annual true up period (subject to a prudency review by the MPSC).

        Cash flows from hedges for both electric and gas segments are classified within cash flows from operations.

Pension and Other Postretirement Benefits

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

Pensions

        We have rate orders with Missouri, Kansas and Oklahoma that allow us to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate orders, we prospectively calculate the value of plan assets using a market-related value method as allowed by the ASC guidance on pension benefits. As a result, we are allowed to record the Missouri, Kansas and Oklahoma portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively. The MPSC has allowed us to adopt this pension cost recovery methodology for EDG as well.

Other Postretirement Benefits (OPEB)

        We have regulatory treatment for our OPEB costs similar to the treatment described above for pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into actuarial expense over ten years and the recognition of regulatory assets and liabilities as described above.

        Additional guidance in the ASC on employers' accounting for defined benefit pension and other postretirement plans requires an employer to recognize the over funded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The guidance also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. Pension and other postretirement employee benefits tracking mechanisms are utilized to allow for future rate recovery of these obligations. We record these as regulatory assets on the balance sheet rather than as reductions of equity through comprehensive income (See Note 7).

Unamortized Debt Discount, Premium and Expense

        Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices.

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Liability Insurance

        We are primarily self-insured for workers' compensation claims, general liabilities, benefits paid under employee healthcare programs and long-term disability benefits. Accruals are primarily based on the estimated undiscounted cost of claims. We self-insure up to certain limits that vary by segment and type of risk. Periodically, we evaluate the level of insurance coverage over the self-insured limits and adjust insurance levels based on risk tolerance and premium expense. We carry excess liability insurance for workers' compensation and public liability claims for our electric segment. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. Our gas segment is covered by excess liability insurance for public liability claims, and workers' compensation claims are covered by a guaranteed cost policy (See Note 11).

Other Noncurrent Liabilities

        Other noncurrent liabilities are comprised of accruals and other accounting estimates not sufficiently large enough to merit individual disclosure. At December 31, 2015, the balance of other noncurrent liabilities is primarily comprised of accruals for self-insurance, customer advances for construction and asset retirement obligations.

Cash & Cash Equivalents

        Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities and were $23.2 million and $28.3 million at December 31, 2015 and 2014, respectively.

Restricted Cash

        As part of our Plum Point ownership agreement, we are required to have funds available in an escrow account which guarantees payment of certain operating costs. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts restricted, which were $1.8 million at December 31, 2015 and 2014, may increase or decrease based on an annual review.

        We are required to post cash collateral with Southwest Power Pool (SPP) to participate in Transmission Congestion Rights (TCR) auctions. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $2.5 million at December 31, 2015 and 2014.

        Due to our Plum Point energy station interconnection with Midcontinent Independent System Operator (MISO), we participate in Financial Transmission Rights (FTR) auctions which require us to post cash collateral. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $0.5 million at December 31, 2015 and 2014.

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Fuel, Materials and Supplies

        Fuel, materials and supplies consist primarily of coal, natural gas in storage and materials and supplies, which are reported at average cost. These balances are as follows (in thousands):

	2015		2014
Electric fuel inventory	$	30,185	$	26,454
Natural gas inventory		3,868		5,040
Materials and supplies		26,897		26,305
TOTAL	$	60,950	$	57,799

Income Taxes

        Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes; measured using statutory tax rates (See Note 9).

        Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. The longest remaining amortization period for investment tax credits is approximately 55 years.

Accounting for Uncertainty in Income Taxes

        In 2006, the FASB issued guidance which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with the ASC guidance on accounting for income taxes. We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2010. At December 31, 2015 and 2014, our balance sheet did not include any unrecognized tax benefits. We do not expect any material changes to unrecognized tax benefits within the next twelve months. We recognize interest and penalties, if any, related to unrecognized tax benefits in other expenses.

Computations of Earnings Per Share

        The ASC guidance on earnings per share requires dual presentation of basic and diluted earnings per share. Basic earnings per share does not include potentially dilutive securities and is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share assumes the issuance of common shares pursuant to the Company's stock-based compensation plans at the

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beginning of each respective period, or at the date of grant or award if later. Shares attributable to stock options are excluded from the calculation of diluted earnings per share if the effect would be antidilutive.

	2015		2014		2013
Weighted Average Number Of Shares
Basic		43,670,908		43,291,031		42,781,382
Dilutive Securities:
Performance-based restricted stock awards		19,890		8,809		12,142
Employee stock purchase plan		1,249		3,422		1,729
Stock options		—		—		61
Time-based restricted stock awards		25,523		10,666		7,907
Total dilutive securities		46,662		22,897		21,839
Diluted weighted average number of shares		43,717,570		43,313,928		42,803,221
Antidilutive Shares		20,289		25,259		107,100

        Potentially dilutive shares are not expected to have a material impact unless significant appreciation of the Company's stock price occurs.

Stock-Based Compensation

        We have several stock-based compensation plans, which are described in more detail in Note 8. In accordance with the ASC guidance on stock-based compensation, we recognize compensation expense over the requisite service period of all stock-based compensation awards based upon the fair-value of the award as of the date of issuance.

Recently Issued and Proposed Accounting Standards

        Revenue from contracts with customers:    In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In July 2015, the FASB approved a one year delay in the standard's effective date. The new standard is now effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard.

        Extraordinary and unusual items:    In January 2015, the FASB issued revised guidance that eliminates from GAAP the concept of extraordinary items. Under the revised guidance, an entity will no longer be required to separately classify, present and disclose events or transactions that are determined to be both unusual in nature and infrequent in occurrence. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

        Presentation of debt issuance costs:    In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. As of December 31, 2015, we expect that the implementation of this standard would

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reduce both assets and liabilities by approximately $8.7 million. The application of this standard is not expected to have a material impact on our results of operations or liquidity.

        Balance sheet classification of deferred taxes:    In November 2015, the FASB issued revised guidance addressing the classification of deferred taxes. Under the revised guidance all deferred tax assets and liabilities will be classified as noncurrent in a classified statement of financial position. The revised guidance is effective for interim and annual periods beginning after December 15, 2016, however early adoption is permitted. As of December 31, 2015, we have retrospectively adopted this standard. The application of this guidance resulted in $19.2 million in current deferred tax assets being reclassified from prepaid expenses and other to deferred income taxes (noncurrent) on the December 31, 2014 Consolidated Balance Sheet.

        Recognition and measurement of financial assets and financial liabilities:    In January 2016, the FASB issued revised guidance addressing the recognition, measurement, presentation and disclosure of financial instruments. Under the revised guidance all equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are to be measured at fair value with the changes in fair value recognized in net income. The amended guidance also addresses the impairment assessment of some equity investments, as well as disclosure requirements. The revised guidance is effective for interim and annual periods beginning after December 15, 2017. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

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2.     PROPERTY, PLANT AND EQUIPMENT

        Our total property, plant and equipment are summarized below (in thousands).

	December 31,
	2015		2014
Electric plant
Production	$	1,151,395	$	1,159,140
Transmission		316,038		288,542
Distribution		870,047		840,761
General(1)		123,338		119,572
Electric plant		2,460,818		2,408,015
Less accumulated depreciation and amortization(2)		721,883		704,596
Electric plant net of depreciation and amortization		1,738,935		1,703,419
Construction work in progress		182,585		110,500
Net electric plant		1,921,520		1,813,919
Water plant		13,109		12,809
Less accumulated depreciation and amortization		5,281		5,102
Water plant net of depreciation and amortization		7,828		7,707
Construction work in progress		75		146
Net water plant		7,903		7,853
Net electric segment plant		1,929,423		1,821,772
Gas plant
Transmission		8,498		8,269
Distribution		66,588		63,319
General(3)		8,316		7,776
Gas Plant		83,402		79,364
Less accumulated depreciation and amortization		18,557		16,405
Gas plant net of accumulated depreciation		64,845		62,959
Construction work in progress		627		379
Net gas plant		65,472		63,338
Other
Fiber		44,263		41,394
Less accumulated depreciation and amortization		19,174		17,304
Non-regulated net of depreciation and amortization		25,089		24,090
Construction work in progress		402		1,072
Net non-regulated property		25,491		25,162
TOTAL NET PLANT AND PROPERTY	$	2,020,386	$	1,910,272

(1)

Includes intangible property of $39.8 and $41.2 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by

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other utilities. Accumulated amortization related to this property in 2015 and 2014 was $15.6 and $15.7 million, respectively.

(2)

As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are not reflected here. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.

(3)

Includes intangible property of $0.9 and $0.7 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2015 and 2014 was $0.6 million and $0.5 million, respectively.

        The table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended December 31 (in thousands):

	2015		2014		2013
Provision for depreciation
Regulated — Electric and Water(1)	$	73,885	$	66,600	$	63,192
Regulated — Gas(1)		4,036		3,851		3,763
Non-Regulated		4,895		1,891		1,938
TOTAL		82,816		72,342		68,893
Amortization		2,858		2,692		2,492
TOTAL	$	85,674	$	75,034	$	71,385

(1)

A portion of this amount is reclassified to a regulatory liability for the cost of removal. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.

	2015			2014			2013
Annual depreciation rates
Electric and water		3.1	%		3.0	%		3.0	%
Gas		5.1	%		5.2	%		5.4	%
Non-Regulated		4.4	%		4.7	%		5.0	%
TOTAL COMPANY		3.2	%		3.0	%		3.1	%

        The table below sets forth the average depreciation rate for each class of assets for each period presented:

	2015			2014			2013
Annual Weighted Average Depreciation Rate
Electric fixed assets:
Production plant		2.8	%		2.4	%		2.4	%
Transmission plant		2.4	%		2.4	%		2.4	%
Distribution plant		3.5	%		3.6	%		3.6	%
General plant		5.9	%		5.8	%		5.8	%
Water		2.8	%		2.7	%		2.8	%
Gas		5.1	%		5.2	%		5.4	%
Non-regulated		4.4	%		4.7	%		5.0	%

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3.     REGULATORY MATTERS

Regulatory Assets and Liabilities and Other Deferred Credits

Changes

        Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives from December 31, 2014 to December 31, 2015 resulted from our 2014 Missouri rate case, which was effective July 26, 2015. As a result of this case, a new tracking mechanism related to our Riverton Unit 12 Long Term Maintenance Agreement was established. The tracking mechanisms related to Iatan 2, Iatan Common and Plum Point operating and maintenance costs were discontinued. The balances accumulated through August 2014 from these tracking mechanisms are to be amortized over three years. The tracking mechanism related to vegetation management was also discontinued. Balances accumulated through August 2014 will be amortized over five years. The balances accumulated in these discontinued tracking mechanisms after August 2014 will be addressed during the next rate case. In addition to these changes, the order also included the continuation of tracking mechanisms for expenses related to employee pension and retiree health care. There were no changes to regulatory assets and liabilities with regards to their rate base inclusion or amortizable lives from December 31, 2013 to December 31, 2014.

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        The following table sets forth the components of our regulatory assets and regulatory liabilities on our consolidated balance sheet (in thousands).

	December 31,
	2015			2014
Regulatory Assets:
Current:
Under recovered fuel costs	$	196		$	2,618
Current portion of long-term regulatory assets		6,856			8,134
Regulatory assets, current		7,052			10,752
Long-term:
Pension and other postretirement benefits(1)		108,273			111,121
Income taxes		48,613			47,177
Deferred construction accounting costs(2)		14,977			15,521
Unamortized loss on reacquired debt		9,731			10,405
Unsettled derivative losses — electric segment		7,775			9,037
System reliability — vegetation management		3,604			5,337
Storm costs(3)		3,531			4,183
Asset retirement obligation		7,722			5,145
Customer programs		5,942			5,253
Missouri solar initiative		3,504			—
Current portion of long-term regulatory assets		(6,856	)		(8,134	)
Other		2,892			4,672
Regulatory assets, long-term		209,708			209,717
Total Regulatory Assets	$	216,760		$	220,469
Regulatory Liabilities
Current:
Over recovered fuel costs	$	5,280		$	4,227
Current portion of long-term regulatory liabilities		3,335			3,671
Regulatory liabilities, current		8,615			7,898
Long-term:
Costs of removal(4)		94,193			90,527
SWPA payment for Ozark Beach lost generation		14,213			16,744
Income taxes		11,244			11,451
Deferred construction accounting costs — fuel(5)		7,690			7,849
Unamortized gain on interest rate derivative		3,031			3,201
Pension and other postretirement benefits		1,745			2,369
Over recovered fuel costs		2,300			1
System reliability — vegetation management		1,320			—
Current portion of long-term regulatory liabilities		(3,335	)		(3,671	)
Other		56			—
Regulatory liabilities, long-term		132,457			128,471
Total Regulatory Liabilities	$	141,072		$	136,369

(1)

Primarily consists of unfunded pension and OPEB liability. See Note 7.

(2)

Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants.

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(3)

Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $2.9 million at December 31, 2015.

(4)

As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are reflected here. See the depreciation discussion under Note 1 and Note 2 Property, Plant and Equipment for more detail.

(5)

Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.

        Unamortized losses on debt and losses on interest rate derivatives are not included in rate base, but are included in our capital structure for rate base purposes. The remainder of our regulatory assets are not included in rate base, generally because they are not cash items. However, as of December 31, 2015, the costs of all of our regulatory assets are currently being recovered except for approximately $99.0 million of pension and other postretirement costs primarily related to the unfunded liabilities for future pension and OPEB costs. The amount and timing of recovery of this item will be based on the changing funded status of the pension and OPEB plans in future periods.

        The regulatory income tax assets and liabilities are generally amortized over the average depreciable life of the related assets. The loss on reacquired debt and the loss and gain on interest rate derivatives are amortized over the life of the related new debt issue, which currently ranges from 4 to 25 years. The unrecovered fuel costs are generally recovered within a year following their recognition. Severe storm costs and the Asbury maintenance outage costs are recovered over five years. Pension and other postretirement benefit tracking mechanisms are recovered over a five year period. The cost of removal regulatory liability is amortized as removal costs are incurred.

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

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

Electric Segment

Missouri

Rate Activity

        2015 Rate Case:    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.

        2014 Rate Case:    On August 29, 2014, we filed a request with the MPSC for changes in rates for our Missouri electric customers. We requested an annual increase in total revenue of approximately $24.3 million, or approximately 5.5%. The main cost drivers in the rate increase are the costs associated with our investment in Air Quality Control Facilities at our Asbury power plant (See Note 11 — New Construction of "Notes to Consolidated Financial Statements (Unaudited)") that were incurred to comply with the Environmental Protection Agency's (EPA) rules governing the continued operation of the plant, increases in property taxes, increases in ongoing maintenance expenses and increases in Regional Transmission Organization transmission fees. On June 24, 2015, the MPSC granted new rates for Missouri customers, effective on 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, consistent with the non-unanimous stipulation and agreement filed April 8, 2015. The order establishes a tracking mechanism for expenses related to the Riverton 12 long-term maintenance contract; continues tracking of pension and other post-employment benefit expenses; and discontinues tracking of vegetation management expenses and Iatan 2, Iatan Common and Plum Point operating and maintenance costs. In addition, the order provides for the tracking and recovery of certain future changes in total transmission expense through the Fuel Adjustment Charge, which we estimate at approximately 34% of such changes.

2015 Missouri Energy Efficiency Investment Act and Integrated Resource Plan

        On October 29, 2013 we filed an application with the Missouri Public Service Commission 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).

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        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.

2015 Solar Rebate Tariff

        On May 5, 2015, we filed a proposed solar rebate tariff with the MPSC and requested expedited treatment. On May 6, 2015, the MPSC ordered our request for expedited treatment of our tariff filing be granted and approved the tariff, effective May 16, 2015. 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.

Kansas

2015 Ad Valorem Tax Surcharge

        On January 22, 2015, we filed an Application with the 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.

2014 Environmental Cost Recovery Rider

        On December 5, 2014, we filed an Application with the KCC requesting approval of our proposed Asbury Environmental Cost Recovery (AECR) tariff rider. The request sought approval for recovery of our jurisdictional portion of annual carrying costs (rate of return, income taxes, and depreciation) of approximately $0.86 million, associated with investment in the Asbury AQCS. A Commission Order was received April 15, 2015 approving the rider in the amount of $0.78 million effective June 1, 2015.

Oklahoma

        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.

Arkansas

2015 Tariff Rider

        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

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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.

2014 Rate Case

        On May 20, 2014, we filed a settlement agreement with the Arkansas Public Service Commission (APSC) for an increase of $1.375 million, or approximately 11%. A hearing was held on the settlement agreement on July 22, 2014. On September 16, 2014, the APSC issued an order approving the settlement with a modification that reduced the overall revenue increase to $1.367 million. The new rates were effective September 26, 2014. We had filed a request on December 3, 2013, with the APSC seeking an annual increase in total revenue of approximately $2.2 million, or approximately 18%. The rate increase was requested to recover costs incurred to ensure continued reliable service for our customers, including capital investments, operating systems replacement costs and ongoing increases in other operation and maintenance expenses and capital costs.

FERC

        We have in place a cost-based transmission formula rate (TFR). On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement included a TFR that would establish an ROE of 10.0%. The Agreement calls for the TFR to be updated annually with the new updated TFR rates effective on July 1 of each year. FERC conditionally approved the Agreement on November 18, 2013, and we made a compliance filing with FERC on December 18, 2013 in connection with this conditional approval. The FERC approved our compliance filing on June 12, 2014.

        We have in place a cost-based generation formula rate (GFR). Our GFR requires an update to be completed annually for rates effective June 1. On October 29, 2014, Empire made a "limited" Section 205 filing to request some minor changes in the existing GFR formula to incorporate the impact of the recent implementation of the Southwest Power Pool Integrated Marketplace (IM). As a result of this filing, our customers' share of the margins we receive from sales into the IM will be passed on to them through the monthly fuel and purchased power cost adjustment mechanism rather than making one-time adjustments at each annual update. This filing was approved by FERC on January 13, 2015.

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

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Notes to Consolidated Financial Statements (Continued)

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

        FERC Order No. 1000:    In July 2011, the FERC issued Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities) which requires all public utility transmission providers to allow transmission developers outside their retail distribution service territory to participate in regional transmission planning. Order No. 1000 eliminates the federal right of first refusal for entities that develop transmission projects within their own retail distribution service territories to construct transmission facilities selected in a regional transmission plan. This order will directly affect our rights to build 161kV and above transmission facilities within our retail service territory.

        Order No. 1000 also directed transmission providers to develop policy and procedures for regional and interregional transmission planning as well as regional and interregional transmission cost allocation (see "SPP Regional Transmission Development" below) for approved transmission projects. We continue to participate in the SPP processes to understand the impact of these FERC orders on our ability to construct new facilities within our service territory as well as their influence on promoting construction of transmission projects on or near our borders with our neighbors. SPP completed and filed with the FERC a required interregional policy and procedure compliance filing, and while FERC partially approved SPP's compliance filing, remaining issues have been addressed in a subsequent filing that is currently waiting FERC approval.

        SPP Regional Transmission Development:    In 2010, SPP received FERC approval to implement a new highway/byway cost allocation methodology for new SPP approved transmission projects. We actively monitor SPP's policy to allocate the costs of transmission projects to its members. 2015 net SPP transmission expenses were approximately $1.3 million above 2014 levels. Our Arkansas and Oklahoma jurisdictions have cost recovery mechanisms in place to fully recover additional transmission costs outside the traditional rate making process, and Missouri has a mechanism in place to recover a portion of transmission expense above the amount in base fuel. See "Rate Matters" above for more information.

        The highway/byway allocation methodology requires the costs of SPP approved transmission projects to be allocated to 1) members across the entire SPP region; 2) members within certain localized service territories or zones; or 3) a combination of both regional and zonal allocation. The allocation is based on project voltage, as follows:

Transmission Project Voltage	Regional Funding Percentage			Zonal Funding Percentage
300 kV and Above		100.0	%		0.0	%
100kV to 299kV		33.3	%		66.7	%
Below 100 kV		0.0	%		100.0	%

        SPP's formal regional cost allocation review and benefit to cost imbalance analysis process is ongoing. A filing to outline several possible remedies for entities not receiving adequate benefits from projects regionally funded was rejected by FERC and discussion continues in stakeholder groups to develop alternatives.

        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.

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        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.

Gas Segment

        Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers.

Other — Rate Matters

        In accordance with ASC guidance on regulated operations, we currently have deferred approximately $0.4 million of expense related to rate cases under other non-current assets and deferred charges. These amounts will be amortized over varying periods based upon the completion of the specific cases. Based on past history, we expect all these expenses to be recovered in rates.

4.     SHAREHOLDERS' EQUITY

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 million remains available after the issuance of $60 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.

Employee Benefit Plans

        Our Employee Stock Purchase Plan permits the grant to eligible employees of options to purchase our common stock at a discounted price. As of December 31, 2015 there were 764,645 shares available for issuance in this plan. Under our Employee 401(k) Plan and ESOP we match a percentage of each employee's deferrals by contributing shares of our common stock. At December 31, 2015 there were 129,616 shares available to be issued. (See Note 7 for further discussion of these plans).

Equity Based Compensation

        We have several stock-based awards programs, which are described in Note 8. Our 2015 Stock Incentive Plan provides for grants of up to 500,000 shares of common stock through January 2025. At December 31, 2015 there were 496,766 shares available to be issued.

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Dividends

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

        The following table shows our diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance for the years ended December 31, 2015, 2014 and 2013:

(in millions, except per share amounts)	2015		2014		2013
Diluted earnings per share	$	1.29	$	1.55	$	1.48
Dividends paid per share	$	1.04	$	1.025	$	1.005
Total dividends paid	$	45.4	$	44.4	$	43.0
Retained earnings year-end balance	$	101.4	$	90.3	$	67.6

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

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

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Preferred and Preference Stock

        We have 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A Participating Preference Stock, none of which have been issued. We have 5 million shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2015 or 2014.

5.     LONG-TERM DEBT

        At December 31, 2015 and 2014, the balance of long-term debt outstanding was as follows (in thousands):

	2015			2014
First mortgage bonds (EDE):
7.20% Series due 2016	$	25,000		$	25,000
6.375% Series due 2018(1)		90,000			90,000
4.65% Series due 2020(1)		100,000			100,000
3.58% Series due 2027(1)		88,000			88,000
3.59% Series due 2030(1)		60,000			—
3.73% Series due 2033(1)		30,000			30,000
5.875% Series due 2037(1)		80,000			80,000
5.20% Series due 2040(1)		50,000			50,000
4.32% Series due 2043(1)		120,000			120,000
4.27% Series due 2044(1)		60,000			60,000
First mortgage bonds (EDG):
6.82% Series due 2036(1)		55,000			55,000
		758,000			698,000
Senior Notes, 6.70% Series due 2033(1)		62,000			62,000
Senior Notes, 5.80% Series due 2035(1)		40,000			40,000
Capital lease obligations		3,890			4,167
Less unamortized net discount		(633	)		(686	)
		863,257			803,481
Less current obligations of long-term debt		(25,000	)		—
Less current obligations under capital lease		(310	)		(292	)
TOTAL LONG-TERM DEBT	$	837,947		$	803,189

(1)

We may redeem some or all of the notes at any time at 100% of their principal amount, plus a make-whole premium, plus accrued and unpaid interest to the redemption date.

Debt 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. The bonds are prepayable at our option at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the prepayment date. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for

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general corporate purposes. The bonds have not been and will not be registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage.

        On October 15, 2014, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 4.27% First Mortgage Bonds due December 1, 2044. A delayed settlement occurred on December 1, 2014. Interest is payable semi-annually on the bonds on each December 1 and June 1, commencing June 1, 2015. The bonds may be redeemed at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for general corporate purposes. The bonds have not been, and will not be, registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage.

Shelf Registration

        We have a $200 million shelf registration statement with the SEC that is effective for three years from December 13, 2013. See Note 4.

EDE Mortgage Indenture

        Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $297 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 test would permit the issuance of more than $297.0 million of 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.

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

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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.

        Our long-term debt obligations over the next five years are as follows (in thousands):

	Payments Due By Period
Long-Term Debt Payout Schedule (Excluding Unamortized Discount) (in thousands)	Total		Regulated Entity Debt Obligations		Capital Lease Obligations
2016	$	25,310	$	25,000	$	310
2017		329		—		329
2018		90,351		90,000		351
2019		375		—		375
2020		100,396		100,000		396
Thereafter		647,129		645,000		2,129
Total long-term debt obligations		863,890	$	860,000	$	3,890
Less current obligations and unamortized discount		25,943
TOTAL LONG-TERM DEBT	$	837,947

6.     SHORT-TERM BORROWINGS

        At December 31, 2015, total short-term borrowings consisted of $25.0 million in commercial paper and no borrowings under our line of credit. During 2015 and 2014 our short-term borrowings outstanding averaged (in millions)

	2015		2014
Average borrowings outstanding	$	48.9	$	30.0
Highest month end balance	$	97.0	$	77.0

        The weighted average interest rates and the weighted average interest rate of borrowings outstanding at December 31, 2015 and 2014 were:.

	2015			2014
Weighted average interest rate		0.54	%		0.38	%
Weighted average interest rate of borrowings outstanding		0.84	%		0.44	%

        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.

        Interest on borrowings under the new facility accrues at a rate equal to, at our option, (i) the highest of (A) the agent prime rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, in each case, plus a margin or (ii) one month, two month, three month or six month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the

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facility is 1.025%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings, which is currently 0.175%. In addition, upon entering into the new credit facility, we paid upfront fees to the revolving credit banks of $0.3 million in the aggregate.

        The new credit facility requires our total indebtedness to be less than 65.0% of our total capitalization at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2015, we were in compliance with this covenant as our ratio of total indebtedness to total capitalization was 0.53 to 1.0. The new credit facility is also subject to cross-default if we default on more than $25 million in the aggregate on our other indebtedness. As of December 31, 2015, we were not in default under any of our debt obligations.

        The new credit agreement does not legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under the agreement at December 31, 2015; however, $25.0 million was used to back up our outstanding commercial paper.

7.     RETIREMENT AND OTHER EMPLOYEE BENEFITS

        We record retirement benefits in accordance with the ASC guidance on accounting for pension and other postretirement benefits, and have recorded the appropriate liabilities to reflect the unfunded status of our benefit plans, with offsetting entries to a regulatory asset, because we believe it is probable the unfunded amount of these plans will be afforded rate recovery. Additionally, the MPSC agreed that the effects of purchase accounting entries related to pension and other post-retirement benefits would be recoverable in future rate proceedings. These amounts, which are related to EDG, were recorded as regulatory assets and are being amortized. The tax effects of these entries are reflected as deferred tax assets and liabilities and regulatory liabilities.

        Annually we evaluate the discount rate, retirement age, compensation rate increases, expected return on plan assets, healthcare cost trend rate, and other actuarial assumptions related to pension benefit and post-retirement medical plan. We utilize an interest rate yield curve to determine an appropriate discount rate. The yield curve is constructed based on the yields on over 500 high-quality, non-callable corporate bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of the Empire pension plan and develop a single point discount rate matching the plan's payout structure. In evaluating these assumptions, many factors are considered, including, current market conditions, asset allocations, changes in demographics and the views of leading financial advisors and economists. In evaluating the expected retirement age assumption, we consider the retirement ages of past employees eligible for pension and medical benefits together with expectations of future retirement ages. It is reasonably possible that changes in these assumptions will occur in the near term and, due to the uncertainties inherent in setting assumptions, the effect of such changes could be material to the Company's consolidated financial statements. A roll forward technique is used to value the year ending pension obligations. The roll forward technique values the year-end obligation by rolling forward the beginning-of-year obligation using the demographic assumptions disclosed below. The economic assumptions are updated as of the end of the year. All of the benefit plans have been measured as of December 31, 2015, consistent with previous years. See Note 1.

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Pensions

        Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. Effective on January 1, 2014, the plan was amended to include a cash balance benefit formula. Employees hired on or after January 1, 2014 will accrue benefits based on a cash balance methodology. Employees hired prior to January 1, 2014 were given a one-time option to convert to the cash balance methodology, or remain with our traditional average annual basic earnings formula, by December 31, 2014. Both benefit formulas allow for a lump sum distribution of vested benefits. Lump sum distributions totaled approximately $15.3 million and $9.0 million during 2015 and 2014, respectively, and did not require settlement accounting according to ASC 715.

        Annual contributions to the plan are at least equal to the greater of either minimum funding requirements of ERISA or the accrued cost of the Plan, as required by the Missouri Public Service Commission.

        Our net pension liability decreased $2.4 million in 2015, which was recorded as a decrease in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The decrease in the liability is primarily due to an increase in discount rates. Our contribution is estimated to be approximately $13.6 million for 2016. We expect future pension funding commitments to continue at least at the level of our accrued cost, as required by our regulator. The actual minimum funding requirements will be determined based on the results of the actuarial valuations and, in the case of 2017, the performance of our pension assets during 2016.

        We also have a supplemental retirement program ("SERP") for designated officers of the Company, which we fund from Company funds as the benefits are paid. The liability for this plan increased $0.7 million in 2015.

        Expected benefit payments are as follows (in millions):

Year	Payments from Trust		Payments from Company Funds
2016	$	22.5	$	0.5
2017		22.8		0.6
2018		21.5		0.5
2019		20.0		0.5
2020		20.9		0.8
2021 – 2025		97.4		2.9

Other Postretirement Benefits (OPEB)

        We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors through trusts we have established. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service. Employees hired after January 1, 2014 will be offered unsubsidized retiree healthcare benefits upon retirement.

        Our net liability decreased $10.0 million in 2015, which was recorded as a decrease in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The decrease in the liability is primarily due to a significant actuarial gain resulting from increases in discount rates, the adoption of a new mortality table and positive claims trends. Our funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. We expect to be required to fund approximately $4.9 million in 2016.

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        Estimated benefit payments are as follows (in millions):

Year	Payments from Trust		Expected Federal Subsidy		Payments from Company Funds
2016	$	2.8	$	0.4	$	0.2
2017		3.2		0.4		0.2
2018		3.5		0.5		0.2
2019		3.8		0.5		0.2
2020		4.1		0.6		0.2
2021 – 2025		25.0		3.7		0.8

        The following tables set forth the Company's benefit plans' projected benefit obligations, the fair value of the plans' assets and the funded status (in thousands).

	Pension						SERP						OPEB
Reconciliation of Projected Benefit Obligations:	2015			2014			2015			2014			2015			2014
Benefit obligation at beginning of year	$	251,879		$	225,131		$	9,155		$	7,108		$	109,899		$	85,332
Service cost		7,442			6,467			158			153			3,713			2,601
Interest cost		10,278			10,819			382			387			4,670			4,360
Amendments		—			(7,753	)		—			(45	)		—			—
Net actuarial (gain)/loss		(708	)		36,742			557			1,890			(14,358	)		20,347
Plan participant's contribution		—			—			—			—			963			850
Benefits and expenses paid		(25,201	)		(19,527	)		(366	)		(338	)		(3,839	)		(3,897	)
Federal subsidy		—			—			—			—			419			306
Benefit obligation at end of year	$	243,690		$	251,879		$	9,886		$	9,155		$	101,467		$	109,899

	Pension						SERP				OPEB
Reconciliation of Fair Value of Plan Assets:	2015			2014			2015		2014		2015			2014
Fair value of plan assets at beginning of year	$	192,674		$	186,547		$	—	$	—	$	83,776		$	79,098
Actual return on plan assets — gain/(loss)		(1,978	)		14,319			—		—		(955	)		5,030
Employer contribution		21,350			11,335			—		—		4,903			2,258
Benefits paid		(25,201	)		(19,527	)		—		—		(3,670	)		(3,707	)
Plan participant's contribution		—			—			—		—		912			804
Federal subsidy		—			—			—		—		403			293
Fair value of plan assets at end of year	$	186,845		$	192,674		$	—	$	—	$	85,369		$	83,776

	Pension						SERP						OPEB
Reconciliation of Funded Status:	2015			2014			2015			2014			2015			2014
Fair value of plan assets	$	186,845		$	192,674		$	—		$	—		$	85,369		$	83,776
Projected benefit obligations		(243,690	)		(251,879	)		(9,886	)		(9155	)		(101,467	)		(109,899	)
Funded status	$	(56,845	)	$	(59,205	)	$	(9,886	)	$	(9,155	)	$	(16,098	)	$	(26,123	)

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        The employee pension plan accumulated benefit obligation at December 31, 2015 and 2014 is presented in the following table (in thousands):

	Pension Benefits				SERP
	2015		2014		2015		2014
Accumulated benefit obligation	$	221,481	$	227,928	$	8,609	$	7,160

        Amounts recognized in the balance sheet consist of (in thousands):

	Pension				SERP				OPEB
	2015		2014		2015		2014		2015		2014
Accounts Payable and Accrued Liabilities	$	—	$	—	$	534	$	481	$	151	$	139
Pension and other postretirement benefit obligation	$	56,845	$	59,205	$	9,352	$	8,674	$	15,947	$	25,984

        Net periodic benefit pension cost for 2015, 2014 and 2013, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset (see Note 3), is comprised of the following components (in thousands):

	Pension									OPEB
Net Periodic Pension Benefit Cost:	2015			2014			2013			2015			2014			2013
Service cost	$	7,442		$	6,467		$	7,454		$	3,713		$	2,601		$	2,941
Interest cost		10,278			10,819			10,063			4,670			4,360			3,827
Expected return on plan assets		(13,567	)		(13,105	)		(12,428	)		(5,197	)		(4,801	)		(4,353	)
Amortization of prior service cost/(benefit)(1)		(630	)		418			532			(1,011	)		(1,011	)		(1,011	)
Amortization of actuarial loss(1)		10,033			6,611			10,445			2,747			967			2,261
Net periodic benefit cost	$	13,556		$	11,210		$	16,066		$	4,922		$	2,116		$	3,665

	SERP
Net Periodic Pension Benefit Cost:	2015			2014			2013
Service cost	$	158		$	153		$	135
Interest cost		382			387			315
Expected return on plan assets		—			—			—
Amortization of prior service cost/(benefit)t(1)		(42	)		(8	)		(8	)
Amortization of actuarial loss(1)		597			504			567
Net periodic benefit cost	$	1,095		$	1,036		$	1,009

(1)

Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.

94

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

        The tables below present other changes in plan assets and benefit obligations recognized in the regulatory asset accounts for the year (in thousands).

			Amount Recognized
Regulatory Assets	Beginning Balance 12/31/14		Current Year Actuarial Loss			Amortization of Actuarial Loss			Current Year Prior Service Credit		Amortization of Prior Service (Cost)/Credit		Ending Balance 12/31/15
Pension	$	77,456		14,836			(10,033	)		—		630	$	82,889
SERP	$	5,537		557			(597	)		—		42	$	5,539
OPEB	$	20,446		(8,208	)		(2,747	)		—		1,011	$	10,502

			Amount Recognized
Regulatory Assets	Beginning Balance 12/31/13		Current Year Actuarial Loss		Amortization of Actuarial Loss			Current Year Prior Service Credit			Amortization of Prior Service (Cost)/Credit			Ending Balance 12/31/14
Pension	$	56,709		35,529		(6,611	)		(7,753	)		(418	)	$	77,456
SERP	$	4,188		1,890		(504	)		(45	)		8		$	5,537
OPEB	$	285		20,117		(967	)		—			1,011		$	20,446

        The following table presents the amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost. It also shows the amounts expected to be recognized in the subsequent year. The following table presents those items for the employee pension plan and other benefits plan at December 31, 2015, and the subsequent twelve-month period (in thousands):

	Pension Benefits						SERP						OPEB
	2015			Subsequent Period			2015			Subsequent Period			2015			Subsequent Period
Net actuarial loss	$	88,981		$	8,426		$	5,555		$	555		$	12,075		$	1,030
Prior service cost (benefit)		(6,092	)		(630	)		(16	)		(14	)		(1,573	)		(1,011	)
Total	$	82,889		$	7,796		$	5,539		$	541		$	10,502		$	19

        The measurement date used to determine the pension and other postretirement benefits is December 31. The assumptions used to determine the benefit obligation and the periodic costs are as follows:

Weighted-average assumptions used to determine the benefit obligation as of December 31:

	Pension Benefits						OPEB
	2015			2014			2015			2014
Discount rate		4.40	%		4.06	%		4.48	%		4.15	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%		3.50	%

95

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

Weighted-average assumptions used to determine the net benefit cost (income) as of January 1:

	Pension Benefits									OPEB
	2015			2014			2013			2015			2014			2013
Discount rate		4.06	%		4.90	%		4.00	%		4.15	%		5.00	%		4.11	%
Expected return on plan assets		7.75	%		7.75	%		7.75	%		6.52	%		6.52	%		6.52	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%

        The expected long-term rate of return assumption was based on historical return and adjusted to estimate the potential range of returns for the current asset allocation. The assumed 2015 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 7.0%. Each trend rate decreases 0.50% through 2020 to an ultimate rate of 5.0% in 2020 and subsequent years.

        The healthcare cost trend rate affects projected benefit obligations. A 1% change in assumed healthcare cost growth rates would have the following effects (in thousands):

	1% Increase		1% Decrease
Effect on total of service and interest cost	$	2,051	$	(1,530	)
Effect on post-retirement benefit obligation	$	17,473	$	(13,794	)

Fair value measurements of plan assets

        See Note 15 for a discussion of fair value measurements. The Company believes that it is appropriate for the pension fund to assume a moderate degree of investment risk with diversification of fund assets among different classes (or types) of investments, as appropriate, as a means of reducing risk. Although the pension fund can and will tolerate some variability in market value and rates of return in order to achieve a greater long-term rate of return, primary emphasis is placed on preserving the pension fund's principal. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company's Investment Committee. The following is a description of the valuation methodologies used for assets measured at fair value using significant other observable, or significant unobservable inputs.

        Short-term investments:    Valued at cost, which approximates fair value.

        Common/Collective trusts:    Valued at the fair value based on audited financials of the trusts.

        U.S. corporate and foreign issue debt:    Valued at quoted market prices when available in an active market. If quoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows.

        Equity long/short hedge funds:    Valued at the net asset value reported in the annual audited financial statements and updated monthly based on changes in the value of the underlying funds reported by the fund manager.

Pension plan assets

        We utilize fair value in determining the market-related values for the different classes of our pension plan assets. The market-related value is determined based on smoothing actual asset returns in excess of (or less than) expected return on assets over a 5-year period.

96

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

        The Company's primary investment goals for pension fund assets are based around four basic elements:

1.

Preserve capital,



2.

Maintain a minimum level of return equal to the actuarial interest rate assumption,



3.

Maintain a high degree of flexibility and a low degree of volatility, and



4.

Maximize the rate of return while operating within the confines of prudence and safety.

Asset Allocation

        We have adopted an investment strategy referred to as a de-risking glide path to increase the fixed income allocation as the plan's funded status improves. As the pension plan reaches set funded status milestones, the plan's assets will be rebalanced to shift more assets from equity to fixed income. Based on the plan's progress with this strategy, the target investment allocation for pension fund assets is approximately 72% equities and 28% fixed income securities. However, these allocations are permitted to vary within the following ranges: 60% – 80% for equities and 20% – 40% for fixed income securities. Money market funds are permitted within the fixed income category. Investment managers may generally hold up to 10% cash in their portfolios although this limit may be exceeded if market conditions warrant.

        The following fair value hierarchy table presents information about the pension fund assets measured at fair value as of December 31, 2015 and December 31, 2014 (in thousands):

	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Percentage of Plan Assets
Short term investments	$	—	$	71	$	—	$	71		0.0	%
Equity securities
Common collective trusts — domestic		—		46,182		—		46,182		24.7	%
Common collective trusts — international				41,928				41,928		22.5	%
Fixed income
Common collective trust		—		60,694		—		60,694		32.5	%
Other types of investments
Equity long/short hedge funds		—		—		37,970		37,970		20.3	%
	$	—	$	148,875	$	37,970	$	186,845		100.0	%

97

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

	Fair Value Measurements as of December 31, 2014
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Percentage of Plan Assets
Short term investments	$	—	$	70	$	—	$	70		0.0	%
Equity securities
Common collective trusts — domestic		—		48,760		—		48,760		25.3	%
Common collective trusts — international				42,770				42,770		22.2	%
Fixed income
Common collective trust		—		62,646		—		62,646		32.5	%
Other types of investments
Equity long/short hedge funds		—		—		38,428		38,428		20.0	%
	$	—	$	154,246	$	38,428	$	192,674		100.0	%

Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — December 31,

	2015			2014
	Equity long/short hedge funds			Equity long/short hedge funds
Beginning Balance, January 1,	$	38,428		$	36,729
Actual return on plan assets:
Relating to assets still held at the reporting date		(458	)		1,382
Relating to assets sold during the period		—			1,491
Purchases		—			9,700
Sales		—			(10,874	)
Settlements		—			—
Transfers into and (out of) Level 3		—			—
Ending Balance, December 31,	$	37,970		$	38,428

98

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

Permissible Investments

        Listed below are the investment vehicles specifically permitted:

Permissible Investments

Equity Oriented

Fixed Income Oriented and Real Estate

· Common Stocks · Preferred Stocks (minimum "A-rated" by Moody's or S&P) · American Depository Receipts · Convertible Preferred Stocks · Convertible Bonds · Covered Options · Hedged Equity Funds of Funds

· Bonds (including US Government and Agencies) · Corporate Bonds (minimum quality rating of Baa by Moody's or BBB by S&P) · Comingled bond funds (25% max. allocation to high yield) · Foreign Government Bonds · GIC's, BIC's · Commercial Paper (rated A1 by S&P or P1 by Moody's) · Certificates of Deposit in institutions with FDIC/FSLIC protection · Money Market Funds/Bank STIF Funds · Real Estate — Publicly Traded

        The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

        Those investments prohibited by the Investment Committee without prior approval are:

Prohibited Investments Requiring Pre-approval

· Privately Placed Securities · Commodities Futures · Securities of Empire District (except in the hedged equity funds of funds or commingled funds) · Restricted Stock · Warrants · Short Sales · Index Options · Letter Stock

OPEB plan assets

        The Company's primary investment goals for the component of the OPEB fund used to pay current benefits are liquidity and safety. The primary investment goals for the component of the OPEB fund used to accumulate funds to provide for payment of benefits after the retirement of plan participants are preservation of the fund with a reasonable rate of return. The target allocation for plan assets is 60% equities and 40% fixed income, although, at any given time, up to 10% of either category may be invested in cash equivalents. The 10% cash limitation may be exceeded if market conditions warrant. Allocations may also vary within the following ranges: 44% – 76% equities and 36% – 44% fixed income securities. The

99

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

following fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2014 and December 31, 2013 (in thousands):

	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total			Percentage of Plan Assets
Equity securities
Common collective trusts	$	—	$	48,553	$	—	$	48,553			56.9	%
Fixed income
Common collective trusts		—		34,395		—		34,395			40.3	%
Other types of investments
Common collective trusts		—		2,556		—		2,556			3.0	%
	$	—	$	85,504	$	—		85,504
Payable for securities purchased								(135	)		–0.2	%
							$	85,369			100.0	%

	Fair Value Measurements as of December 31, 2014
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total			Percentage of Plan Assets
Equity securities
Common collective trusts	$	—	$	47,690	$	—	$	47,690			56.9	%
Fixed income
Common collective trusts		—		33,708		—		33,708			40.2	%
Other types of investments
Common collective trusts		—		2,453		—		2,453			2.9	%
	$	—	$	83,851	$	—	$	83,851
Payable for securities purchased								(75	)		0.0	%
							$	83,776			100.0	%

        The Company's guideline in the management of this fund is to endorse a long-term approach, but not expose the fund to levels of volatility that might adversely affect the value of the assets. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company's Investment Committee.

100

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

Permissible Investments

        Listed below are the investment vehicles specifically permitted:

Permissible Investments

Equity

Fixed Income

· Common Stocks · Preferred Stocks

· Cash-Equivalent Securities with a maturity of one-year or less, including: money market funds, US Government and Agency securities, certificates of deposit or banker's acceptances issued by domestic banks with FDIC protection and commercial paper rated A1 by S&P or P1 by Moody's · Government Bonds · Money Market Funds / Bank STIF Funds · Certificates of Deposit in institutions with FDIC protection · Corporate Bonds (minimum quality rating of A Baa by Moody's or BBB by S&P at time of issuance)

        The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

        Listed below are those investments prohibited by the Investment Committee:

Prohibited Investments

· Privately Placed Securities · Securities of Empire District · Derivatives · Instrumentalities in violation of the Prohibited Transactions Standards of ERISA · Margin Transactions · Options (other than "covered call options") · Lettered or Restricted Stock · Any other investment security which, in the opinion of the investment manager produces an imprudent risk to the fund

Employee Stock Purchase Plan

        Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The look-back feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the

101

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

maximum subscription price. As of December 31, 2015 there were 764,645 shares available for issuance in this plan.

	2015			2014		2013
Subscriptions outstanding at December 31,		58,742			57,369		60,413
Maximum subscription price	$	21.09	(1)	$	21.43	$	19.58
Shares of stock issued		56,193			56,942		68,099
Stock issuance price	$	21.01		$	19.58	$	17.95

(1)

Stock will be issued on the closing date of the purchase period, which runs from June 1, 2015 to May 31, 2016.

        Assumptions for valuation of these shares are shown in the table below.

	2015			2014			2013
Weighted average fair value of grants	$	3.58		$	3.07		$	2.78
Risk-free interest rate		0.26	%		0.10	%		0.14	%
Dividend yield		4.40	%		4.30	%		4.60	%
Expected volatility(1)		21.00	%		14.00	%		14.00	%
Expected life in months		12			12			12
Grant date		6/1/2015			6/2/2014			6/1/2013

(1)

One-year historic volatility

401(k) Plan and ESOP

        Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to 25% of their annual compensation up to an Internal Revenue Service specified limit. For employees participating in the cash balance formula of the pension plan, discussed above, we match 100% of their deferrals, not to exceed 6% of the employee's eligible compensation. The first 3% of the matching contribution is made in shares of our common stock with the remaining portion made by contributing cash. For employees remaining with the traditional average annual basic earnings formula of the pension plan, we match 50% of their deferrals by contributing shares of our common stock, with such matching contributions not to exceed 3% of the employee's eligible compensation. We record the compensation expense at the time the quarterly matching contributions are made to the plan. At December 31, 2015 there were 129,616 shares available to be issued.

	2015		2014		2013
Shares contributed		66,783		60,049		64,128

Deferred Compensation

        Effective January 2015, we established a non-qualified Deferred Compensation Plan for the purpose of allowing executive officers who elect to participate in the qualifying cash balance option of the Pension plan to obtain retirement savings that are not available to them under the 401(k) plan.

102

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

8.     EQUITY COMPENSATION

        We have several stock-based awards and programs, which are described below. Performance-based restricted stock awards, time-vested restricted stock and stock options are valued as liability awards, in accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award.

        We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in thousands):

	2015		2014		2013
Compensation expense	$	4,279	$	3,688	$	2,577
Tax benefit recognized		1,576		1,359		929

Stock Incentive Plans

        Our 2006 Stock Incentive Plan (the 2006 Incentive Plan), which expired on December 31, 2015, was replaced by the 2015 Stock Incentive Plan (the 2015 Incentive Plan). The 2015 Incentive Plan was adopted by shareholders at the annual meeting on May 1, 2014 and provides for grants of up to 500,000 shares of common stock through January 2025. At December 31, 2015 there were 496,766 shares available to be issued. The 2015 Stock Incentive Plan permits (and the 2006 Incentive Plan permitted) grants of stock options and restricted stock to qualified employees and permits Directors and, if approved by the Compensation Committee of the Board of Directors, qualified employees to receive common stock in lieu of cash. Certain executive officers and other senior managers applied to receive annual incentive awards related to 2013, 2014 and 2015 performance in the form of Empire common stock rather than cash. These requests were granted by the Compensation Committee of the Board of Directors under the terms of our 2006 and 2015 Stock Incentive Plans. The terms and conditions of any option or stock grant are determined by the Board of Directors Compensation Committee, within the provisions of these Stock Incentive Plans.

Time-Vested Restricted Stock Awards

        Beginning in 2011, we began granting, to qualified individuals, time-vested restricted stock awards that vest after a three-year period, in lieu of stock options. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminates during the vesting period because of death, retirement or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned, which is distributed following the date of termination, with the remainder of the award forfeited. If employment is terminated during the vesting period for reasons other than those listed above, the time-vested restricted stock awards will be forfeited on the date of the termination, unless the Board of Directors' Compensation Committee determines, in its sole discretion, that the participant is entitled to a pro-rata portion of the award. In addition, if a change in control occurs during the vesting period, a pro-rata portion of the time-vested restricted stock awards will vest upon such change in control, and any portion of such awards that remains unvested immediately after the change in control will be forfeited.

103

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

        The fair value measurements for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at December 31
	2015	2014
Total unrecognized compensation cost (in millions)	$0.4	$0.4
Recognition period	0.1 years to 2.1 years	1.1 years to 2.1 years
Fair value	$25.17	$26.82

        A summary of time-vested restricted stock activity under the plan for 2015, 2014 and 2013 is presented in the table below:

	2015					2014					2013
	Number of Shares			Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Grant Date Fair Value		Number Of Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1,		41,000		$	21.89		24,900		$	21.42		3,300	$	21.84
Granted		19,000		$	30.40		22,600		$	22.40		21,600	$	21.36
Distributed		(1,654	)	$	21.92		(4,010	)	$	21.77		—		—
Forfeited		(2,746	)	$	25.91		(2,490	)	$	21.99		—		—
Outstanding at December 31,		55,600		$	24.60		41,000		$	21.89		24,900	$	21.42

Performance-Based Restricted Stock Awards

        Performance-based restricted stock awards are granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of the restricted period assuming performance criteria are met. The performance measure for the award is the total return to our shareholders over a three-year period compared with an investor-owned utility peer group. The threshold level of performance under the 2013, 2014 and 2015 grants was set at the 20th percentile level of the peer group, target at the 50th percentile level, and the maximum at the 80th percentile level. Shares would be earned at the end of the three-year performance period as follows: 100% of the target number of shares if the target level of performance is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above the maximum, with the number of shares interpolated between these levels. However, no shares would be payable if the threshold level is not reached.

        If employment terminates during the performance period because of death, retirement, or disability, the individual is entitled to a pro-rata portion of the performance-based restricted stock awards such individual would otherwise have earned. If employment is terminated during the performance period for reasons other than those listed above, the performance-based restricted stock awards will be forfeited on the date of the termination unless the Compensation Committee of the Board of Directors determines, in its sole discretion, that the individual is entitled to a pro-rata portion of such award. In addition, if a change in control occurs during the performance period, a pro-rata portion of the target performance-based restricted stock awards will vest and be distributed upon such change in control. At the end of the performance period, the number of shares earned, determined without regard to the special change in control vesting provisions will be determined and such amount, less the number of shares distributed upon the change in control, shall be distributed. In connection with the Agreement and Plan of Merger dated February 9, 2016, by and among the Company, Liberty Utilities (Central) Co. and Liberty Sub Corp. (the "Merger Agreement"), we amended outstanding performance-based restricted stock awards to provide that, effective upon and subject to the occurrence of the merger under the Merger

104

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

Agreement, each performance-based restricted stock award outstanding immediately prior to the effective time of the merger will be converted into the right to receive a lump sum in cash equal to the merger consideration under the merger agreement, multiplied by the target number of shares under the award. (See Note 17 for further discussion of the Merger Agreement).

        The fair value of the outstanding restricted stock awards was estimated as of December 31, 2015, 2014 and 2013 using a Monte Carlo option valuation model. The assumptions used in the model for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at December 31,
	2015	2014	2013
Risk-free interest rate	0.65% to 1.06%	0.25% to 0.67%	0.13% to 0.38%
Expected volatility of Empire stock	18.7%	14.5%	20.2%
Expected volatility of peer group stock	14.5% to 34.4%	12.4% to 24.8%	12.3% to 27.5%
Expected dividend yield on Empire stock	3.7%	3.5%	4.5%
Expected forfeiture rates	3%	3%	3%
Plan cycle	3 years	3 years	3 years
Fair value percentage	115.0% to 182.0%	140.0% to 157.0%	0.0% to 108.0%
Weighted average fair value per share	$41.73	$43.80	$18.47

        Non-vested performance-based restricted stock awards (based on target number) as of December 31, 2015, 2014 and 2013 and changes during the year ended December 31, 2015, 2014 and 2013 were as follows:

	2015					2014					2013
	Number of Shares			Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Grant Date Fair Value		Number Of Shares			Weighted Average Grant Date Fair Value
Outstanding at January 1,		63,300		$	21.74		47,200		$	21.39		33,900		$	20.25
Target shares granted		21,800		$	30.40		27,000		$	22.40		26,300		$	21.36
Shares issued in excess of target		3,653		$	20.97		—			—		—			—
Shares awarded		(13,653	)	$	20.97		—			—		(4,460	)	$	18.36
Forfeited shares		(6,079	)	$	24.10		—			—		—
Target shares not awarded		—			—		(10,900	)	$	21.84		(8,540	)	$	18.36
Nonvested at December 31,		69,021		$	24.38		63,300		$	21.74		47,200		$	21.39

        At December 31, 2015 and 2014, unrecognized compensation expense related to estimated outstanding awards was $0.7 million and $1.1 million, respectively.

Stock Options

        Beginning in 2011, we began issuing time-vested restricted stock in lieu of stock options and dividend equivalents. Prior to 2011 stock options were issued with an exercise price equal to the fair market value of the shares on the date of grant. They became exercisable after three years and expired ten years after the date granted. Dividend equivalent awards, under which dividend equivalents accumulated during the vesting period, were also issued to recipients of the stock options. Participants' options and dividend equivalents that were not vested were forfeited when participants left Empire, except for terminations of employment under certain specified circumstances. There were no stock options or dividend equivalents granted in 2015, 2014, or 2013, and all outstanding options were exercised prior to December 31, 2014.

105

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

        Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. There were no outstanding options at December 31, 2015 and 2014. The fair value of the outstanding options was estimated as of December 31, 2013, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

	Fair Value of Grants Outstanding at December 31, 2013
Risk-free interest rate	0.10% to 0.38%
Dividend yield	4.5%
Expected volatility	24.0%
Expected life in months	6.5 to 24.5
Market value	$22.69
Weighted average fair value per option	$1.57

        A summary of option activity under the plan during the years ended December 31, 2014 and 2013 is presented below:

	2014				2013
	Options		Weighted Average Exercise Price		Options			Weighted Average Exercise Price
Outstanding at January 1,		112,500	$	23.27		163,300		$	22.13
Granted		—		—				$	—
Exercised		112,500	$	24.58		(50,800	)	$	21.78
Outstanding at December 31,		—				112,500		$	23.27
Exercisable, end of year		—				112,500		$	23.27

        The intrinsic value of the unexercised options is the difference between the Company's closing stock price on the last day of the period and the exercise price multiplied by the number of in-the-money options, had all option holders exercised their options on the last day of the period. The intrinsic value is zero if such closing price is less than the exercise price. The table below shows the aggregate intrinsic values at December 31, 2013:

	2013
Aggregate intrinsic value (in millions)	Less than $0.1
Weighted-average remaining contractual life of outstanding options	2.1 years
Range of exercise prices	$21.92 to $23.81
Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	—
Recognition period	—

Stock Unit Plan for Directors

        Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based compensation program for directors. This plan enhances our ability to attract and retain competent and experienced directors and

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allows the directors the opportunity to accumulate compensation in the form of common stock units. The Stock Unit Plan also provides directors the opportunity to convert previously earned cash retirement benefits to common stock units. All eligible directors who had benefits under the prior cash retirement plan converted their cash retirement benefits to common stock units.

        As of December 31, 2015, a total of 900,000 shares were authorized under this plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock. In connection with the Merger Agreement, we amended the Stock Unit Plan to provide that, effective upon and subject to the occurrence of the merger under the Merger Agreement, each stock unit outstanding immediately prior to the effective time of the merger will be converted into the right to receive in cash the merger consideration under the Merger Agreement, with interest at the prime rate from the effective time of the merger until the payment date under the plan. (See Note 17 for further discussion of the Merger Agreement).

        The number of units granted annually is computed by dividing an annual credit (determined by the Compensation Committee) by the fair market value of our common stock on January 1 of the year the units are granted. Common stock unit dividends are computed based on the fair market value of our stock on the dividend's record date. We record the related compensation expense at the time we make the accrual for the directors' benefits as the directors provide services. Shares accrued to directors' accounts and shares available for issuance under this plan at December 31 are shown in the table below:

	2015		2014
Shares accrued to directors' accounts		157,672		164,085
Shares available for issuance		677,980		714,978

        Units accrued for service and dividends as well as units redeemed for common stock at December 31 are shown in the table below:

	2015		2014		2013
Units accrued for service and dividends		30,595		30,765		34,252
Units redeemed for common stock		37,008		21,083		22,908

9.     INCOME TAXES

        Income tax expense components for the years ended December 31 are as follows (in thousands):

	2015			2014			2013
Current income taxes:
Federal	$	—		$	(2,350	)	$	6,726
State		—			(123	)		2,495
TOTAL		—			(2,473	)		9,221
Deferred income taxes:
Federal		29,722			36,620			24,954
State		4,233			5,216			3,554
TOTAL		33,955			41,836			28,508
Investment tax credit amortization		(143	)		(143	)		(237	)
TOTAL INCOME TAX EXPENSE	$	33,812		$	39,220		$	37,492

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Deferred Income Taxes

        Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows
(in thousands):

	December 31,
Deferred Income Taxes	2015		2014
NET DEFERRED TAX LIABILITIES	$	396,542	$	358,252

        Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows (in thousands):

	December 31,
Temporary Differences	2015		2014
Deferred tax assets:
Plant related basis differences	$	27,347	$	25,349
Net operating loss (NOL)		9,055		22,000
Regulated liabilities related to income taxes		13,142		13,350
Disallowed plant costs		1,699		1,754
Gains on hedging transactions		1,195		1,260
Pensions and other post-retirement benefits		—		1,175
Carry forward of income tax credit		8,675		6,367
Other		1,550		1,633
Total deferred tax assets	$	62,663	$	72,888
Deferred tax liabilities:
Depreciation, amortization and other plant related differences	$	382,897	$	363,337
Regulated assets related to income		38,615		37,180
Loss on reacquired debt		3,572		3,828
Amortization of intangibles		10,248		9,168
Pensions and other post-retirement benefits		7,112		—
Deferred construction accounting costs		5,711		6,082
Other		11,050		11,545
Total deferred tax liabilities		459,205		431,140
NET DEFERRED TAX LIABILITIES	$	396,542	$	358,252

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Effective Income Tax Rates

        The difference between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing operations were as follows:

Effective Income Tax Rates	2015			2014			2015
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit)		3.1			3.1			3.1
Investment tax credit amortization		(0.2	)		(0.1	)		(0.2	)
Effect of ratemaking on property related differences		(1.4	)		(1.7	)		(1.1	)
Other		0.9			0.6			0.3
EFFECTIVE INCOME TAX RATE		37.4	%		36.9	%		37.1	%

        We do not have any unrecognized tax benefits as of December 31, 2015. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.

        The "Protecting Americans from Tax Hikes" Act (the "Act") was signed into law on December 18, 2015. The Act restored several expired business tax provisions, including bonus depreciation for 2015. Because of the reinstatement of bonus depreciation, we anticipate making no material income tax payments in 2016.

        We generated $74.1 million of tax NOLs during 2014, mainly due to bonus depreciation. We intend to carry forward these tax NOLs, which, if unused, will expire in 2034. We estimate that we will utilize approximately $38.0 million of the 2014 tax NOLs on our 2015 return when filed. As of December 31, 2015, we estimate there is $13.5 million of deferred tax assets remaining to be utilized related to the tax NOLs. A portion of the deferred tax assets related to the tax NOLs is recorded as a receivable on the balance sheet in anticipation of income tax payment refunds.

        In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2, which, if unused, will expire in 2030. We utilized $9.0 million of these credits on our 2013 tax return. Due to the passage of the Act, we estimate we will not be able to use the remaining credits on our 2015 tax return, but expect to use them to offset future income tax liabilities. The tax credits will have no significant income statement impact because they will flow to our customers as we amortize the tax credits over the life of the plant.

        On September 13, 2013, the IRS and the Treasury Department released final regulations under Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations applied to tax years beginning on or after January 1, 2014, and we filed a Form 3115 with the IRS to change our tax accounting method to comply with the regulations. As a result, we deducted approximately $29 million on our 2014 income tax return under IRS Code Section 481(a) as an adjustment required by the change in tax accounting method.

        Our 2014 income tax return included another tax accounting method change regarding the deductibility of the Voluntary Employee Benefit Association (VEBA) plan activity. As a result, we deducted approximately $14 million as an adjustment required by the change in tax method of accounting. These changes did not have a material impact on the effective tax rate.

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10.   COMMONLY OWNED FACILITIES

Iatan

        We own a 12% undivided interest in the coal-fired Units No. 1 and 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 each unit's available capacity and are obligated to pay for a like percentage of the operating costs of the units. KCP&L and KCP&L Greater Missouri Operations Co. own 70% and 18% respectively, of Unit 1, and 54% and 18%, respectively, of Unit 2. KCP&L operates the units for the joint owners.

        At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions):

Iatan	2015		2014
Cost of ownership in plant in service	$	380.2	$	373.3
Accumulated Depreciation	$	105.3	$	99.1
Expenditures(1)	$	26.9	$	27.8

(1)

Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.

State Line Combined Cycle Unit

        We and Westar Generating, Inc, ("WGI"), a subsidiary of Westar Energy, Inc., share joint ownership of a nominal 500-megawatt combined cycle unit at the State Line Power Plant (the "State Line Combined Cycle Unit"). We are responsible for the operation and maintenance of the State Line Combined Cycle Unit, and are entitled to 60% of the available capacity and are responsible for approximately 60% of its costs.

        At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions):

State Line Combined Cycle Unit	2015		2014
Cost of ownership in plant in service	$	163.0	$	161.5
Accumulated Depreciation	$	43.5	$	40.0
Expenditures(1)	$	40.7	$	47.1

(1)

Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.

Plum Point Energy Station

        We own a 7.52% undivided interest in the coal-fired Plum Point Energy Station located near Osceola, Arkansas. We are entitled to 7.52% of the station's capacity, and are obligated to pay for a like percentage of the station's operating costs.

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        At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions):

Plum Point Energy Station	2015		2014
Cost of ownership in plant in service	$	109.1	$	108.3
Accumulated Depreciation	$	11.9	$	9.4
Expenditures(1)	$	9.6	$	8.1

(1)

Recognized in operating, maintenance and fuel expenditures excluding depreciation expense.

        All of the dollar amounts listed above represent our ownership share of costs.

11.   COMMITMENTS AND CONTINGENCIES

        We are a party to various claims and legal proceedings arising out of the normal course of our business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company's defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.

Coal, Natural Gas and Transportation Contracts

        The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of December 31, 2015 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
January 1, 2016 through December 31, 2016	$	26.7	$	18.0
January 1, 2017 through December 31, 2018		37.4		27.5
January 1, 2019 through December 31, 2020		28.8		10.8
January 1, 2021 and beyond		45.7		—

        We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be placed in storage. The firm physical gas and transportation commitments are detailed in the table above.

        We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of December 31, 2015 are detailed in the table above.

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Purchased Power

        We currently supplement our on-system (native load) generating capacity with purchases of capacity and energy from other entities 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 (NERC) rules.

        The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit's capacity. We also have a long-term agreement for the purchase of an additional 50 megawatts of capacity from Plum Point. Commitments under this agreement are approximately $277.6 million through August 31, 2039, the end date of the agreement. 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 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 do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.

        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 the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost.

        Payments for these agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations shown below.

New Construction

        We have in place a contract with a third party vendor to complete engineering, procurement, and construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion includes the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. The Air Emission Source Construction Permit necessary for this project was issued by Kansas Department of Health and Environment on July 11, 2013. This conversion is currently scheduled to be completed in early to mid-2016 at a cost estimated to range from $165 million to $175 million, excluding allowance for funds used during construction (AFUDC). Construction costs, consisting of pre-engineering, site preparation activities and contract costs incurred project to date through December 31, 2015 were $159.6 million, excluding AFUDC.

        In December 2014 we completed an environmental retrofit at our Asbury plant. The retrofit project included the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This new equipment enables us to comply with the Mercury and Air Toxics Standard (MATS). Final costs were approximately $112.1 million, excluding AFUDC.

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Leases

        We have purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these agreements are disclosed in the Purchased Power section of this note.

        We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.

        The gross amount of assets recorded under capital leases total $5.3 million at December 31, 2015.

        Our lease obligations over the next five years are as follows (in thousands):

	Capital Leases		Operating Leases
2016	$	554	$	734
2017		551		689
2018		551		648
2019		550		484
2020		546		—
Thereafter		2,460		—
Total minimum payments		5,212	$	2,555
Less amount representing interest		1,322
Present value of net minimum lease payments	$	3,890

        Expenses incurred related to operating leases were $0.8 million, $0.8 million and $0.8 million for 2015, 2014, and 2013, respectively, excluding payments for wind generated purchased power agreements. The accumulated amount of amortization for our capital leases was $1.9 million and $1.5 million at December 31, 2015 and 2014, respectively.

Environmental Matters

        We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and hazardous and other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. We believe that our operations are in material compliance with present environmental laws and regulations. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect these costs to be material, although recoverable in rates.

Compliance Plan

        In order to comply with current and forthcoming environmental regulations, we continue to implement our compliance plan and strategy (Compliance Plan), which largely follows our Integrated Resource Plan (IRP) filed with MPSC in mid-2013. The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), are the drivers behind our Compliance Plan and its implementation schedule. We anticipate compliance costs associated with the MATS, CAIR and CSAPR regulations to continue to be recoverable in our rates.

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        The following list summarizes the most significant environmental regulations affecting our operations:

Regulations

Air Emissions — NOx and SO2

CAIR (Clean Air Interstate Rule)

CSAPR (Cross State Air Pollution Rule)

MATS (Mercury Air Toxic Standards)

NAAQS (National Ambient Air Quality Standards)

Greenhouse Gases (GHGs) — CO₂

Surface Impoundments

Coal Ash Impoundments:

Asbury Power Plant

Riverton (capped and closed in 2014 as industrial (coal combustion waste) landfill)

Water Discharges

        MATS:    In June 2015, the U.S. Supreme Court remanded the MATS back to the D.C. Circuit Court, holding that the EPA must consider cost (including cost of compliance) before deciding whether a regulation is appropriate and necessary. The court noted that it will be up to the EPA to decide within the limits of reasonable interpretation how to account for cost. MATS remains in effect until the D.C. Circuit Court acts.

        Greenhouse Gases:    On August 3, 2015, the EPA released the final rule for limiting carbon emissions from existing power plants. The "Clean Power Plan" (CPP) requires a 32% carbon emission reduction from 2005 baseline levels by 2030 and requires fossil fuel-fired power plants across the nation, including those in Empire's fleet, to meet state-specific goals to lower carbon levels. States will choose between two plan types to meet their goals: an emission standards plan which includes source-specific requirements impacting affected power plants or a state measures plan which includes a mixture of measures implemented by the state.

        By September 6, 2016, each state must either submit to the EPA its initial plan with a request for an extension or a final plan. If the state receives an extension, the final plan must be submitted by September 6, 2018. States will then implement plans to achieve the progressive CO2 emissions performance rates over the period of 2022 to 2029 with the final CO2 goal accountability by 2030. Empire continues to evaluate potential paths forward on the final rule released by the EPA. As of January 26, 2016, twenty-five states have initiated legal challenges to the CPP which by and large seek to invalidate the rule. The ultimate cost of compliance cannot be determined at this time because of the uncertainties regarding the final outcome of the GHG regulations, including the legal challenges thereto, and the compliance methods yet to be chosen by the jurisdictions in which we operate. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates.

        Surface Impoundments:    On September 30, 2015, the EPA finalized a revision of the Clean Water Act (CWA) Steam Electric Effluent Limitation Guidelines (ELGs) for coal-fired power plants. The new rule sets technology-based ELGs based on the nature of the pollutants being discharged and the facilities involved. As published, beginning in November 2018, the EPA and states would incorporate the new standards into all wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs at each facility that will result from the new standards to be in effect no later than December 2023.

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        Effective October 19, 2015, the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs) as a non-hazardous solid waste under subtitle D of the Resource Conservation and Recovery Act (RCRA). We expect compliance with both the CCR and ELG rule to result in the need to construct a new landfill and the conversion of existing bottom ash handling from a wet to a dry system at a potential cost of up to $15 million at our Asbury Power Plant. We expect resulting costs to be recoverable in our rates. Final closure of the existing ash impoundment, for which an asset retirement obligation of $5.4 million has been recorded, is anticipated after the new landfill is operational. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station.

        We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. A technical review of our Detailed Site Investigation (DSI) for the specific site has been completed and was approved by the Missouri Department of Natural Resources on June 29, 2015. Receipt of the final construction permit for the CCR waste landfill is expected in January 2017.

        Water Discharges:    We operate under the Kansas and Missouri Water Pollution Plans pursuant to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received all necessary discharge permits.

        The EPA final rule under the CWA Section 316(b) for existing cooling water intake structures became effective on October 14, 2014. An industry coalition has filed an appeal of the rule in the Fifth Circuit and additional court challenges are expected. We expect the regulations to have no future impact at Riverton as the new intake structure design and installed cooling tower, as part of the Unit 12 conversion, meets the regulatory requirement for aquatic life protections. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Iatan Unit 2 and Plum Point Unit 1 are covered by the regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally affected by the final rule.

Renewable Energy

        On November 4, 2008 Missouri voters approved the Clean Energy Initiative (Proposition C) which currently requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC. Proposition C also requires that 2% of the energy from renewable energy sources must be solar; however, we believed that we were exempted by statute from the solar requirement. On January 20, 2013 the Earth Island Institute, d/b/a Renew Missouri, and others challenged our solar exemption by filing a complaint with the MPSC. The MPSC dismissed the complaint and Renew Missouri filed a notice of appeal seeking review by the Missouri Supreme Court. On February 10, 2015 the Missouri Supreme Court issued an opinion holding that the legislature had the authority to adopt the statute providing the exemption but reversed the MPSC's holding that the two laws could be harmonized. The statute providing the exemption (which was enacted in August 2008) was impliedly repealed by the adoption of Proposition C because it conflicted with the latter law. 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. As of December 31, 2015, we had processed 262 solar rebate applications resulting in solar rebate-related costs totaling approximately $3.5 million under the new tariff. We have recorded the $3.5 million as a regulatory asset

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Notes to Consolidated Financial Statements (Continued)

(See Note 3 — Regulatory Matters). The law provides a number of methods that may be utilized to recover the associated expenses. We expect any costs to be recoverable in rates.

        Legislation was recently adopted that altered the Kansas renewable portfolio standard (RPS), ending all mandatory requirements in 2015. The mandate, which required 20% of our Kansas retail customer peak capacity requirements to be sourced from renewables by 2020, has been changed to a voluntary goal. We are currently in compliance as a result of purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC.

12.   SEGMENT INFORMATION

        We operate our business as three segments: electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company is our wholly owned subsidiary formed to provide gas distribution service in Missouri. The other segment consists of our non-regulated businesses which is primarily our fiber optics business.

        The tables below present statement of income information, balance sheet information and capital expenditures of our business segments.

	For the year ended December 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
Operating Revenues(1)	$	555,085	$	41,702	$	10,165	$	(1,379	)	$	605,573
Depreciation and amortization		74,732		3,923		1,895		—			80,550
Federal and state income taxes		31,123		800		1,889		—			33,812
Operating income		88,124		5,153		3,024		—			96,301
Interest income		133		36		47		(71	)		145
Interest expense		41,307		3,867		—		(71	)		45,103
Income from AFUDC (debt and equity)		7,681		14		—		—			7,695
Income from continuing operations	$	52,240	$	1,287	$	3,070	$	—		$	56,597
Capital Expenditures	$	169,111	$	5,190	$	2,223	$	—		$	176,524

(1)

The Electric Segment includes SPP Integrated Marketplace net revenues of $15.0 million.

	2014
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
Operating Revenues(1)	$	592,491	$	51,842	$	9,302	$	(1,305	)	$	652,330
Depreciation and amortization		67,534		3,760		1,891		—			73,185
Federal and state income taxes		35,737		1,840		1,643		—			39,220
Operating income		90,488		6,775		2,736		—			99,999
Interest income		37		25		21		(32	)		51
Interest expense		37,911		3,861		—		(32	)		41,740
Income from AFUDC (debt and equity)		9,833		84		—		—			9,917
Income from continuing operations	$	61,467	$	2,965	$	2,671	$	—		$	67,103
Capital Expenditures	$	212,866	$	7,836	$	2,151	$	—		$	222,853

(1)

The Electric Segment includes SPP Integrated Marketplace net revenues of $41.9 million.

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	2013
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
Operating Revenues	$	536,413	$	50,041	$	9,147	$	(1,271	)	$	594,330
Depreciation and amortization		63,659		3,709		1,938		—			69,306
Federal and state income taxes		34,478		1,484		1,530		—			37,492
Operating income		90,984		6,194		2,485		—			99,663
Interest income		537		115		8		(94	)		566
Interest expense		37,683		3,890		—		(94	)		41,479
Income from AFUDC (debt and equity)		5,910		30		—		—			5,940
Income from continuing operations	$	58,603	$	2,355	$	2,487	$	—		$	63,445
Capital Expenditures	$	153,401	$	4,419	$	2,388	$	—		$	160,208

	December 31, 2015
	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information:
Total assets	$	2,339,850	$	127,871	$	38,300	$	(50,718	)	$	2,455,303

	December 31, 2014
	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information:
Total assets	$	2,252,339	$	130,856	$	34,655	$	(46,794	)	$	2,371,056

(1)

Includes goodwill of $39,492 at December 31, 2015 and 2014.

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Notes to Consolidated Financial Statements (Continued)

13.   SELECTED QUARTERLY INFORMATION (UNAUDITED)

        The following is a summary of quarterly results for 2015 and 2014 (dollars in thousands except per share amounts):

	Quarters
Quarterly Results for 2015	First		Second		Third		Fourth
Operating revenues(1)	$	164,544	$	134,557	$	169,714	$	136,758
Operating income	$	24,713	$	16,047	$	35,783	$	19,757
Net Income	$	14,637	$	6,770	$	25,285	$	9,905
Basic Earnings Per Share	$	0.34	$	0.16	$	0.58	$	0.23
Diluted Earnings Per Share	$	0.34	$	0.15	$	0.58	$	0.23

(1)

Operating revenue for the first, second, third and fourth quarters of 2015 include SPP IM net revenues of $4.7 million, $3.4 million, $4.0 million, and $2.9 million, respectively.

	Quarters
Quarterly Results for 2014	First		Second		Third		Fourth
Operating revenues(1)	$	179,673	$	149,782	$	171,512	$	151,363
Operating income	$	29,488	$	19,502	$	31,709	$	19,300
Net Income	$	20,905	$	11,194	$	23,892	$	11,112
Basic and Diluted Earnings Per Share	$	0.48	$	0.26	$	0.55	$	0.26

(1)

Operating revenue for the first, second, third and fourth quarters of 2014 include SPP IM net revenues of $6.2 million, $16.5 million, $11.5 million, and $7.5 million, respectively.

        The sum of the net income and quarterly earnings per share of common stock may not equal the net income and earnings per share of common stock as computed on an annual basis due to rounding.

14.   RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

        We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain cost predictability.

        We began acquiring Transmission Congestion Rights (TCR) in 2013 in an effort to mitigate the cost of power we purchase from the SPP IM due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

        All derivative instruments are recognized at fair value on the balance sheet. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms.

        Risks and uncertainties affecting the determination of fair value include: market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instruments in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income and subject to our fuel adjustment mechanism.

        As of December 31, 2015 and 2014, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of December 31, (in thousands):

ASSET DERIVATIVES

Non-designated hedging instruments due to regulatory accounting		2015		2014
	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	2	$	—
	Non-current assets and deferred charges — Other		16		—
Natural gas contracts, electric segment	Current assets		—		1
	Non-current assets and deferred charges — Other		—		—
Transmission congestion rights, electric segment	Current assets		1,293		3,900
Total derivatives assets		$	1,311	$	3,901

LIABILITY DERIVATIVES

Non-designated as hedging instruments due to regulatory accounting		2015		2014
	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	282	$	476
	Non-current liabilities and deferred credits		66		—
Natural gas contracts, electric segment	Current liabilities		4,190		5,993
	Non-current liabilities and deferred credits		3,630		3,243
Transmission congestion rights, electric segment	Current liabilities		—		—
Total derivatives liabilities		$	8,168	$	9,712

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

Electric

        At December 31, 2015, approximately $4.2 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months.

        There were no "mark-to-market" pre-tax gains/ (losses) from ineffective portions of our hedging activities for the electric segment for the years ended December 31, 2015 and 2014, respectively.

        The following tables set forth "mark-to-market" pre-tax gains/ (losses) from non-designated derivative instruments for the electric segment for each of the years ended December 31 (in thousands):

Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment

		Amount of Gain/(Loss) Recognized on Balance Sheet
	Balance Sheet Classification of Gain/(Loss) on Derivative	2015			2014
Commodity contracts — electric segment	Regulatory (assets)/liabilities	$	(6,853	)	$	(6,780	)
Transmission congestion rights — electric segment	Regulatory (assets)/liabilities		4,970			12,958
Total — Electric Segment		$	(1,883	)	$	6,178

Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment

		Amount of Gain/(Loss) Recognized in Income on Derivative
	Statement of Operations Classification of Loss on Derivative	2015			2014
Commodity contracts	Fuel and purchased power expense	$	(8,115	)	$	(1,659	)
Transmission congestion rights — electric segment	Fuel and purchased power expense		7,468			11,106
Total — Electric Segment		$	(647	)	$	9,447

        We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to fair value accounting because they qualify for the normal purchase normal sale exemption. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchase normal sale exception contain a price adjustment feature and will account for these contracts accordingly.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

        At December 31, 2015, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for 2016 and the next four years are hedged at the following average prices per Dekatherm (Dth):

Year	% Hedged			Dth Hedged Physical		Dth Hedged Financial		Average Price
2016		61	%		2,706,000		5,940,000	$	3.372
2017		41	%		782,900		5,210,000	$	3.347
2018		20	%		565,000		2,460,000	$	3.334
2019		10	%		—		1,460,000	$	2.955
2020		0	%		—		—		—

        We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year's and 80% of any future year's expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.

Year	End of Year Minimum % Hedged
Current	Up to 100%
First	60%
Second	40%
Third	20%
Fourth	10%

        At December 31, 2015, the following transmission congestion rights (TCR) have been obtained from TCR auctions to hedge congestion costs in the SPP Integrated Marketplace:

Year	Monthly MWH Hedged		$ Value
2016		3,212	$	1,292,943

Gas

        We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of December 31, 2015 we had 1.4 million Dths in storage on the three pipelines that serve our customers. This represents 70% of our storage capacity.

        The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

winter seasons by the beginning of the ACA year at September 1 and illustrates our hedged position as of December 31, 2015 (Dth in thousands).

Season	Minimum % Hedged			Dth Hedged Financial		Dth Hedged Physical		Dth in Storage		Actual % Hedged
Current		50	%		400,000		—		1,419,752		93	%
Second		Up to 50	%		200,000		—		—		6	%
Third		Up to 20	%		280,000		—		—		9	%

        A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

        The following table sets forth "mark-to-market" pre-tax gains/ (losses) from derivatives not designated as hedging instruments for the gas segment for the years ended December 31 (in thousands):

Non-Designated Hedging Instruments Due to Regulatory Accounting — Gas Segment

		Amount of Loss Recognized on Balance Sheet
	Balance Sheet Classification of Loss on Derivative	2015			2014
Commodity contracts	Regulatory assets	$	(447	)	$	(511	)
						—
Total — Gas Segment		$	(447	)	$	(511	)

Contingent Features

        Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. We had no derivative instruments with the credit-risk-related contingent features in a net liability position on December 31, 2015 and have posted no collateral in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at the dates shown. There were no margin deposit liabilities at these dates.

(in millions)	December 31, 2015		December 31, 2014
Margin deposit assets	$	11.2	$	9.1

Offsetting of derivative assets and liabilities

        We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Collateral requirements are calculated at the master trading and netting agreement level by the counterparty.

        As shown above, our asset and liability commodity contract derivatives are reported at gross on the balance sheet. ASC guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. For the years ended December 31, 2015 and December 31, 2014, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

15.   FAIR VALUE MEASUREMENTS

        The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data.

        The guidance also requires that the fair value measurement of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.

        Our TCR positions, which are acquired on the SPP Integrated Marketplace, are valued using the most recent monthly auction clearing prices. Our commodity contracts are valued using the market value

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Notes to Consolidated Financial Statements (Continued)

approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of December 31:

Fair Value Measurements at Reporting Date Using

($ in 000's) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2015
Derivative assets	$	1,311		$	18		$	1,293	$	—
Derivative liabilities	$	(8,168	)	$	(8,168	)	$	—	$	—
December 31, 2014
Derivative assets	$	3,901		$	1		$	3,900	$	—
Derivative liabilities	$	(9,712	)	$	(9,712	)	$	—	$	—

*

The only recurring measurements are derivative related.

Other fair value considerations

        Our cash and cash equivalents approximate fair value because of the short-term nature of these instruments, and are classified as Level 1 in the fair value hierarchy. The carrying amount of our short-term debt, which is composed of Empire issued commercial paper or revolving credit borrowings, also approximates fair value because of their short-term nature. These instruments are classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions.

        The carrying amount of our total long-term debt exclusive of capital leases at December 31, 2015 and 2014 was $859 million and $799 million, compared to a fair market value of approximately $815 million and $829 million, respectively. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of December 31, 2015 or that will be realizable in the future.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

16.   REGULATED OPERATING EXPENSE

        The following table sets forth the major components comprising "regulated operating expenses" under "Operating Revenue Deductions" on our consolidated statements of income for the years ended (in thousands):

	December 31,
	2015		2014		2013
Power operation expense (other than fuel)	$	18,263	$	16,089	$	15,643
Electric transmission and distribution expense		28,893		27,919		21,863
Natural gas transmission and distribution expense		2,699		2,362		2,498
Customer accounts & assistance expense		10,937		11,239		11,180
Employee pension expense(1)		10,786		10,590		10,736
Employee healthcare plan(1)		10,162		9,147		10,190
General office supplies and expense		14,438		15,024		12,850
Administrative and general expense		14,863		14,385		14,800
Bad debt expense		2,080		3,420		3,665
Regulatory reversal of gain on sale of assets		—		44		1,236
Miscellaneous expense		430		472		672
TOTAL	$	113,551	$	110,691	$	105,333

(1)

Does not include the capitalized portion of actuarially calculated costs, but reflects the GAAP expensed portion of these costs plus or minus costs deferred to a regulatory asset or recognized as a regulatory liability for Missouri and Kansas jurisdictions.

17.   SUBSEQUENT EVENT — AGREEMENT AND PLAN OF MERGER

        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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements (Continued)

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), 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.

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

        None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

        As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2015.

Management's Report on Internal Control Over Financial Reporting

        Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2015.

Audit of Internal Control Over Financial Reporting

        The effectiveness of our internal control over financial reporting as of December 31, 2015, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Control Over Financial Reporting

        There have been no changes in our internal control over financial reporting that occurred during the fourth quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

        None.

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

        Except as set forth below, the information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2016, which is incorporated herein by reference.

        Pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, the information required by this Item with respect to executive officers is set forth in Item 1 of Part I of this Form 10-K under "Executive Officers and Other Officers of Empire."

        We have adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers. A copy of the code is available on our website at www.empiredistrict.com. Any future amendments or waivers to the code will be posted on our website at www.empiredistrict.com.

ITEM 11.    EXECUTIVE COMPENSATION

        Information required by this item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2016, which is incorporated herein by reference.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

        Except as set forth below, information required by this item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2016, which is incorporated herein by reference.

Securities Authorized For Issuance Under Equity Compensation Plans

        We have four equity compensation plans, all of which have been approved by shareholders, namely the 2006 Stock Incentive Plan, the 2015 Stock Incentive Plan (which replaces the 2006 Stock Incentive Plan for new grants effective January 1, 2015), the Employee Stock Purchase Plan (ESPP) and the Stock Unit Plan for Directors.

        The following table summarizes information about our equity compensation plans as of December 31, 2015:

Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights.		(b) Weighted-average exercise price of outstanding options, warrants and rights(1)		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders		422,214	$	N/A		2,023,019
Equity compensation plans not approved by security holders		—		—		—
TOTAL		422,214	$	N/A		2,023,019

(1)

There is no exercise price for 150,200 performance-based stock awards and 55,600 time-vested restricted stock awards awarded under the 2006and 2015 Stock Incentive Plan or for 157,672 units awarded under the Stock Unit Plan for Directors

(2)

Includes 764,645 shares available for issuance under the ESPP of which 58,742 shares are subject to purchase under the current purchase period.

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ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

        The information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2016 which is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

        The information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2016 which is incorporated herein by reference.

129

PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Index to Financial Statements and Financial Statement Schedule Covered by Report of
Independent Registered Public Accounting Firm

Consolidated balance sheets at December 31, 2015 and 2014	58
Consolidated statements of income for each of the three years in the period ended December 31, 2015	60
Consolidated statements of common stockholders' equity for each of the three years in the period ended December 31, 2015	61
Consolidated statements of cash flows for each of the three years in the period ended December 31, 2015	62
Notes to consolidated financial statements	64
Schedule for the years ended December 31, 2015, 2014 and 2013:
Schedule II — Valuation and qualifying accounts	135

        All other schedules are omitted as the required information is either not present, is not present in sufficient amounts, or the information required therein is included in the financial statements or notes thereto.

List of Exhibits

(2)(a)	Agreement and Plan of Merger, dated as of February 9, 2016, by and among The Empire District Electric Company, Liberty Utilities (Central) Co. and Liberty Sub Corp. (Incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K dated February 9, 2016 and filed February 9, 2016, File No. 1-3368).
(3)(a)	The Restated Articles of Incorporation of Empire (Incorporated by reference to Exhibit 4(a) to Registration Statement No. 33-54539 on Form S-3).
(b)	Amended and Restated By-Laws of The Empire District Electric Company, effective February 9, 2016 (Incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K dated February 9, 2016 and filed February 9, 2016, File No. 1-3368).
(4)(a)	Indenture of Mortgage and Deed of Trust dated as of September 1, 1944 and First Supplemental Indenture thereto among The Empire District Electric Company, The Bank of New York Mellon Trust Company, N.A. and UMB Bank, N.A., (Incorporated by reference to Exhibits B(1) and B(2) to Form 10, File No. 1-3368).
(b)	Third Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924).
(c)	Sixth through Eighth Supplemental Indentures to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924).
(d)	Fourteenth Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(f) to Registration Statement No. 33-56635 on Form S-3).
(e)	Twenty-Fourth Supplemental Indenture dated as of March 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-3368).

130

(f)	Twenty-Eighth Supplemental Indenture dated as of December 1, 1996 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(g) to Annual Report on Form 10-K for the year ended December 31, 1996, File No. 1-3368).
(g)	Thirty-First Supplemental Indenture dated as of March 26, 2007 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated March 26, 2007 and filed March 28, 2007, File No. 1-3368).
(h)	Thirty-Second Supplemental Indenture dated as of March 11, 2008 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated March 11, 2008 and filed March 12, 2008, File No. 1-3368).
(i)	Thirty-Third Supplemental Indenture dated as of May 16, 2008 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated May 16, 2008 and filed May 16, 2008, File No. 1-3368).
(j)	Thirty-Fifth Supplemental Indenture, dated as of May 28, 2010, to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated May 28, 2010 and filed May 28, 2010, File No. 1-3368).
(k)	Thirty-Sixth Supplemental Indenture, dated as of August 25, 2010, to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated August 25, 2010 and filed August 26, 2010, File No. 1-3368).
(l)	Thirty-Seventh Supplemental Indenture, dated as of June 9, 2011, to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated June 9, 2011 and filed June 10, 2011, File No. 1-3368).
(m)	Thirty-Eighth Supplemental Indenture, dated as of April 2, 2012, to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated April 2, 2012 and filed April 2, 2012, File No. 1-3368).
(n)	Thirty-Ninth Supplemental Indenture, dated as of May 30, 2013, to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated May 30, 2013 and filed May 30, 2013, File No. 1-3368).
(o)	Fortieth Supplemental Indenture, dated as of December 1, 2014, to the Indenture of Mortgage and Deed of Trust (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated December 1, 2014 and filed December 2, 2014, File No. 1-3368).
(p)	Forty-first Supplemental Indenture, dated as of August 20, 2015, to the Indenture of Mortgage and Deed of Trust (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated August 20, 2015 and filed August 21, 2015, File No. 1-3368).
(q)	Bond Purchase Agreement, dated as of April 2, 2012, by and among the Company and the Purchasers named therein (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated April 2, 2012 and filed April 2, 2012, File No. 1-3368).
(r)	Bond Purchase Agreement, dated as of October 30, 2012, by and among the Company and the Purchasers named therein (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated October 30, 2012 and filed November 2, 2012, File No. 1-3368).
(s)	Bond Purchase Agreement, dated as of October 15, 2014, by and among the Company and the Purchasers named therein (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated October 15, 2014 and filed October 16, 2014, File No. 1-3368).

131

(t)	Bond Purchase Agreement, dated as of June 11, 2015, by and among the Company and the Purchasers named therein (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated June 11, 2015 and filed June 12, 2015, File No. 1-3368).
(u)	Indenture for Unsecured Debt Securities, dated as of September 10, 1999 between Empire and Wells Fargo Bank, National Association (Incorporated by reference to Exhibit 4(v) to Registration Statement No. 333-87015 on Form S-3).
(v)	Securities Resolution No. 5, dated as of October 29, 2003, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Quarterly Report on Form 10-Q for quarter ended September 30, 2003), File No. 1-3368).
(w)	Securities Resolution No. 6, dated as of June 27, 2005, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated June 27, 2005 and filed June 28, 2005, File No. 1-3368).
(x)	Bond Purchase Agreement dated June 1, 2006 among The Empire District Gas Company and the purchasers party thereto (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated June 1, 2006 and filed June 6, 2006, File No. 1-3368).
(y)	Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The Empire District Gas Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for the Benefit of The Bank of New York Trust Company, N.A., Bond Trustee, as Grantee (Incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated June 1, 2006 and filed June 6, 2006, File No. 1-3368).
(z)	First Supplemental Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The Empire District Gas Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for the Benefit of The Bank of New York Trust Company, N.A., Bond Trustee, as Grantee (Incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K dated June 1, 2006 and filed June 6, 2006, File No. 1-3368).
(10)(a)	2006 Stock Incentive Plan (Incorporated by reference to Exhibit 4(u) to Form S-8, File No. 333-130075).†
(b)	First Amendment to 2006 Stock Incentive Plan. (Incorporated by reference to Exhibit 10(d) to Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-3368).†
(c)	Second Amendment to 2006 Stock Incentive Plan (Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-3368).†
(d)	2015 Stock Incentive Plan (incorporated by reference to Appendix B to the definitive proxy statement filed pursuant to Regulation 14A on March 19, 2014, File No. 1-3368).
(e)	Deferred Compensation Plan for Directors as amended and restated effective January 1, 2008. (Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for the year ended December 31, 2007).†
(f)	Deferred Compensation Plan for Officers effective January 1, 2015, (Incorporated by reference to Exhibit 10(f) to Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-03368).†*
(g)	The Empire District Electric Company Change in Control Severance Pay Plan as amended and restated effective January 1, 2008. (Incorporated by reference to Exhibit 10(f) to Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-3368).†

132

(h)	Form of Severance Pay Agreement under The Empire District Electric Company Change in Control Severance Pay Plan. (Incorporated by reference to Exhibit 10(g) to Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-3368).†
(i)	The Empire District Electric Company Supplemental Executive Retirement Plan as amended and restated effective January 1, 2014 (Incorporated by reference to Exhibit 10(i) to Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-03368).†*
(j)	Retirement Plan for Directors as amended August 1, 1998 (Incorporated by reference to Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 1998, File No. 1-3368).†
(k)	Stock Unit Plan for Directors of The Empire District Electric Company (Incorporated by reference to Exhibit 10(i) to Annual Report on Form 10-K for the year ended December 31, 2005, File No. 1-3368).†
(l)	First Amendment to Stock Unit Plan for Directors. (Incorporated by reference to Exhibit 10(k) to Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-3368).†
(m)	Amended and Restated Stock Unit Plan for Directors (incorporated by reference to Appendix C to the definitive proxy statement filed pursuant to Regulation 14A on March 19, 2014, File No. 1-3368).
(n)	Amendment to the Amended and Restated Stock Unit Plan for Directors.†*
(o)	Summary of Annual Incentive Plan (Incorporated by reference to Exhibit 10(n) to Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-03368).†
(p)	Form of Notice of Award of Performance-Based Restricted Stock. (Incorporated by reference to Exhibit 10(p) to Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-3368).†
(q)	Form of Amendment to Performance-Based Restricted Stock Award.†*
(r)	Form of Notice of Award of Time-Vested Restricted Stock.†*
(s)	Summary of Compensation of Non-Employee Directors.† (Incorporated by reference to Exhibit 10(r) to Annual Report on Form 10-K for the year ended December 31, 2012, File No. 1-3368).
(t)	Form of Indemnity Agreement (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated February 5, 2009 and filed February 10, 2009, File No. 1-3368).†
(u)	Credit Agreement, dated as of October 20, 2014, among The Empire District Electric Company, Wells Fargo Bank, as Administrative Agent, Swingline Lender and Issuing Bank, and the lenders named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated October 20, 2014 and filed October 22, 2014, File No. 1-3368).
(v)	Guarantee Agreement, dated as of February 9, 2016, made by Algonquin Power and Utilities Corp. in favor of The Empire District Electric Company (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated February 9, 2016 and filed February 9, 2016, File No. 1-3368).
(12)	Computation of Ratios of Earnings to Fixed Charges.*
(21)	Subsidiaries of Empire.*
(23)	Consent of PricewaterhouseCoopers LLP.*
(24)	Powers of Attorney.*

133

(31)(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
(31)(b)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
(32)(a)	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~
(32)(b)	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~
(101)	The following financial information from The Empire District Electric Company's Annual Report on Form 10-K for the period ended December 31, 2015, filed with the SEC on February 26, 2016, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for 2015, 2014 and 2013, (ii) the Consolidated Balance Sheets at December 31, 2015 and December 31, 2014, (iii) the Consolidated Statements of Cash Flows for 2015, 2014 and 2013, and (iv) Notes to Consolidated Financial Statements.**

†

This exhibit is a compensatory plan or arrangement as contemplated by Item 15(a)(3) of Form 10-K.

*

Filed herewith.

**

Pursuant to Rule 406T of Regulation S-T, the XBRL related information in Exhibit 101 to this Annual Report on Form 10-K shall not be deemed to be "filed" by the Company for purposes of Section 18 of the Exchange Act of 1934, as amended, or otherwise subject to the liability of that section, and shall not be deemed incorporated by reference into, or part of a registration statement, prospectus or other document filed under the Securities Act of 1933, as amended or the Exchange Act except as shall be expressly set forth by specific reference in such filings.

~

This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.

134

SCHEDULE II

Valuation and Qualifying Accounts

Years ended December 31, 2015, 2014 and 2013:

			Additions Charged to Other Accounts					Deductions From Reserve
	Balance At Beginning Of Period		Charged To Income		Description	Amount		Description	Amount		Balance At Close of Period
Year ended December 31, 2015:
Reserve deducted from assets: accumulated provision for uncollectible accounts.	$	1,020,637	$	2,266,976	Recovery of amounts previously written off	$	2,079,751	Accounts written off	$	4,744,648	$	622,716
Year ended December 31, 2014:
Reserve deducted from assets: accumulated provision for uncollectible accounts.	$	1,025,177	$	3,463,797	Recovery of amounts previously written off	$	2,128,325	Accounts written off	$	5,596,662	$	1,020,637
Year ended December 31, 2013:
Reserve deducted from assets: accumulated provision for uncollectible accounts.	$	1,387,673	$	2,213,988	Recovery of amounts previously written off	$	2,013,959	Accounts written off	$	4,590,443	$	1,025,177

135

SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	THE EMPIRE DISTRICT ELECTRIC COMPANY
Date: February 26, 2016	By	/s/ BRADLEY P. BEECHER Bradley P. Beecher, President and Chief Executive Officer

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ BRADLEY P. BEECHER Bradley P. Beecher, President, Chief Executive Officer, Director (Principal Executive Officer)	Date: February 26, 2016
/s/ LAURIE A. DELANO Laurie A. Delano, Vice President-Finance (Principal Financial Officer)
/s/ ROBERT W. SAGER Robert W. Sager, Controller, Assistant Secretary and Assistant Treasurer (Principal Accounting Officer)
D. RANDY LANEY* D. Randy Laney, Director
KENNETH R. ALLEN* Kenneth R. Allen, Director
PAUL R. PORTNEY* Paul R. Portney, Director
ROSS C. HARTLEY* Ross C. Hartley, Director
HERBERT J. SCHMIDT* Herbert J. Schmidt, Director
THOMAS OHLMACHER* Thomas Ohlmacher, Director
B. THOMAS MUELLER* B. Thomas Mueller, Director
C. JAMES SULLIVAN* C. James Sullivan, Director
BONNIE C. LIND* Bonnie C. Lind, Director
/s/ LAURIE A. DELANO *By (Laurie A. Delano, as attorney in fact for each of the persons indicated)

136

EX-10.(N)

EXHIBIT (10)(n)

AMENDMENT TO THE
STOCK UNIT PLAN FOR DIRECTORS OF
THE EMPIRE DISTRICT ELECTRIC COMPANY

The Stock Unit Plan for Directors of The Empire District Electric Company (the “Plan”) is amended in the following respects:

1.     Section 8 of the Plan is amended to insert the following new subsection (i):

“(i)          Effective upon and subject to the occurrence of the Merger (as defined below), each Stock Unit credited to an Account that is outstanding immediately prior to the Effective Time (as defined below) shall be cancelled and converted, as of the Effective Time, into the right to receive payment on the Payment Date of an amount in cash equal to the Merger Consideration (as defined below), together with interest on such amount at the “U.S. Prime Rate” as quoted by the Wall Street Journal in effect at the Effective Time for the period, if any, from the Effective Time until the Payment Date.  For purposes of this Section 8(i), the terms “Merger”, “Effective Time” and “Merger Consideration” shall have the meanings given to them under the Agreement and Plan of Merger, dated February 9, 2016, by and among the Company, Liberty Utilities (Central) Co. and Liberty Sub Corp.”

2.     Except as set forth above, the Plan shall remain in effect in accordance with its terms.

EX-10.(Q)

EXHIBIT (10)(q)

THE EMPIRE DISTRICT ELECTRIC COMPANY 2006 INCENTIVE PLAN
THE EMPIRE DISTRICT ELECTRIC COMPANY 2015 INCENTIVE PLAN

AMENDMENT TO PERFORMANCE-BASED RESTRICTED STOCK AWARDS

The performance-based Restricted Stock Awards granted to the undersigned                           (the “Grantee”) by The Empire District Electric Company (the “Company”) under The Empire District Electric Company 2006 Stock Incentive Plan and The Empire District Electric Company 2015 Stock Incentive Plan, as applicable, that are outstanding as of the date hereof (each, an “Award”), which may include one or more of the Awards dated February 5, 2014, February 4, 2015, and February 3, 2016, as the case may be, as set forth in the Notices of Performance-Based Restricted Stock Award as of such dates, are hereby amended, effective upon and subject to the occurrence of the Merger (as defined below) and to the extent outstanding immediately prior to the Effective Time (as defined below), to provide that, as of the Effective Time, each Award shall be cancelled and converted into the right to receive a lump-sum cash payment, payable in accordance with the Merger Agreement (as defined below) to the Grantee, equal to the product of (i) the Merger Consideration (as defined below), multiplied by (ii) the total number of shares of Common Stock of the Company that would be earned for performance at Target for the Performance Period in accordance with provisions of the applicable Notice of Award.  For purposes of this Amendment, the term “Merger Agreement” shall mean the the Agreement and Plan of Merger, dated February 9, 2016, by and among the Company, Liberty Utilities (Central) Co. and Liberty Sub Corp., and the terms “Merger”, “Effective Time” and “Merger Consideration” shall have the meanings given to them thereunder.

AGREED BY:
THE EMPIRE DISTRICT ELECTRIC COMPANY
By:
	Name:
	By:
GRANTEE
Name:

EX-10.(R)

EXHIBIT (10)(r)

February 3, 2016

«Title» «Name1» «Name2»

«Address1»

«Address2»

Dear «Title» «Name2»:

The Empire District Electric Company

2015 Stock Incentive Plan (the “Plan”)

Notice of Time-Vested Restricted Stock Award

This is to advise you that effective as of February 3, 2016 (the “Grant Date”), The Empire District Electric Company (“the Company”) has granted to you a Time-Vested Restricted Stock Award (the “Award”) under the Plan consisting of the right to receive «ColumnA» shares (the “Time-Vested Restricted Shares”) of Common Stock of the Company (“Stock”), subject to the vesting, forfeiture and other conditions and terms herein stated and the applicable terms and conditions of the Plan (copy attached).  This Award shall relate to the Restricted Period beginning on February 3, 2016 and ending on February 3, 2019 (the “Restricted Period”).

Settlement of Awards.  The Company shall deliver to you one share of Stock for each Time-Vested Restricted Share in which you vest, as determined in accordance with the provisions of this Award.  The Time-Vested Restricted Shares which vest in accordance with the provisions of this Award shall be paid solely in shares of Stock.  The date on which you vest in any Time-Vested Restricted Shares pursuant to the terms of this Award shall be the “Vesting Date” with respect to those Time-Vested Restricted Shares.

Time of Payment.  Except as otherwise provided in Section 15 of this Award, payment of Time-Vested Restricted Shares that vest in accordance with the provisions of this Award will be delivered as soon as practicable after the Vesting Date with respect to those Time-Vested Restricted Shares but not later than 60 days after the Vesting Date with respect to those Time-Vested Restricted Shares.

Vesting.  Except as otherwise provided in Section 4, 5 or 6 of this Award, you shall vest in all of your Time-Vested Restricted Shares under this Award on the last day of the Restricted Period if you remain in the employment of the Company and its Subsidiaries through the last day of the Restricted Period.

Retirement, Disability, or Death During Restricted Period.  If your employment with the Company and its Subsidiaries terminates during the Restricted Period because of your Retirement, Disability, or death, you shall vest in a prorated number of the Time-Vested Restricted Shares based on the ratio of the number of months you were employed during the Restricted Period (rounding a fraction of a month to the next higher number of whole months) to the total number of months in the Restricted Period.  Fractional shares shall be disregarded.  Any Time-Vested Restricted Shares that do not vest pursuant to this Section 4 upon your Retirement, Disability or death shall be forfeited.

Termination of Employment During Restricted Period.  If your employment with the Company and its Subsidiaries terminates during the Restricted Period for any reason other than your Retirement, Disability, or death, the Time-Vested Restricted Shares granted under this Award will be forfeited

on the date of such termination of employment; provided, however, that in such circumstances, the Committee, in its sole discretion, may determine that you will vest in a portion of the Time-Vested Restricted Shares under this Award upon termination of your employment, but not in excess of a pro rata portion of such Time-Vested Restricted Shares based on the ratio of the number of months you were employed during the Restricted Period (rounding a fraction of a month to the next higher number of whole months) to the total number of months in the Restricted Period and disregarding fractional shares; any Time-Vested Restricted Shares in which you do not so vest shall be forfeited upon termination of your employment.

Change in Control.  If a Change in Control of the Company occurs during the Restricted Period, and the date of termination of your employment does not fall before the Change in Control date, you shall vest in a prorated number of the Time-Vested Restricted Shares based on the ratio of the number of months you were employed during the Restricted Period through the date of the Change in Control (rounding a fraction of a month to the next higher number of whole months), to the total number of months in the Restricted Period.  Any Time-Vested Restricted Shares that do not vest pursuant to this Section 6 upon a Change in Control shall be forfeited.

Heirs and Successors.  This Award shall be binding upon, and inure to the benefit of, the Company and its successors and assigns, and upon any person acquiring, whether by merger, consolidation, purchase of assets or otherwise, all or substantially all of the Company’s assets and business.  If any of the benefits distributable to you under this Award have not been distributed at the time of your death, such benefits shall be distributed to your Designated Beneficiary, in accordance with the provisions of this Award and the Plan.  The “Designated Beneficiary” shall be the beneficiary or beneficiaries designated by you in a writing filed with the Committee in such form and at such time as the Committee shall require.  If you are deceased and failed to designate a beneficiary, or if the Designated Beneficiary does not survive you, any benefits distributable to you shall be distributed to the legal representative of your estate.  If you are deceased and have designated a beneficiary and the Designated Beneficiary survives you but dies before the complete distribution of benefits to the Designated Beneficiary under this Award, then any benefits distributable to the Designated Beneficiary shall be distributed to the legal representative of the estate of the Designated Beneficiary.

Administration.  The authority to manage and control the operation and administration of this Award shall be vested in the Committee identified in the Plan, and the Committee shall have all of the powers with respect to this Award that it has with respect to the Plan.  Any interpretation of the Award by the Committee and any decision made by it with respect to the Award are final and binding on all persons.

Amendment.  This Award may be amended by written agreement between you and the Company, without the consent of any other person.

Nontransferability.  This Award shall not be transferable except by will or the laws of descent and distribution or by beneficiary designation in accordance with Section 7 above.

Taxes.  The Company shall be entitled to withhold the amount of any withholding tax payable with respect to the Award and to sell such number of shares of Stock as may be necessary to produce the amount requested by the employee to be withheld, unless the recipient supplies to the Company cash in the amount requested by the Company for the purpose.  The employee may request amounts withheld in excess of the minimum statutory requirement.

Employee and Shareholder Status.  This Award does not constitute a contract of continued service and does not give you the right to be retained as an employee of the Company or any of its Subsidiaries.  This Award does not confer upon you or any other holder thereof any right as a shareholder of the Company prior to the issuance of shares of Stock pursuant to this Award.

Plan Governs.  Notwithstanding anything in this Award to the contrary, the terms of this Award shall be subject to the terms of the Plan.

Unsecured Creditor.  Your rights with respect to the Award and the shares of Stock subject thereto during the Restricted Period prior to issuance of shares of Stock to you, your beneficiary or your estate pursuant to the Award are those of an unsecured general creditor of the Company.  No shares of Stock or other specific property is or will be set apart in trust or otherwise with respect to the Award but all of your rights in the Award will be evidenced only by entries on the books of the Company unless and until shares of Stock are actually issued to you, your beneficiary or your estate pursuant to the Award.

Compliance with Code Section 409A.  Notwithstanding anything in this Award to the contrary, the following rules shall apply if, under the definition of “Retirement” set forth in Section 16 below, you may become eligible for Retirement before the first day in the calendar year that includes the last day in the Restricted Period: (i) if you are a “specified employee” (within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations thereunder and as determined by the Company in accordance with said Section 409A) at the time of your separation from service (as defined below), the payment of any vested Time-Vested Restricted Shares pursuant to Section 2 of this Award shall be made no earlier than the date which is 6 months after the date of your separation from service (or, if earlier than the end of the 6-month period, the date of your death), and (ii) you shall be deemed to have terminated from employment for purposes of this Award if and only if you have experienced a “separation from service” within the meaning of said Section 409A and the regulations thereunder.  To the extent any payment under this Award is subject to the 6-month delay, such payment shall be paid immediately after the end of such 6-month period (or the date of your death, if earlier).  The provisions of this Award shall be interpreted and operated consistently with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations thereunder (to the extent applicable).

Definitions.  For purposes of this Award, the terms used in this Award shall have the following meanings:

Change in Control.  A “Change in Control” of the Company shall mean “a change in the ownership or effective control” of the Company, or “in the ownership of a substantial portion of the assets” of the Company, within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended, and Treasury regulations and Internal Revenue Service guidance thereunder.

Disability.  Except as otherwise provided by the Committee, “Disability” means the determination by the Committee, in its sole discretion, that a permanent and total disability exists in accordance with uniform and non-discriminatory standards adopted by the Committee from time to time.

Retirement.  “Retirement” means your retirement on an “Early Retirement Date” or on or after your “Normal Retirement Date,” as those terms are defined in The Empire District Electric Company Employees’ Retirement Plan.

Plan Definitions.  Except where the context clearly implies or indicates the contrary, a word, term, or phrase used in the Plan is similarly used in this Award.

Please acknowledge receipt of this Notice of Award by signing and returning to the Secretary of the Company the enclosed copy thereof, together with a completed and signed beneficiary designation form.

Very truly yours,

Chairman of the Compensation Committee

Receipt of the foregoing Notice of

Time-Vested Restricted Stock Award is

hereby acknowledged.  My signed beneficiary

designation form is attached.

Name: «Name1» «Name2»

Date

EX-12

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EXHIBIT (12)

Computation of Ratios of Earnings to Fixed Charges
Year ended December 31,

	2015		2014		2013		2012		2011
Income before provision for income taxes and fixed charges (Note A)	$	145,179,076	$	158,919,435	$	152,117,322	$	137,251,581	$	136,980,092
Fixed Charges:
Interest on long-term debt	$	43,801,555	$	40,636,896	$	40,354,153	$	40,192,347	$	42,580,987
Interest on short-term debt		265,523		113,333		59,504		187,132		86,406
Other interest		1,035,399		989,627		1,064,869		1,087,719		(1,147,472	)
Rental expense representative of an interest factor (Note B)		9,667,300		10,855,975		9,700,747		5,944,675		6,190,709
TOTAL FIXED CHARGES	$	54,769,777	$	52,595,831	$	51,179,273	$	47,411,873	$	47,710,630
Ratio of earnings to fixed charges		2.65		3.02		2.97		2.89		2.87

NOTE A:    For the purpose of determining earnings in the calculation of the ratio, net income has been increased by the provision for income taxes, non-operating income taxes and by the sum of fixed charges as shown above.

NOTE B:    One-third of rental expense (which approximates the interest factor).

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Computation of Ratios of Earnings to Fixed Charges Year ended December 31,

EX-21

EXHIBIT (21)

Subsidiaries of Empire

Subsidiary	State of Organization
Empire District Industries, Inc.	Delaware
The Empire District Gas Company	Kansas

Immaterial subsidiaries are not listed.

EX-23

EXHIBIT (23)

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 33-34807, 333-130075, 333-130076, 333-197981 and 333-197982) and in the Registration Statements on Form S-3 (Nos. 333-192809 and 333-197983) of The Empire District Electric Company of our report dated February 26, 2016 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

February 26, 2016

EX-24

EXHIBIT (24)

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of THE EMPIRE DISTRICT ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Kansas, does hereby constitute and appoint B. P. BEECHER and L. A. DELANO, and each of them, the true and lawful attorney-in-fact of the undersigned, in the name, place and stead of the undersigned, to sign the name of the undersigned to the Company’s Annual Report Form 10-K for the fiscal year ended December 31, 2015, File Number 1-3368, to be filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, and to any amendment thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to give and hereby giving and granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and the undersigned hereby ratifies and confirms all that said attorneys-in-fact, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney this 3rd day of February 2016.

/s/ D. RANDY LANEY

D. RANDY LANEY

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of THE EMPIRE DISTRICT ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Kansas, does hereby constitute and appoint B. P. BEECHER and L. A. DELANO, and each of them, the true and lawful attorney-in-fact of the undersigned, in the name, place and stead of the undersigned, to sign the name of the undersigned to the Company’s Annual Report Form 10-K for the fiscal year ended December 31, 2015, File Number 1-3368, to be filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, and to any amendment thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to give and hereby giving and granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and the undersigned hereby ratifies and confirms all that said attorneys-in-fact, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney this 3rd day of February 2016.

/s/ HERBERT J. SCHMIDT

HERBERT J. SCHMIDT

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of THE EMPIRE DISTRICT ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Kansas, does hereby constitute and appoint B. P. BEECHER and L. A. DELANO, and each of them, the true and lawful attorney-in-fact of the undersigned, in the name, place and stead of the undersigned, to sign the name of the undersigned to the Company’s Annual Report Form 10-K for the fiscal year ended December 31, 2015, File Number 1-3368, to be filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, and to any amendment thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to give and hereby giving and granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and the undersigned hereby ratifies and confirms all that said attorneys-in-fact, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney this 3rd day of February 2016.

/s/ BONNIE C. LIND

BONNIE C. LIND

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of THE EMPIRE DISTRICT ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Kansas, does hereby constitute and appoint B. P. BEECHER and L. A. DELANO, and each of them, the true and lawful attorney-in-fact of the undersigned, in the name, place and stead of the undersigned, to sign the name of the undersigned to the Company’s Annual Report Form 10-K for the fiscal year ended December 31, 2015, File Number 1-3368, to be filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, and to any amendment thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to give and hereby giving and granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and the undersigned hereby ratifies and confirms all that said attorneys-in-fact, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney this 3rd day of February 2016.

/s/ THOMAS OHLMACHER

THOMAS OHLMACHER

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of THE EMPIRE DISTRICT ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Kansas, does hereby constitute and appoint B. P. BEECHER and L. A. DELANO, and each of them, the true and lawful attorney-in-fact of the undersigned, in the name, place and stead of the undersigned, to sign the name of the undersigned to the Company’s Annual Report Form 10-K for the fiscal year ended December 31, 2015, File Number 1-3368, to be filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, and to any amendment thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to give and hereby giving and granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and the undersigned hereby ratifies and confirms all that said attorneys-in-fact, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney this 3rd day of February 2016.

/s/ ROSS C. HARTLEY

ROSS C. HARTLEY

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of THE EMPIRE DISTRICT ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Kansas, does hereby constitute and appoint B. P. BEECHER and L. A. DELANO, and each of them, the true and lawful attorney-in-fact of the undersigned, in the name, place and stead of the undersigned, to sign the name of the undersigned to the Company’s Annual Report Form 10-K for the fiscal year ended December 31, 2015, File Number 1-3368, to be filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, and to any amendment thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to give and hereby giving and granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and the undersigned hereby ratifies and confirms all that said attorneys-in-fact, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney this 3rd day of February 2016.

/s/ B. THOMAS MUELLER

B. THOMAS MUELLER

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of THE EMPIRE DISTRICT ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Kansas, does hereby constitute and appoint B. P. BEECHER and L. A. DELANO, and each of them, the true and lawful attorney-in-fact of the undersigned, in the name, place and stead of the undersigned, to sign the name of the undersigned to the Company’s Annual Report Form 10-K for the fiscal year ended December 31, 2015, File Number 1-3368, to be filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, and to any amendment thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to give and hereby giving and granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and the undersigned hereby ratifies and confirms all that said attorneys-in-fact, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney this 3rd day of February 2016.

/s/ C. JAMES SULLIVAN

C. JAMES SULLIVAN

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of THE EMPIRE DISTRICT ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Kansas, does hereby constitute and appoint B. P. BEECHER and L. A. DELANO, and each of them, the true and lawful attorney-in-fact of the undersigned, in the name, place and stead of the undersigned, to sign the name of the undersigned to the Company’s Annual Report Form 10-K for the fiscal year ended December 31, 2015, File Number 1-3368, to be filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, and to any amendment thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to give and hereby giving and granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and the undersigned hereby ratifies and confirms all that said attorneys-in-fact, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney this 3rd day of February 2016.

/s/ KENNETH R. ALLEN

KENNETH R. ALLEN

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of THE EMPIRE DISTRICT ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Kansas, does hereby constitute and appoint B. P. BEECHER and L. A. DELANO, and each of them, the true and lawful attorney-in-fact of the undersigned, in the name, place and stead of the undersigned, to sign the name of the undersigned to the Company’s Annual Report Form 10-K for the fiscal year ended December 31, 2015, File Number 1-3368, to be filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, and to any amendment thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to give and hereby giving and granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and the undersigned hereby ratifies and confirms all that said attorneys-in-fact, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney this 3rd day of February 2016.

/s/ PAUL R. PORTNEY

PAUL R. PORTNEY

EX-31.(A)

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EXHIBIT (31)(a)

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Bradley P. Beecher, certify that:

        1.     I have reviewed this annual report on Form 10-K of The Empire District Electric Company;

        2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

        3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

        4.     The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a.

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



b.

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



c.

evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



d.

disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

        5.     The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and



b.

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2016

By: /s/ Bradley P. Beecher

Name:	Bradley P. Beecher
Title:	President and Chief Executive Officer

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EXHIBIT (31)(a)

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

EX-31.(B)

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EXHIBIT (31)(b)

CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Laurie A. Delano, certify that:

        1.     I have reviewed this annual report on Form 10-K of The Empire District Electric Company;

        2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

        3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

        4.     The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a.

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



b.

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



c.

evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



d.

disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

        5.     The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and



b.

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2016

By: /s/ Laurie A. Delano

Name:	Laurie A. Delano
Title:	Vice President — Finance and Chief Financial Officer

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EXHIBIT (31)(b)

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

EX-32.(A)

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EXHIBIT (32)(a)

Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350,
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*

        In connection with the Annual Report of The Empire District Electric Company (the "Company") on Form 10-K for the period ending December 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Bradley P. Beecher, as Chief Executive Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

        1.     The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

        2.     The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

By: /s/ Bradley P. Beecher

Name:	Bradley P. Beecher
Title:	President and Chief Executive Officer

Date: February 26, 2016

        A signed original of this written statement required by Section 906 or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to The Empire District Electric Company and will be retained by The Empire District Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

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EXHIBIT (32)(a)

Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

EX-32.(B)

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EXHIBIT (32)(b)

Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350,
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*

        In connection with the Annual Report of The Empire District Electric Company (the "Company") on Form 10-K for the period ending December 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Laurie A. Delano, as Chief Financial Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

        1.     The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

        2.     The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

By: /s/ Laurie A. Delano

Name:	Laurie A. Delano
Title:	Vice President — Finance and Chief Financial Officer

Date: February 26, 2016

        A signed original of this written statement required by Section 906 or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to The Empire District Electric Company and will be retained by The Empire District Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

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EXHIBIT (32)(b)

Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 01, 2016	Jun. 30, 2015
Document and Entity Information
Entity Registrant Name	EMPIRE DISTRICT ELECTRIC CO
Entity Central Index Key	0000032689
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 952,425,061
Entity Common Stock, Shares Outstanding		43,860,337
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Plant and property, at original cost:
Electric	$ 2,473,927	$ 2,420,824
Gas	83,402	79,364
Other	44,263	41,394
Construction work in progress	183,689	112,097
Total plant and property, Gross	2,785,281	2,653,679
Accumulated depreciation and amortization	764,895	743,407
Total plant and property, Net	2,020,386	1,910,272
Current assets:
Cash and cash equivalents	1,753	2,105
Restricted cash	4,726	4,726
Accounts receivable - trade, net of allowance $623 and $1,021, respectively	40,162	45,444
Accrued unbilled revenues	20,653	25,945
Accounts receivable - other	28,320	41,256
Fuel, materials and supplies	60,950	57,799
Prepaid expenses and other	8,835	8,679
Unrealized gain in fair value of derivative contracts	1,295	3,901
Regulatory assets	7,052	10,752
Total current assets	173,746	200,607
Noncurrent assets and deferred charges:
Regulatory assets	209,708	209,717
Goodwill	39,492	39,492
Unamortized debt issuance costs	8,658	8,821
Unrealized gain in fair value of derivative contracts	16
Other	3,297	2,147
Total noncurrent assets and deferred charges	261,171	260,177
Total Assets	2,455,303	2,371,056
Capitalization and liabilities
Common stock, $1 par value, 43,820,726 and 43,479,186 shares issued and outstanding, respectively	43,821	43,479
Capital in excess of par value	657,466	649,543
Retained earnings	101,443	90,276
Total common stockholders' equity	802,730	783,298
Long-term debt (net of current portion):
Obligations under capital lease	3,580	3,875
First mortgage bonds and secured debt	732,653	697,615
Unsecured debt	101,714	101,699
Total long-term debt	837,947	803,189
Total long-term debt and common stockholders' equity	1,640,677	1,586,487
Current liabilities:
Accounts payable and accrued liabilities	66,946	83,420
Current maturities of long-term debt	25,310	292
Short-term debt	25,000	44,000
Regulatory liabilities	8,615	7,898
Customer deposits	14,623	13,747
Interest accrued	7,348	6,565
Unrealized loss in fair value of derivative contracts	4,472	6,469
Taxes accrued	2,832	3,380
Other current liabilities	323	206
Total current liabilities	$ 155,469	$ 165,977
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	$ 132,457	$ 128,471
Deferred income taxes	396,542	358,252
Unamortized investment tax credits	18,487	18,517
Pension and other postretirement benefit obligations	82,144	93,863
Unrealized loss in fair value of derivative contracts	3,696	3,243
Other	25,831	16,246
Total noncurrent liabilities	659,157	618,592
Total Capitalization and Liabilities	$ 2,455,303	$ 2,371,056

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Consolidated Balance Sheets
Accounts receivable - trade, allowance (in dollars)	$ 623	$ 1,021
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	43,820,726	43,479,186
Common stock, shares outstanding	43,820,726	43,479,186

XML

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues:
Electric	$ 555,085	$ 592,491	$ 536,413
Gas	41,702	51,842	50,041
Other	8,786	7,997	7,876
Total operating revenues	605,573	652,330	594,330
Operating revenue deductions:
Fuel and purchased power	169,860	215,086	175,406
Cost of natural gas sold and transported	19,502	27,025	25,795
Regulated operating expenses	113,551	110,691	105,333
Other operating expenses	3,309	2,987	3,142
Maintenance and repairs	48,522	46,775	40,873
Loss on plant disallowance		86	2,409
Depreciation and amortization	80,550	73,185	69,306
Provision for income taxes	34,800	39,398	37,465
Other taxes	39,178	37,098	34,938
Total operating revenue deductions	509,272	552,331	494,667
Operating income	96,301	99,999	99,663
Other income and (deductions):
Allowance for equity funds used during construction	4,850	6,420	3,853
Interest income	145	51	566
Benefit for other income taxes	988	178	(27)
Other - non-operating expense, net	(3,429)	(1,302)	(1,218)
Total other income	2,554	5,347	3,174
Interest charges:
Long-term debt	43,802	40,637	40,354
Short-term debt	266	113	60
Allowance for borrowed funds used during construction	(2,845)	(3,497)	(2,087)
Other	1,035	990	1,065
Total interest charges	42,258	38,243	39,392
Net income	$ 56,597	$ 67,103	$ 63,445
Weighted average number of common shares outstanding - basic (in shares)	43,671	43,291	42,781
Weighted average number of common shares outstanding - diluted (in shares)	43,718	43,314	42,803
Total earnings per weighted average share of common stock - basic (in dollars per share)	$ 1.30	$ 1.55	$ 1.48
Total earnings per weighted average share of common stock - diluted (in dollars per share	1.29	1.55	1.48
Dividends declared per share of common stock (in dollars per share)	$ 1.04	$ 1.025	$ 1.005

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Consolidated Statements of Common Stockholders' Equity - USD ($) $ in Thousands	Common Stock	Capital in excess of Par	Retained earnings	Total
Balance at Dec. 31, 2012	$ 42,484	$ 628,199	$ 47,115	$ 717,798
Increase (Decrease) in Stockholders' Equity
Net income			63,445	63,445
Stock/stock units issued through:
Stock purchase and reinvestment plans	560	11,326		11,886
Dividends declared			(43,006)	(43,006)
Balance at Dec. 31, 2013	43,044	639,525	67,554	750,123
Increase (Decrease) in Stockholders' Equity
Net income			67,103	67,103
Stock/stock units issued through:
Stock purchase and reinvestment plans	435	10,018		10,453
Dividends declared			(44,381)	(44,381)
Balance at Dec. 31, 2014	43,479	649,543	90,276	783,298
Increase (Decrease) in Stockholders' Equity
Net income			56,597	56,597
Stock/stock units issued through:
Stock purchase and reinvestment plans	342	7,923		8,265
Dividends declared			(45,430)	(45,430)
Balance at Dec. 31, 2015	$ 43,821	$ 657,466	$ 101,443	$ 802,730

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income	$ 56,597	$ 67,103	$ 63,445
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	88,801	82,754	71,734
Pension and other postretirement benefit costs, net of contributions	(9,184)	1,973	(1,888)
Deferred income taxes and unamortized investment tax credit, net	36,617	41,693	28,272
Allowance for equity funds used during construction	(4,850)	(6,420)	(3,853)
Stock compensation expense	4,082	4,057	2,984
Other	(625)
Loss on plant disallowance		86	2,409
Reverse gain on sale of assets		44	1,236
Non-cash (gain)/loss on derivatives	6,994	1,245	14
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	16,514	(24,174)	(14,312)
Fuel, materials and supplies	(3,151)	(8,121)	10,891
Prepaid expenses, other current assets and deferred charges	(4,863)	(6,051)	689
Accounts payable and accrued liabilities	(8,630)	1,141	(880)
Asset retirement obligations	(73)	(1,326)	(734)
Interest, taxes accrued and customer deposits	1,111	1,411	1,386
Other liabilities and other deferred credits	5,492	(4,192)	(3,942)
Net cash provided by operating activities	184,832	151,223	157,451
Investing activities:
Capital expenditures - regulated	(183,206)	(211,429)	(152,524)
Capital expenditures and other investments - non-regulated	(2,243)	(1,998)	(2,259)
Restricted cash		(1,854)	1,485
Net cash used in investing activities	(185,449)	(215,281)	(153,298)
Financing activities:
Proceeds from first mortgage bonds, net	60,000	60,000	150,000
Long-term debt issuance costs	(818)	(651)	(1,879)
Proceeds from issuance of common stock, net of issuance costs	5,513	7,994	9,546
Redemption of senior notes			(98,000)
Net short-term debt borrowings/(repayments)	(19,000)	40,000	(20,000)
Dividends	(45,430)	(44,381)	(43,006)
Other		(274)	(714)
Net cash provided by financing activities	265	62,688	(4,053)
Net increase (decrease) in cash and cash equivalents	(352)	(1,370)	100
Cash and cash equivalents at beginning of period	2,105	3,475	3,375
Cash and cash equivalents at end of period	1,753	2,105	3,475
Supplemental cash flow information:
Interest paid	42,858	40,127	39,033
Income taxes (refunded) paid, net of refund	(17,256)	23,103	10,584
Supplementary non-cash investing activities:
Change in accrued additions to property, plant and equipment not reported above	(8,924)	$ 9,427	$ 5,420
Capital lease obligations for purchase of new equipment	$ 17

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2015

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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. See Note 12. 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.

        The utility portions of our business are subject to regulation by the Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). Our accounting policies are in accordance with the ratemaking practices of the regulatory authorities and conform to generally accepted accounting principles as applied to regulated public utilities.

        Our electric operations serve approximately 170,000 customers as of December 31, 2015, and the 2015 electric operating revenues were derived as follows:

Customer Class	% of revenue
Residential		41.7	%
Commercial		31.1
Industrial		15.9
Wholesale on-system		3.3
Wholesale off-system		2.7
Miscellaneous sources, primarily public authorities		2.8
Other electric revenues		2.5

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

Jurisdiction	% of revenue
Missouri		89.0	%
Kansas		4.8
Oklahoma		2.8
Arkansas		3.4

        Our gas operations serve approximately 43,200 customers as of December 31, 2015, and the 2015 gas operating revenues were derived as follows:

Customer Class	% of revenue
Residential		63.0	%
Commercial		25.6
Industrial		0.8
Transportation		8.9
Miscellaneous		1.7

Basis of Presentation

        The consolidated financial statements include the accounts of EDE, EDG, and our other subsidiaries. The consolidated entity is referred to throughout as "we" or the "Company". All intercompany balances and transactions have been eliminated in consolidation. See Note 12 for additional information regarding our three segments. Certain immaterial reclassifications have been made to prior year information to conform to the current year presentation.

Use of Estimates

        The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include unbilled utility revenues, collectability of accounts receivable, depreciable lives, asset impairment and goodwill impairment evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation, and tax provisions. Actual amounts could differ from those estimates.

Accounting for the Effects of Regulation

        In accordance with the Accounting Standard Codification (ASC) guidance for regulated operations, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the APSC and the FERC).

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

        Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory assets and liabilities are ratably amortized through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues. We generally include amortization of regulatory assets and liabilities in the depreciation and amortization line of our statement of cash flows. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC guidance for regulated operations with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of this guidance based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations. (See Note 3 for further discussion of regulatory assets and liabilities)

Revenue Recognition

        For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer classes.

Municipal Franchise Taxes

        Municipal franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other taxes in the Consolidated Statements of Income. Municipal franchise taxes of $11.4 million, $11.8 million and $11.2 million were recorded for each of the years ended December 31, 2015, 2014 and 2013, respectively.

Accounts Receivable

        Accounts receivable are recorded at the tariffed rates for customer usage, including applicable taxes and fees and do not bear interest. We review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered.

Property, Plant & Equipment

        The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material, an allocation of general and administrative costs, and an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of and the costs of removal are charged to accumulated depreciation, unless the removed property constitutes an operating unit or system. In this case a gain or loss is recognized upon the disposal of the asset. Maintenance expenditures and the removal of minor property items are charged to income as incurred. A liability is created for any additions to electric or gas utility property that are paid for by advances from developers. For a period of five years we refund to the developer a pro rata amount of the original cost of the extension for each new customer added to the extension. Nonrefundable payments at the end of the five year period are applied as a reduction to the cost of the plant in service. The liability as of December 31, 2015 and 2014 was $2.1 million and $1.9 million, respectively.

Depreciation

        Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by regulatory authorities. These rates are applied to the various classes of utility assets on a composite basis. Provisions for depreciation for our other segment are computed at straight-line rates over the estimated useful life of the properties (See Note 2 for additional details regarding depreciation rates).

        As of December 31, 2015 and 2014, we had recorded accrued cost of removal of $85.4 million and $82.8 million, respectively, for our electric operating segment. This represents an estimated cost of dismantling and removing plant from service upon retirement, accrued as part of our depreciation rates. We accrue cost of removal in depreciation rates for mass property (including transmission, distribution and general plant assets). These accruals are not considered an asset retirement obligation under the guidance provided on asset retirement obligations within the ASC. We reclassify the accrued cost of dismantling and removing plant from service upon retirement from accumulated depreciation to a regulatory liability. We have a similar cost of removal regulatory liability for our gas operating segment. This amount at December 31, 2015 and 2014 was $8.8 million and $7.7 million, respectively. These amounts are net of our actual cost of removal expenditures.

Asset Retirement Obligation

        We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.

        We have identified asset retirement obligations associated with the future removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We also have a solid waste land fill at the Plum Point Energy Station, and asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. As a result of the fuel use transition from coal to natural gas at the Riverton Power Plant, the closure of the Riverton ash landfill was completed, and the related asset retirement obligation was settled during 2014 (Note 11). During 2015 the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs). As a result of these new rules, an asset retirement obligation of $5.4 million has been recorded for the final closure of the existing ash impoundment at our Asbury Power Plant. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station.

        In addition, we have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB) contaminants associated with our transformers and substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures for the removal of similar past liabilities. The potential costs of these future expenditures are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. This liability will be accreted over the period up to the estimated settlement date.

        All of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 4.5% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. During 2014 the liability for asbestos at the Riverton Power Plant was re-evaluated. Changes in the cost estimates and timing resulted in cash flow revisions for these liabilities.

        The balances at the end of 2015 and 2014 are shown below.

(000's)	Liability Balance 12/31/14		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/15
Asset Retirement Obligation	$	4,847	$	9,812	$	(73	)	$	486	$	—	$	15,072

(000's)	Liability Balance 12/31/13		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/14
Asset Retirement Obligation	$	4,190	$	—	$	(1,175	)	$	172	$	1,660	$	4,847

        Upon adoption of the standards on the retirement of long lived assets and conditional asset retirement obligations, we recorded a liability and regulatory asset because we expect to recover these costs of removal in electric and gas rates either through depreciation accruals or direct expenses. We also defer the liability accretion and depreciation expense as a regulatory asset. At December 31, 2015 and 2014, our regulatory assets relating to asset retirement obligations totaled $7.7 million and $5.1 million, respectively.

        Also as noted previously under property, plant and equipment, we reclassify the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset retirement obligation under this guidance, from accumulated depreciation to a regulatory liability. This balance sheet reclassification has no impact on results of operations.

Allowance for Funds Used During Construction

        As provided in the FERC regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction (AFUDC) when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds applicable to construction programs are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.

        AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation.

        In accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 5.5% for 2015, 6.6% for 2014, and 7.3% for 2013, compounded semiannually.

Asset Impairments (excluding goodwill)

        We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on undiscounted forecasted cash flows to assess the recoverability of the assets and, if necessary, the fair value is determined to measure the impairment amount. None of our assets were impaired as of December 31, 2015 and 2014.

Goodwill

        As of December 31, 2015, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and income approaches is used to estimate the fair value of goodwill.

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

        We also utilize a valuation technique under the income approach which estimates the discounted future cash flows of operations. Our procedures include developing a baseline test and performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering those assumptions which are subjective in nature and inherent to a discounted cash flows calculation. Other qualitative factors and comparisons to industry peers are also used to further support the assumptions and ultimately the overall evaluation. A key qualitative assumption considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for the gas reporting unit. Some of the key quantitative assumptions included in our tests involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. If negative changes occurred to one or more key assumptions, an impairment charge could result. With the exception of the capital spending rate, the key assumptions noted are significantly determined by market factors and significant changes in market factors that impact the gas reporting unit would somewhat be mitigated by our current and future regulatory rate design. Other risks and uncertainties affecting these assumptions include: changes in business, industry, laws, technology and economic conditions. Actual results for the gas reporting unit indicate a slight decline in gas customer count and demand. A continued decline in customer count or demand coupled with an increase in the discount rate would have adverse impacts on the valuation and could result in an impairment charge in the future. Our forecasts anticipate relatively flat customer counts over the next several years.

        We weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of October 2015 indicated the estimated fair market value of the gas reporting unit to be $18 – $22 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future.

Fuel and Purchased Power

Electric Segment

        Fuel and purchased power costs are recorded at the time the fuel is used, or the power purchased. SPP Integrated Marketplace purchased power is also included in fuel and purchased power costs. The net effects of our SPP IM activity, including SPP IM net revenue and net purchased power costs, flow through our fuel recovery mechanisms in each state.

        In our Missouri jurisdiction, the MPSC establishes a base cost for the recovery of fuel and purchased power expenses used to supply energy for our fuel adjustment clause (FAC). Beginning with our 2015 rate order, certain transmission costs are also included in the base cost. The FAC permits the distribution to customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, nearly the entire off-system sales margin flows back to the customer. Rates related to the fuel adjustment clause are modified twice a year subject to the review and approval by the MPSC. In accordance with the ASC guidance for regulated operations, 95% of the difference between the actual costs of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered from or refunded to our customers when the fuel adjustment clause is modified.

        In our Kansas jurisdiction, the costs of fuel are recovered from customers through a fuel adjustment clause, based upon estimated fuel costs and purchased power. The adjustments are subject to audit and final determination by regulators. The difference between the costs of fuel used and the cost of fuel recovered from our Kansas customers is recorded as a regulatory asset or a regulatory liability if the actual costs are higher or lower than the costs billed to customers, in accordance with the ASC guidance for regulated operations.

        Similar fuel recovery mechanisms are in place for our Oklahoma, Arkansas and FERC jurisdictions.

        At December 31, 2015 and 2014, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net over-recovered position by $5.9 million and a net under-recovered position of $3.1 million, respectively, which are reflected in our regulatory assets and liabilities.

        We receive the renewable attributes associated with the power purchased through our purchased power agreements with Elk River Windfarm LLC and Cloud County Windfarm, LLC. These renewable attributes are converted into renewable energy credits (REC), which are considered inventory, and recorded at zero cost (See Note 11). Revenue from the sale of RECs reduces fuel and purchased power expense.

        We have a Stipulation and Agreement with the MPSC granting us authority to manage our emissions allowance inventory in accordance with our Plan for Purchasing and Selling Emissions Allowances (PPSEMA). The PPSEMA allows us to purchase allowances needed for compliance, exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell allowances outright for monetary value. For compliance year 2015 we did not exchange or sell any allowances, and for compliance year 2014 we purchased 69 NOx annual allowances for compliance. We classify our allowances as inventory and they are recorded at cost, with allocated allowances being recorded at zero cost. The allowances are removed from inventory on a FIFO basis, and used allowances are considered to be a part of fuel expense (See Note 11). We had the following emissions allowances in inventory at December 31, 2015 and 2014:

Emission Allowances in Inventory	2015		2014
Acid Rain SO2		11,443		872
CSAPR SO2		5,861		—
CSAPR NOx (annual)		500		—
CSAPR NOx (seasonal)		241		—

Gas Segment

        Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery allowed in rates. A Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and related carrying costs associated with the Company's use of natural gas financial instruments to hedge the purchase price of natural gas. 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.

        We calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC. Elements considered part of the PGA factor include cost of gas supply, storage costs, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.

        Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and carrying costs associated with the use of financial instruments) are reflected as a regulatory asset or liability. The balance is amortized as amounts are reflected in customer billings.

Derivatives

        We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel in our electric business or sold in our natural gas business, on the spot market and to manage certain interest rate exposure. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we purchase from the SPP Integrated Marketplace (see Note 14).

Electric Segment

        Pursuant to the ASC guidance on accounting for derivative instruments and hedging activities, derivatives are required to be recognized on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability ("cash-flow" hedge); or (2) an instrument that is held for non-hedging purposes (a "non-hedging" instrument). We record the mark-to-market gains or losses on derivatives used to hedge our fuel and congestion costs as regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

        We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts, if they meet the definition of a derivative, are not subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions. If these transactions don't qualify for NPNS treatment, they would be marked to market for each reporting period through regulatory assets or liabilities.

Gas Segment

        Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because we have a commission approved natural gas cost recovery mechanism (PGA), we record the mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/liability account. The regulatory asset/liability account tracks the difference between revenues billed to customers for natural gas costs and actual natural gas expense which is trued up at the end of August each year and included in the Actual Cost Adjustment (ACA) factor to be billed to customers during the next year. This is consistent with the ASC guidance on regulated operations, in that we will be recovering our costs after the annual true up period (subject to a prudency review by the MPSC).

        Cash flows from hedges for both electric and gas segments are classified within cash flows from operations.

Pension and Other Postretirement Benefits

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

Pensions

        We have rate orders with Missouri, Kansas and Oklahoma that allow us to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate orders, we prospectively calculate the value of plan assets using a market-related value method as allowed by the ASC guidance on pension benefits. As a result, we are allowed to record the Missouri, Kansas and Oklahoma portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively. The MPSC has allowed us to adopt this pension cost recovery methodology for EDG as well.

Other Postretirement Benefits (OPEB)

        We have regulatory treatment for our OPEB costs similar to the treatment described above for pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into actuarial expense over ten years and the recognition of regulatory assets and liabilities as described above.

        Additional guidance in the ASC on employers' accounting for defined benefit pension and other postretirement plans requires an employer to recognize the over funded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The guidance also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. Pension and other postretirement employee benefits tracking mechanisms are utilized to allow for future rate recovery of these obligations. We record these as regulatory assets on the balance sheet rather than as reductions of equity through comprehensive income (See Note 7).

Unamortized Debt Discount, Premium and Expense

        Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices.

Liability Insurance

        We are primarily self-insured for workers' compensation claims, general liabilities, benefits paid under employee healthcare programs and long-term disability benefits. Accruals are primarily based on the estimated undiscounted cost of claims. We self-insure up to certain limits that vary by segment and type of risk. Periodically, we evaluate the level of insurance coverage over the self-insured limits and adjust insurance levels based on risk tolerance and premium expense. We carry excess liability insurance for workers' compensation and public liability claims for our electric segment. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. Our gas segment is covered by excess liability insurance for public liability claims, and workers' compensation claims are covered by a guaranteed cost policy (See Note 11).

Other Noncurrent Liabilities

        Other noncurrent liabilities are comprised of accruals and other accounting estimates not sufficiently large enough to merit individual disclosure. At December 31, 2015, the balance of other noncurrent liabilities is primarily comprised of accruals for self-insurance, customer advances for construction and asset retirement obligations.

Cash & Cash Equivalents

        Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities and were $23.2 million and $28.3 million at December 31, 2015 and 2014, respectively.

Restricted Cash

        As part of our Plum Point ownership agreement, we are required to have funds available in an escrow account which guarantees payment of certain operating costs. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts restricted, which were $1.8 million at December 31, 2015 and 2014, may increase or decrease based on an annual review.

        We are required to post cash collateral with Southwest Power Pool (SPP) to participate in Transmission Congestion Rights (TCR) auctions. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $2.5 million at December 31, 2015 and 2014.

        Due to our Plum Point energy station interconnection with Midcontinent Independent System Operator (MISO), we participate in Financial Transmission Rights (FTR) auctions which require us to post cash collateral. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $0.5 million at December 31, 2015 and 2014.

Fuel, Materials and Supplies

        Fuel, materials and supplies consist primarily of coal, natural gas in storage and materials and supplies, which are reported at average cost. These balances are as follows (in thousands):

	2015		2014
Electric fuel inventory	$	30,185	$	26,454
Natural gas inventory		3,868		5,040
Materials and supplies		26,897		26,305
TOTAL	$	60,950	$	57,799

Income Taxes

        Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes; measured using statutory tax rates (See Note 9).

        Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. The longest remaining amortization period for investment tax credits is approximately 55 years.

Accounting for Uncertainty in Income Taxes

        In 2006, the FASB issued guidance which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with the ASC guidance on accounting for income taxes. We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2010. At December 31, 2015 and 2014, our balance sheet did not include any unrecognized tax benefits. We do not expect any material changes to unrecognized tax benefits within the next twelve months. We recognize interest and penalties, if any, related to unrecognized tax benefits in other expenses.

Computations of Earnings Per Share

        The ASC guidance on earnings per share requires dual presentation of basic and diluted earnings per share. Basic earnings per share does not include potentially dilutive securities and is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share assumes the issuance of common shares pursuant to the Company's stock-based compensation plans at the beginning of each respective period, or at the date of grant or award if later. Shares attributable to stock options are excluded from the calculation of diluted earnings per share if the effect would be antidilutive.

	2015		2014		2013
Weighted Average Number Of Shares
Basic		43,670,908		43,291,031		42,781,382
Dilutive Securities:
Performance-based restricted stock awards		19,890		8,809		12,142
Employee stock purchase plan		1,249		3,422		1,729
Stock options		—		—		61
Time-based restricted stock awards		25,523		10,666		7,907
Total dilutive securities		46,662		22,897		21,839
Diluted weighted average number of shares		43,717,570		43,313,928		42,803,221
Antidilutive Shares		20,289		25,259		107,100

        Potentially dilutive shares are not expected to have a material impact unless significant appreciation of the Company's stock price occurs.

Stock-Based Compensation

        We have several stock-based compensation plans, which are described in more detail in Note 8. In accordance with the ASC guidance on stock-based compensation, we recognize compensation expense over the requisite service period of all stock-based compensation awards based upon the fair-value of the award as of the date of issuance.

Recently Issued and Proposed Accounting Standards

Revenue from contracts with customers:    In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In July 2015, the FASB approved a one year delay in the standard's effective date. The new standard is now effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard.

Extraordinary and unusual items:    In January 2015, the FASB issued revised guidance that eliminates from GAAP the concept of extraordinary items. Under the revised guidance, an entity will no longer be required to separately classify, present and disclose events or transactions that are determined to be both unusual in nature and infrequent in occurrence. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

Presentation of debt issuance costs:    In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. As of December 31, 2015, we expect that the implementation of this standard would reduce both assets and liabilities by approximately $8.7 million. The application of this standard is not expected to have a material impact on our results of operations or liquidity.

Balance sheet classification of deferred taxes:    In November 2015, the FASB issued revised guidance addressing the classification of deferred taxes. Under the revised guidance all deferred tax assets and liabilities will be classified as noncurrent in a classified statement of financial position. The revised guidance is effective for interim and annual periods beginning after December 15, 2016, however early adoption is permitted. As of December 31, 2015, we have retrospectively adopted this standard. The application of this guidance resulted in $19.2 million in current deferred tax assets being reclassified from prepaid expenses and other to deferred income taxes (noncurrent) on the December 31, 2014 Consolidated Balance Sheet.

Recognition and measurement of financial assets and financial liabilities:    In January 2016, the FASB issued revised guidance addressing the recognition, measurement, presentation and disclosure of financial instruments. Under the revised guidance all equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are to be measured at fair value with the changes in fair value recognized in net income. The amended guidance also addresses the impairment assessment of some equity investments, as well as disclosure requirements. The revised guidance is effective for interim and annual periods beginning after December 15, 2017. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

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PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2015

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT

2.     PROPERTY, PLANT AND EQUIPMENT

        Our total property, plant and equipment are summarized below (in thousands).

	December 31,
	2015		2014
Electric plant
Production	$	1,151,395	$	1,159,140
Transmission		316,038		288,542
Distribution		870,047		840,761
General(1)		123,338		119,572
Electric plant		2,460,818		2,408,015
Less accumulated depreciation and amortization(2)		721,883		704,596
Electric plant net of depreciation and amortization		1,738,935		1,703,419
Construction work in progress		182,585		110,500
Net electric plant		1,921,520		1,813,919
Water plant		13,109		12,809
Less accumulated depreciation and amortization		5,281		5,102
Water plant net of depreciation and amortization		7,828		7,707
Construction work in progress		75		146
Net water plant		7,903		7,853
Net electric segment plant		1,929,423		1,821,772
Gas plant
Transmission		8,498		8,269
Distribution		66,588		63,319
General(3)		8,316		7,776
Gas Plant		83,402		79,364
Less accumulated depreciation and amortization		18,557		16,405
Gas plant net of accumulated depreciation		64,845		62,959
Construction work in progress		627		379
Net gas plant		65,472		63,338
Other
Fiber		44,263		41,394
Less accumulated depreciation and amortization		19,174		17,304
Non-regulated net of depreciation and amortization		25,089		24,090
Construction work in progress		402		1,072
Net non-regulated property		25,491		25,162
TOTAL NET PLANT AND PROPERTY	$	2,020,386	$	1,910,272

(1)Includes intangible property of $39.8 and $41.2 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2015 and 2014 was $15.6 and $15.7 million, respectively.

(2)As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are not reflected here. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.

(3)Includes intangible property of $0.9 and $0.7 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2015 and 2014 was $0.6 million and $0.5 million, respectively.

        The table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended December 31 (in thousands):

	2015		2014		2013
Provision for depreciation
Regulated — Electric and Water(1)	$	73,885	$	66,600	$	63,192
Regulated — Gas(1)		4,036		3,851		3,763
Non-Regulated		4,895		1,891		1,938
TOTAL		82,816		72,342		68,893
Amortization		2,858		2,692		2,492
TOTAL	$	85,674	$	75,034	$	71,385

(1)A portion of this amount is reclassified to a regulatory liability for the cost of removal. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.

	2015			2014			2013
Annual depreciation rates
Electric and water		3.1	%		3.0	%		3.0	%
Gas		5.1	%		5.2	%		5.4	%
Non-Regulated		4.4	%		4.7	%		5.0	%
TOTAL COMPANY		3.2	%		3.0	%		3.1	%

        The table below sets forth the average depreciation rate for each class of assets for each period presented:

	2015			2014			2013
Annual Weighted Average Depreciation Rate
Electric fixed assets:
Production plant		2.8	%		2.4	%		2.4	%
Transmission plant		2.4	%		2.4	%		2.4	%
Distribution plant		3.5	%		3.6	%		3.6	%
General plant		5.9	%		5.8	%		5.8	%
Water		2.8	%		2.7	%		2.8	%
Gas		5.1	%		5.2	%		5.4	%
Non-regulated		4.4	%		4.7	%		5.0	%

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REGULATORY MATTERS

12 Months Ended

Dec. 31, 2015

REGULATORY MATTERS

REGULATORY MATTERS

3.     REGULATORY MATTERS

Regulatory Assets and Liabilities and Other Deferred Credits

Changes

        Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives from December 31, 2014 to December 31, 2015 resulted from our 2014 Missouri rate case, which was effective July 26, 2015. As a result of this case, a new tracking mechanism related to our Riverton Unit 12 Long Term Maintenance Agreement was established. The tracking mechanisms related to Iatan 2, Iatan Common and Plum Point operating and maintenance costs were discontinued. The balances accumulated through August 2014 from these tracking mechanisms are to be amortized over three years. The tracking mechanism related to vegetation management was also discontinued. Balances accumulated through August 2014 will be amortized over five years. The balances accumulated in these discontinued tracking mechanisms after August 2014 will be addressed during the next rate case. In addition to these changes, the order also included the continuation of tracking mechanisms for expenses related to employee pension and retiree health care. There were no changes to regulatory assets and liabilities with regards to their rate base inclusion or amortizable lives from December 31, 2013 to December 31, 2014.

        The following table sets forth the components of our regulatory assets and regulatory liabilities on our consolidated balance sheet (in thousands).

	December 31,
	2015			2014
Regulatory Assets:
Current:
Under recovered fuel costs	$	196		$	2,618
Current portion of long-term regulatory assets		6,856			8,134
Regulatory assets, current		7,052			10,752
Long-term:
Pension and other postretirement benefits(1)		108,273			111,121
Income taxes		48,613			47,177
Deferred construction accounting costs(2)		14,977			15,521
Unamortized loss on reacquired debt		9,731			10,405
Unsettled derivative losses — electric segment		7,775			9,037
System reliability — vegetation management		3,604			5,337
Storm costs(3)		3,531			4,183
Asset retirement obligation		7,722			5,145
Customer programs		5,942			5,253
Missouri solar initiative		3,504			—
Current portion of long-term regulatory assets		(6,856	)		(8,134	)
Other		2,892			4,672
Regulatory assets, long-term		209,708			209,717
Total Regulatory Assets	$	216,760		$	220,469
Regulatory Liabilities
Current:
Over recovered fuel costs	$	5,280		$	4,227
Current portion of long-term regulatory liabilities		3,335			3,671
Regulatory liabilities, current		8,615			7,898
Long-term:
Costs of removal(4)		94,193			90,527
SWPA payment for Ozark Beach lost generation		14,213			16,744
Income taxes		11,244			11,451
Deferred construction accounting costs — fuel(5)		7,690			7,849
Unamortized gain on interest rate derivative		3,031			3,201
Pension and other postretirement benefits		1,745			2,369
Over recovered fuel costs		2,300			1
System reliability — vegetation management		1,320			—
Current portion of long-term regulatory liabilities		(3,335	)		(3,671	)
Other		56			—
Regulatory liabilities, long-term		132,457			128,471
Total Regulatory Liabilities	$	141,072		$	136,369

(1)Primarily consists of unfunded pension and OPEB liability. See Note 7.

(2)Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants.

(3)Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $2.9 million at December 31, 2015.

(4)As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are reflected here. See the depreciation discussion under Note 1 and Note 2 Property, Plant and Equipment for more detail.

(5)Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.

        Unamortized losses on debt and losses on interest rate derivatives are not included in rate base, but are included in our capital structure for rate base purposes. The remainder of our regulatory assets are not included in rate base, generally because they are not cash items. However, as of December 31, 2015, the costs of all of our regulatory assets are currently being recovered except for approximately $99.0 million of pension and other postretirement costs primarily related to the unfunded liabilities for future pension and OPEB costs. The amount and timing of recovery of this item will be based on the changing funded status of the pension and OPEB plans in future periods.

        The regulatory income tax assets and liabilities are generally amortized over the average depreciable life of the related assets. The loss on reacquired debt and the loss and gain on interest rate derivatives are amortized over the life of the related new debt issue, which currently ranges from 4 to 25 years. The unrecovered fuel costs are generally recovered within a year following their recognition. Severe storm costs and the Asbury maintenance outage costs are recovered over five years. Pension and other postretirement benefit tracking mechanisms are recovered over a five year period. The cost of removal regulatory liability is amortized as removal costs are incurred.

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 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

Electric Segment

Missouri

Rate Activity

2015 Rate Case:    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.

2014 Rate Case:    On August 29, 2014, we filed a request with the MPSC for changes in rates for our Missouri electric customers. We requested an annual increase in total revenue of approximately $24.3 million, or approximately 5.5%. The main cost drivers in the rate increase are the costs associated with our investment in Air Quality Control Facilities at our Asbury power plant (See Note 11 — New Construction of "Notes to Consolidated Financial Statements (Unaudited)") that were incurred to comply with the Environmental Protection Agency's (EPA) rules governing the continued operation of the plant, increases in property taxes, increases in ongoing maintenance expenses and increases in Regional Transmission Organization transmission fees. On June 24, 2015, the MPSC granted new rates for Missouri customers, effective on 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, consistent with the non-unanimous stipulation and agreement filed April 8, 2015. The order establishes a tracking mechanism for expenses related to the Riverton 12 long-term maintenance contract; continues tracking of pension and other post-employment benefit expenses; and discontinues tracking of vegetation management expenses and Iatan 2, Iatan Common and Plum Point operating and maintenance costs. In addition, the order provides for the tracking and recovery of certain future changes in total transmission expense through the Fuel Adjustment Charge, which we estimate at approximately 34% of such changes.

2015 Missouri Energy Efficiency Investment Act and Integrated Resource Plan

        On October 29, 2013 we filed an application with the Missouri Public Service Commission 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.

2015 Solar Rebate Tariff

        On May 5, 2015, we filed a proposed solar rebate tariff with the MPSC and requested expedited treatment. On May 6, 2015, the MPSC ordered our request for expedited treatment of our tariff filing be granted and approved the tariff, effective May 16, 2015. 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.

Kansas

2015 Ad Valorem Tax Surcharge

        On January 22, 2015, we filed an Application with the 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.

2014 Environmental Cost Recovery Rider

        On December 5, 2014, we filed an Application with the KCC requesting approval of our proposed Asbury Environmental Cost Recovery (AECR) tariff rider. The request sought approval for recovery of our jurisdictional portion of annual carrying costs (rate of return, income taxes, and depreciation) of approximately $0.86 million, associated with investment in the Asbury AQCS. A Commission Order was received April 15, 2015 approving the rider in the amount of $0.78 million effective June 1, 2015.

Oklahoma

        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.

Arkansas

2015 Tariff Rider

        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.

2014 Rate Case

        On May 20, 2014, we filed a settlement agreement with the Arkansas Public Service Commission (APSC) for an increase of $1.375 million, or approximately 11%. A hearing was held on the settlement agreement on July 22, 2014. On September 16, 2014, the APSC issued an order approving the settlement with a modification that reduced the overall revenue increase to $1.367 million. The new rates were effective September 26, 2014. We had filed a request on December 3, 2013, with the APSC seeking an annual increase in total revenue of approximately $2.2 million, or approximately 18%. The rate increase was requested to recover costs incurred to ensure continued reliable service for our customers, including capital investments, operating systems replacement costs and ongoing increases in other operation and maintenance expenses and capital costs.

FERC

        We have in place a cost-based transmission formula rate (TFR). On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement included a TFR that would establish an ROE of 10.0%. The Agreement calls for the TFR to be updated annually with the new updated TFR rates effective on July 1 of each year. FERC conditionally approved the Agreement on November 18, 2013, and we made a compliance filing with FERC on December 18, 2013 in connection with this conditional approval. The FERC approved our compliance filing on June 12, 2014.

        We have in place a cost-based generation formula rate (GFR). Our GFR requires an update to be completed annually for rates effective June 1. On October 29, 2014, Empire made a "limited" Section 205 filing to request some minor changes in the existing GFR formula to incorporate the impact of the recent implementation of the Southwest Power Pool Integrated Marketplace (IM). As a result of this filing, our customers' share of the margins we receive from sales into the IM will be passed on to them through the monthly fuel and purchased power cost adjustment mechanism rather than making one-time adjustments at each annual update. This filing was approved by FERC on January 13, 2015.

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

FERC Order No. 1000:    In July 2011, the FERC issued Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities) which requires all public utility transmission providers to allow transmission developers outside their retail distribution service territory to participate in regional transmission planning. Order No. 1000 eliminates the federal right of first refusal for entities that develop transmission projects within their own retail distribution service territories to construct transmission facilities selected in a regional transmission plan. This order will directly affect our rights to build 161kV and above transmission facilities within our retail service territory.

        Order No. 1000 also directed transmission providers to develop policy and procedures for regional and interregional transmission planning as well as regional and interregional transmission cost allocation (see "SPP Regional Transmission Development" below) for approved transmission projects. We continue to participate in the SPP processes to understand the impact of these FERC orders on our ability to construct new facilities within our service territory as well as their influence on promoting construction of transmission projects on or near our borders with our neighbors. SPP completed and filed with the FERC a required interregional policy and procedure compliance filing, and while FERC partially approved SPP's compliance filing, remaining issues have been addressed in a subsequent filing that is currently waiting FERC approval.

SPP Regional Transmission Development:    In 2010, SPP received FERC approval to implement a new highway/byway cost allocation methodology for new SPP approved transmission projects. We actively monitor SPP's policy to allocate the costs of transmission projects to its members. 2015 net SPP transmission expenses were approximately $1.3 million above 2014 levels. Our Arkansas and Oklahoma jurisdictions have cost recovery mechanisms in place to fully recover additional transmission costs outside the traditional rate making process, and Missouri has a mechanism in place to recover a portion of transmission expense above the amount in base fuel. See "Rate Matters" above for more information.

        The highway/byway allocation methodology requires the costs of SPP approved transmission projects to be allocated to 1) members across the entire SPP region; 2) members within certain localized service territories or zones; or 3) a combination of both regional and zonal allocation. The allocation is based on project voltage, as follows:

Transmission Project Voltage	Regional Funding Percentage			Zonal Funding Percentage
300 kV and Above		100.0	%		0.0	%
100kV to 299kV		33.3	%		66.7	%
Below 100 kV		0.0	%		100.0	%

        SPP's formal regional cost allocation review and benefit to cost imbalance analysis process is ongoing. A filing to outline several possible remedies for entities not receiving adequate benefits from projects regionally funded was rejected by FERC and discussion continues in stakeholder groups to develop alternatives.

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.

Gas Segment

        Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers.

Other — Rate Matters

        In accordance with ASC guidance on regulated operations, we currently have deferred approximately $0.4 million of expense related to rate cases under other non-current assets and deferred charges. These amounts will be amortized over varying periods based upon the completion of the specific cases. Based on past history, we expect all these expenses to be recovered in rates.

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SHAREHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2015

SHAREHOLDERS' EQUITY

SHAREHOLDERS' EQUITY

4.     SHAREHOLDERS' EQUITY

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 million remains available after the issuance of $60 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.

Employee Benefit Plans

        Our Employee Stock Purchase Plan permits the grant to eligible employees of options to purchase our common stock at a discounted price. As of December 31, 2015 there were 764,645 shares available for issuance in this plan. Under our Employee 401(k) Plan and ESOP we match a percentage of each employee's deferrals by contributing shares of our common stock. At December 31, 2015 there were 129,616 shares available to be issued. (See Note 7 for further discussion of these plans).

Equity Based Compensation

        We have several stock-based awards programs, which are described in Note 8. Our 2015 Stock Incentive Plan provides for grants of up to 500,000 shares of common stock through January 2025. At December 31, 2015 there were 496,766 shares available to be issued.

Dividends

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

        The following table shows our diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance for the years ended December 31, 2015, 2014 and 2013:

(in millions, except per share amounts)	2015		2014		2013
Diluted earnings per share	$	1.29	$	1.55	$	1.48
Dividends paid per share	$	1.04	$	1.025	$	1.005
Total dividends paid	$	45.4	$	44.4	$	43.0
Retained earnings year-end balance	$	101.4	$	90.3	$	67.6

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

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

Preferred and Preference Stock

        We have 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A Participating Preference Stock, none of which have been issued. We have 5 million shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2015 or 2014.

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2015

LONG-TERM DEBT.

LONG-TERM DEBT

5.     LONG-TERM DEBT

        At December 31, 2015 and 2014, the balance of long-term debt outstanding was as follows (in thousands):

	2015			2014
First mortgage bonds (EDE):
7.20% Series due 2016	$	25,000		$	25,000
6.375% Series due 2018(1)		90,000			90,000
4.65% Series due 2020(1)		100,000			100,000
3.58% Series due 2027(1)		88,000			88,000
3.59% Series due 2030(1)		60,000			—
3.73% Series due 2033(1)		30,000			30,000
5.875% Series due 2037(1)		80,000			80,000
5.20% Series due 2040(1)		50,000			50,000
4.32% Series due 2043(1)		120,000			120,000
4.27% Series due 2044(1)		60,000			60,000
First mortgage bonds (EDG):
6.82% Series due 2036(1)		55,000			55,000
		758,000			698,000
Senior Notes, 6.70% Series due 2033(1)		62,000			62,000
Senior Notes, 5.80% Series due 2035(1)		40,000			40,000
Capital lease obligations		3,890			4,167
Less unamortized net discount		(633	)		(686	)
		863,257			803,481
Less current obligations of long-term debt		(25,000	)		—
Less current obligations under capital lease		(310	)		(292	)
TOTAL LONG-TERM DEBT	$	837,947		$	803,189

(1)We may redeem some or all of the notes at any time at 100% of their principal amount, plus a make-whole premium, plus accrued and unpaid interest to the redemption date.

Debt 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. The bonds are prepayable at our option at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the prepayment date. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for general corporate purposes. The bonds have not been and will not be registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage.

        On October 15, 2014, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 4.27% First Mortgage Bonds due December 1, 2044. A delayed settlement occurred on December 1, 2014. Interest is payable semi-annually on the bonds on each December 1 and June 1, commencing June 1, 2015. The bonds may be redeemed at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for general corporate purposes. The bonds have not been, and will not be, registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage.

Shelf Registration

        We have a $200 million shelf registration statement with the SEC that is effective for three years from December 13, 2013. See Note 4.

EDE Mortgage Indenture

        Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $297 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 test would permit the issuance of more than $297.0 million of 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.

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.

        Our long-term debt obligations over the next five years are as follows (in thousands):

	Payments Due By Period
Long-Term Debt Payout Schedule (Excluding Unamortized Discount) (in thousands)	Total		Regulated Entity Debt Obligations		Capital Lease Obligations
2016	$	25,310	$	25,000	$	310
2017		329		—		329
2018		90,351		90,000		351
2019		375		—		375
2020		100,396		100,000		396
Thereafter		647,129		645,000		2,129
Total long-term debt obligations		863,890	$	860,000	$	3,890
Less current obligations and unamortized discount		25,943
TOTAL LONG-TERM DEBT	$	837,947

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SHORT-TERM BORROWINGS

12 Months Ended

Dec. 31, 2015

SHORT-TERM BORROWINGS

SHORT-TERM BORROWINGS

6.     SHORT-TERM BORROWINGS

        At December 31, 2015, total short-term borrowings consisted of $25.0 million in commercial paper and no borrowings under our line of credit. During 2015 and 2014 our short-term borrowings outstanding averaged (in millions)

	2015		2014
Average borrowings outstanding	$	48.9	$	30.0
Highest month end balance	$	97.0	$	77.0

        The weighted average interest rates and the weighted average interest rate of borrowings outstanding at December 31, 2015 and 2014 were:.

	2015			2014
Weighted average interest rate		0.54	%		0.38	%
Weighted average interest rate of borrowings outstanding		0.84	%		0.44	%

        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.

        Interest on borrowings under the new facility accrues at a rate equal to, at our option, (i) the highest of (A) the agent prime rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, in each case, plus a margin or (ii) one month, two month, three month or six month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility is 1.025%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings, which is currently 0.175%. In addition, upon entering into the new credit facility, we paid upfront fees to the revolving credit banks of $0.3 million in the aggregate.

        The new credit facility requires our total indebtedness to be less than 65.0% of our total capitalization at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2015, we were in compliance with this covenant as our ratio of total indebtedness to total capitalization was 0.53 to 1.0. The new credit facility is also subject to cross-default if we default on more than $25 million in the aggregate on our other indebtedness. As of December 31, 2015, we were not in default under any of our debt obligations.

        The new credit agreement does not legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under the agreement at December 31, 2015; however, $25.0 million was used to back up our outstanding commercial paper.

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RETIREMENT AND OTHER EMPLOYEE BENEFITS

12 Months Ended

Dec. 31, 2015

RETIREMENT AND OTHER EMPLOYEE BENEFITS

RETIREMENT AND OTHER EMPLOYEE BENEFITS

7.     RETIREMENT AND OTHER EMPLOYEE BENEFITS

        We record retirement benefits in accordance with the ASC guidance on accounting for pension and other postretirement benefits, and have recorded the appropriate liabilities to reflect the unfunded status of our benefit plans, with offsetting entries to a regulatory asset, because we believe it is probable the unfunded amount of these plans will be afforded rate recovery. Additionally, the MPSC agreed that the effects of purchase accounting entries related to pension and other post-retirement benefits would be recoverable in future rate proceedings. These amounts, which are related to EDG, were recorded as regulatory assets and are being amortized. The tax effects of these entries are reflected as deferred tax assets and liabilities and regulatory liabilities.

        Annually we evaluate the discount rate, retirement age, compensation rate increases, expected return on plan assets, healthcare cost trend rate, and other actuarial assumptions related to pension benefit and post-retirement medical plan. We utilize an interest rate yield curve to determine an appropriate discount rate. The yield curve is constructed based on the yields on over 500 high-quality, non-callable corporate bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of the Empire pension plan and develop a single point discount rate matching the plan's payout structure. In evaluating these assumptions, many factors are considered, including, current market conditions, asset allocations, changes in demographics and the views of leading financial advisors and economists. In evaluating the expected retirement age assumption, we consider the retirement ages of past employees eligible for pension and medical benefits together with expectations of future retirement ages. It is reasonably possible that changes in these assumptions will occur in the near term and, due to the uncertainties inherent in setting assumptions, the effect of such changes could be material to the Company's consolidated financial statements. A roll forward technique is used to value the year ending pension obligations. The roll forward technique values the year-end obligation by rolling forward the beginning-of-year obligation using the demographic assumptions disclosed below. The economic assumptions are updated as of the end of the year. All of the benefit plans have been measured as of December 31, 2015, consistent with previous years. See Note 1.

Pensions

        Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. Effective on January 1, 2014, the plan was amended to include a cash balance benefit formula. Employees hired on or after January 1, 2014 will accrue benefits based on a cash balance methodology. Employees hired prior to January 1, 2014 were given a one-time option to convert to the cash balance methodology, or remain with our traditional average annual basic earnings formula, by December 31, 2014. Both benefit formulas allow for a lump sum distribution of vested benefits. Lump sum distributions totaled approximately $15.3 million and $9.0 million during 2015 and 2014, respectively, and did not require settlement accounting according to ASC 715.

        Annual contributions to the plan are at least equal to the greater of either minimum funding requirements of ERISA or the accrued cost of the Plan, as required by the Missouri Public Service Commission.

        Our net pension liability decreased $2.4 million in 2015, which was recorded as a decrease in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The decrease in the liability is primarily due to an increase in discount rates. Our contribution is estimated to be approximately $13.6 million for 2016. We expect future pension funding commitments to continue at least at the level of our accrued cost, as required by our regulator. The actual minimum funding requirements will be determined based on the results of the actuarial valuations and, in the case of 2017, the performance of our pension assets during 2016.

        We also have a supplemental retirement program ("SERP") for designated officers of the Company, which we fund from Company funds as the benefits are paid. The liability for this plan increased $0.7 million in 2015.

        Expected benefit payments are as follows (in millions):

Year	Payments from Trust		Payments from Company Funds
2016	$	22.5	$	0.5
2017		22.8		0.6
2018		21.5		0.5
2019		20.0		0.5
2020		20.9		0.8
2021 – 2025		97.4		2.9

Other Postretirement Benefits (OPEB)

        We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors through trusts we have established. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service. Employees hired after January 1, 2014 will be offered unsubsidized retiree healthcare benefits upon retirement.

        Our net liability decreased $10.0 million in 2015, which was recorded as a decrease in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The decrease in the liability is primarily due to a significant actuarial gain resulting from increases in discount rates, the adoption of a new mortality table and positive claims trends. Our funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. We expect to be required to fund approximately $4.9 million in 2016.

        Estimated benefit payments are as follows (in millions):

Year	Payments from Trust		Expected Federal Subsidy		Payments from Company Funds
2016	$	2.8	$	0.4	$	0.2
2017		3.2		0.4		0.2
2018		3.5		0.5		0.2
2019		3.8		0.5		0.2
2020		4.1		0.6		0.2
2021 – 2025		25.0		3.7		0.8

        The following tables set forth the Company's benefit plans' projected benefit obligations, the fair value of the plans' assets and the funded status (in thousands).

	Pension						SERP						OPEB
Reconciliation of Projected Benefit Obligations:	2015			2014			2015			2014			2015			2014
Benefit obligation at beginning of year	$	251,879		$	225,131		$	9,155		$	7,108		$	109,899		$	85,332
Service cost		7,442			6,467			158			153			3,713			2,601
Interest cost		10,278			10,819			382			387			4,670			4,360
Amendments		—			(7,753	)		—			(45	)		—			—
Net actuarial (gain)/loss		(708	)		36,742			557			1,890			(14,358	)		20,347
Plan participant's contribution		—			—			—			—			963			850
Benefits and expenses paid		(25,201	)		(19,527	)		(366	)		(338	)		(3,839	)		(3,897	)
Federal subsidy		—			—			—			—			419			306
Benefit obligation at end of year	$	243,690		$	251,879		$	9,886		$	9,155		$	101,467		$	109,899

	Pension						SERP				OPEB
Reconciliation of Fair Value of Plan Assets:	2015			2014			2015		2014		2015			2014
Fair value of plan assets at beginning of year	$	192,674		$	186,547		$	—	$	—	$	83,776		$	79,098
Actual return on plan assets — gain/(loss)		(1,978	)		14,319			—		—		(955	)		5,030
Employer contribution		21,350			11,335			—		—		4,903			2,258
Benefits paid		(25,201	)		(19,527	)		—		—		(3,670	)		(3,707	)
Plan participant's contribution		—			—			—		—		912			804
Federal subsidy		—			—			—		—		403			293
Fair value of plan assets at end of year	$	186,845		$	192,674		$	—	$	—	$	85,369		$	83,776

	Pension						SERP						OPEB
Reconciliation of Funded Status:	2015			2014			2015			2014			2015			2014
Fair value of plan assets	$	186,845		$	192,674		$	—		$	—		$	85,369		$	83,776
Projected benefit obligations		(243,690	)		(251,879	)		(9,886	)		(9155	)		(101,467	)		(109,899	)
Funded status	$	(56,845	)	$	(59,205	)	$	(9,886	)	$	(9,155	)	$	(16,098	)	$	(26,123	)

        The employee pension plan accumulated benefit obligation at December 31, 2015 and 2014 is presented in the following table (in thousands):

	Pension Benefits				SERP
	2015		2014		2015		2014
Accumulated benefit obligation	$	221,481	$	227,928	$	8,609	$	7,160

        Amounts recognized in the balance sheet consist of (in thousands):

	Pension				SERP				OPEB
	2015		2014		2015		2014		2015		2014
Accounts Payable and Accrued Liabilities	$	—	$	—	$	534	$	481	$	151	$	139
Pension and other postretirement benefit obligation	$	56,845	$	59,205	$	9,352	$	8,674	$	15,947	$	25,984

        Net periodic benefit pension cost for 2015, 2014 and 2013, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset (see Note 3), is comprised of the following components (in thousands):

	Pension									OPEB
Net Periodic Pension Benefit Cost:	2015			2014			2013			2015			2014			2013
Service cost	$	7,442		$	6,467		$	7,454		$	3,713		$	2,601		$	2,941
Interest cost		10,278			10,819			10,063			4,670			4,360			3,827
Expected return on plan assets		(13,567	)		(13,105	)		(12,428	)		(5,197	)		(4,801	)		(4,353	)
Amortization of prior service cost/(benefit)(1)		(630	)		418			532			(1,011	)		(1,011	)		(1,011	)
Amortization of actuarial loss(1)		10,033			6,611			10,445			2,747			967			2,261
Net periodic benefit cost	$	13,556		$	11,210		$	16,066		$	4,922		$	2,116		$	3,665

	SERP
Net Periodic Pension Benefit Cost:	2015			2014			2013
Service cost	$	158		$	153		$	135
Interest cost		382			387			315
Expected return on plan assets		—			—			—
Amortization of prior service cost/(benefit)t(1)		(42	)		(8	)		(8	)
Amortization of actuarial loss(1)		597			504			567
Net periodic benefit cost	$	1,095		$	1,036		$	1,009

(1)Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.

        The tables below present other changes in plan assets and benefit obligations recognized in the regulatory asset accounts for the year (in thousands).

			Amount Recognized
Regulatory Assets	Beginning Balance 12/31/14		Current Year Actuarial Loss			Amortization of Actuarial Loss			Current Year Prior Service Credit		Amortization of Prior Service (Cost)/Credit		Ending Balance 12/31/15
Pension	$	77,456		14,836			(10,033	)		—		630	$	82,889
SERP	$	5,537		557			(597	)		—		42	$	5,539
OPEB	$	20,446		(8,208	)		(2,747	)		—		1,011	$	10,502

			Amount Recognized
Regulatory Assets	Beginning Balance 12/31/13		Current Year Actuarial Loss		Amortization of Actuarial Loss			Current Year Prior Service Credit			Amortization of Prior Service (Cost)/Credit			Ending Balance 12/31/14
Pension	$	56,709		35,529		(6,611	)		(7,753	)		(418	)	$	77,456
SERP	$	4,188		1,890		(504	)		(45	)		8		$	5,537
OPEB	$	285		20,117		(967	)		—			1,011		$	20,446

        The following table presents the amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost. It also shows the amounts expected to be recognized in the subsequent year. The following table presents those items for the employee pension plan and other benefits plan at December 31, 2015, and the subsequent twelve-month period (in thousands):

	Pension Benefits						SERP						OPEB
	2015			Subsequent Period			2015			Subsequent Period			2015			Subsequent Period
Net actuarial loss	$	88,981		$	8,426		$	5,555		$	555		$	12,075		$	1,030
Prior service cost (benefit)		(6,092	)		(630	)		(16	)		(14	)		(1,573	)		(1,011	)
Total	$	82,889		$	7,796		$	5,539		$	541		$	10,502		$	19

        The measurement date used to determine the pension and other postretirement benefits is December 31. The assumptions used to determine the benefit obligation and the periodic costs are as follows:

Weighted-average assumptions used to determine the benefit obligation as of December 31:

	Pension Benefits						OPEB
	2015			2014			2015			2014
Discount rate		4.40	%		4.06	%		4.48	%		4.15	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%		3.50	%

Weighted-average assumptions used to determine the net benefit cost (income) as of January 1:

	Pension Benefits									OPEB
	2015			2014			2013			2015			2014			2013
Discount rate		4.06	%		4.90	%		4.00	%		4.15	%		5.00	%		4.11	%
Expected return on plan assets		7.75	%		7.75	%		7.75	%		6.52	%		6.52	%		6.52	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%

        The expected long-term rate of return assumption was based on historical return and adjusted to estimate the potential range of returns for the current asset allocation. The assumed 2015 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 7.0%. Each trend rate decreases 0.50% through 2020 to an ultimate rate of 5.0% in 2020 and subsequent years.

        The healthcare cost trend rate affects projected benefit obligations. A 1% change in assumed healthcare cost growth rates would have the following effects (in thousands):

	1% Increase		1% Decrease
Effect on total of service and interest cost	$	2,051	$	(1,530	)
Effect on post-retirement benefit obligation	$	17,473	$	(13,794	)

Fair value measurements of plan assets

        See Note 15 for a discussion of fair value measurements. The Company believes that it is appropriate for the pension fund to assume a moderate degree of investment risk with diversification of fund assets among different classes (or types) of investments, as appropriate, as a means of reducing risk. Although the pension fund can and will tolerate some variability in market value and rates of return in order to achieve a greater long-term rate of return, primary emphasis is placed on preserving the pension fund's principal. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company's Investment Committee. The following is a description of the valuation methodologies used for assets measured at fair value using significant other observable, or significant unobservable inputs.

        Short-term investments:    Valued at cost, which approximates fair value.

        Common/Collective trusts:    Valued at the fair value based on audited financials of the trusts.

        U.S. corporate and foreign issue debt:    Valued at quoted market prices when available in an active market. If quoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows.

        Equity long/short hedge funds:    Valued at the net asset value reported in the annual audited financial statements and updated monthly based on changes in the value of the underlying funds reported by the fund manager.

Pension plan assets

        We utilize fair value in determining the market-related values for the different classes of our pension plan assets. The market-related value is determined based on smoothing actual asset returns in excess of (or less than) expected return on assets over a 5-year period.

        The Company's primary investment goals for pension fund assets are based around four basic elements:

1.	Preserve capital,
2.	Maintain a minimum level of return equal to the actuarial interest rate assumption,
3.	Maintain a high degree of flexibility and a low degree of volatility, and
4.	Maximize the rate of return while operating within the confines of prudence and safety.

Asset Allocation

        We have adopted an investment strategy referred to as a de-risking glide path to increase the fixed income allocation as the plan's funded status improves. As the pension plan reaches set funded status milestones, the plan's assets will be rebalanced to shift more assets from equity to fixed income. Based on the plan's progress with this strategy, the target investment allocation for pension fund assets is approximately 72% equities and 28% fixed income securities. However, these allocations are permitted to vary within the following ranges: 60% – 80% for equities and 20% – 40% for fixed income securities. Money market funds are permitted within the fixed income category. Investment managers may generally hold up to 10% cash in their portfolios although this limit may be exceeded if market conditions warrant.

        The following fair value hierarchy table presents information about the pension fund assets measured at fair value as of December 31, 2015 and December 31, 2014 (in thousands):

	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Percentage of Plan Assets
Short term investments	$	—	$	71	$	—	$	71		0.0	%
Equity securities
Common collective trusts — domestic		—		46,182		—		46,182		24.7	%
Common collective trusts — international				41,928				41,928		22.5	%
Fixed income
Common collective trust		—		60,694		—		60,694		32.5	%
Other types of investments
Equity long/short hedge funds		—		—		37,970		37,970		20.3	%
	$	—	$	148,875	$	37,970	$	186,845		100.0	%

	Fair Value Measurements as of December 31, 2014
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Percentage of Plan Assets
Short term investments	$	—	$	70	$	—	$	70		0.0	%
Equity securities
Common collective trusts — domestic		—		48,760		—		48,760		25.3	%
Common collective trusts — international				42,770				42,770		22.2	%
Fixed income
Common collective trust		—		62,646		—		62,646		32.5	%
Other types of investments
Equity long/short hedge funds		—		—		38,428		38,428		20.0	%
	$	—	$	154,246	$	38,428	$	192,674		100.0	%

Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — December 31,

	2015			2014
	Equity long/short hedge funds			Equity long/short hedge funds
Beginning Balance, January 1,	$	38,428		$	36,729
Actual return on plan assets:
Relating to assets still held at the reporting date		(458	)		1,382
Relating to assets sold during the period		—			1,491
Purchases		—			9,700
Sales		—			(10,874	)
Settlements		—			—
Transfers into and (out of) Level 3		—			—
Ending Balance, December 31,	$	37,970		$	38,428

Permissible Investments

        Listed below are the investment vehicles specifically permitted:

Permissible Investments

Equity Oriented

Fixed Income Oriented and Real Estate

 Common Stocks  Preferred Stocks (minimum "A-rated" by Moody's or S&P)  American Depository Receipts  Convertible Preferred Stocks  Convertible Bonds  Covered Options  Hedged Equity Funds of Funds

 Bonds (including US Government and Agencies)  Corporate Bonds (minimum quality rating of Baa by Moody's or BBB by S&P)  Comingled bond funds (25% max. allocation to high yield)  Foreign Government Bonds  GIC's, BIC's  Commercial Paper (rated A1 by S&P or P1 by Moody's)  Certificates of Deposit in institutions with FDIC/FSLIC protection  Money Market Funds/Bank STIF Funds  Real Estate — Publicly Traded

        The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

        Those investments prohibited by the Investment Committee without prior approval are:

Prohibited Investments Requiring Pre-approval

 Privately Placed Securities  Commodities Futures  Securities of Empire District (except in the hedged equity funds of funds or commingled funds)  Restricted Stock  Warrants  Short Sales  Index Options  Letter Stock

OPEB plan assets

        The Company's primary investment goals for the component of the OPEB fund used to pay current benefits are liquidity and safety. The primary investment goals for the component of the OPEB fund used to accumulate funds to provide for payment of benefits after the retirement of plan participants are preservation of the fund with a reasonable rate of return. The target allocation for plan assets is 60% equities and 40% fixed income, although, at any given time, up to 10% of either category may be invested in cash equivalents. The 10% cash limitation may be exceeded if market conditions warrant. Allocations may also vary within the following ranges: 44% – 76% equities and 36% – 44% fixed income securities. The following fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2014 and December 31, 2013 (in thousands):

	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total			Percentage of Plan Assets
Equity securities
Common collective trusts	$	—	$	48,553	$	—	$	48,553			56.9	%
Fixed income
Common collective trusts		—		34,395		—		34,395			40.3	%
Other types of investments
Common collective trusts		—		2,556		—		2,556			3.0	%
	$	—	$	85,504	$	—		85,504
Payable for securities purchased								(135	)		–0.2	%
							$	85,369			100.0	%

	Fair Value Measurements as of December 31, 2014
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total			Percentage of Plan Assets
Equity securities
Common collective trusts	$	—	$	47,690	$	—	$	47,690			56.9	%
Fixed income
Common collective trusts		—		33,708		—		33,708			40.2	%
Other types of investments
Common collective trusts		—		2,453		—		2,453			2.9	%
	$	—	$	83,851	$	—	$	83,851
Payable for securities purchased								(75	)		0.0	%
							$	83,776			100.0	%

        The Company's guideline in the management of this fund is to endorse a long-term approach, but not expose the fund to levels of volatility that might adversely affect the value of the assets. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company's Investment Committee.

Permissible Investments

        Listed below are the investment vehicles specifically permitted:

Permissible Investments

Equity

Fixed Income

 Common Stocks  Preferred Stocks

 Cash-Equivalent Securities with a maturity of one-year or less, including: money market funds, US Government and Agency securities, certificates of deposit or banker's acceptances issued by domestic banks with FDIC protection and commercial paper rated A1 by S&P or P1 by Moody's  Government Bonds  Money Market Funds / Bank STIF Funds  Certificates of Deposit in institutions with FDIC protection  Corporate Bonds (minimum quality rating of A Baa by Moody's or BBB by S&P at time of issuance)

        The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

        Listed below are those investments prohibited by the Investment Committee:

Prohibited Investments

 Privately Placed Securities  Securities of Empire District  Derivatives  Instrumentalities in violation of the Prohibited Transactions Standards of ERISA  Margin Transactions  Options (other than "covered call options")  Lettered or Restricted Stock  Any other investment security which, in the opinion of the investment manager produces an imprudent risk to the fund

Employee Stock Purchase Plan

        Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The look-back feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of December 31, 2015 there were 764,645 shares available for issuance in this plan.

	2015			2014		2013
Subscriptions outstanding at December 31,		58,742			57,369		60,413
Maximum subscription price	$	21.09	(1)	$	21.43	$	19.58
Shares of stock issued		56,193			56,942		68,099
Stock issuance price	$	21.01		$	19.58	$	17.95

(1)Stock will be issued on the closing date of the purchase period, which runs from June 1, 2015 to May 31, 2016.

        Assumptions for valuation of these shares are shown in the table below.

	2015			2014			2013
Weighted average fair value of grants	$	3.58		$	3.07		$	2.78
Risk-free interest rate		0.26	%		0.10	%		0.14	%
Dividend yield		4.40	%		4.30	%		4.60	%
Expected volatility(1)		21.00	%		14.00	%		14.00	%
Expected life in months		12			12			12
Grant date		6/1/2015			6/2/2014			6/1/2013

(1)One-year historic volatility

401(k) Plan and ESOP

        Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to 25% of their annual compensation up to an Internal Revenue Service specified limit. For employees participating in the cash balance formula of the pension plan, discussed above, we match 100% of their deferrals, not to exceed 6% of the employee's eligible compensation. The first 3% of the matching contribution is made in shares of our common stock with the remaining portion made by contributing cash. For employees remaining with the traditional average annual basic earnings formula of the pension plan, we match 50% of their deferrals by contributing shares of our common stock, with such matching contributions not to exceed 3% of the employee's eligible compensation. We record the compensation expense at the time the quarterly matching contributions are made to the plan. At December 31, 2015 there were 129,616 shares available to be issued.

	2015		2014		2013
Shares contributed		66,783		60,049		64,128

Deferred Compensation

        Effective January 2015, we established a non-qualified Deferred Compensation Plan for the purpose of allowing executive officers who elect to participate in the qualifying cash balance option of the Pension plan to obtain retirement savings that are not available to them under the 401(k) plan.

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EQUITY COMPENSATION

12 Months Ended

Dec. 31, 2015

EQUITY COMPENSATION

EQUITY COMPENSATION

8.     EQUITY COMPENSATION

        We have several stock-based awards and programs, which are described below. Performance-based restricted stock awards, time-vested restricted stock and stock options are valued as liability awards, in accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award.

        We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in thousands):

	2015		2014		2013
Compensation expense	$	4,279	$	3,688	$	2,577
Tax benefit recognized		1,576		1,359		929

Stock Incentive Plans

        Our 2006 Stock Incentive Plan (the 2006 Incentive Plan), which expired on December 31, 2015, was replaced by the 2015 Stock Incentive Plan (the 2015 Incentive Plan). The 2015 Incentive Plan was adopted by shareholders at the annual meeting on May 1, 2014 and provides for grants of up to 500,000 shares of common stock through January 2025. At December 31, 2015 there were 496,766 shares available to be issued. The 2015 Stock Incentive Plan permits (and the 2006 Incentive Plan permitted) grants of stock options and restricted stock to qualified employees and permits Directors and, if approved by the Compensation Committee of the Board of Directors, qualified employees to receive common stock in lieu of cash. Certain executive officers and other senior managers applied to receive annual incentive awards related to 2013, 2014 and 2015 performance in the form of Empire common stock rather than cash. These requests were granted by the Compensation Committee of the Board of Directors under the terms of our 2006 and 2015 Stock Incentive Plans. The terms and conditions of any option or stock grant are determined by the Board of Directors Compensation Committee, within the provisions of these Stock Incentive Plans.

Time-Vested Restricted Stock Awards

        Beginning in 2011, we began granting, to qualified individuals, time-vested restricted stock awards that vest after a three-year period, in lieu of stock options. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminates during the vesting period because of death, retirement or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned, which is distributed following the date of termination, with the remainder of the award forfeited. If employment is terminated during the vesting period for reasons other than those listed above, the time-vested restricted stock awards will be forfeited on the date of the termination, unless the Board of Directors' Compensation Committee determines, in its sole discretion, that the participant is entitled to a pro-rata portion of the award. In addition, if a change in control occurs during the vesting period, a pro-rata portion of the time-vested restricted stock awards will vest upon such change in control, and any portion of such awards that remains unvested immediately after the change in control will be forfeited.

        The fair value measurements for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at December 31
	2015	2014
Total unrecognized compensation cost (in millions)	$0.4	$0.4
Recognition period	0.1 years to 2.1 years	1.1 years to 2.1 years
Fair value	$25.17	$26.82

        A summary of time-vested restricted stock activity under the plan for 2015, 2014 and 2013 is presented in the table below:

	2015					2014					2013
	Number of Shares			Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Grant Date Fair Value		Number Of Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1,		41,000		$	21.89		24,900		$	21.42		3,300	$	21.84
Granted		19,000		$	30.40		22,600		$	22.40		21,600	$	21.36
Distributed		(1,654	)	$	21.92		(4,010	)	$	21.77		—		—
Forfeited		(2,746	)	$	25.91		(2,490	)	$	21.99		—		—
Outstanding at December 31,		55,600		$	24.60		41,000		$	21.89		24,900	$	21.42

Performance-Based Restricted Stock Awards

        Performance-based restricted stock awards are granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of the restricted period assuming performance criteria are met. The performance measure for the award is the total return to our shareholders over a three-year period compared with an investor-owned utility peer group. The threshold level of performance under the 2013, 2014 and 2015 grants was set at the 20th percentile level of the peer group, target at the 50th percentile level, and the maximum at the 80th percentile level. Shares would be earned at the end of the three-year performance period as follows: 100% of the target number of shares if the target level of performance is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above the maximum, with the number of shares interpolated between these levels. However, no shares would be payable if the threshold level is not reached.

        If employment terminates during the performance period because of death, retirement, or disability, the individual is entitled to a pro-rata portion of the performance-based restricted stock awards such individual would otherwise have earned. If employment is terminated during the performance period for reasons other than those listed above, the performance-based restricted stock awards will be forfeited on the date of the termination unless the Compensation Committee of the Board of Directors determines, in its sole discretion, that the individual is entitled to a pro-rata portion of such award. In addition, if a change in control occurs during the performance period, a pro-rata portion of the target performance-based restricted stock awards will vest and be distributed upon such change in control. At the end of the performance period, the number of shares earned, determined without regard to the special change in control vesting provisions will be determined and such amount, less the number of shares distributed upon the change in control, shall be distributed. In connection with the Agreement and Plan of Merger dated February 9, 2016, by and among the Company, Liberty Utilities (Central) Co. and Liberty Sub Corp. (the "Merger Agreement"), we amended outstanding performance-based restricted stock awards to provide that, effective upon and subject to the occurrence of the merger under the Merger Agreement, each performance-based restricted stock award outstanding immediately prior to the effective time of the merger will be converted into the right to receive a lump sum in cash equal to the merger consideration under the merger agreement, multiplied by the target number of shares under the award. (See Note 17 for further discussion of the Merger Agreement).

        The fair value of the outstanding restricted stock awards was estimated as of December 31, 2015, 2014 and 2013 using a Monte Carlo option valuation model. The assumptions used in the model for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at December 31,
	2015	2014	2013
Risk-free interest rate	0.65% to 1.06%	0.25% to 0.67%	0.13% to 0.38%
Expected volatility of Empire stock	18.7%	14.5%	20.2%
Expected volatility of peer group stock	14.5% to 34.4%	12.4% to 24.8%	12.3% to 27.5%
Expected dividend yield on Empire stock	3.7%	3.5%	4.5%
Expected forfeiture rates	3%	3%	3%
Plan cycle	3 years	3 years	3 years
Fair value percentage	115.0% to 182.0%	140.0% to 157.0%	0.0% to 108.0%
Weighted average fair value per share	$41.73	$43.80	$18.47

        Non-vested performance-based restricted stock awards (based on target number) as of December 31, 2015, 2014 and 2013 and changes during the year ended December 31, 2015, 2014 and 2013 were as follows:

	2015					2014					2013
	Number of Shares			Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Grant Date Fair Value		Number Of Shares			Weighted Average Grant Date Fair Value
Outstanding at January 1,		63,300		$	21.74		47,200		$	21.39		33,900		$	20.25
Target shares granted		21,800		$	30.40		27,000		$	22.40		26,300		$	21.36
Shares issued in excess of target		3,653		$	20.97		—			—		—			—
Shares awarded		(13,653	)	$	20.97		—			—		(4,460	)	$	18.36
Forfeited shares		(6,079	)	$	24.10		—			—		—
Target shares not awarded		—			—		(10,900	)	$	21.84		(8,540	)	$	18.36
Nonvested at December 31,		69,021		$	24.38		63,300		$	21.74		47,200		$	21.39

        At December 31, 2015 and 2014, unrecognized compensation expense related to estimated outstanding awards was $0.7 million and $1.1 million, respectively.

Stock Options

        Beginning in 2011, we began issuing time-vested restricted stock in lieu of stock options and dividend equivalents. Prior to 2011 stock options were issued with an exercise price equal to the fair market value of the shares on the date of grant. They became exercisable after three years and expired ten years after the date granted. Dividend equivalent awards, under which dividend equivalents accumulated during the vesting period, were also issued to recipients of the stock options. Participants' options and dividend equivalents that were not vested were forfeited when participants left Empire, except for terminations of employment under certain specified circumstances. There were no stock options or dividend equivalents granted in 2015, 2014, or 2013, and all outstanding options were exercised prior to December 31, 2014.

        Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. There were no outstanding options at December 31, 2015 and 2014. The fair value of the outstanding options was estimated as of December 31, 2013, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

	Fair Value of Grants Outstanding at December 31, 2013
Risk-free interest rate	0.10% to 0.38%
Dividend yield	4.5%
Expected volatility	24.0%
Expected life in months	6.5 to 24.5
Market value	$22.69
Weighted average fair value per option	$1.57

        A summary of option activity under the plan during the years ended December 31, 2014 and 2013 is presented below:

	2014				2013
	Options		Weighted Average Exercise Price		Options			Weighted Average Exercise Price
Outstanding at January 1,		112,500	$	23.27		163,300		$	22.13
Granted		—		—				$	—
Exercised		112,500	$	24.58		(50,800	)	$	21.78
Outstanding at December 31,		—				112,500		$	23.27
Exercisable, end of year		—				112,500		$	23.27

        The intrinsic value of the unexercised options is the difference between the Company's closing stock price on the last day of the period and the exercise price multiplied by the number of in-the-money options, had all option holders exercised their options on the last day of the period. The intrinsic value is zero if such closing price is less than the exercise price. The table below shows the aggregate intrinsic values at December 31, 2013:

	2013
Aggregate intrinsic value (in millions)	Less than $0.1
Weighted-average remaining contractual life of outstanding options	2.1 years
Range of exercise prices	$21.92 to $23.81
Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	—
Recognition period	—

Stock Unit Plan for Directors

        Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based compensation program for directors. This plan enhances our ability to attract and retain competent and experienced directors and allows the directors the opportunity to accumulate compensation in the form of common stock units. The Stock Unit Plan also provides directors the opportunity to convert previously earned cash retirement benefits to common stock units. All eligible directors who had benefits under the prior cash retirement plan converted their cash retirement benefits to common stock units.

        As of December 31, 2015, a total of 900,000 shares were authorized under this plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock. In connection with the Merger Agreement, we amended the Stock Unit Plan to provide that, effective upon and subject to the occurrence of the merger under the Merger Agreement, each stock unit outstanding immediately prior to the effective time of the merger will be converted into the right to receive in cash the merger consideration under the Merger Agreement, with interest at the prime rate from the effective time of the merger until the payment date under the plan. (See Note 17 for further discussion of the Merger Agreement).

        The number of units granted annually is computed by dividing an annual credit (determined by the Compensation Committee) by the fair market value of our common stock on January 1 of the year the units are granted. Common stock unit dividends are computed based on the fair market value of our stock on the dividend's record date. We record the related compensation expense at the time we make the accrual for the directors' benefits as the directors provide services. Shares accrued to directors' accounts and shares available for issuance under this plan at December 31 are shown in the table below:

	2015		2014
Shares accrued to directors' accounts		157,672		164,085
Shares available for issuance		677,980		714,978

        Units accrued for service and dividends as well as units redeemed for common stock at December 31 are shown in the table below:

	2015		2014		2013
Units accrued for service and dividends		30,595		30,765		34,252
Units redeemed for common stock		37,008		21,083		22,908

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INCOME TAXES

12 Months Ended

Dec. 31, 2015

INCOME TAXES.

INCOME TAXES

9.     INCOME TAXES

        Income tax expense components for the years ended December 31 are as follows (in thousands):

	2015			2014			2013
Current income taxes:
Federal	$	—		$	(2,350	)	$	6,726
State		—			(123	)		2,495
TOTAL		—			(2,473	)		9,221
Deferred income taxes:
Federal		29,722			36,620			24,954
State		4,233			5,216			3,554
TOTAL		33,955			41,836			28,508
Investment tax credit amortization		(143	)		(143	)		(237	)
TOTAL INCOME TAX EXPENSE	$	33,812		$	39,220		$	37,492

Deferred Income Taxes

        Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows
(in thousands):

	December 31,
Deferred Income Taxes	2015		2014
NET DEFERRED TAX LIABILITIES	$	396,542	$	358,252

        Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows (in thousands):

	December 31,
Temporary Differences	2015		2014
Deferred tax assets:
Plant related basis differences	$	27,347	$	25,349
Net operating loss (NOL)		9,055		22,000
Regulated liabilities related to income taxes		13,142		13,350
Disallowed plant costs		1,699		1,754
Gains on hedging transactions		1,195		1,260
Pensions and other post-retirement benefits		—		1,175
Carry forward of income tax credit		8,675		6,367
Other		1,550		1,633
Total deferred tax assets	$	62,663	$	72,888
Deferred tax liabilities:
Depreciation, amortization and other plant related differences	$	382,897	$	363,337
Regulated assets related to income		38,615		37,180
Loss on reacquired debt		3,572		3,828
Amortization of intangibles		10,248		9,168
Pensions and other post-retirement benefits		7,112		—
Deferred construction accounting costs		5,711		6,082
Other		11,050		11,545
Total deferred tax liabilities		459,205		431,140
NET DEFERRED TAX LIABILITIES	$	396,542	$	358,252

Effective Income Tax Rates

        The difference between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing operations were as follows:

Effective Income Tax Rates	2015			2014			2015
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit)		3.1			3.1			3.1
Investment tax credit amortization		(0.2	)		(0.1	)		(0.2	)
Effect of ratemaking on property related differences		(1.4	)		(1.7	)		(1.1	)
Other		0.9			0.6			0.3
EFFECTIVE INCOME TAX RATE		37.4	%		36.9	%		37.1	%

        We do not have any unrecognized tax benefits as of December 31, 2015. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.

        The "Protecting Americans from Tax Hikes" Act (the "Act") was signed into law on December 18, 2015. The Act restored several expired business tax provisions, including bonus depreciation for 2015. Because of the reinstatement of bonus depreciation, we anticipate making no material income tax payments in 2016.

        We generated $74.1 million of tax NOLs during 2014, mainly due to bonus depreciation. We intend to carry forward these tax NOLs, which, if unused, will expire in 2034. We estimate that we will utilize approximately $38.0 million of the 2014 tax NOLs on our 2015 return when filed. As of December 31, 2015, we estimate there is $13.5 million of deferred tax assets remaining to be utilized related to the tax NOLs. A portion of the deferred tax assets related to the tax NOLs is recorded as a receivable on the balance sheet in anticipation of income tax payment refunds.

        In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2, which, if unused, will expire in 2030. We utilized $9.0 million of these credits on our 2013 tax return. Due to the passage of the Act, we estimate we will not be able to use the remaining credits on our 2015 tax return, but expect to use them to offset future income tax liabilities. The tax credits will have no significant income statement impact because they will flow to our customers as we amortize the tax credits over the life of the plant.

        On September 13, 2013, the IRS and the Treasury Department released final regulations under Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations applied to tax years beginning on or after January 1, 2014, and we filed a Form 3115 with the IRS to change our tax accounting method to comply with the regulations. As a result, we deducted approximately $29 million on our 2014 income tax return under IRS Code Section 481(a) as an adjustment required by the change in tax accounting method.

        Our 2014 income tax return included another tax accounting method change regarding the deductibility of the Voluntary Employee Benefit Association (VEBA) plan activity. As a result, we deducted approximately $14 million as an adjustment required by the change in tax method of accounting. These changes did not have a material impact on the effective tax rate.

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COMMONLY OWNED FACILITIES

12 Months Ended

Dec. 31, 2015

COMMONLY OWNED FACILITIES

COMMONLY OWNED FACILITIES

10.   COMMONLY OWNED FACILITIES

Iatan

        We own a 12% undivided interest in the coal-fired Units No. 1 and 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 each unit's available capacity and are obligated to pay for a like percentage of the operating costs of the units. KCP&L and KCP&L Greater Missouri Operations Co. own 70% and 18% respectively, of Unit 1, and 54% and 18%, respectively, of Unit 2. KCP&L operates the units for the joint owners.

        At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions):

Iatan	2015		2014
Cost of ownership in plant in service	$	380.2	$	373.3
Accumulated Depreciation	$	105.3	$	99.1
Expenditures(1)	$	26.9	$	27.8

(1)Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.

State Line Combined Cycle Unit

        We and Westar Generating, Inc, ("WGI"), a subsidiary of Westar Energy, Inc., share joint ownership of a nominal 500-megawatt combined cycle unit at the State Line Power Plant (the "State Line Combined Cycle Unit"). We are responsible for the operation and maintenance of the State Line Combined Cycle Unit, and are entitled to 60% of the available capacity and are responsible for approximately 60% of its costs.

        At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions):

State Line Combined Cycle Unit	2015		2014
Cost of ownership in plant in service	$	163.0	$	161.5
Accumulated Depreciation	$	43.5	$	40.0
Expenditures(1)	$	40.7	$	47.1

(1)Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.

Plum Point Energy Station

        We own a 7.52% undivided interest in the coal-fired Plum Point Energy Station located near Osceola, Arkansas. We are entitled to 7.52% of the station's capacity, and are obligated to pay for a like percentage of the station's operating costs.

        At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions):

Plum Point Energy Station	2015		2014
Cost of ownership in plant in service	$	109.1	$	108.3
Accumulated Depreciation	$	11.9	$	9.4
Expenditures(1)	$	9.6	$	8.1

(1)Recognized in operating, maintenance and fuel expenditures excluding depreciation expense.

        All of the dollar amounts listed above represent our ownership share of costs.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2015

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

11.   COMMITMENTS AND CONTINGENCIES

        We are a party to various claims and legal proceedings arising out of the normal course of our business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company's defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.

Coal, Natural Gas and Transportation Contracts

        The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of December 31, 2015 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
January 1, 2016 through December 31, 2016	$	26.7	$	18.0
January 1, 2017 through December 31, 2018		37.4		27.5
January 1, 2019 through December 31, 2020		28.8		10.8
January 1, 2021 and beyond		45.7		—

        We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be placed in storage. The firm physical gas and transportation commitments are detailed in the table above.

        We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of December 31, 2015 are detailed in the table above.

Purchased Power

        We currently supplement our on-system (native load) generating capacity with purchases of capacity and energy from other entities 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 (NERC) rules.

        The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit's capacity. We also have a long-term agreement for the purchase of an additional 50 megawatts of capacity from Plum Point. Commitments under this agreement are approximately $277.6 million through August 31, 2039, the end date of the agreement. 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 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 do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.

        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 the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost.

        Payments for these agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations shown below.

New Construction

        We have in place a contract with a third party vendor to complete engineering, procurement, and construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion includes the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. The Air Emission Source Construction Permit necessary for this project was issued by Kansas Department of Health and Environment on July 11, 2013. This conversion is currently scheduled to be completed in early to mid-2016 at a cost estimated to range from $165 million to $175 million, excluding allowance for funds used during construction (AFUDC). Construction costs, consisting of pre-engineering, site preparation activities and contract costs incurred project to date through December 31, 2015 were $159.6 million, excluding AFUDC.

        In December 2014 we completed an environmental retrofit at our Asbury plant. The retrofit project included the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This new equipment enables us to comply with the Mercury and Air Toxics Standard (MATS). Final costs were approximately $112.1 million, excluding AFUDC.

Leases

        We have purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these agreements are disclosed in the Purchased Power section of this note.

        We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.

        The gross amount of assets recorded under capital leases total $5.3 million at December 31, 2015.

        Our lease obligations over the next five years are as follows (in thousands):

	Capital Leases		Operating Leases
2016	$	554	$	734
2017		551		689
2018		551		648
2019		550		484
2020		546		—
Thereafter		2,460		—
Total minimum payments		5,212	$	2,555
Less amount representing interest		1,322
Present value of net minimum lease payments	$	3,890

        Expenses incurred related to operating leases were $0.8 million, $0.8 million and $0.8 million for 2015, 2014, and 2013, respectively, excluding payments for wind generated purchased power agreements. The accumulated amount of amortization for our capital leases was $1.9 million and $1.5 million at December 31, 2015 and 2014, respectively.

Environmental Matters

        We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and hazardous and other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. We believe that our operations are in material compliance with present environmental laws and regulations. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect these costs to be material, although recoverable in rates.

Compliance Plan

        In order to comply with current and forthcoming environmental regulations, we continue to implement our compliance plan and strategy (Compliance Plan), which largely follows our Integrated Resource Plan (IRP) filed with MPSC in mid-2013. The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), are the drivers behind our Compliance Plan and its implementation schedule. We anticipate compliance costs associated with the MATS, CAIR and CSAPR regulations to continue to be recoverable in our rates.

        The following list summarizes the most significant environmental regulations affecting our operations:

Regulations

Air Emissions — NOx and SO2

CAIR (Clean Air Interstate Rule)

CSAPR (Cross State Air Pollution Rule)

MATS (Mercury Air Toxic Standards)

NAAQS (National Ambient Air Quality Standards)

Greenhouse Gases (GHGs) — CO₂

Surface Impoundments

Coal Ash Impoundments:

Asbury Power Plant

Riverton (capped and closed in 2014 as industrial (coal combustion waste) landfill)

Water Discharges

MATS:    In June 2015, the U.S. Supreme Court remanded the MATS back to the D.C. Circuit Court, holding that the EPA must consider cost (including cost of compliance) before deciding whether a regulation is appropriate and necessary. The court noted that it will be up to the EPA to decide within the limits of reasonable interpretation how to account for cost. MATS remains in effect until the D.C. Circuit Court acts.

Greenhouse Gases:    On August 3, 2015, the EPA released the final rule for limiting carbon emissions from existing power plants. The "Clean Power Plan" (CPP) requires a 32% carbon emission reduction from 2005 baseline levels by 2030 and requires fossil fuel-fired power plants across the nation, including those in Empire's fleet, to meet state-specific goals to lower carbon levels. States will choose between two plan types to meet their goals: an emission standards plan which includes source-specific requirements impacting affected power plants or a state measures plan which includes a mixture of measures implemented by the state.

        By September 6, 2016, each state must either submit to the EPA its initial plan with a request for an extension or a final plan. If the state receives an extension, the final plan must be submitted by September 6, 2018. States will then implement plans to achieve the progressive CO2 emissions performance rates over the period of 2022 to 2029 with the final CO2 goal accountability by 2030. Empire continues to evaluate potential paths forward on the final rule released by the EPA. As of January 26, 2016, twenty-five states have initiated legal challenges to the CPP which by and large seek to invalidate the rule. The ultimate cost of compliance cannot be determined at this time because of the uncertainties regarding the final outcome of the GHG regulations, including the legal challenges thereto, and the compliance methods yet to be chosen by the jurisdictions in which we operate. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates.

Surface Impoundments:    On September 30, 2015, the EPA finalized a revision of the Clean Water Act (CWA) Steam Electric Effluent Limitation Guidelines (ELGs) for coal-fired power plants. The new rule sets technology-based ELGs based on the nature of the pollutants being discharged and the facilities involved. As published, beginning in November 2018, the EPA and states would incorporate the new standards into all wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs at each facility that will result from the new standards to be in effect no later than December 2023.

        Effective October 19, 2015, the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs) as a non-hazardous solid waste under subtitle D of the Resource Conservation and Recovery Act (RCRA). We expect compliance with both the CCR and ELG rule to result in the need to construct a new landfill and the conversion of existing bottom ash handling from a wet to a dry system at a potential cost of up to $15 million at our Asbury Power Plant. We expect resulting costs to be recoverable in our rates. Final closure of the existing ash impoundment, for which an asset retirement obligation of $5.4 million has been recorded, is anticipated after the new landfill is operational. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station.

        We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. A technical review of our Detailed Site Investigation (DSI) for the specific site has been completed and was approved by the Missouri Department of Natural Resources on June 29, 2015. Receipt of the final construction permit for the CCR waste landfill is expected in January 2017.

Water Discharges:    We operate under the Kansas and Missouri Water Pollution Plans pursuant to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received all necessary discharge permits.

        The EPA final rule under the CWA Section 316(b) for existing cooling water intake structures became effective on October 14, 2014. An industry coalition has filed an appeal of the rule in the Fifth Circuit and additional court challenges are expected. We expect the regulations to have no future impact at Riverton as the new intake structure design and installed cooling tower, as part of the Unit 12 conversion, meets the regulatory requirement for aquatic life protections. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Iatan Unit 2 and Plum Point Unit 1 are covered by the regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally affected by the final rule.

Renewable Energy

        On November 4, 2008 Missouri voters approved the Clean Energy Initiative (Proposition C) which currently requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC. Proposition C also requires that 2% of the energy from renewable energy sources must be solar; however, we believed that we were exempted by statute from the solar requirement. On January 20, 2013 the Earth Island Institute, d/b/a Renew Missouri, and others challenged our solar exemption by filing a complaint with the MPSC. The MPSC dismissed the complaint and Renew Missouri filed a notice of appeal seeking review by the Missouri Supreme Court. On February 10, 2015 the Missouri Supreme Court issued an opinion holding that the legislature had the authority to adopt the statute providing the exemption but reversed the MPSC's holding that the two laws could be harmonized. The statute providing the exemption (which was enacted in August 2008) was impliedly repealed by the adoption of Proposition C because it conflicted with the latter law. 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. As of December 31, 2015, we had processed 262 solar rebate applications resulting in solar rebate-related costs totaling approximately $3.5 million under the new tariff. We have recorded the $3.5 million as a regulatory asset (See Note 3 — Regulatory Matters). The law provides a number of methods that may be utilized to recover the associated expenses. We expect any costs to be recoverable in rates.

        Legislation was recently adopted that altered the Kansas renewable portfolio standard (RPS), ending all mandatory requirements in 2015. The mandate, which required 20% of our Kansas retail customer peak capacity requirements to be sourced from renewables by 2020, has been changed to a voluntary goal. We are currently in compliance as a result of purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC.

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SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2015

SEGMENT INFORMATION

SEGMENT INFORMATION

12.   SEGMENT INFORMATION

        We operate our business as three segments: electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company is our wholly owned subsidiary formed to provide gas distribution service in Missouri. The other segment consists of our non-regulated businesses which is primarily our fiber optics business.

        The tables below present statement of income information, balance sheet information and capital expenditures of our business segments.

	For the year ended December 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
Operating Revenues(1)	$	555,085	$	41,702	$	10,165	$	(1,379	)	$	605,573
Depreciation and amortization		74,732		3,923		1,895		—			80,550
Federal and state income taxes		31,123		800		1,889		—			33,812
Operating income		88,124		5,153		3,024		—			96,301
Interest income		133		36		47		(71	)		145
Interest expense		41,307		3,867		—		(71	)		45,103
Income from AFUDC (debt and equity)		7,681		14		—		—			7,695
Income from continuing operations	$	52,240	$	1,287	$	3,070	$	—		$	56,597
Capital Expenditures	$	169,111	$	5,190	$	2,223	$	—		$	176,524

(1)The Electric Segment includes SPP Integrated Marketplace net revenues of $15.0 million.

	2014
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
Operating Revenues(1)	$	592,491	$	51,842	$	9,302	$	(1,305	)	$	652,330
Depreciation and amortization		67,534		3,760		1,891		—			73,185
Federal and state income taxes		35,737		1,840		1,643		—			39,220
Operating income		90,488		6,775		2,736		—			99,999
Interest income		37		25		21		(32	)		51
Interest expense		37,911		3,861		—		(32	)		41,740
Income from AFUDC (debt and equity)		9,833		84		—		—			9,917
Income from continuing operations	$	61,467	$	2,965	$	2,671	$	—		$	67,103
Capital Expenditures	$	212,866	$	7,836	$	2,151	$	—		$	222,853

(1)The Electric Segment includes SPP Integrated Marketplace net revenues of $41.9 million.

	2013
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
Operating Revenues	$	536,413	$	50,041	$	9,147	$	(1,271	)	$	594,330
Depreciation and amortization		63,659		3,709		1,938		—			69,306
Federal and state income taxes		34,478		1,484		1,530		—			37,492
Operating income		90,984		6,194		2,485		—			99,663
Interest income		537		115		8		(94	)		566
Interest expense		37,683		3,890		—		(94	)		41,479
Income from AFUDC (debt and equity)		5,910		30		—		—			5,940
Income from continuing operations	$	58,603	$	2,355	$	2,487	$	—		$	63,445
Capital Expenditures	$	153,401	$	4,419	$	2,388	$	—		$	160,208

	December 31, 2015
	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information:
Total assets	$	2,339,850	$	127,871	$	38,300	$	(50,718	)	$	2,455,303

	December 31, 2014
	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information:
Total assets	$	2,252,339	$	130,856	$	34,655	$	(46,794	)	$	2,371,056

(1)Includes goodwill of $39,492 at December 31, 2015 and 2014.

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SELECTED QUARTERLY INFORMATION (UNAUDITED)

12 Months Ended

Dec. 31, 2015

SELECTED QUARTERLY INFORMATION (UNAUDITED)

SELECTED QUARTERLY INFORMATION (UNAUDITED)

13.   SELECTED QUARTERLY INFORMATION (UNAUDITED)

        The following is a summary of quarterly results for 2015 and 2014 (dollars in thousands except per share amounts):

	Quarters
Quarterly Results for 2015	First		Second		Third		Fourth
Operating revenues(1)	$	164,544	$	134,557	$	169,714	$	136,758
Operating income	$	24,713	$	16,047	$	35,783	$	19,757
Net Income	$	14,637	$	6,770	$	25,285	$	9,905
Basic Earnings Per Share	$	0.34	$	0.16	$	0.58	$	0.23
Diluted Earnings Per Share	$	0.34	$	0.15	$	0.58	$	0.23

(1)Operating revenue for the first, second, third and fourth quarters of 2015 include SPP IM net revenues of $4.7 million, $3.4 million, $4.0 million, and $2.9 million, respectively.

	Quarters
Quarterly Results for 2014	First		Second		Third		Fourth
Operating revenues(1)	$	179,673	$	149,782	$	171,512	$	151,363
Operating income	$	29,488	$	19,502	$	31,709	$	19,300
Net Income	$	20,905	$	11,194	$	23,892	$	11,112
Basic and Diluted Earnings Per Share	$	0.48	$	0.26	$	0.55	$	0.26

(1)Operating revenue for the first, second, third and fourth quarters of 2014 include SPP IM net revenues of $6.2 million, $16.5 million, $11.5 million, and $7.5 million, respectively.

        The sum of the net income and quarterly earnings per share of common stock may not equal the net income and earnings per share of common stock as computed on an annual basis due to rounding.

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RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2015

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

14.   RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

        We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain cost predictability.

        We began acquiring Transmission Congestion Rights (TCR) in 2013 in an effort to mitigate the cost of power we purchase from the SPP IM due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

        All derivative instruments are recognized at fair value on the balance sheet. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms.

        Risks and uncertainties affecting the determination of fair value include: market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instruments in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income and subject to our fuel adjustment mechanism.

        As of December 31, 2015 and 2014, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of December 31, (in thousands):

ASSET DERIVATIVES

Non-designated hedging instruments due to regulatory accounting		2015		2014
	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	2	$	—
	Non-current assets and deferred charges — Other		16		—
Natural gas contracts, electric segment	Current assets		—		1
	Non-current assets and deferred charges — Other		—		—
Transmission congestion rights, electric segment	Current assets		1,293		3,900
Total derivatives assets		$	1,311	$	3,901

LIABILITY DERIVATIVES

Non-designated as hedging instruments due to regulatory accounting		2015		2014
	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	282	$	476
	Non-current liabilities and deferred credits		66		—
Natural gas contracts, electric segment	Current liabilities		4,190		5,993
	Non-current liabilities and deferred credits		3,630		3,243
Transmission congestion rights, electric segment	Current liabilities		—		—
Total derivatives liabilities		$	8,168	$	9,712

Electric

        At December 31, 2015, approximately $4.2 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months.

        There were no "mark-to-market" pre-tax gains/ (losses) from ineffective portions of our hedging activities for the electric segment for the years ended December 31, 2015 and 2014, respectively.

        The following tables set forth "mark-to-market" pre-tax gains/ (losses) from non-designated derivative instruments for the electric segment for each of the years ended December 31 (in thousands):

Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment

		Amount of Gain/(Loss) Recognized on Balance Sheet
	Balance Sheet Classification of Gain/(Loss) on Derivative	2015			2014
Commodity contracts — electric segment	Regulatory (assets)/liabilities	$	(6,853	)	$	(6,780	)
Transmission congestion rights — electric segment	Regulatory (assets)/liabilities		4,970			12,958
Total — Electric Segment		$	(1,883	)	$	6,178

Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment

		Amount of Gain/(Loss) Recognized in Income on Derivative
	Statement of Operations Classification of Loss on Derivative	2015			2014
Commodity contracts	Fuel and purchased power expense	$	(8,115	)	$	(1,659	)
Transmission congestion rights — electric segment	Fuel and purchased power expense		7,468			11,106
Total — Electric Segment		$	(647	)	$	9,447

        We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to fair value accounting because they qualify for the normal purchase normal sale exemption. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchase normal sale exception contain a price adjustment feature and will account for these contracts accordingly.

        At December 31, 2015, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for 2016 and the next four years are hedged at the following average prices per Dekatherm (Dth):

Year	% Hedged			Dth Hedged Physical		Dth Hedged Financial		Average Price
2016		61	%		2,706,000		5,940,000	$	3.372
2017		41	%		782,900		5,210,000	$	3.347
2018		20	%		565,000		2,460,000	$	3.334
2019		10	%		—		1,460,000	$	2.955
2020		0	%		—		—		—

        We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year's and 80% of any future year's expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.

Year	End of Year Minimum % Hedged
Current	Up to 100%
First	60%
Second	40%
Third	20%
Fourth	10%

        At December 31, 2015, the following transmission congestion rights (TCR) have been obtained from TCR auctions to hedge congestion costs in the SPP Integrated Marketplace:

Year	Monthly MWH Hedged		$ Value
2016		3,212	$	1,292,943

Gas

        We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of December 31, 2015 we had 1.4 million Dths in storage on the three pipelines that serve our customers. This represents 70% of our storage capacity.

        The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the ACA year at September 1 and illustrates our hedged position as of December 31, 2015 (Dth in thousands).

Season	Minimum % Hedged			Dth Hedged Financial		Dth Hedged Physical		Dth in Storage		Actual % Hedged
Current		50	%		400,000		—		1,419,752		93	%
Second		Up to 50	%		200,000		—		—		6	%
Third		Up to 20	%		280,000		—		—		9	%

        A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

        The following table sets forth "mark-to-market" pre-tax gains/ (losses) from derivatives not designated as hedging instruments for the gas segment for the years ended December 31 (in thousands):

Non-Designated Hedging Instruments Due to Regulatory Accounting — Gas Segment

		Amount of Loss Recognized on Balance Sheet
	Balance Sheet Classification of Loss on Derivative	2015			2014
Commodity contracts	Regulatory assets	$	(447	)	$	(511	)
						—
Total — Gas Segment		$	(447	)	$	(511	)

Contingent Features

        Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. We had no derivative instruments with the credit-risk-related contingent features in a net liability position on December 31, 2015 and have posted no collateral in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at the dates shown. There were no margin deposit liabilities at these dates.

(in millions)	December 31, 2015		December 31, 2014
Margin deposit assets	$	11.2	$	9.1

Offsetting of derivative assets and liabilities

        We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Collateral requirements are calculated at the master trading and netting agreement level by the counterparty.

        As shown above, our asset and liability commodity contract derivatives are reported at gross on the balance sheet. ASC guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. For the years ended December 31, 2015 and December 31, 2014, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2015

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

15.   FAIR VALUE MEASUREMENTS

        The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data.

        The guidance also requires that the fair value measurement of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.

        Our TCR positions, which are acquired on the SPP Integrated Marketplace, are valued using the most recent monthly auction clearing prices. Our commodity contracts are valued using the market value approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of December 31:

Fair Value Measurements at Reporting Date Using

($ in 000's) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2015
Derivative assets	$	1,311		$	18		$	1,293	$	—
Derivative liabilities	$	(8,168	)	$	(8,168	)	$	—	$	—
December 31, 2014
Derivative assets	$	3,901		$	1		$	3,900	$	—
Derivative liabilities	$	(9,712	)	$	(9,712	)	$	—	$	—

*The only recurring measurements are derivative related.

Other fair value considerations

        Our cash and cash equivalents approximate fair value because of the short-term nature of these instruments, and are classified as Level 1 in the fair value hierarchy. The carrying amount of our short-term debt, which is composed of Empire issued commercial paper or revolving credit borrowings, also approximates fair value because of their short-term nature. These instruments are classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions.

        The carrying amount of our total long-term debt exclusive of capital leases at December 31, 2015 and 2014 was $859 million and $799 million, compared to a fair market value of approximately $815 million and $829 million, respectively. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of December 31, 2015 or that will be realizable in the future.

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REGULATED OPERATING EXPENSE

12 Months Ended

Dec. 31, 2015

REGULATED OPERATING EXPENSE

REGULATED OPERATING EXPENSE

16.   REGULATED OPERATING EXPENSE

        The following table sets forth the major components comprising "regulated operating expenses" under "Operating Revenue Deductions" on our consolidated statements of income for the years ended (in thousands):

	December 31,
	2015		2014		2013
Power operation expense (other than fuel)	$	18,263	$	16,089	$	15,643
Electric transmission and distribution expense		28,893		27,919		21,863
Natural gas transmission and distribution expense		2,699		2,362		2,498
Customer accounts & assistance expense		10,937		11,239		11,180
Employee pension expense(1)		10,786		10,590		10,736
Employee healthcare plan(1)		10,162		9,147		10,190
General office supplies and expense		14,438		15,024		12,850
Administrative and general expense		14,863		14,385		14,800
Bad debt expense		2,080		3,420		3,665
Regulatory reversal of gain on sale of assets		—		44		1,236
Miscellaneous expense		430		472		672
TOTAL	$	113,551	$	110,691	$	105,333

(1)Does not include the capitalized portion of actuarially calculated costs, but reflects the GAAP expensed portion of these costs plus or minus costs deferred to a regulatory asset or recognized as a regulatory liability for Missouri and Kansas jurisdictions.

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SUBSEQUENT EVENT - AGREEMENT AND PLAN OF MERGER

12 Months Ended

Dec. 31, 2015

SUBSEQUENT EVENT - AGREEMENT AND PLAN OF MERGER

SUBSEQUENT EVENT - AGREEMENT AND PLAN OF MERGER

17.   SUBSEQUENT EVENT — AGREEMENT AND PLAN OF MERGER

        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), 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.

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SCHEDULE II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2015

SCHEDULE II - Valuation and Qualifying Accounts

SCHEDULE II - Valuation and Qualifying Accounts

SCHEDULE II

Valuation and Qualifying Accounts

Years ended December 31, 2015, 2014 and 2013:

			Additions Charged to Other Accounts					Deductions From Reserve
	Balance At Beginning Of Period		Charged To Income		Description	Amount		Description	Amount		Balance At Close of Period
Year ended December 31, 2015:
Reserve deducted from assets: accumulated provision for uncollectible accounts.	$	1,020,637	$	2,266,976	Recovery of amounts previously written off	$	2,079,751	Accounts written off	$	4,744,648	$	622,716
Year ended December 31, 2014:
Reserve deducted from assets: accumulated provision for uncollectible accounts.	$	1,025,177	$	3,463,797	Recovery of amounts previously written off	$	2,128,325	Accounts written off	$	5,596,662	$	1,020,637
Year ended December 31, 2013:
Reserve deducted from assets: accumulated provision for uncollectible accounts.	$	1,387,673	$	2,213,988	Recovery of amounts previously written off	$	2,013,959	Accounts written off	$	4,590,443	$	1,025,177

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2015

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Basis of Presentation

        The consolidated financial statements include the accounts of EDE, EDG, and our other subsidiaries. The consolidated entity is referred to throughout as "we" or the "Company". All intercompany balances and transactions have been eliminated in consolidation. See Note 12 for additional information regarding our three segments. Certain immaterial reclassifications have been made to prior year information to conform to the current year presentation.

Use of Estimates

Use of Estimates

        The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include unbilled utility revenues, collectability of accounts receivable, depreciable lives, asset impairment and goodwill impairment evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation, and tax provisions. Actual amounts could differ from those estimates.

Accounting for the Effects of Regulation

Accounting for the Effects of Regulation

        In accordance with the Accounting Standard Codification (ASC) guidance for regulated operations, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the APSC and the FERC).

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

        Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory assets and liabilities are ratably amortized through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues. We generally include amortization of regulatory assets and liabilities in the depreciation and amortization line of our statement of cash flows. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC guidance for regulated operations with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of this guidance based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations. (See Note 3 for further discussion of regulatory assets and liabilities)

Revenue Recognition

Revenue Recognition

        For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer classes.

Municipal Franchise Taxes

Municipal Franchise Taxes

        Municipal franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other taxes in the Consolidated Statements of Income. Municipal franchise taxes of $11.4 million, $11.8 million and $11.2 million were recorded for each of the years ended December 31, 2015, 2014 and 2013, respectively.

Accounts Receivable

Accounts Receivable

        Accounts receivable are recorded at the tariffed rates for customer usage, including applicable taxes and fees and do not bear interest. We review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered.

Property, Plant & Equipment

Property, Plant & Equipment

        The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material, an allocation of general and administrative costs, and an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of and the costs of removal are charged to accumulated depreciation, unless the removed property constitutes an operating unit or system. In this case a gain or loss is recognized upon the disposal of the asset. Maintenance expenditures and the removal of minor property items are charged to income as incurred. A liability is created for any additions to electric or gas utility property that are paid for by advances from developers. For a period of five years we refund to the developer a pro rata amount of the original cost of the extension for each new customer added to the extension. Nonrefundable payments at the end of the five year period are applied as a reduction to the cost of the plant in service. The liability as of December 31, 2015 and 2014 was $2.1 million and $1.9 million, respectively.

Depreciation

Depreciation

        Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by regulatory authorities. These rates are applied to the various classes of utility assets on a composite basis. Provisions for depreciation for our other segment are computed at straight-line rates over the estimated useful life of the properties (See Note 2 for additional details regarding depreciation rates).

        As of December 31, 2015 and 2014, we had recorded accrued cost of removal of $85.4 million and $82.8 million, respectively, for our electric operating segment. This represents an estimated cost of dismantling and removing plant from service upon retirement, accrued as part of our depreciation rates. We accrue cost of removal in depreciation rates for mass property (including transmission, distribution and general plant assets). These accruals are not considered an asset retirement obligation under the guidance provided on asset retirement obligations within the ASC. We reclassify the accrued cost of dismantling and removing plant from service upon retirement from accumulated depreciation to a regulatory liability. We have a similar cost of removal regulatory liability for our gas operating segment. This amount at December 31, 2015 and 2014 was $8.8 million and $7.7 million, respectively. These amounts are net of our actual cost of removal expenditures.

Asset Retirement Obligation

Asset Retirement Obligation

        We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.

        We have identified asset retirement obligations associated with the future removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We also have a solid waste land fill at the Plum Point Energy Station, and asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. As a result of the fuel use transition from coal to natural gas at the Riverton Power Plant, the closure of the Riverton ash landfill was completed, and the related asset retirement obligation was settled during 2014 (Note 11). During 2015 the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs). As a result of these new rules, an asset retirement obligation of $5.4 million has been recorded for the final closure of the existing ash impoundment at our Asbury Power Plant. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station.

        In addition, we have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB) contaminants associated with our transformers and substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures for the removal of similar past liabilities. The potential costs of these future expenditures are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. This liability will be accreted over the period up to the estimated settlement date.

        All of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 4.5% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. During 2014 the liability for asbestos at the Riverton Power Plant was re-evaluated. Changes in the cost estimates and timing resulted in cash flow revisions for these liabilities.

        The balances at the end of 2015 and 2014 are shown below.

(000's)	Liability Balance 12/31/14		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/15
Asset Retirement Obligation	$	4,847	$	9,812	$	(73	)	$	486	$	—	$	15,072

(000's)	Liability Balance 12/31/13		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/14
Asset Retirement Obligation	$	4,190	$	—	$	(1,175	)	$	172	$	1,660	$	4,847

        Upon adoption of the standards on the retirement of long lived assets and conditional asset retirement obligations, we recorded a liability and regulatory asset because we expect to recover these costs of removal in electric and gas rates either through depreciation accruals or direct expenses. We also defer the liability accretion and depreciation expense as a regulatory asset. At December 31, 2015 and 2014, our regulatory assets relating to asset retirement obligations totaled $7.7 million and $5.1 million, respectively.

        Also as noted previously under property, plant and equipment, we reclassify the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset retirement obligation under this guidance, from accumulated depreciation to a regulatory liability. This balance sheet reclassification has no impact on results of operations.

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction

        As provided in the FERC regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction (AFUDC) when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds applicable to construction programs are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.

        AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation.

        In accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 5.5% for 2015, 6.6% for 2014, and 7.3% for 2013, compounded semiannually.

Asset Impairments (excluding goodwill)

Asset Impairments (excluding goodwill)

        We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on undiscounted forecasted cash flows to assess the recoverability of the assets and, if necessary, the fair value is determined to measure the impairment amount. None of our assets were impaired as of December 31, 2015 and 2014.

Goodwill

Goodwill

        As of December 31, 2015, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and income approaches is used to estimate the fair value of goodwill.

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

        We also utilize a valuation technique under the income approach which estimates the discounted future cash flows of operations. Our procedures include developing a baseline test and performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering those assumptions which are subjective in nature and inherent to a discounted cash flows calculation. Other qualitative factors and comparisons to industry peers are also used to further support the assumptions and ultimately the overall evaluation. A key qualitative assumption considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for the gas reporting unit. Some of the key quantitative assumptions included in our tests involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. If negative changes occurred to one or more key assumptions, an impairment charge could result. With the exception of the capital spending rate, the key assumptions noted are significantly determined by market factors and significant changes in market factors that impact the gas reporting unit would somewhat be mitigated by our current and future regulatory rate design. Other risks and uncertainties affecting these assumptions include: changes in business, industry, laws, technology and economic conditions. Actual results for the gas reporting unit indicate a slight decline in gas customer count and demand. A continued decline in customer count or demand coupled with an increase in the discount rate would have adverse impacts on the valuation and could result in an impairment charge in the future. Our forecasts anticipate relatively flat customer counts over the next several years.

        We weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of October 2015 indicated the estimated fair market value of the gas reporting unit to be $18 – $22 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future.

Fuel and Purchased Power

Fuel and Purchased Power

Electric Segment

        Fuel and purchased power costs are recorded at the time the fuel is used, or the power purchased. SPP Integrated Marketplace purchased power is also included in fuel and purchased power costs. The net effects of our SPP IM activity, including SPP IM net revenue and net purchased power costs, flow through our fuel recovery mechanisms in each state.

        In our Missouri jurisdiction, the MPSC establishes a base cost for the recovery of fuel and purchased power expenses used to supply energy for our fuel adjustment clause (FAC). Beginning with our 2015 rate order, certain transmission costs are also included in the base cost. The FAC permits the distribution to customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, nearly the entire off-system sales margin flows back to the customer. Rates related to the fuel adjustment clause are modified twice a year subject to the review and approval by the MPSC. In accordance with the ASC guidance for regulated operations, 95% of the difference between the actual costs of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered from or refunded to our customers when the fuel adjustment clause is modified.

        In our Kansas jurisdiction, the costs of fuel are recovered from customers through a fuel adjustment clause, based upon estimated fuel costs and purchased power. The adjustments are subject to audit and final determination by regulators. The difference between the costs of fuel used and the cost of fuel recovered from our Kansas customers is recorded as a regulatory asset or a regulatory liability if the actual costs are higher or lower than the costs billed to customers, in accordance with the ASC guidance for regulated operations.

        Similar fuel recovery mechanisms are in place for our Oklahoma, Arkansas and FERC jurisdictions.

        At December 31, 2015 and 2014, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net over-recovered position by $5.9 million and a net under-recovered position of $3.1 million, respectively, which are reflected in our regulatory assets and liabilities.

        We receive the renewable attributes associated with the power purchased through our purchased power agreements with Elk River Windfarm LLC and Cloud County Windfarm, LLC. These renewable attributes are converted into renewable energy credits (REC), which are considered inventory, and recorded at zero cost (See Note 11). Revenue from the sale of RECs reduces fuel and purchased power expense.

        We have a Stipulation and Agreement with the MPSC granting us authority to manage our emissions allowance inventory in accordance with our Plan for Purchasing and Selling Emissions Allowances (PPSEMA). The PPSEMA allows us to purchase allowances needed for compliance, exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell allowances outright for monetary value. For compliance year 2015 we did not exchange or sell any allowances, and for compliance year 2014 we purchased 69 NOx annual allowances for compliance. We classify our allowances as inventory and they are recorded at cost, with allocated allowances being recorded at zero cost. The allowances are removed from inventory on a FIFO basis, and used allowances are considered to be a part of fuel expense (See Note 11). We had the following emissions allowances in inventory at December 31, 2015 and 2014:

Emission Allowances in Inventory	2015		2014
Acid Rain SO2		11,443		872
CSAPR SO2		5,861		—
CSAPR NOx (annual)		500		—
CSAPR NOx (seasonal)		241		—

Gas Segment

        Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery allowed in rates. A Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and related carrying costs associated with the Company's use of natural gas financial instruments to hedge the purchase price of natural gas. 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.

        We calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC. Elements considered part of the PGA factor include cost of gas supply, storage costs, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.

        Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and carrying costs associated with the use of financial instruments) are reflected as a regulatory asset or liability. The balance is amortized as amounts are reflected in customer billings.

Derivatives

Derivatives

        We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel in our electric business or sold in our natural gas business, on the spot market and to manage certain interest rate exposure. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we purchase from the SPP Integrated Marketplace (see Note 14).

Electric Segment

        Pursuant to the ASC guidance on accounting for derivative instruments and hedging activities, derivatives are required to be recognized on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability ("cash-flow" hedge); or (2) an instrument that is held for non-hedging purposes (a "non-hedging" instrument). We record the mark-to-market gains or losses on derivatives used to hedge our fuel and congestion costs as regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

        We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts, if they meet the definition of a derivative, are not subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions. If these transactions don't qualify for NPNS treatment, they would be marked to market for each reporting period through regulatory assets or liabilities.

Gas Segment

        Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because we have a commission approved natural gas cost recovery mechanism (PGA), we record the mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/liability account. The regulatory asset/liability account tracks the difference between revenues billed to customers for natural gas costs and actual natural gas expense which is trued up at the end of August each year and included in the Actual Cost Adjustment (ACA) factor to be billed to customers during the next year. This is consistent with the ASC guidance on regulated operations, in that we will be recovering our costs after the annual true up period (subject to a prudency review by the MPSC).

        Cash flows from hedges for both electric and gas segments are classified within cash flows from operations.

Pension and Other Postretirement Benefits

Pension and Other Postretirement Benefits

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

Pensions

        We have rate orders with Missouri, Kansas and Oklahoma that allow us to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate orders, we prospectively calculate the value of plan assets using a market-related value method as allowed by the ASC guidance on pension benefits. As a result, we are allowed to record the Missouri, Kansas and Oklahoma portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively. The MPSC has allowed us to adopt this pension cost recovery methodology for EDG as well.

Other Postretirement Benefits (OPEB)

        We have regulatory treatment for our OPEB costs similar to the treatment described above for pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into actuarial expense over ten years and the recognition of regulatory assets and liabilities as described above.

        Additional guidance in the ASC on employers' accounting for defined benefit pension and other postretirement plans requires an employer to recognize the over funded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The guidance also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. Pension and other postretirement employee benefits tracking mechanisms are utilized to allow for future rate recovery of these obligations. We record these as regulatory assets on the balance sheet rather than as reductions of equity through comprehensive income (See Note 7).

Unamortized Debt Discount, Premium and Expense

Unamortized Debt Discount, Premium and Expense

        Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices.

Liability Insurance

Liability Insurance

        We are primarily self-insured for workers' compensation claims, general liabilities, benefits paid under employee healthcare programs and long-term disability benefits. Accruals are primarily based on the estimated undiscounted cost of claims. We self-insure up to certain limits that vary by segment and type of risk. Periodically, we evaluate the level of insurance coverage over the self-insured limits and adjust insurance levels based on risk tolerance and premium expense. We carry excess liability insurance for workers' compensation and public liability claims for our electric segment. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. Our gas segment is covered by excess liability insurance for public liability claims, and workers' compensation claims are covered by a guaranteed cost policy (See Note 11).

Other Noncurrent Liabilities

Other Noncurrent Liabilities

        Other noncurrent liabilities are comprised of accruals and other accounting estimates not sufficiently large enough to merit individual disclosure. At December 31, 2015, the balance of other noncurrent liabilities is primarily comprised of accruals for self-insurance, customer advances for construction and asset retirement obligations.

Cash & Cash Equivalents

Cash & Cash Equivalents

        Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities and were $23.2 million and $28.3 million at December 31, 2015 and 2014, respectively.

Restricted Cash

Restricted Cash

        As part of our Plum Point ownership agreement, we are required to have funds available in an escrow account which guarantees payment of certain operating costs. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts restricted, which were $1.8 million at December 31, 2015 and 2014, may increase or decrease based on an annual review.

        We are required to post cash collateral with Southwest Power Pool (SPP) to participate in Transmission Congestion Rights (TCR) auctions. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $2.5 million at December 31, 2015 and 2014.

        Due to our Plum Point energy station interconnection with Midcontinent Independent System Operator (MISO), we participate in Financial Transmission Rights (FTR) auctions which require us to post cash collateral. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $0.5 million at December 31, 2015 and 2014.

Fuel, Materials and Supplies

Fuel, Materials and Supplies

        Fuel, materials and supplies consist primarily of coal, natural gas in storage and materials and supplies, which are reported at average cost. These balances are as follows (in thousands):

	2015		2014
Electric fuel inventory	$	30,185	$	26,454
Natural gas inventory		3,868		5,040
Materials and supplies		26,897		26,305
TOTAL	$	60,950	$	57,799

Income Taxes

Income Taxes

        Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes; measured using statutory tax rates (See Note 9).

        Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. The longest remaining amortization period for investment tax credits is approximately 55 years.

Accounting for Uncertainty in Income Taxes

Accounting for Uncertainty in Income Taxes

        In 2006, the FASB issued guidance which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with the ASC guidance on accounting for income taxes. We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2010. At December 31, 2015 and 2014, our balance sheet did not include any unrecognized tax benefits. We do not expect any material changes to unrecognized tax benefits within the next twelve months. We recognize interest and penalties, if any, related to unrecognized tax benefits in other expenses.

Computations of Earnings Per Share

Computations of Earnings Per Share

        The ASC guidance on earnings per share requires dual presentation of basic and diluted earnings per share. Basic earnings per share does not include potentially dilutive securities and is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share assumes the issuance of common shares pursuant to the Company's stock-based compensation plans at the beginning of each respective period, or at the date of grant or award if later. Shares attributable to stock options are excluded from the calculation of diluted earnings per share if the effect would be antidilutive.

	2015		2014		2013
Weighted Average Number Of Shares
Basic		43,670,908		43,291,031		42,781,382
Dilutive Securities:
Performance-based restricted stock awards		19,890		8,809		12,142
Employee stock purchase plan		1,249		3,422		1,729
Stock options		—		—		61
Time-based restricted stock awards		25,523		10,666		7,907
Total dilutive securities		46,662		22,897		21,839
Diluted weighted average number of shares		43,717,570		43,313,928		42,803,221
Antidilutive Shares		20,289		25,259		107,100

        Potentially dilutive shares are not expected to have a material impact unless significant appreciation of the Company's stock price occurs.

Stock-Based Compensation

Stock-Based Compensation

        We have several stock-based compensation plans, which are described in more detail in Note 8. In accordance with the ASC guidance on stock-based compensation, we recognize compensation expense over the requisite service period of all stock-based compensation awards based upon the fair-value of the award as of the date of issuance.

Recently Issued and Proposed Accounting Standards

Recently Issued and Proposed Accounting Standards

Revenue from contracts with customers:    In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In July 2015, the FASB approved a one year delay in the standard's effective date. The new standard is now effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard.

Extraordinary and unusual items:    In January 2015, the FASB issued revised guidance that eliminates from GAAP the concept of extraordinary items. Under the revised guidance, an entity will no longer be required to separately classify, present and disclose events or transactions that are determined to be both unusual in nature and infrequent in occurrence. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

Presentation of debt issuance costs:    In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. As of December 31, 2015, we expect that the implementation of this standard would reduce both assets and liabilities by approximately $8.7 million. The application of this standard is not expected to have a material impact on our results of operations or liquidity.

Balance sheet classification of deferred taxes:    In November 2015, the FASB issued revised guidance addressing the classification of deferred taxes. Under the revised guidance all deferred tax assets and liabilities will be classified as noncurrent in a classified statement of financial position. The revised guidance is effective for interim and annual periods beginning after December 15, 2016, however early adoption is permitted. As of December 31, 2015, we have retrospectively adopted this standard. The application of this guidance resulted in $19.2 million in current deferred tax assets being reclassified from prepaid expenses and other to deferred income taxes (noncurrent) on the December 31, 2014 Consolidated Balance Sheet.

Recognition and measurement of financial assets and financial liabilities:    In January 2016, the FASB issued revised guidance addressing the recognition, measurement, presentation and disclosure of financial instruments. Under the revised guidance all equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are to be measured at fair value with the changes in fair value recognized in net income. The amended guidance also addresses the impairment assessment of some equity investments, as well as disclosure requirements. The revised guidance is effective for interim and annual periods beginning after December 15, 2017. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2015

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Schedule of gross operating revenues by segments

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.

Operating revenues

Schedule of asset retirement obligation

(000's)	Liability Balance 12/31/14		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/15
Asset Retirement Obligation	$	4,847	$	9,812	$	(73	)	$	486	$	—	$	15,072

(000's)	Liability Balance 12/31/13		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/14
Asset Retirement Obligation	$	4,190	$	—	$	(1,175	)	$	172	$	1,660	$	4,847

Schedule of inventory emission allowances

Emission Allowances in Inventory	2015		2014
Acid Rain SO2		11,443		872
CSAPR SO2		5,861		—
CSAPR NOx (annual)		500		—
CSAPR NOx (seasonal)		241		—

Schedule of fuel, materials and supplies

These balances are as follows (in thousands):

	2015		2014
Electric fuel inventory	$	30,185	$	26,454
Natural gas inventory		3,868		5,040
Materials and supplies		26,897		26,305
TOTAL	$	60,950	$	57,799

Schedule of weighted average number of shares

	2015		2014		2013
Weighted Average Number Of Shares
Basic		43,670,908		43,291,031		42,781,382
Dilutive Securities:
Performance-based restricted stock awards		19,890		8,809		12,142
Employee stock purchase plan		1,249		3,422		1,729
Stock options		—		—		61
Time-based restricted stock awards		25,523		10,666		7,907
Total dilutive securities		46,662		22,897		21,839
Diluted weighted average number of shares		43,717,570		43,313,928		42,803,221
Antidilutive Shares		20,289		25,259		107,100

Electric

Operating revenues

Schedule of operating revenues by major customer classes

        Our electric operations serve approximately 170,000 customers as of December 31, 2015, and the 2015 electric operating revenues were derived as follows:

Customer Class	% of revenue
Residential		41.7	%
Commercial		31.1
Industrial		15.9
Wholesale on-system		3.3
Wholesale off-system		2.7
Miscellaneous sources, primarily public authorities		2.8
Other electric revenues		2.5

Schedule of operating revenues, by jurisdiction

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

Jurisdiction	% of revenue
Missouri		89.0	%
Kansas		4.8
Oklahoma		2.8
Arkansas		3.4

Gas

Operating revenues

Schedule of operating revenues by major customer classes

        Our gas operations serve approximately 43,200 customers as of December 31, 2015, and the 2015 gas operating revenues were derived as follows:

Customer Class	% of revenue
Residential		63.0	%
Commercial		25.6
Industrial		0.8
Transportation		8.9
Miscellaneous		1.7

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PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2015

PROPERTY, PLANT AND EQUIPMENT

Summary of property, plant and equipment

        Our total property, plant and equipment are summarized below (in thousands).

	December 31,
	2015		2014
Electric plant
Production	$	1,151,395	$	1,159,140
Transmission		316,038		288,542
Distribution		870,047		840,761
General(1)		123,338		119,572
Electric plant		2,460,818		2,408,015
Less accumulated depreciation and amortization(2)		721,883		704,596
Electric plant net of depreciation and amortization		1,738,935		1,703,419
Construction work in progress		182,585		110,500
Net electric plant		1,921,520		1,813,919
Water plant		13,109		12,809
Less accumulated depreciation and amortization		5,281		5,102
Water plant net of depreciation and amortization		7,828		7,707
Construction work in progress		75		146
Net water plant		7,903		7,853
Net electric segment plant		1,929,423		1,821,772
Gas plant
Transmission		8,498		8,269
Distribution		66,588		63,319
General(3)		8,316		7,776
Gas Plant		83,402		79,364
Less accumulated depreciation and amortization		18,557		16,405
Gas plant net of accumulated depreciation		64,845		62,959
Construction work in progress		627		379
Net gas plant		65,472		63,338
Other
Fiber		44,263		41,394
Less accumulated depreciation and amortization		19,174		17,304
Non-regulated net of depreciation and amortization		25,089		24,090
Construction work in progress		402		1,072
Net non-regulated property		25,491		25,162
TOTAL NET PLANT AND PROPERTY	$	2,020,386	$	1,910,272

(1)Includes intangible property of $39.8 and $41.2 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2015 and 2014 was $15.6 and $15.7 million, respectively.

(2)As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are not reflected here. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.

(3)Includes intangible property of $0.9 and $0.7 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2015 and 2014 was $0.6 million and $0.5 million, respectively.

Summary of total provision for depreciation and the depreciation rates for continuing operations

        The table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended December 31 (in thousands):

	2015		2014		2013
Provision for depreciation
Regulated — Electric and Water(1)	$	73,885	$	66,600	$	63,192
Regulated — Gas(1)		4,036		3,851		3,763
Non-Regulated		4,895		1,891		1,938
TOTAL		82,816		72,342		68,893
Amortization		2,858		2,692		2,492
TOTAL	$	85,674	$	75,034	$	71,385

(1)A portion of this amount is reclassified to a regulatory liability for the cost of removal. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.

	2015			2014			2013
Annual depreciation rates
Electric and water		3.1	%		3.0	%		3.0	%
Gas		5.1	%		5.2	%		5.4	%
Non-Regulated		4.4	%		4.7	%		5.0	%
TOTAL COMPANY		3.2	%		3.0	%		3.1	%

Summary of average depreciation rate for each class of assets

	2015			2014			2013
Annual Weighted Average Depreciation Rate
Electric fixed assets:
Production plant		2.8	%		2.4	%		2.4	%
Transmission plant		2.4	%		2.4	%		2.4	%
Distribution plant		3.5	%		3.6	%		3.6	%
General plant		5.9	%		5.8	%		5.8	%
Water		2.8	%		2.7	%		2.8	%
Gas		5.1	%		5.2	%		5.4	%
Non-regulated		4.4	%		4.7	%		5.0	%

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REGULATORY MATTERS (Tables)

12 Months Ended

Dec. 31, 2015

REGULATORY MATTERS

Components of regulatory assets and liabilities

        The following table sets forth the components of our regulatory assets and regulatory liabilities on our consolidated balance sheet (in thousands).

	December 31,
	2015			2014
Regulatory Assets:
Current:
Under recovered fuel costs	$	196		$	2,618
Current portion of long-term regulatory assets		6,856			8,134
Regulatory assets, current		7,052			10,752
Long-term:
Pension and other postretirement benefits(1)		108,273			111,121
Income taxes		48,613			47,177
Deferred construction accounting costs(2)		14,977			15,521
Unamortized loss on reacquired debt		9,731			10,405
Unsettled derivative losses — electric segment		7,775			9,037
System reliability — vegetation management		3,604			5,337
Storm costs(3)		3,531			4,183
Asset retirement obligation		7,722			5,145
Customer programs		5,942			5,253
Missouri solar initiative		3,504			—
Current portion of long-term regulatory assets		(6,856	)		(8,134	)
Other		2,892			4,672
Regulatory assets, long-term		209,708			209,717
Total Regulatory Assets	$	216,760		$	220,469
Regulatory Liabilities
Current:
Over recovered fuel costs	$	5,280		$	4,227
Current portion of long-term regulatory liabilities		3,335			3,671
Regulatory liabilities, current		8,615			7,898
Long-term:
Costs of removal(4)		94,193			90,527
SWPA payment for Ozark Beach lost generation		14,213			16,744
Income taxes		11,244			11,451
Deferred construction accounting costs — fuel(5)		7,690			7,849
Unamortized gain on interest rate derivative		3,031			3,201
Pension and other postretirement benefits		1,745			2,369
Over recovered fuel costs		2,300			1
System reliability — vegetation management		1,320			—
Current portion of long-term regulatory liabilities		(3,335	)		(3,671	)
Other		56			—
Regulatory liabilities, long-term		132,457			128,471
Total Regulatory Liabilities	$	141,072		$	136,369

(1)Primarily consists of unfunded pension and OPEB liability. See Note 7.

(2)Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants.

(3)Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $2.9 million at December 31, 2015.

(4)As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are reflected here. See the depreciation discussion under Note 1 and Note 2 Property, Plant and Equipment for more detail.

(5)Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.

Schedule of electric and water rate increases

        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

Schedule of new highway/byway cost allocation methodology

Transmission Project Voltage	Regional Funding Percentage			Zonal Funding Percentage
300 kV and Above		100.0	%		0.0	%
100kV to 299kV		33.3	%		66.7	%
Below 100 kV		0.0	%		100.0	%

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SHAREHOLDERS' EQUITY (Tables)

12 Months Ended

Dec. 31, 2015

SHAREHOLDERS' EQUITY

Schedule of diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance

(in millions, except per share amounts)	2015		2014		2013
Diluted earnings per share	$	1.29	$	1.55	$	1.48
Dividends paid per share	$	1.04	$	1.025	$	1.005
Total dividends paid	$	45.4	$	44.4	$	43.0
Retained earnings year-end balance	$	101.4	$	90.3	$	67.6

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LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2015

LONG-TERM DEBT.

Schedule of long-term debt outstanding

        At December 31, 2015 and 2014, the balance of long-term debt outstanding was as follows (in thousands):

	2015			2014
First mortgage bonds (EDE):
7.20% Series due 2016	$	25,000		$	25,000
6.375% Series due 2018(1)		90,000			90,000
4.65% Series due 2020(1)		100,000			100,000
3.58% Series due 2027(1)		88,000			88,000
3.59% Series due 2030(1)		60,000			—
3.73% Series due 2033(1)		30,000			30,000
5.875% Series due 2037(1)		80,000			80,000
5.20% Series due 2040(1)		50,000			50,000
4.32% Series due 2043(1)		120,000			120,000
4.27% Series due 2044(1)		60,000			60,000
First mortgage bonds (EDG):
6.82% Series due 2036(1)		55,000			55,000
		758,000			698,000
Senior Notes, 6.70% Series due 2033(1)		62,000			62,000
Senior Notes, 5.80% Series due 2035(1)		40,000			40,000
Capital lease obligations		3,890			4,167
Less unamortized net discount		(633	)		(686	)
		863,257			803,481
Less current obligations of long-term debt		(25,000	)		—
Less current obligations under capital lease		(310	)		(292	)
TOTAL LONG-TERM DEBT	$	837,947		$	803,189

(1)We may redeem some or all of the notes at any time at 100% of their principal amount, plus a make-whole premium, plus accrued and unpaid interest to the redemption date.

Long-term Debt Payout Schedule (Excluding Unamortized Discount)

        Our long-term debt obligations over the next five years are as follows (in thousands):

	Payments Due By Period
Long-Term Debt Payout Schedule (Excluding Unamortized Discount) (in thousands)	Total		Regulated Entity Debt Obligations		Capital Lease Obligations
2016	$	25,310	$	25,000	$	310
2017		329		—		329
2018		90,351		90,000		351
2019		375		—		375
2020		100,396		100,000		396
Thereafter		647,129		645,000		2,129
Total long-term debt obligations		863,890	$	860,000	$	3,890
Less current obligations and unamortized discount		25,943
TOTAL LONG-TERM DEBT	$	837,947

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SHORT-TERM BORROWINGS (Tables)

12 Months Ended

Dec. 31, 2015

SHORT-TERM BORROWINGS

Schedule of the entity's average short-term borrowings outstanding

        At December 31, 2015, total short-term borrowings consisted of $25.0 million in commercial paper and no borrowings under our line of credit. During 2015 and 2014 our short-term borrowings outstanding averaged (in millions)

	2015		2014
Average borrowings outstanding	$	48.9	$	30.0
Highest month end balance	$	97.0	$	77.0

Schedule of weighted average interest rates and the weighted average interest rate of borrowings outstanding

	2015			2014
Weighted average interest rate		0.54	%		0.38	%
Weighted average interest rate of borrowings outstanding		0.84	%		0.44	%

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RETIREMENT AND OTHER EMPLOYEE BENEFITS (Tables)

12 Months Ended

Dec. 31, 2015

RETIREMENT AND OTHER EMPLOYEE BENEFITS

Schedule of the Company's benefit plans' projected benefit obligations

        The following table set forth the Company's benefit plans' projected benefit obligations (in thousands).

	Pension						SERP						OPEB
Reconciliation of Projected Benefit Obligations:	2015			2014			2015			2014			2015			2014
Benefit obligation at beginning of year	$	251,879		$	225,131		$	9,155		$	7,108		$	109,899		$	85,332
Service cost		7,442			6,467			158			153			3,713			2,601
Interest cost		10,278			10,819			382			387			4,670			4,360
Amendments		—			(7,753	)		—			(45	)		—			—
Net actuarial (gain)/loss		(708	)		36,742			557			1,890			(14,358	)		20,347
Plan participant's contribution		—			—			—			—			963			850
Benefits and expenses paid		(25,201	)		(19,527	)		(366	)		(338	)		(3,839	)		(3,897	)
Federal subsidy		—			—			—			—			419			306
Benefit obligation at end of year	$	243,690		$	251,879		$	9,886		$	9,155		$	101,467		$	109,899

Schedule of fair value of the plans' assets

        The following table set forth the fair value of the plans' assets (in thousands).

	Pension						SERP				OPEB
Reconciliation of Fair Value of Plan Assets:	2015			2014			2015		2014		2015			2014
Fair value of plan assets at beginning of year	$	192,674		$	186,547		$	—	$	—	$	83,776		$	79,098
Actual return on plan assets — gain/(loss)		(1,978	)		14,319			—		—		(955	)		5,030
Employer contribution		21,350			11,335			—		—		4,903			2,258
Benefits paid		(25,201	)		(19,527	)		—		—		(3,670	)		(3,707	)
Plan participant's contribution		—			—			—		—		912			804
Federal subsidy		—			—			—		—		403			293
Fair value of plan assets at end of year	$	186,845		$	192,674		$	—	$	—	$	85,369		$	83,776

Schedule of the funded status

        The following table set forth the fair value of the funded status (in thousands).

	Pension						SERP						OPEB
Reconciliation of Funded Status:	2015			2014			2015			2014			2015			2014
Fair value of plan assets	$	186,845		$	192,674		$	—		$	—		$	85,369		$	83,776
Projected benefit obligations		(243,690	)		(251,879	)		(9,886	)		(9155	)		(101,467	)		(109,899	)
Funded status	$	(56,845	)	$	(59,205	)	$	(9,886	)	$	(9,155	)	$	(16,098	)	$	(26,123	)

Schedule of employee pension plan accumulated benefit obligation

        The employee pension plan accumulated benefit obligation at December 31, 2015 and 2014 is presented in the following table (in thousands):

	Pension Benefits				SERP
	2015		2014		2015		2014
Accumulated benefit obligation	$	221,481	$	227,928	$	8,609	$	7,160

Schedule of amounts recognized in the balance sheet

        Amounts recognized in the balance sheet consist of (in thousands):

	Pension				SERP				OPEB
	2015		2014		2015		2014		2015		2014
Accounts Payable and Accrued Liabilities	$	—	$	—	$	534	$	481	$	151	$	139
Pension and other postretirement benefit obligation	$	56,845	$	59,205	$	9,352	$	8,674	$	15,947	$	25,984

Schedule of net periodic benefit pension cost

        Net periodic benefit pension cost for 2015, 2014 and 2013, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset (see Note 3), is comprised of the following components (in thousands):

	Pension									OPEB
Net Periodic Pension Benefit Cost:	2015			2014			2013			2015			2014			2013
Service cost	$	7,442		$	6,467		$	7,454		$	3,713		$	2,601		$	2,941
Interest cost		10,278			10,819			10,063			4,670			4,360			3,827
Expected return on plan assets		(13,567	)		(13,105	)		(12,428	)		(5,197	)		(4,801	)		(4,353	)
Amortization of prior service cost/(benefit)(1)		(630	)		418			532			(1,011	)		(1,011	)		(1,011	)
Amortization of actuarial loss(1)		10,033			6,611			10,445			2,747			967			2,261
Net periodic benefit cost	$	13,556		$	11,210		$	16,066		$	4,922		$	2,116		$	3,665

	SERP
Net Periodic Pension Benefit Cost:	2015			2014			2013
Service cost	$	158		$	153		$	135
Interest cost		382			387			315
Expected return on plan assets		—			—			—
Amortization of prior service cost/(benefit)t(1)		(42	)		(8	)		(8	)
Amortization of actuarial loss(1)		597			504			567
Net periodic benefit cost	$	1,095		$	1,036		$	1,009

(1)Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.

Schedule of activity in the regulatory asset accounts

        The tables below present other changes in plan assets and benefit obligations recognized in the regulatory asset accounts for the year (in thousands).

			Amount Recognized
Regulatory Assets	Beginning Balance 12/31/14		Current Year Actuarial Loss			Amortization of Actuarial Loss			Current Year Prior Service Credit		Amortization of Prior Service (Cost)/Credit		Ending Balance 12/31/15
Pension	$	77,456		14,836			(10,033	)		—		630	$	82,889
SERP	$	5,537		557			(597	)		—		42	$	5,539
OPEB	$	20,446		(8,208	)		(2,747	)		—		1,011	$	10,502

			Amount Recognized
Regulatory Assets	Beginning Balance 12/31/13		Current Year Actuarial Loss		Amortization of Actuarial Loss			Current Year Prior Service Credit			Amortization of Prior Service (Cost)/Credit			Ending Balance 12/31/14
Pension	$	56,709		35,529		(6,611	)		(7,753	)		(418	)	$	77,456
SERP	$	4,188		1,890		(504	)		(45	)		8		$	5,537
OPEB	$	285		20,117		(967	)		—			1,011		$	20,446

Schedule of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost and the amounts expected to be recognized in the subsequent year

The following table presents those items for the employee pension plan and other benefits plan at December 31, 2015, and the subsequent twelve-month period (in thousands):

	Pension Benefits						SERP						OPEB
	2015			Subsequent Period			2015			Subsequent Period			2015			Subsequent Period
Net actuarial loss	$	88,981		$	8,426		$	5,555		$	555		$	12,075		$	1,030
Prior service cost (benefit)		(6,092	)		(630	)		(16	)		(14	)		(1,573	)		(1,011	)
Total	$	82,889		$	7,796		$	5,539		$	541		$	10,502		$	19

Schedule of assumptions used to determine the benefit obligation

Weighted-average assumptions used to determine the benefit obligation as of December 31:

	Pension Benefits						OPEB
	2015			2014			2015			2014
Discount rate		4.40	%		4.06	%		4.48	%		4.15	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%		3.50	%

Schedule of assumptions used to determine the periodic costs

Weighted-average assumptions used to determine the net benefit cost (income) as of January 1:

	Pension Benefits									OPEB
	2015			2014			2013			2015			2014			2013
Discount rate		4.06	%		4.90	%		4.00	%		4.15	%		5.00	%		4.11	%
Expected return on plan assets		7.75	%		7.75	%		7.75	%		6.52	%		6.52	%		6.52	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%

Schedule of employee stock purchase plan

	2015			2014		2013
Subscriptions outstanding at December 31,		58,742			57,369		60,413
Maximum subscription price	$	21.09	(1)	$	21.43	$	19.58
Shares of stock issued		56,193			56,942		68,099
Stock issuance price	$	21.01		$	19.58	$	17.95

(1)Stock will be issued on the closing date of the purchase period, which runs from June 1, 2015 to May 31, 2016.

Schedule of assumptions used in valuation of shares under employee stock purchase plan

	2015			2014			2013
Weighted average fair value of grants	$	3.58		$	3.07		$	2.78
Risk-free interest rate		0.26	%		0.10	%		0.14	%
Dividend yield		4.40	%		4.30	%		4.60	%
Expected volatility(1)		21.00	%		14.00	%		14.00	%
Expected life in months		12			12			12
Grant date		6/1/2015			6/2/2014			6/1/2013

(1)One-year historic volatility

Schedule of shares contributed under 401(k) plan and ESOP

	2015		2014		2013
Shares contributed		66,783		60,049		64,128

Pension Benefits

RETIREMENT AND OTHER EMPLOYEE BENEFITS

Schedule of expected benefit payments

        Expected benefit payments are as follows (in millions):

Year	Payments from Trust		Payments from Company Funds
2016	$	22.5	$	0.5
2017		22.8		0.6
2018		21.5		0.5
2019		20.0		0.5
2020		20.9		0.8
2021 – 2025		97.4		2.9

Schedule of fund assets measured at fair value

        The following fair value hierarchy table presents information about the pension fund assets measured at fair value as of December 31, 2015 and December 31, 2014 (in thousands):

	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Percentage of Plan Assets
Short term investments	$	—	$	71	$	—	$	71		0.0	%
Equity securities
Common collective trusts — domestic		—		46,182		—		46,182		24.7	%
Common collective trusts — international				41,928				41,928		22.5	%
Fixed income
Common collective trust		—		60,694		—		60,694		32.5	%
Other types of investments
Equity long/short hedge funds		—		—		37,970		37,970		20.3	%
	$	—	$	148,875	$	37,970	$	186,845		100.0	%

	Fair Value Measurements as of December 31, 2014
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Percentage of Plan Assets
Short term investments	$	—	$	70	$	—	$	70		0.0	%
Equity securities
Common collective trusts — domestic		—		48,760		—		48,760		25.3	%
Common collective trusts — international				42,770				42,770		22.2	%
Fixed income
Common collective trust		—		62,646		—		62,646		32.5	%
Other types of investments
Equity long/short hedge funds		—		—		38,428		38,428		20.0	%
	$	—	$	154,246	$	38,428	$	192,674		100.0	%

Schedule of fair value measurements using significant unobservable inputs (level 3)

Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — December 31,

	2015			2014
	Equity long/short hedge funds			Equity long/short hedge funds
Beginning Balance, January 1,	$	38,428		$	36,729
Actual return on plan assets:
Relating to assets still held at the reporting date		(458	)		1,382
Relating to assets sold during the period		—			1,491
Purchases		—			9,700
Sales		—			(10,874	)
Settlements		—			—
Transfers into and (out of) Level 3		—			—
Ending Balance, December 31,	$	37,970		$	38,428

Schedule of permissible investments

Permissible Investments

Equity Oriented

Fixed Income Oriented and Real Estate

 Common Stocks  Preferred Stocks (minimum "A-rated" by Moody's or S&P)  American Depository Receipts  Convertible Preferred Stocks  Convertible Bonds  Covered Options  Hedged Equity Funds of Funds

 Bonds (including US Government and Agencies)  Corporate Bonds (minimum quality rating of Baa by Moody's or BBB by S&P)  Comingled bond funds (25% max. allocation to high yield)  Foreign Government Bonds  GIC's, BIC's  Commercial Paper (rated A1 by S&P or P1 by Moody's)  Certificates of Deposit in institutions with FDIC/FSLIC protection  Money Market Funds/Bank STIF Funds  Real Estate — Publicly Traded

        The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

        Those investments prohibited by the Investment Committee without prior approval are:

Prohibited Investments Requiring Pre-approval

 Privately Placed Securities  Commodities Futures  Securities of Empire District (except in the hedged equity funds of funds or commingled funds)  Restricted Stock  Warrants  Short Sales  Index Options  Letter Stock

OPEB

RETIREMENT AND OTHER EMPLOYEE BENEFITS

Schedule of expected benefit payments

        Estimated benefit payments are as follows (in millions):

Year	Payments from Trust		Expected Federal Subsidy		Payments from Company Funds
2016	$	2.8	$	0.4	$	0.2
2017		3.2		0.4		0.2
2018		3.5		0.5		0.2
2019		3.8		0.5		0.2
2020		4.1		0.6		0.2
2021 – 2025		25.0		3.7		0.8

Schedule of effect of 1% change in assumed healthcare cost growth rates

        The healthcare cost trend rate affects projected benefit obligations. A 1% change in assumed healthcare cost growth rates would have the following effects (in thousands):

	1% Increase		1% Decrease
Effect on total of service and interest cost	$	2,051	$	(1,530	)
Effect on post-retirement benefit obligation	$	17,473	$	(13,794	)

Schedule of fund assets measured at fair value

The following fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2014 and December 31, 2013 (in thousands):

	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total			Percentage of Plan Assets
Equity securities
Common collective trusts	$	—	$	48,553	$	—	$	48,553			56.9	%
Fixed income
Common collective trusts		—		34,395		—		34,395			40.3	%
Other types of investments
Common collective trusts		—		2,556		—		2,556			3.0	%
	$	—	$	85,504	$	—		85,504
Payable for securities purchased								(135	)		–0.2	%
							$	85,369			100.0	%

	Fair Value Measurements as of December 31, 2014
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total			Percentage of Plan Assets
Equity securities
Common collective trusts	$	—	$	47,690	$	—	$	47,690			56.9	%
Fixed income
Common collective trusts		—		33,708		—		33,708			40.2	%
Other types of investments
Common collective trusts		—		2,453		—		2,453			2.9	%
	$	—	$	83,851	$	—	$	83,851
Payable for securities purchased								(75	)		0.0	%
							$	83,776			100.0	%

Schedule of permissible investments

Permissible Investments

Equity

Fixed Income

 Common Stocks  Preferred Stocks

 Cash-Equivalent Securities with a maturity of one-year or less, including: money market funds, US Government and Agency securities, certificates of deposit or banker's acceptances issued by domestic banks with FDIC protection and commercial paper rated A1 by S&P or P1 by Moody's  Government Bonds  Money Market Funds / Bank STIF Funds  Certificates of Deposit in institutions with FDIC protection  Corporate Bonds (minimum quality rating of A Baa by Moody's or BBB by S&P at time of issuance)

        The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

        Listed below are those investments prohibited by the Investment Committee:

Prohibited Investments

 Privately Placed Securities  Securities of Empire District  Derivatives  Instrumentalities in violation of the Prohibited Transactions Standards of ERISA  Margin Transactions  Options (other than "covered call options")  Lettered or Restricted Stock  Any other investment security which, in the opinion of the investment manager produces an imprudent risk to the fund

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EQUITY COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2015

EQUITY COMPENSATION

Schedule of compensation expense and tax benefits for stock-based awards and programs

        We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in thousands):

	2015		2014		2013
Compensation expense	$	4,279	$	3,688	$	2,577
Tax benefit recognized		1,576		1,359		929

Schedule of fair value measurements for each grant year

	Fair Value of Grants Outstanding at December 31
	2015	2014
Total unrecognized compensation cost (in millions)	$0.4	$0.4
Recognition period	0.1 years to 2.1 years	1.1 years to 2.1 years
Fair value	$25.17	$26.82

Schedule of time vested restricted stock activity

	2015					2014					2013
	Number of Shares			Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Grant Date Fair Value		Number Of Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1,		41,000		$	21.89		24,900		$	21.42		3,300	$	21.84
Granted		19,000		$	30.40		22,600		$	22.40		21,600	$	21.36
Distributed		(1,654	)	$	21.92		(4,010	)	$	21.77		—		—
Forfeited		(2,746	)	$	25.91		(2,490	)	$	21.99		—		—
Outstanding at December 31,		55,600		$	24.60		41,000		$	21.89		24,900	$	21.42

Schedule of assumptions used in valuation of performance-based restricted stock awards

	Fair Value of Grants Outstanding at December 31,
	2015	2014	2013
Risk-free interest rate	0.65% to 1.06%	0.25% to 0.67%	0.13% to 0.38%
Expected volatility of Empire stock	18.7%	14.5%	20.2%
Expected volatility of peer group stock	14.5% to 34.4%	12.4% to 24.8%	12.3% to 27.5%
Expected dividend yield on Empire stock	3.7%	3.5%	4.5%
Expected forfeiture rates	3%	3%	3%
Plan cycle	3 years	3 years	3 years
Fair value percentage	115.0% to 182.0%	140.0% to 157.0%	0.0% to 108.0%
Weighted average fair value per share	$41.73	$43.80	$18.47

Schedule of non-vested performance-based restricted stock awards (based on target number) and changes during the reporting period

	2015					2014					2013
	Number of Shares			Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Grant Date Fair Value		Number Of Shares			Weighted Average Grant Date Fair Value
Outstanding at January 1,		63,300		$	21.74		47,200		$	21.39		33,900		$	20.25
Target shares granted		21,800		$	30.40		27,000		$	22.40		26,300		$	21.36
Shares issued in excess of target		3,653		$	20.97		—			—		—			—
Shares awarded		(13,653	)	$	20.97		—			—		(4,460	)	$	18.36
Forfeited shares		(6,079	)	$	24.10		—			—		—
Target shares not awarded		—			—		(10,900	)	$	21.84		(8,540	)	$	18.36
Nonvested at December 31,		69,021		$	24.38		63,300		$	21.74		47,200		$	21.39

Schedule of assumptions used in the valuations of stock options

	Fair Value of Grants Outstanding at December 31, 2013
Risk-free interest rate	0.10% to 0.38%
Dividend yield	4.5%
Expected volatility	24.0%
Expected life in months	6.5 to 24.5
Market value	$22.69
Weighted average fair value per option	$1.57

Schedule of stock options activity

	2014				2013
	Options		Weighted Average Exercise Price		Options			Weighted Average Exercise Price
Outstanding at January 1,		112,500	$	23.27		163,300		$	22.13
Granted		—		—				$	—
Exercised		112,500	$	24.58		(50,800	)	$	21.78
Outstanding at December 31,		—				112,500		$	23.27
Exercisable, end of year		—				112,500		$	23.27

Schedule of aggregate intrinsic values of stock options

	2013
Aggregate intrinsic value (in millions)	Less than $0.1
Weighted-average remaining contractual life of outstanding options	2.1 years
Range of exercise prices	$21.92 to $23.81
Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	—
Recognition period	—

Schedule of shares accrued to directors' accounts and shares available for issuance under Stock Unit Plan for directors

	2015		2014
Shares accrued to directors' accounts		157,672		164,085
Shares available for issuance		677,980		714,978

Schedule of units accrued and redeemed under Stock Unit Plan for directors

	2015		2014		2013
Units accrued for service and dividends		30,595		30,765		34,252
Units redeemed for common stock		37,008		21,083		22,908

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2015

INCOME TAXES.

Schedule of income tax expense components

        Income tax expense components for the years ended December 31 are as follows (in thousands):

	2015			2014			2013
Current income taxes:
Federal	$	—		$	(2,350	)	$	6,726
State		—			(123	)		2,495
TOTAL		—			(2,473	)		9,221
Deferred income taxes:
Federal		29,722			36,620			24,954
State		4,233			5,216			3,554
TOTAL		33,955			41,836			28,508
Investment tax credit amortization		(143	)		(143	)		(237	)
TOTAL INCOME TAX EXPENSE	$	33,812		$	39,220		$	37,492

Schedule of deferred tax assets and liabilities as reflected on consolidated balance sheet

        Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows
(in thousands):

	December 31,
Deferred Income Taxes	2015		2014
NET DEFERRED TAX LIABILITIES	$	396,542	$	358,252

Summary of temporary differences related to deferred tax assets and deferred tax liabilities

        Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows (in thousands):

	December 31,
Temporary Differences	2015		2014
Deferred tax assets:
Plant related basis differences	$	27,347	$	25,349
Net operating loss (NOL)		9,055		22,000
Regulated liabilities related to income taxes		13,142		13,350
Disallowed plant costs		1,699		1,754
Gains on hedging transactions		1,195		1,260
Pensions and other post-retirement benefits		—		1,175
Carry forward of income tax credit		8,675		6,367
Other		1,550		1,633
Total deferred tax assets	$	62,663	$	72,888
Deferred tax liabilities:
Depreciation, amortization and other plant related differences	$	382,897	$	363,337
Regulated assets related to income		38,615		37,180
Loss on reacquired debt		3,572		3,828
Amortization of intangibles		10,248		9,168
Pensions and other post-retirement benefits		7,112		—
Deferred construction accounting costs		5,711		6,082
Other		11,050		11,545
Total deferred tax liabilities		459,205		431,140
NET DEFERRED TAX LIABILITIES	$	396,542	$	358,252

Schedule of difference between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing operations

Effective Income Tax Rates	2015			2014			2015
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit)		3.1			3.1			3.1
Investment tax credit amortization		(0.2	)		(0.1	)		(0.2	)
Effect of ratemaking on property related differences		(1.4	)		(1.7	)		(1.1	)
Other		0.9			0.6			0.3
EFFECTIVE INCOME TAX RATE		37.4	%		36.9	%		37.1	%

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COMMONLY OWNED FACILITIES (Tables)

12 Months Ended

Dec. 31, 2015

Iatan

COMMONLY OWNED FACILITIES

Schedule of property, plant and equipment

        At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions):

Iatan	2015		2014
Cost of ownership in plant in service	$	380.2	$	373.3
Accumulated Depreciation	$	105.3	$	99.1
Expenditures(1)	$	26.9	$	27.8

(1)Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.

State Line Combined Cycle Unit

COMMONLY OWNED FACILITIES

Schedule of property, plant and equipment

        At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions):

State Line Combined Cycle Unit	2015		2014
Cost of ownership in plant in service	$	163.0	$	161.5
Accumulated Depreciation	$	43.5	$	40.0
Expenditures(1)	$	40.7	$	47.1

(1)Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.

Plum point

COMMONLY OWNED FACILITIES

Schedule of property, plant and equipment

        At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions):

Plum Point Energy Station	2015		2014
Cost of ownership in plant in service	$	109.1	$	108.3
Accumulated Depreciation	$	11.9	$	9.4
Expenditures(1)	$	9.6	$	8.1

(1)Recognized in operating, maintenance and fuel expenditures excluding depreciation expense.

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2015

COMMITMENTS AND CONTINGENCIES

Schedule of physical gas, coal and transportation contracts

        The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of December 31, 2015 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
January 1, 2016 through December 31, 2016	$	26.7	$	18.0
January 1, 2017 through December 31, 2018		37.4		27.5
January 1, 2019 through December 31, 2020		28.8		10.8
January 1, 2021 and beyond		45.7		—

Schedule of lease obligations over the next five years

        Our lease obligations over the next five years are as follows (in thousands):

	Capital Leases		Operating Leases
2016	$	554	$	734
2017		551		689
2018		551		648
2019		550		484
2020		546		—
Thereafter		2,460		—
Total minimum payments		5,212	$	2,555
Less amount representing interest		1,322
Present value of net minimum lease payments	$	3,890

Summary of most significant environmental regulations affecting operations

Regulations

Air Emissions — NOx and SO2

CAIR (Clean Air Interstate Rule)

CSAPR (Cross State Air Pollution Rule)

MATS (Mercury Air Toxic Standards)

NAAQS (National Ambient Air Quality Standards)

Greenhouse Gases (GHGs) — CO₂

Surface Impoundments

Coal Ash Impoundments:

Asbury Power Plant

Riverton (capped and closed in 2014 as industrial (coal combustion waste) landfill)

Water Discharges

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SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2015

SEGMENT INFORMATION

Schedule of statement of income information, balance sheet information and capital expenditures by business segments

	For the year ended December 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
Operating Revenues(1)	$	555,085	$	41,702	$	10,165	$	(1,379	)	$	605,573
Depreciation and amortization		74,732		3,923		1,895		—			80,550
Federal and state income taxes		31,123		800		1,889		—			33,812
Operating income		88,124		5,153		3,024		—			96,301
Interest income		133		36		47		(71	)		145
Interest expense		41,307		3,867		—		(71	)		45,103
Income from AFUDC (debt and equity)		7,681		14		—		—			7,695
Income from continuing operations	$	52,240	$	1,287	$	3,070	$	—		$	56,597
Capital Expenditures	$	169,111	$	5,190	$	2,223	$	—		$	176,524

(1)The Electric Segment includes SPP Integrated Marketplace net revenues of $15.0 million.

	2014
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
Operating Revenues(1)	$	592,491	$	51,842	$	9,302	$	(1,305	)	$	652,330
Depreciation and amortization		67,534		3,760		1,891		—			73,185
Federal and state income taxes		35,737		1,840		1,643		—			39,220
Operating income		90,488		6,775		2,736		—			99,999
Interest income		37		25		21		(32	)		51
Interest expense		37,911		3,861		—		(32	)		41,740
Income from AFUDC (debt and equity)		9,833		84		—		—			9,917
Income from continuing operations	$	61,467	$	2,965	$	2,671	$	—		$	67,103
Capital Expenditures	$	212,866	$	7,836	$	2,151	$	—		$	222,853

(1)The Electric Segment includes SPP Integrated Marketplace net revenues of $41.9 million.

	2013
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
Operating Revenues	$	536,413	$	50,041	$	9,147	$	(1,271	)	$	594,330
Depreciation and amortization		63,659		3,709		1,938		—			69,306
Federal and state income taxes		34,478		1,484		1,530		—			37,492
Operating income		90,984		6,194		2,485		—			99,663
Interest income		537		115		8		(94	)		566
Interest expense		37,683		3,890		—		(94	)		41,479
Income from AFUDC (debt and equity)		5,910		30		—		—			5,940
Income from continuing operations	$	58,603	$	2,355	$	2,487	$	—		$	63,445
Capital Expenditures	$	153,401	$	4,419	$	2,388	$	—		$	160,208

	December 31, 2015
	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information:
Total assets	$	2,339,850	$	127,871	$	38,300	$	(50,718	)	$	2,455,303

	December 31, 2014
	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information:
Total assets	$	2,252,339	$	130,856	$	34,655	$	(46,794	)	$	2,371,056

(1)Includes goodwill of $39,492 at December 31, 2015 and 2014.

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SELECTED QUARTERLY INFORMATION (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2015

SELECTED QUARTERLY INFORMATION (UNAUDITED)

Summary of quarterly results

        The following is a summary of quarterly results for 2015 and 2014 (dollars in thousands except per share amounts):

	Quarters
Quarterly Results for 2015	First		Second		Third		Fourth
Operating revenues(1)	$	164,544	$	134,557	$	169,714	$	136,758
Operating income	$	24,713	$	16,047	$	35,783	$	19,757
Net Income	$	14,637	$	6,770	$	25,285	$	9,905
Basic Earnings Per Share	$	0.34	$	0.16	$	0.58	$	0.23
Diluted Earnings Per Share	$	0.34	$	0.15	$	0.58	$	0.23

(1)Operating revenue for the first, second, third and fourth quarters of 2015 include SPP IM net revenues of $4.7 million, $3.4 million, $4.0 million, and $2.9 million, respectively.

	Quarters
Quarterly Results for 2014	First		Second		Third		Fourth
Operating revenues(1)	$	179,673	$	149,782	$	171,512	$	151,363
Operating income	$	29,488	$	19,502	$	31,709	$	19,300
Net Income	$	20,905	$	11,194	$	23,892	$	11,112
Basic and Diluted Earnings Per Share	$	0.48	$	0.26	$	0.55	$	0.26

(1)Operating revenue for the first, second, third and fourth quarters of 2014 include SPP IM net revenues of $6.2 million, $16.5 million, $11.5 million, and $7.5 million, respectively.

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RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2015

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

Schedule of fair value of derivative financial instruments, balance sheet classification

        As of December 31, 2015 and 2014, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of December 31, (in thousands):

ASSET DERIVATIVES

Non-designated hedging instruments due to regulatory accounting		2015		2014
	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	2	$	—
	Non-current assets and deferred charges — Other		16		—
Natural gas contracts, electric segment	Current assets		—		1
	Non-current assets and deferred charges — Other		—		—
Transmission congestion rights, electric segment	Current assets		1,293		3,900
Total derivatives assets		$	1,311	$	3,901

LIABILITY DERIVATIVES

Non-designated as hedging instruments due to regulatory accounting		2015		2014
	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	282	$	476
	Non-current liabilities and deferred credits		66		—
Natural gas contracts, electric segment	Current liabilities		4,190		5,993
	Non-current liabilities and deferred credits		3,630		3,243
Transmission congestion rights, electric segment	Current liabilities		—		—
Total derivatives liabilities		$	8,168	$	9,712

Schedule of mark-to-market pre-tax gains/(losses) from non-designated derivative instruments - electric segment

        The following tables set forth "mark-to-market" pre-tax gains/ (losses) from non-designated derivative instruments for the electric segment for each of the years ended December 31 (in thousands):

Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment

		Amount of Gain/(Loss) Recognized on Balance Sheet
	Balance Sheet Classification of Gain/(Loss) on Derivative	2015			2014
Commodity contracts — electric segment	Regulatory (assets)/liabilities	$	(6,853	)	$	(6,780	)
Transmission congestion rights — electric segment	Regulatory (assets)/liabilities		4,970			12,958
Total — Electric Segment		$	(1,883	)	$	6,178

Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment

		Amount of Gain/(Loss) Recognized in Income on Derivative
	Statement of Operations Classification of Loss on Derivative	2015			2014
Commodity contracts	Fuel and purchased power expense	$	(8,115	)	$	(1,659	)
Transmission congestion rights — electric segment	Fuel and purchased power expense		7,468			11,106
Total — Electric Segment		$	(647	)	$	9,447

Schedule of volumes and percentage of anticipated volume of natural gas usage for entity's electric operations with procurement guidelines

Year	% Hedged			Dth Hedged Physical		Dth Hedged Financial		Average Price
2016		61	%		2,706,000		5,940,000	$	3.372
2017		41	%		782,900		5,210,000	$	3.347
2018		20	%		565,000		2,460,000	$	3.334
2019		10	%		—		1,460,000	$	2.955
2020		0	%		—		—		—

Schedule of minimum percentage hedged by year in the entity's procurement guidelines

Year	End of Year Minimum % Hedged
Current	Up to 100%
First	60%
Second	40%
Third	20%
Fourth	10%

Schedule of transmission congestion rights (TCR)

Year	Monthly MWH Hedged		$ Value
2016		3,212	$	1,292,943

Schedule of minimum percentage of winter season usage hedged by year of the entity's gas operations

        The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the ACA year at September 1 and illustrates our hedged position as of December 31, 2015 (Dth in thousands).

Season	Minimum % Hedged			Dth Hedged Financial		Dth Hedged Physical		Dth in Storage		Actual % Hedged
Current		50	%		400,000		—		1,419,752		93	%
Second		Up to 50	%		200,000		—		—		6	%
Third		Up to 20	%		280,000		—		—		9	%

Schedule of mark-to-market pre-tax gains/(losses) from non-designated derivative instruments - gas segment

        The following table sets forth "mark-to-market" pre-tax gains/ (losses) from derivatives not designated as hedging instruments for the gas segment for the years ended December 31 (in thousands):

Non-Designated Hedging Instruments Due to Regulatory Accounting — Gas Segment

		Amount of Loss Recognized on Balance Sheet
	Balance Sheet Classification of Loss on Derivative	2015			2014
Commodity contracts	Regulatory assets	$	(447	)	$	(511	)
						—
Total — Gas Segment		$	(447	)	$	(511	)

Schedule of margin deposit assets

(in millions)	December 31, 2015		December 31, 2014
Margin deposit assets	$	11.2	$	9.1

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2015

FAIR VALUE MEASUREMENTS

Schedule of transmission congestion rights (TCR) and commodity contracts measured at fair value

Fair Value Measurements at Reporting Date Using

($ in 000's) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2015
Derivative assets	$	1,311		$	18		$	1,293	$	—
Derivative liabilities	$	(8,168	)	$	(8,168	)	$	—	$	—
December 31, 2014
Derivative assets	$	3,901		$	1		$	3,900	$	—
Derivative liabilities	$	(9,712	)	$	(9,712	)	$	—	$	—

*The only recurring measurements are derivative related.

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REGULATED OPERATING EXPENSE (Tables)

12 Months Ended

Dec. 31, 2015

REGULATED OPERATING EXPENSE

Schedule of regulated operating expenses

        The following table sets forth the major components comprising "regulated operating expenses" under "Operating Revenue Deductions" on our consolidated statements of income for the years ended (in thousands):

	December 31,
	2015		2014		2013
Power operation expense (other than fuel)	$	18,263	$	16,089	$	15,643
Electric transmission and distribution expense		28,893		27,919		21,863
Natural gas transmission and distribution expense		2,699		2,362		2,498
Customer accounts & assistance expense		10,937		11,239		11,180
Employee pension expense(1)		10,786		10,590		10,736
Employee healthcare plan(1)		10,162		9,147		10,190
General office supplies and expense		14,438		15,024		12,850
Administrative and general expense		14,863		14,385		14,800
Bad debt expense		2,080		3,420		3,665
Regulatory reversal of gain on sale of assets		—		44		1,236
Miscellaneous expense		430		472		672
TOTAL	$	113,551	$	110,691	$	105,333

(1)Does not include the capitalized portion of actuarially calculated costs, but reflects the GAAP expensed portion of these costs plus or minus costs deferred to a regulatory asset or recognized as a regulatory liability for Missouri and Kansas jurisdictions.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2015 segment customer item
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Number of business segments | segment	3
Number of towns to which water service is provided | item	3
Electric
Operating revenues
% of revenue (as a percent)	91.70%
Number of customers	170,000
Electric | On-system Member
Operating revenues
% of revenue (as a percent)	86.60%
Electric | SPP IM
Operating revenues
% of revenue (as a percent)	2.50%
Electric | Other revenues
Operating revenues
% of revenue (as a percent)	2.30%
Electric | Water
Operating revenues
% of revenue (as a percent)	0.30%
Electric | Missouri
Operating revenues
% of revenue (as a percent)	89.00%
Electric | Kansas
Operating revenues
% of revenue (as a percent)	4.80%
Electric | Arkansas
Operating revenues
% of revenue (as a percent)	3.40%
Electric | Oklahoma
Operating revenues
% of revenue (as a percent)	2.80%
Electric | Residential
Operating revenues
% of revenue (as a percent)	41.70%
Electric | Commercial
Operating revenues
% of revenue (as a percent)	31.10%
Electric | Industrial
Operating revenues
% of revenue (as a percent)	15.90%
Electric | Wholesale on-system
Operating revenues
% of revenue (as a percent)	3.30%
Electric | Wholesale off-system
Operating revenues
% of revenue (as a percent)	2.70%
Electric | Miscellaneous sources, primarily public authorities
Operating revenues
% of revenue (as a percent)	2.80%
Electric | Miscellaneous
Operating revenues
% of revenue (as a percent)	2.50%
Gas
Operating revenues
% of revenue (as a percent)	6.90%
Number of customers	43,200
Gas | Residential
Operating revenues
% of revenue (as a percent)	63.00%
Gas | Commercial
Operating revenues
% of revenue (as a percent)	25.60%
Gas | Industrial
Operating revenues
% of revenue (as a percent)	0.80%
Gas | Transportation
Operating revenues
% of revenue (as a percent)	8.90%
Gas | Miscellaneous
Operating revenues
% of revenue (as a percent)	1.70%
Other
Operating revenues
% of revenue (as a percent)	1.40%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Municipal Franchise Taxes
Municipal franchise taxes	$ 11,400	$ 11,800	$ 11,200
Property, Plant and Equipment
Period for refund of pro rata amount of the original cost of the extension to developers	5 years
Liability for refund of pro rata amount of the original cost of the extension to developers	$ 2,100	1,900
Regulatory Liability [Abstract]
Regulatory liability	141,072	136,369
Electric | Costs of removal
Regulatory Liability [Abstract]
Regulatory liability	85,400	82,800
Gas | Costs of removal
Regulatory Liability [Abstract]
Regulatory liability	$ 8,800	$ 7,700

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 3)			12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($) item	Dec. 31, 2013 USD ($)	Dec. 31, 2015 USD ($)	Oct. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Asset Retirement Obligation
Proportionate ownership interest (as a percent)						12.00%
Change in asset retirement obligation
Asset retirement obligation	$ 15,072,000	$ 4,847,000	$ 4,847,000	$ 4,190,000	$ 4,190,000	$ 15,072,000		$ 4,847,000
Opening balance of asset retirement obligation			4,847,000	4,190,000
Liabilities Recognized			9,812,000
Liabilities settled			(73,000)	(1,175,000)
Accretion			486,000	172,000
Cash Flow Revisions				1,660,000
Closing balance of asset retirement obligation	15,072,000	4,847,000	$ 15,072,000	$ 4,847,000	$ 4,190,000
Regulatory assets						216,760,000		220,469,000
Allowance for Funds Used During Construction
Aggregate rates (on a before-tax basis)			5.50%	6.60%	7.30%
Asset Impairments (excluding goodwill)
Assets impaired	0	$ 0
Goodwill
Number of assumptions whose negative charge will affect impairment | item			1
Number of approaches used to estimate the fair value | item			2
Fuel and Purchased Power
Inventory allowances						0
Pension and Other Postretirement Benefits
Percentage that unrecognized gains or losses must exceed postretirement benefit obligation or fair value of plan assets for recognition of additional income or expense			10.00%
Amortization period of unrecognized gains or losses into actuarial expense			10 years
Cash & Cash Equivalents
Checks and electronic fund transfers that have been issued but not cleared through bank						23,200,000		28,300,000
Restricted Cash
Amounts restricted for operating costs						1,800,000		1,800,000
Asbury Power Plant
Change in asset retirement obligation
Asset retirement obligation	5,400,000		$ 5,400,000			5,400,000
Closing balance of asset retirement obligation	5,400,000		5,400,000
Iatan Generating Station
Change in asset retirement obligation
Asset retirement obligation	4,400,000		4,400,000			4,400,000
Closing balance of asset retirement obligation	$ 4,400,000		$ 4,400,000
SPP
Restricted Cash
Amounts restricted for secured collateral						2,500,000		2,500,000
MISO
Restricted Cash
Amounts restricted for secured collateral						$ 500,000		500,000
Electric
Fuel and Purchased Power
Number of NOx annual allowances purchased for compliance | item				69
Electric | Missouri Public Service Commission (MPSC)
Fuel and Purchased Power
Percentage of changes in fuel and purchased power costs from the base cost permitted for distribution to customers under fuel adjustment clause			95.00%
Gas
Fuel and Purchased Power
Maximum number of rate changes allowed by PGA clause throughout the year | item			4
Low end of range
Asset Retirement Obligation
Credit adjusted risk-free rate (as a percent)						4.50%
Low end of range | Gas
Goodwill
Excess fair value of the reporting unit over carrying value							$ 18,000,000
High end of range
Asset Retirement Obligation
Credit adjusted risk-free rate (as a percent)						5.52%
High end of range | Gas
Goodwill
Excess fair value of the reporting unit over carrying value							$ 22,000,000
Asset retirement obligation.
Change in asset retirement obligation
Regulatory assets						$ 7,700,000		5,100,000
Under recovered fuel costs
Change in asset retirement obligation
Regulatory assets						5,900,000		3,100,000
Acid Rain SO2
Fuel and Purchased Power
Inventory allowances						11,443		$ 872
CSAPR SO2
Fuel and Purchased Power
Inventory allowances						5,861
CSAPR NOx (annual)
Fuel and Purchased Power
Inventory allowances						500
CSAPR Nox (seasonal)
Fuel and Purchased Power
Inventory allowances						$ 241

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Detail 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fuel, Materials and Supplies
Total	$ 60,950	$ 57,799
Income taxes
Longest remaining amortization period for investment tax credits	55 years
Accounting for Uncertainty in Income Taxes
No material changes to unrecognized tax benefits in other expenses	12 months
Weighted Average Number Of Shares
Basic (in shares)	43,671,000	43,291,000	42,781,000
Dilutive Securities:
Performance-based restricted stock awards (in shares)	19,890	8,809	12,142
Employee stock purchase plan (in shares)	1,249	3,422	1,729
Stock options (in shares)			61
Time-based restricted stock awards (in shares)	25,523	10,666	7,907
Total dilutive securities (in shares)	46,662	22,897	21,839
Diluted weighted average number of shares	43,718,000	43,314,000	42,803,000
Antidilutive Shares	20,289	25,259	107,100
Electric fuel inventory
Fuel, Materials and Supplies
Total	$ 30,185	$ 26,454
Natural gas inventory
Fuel, Materials and Supplies
Total	3,868	5,040
Materials and supplies
Fuel, Materials and Supplies
Total	$ 26,897	$ 26,305

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 5) - New Accounting Pronouncement, Early Adoption, Effect $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Accounting Standards Update 2015-03 Simplifying the Presentation of Debt Issuance Costs
Recently Issued and Proposed Accounting Standards
Change in financial position	$ 8.7
Accounting Standards Update 2015-11 Balance Sheet Classification of Deferred Taxes
Recently Issued and Proposed Accounting Standards
Change in financial position	$ 19.2

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PROPERTY, PLANT AND EQUIPMENT (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, plant and equipment
Less accumulated depreciation and amortization	$ 764,895	$ 743,407
Construction work in progress	183,689	112,097
Total plant and property, Net	2,020,386	1,910,272
Plant and property, Gross	83,402	79,364
Plant and property, Gross	44,263	41,394
Provision for depreciation	82,816	72,342	$ 68,893
Amortization	2,858	2,692	2,492
Total depreciation and amortization	$ 85,674	$ 75,034	$ 71,385
Annual depreciation rates (as a percent)	3.20%	3.00%	3.10%
Regulated
Property, plant and equipment
Total plant and property, Net	$ 1,929,423	$ 1,821,772
Non-Regulated
Property, plant and equipment
Provision for depreciation	$ 4,895	$ 1,891	$ 1,938
Annual depreciation rates (as a percent)	4.40%	4.70%	5.00%
Electric plant | Regulated
Property, plant and equipment
Plant and property, Gross	$ 2,460,818	$ 2,408,015
Less accumulated depreciation and amortization	721,883	704,596
Plant and property, net of depreciation and amortization	1,738,935	1,703,419
Construction work in progress	182,585	110,500
Total plant and property, Net	1,921,520	1,813,919
Electric plant | Intangible property, primarily capitalized software and investments in facility upgrades | Regulated
Property, plant and equipment
Plant and property, Gross	39,800	41,200
Less accumulated depreciation and amortization	15,600	15,700
Production | Regulated
Property, plant and equipment
Plant and property, Gross	$ 1,151,395	$ 1,159,140
Annual depreciation rates (as a percent)	2.80%	2.40%	2.40%
Transmission. | Regulated
Property, plant and equipment
Plant and property, Gross	$ 316,038	$ 288,542
Annual depreciation rates (as a percent)	2.40%	2.40%	2.40%
Distribution. | Regulated
Property, plant and equipment
Plant and property, Gross	$ 870,047	$ 840,761
Annual depreciation rates (as a percent)	3.50%	3.60%	3.60%
General | Regulated
Property, plant and equipment
Plant and property, Gross	$ 123,338	$ 119,572
Annual depreciation rates (as a percent)	5.90%	5.80%	5.80%
Gas plant | Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	$ 18,557	$ 16,405
Plant and property, net of depreciation and amortization	64,845	62,959
Construction work in progress	627	379
Total plant and property, Net	65,472	63,338
Plant and property, Gross	83,402	79,364
Provision for depreciation	$ 4,036	$ 3,851	$ 3,763
Annual depreciation rates (as a percent)	5.10%	5.20%	5.40%
Transmission | Regulated
Property, plant and equipment
Plant and property, Gross	$ 8,498	$ 8,269
Distribution | Regulated
Property, plant and equipment
Plant and property, Gross	66,588	63,319
General | Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	600	500
Plant and property, Gross	8,316	7,776
General | Intangible property, primarily capitalized software and investments in facility upgrades | Regulated
Property, plant and equipment
Plant and property, Gross	900	700
Water plant | Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	5,281	5,102
Plant and property, net of depreciation and amortization	7,828	7,707
Construction work in progress	75	146
Total plant and property, Net	7,903	7,853
Plant and property, Gross	$ 13,109	$ 12,809
Annual depreciation rates (as a percent)	2.80%	2.70%	2.80%
Other | Non-Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	$ 19,174	$ 17,304
Plant and property, net of depreciation and amortization	25,089	24,090
Construction work in progress	402	1,072
Total plant and property, Net	25,491	25,162
Fiber | Non-Regulated
Property, plant and equipment
Plant and property, Gross	44,263	41,394
Electric and Water | Regulated
Property, plant and equipment
Provision for depreciation	$ 73,885	$ 66,600	$ 63,192
Annual depreciation rates (as a percent)	3.10%	3.00%	3.00%

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REGULATORY MATTERS (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Aug. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets:
Regulatory assets, current		$ 7,052	$ 10,752
Regulatory assets, long-term		209,708	209,717
Total Regulatory Assets		216,760	220,469
Regulatory Liabilities:
Regulatory liabilities, current		8,615	7,898
Regulatory liabilities, long-term		132,457	128,471
Total Regulatory Liabilities		141,072	136,369
Missouri 2015 Rate Case | Iatan2
Regulatory Assets and Liabilities
Amortizable life tracking mechanism	3 years
Amortizable life tracking mechanism related to vegetation	5 years
Over recovered fuel costs
Regulatory Liabilities:
Regulatory liabilities, current		5,280	4,227
System reliability - vegetation management
Regulatory Liabilities:
Regulatory liabilities, long-term		1,320
Current portion of long-term regulatory liabilities
Regulatory Liabilities:
Regulatory liabilities, current		3,335	3,671
Other
Regulatory Liabilities:
Regulatory liabilities, long-term		56
Costs of removal
Regulatory Liabilities:
Regulatory liabilities, long-term		94,193	90,527
SWPA payment for Ozark Beach lost generation
Regulatory Liabilities:
Regulatory liabilities, long-term		14,213	16,744
Income taxes
Regulatory Liabilities:
Regulatory liabilities, long-term		11,244	11,451
Deferred construction accounting costs - fuel
Regulatory Liabilities:
Regulatory liabilities, long-term		7,690	7,849
Unamortized gain on interest rate derivative
Regulatory Liabilities:
Regulatory liabilities, long-term		$ 3,031	3,201
Unamortized gain on interest rate derivative | High end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		25 years
Unamortized gain on interest rate derivative | Low end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		4 years
Pension and other postretirement benefits
Regulatory Liabilities:
Regulatory liabilities, long-term		$ 1,745	2,369
Over recovered electric fuel and purchased power costs
Regulatory Liabilities:
Regulatory liabilities, long-term		2,300	1
Under recovered fuel costs
Regulatory Assets:
Regulatory assets, current		196	2,618
Total Regulatory Assets		5,900	3,100
Current portion of long-term regulatory assets
Regulatory Assets:
Regulatory assets, current		6,856	8,134
Pension and other postretirement benefits
Regulatory Assets:
Regulatory assets, long-term		$ 108,273	111,121
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		5 years
Portion of regulatory assets expected to be recoverable in future periods		$ 99,000
Income taxes
Regulatory Assets:
Regulatory assets, long-term		48,613	47,177
Deferred construction accounting costs
Regulatory Assets:
Regulatory assets, long-term		14,977	15,521
Unamortized loss on reacquired debt
Regulatory Assets:
Regulatory assets, long-term		$ 9,731	10,405
Unamortized loss on reacquired debt | High end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		25 years
Unamortized loss on reacquired debt | Low end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		4 years
System reliability - vegetation management
Regulatory Assets:
Regulatory assets, long-term		$ 3,604	5,337
Storm costs
Regulatory Assets:
Regulatory assets, long-term		$ 3,531	4,183
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		5 years
Asset retirement obligation.
Regulatory Assets:
Regulatory assets, long-term		$ 7,722	5,145
Total Regulatory Assets		7,700	5,100
Customer programs
Regulatory Assets:
Regulatory assets, long-term		5,942	5,253
Missouri solar initiative
Regulatory Assets:
Regulatory assets, long-term		3,504
Other
Regulatory Assets:
Regulatory assets, long-term		2,892	4,672
Ice storm and tornado cost
Regulatory Assets:
Regulatory assets, long-term		$ 2,900
Asbury five-year maintenance
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		5 years
Electric | Costs of removal
Regulatory Liabilities:
Total Regulatory Liabilities		$ 85,400	82,800
Electric | Unsettled derivative losses- electric segment
Regulatory Assets:
Regulatory assets, long-term		7,775	9,037
Gas | Costs of removal
Regulatory Liabilities:
Total Regulatory Liabilities		$ 8,800	$ 7,700

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REGULATORY MATTERS (Details 2)									12 Months Ended
	Jan. 22, 2016 USD ($)	Jul. 26, 2015 USD ($) $ / MWh	Jun. 08, 2015	Jun. 01, 2015 USD ($)	Jan. 22, 2015 USD ($)	Dec. 05, 2014 USD ($)	Oct. 29, 2013 item	Jun. 13, 2012	Dec. 31, 2015	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Oct. 16, 2015 USD ($)	Feb. 23, 2015 USD ($)	Sep. 26, 2014 USD ($)	Aug. 29, 2014 USD ($)	May. 20, 2014 USD ($)	Dec. 03, 2013 USD ($)	Apr. 01, 2013 USD ($)
RATE MATTERS
Plant Disallowance										$ 86,000	$ 2,409,000
Utilities Operating Expense Reverse Gain on Sale of Assets										$ 44,000	$ 1,236,000
Number of new Missouri demand-side management programs | item							4
Missouri Public Service Commission (MPSC) | Missouri 2015 Rate Case
RATE MATTERS
Net reduction in base fuel and purchased power | $ / MWh		1.60
Fuel Adjustment Charge (in percent)									34
Missouri Public Service Commission (MPSC) | Electric
RATE MATTERS
Approved amount of annual increase in base rate		$ 17,125,000																$ 27,500,000
Approved percentage of annual increase in base rate		3.90%																6.78%
Missouri Public Service Commission (MPSC) | Electric | Missouri 2015 Rate Case
RATE MATTERS
Requested amount of annual increase in base rate												$ 33,400,000
Requested percentage of annual increase in base rate												7.30%
Missouri Public Service Commission (MPSC) | Electric | Missouri 2014 Rate Case
RATE MATTERS
Requested amount of annual increase in electric base rate															$ 24,300,000
Percentage of annual base rate increase requested															5.50%
Kansas Corporation Commission (KCC) | 2014 Environmental Cost Recovery Rider Member
RATE MATTERS
Proposed recover costs						$ 860,000
Approved recover costs				$ 780,000
Kansas Corporation Commission (KCC) | Ad Valorem Tax Surcharge
RATE MATTERS
Annual increase related to Ad Valorem taxes					$ 270,000,000
Additional Annual Increase Related To AdValorem Taxes	$ 200,000
Kansas Corporation Commission (KCC) | Electric
RATE MATTERS
Approved amount of annual increase in base rate				$ 782,479									$ 273,455
Approved percentage of annual increase in base rate				4.71%									1.08%
Oklahoma Corporation Commission (OCC) | Electric | High end of range
RATE MATTERS
Customer rate reciprocity who serve less of total customers (in percent)			10
Arkansas Public Service Commission (APSC) | Electric
RATE MATTERS
Approved amount of annual increase in base rate													$ 457,000	$ 1,366,809
Approved percentage of annual increase in base rate													3.35%	11.34%
Arkansas Public Service Commission (APSC) | Electric | Missouri 2014 Rate Case
RATE MATTERS
Requested amount of annual increase in electric base rate																$ 1,375,000
Percentage of annual base rate increase requested																11.00%
Arkansas Public Service Commission (APSC) | Electric | Arkansas 2013 Rate Case
RATE MATTERS
Requested amount of annual increase in electric base rate																	$ 2,200,000
Percentage of annual base rate increase requested																	18.00%
Federal Energy Regulatory Commission (FERC) | TFR rate case
RATE MATTERS
Percentage of ROE								10.00%

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REGULATORY MATTERS (Details 3) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2012 item	Dec. 31, 2015 USD ($)	Dec. 31, 2010
RATE MATTERS
Deferred expenses related to rate cases		$ 0.4
SPP Regional Transmission Development
RATE MATTERS
Estimated increase in transmission expenses		$ 1.3
SPP Regional Transmission Development | Low end of range
RATE MATTERS
Transmission Project Voltage (in kV) | item	161
SPP Regional Transmission Development | Transmission projects between 100 kV and 299 kV | Electric
RATE MATTERS
Regional Funding Percentage			33.30%
Zonal Funding Percentage			66.70%
SPP Regional Transmission Development | Transmission projects 300 kV or above | Electric
RATE MATTERS
Regional Funding Percentage			100.00%
Zonal Funding Percentage			0.00%
SPP Regional Transmission Development | Transmission projects below 100 kV | Electric
RATE MATTERS
Regional Funding Percentage			0.00%
Zonal Funding Percentage			100.00%
SPP Day-Ahead Market | Low end of range
RATE MATTERS
Percentage of generation needed for next day throughout SPP territory that will be cleared through Integrated Marketplace		90.00%
SPP Day-Ahead Market | High end of range
RATE MATTERS
Percentage of generation needed for next day throughout SPP territory that will be cleared through Integrated Marketplace		95.00%

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SHAREHOLDERS' EQUITY (Details) - USD ($) $ in Millions				12 Months Ended
	Aug. 20, 2015	Dec. 01, 2014	Dec. 13, 2013	Dec. 31, 2015
SHAREHOLDERS' EQUITY
Shelf registration statement, amount			$ 200.0	$ 200.0
Maximum amount of securities to be issued in the form of first mortgage bonds				150.0
Amount that would remain available after giving effect to issuance of first mortgage bonds				$ 30.0
Issuance of first mortgage bonds	$ 60.0	$ 60.0
Effective period to use proceeds under shelf to fund capital expenditures, refinancings of existing debt or general corporate needs			3 years
Employee Stock Purchase Plan
Equity compensation
Shares available for issuance				764,645
2015 Stock Incentive Plan
Equity compensation
Shares available for issuance				496,766
Number of shares of common stock provided for grant				500,000
401 (k) plan and ESOP
Equity compensation
Shares available to be issued				129,616

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SHAREHOLDERS' EQUITY (Details 2)	12 Months Ended
	Dec. 31, 2015 USD ($) $ / shares	Dec. 31, 2014 USD ($) $ / shares	Dec. 31, 2013 USD ($) $ / shares
Dividends
Total earnings per weighted average share of common stock - diluted (in dollars per share | $ / shares	$ 1.29	$ 1.55	$ 1.48
Dividends paid per share (in dollars per share) | $ / shares	$ 1.04	$ 1.025	$ 1.005
Total dividends paid	$ 45,430,000	$ 44,381,000	$ 43,006,000
Retained earnings year-end balance	101,443,000	$ 90,276,000	$ 67,600,000
First quarterly dividend paid excluded from EDE Mortgage covenant	98,000
Cumulative aggregate amount up to which the entity may declare or pay any dividends as per EDE Mortgage covenant	$ 10,750,000
Maximum period for payment of dividend after the related date of declaration or notice of dividend as per EDE Mortgage covenant	60 days
Ratio of total indebtedness to total capitalization	0.625

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SHAREHOLDERS' EQUITY (Details 3) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Preferred stock issued (in shares)	0	0
Preferred stock outstanding (in shares)	0	0
Preferred stock
Preferred stock authorized (in shares)	2,500,000
Series A Participating Preference Stock
Preferred stock authorized (in shares)	500,000
Cumulative preferred stock
Preferred stock authorized (in shares)	5,000,000
Preferred stock, par value per share (in dollars per share)	$ 10.00

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LONG-TERM DEBT (Details) $ in Thousands				12 Months Ended
	Jun. 11, 2015 USD ($)	Oct. 15, 2014 USD ($)	Dec. 13, 2013 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
LONG-TERM DEBT
Less unamortized net discount				$ (633)	$ (686)
Total long-term debt, current and non current				863,257	803,481
Total long-term debt, current and non current				863,890
Current obligations of long term debt				(25,000)
Current obligations under capital lease				(310)	(292)
Total long-term debt				837,947	803,189
Shelf registration statement, amount			$ 200,000	200,000
Effective period to use proceeds under shelf to fund capital expenditures, refinancings of existing debt or general corporate needs			3 years
First mortgage bonds
LONG-TERM DEBT
Total long-term debt, current and non current				$ 758,000	698,000
First mortgage bonds | EDE
LONG-TERM DEBT
Number of consecutive months within the fifteen months preceding issuance to determine net earnings to annual interest requirement ratio				12 months
Number of months preceding issuance to determine net earnings to annual interest requirement ratio				15 months
Net earnings to annual interest requirement ratio				2
Maximum principal amount outstanding at any one time				$ 1,000,000
New bonds to be issued as a percentage of net property additions				60.00%
First mortgage bonds | EDE | Low end of range
LONG-TERM DEBT
Debt permitted to be issued on compliance of amount of retired bonds and percentage of net property additions covenant				$ 297,000
First mortgage bonds | EDG
LONG-TERM DEBT
Maximum principal amount outstanding at any one time				$ 300,000
Interest rate assumed on debt permitted to be issued on compliance of interest coverage ratio covenant (as a percent)				5.50%
Debt permitted to be issued on compliance of amount of retired bonds and percentage of net property additions covenant				$ 19,500
Number of most recent fiscal quarters used in calculating the interest coverage ratio as per the terms of debt instrument covenants				12 months
Ratio of EBITDA to interest charges, minimum				2.0
First mortgage bonds | EDG | High end of range
LONG-TERM DEBT
New bonds to be issued as a percentage of net property additions				75.00%
7.20% Series due 2016 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 25,000	$ 25,000
Interest rate, stated percentage				7.20%	7.20%
5.875% Series due 2037 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 80,000	$ 80,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				5.875%
6.375% Series due 2018 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 90,000	$ 90,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%	100.00%
Interest rate, stated percentage				6.375%	6.375%
4.65% Series due 2020 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 100,000	$ 100,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				4.65%	4.65%
5.20% Series due 2040 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 50,000	$ 50,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				5.20%
3.58% Series Due 2027 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 88,000	$ 88,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				3.58%	3.58%
3.59% Series due 2030
LONG-TERM DEBT
Aggregate principal amount of debt entered into in private placement	$ 60,000
Interest rate, stated percentage	3.59%
3.59% Series due 2030 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 60,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				3.59%
3.73% Series due 2033 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 30,000	$ 30,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				3.73%
4.32% Series due 2043 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 120,000	120,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				4.32%
4.27% Series due 2044
LONG-TERM DEBT
Aggregate principal amount of debt entered into in private placement		$ 60,000
Interest rate, stated percentage				4.27%
4.27% Series due 2044 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 60,000	60,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				4.27%
6.82% Series due 2036 | EDG
LONG-TERM DEBT
Total long-term debt, current and non current				$ 55,000	$ 55,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				6.82%	6.82%
Senior Notes, 6.70% Series due 2033
LONG-TERM DEBT
Total long-term debt, current and non current				$ 62,000	$ 62,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				6.70%	6.70%
Senior Notes, 5.80% Series due 2035
LONG-TERM DEBT
Total long-term debt, current and non current				$ 40,000	$ 40,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				5.80%	5.80%
Other.
LONG-TERM DEBT
Total long-term debt, current and non current				$ 3,890	$ 4,167
New first mortgage bonds | EDE | Low end of range
LONG-TERM DEBT
Debt permitted to be issued on compliance of amount of retired bonds and percentage of net property additions covenant				297,000
New first mortgage bonds | EDE | High end of range
LONG-TERM DEBT
Debt permitted to be issued based on the limit on the principal amount and current level of outstanding bonds				$ 297,000

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LONG-TERM DEBT (Details 2) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long-Term Debt Payout Schedule
2016	$ 25,310
2017	329
2018	90,351
2019	375
2020	100,396
Thereafter	647,129
Total long-term debt obligations	863,890
Less current obligations and unamortized discount	25,943
Total long-term debt	837,947	$ 803,189
Regulated Entity Debt Obligations
Long-Term Debt Payout Schedule
2016	25,000
2018	90,000
2020	100,000
Thereafter	645,000
Total long-term debt obligations	860,000
Capital Lease Obligations
Long-Term Debt Payout Schedule
2016	310
2017	329
2018	351
2019	375
2020	396
Thereafter	2,129
Total long-term debt obligations	$ 3,890

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SHORT-TERM BORROWINGS (Details) $ in Thousands		12 Months Ended
	Oct. 20, 2014 USD ($) item	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Oct. 19, 2014 USD ($)
Short-Term Borrowings
Short-term borrowings		$ 25,000	$ 44,000
Average borrowings outstanding		48,900	30,000
Highest month-end balances		$ 97,000	$ 77,000
Weighted average interest rate during period (as a percent)		0.54	0.38
Weighted average interest rate at year end (as a percent)		0.84%	0.44%
Debt issuance costs		$ 818	$ 651	$ 1,879
Commercial paper
Short-Term Borrowings
Short-term borrowings		25,000
Outstanding borrowings		0
Amount of credit facility used to back up outstanding commercial paper borrowings		25,000
Unsecured revolving credit facility
Short-Term Borrowings
Outstanding borrowings		$ 0
Unsecured revolving credit facility	$ 200,000				$ 150,000
Maturity term	5 years
Number of extensions | item	2
Extension period	1 year
Facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings (as a percent)		0.175%
Debt issuance costs		$ 300
Maximum percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement		65.00%
Percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement		53.00%
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.		$ 25,000
Unsecured revolving credit facility | Federal fund effective rate
Short-Term Borrowings
Margin over the base rate (as a percent)		0.50%
Unsecured revolving credit facility | One month LIBOR
Short-Term Borrowings
Description of interest rate basis		one month LIBOR
Margin over the base rate (as a percent)		1.00%
Unsecured revolving credit facility | One month, two month or three month LIBOR
Short-Term Borrowings
Description of interest rate basis		one month, two month, three month or six month LIBOR
Margin over the base rate (as a percent)		1.025%
Letters of credit
Short-Term Borrowings
Unsecured revolving credit facility	$ 20,000
Additional borrowing capacity		$ 75,000
Swingline loan
Short-Term Borrowings
Unsecured revolving credit facility	$ 20,000

XML

RETIREMENT AND OTHER EMPLOYEE BENEFITS (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Amounts recognized in the balance sheet
Accounts payable and accrued liabilities				$ 66,946	$ 83,420
Pension and other postretirement benefit obligations				82,144	93,863
Effect of 1% change in assumed healthcare cost growth rates
Number of non-callable corporate bonds | item	500
Low end of range
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Maturity of non-cancellable corporate bonds	0 years
High end of range
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Maturity of non-cancellable corporate bonds	30 years
Pension Benefits
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Lump sum distribution	$ 15,300	$ 9,000
Increase (decrease) in net liability	(2,400)
Estimated contribution in next fiscal year	13,600
Reconciliation of Projected Benefit Obligations:
Benefit obligation at beginning of year	251,879	225,131
Amendments		(7,753)
Net actuarial (gain)/loss	(708)	36,742
Benefits and expenses paid	(25,201)	(19,527)
Benefit obligation at end of year	243,690	251,879	$ 225,131
Reconciliation of Fair Value of Plan Assets:
Fair value of plan assets at beginning of year	192,674	186,547
Actual return on plan assets gain/(loss)	(1,978)	14,319
Employer contribution	21,350	11,335
Benefits paid	(25,201)	(19,527)
Fair value of plan assets at end of year	186,845	192,674	186,547
Reconciliation of Funded Status:
Fair value of plan assets	192,674	186,547	186,547	186,845	192,674
Projected benefit obligations	(251,879)	(225,131)	(225,131)	(243,690)	(251,879)
Funded status				(56,845)	(59,205)
Employee pension plan accumulated benefit obligation
Accumulated benefit obligation				221,481	227,928
Amounts recognized in the balance sheet
Pension and other postretirement benefit obligations				56,845	59,205
Net Periodic Pension Benefit Cost:
Service cost	7,442	6,467	7,454
Interest cost	10,278	10,819	10,063
Expected return on plan assets	(13,567)	(13,105)	(12,428)
Amortization of prior service cost	(630)	418	532
Amortization of net actuarial loss	10,033	6,611	10,445
Net periodic benefit cost	13,556	11,210	16,066
Activity in the regulatory asset accounts
Beginning Balance	77,456	56,709
Current Year Actuarial (Gain)/Loss	14,836	35,529
Amortization of Actuarial Loss	(10,033)	(6,611)
Current Year Prior Service Credit		(7,753)
Amortization of Prior Service (Cost)/Credit	630	(418)
Ending Balance	82,889	77,456	56,709
Amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost
Net actuarial loss				88,981
Prior service cost (benefit)				(6,092)
Total	77,456	$ 56,709	$ 56,709	$ 82,889	$ 77,456
Amounts expected to be recognized in the subsequent year
Net actuarial loss	8,426
Prior service cost (benefit)	(630)
Total	$ 7,796
Weighted-average assumptions used to determine the benefit obligation
Discount rate (as a percent)				4.40%	4.06%
Rate of compensation increase (as a percent)				3.50%	3.50%
Weighted-average assumptions used to determine the net benefit cost (income)
Discount rate (as a percent)	4.06%	4.90%	4.00%
Expected return on plan assets (as a percent)	7.75%	7.75%	7.75%
Rate of compensation increase (as a percent)	3.50%	3.50%	3.50%
Pension Benefits | Payments from Trust
Expected benefit payments
2016				$ 22,500
2017				22,800
2018				21,500
2019				20,000
2020				20,900
2021 - 2025				97,400
Pension Benefits | Payments from Company Funds
Expected benefit payments
2016				500
2017				600
2018				500
2019				500
2020				800
2021 - 2025				2,900
SERP
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Increase (decrease) in net liability	$ 700
Reconciliation of Projected Benefit Obligations:
Benefit obligation at beginning of year	9,155	$ 7,108
Amendments		(45)
Net actuarial (gain)/loss	557	1,890
Benefits and expenses paid	(366)	(338)
Benefit obligation at end of year	9,886	9,155	$ 7,108
Reconciliation of Funded Status:
Projected benefit obligations	(9,155)	(7,108)	(7,108)	(9,886)	$ (9,155)
Funded status				(9,886)	(9,155)
Employee pension plan accumulated benefit obligation
Accumulated benefit obligation				8,609	7,160
Amounts recognized in the balance sheet
Accounts payable and accrued liabilities				534	481
Pension and other postretirement benefit obligations				9,352	8,674
Net Periodic Pension Benefit Cost:
Service cost	158	153	135
Interest cost	382	387	315
Amortization of prior service cost	(42)	(8)	(8)
Amortization of net actuarial loss	597	504	567
Net periodic benefit cost	1,095	1,036	1,009
Activity in the regulatory asset accounts
Beginning Balance	5,537	4,188
Current Year Actuarial (Gain)/Loss	557	1,890
Amortization of Actuarial Loss	(597)	(504)
Current Year Prior Service Credit		(45)
Amortization of Prior Service (Cost)/Credit	42	8
Ending Balance	5,539	5,537	4,188
Amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost
Net actuarial loss				5,555
Prior service cost (benefit)				(16)
Total	5,537	4,188	4,188	5,539	5,537
Amounts expected to be recognized in the subsequent year
Net actuarial loss	555
Prior service cost (benefit)	(14)
Total	541
OPEB
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Increase (decrease) in net liability	(10,000)
Estimated contribution in next fiscal year	$ 4,900
Expected benefit payments
Eligible age	55 years
Minimum service period for eligibility	5 years
Reconciliation of Projected Benefit Obligations:
Benefit obligation at beginning of year	$ 109,899	85,332
Net actuarial (gain)/loss	(14,358)	20,347
Plan participant's contribution	963	850
Benefits and expenses paid	(3,839)	(3,897)
Federal subsidy	419	306
Benefit obligation at end of year	101,467	109,899	85,332
Reconciliation of Fair Value of Plan Assets:
Fair value of plan assets at beginning of year	83,776	79,098
Actual return on plan assets gain/(loss)	(955)	5,030
Employer contribution	4,903	2,258
Benefits paid	(3,670)	(3,707)
Plan participant's contribution	912	804
Federal subsidy	403	293
Fair value of plan assets at end of year	85,369	83,776	79,098
Reconciliation of Funded Status:
Fair value of plan assets	83,776	79,098	79,098	85,369	83,776
Projected benefit obligations	(109,899)	(85,332)	(85,332)	(101,467)	(109,899)
Funded status				(16,098)	(26,123)
Amounts recognized in the balance sheet
Accounts payable and accrued liabilities				151	139
Pension and other postretirement benefit obligations				15,947	25,984
Net Periodic Pension Benefit Cost:
Service cost	3,713	2,601	2,941
Interest cost	4,670	4,360	3,827
Expected return on plan assets	(5,197)	(4,801)	(4,353)
Amortization of prior service cost	(1,011)	(1,011)	(1,011)
Amortization of net actuarial loss	2,747	967	2,261
Net periodic benefit cost	4,922	2,116	3,665
Activity in the regulatory asset accounts
Beginning Balance	20,446	285
Current Year Actuarial (Gain)/Loss	(8,208)	20,117
Amortization of Actuarial Loss	(2,747)	(967)
Amortization of Prior Service (Cost)/Credit	1,011	1,011
Ending Balance	10,502	20,446	285
Amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost
Net actuarial loss				12,075
Prior service cost (benefit)				(1,573)
Total	20,446	$ 285	$ 285	$ 10,502	$ 20,446
Amounts expected to be recognized in the subsequent year
Net actuarial loss	1,030
Prior service cost (benefit)	(1,011)
Total	$ 19
Weighted-average assumptions used to determine the benefit obligation
Discount rate (as a percent)				4.48%	4.15%
Rate of compensation increase (as a percent)				3.50%	3.50%
Weighted-average assumptions used to determine the net benefit cost (income)
Discount rate (as a percent)	4.15%	5.00%	4.11%
Expected return on plan assets (as a percent)	6.52%	6.52%	6.52%
Rate of compensation increase (as a percent)	3.50%	3.50%	3.50%
Cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation
Cost trend rate assumed (as a percent)	7.00%
Decrease in trend rate through 2019 (as a percent)	0.50%
Ultimate rate (as a percent)	5.00%
Effect of 1% change in assumed healthcare cost growth rates
Effect of 1% increase on total of service and interest cost	$ 2,051
Effect of 1% decrease on total of service and interest cost	(1,530)
Effect of 1% increase on post-retirement benefit obligation	17,473
Effect of 1% decrease on post-retirement benefit obligation	$ (13,794)
OPEB | Payments from Trust
Expected benefit payments
2016				$ 2,800
2017				3,200
2018				3,500
2019				3,800
2020				4,100
2021 - 2025				25,000
OPEB | Expected Federal Subsidy
Estimated benefit payments
2016				400
2017				400
2018				500
2019				500
2020				600
2021 - 2025				3,700
OPEB | Payments from Company Funds
Expected benefit payments
2016				200
2017				200
2018				200
2019				200
2020				200
2021 - 2025				$ 800

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RETIREMENT AND OTHER EMPLOYEE BENEFITS (Details 2) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) $ / shares shares	Dec. 31, 2014 USD ($) $ / shares shares	Dec. 31, 2013 USD ($) $ / shares shares	Dec. 31, 2015 USD ($) item $ / shares shares	Dec. 31, 2014 USD ($) $ / shares shares	Dec. 31, 2013 USD ($) $ / shares shares
Actual return on plan assets:
Cash-Equivalent Securities with a maturity	1 year
Employee Stock Purchase Plan
Actual return on plan assets:
Common stock purchase price to eligible employees (as a percent)	90.00%
Percentage of Black-Scholes methodology used as a component to calculate value of lookback feature	90.00%
Percentage of maximum subscription price used as a component to calculate value of lookback feature	10.00%
Shares available for issuance | shares				764,645
Subscriptions outstanding (in shares) | shares				58,742	57,369	60,413
Maximum subscription price (in dollars per share) | $ / shares				$ 21.09	$ 21.43	$ 19.58
Shares of stock issued | shares	56,193	56,942	68,099
Stock issuance price (in dollars per share) | $ / shares				$ 21.01	$ 19.58	$ 17.95
Assumptions for valuation of shares
Fair value of grants (in dollars per share) | $ / shares	$ 3.58	$ 3.07	$ 2.78
Risk-free interest rate (as a percent)	0.26%	0.10%	0.14%
Dividend yield (as a percent)	4.40%	4.30%	4.60%
Expected volatility (as a percent)	21.00%	14.00%	14.00%
Expected life in months	12 months	12 months	12 months
Pension Benefits
Fair value measurements of plan assets
Period over which the market-related value is determined	5 years
Number of basic elements on which primary investment goals of the company for pension fund assets are based (in counts) | item				4
Target allocations for plan assets
Cash investment managers generally hold in their portfolios (as a percent)	10.00%
Fund assets measured at fair value
Fair value of plan assets	$ 192,674	$ 186,547	$ 186,547	$ 186,845	$ 192,674	$ 186,547
Percentage of Plan Assets				100.00%	100.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	192,674	186,547
Actual return on plan assets:
Fair value of plan assets at end of year	$ 186,845	192,674	186,547
Pension Benefits | Equity securities
Target allocations for plan assets
Target allocation (as a percent)	72.00%
Pension Benefits | Equity securities | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	80.00%
Pension Benefits | Equity securities | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	60.00%
Pension Benefits | Common collective trusts - domestic
Fund assets measured at fair value
Fair value of plan assets	$ 48,760	48,760		$ 46,182	$ 48,760
Percentage of Plan Assets				24.70%	25.30%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	48,760
Actual return on plan assets:
Fair value of plan assets at end of year	46,182	48,760
Pension Benefits | Common collective trusts - international
Fund assets measured at fair value
Fair value of plan assets	42,770	42,770		$ 41,928	$ 42,770
Percentage of Plan Assets				22.50%	22.20%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	42,770
Actual return on plan assets:
Fair value of plan assets at end of year	41,928	42,770
Pension Benefits | Short term investments
Fund assets measured at fair value
Fair value of plan assets	70	70		$ 71	$ 70
Percentage of Plan Assets				0.00%	0.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	70
Actual return on plan assets:
Fair value of plan assets at end of year	71	70
Pension Benefits | Equity long/short hedge funds
Fund assets measured at fair value
Fair value of plan assets	38,428	38,428		$ 37,970	$ 38,428
Percentage of Plan Assets				20.30%	20.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	38,428
Actual return on plan assets:
Fair value of plan assets at end of year	$ 37,970	38,428
Pension Benefits | Fixed income
Target allocations for plan assets
Target allocation (as a percent)	28.00%
Pension Benefits | Fixed income | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	40.00%
Pension Benefits | Fixed income | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	20.00%
Pension Benefits | Common collective trust fixed income
Fund assets measured at fair value
Fair value of plan assets	$ 62,646	62,646		$ 60,694	$ 62,646
Percentage of Plan Assets				32.50%	32.50%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	62,646
Actual return on plan assets:
Fair value of plan assets at end of year	$ 60,694	62,646
Pension Benefits | Comingled bond funds
Fund assets measured at fair value
Maximum high yield	25.00%
Pension Benefits | Significant Other Observable Inputs (Level 2)
Fund assets measured at fair value
Fair value of plan assets	$ 154,246	154,246		$ 148,875	$ 154,246
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	154,246
Actual return on plan assets:
Fair value of plan assets at end of year	148,875	154,246
Pension Benefits | Significant Other Observable Inputs (Level 2) | Common collective trusts - domestic
Fund assets measured at fair value
Fair value of plan assets	48,760	48,760		46,182	48,760
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	48,760
Actual return on plan assets:
Fair value of plan assets at end of year	46,182	48,760
Pension Benefits | Significant Other Observable Inputs (Level 2) | Common collective trusts - international
Fund assets measured at fair value
Fair value of plan assets	42,770	42,770		41,928	42,770
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	42,770
Actual return on plan assets:
Fair value of plan assets at end of year	41,928	42,770
Pension Benefits | Significant Other Observable Inputs (Level 2) | Short term investments
Fund assets measured at fair value
Fair value of plan assets	70	70		71	70
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	70
Actual return on plan assets:
Fair value of plan assets at end of year	71	70
Pension Benefits | Significant Other Observable Inputs (Level 2) | Common collective trust fixed income
Fund assets measured at fair value
Fair value of plan assets	62,646	62,646		60,694	62,646
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	62,646
Actual return on plan assets:
Fair value of plan assets at end of year	60,694	62,646
Pension Benefits | Significant Unobservable Inputs (Level 3)
Fund assets measured at fair value
Fair value of plan assets	38,428	38,428		37,970	38,428
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	38,428
Actual return on plan assets:
Fair value of plan assets at end of year	37,970	38,428
Pension Benefits | Significant Unobservable Inputs (Level 3) | Equity long/short hedge funds
Fund assets measured at fair value
Fair value of plan assets	38,428	36,729	36,729	37,970	38,428	36,729
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	38,428	36,729
Actual return on plan assets:
Relating to assets still held at the reporting date	(458)	1,382
Relating to assets sold during the period		1,491
Purchases		9,700
Sales		(10,874)
Fair value of plan assets at end of year	37,970	38,428	36,729
OPEB
Fund assets measured at fair value
Fair value of plan assets	83,776	79,098	79,098	$ 85,369	$ 83,776	$ 79,098
Percentage of Plan Assets				100.00%	100.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	83,776	79,098
Actual return on plan assets:
Fair value of plan assets at end of year	$ 85,369	83,776	$ 79,098
OPEB | Equity securities
Target allocations for plan assets
Target allocation (as a percent)	60.00%
OPEB | Equity securities | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	76.00%
OPEB | Equity securities | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	44.00%
OPEB | Common collective trust equity securities
Fund assets measured at fair value
Fair value of plan assets	$ 47,690	47,690		$ 48,553	$ 47,690
Percentage of Plan Assets				56.90%	56.90%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	47,690
Actual return on plan assets:
Fair value of plan assets at end of year	48,553	47,690
OPEB | Fund assets
Fund assets measured at fair value
Fair value of plan assets	83,851	83,851		$ 85,504	$ 83,851
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	83,851
Actual return on plan assets:
Fair value of plan assets at end of year	$ 85,504	83,851
OPEB | Cash and cash equivalents | High end of range
Target allocations for plan assets
Target allocation (as a percent)	10.00%
OPEB | Fixed income
Target allocations for plan assets
Target allocation (as a percent)	40.00%
OPEB | Fixed income | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	44.00%
OPEB | Fixed income | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	36.00%
OPEB | Common collective trust fixed income
Fund assets measured at fair value
Fair value of plan assets	$ 33,708	33,708		$ 34,395	$ 33,708
Percentage of Plan Assets				40.30%	40.20%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	33,708
Actual return on plan assets:
Fair value of plan assets at end of year	34,395	33,708
OPEB | Common collective trusts
Fund assets measured at fair value
Fair value of plan assets	2,453	2,453		$ 2,556	$ 2,453
Percentage of Plan Assets				3.00%	2.90%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	2,453
Actual return on plan assets:
Fair value of plan assets at end of year	2,556	2,453
OPEB | Payable for securities purchased
Fund assets measured at fair value
Fair value of plan assets	(75)	(75)		$ (135)	$ (75)
Percentage of Plan Assets				(0.20%)	0.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	(75)
Actual return on plan assets:
Fair value of plan assets at end of year	(135)	(75)
OPEB | Significant Other Observable Inputs (Level 2) | Common collective trust equity securities
Fund assets measured at fair value
Fair value of plan assets	47,690	47,690		$ 48,553	$ 47,690
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	47,690
Actual return on plan assets:
Fair value of plan assets at end of year	48,553	47,690
OPEB | Significant Other Observable Inputs (Level 2) | Fund assets
Fund assets measured at fair value
Fair value of plan assets	83,851	83,851		85,504	83,851
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	83,851
Actual return on plan assets:
Fair value of plan assets at end of year	85,504	83,851
OPEB | Significant Other Observable Inputs (Level 2) | Common collective trust fixed income
Fund assets measured at fair value
Fair value of plan assets	33,708	33,708		34,395	33,708
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	33,708
Actual return on plan assets:
Fair value of plan assets at end of year	34,395	33,708
OPEB | Significant Other Observable Inputs (Level 2) | Common collective trusts
Fund assets measured at fair value
Fair value of plan assets	2,453	2,453		$ 2,556	$ 2,453
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	2,453
Actual return on plan assets:
Fair value of plan assets at end of year	$ 2,556	$ 2,453
401 (k) plan and ESOP
Employee 401k and Stock Ownership Plan, ESOP Disclosures [Abstract]
Maximum percentage of annual compensation to be deferred by participating employees	25.00%
Shares available to be issued | shares				129,616
Shares contributed | shares	66,783	60,049	64,128
Cash balance formula
Employee 401k and Stock Ownership Plan, ESOP Disclosures [Abstract]
Percentage of each employee's deferrals to be matched	100.00%
Maximum matching contribution as a percentage of employee's eligible compensation	6.00%
Percentage of matching contribution made in shares	3.00%
Average annual basic earnings formula
Employee 401k and Stock Ownership Plan, ESOP Disclosures [Abstract]
Percentage of each employee's deferrals to be matched	50.00%
Maximum matching contribution as a percentage of employee's eligible compensation	3.00%

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EQUITY COMPENSATION (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
EQUITY COMPENSATION
Compensation Expense	$ 4,279	$ 3,688	$ 2,577
Tax Benefit Recognized	$ 1,576	1,359	$ 929
2015 Stock Incentive Plan
Fair value
Number of shares of common stock provided for grant	500,000
Shares available for issuance	496,766
Performance-Based Restricted Stock Awards
Assumptions used for estimating fair value of grants outstanding
Unrecognized compensation expense	$ 700	$ 1,100
Vesting period	3 years
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)	63,300	47,200	33,900
Target shares granted (in shares)	21,800	27,000	26,300
Shares issued in excess of target (in shares)	3,653
Shares awarded (in shares)	(13,653)		(4,460)
Forfeited shares (in shares)	(6,079)
Target shares not awarded (in shares)		(10,900)	(8,540)
Nonvested, balance at the end of the period (in shares)	69,021	63,300	47,200
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)	$ 21.74	$ 21.39	$ 20.25
Granted (in dollars per share)	$ 30.40
Target shares granted (in dollars per share)		22.40	21.36
Shares issued in excess of target (in dollars per share)	20.97
Shares awarded (in dollars per share)	$ 20.97		18.36
Forfeited shares ( in dollars per share)	24.10
Target shares not awarded (in dollars per share)		21.84	18.36
Nonvested, balance at the end of the period (in dollars per share)	$ 24.38	$ 21.74	$ 21.39
Assumptions for valuation of shares
Risk-free interest rate, low end of range (as a percent)	0.65%	0.25%	0.13%
Risk-free interest rate, high end of range (as a percent)	1.06%	0.67%	0.38%
Expected dividend yield (as a percent)	3.70%	3.50%	4.50%
Expected forfeiture rates (as a percent)	3.00%	3.00%	3.00%
Plan cycle	3 years	3 years	3 years
Weighted average fair value per share (in dollars per share)	$ 41.70	$ 43.80	$ 18.47
Expected volatility (as a percent)	18.70%	14.50%	20.20%
Fair value
Threshold performance level set at percentile level of peer group (as a percent)	20.00%	20.00%	20.00%
Target performance level set at percentile level of peer group (as a percent)	50.00%	50.00%	50.00%
Maximum performance level set at percentile level of peer group (as a percent)	80.00%	80.00%	80.00%
Percentage of shares granted on reaching target performance level	100.00%
Percentage of shares granted on reaching threshold performance level	50.00%
Percentage of shares granted on reaching maximum performance level	200.00%
Performance-Based Restricted Stock Awards | Low end of range
Assumptions for valuation of shares
Expected volatility of peer group stock (as a percent)	14.50%	12.40%	12.30%
Fair value percentage	115.00%	140.00%	0.00%
Performance-Based Restricted Stock Awards | High end of range
Assumptions for valuation of shares
Expected volatility of peer group stock (as a percent)	34.40%	24.80%	27.50%
Fair value percentage	182.00%	157.00%	108.00%
Time-Vested Restricted Stock Awards
Assumptions used for estimating fair value of grants outstanding
Unrecognized compensation expense	$ 400	$ 400
Vesting period	3 years
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)	41,000	24,900	3,300
Granted (in shares)	19,000	22,600	21,600
Distributed (in shares)	(1,654)	(4,010)
Forfeited shares (in shares)	(2,746)	(2,490)
Nonvested, balance at the end of the period (in shares)	55,600	41,000	24,900
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)	$ 21.89	$ 21.42	$ 21.84
Granted (in dollars per share)	30.40	22.40	21.36
Distributed (in dollars per share)	21.92	21.77
Forfeited shares ( in dollars per share)	25.91	21.99
Nonvested, balance at the end of the period (in dollars per share)	24.60	21.89	$ 21.42
Fair value
Fair value (in dollars per share)	$ 25.17	$ 26.82
Time-Vested Restricted Stock Awards | Low end of range
Fair value
Recognition period	1 month 6 days	1 year 1 month 6 days
Time-Vested Restricted Stock Awards | High end of range
Fair value
Recognition period	2 years 1 month 6 days	2 years 1 month 6 days
Stock Options
Assumptions used for estimating fair value of grants outstanding
Vesting period	3 years
Stock options, expiration term	10 years
Stock options or divident equivalents granted	0	0	0
Outstanding options	0	0	112,500	163,300
Assumptions for valuation of shares
Risk-free interest rate, low end of range (as a percent)			0.10%
Risk-free interest rate, high end of range (as a percent)			0.38%
Expected dividend yield (as a percent)			4.50%
Expected volatility (as a percent)			24.00%
Market value (in dollars per share)			$ 22.69
Weighted average fair value per option (in dollars per share)			$ 1.57
Stock Options | Low end of range
Assumptions for valuation of shares
Expected life in months			6 months 15 days
Stock Options | High end of range
Assumptions for valuation of shares
Expected life in months			24 months 15 days

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EQUITY COMPENSATION (Details 2) - Stock Options - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock options
Outstanding, balance at the beginning of the period (in shares)	0	112,500	163,300
Exercised (in shares)		112,500	(50,800)
Outstanding, balance at the end of the period (in shares)	0	0	112,500
Exercisable (in shares)			112,500
Weighted Average Exercise Price
Outstanding, balance at the beginning of the period (in dollars per option)		$ 23.27	$ 22.13
Exercised (in dollars per share)		$ 24.58	21.78
Outstanding, balance at the end of the period (in dollars per option)			23.27
Exercisable (in dollars per share)			$ 23.27
Intrinsic value of unexercised options if closing price of stock is less than the exercise price (in dollars per share)	$ 0.00
Aggregate intrinsic value
Weighted-average remaining contractual life of outstanding options			2 years 1 month 6 days
Range of exercise prices, low end of range (in dollars per share)			$ 21.92
Range of exercise prices, high end of range (in dollars per share)			$ 23.81
Assumptions for valuation of shares
Dividend yield (as a percent)			4.50%
Expected volatility (as a percent)			24.00%
High end of range
Aggregate intrinsic value
Aggregate intrinsic values			$ 0.1
Assumptions for valuation of shares
Expected life in months			24 months 15 days

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EQUITY COMPENSATION (Details 3) - Stock Unit Plan for directors - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assumptions used for estimating fair value of grants outstanding
Number of shares authorized under the plan	900,000
Number of shares accrued in director's accounts	157,672	164,085
Shares available for issuance	677,980	714,978
Units accrued for service and dividends (in shares)	30,595	30,765	34,252
Units redeemed for common stock (in shares)	37,008	21,083	22,908

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INCOME TAXES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2010
Current income taxes:
Federal		$ (2,350,000)	$ 6,726,000
State		(123,000)	2,495,000
TOTAL		(2,473,000)	9,221,000
Deferred income taxes:
Federal	$ 29,722,000	36,620,000	24,954,000
State	4,233,000	5,216,000	3,554,000
TOTAL	33,955,000	41,836,000	28,508,000
Investment tax credit amortization	(143,000)	(143,000)	(237,000)
TOTAL INCOME TAX EXPENSE	33,812,000	39,220,000	$ 37,492,000
Deferred tax assets and liabilities as reflected on consolidated balance sheet
NET DEFERRED TAX LIABILITIES	396,542,000	358,252,000
Deferred tax assets:
Plant related basis differences	27,347,000	25,349,000
Net operating loss	9,055,000	22,000,000
Disallowed plant costs	1,699,000	1,754,000
Gains on hedging transactions	1,195,000	1,260,000
Regulated liabilities related to income taxes	13,142,000	13,350,000
Pensions and other post-retirement benefits		1,175,000
Carry forward of income tax credit	8,675,000	6,367,000
Other	1,550,000	1,633,000
Total deferred tax assets	62,663,000	72,888,000
Deferred tax liabilities:
Depreciation, amortization and other plant related differences	382,897,000	363,337,000
Regulated assets related to income	38,615,000	37,180,000
Loss on reacquired debt	3,572,000	3,828,000
Amortization of intangibles	10,248,000	9,168,000
Pensions and other post-retirement benefits	7,112,000
Deferred construction accounting costs	5,711,000	6,082,000
Other	11,050,000	11,545,000
Total deferred tax liabilities	459,205,000	431,140,000
NET DEFERRED TAX LIABILITIES	$ 396,542,000	$ 358,252,000
Effective Income Tax Rates
Federal statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (as a percent)	3.10%	3.10%	3.10%
Investment tax credit amortization (as a percent)	(0.20%)	(0.10%)	(0.20%)
Effect of ratemaking on property related differences (as a percent)	(1.40%)	(1.70%)	(1.10%)
Other (as a percent)	0.90%	0.60%	0.30%
Consolidated provision for income taxes	$ 33,812,000	$ 39,220,000	$ 37,492,000
Consolidated effective federal and state income tax rates (as a percent)	37.40%	36.90%	37.10%
Net operating loss carryfowards		$ 74,100,000
Net operating losses estimated to be utilized		38,000,000
Deferred tax assets estimated to be utilized	$ 13,500,000
Advanced coal investment tax credit				$ 17,700,000
Maximum tax credit utilized			$ 9,000,000
Adjustment due to change in tax accounting method om deduction and capitalization of tangible property		29,000,000
Adjustment due to change in tax accounting method on deductibility of VEBA plan activity		$ 14,000,000

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COMMONLY OWNED FACILITIES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) mi MW	Dec. 31, 2014 USD ($)
COMMONLY OWNED FACILITIES
Proportionate ownership interest (as a percent)	12.00%
Distance of Iatan Generating Facility from Kansas city (in miles) | mi	35
Ownership interest in the site (as a percent)	3.00%
EDE
COMMONLY OWNED FACILITIES
Ownership interest in certain common facilities (as a percent)	12.00%
Iatan
COMMONLY OWNED FACILITIES
Proportionate ownership interest (as a percent)	12.00%
Amounts included in property, plant and equipment
Cost of ownership in plant in service	$ 380.2	$ 373.3
Accumulated Depreciation	105.3	99.1
Expenditures	$ 26.9	27.8
Iatan1 | KCP&L
COMMONLY OWNED FACILITIES
Ownership interest in the site (as a percent)	70.00%
Iatan1 | KCP&L Greater Missouri Operations Co.
COMMONLY OWNED FACILITIES
Ownership interest in the site (as a percent)	18.00%
Iatan2 | KCP&L
COMMONLY OWNED FACILITIES
Ownership interest in the site (as a percent)	54.00%
Iatan2 | KCP&L Greater Missouri Operations Co.
COMMONLY OWNED FACILITIES
Ownership interest in the site (as a percent)	18.00%
State Line Combined Cycle Unit
Amounts included in property, plant and equipment
Cost of ownership in plant in service	$ 163.0	161.5
Accumulated Depreciation	43.5	40.0
Expenditures	$ 40.7	47.1
Power capacity (in megawatts) | MW	500
State Line Combined Cycle Unit | EDE
COMMONLY OWNED FACILITIES
Percentage share in available capacity	60.00%
Plum point
Amounts included in property, plant and equipment
Cost of ownership in plant in service	$ 109.1	108.3
Accumulated Depreciation	11.9	9.4
Expenditures	$ 9.6	$ 8.1
Plum point | EDE
COMMONLY OWNED FACILITIES
Proportionate ownership interest (as a percent)	7.52%

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COMMITMENTS AND CONTINGENCIES (Detail) $ in Thousands			12 Months Ended
	Dec. 15, 2008	Dec. 15, 2005	Dec. 31, 2015 USD ($) item MW	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Commitments and Contingencies
Period of the average cost that is used as a basis for determining the maximum annual payments		20 years
Electric | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Construction costs year to date			$ 159,600
Cost related to pre-engineering, site preparation activities and contract cost year to date				$ 112,100
Electric | Low end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			165,000
Electric | High end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			175,000
Firm Physical gas and transportation contracts
Commitments and Contingencies
January 1, 2016 through December 31, 2016			26,700
January 1, 2017 through December 31, 2018			37,400
January 1, 2019 through December 31, 2020			28,800
January 1, 2021 and beyond			45,700
Coal and coal transportation contracts
Commitments and Contingencies
January 1, 2016 through December 31, 2016			18,000
January 1, 2017 through December 31, 2018			27,500
January 1, 2019 through December 31, 2020			$ 10,800
Purchased power | Plum Point Energy Station
Commitments and Contingencies
Energy capacity (in megawatts) | MW			670
Amount of energy capacity owned (in megawatts) | MW			50
Additional capacity under long-term contract agreement (in megawatts) | MW			50
Amount of long-term contract obligation			$ 277,600
Amount of energy capacity under option to purchase (in megawatts) | MW			50
Purchased power | Cloud County Windfarm
Commitments and Contingencies
Energy capacity (in megawatts) | MW			105
Period of the average cost that is used as a basis for determining the maximum annual payments	20 years
Purchased power | Cloud County Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 0
Purchased power | Cloud County Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 14,600
Purchased power | Elk River Windfarm
Commitments and Contingencies
Energy capacity (in megawatts) | MW			150
Purchased power | Elk River Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 0
Purchased power | Elk River Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			16,900
Leases
Commitments and Contingencies
Gross amount of assets recorded under capital leases			5,300
Capital leases, 2016			554
Capital leases, 2017			551
Capital leases, 2018			551
Capital leases, 2019			550
Capital leases, 2020			546
Capital leases, thereafter			2,460
Capital leases, total minimum payments			5,212
Capital leases, amount representing interest			1,322
Capital leases, present value of net minimum lease payments			3,890
Operating leases, 2016			734
Operating leases, 2017			689
Operating leases, 2018			648
Operating leases, 2019			484
Operating leases, total minimum payments			2,555
Expenses incurred related to operating leases			800	800	$ 800
Accumulated amount of amortization of capital leases			$ 1,900	$ 1,500
Leases | Electric
Commitments and Contingencies
Number of unit trains under short-term operating leases | item			2
Leases | Gas
Commitments and Contingencies
Number of office facilities under short-term operating leases | item			1
Leases | Plum Point Energy Station
Commitments and Contingencies
Number of railcars under capital leases | item			108

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COMMITMENTS AND CONTINGENCIES (Details 2) $ in Thousands			12 Months Ended
	Jan. 26, 2016 state	Feb. 10, 2015 item	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Environmental Laws And Regulations
Number of states initiating legal challenges to invalidate rule | state	25
Asset retirement obligation			$ 15,072	$ 4,847	$ 4,190
Regulatory assets of Missouri solar initiative			209,708	$ 209,717
Asbury Power Plant
Environmental Laws And Regulations
Asset retirement obligation			5,400
Iatan Generating Station
Environmental Laws And Regulations
Asset retirement obligation			4,400
Surface Impoundments | Electric | High end of range
Environmental Laws And Regulations
Potential cost for construction of new landfill and conversion of existing ash handling from wet to dry system(s)			$ 15,000
Renewable Energy | Electric
Environmental Laws And Regulations
Minimum percentage of Missouri retail sales required to generate or purchase electricity in 2014			5.00%
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2021			15.00%
Percentage of Missouri retail sales required to generate or purchase solar energy			2.00%
Number of laws harmonized | item		2
Number of solar rebate applications processed in Missouri solar initiative | item			262
Rebate Commitments in Missouri solar initiative			$ 3,500
Regulatory assets of Missouri solar initiative			$ 3,500
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2020			20.00%
Green House Gases
Environmental Laws And Regulations
Percentage of carbon emission reduction from 2005 baseline levels by 2030, required by the proposed Clean Power Plan			32.00%
Number of plan types for states to choose to meet their goals | item			2

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SEGMENT INFORMATION (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	$ 136,758	$ 169,714	$ 134,557	$ 164,544	$ 151,363	$ 171,512	$ 149,782	$ 179,673	$ 605,573	$ 652,330	$ 594,330
Depreciation and amortization									80,550	73,185	69,306
Federal and state income taxes									33,812	39,220	37,492
Operating income	19,757	35,783	16,047	24,713	19,300	31,709	19,502	29,488	96,301	99,999	99,663
Interest income									145	51	566
Interest expense									45,103	41,740	41,479
Income from AFUDC (debt and equity)									7,695	9,917	5,940
Income from continuing operations									56,597	67,103	63,445
Net income	9,905	25,285	6,770	14,637	11,112	23,892	11,194	20,905	56,597	67,103	63,445
Capital Expenditures									176,524	222,853	160,208
Total assets	2,455,303				2,371,056				2,455,303	2,371,056
Goodwill	39,492				39,492				39,492	39,492
SPP IM
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	2,900	$ 4,000	$ 3,400	$ 4,700	7,500	$ 11,500	$ 16,500	$ 6,200
Electric
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									555,085	592,491	536,413
Depreciation and amortization									74,732	67,534	63,659
Federal and state income taxes									31,123	35,737	34,478
Operating income									88,124	90,488	90,984
Interest income									133	37	537
Interest expense									41,307	37,911	37,683
Income from AFUDC (debt and equity)									7,681	9,833	5,910
Income from continuing operations									52,240	61,467	58,603
Capital Expenditures									169,111	212,866	153,401
Total assets	2,339,850				2,252,339				2,339,850	2,252,339
Electric | SPP IM
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									15,000	41,900
Gas
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									41,702	51,842	50,041
Depreciation and amortization									3,923	3,760	3,709
Federal and state income taxes									800	1,840	1,484
Operating income									5,153	6,775	6,194
Interest income									36	25	115
Interest expense									3,867	3,861	3,890
Income from AFUDC (debt and equity)									14	84	30
Income from continuing operations									1,287	2,965	2,355
Capital Expenditures									5,190	7,836	4,419
Total assets	127,871				130,856				127,871	130,856
Goodwill	39,492				39,492				39,492	39,492
Other
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									10,165	9,302	9,147
Depreciation and amortization									1,895	1,891	1,938
Federal and state income taxes									1,889	1,643	1,530
Operating income									3,024	2,736	2,485
Interest income									47	21	8
Income from continuing operations									3,070	2,671	2,487
Capital Expenditures									2,223	2,151	2,388
Total assets	38,300				34,655				38,300	34,655
Eliminations
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									(1,379)	(1,305)	(1,271)
Interest income									(71)	(32)	(94)
Interest expense									(71)	(32)	$ (94)
Total assets	$ (50,718)				$ (46,794)				$ (50,718)	$ (46,794)

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SELECTED QUARTERLY INFORMATION (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues	$ 136,758	$ 169,714	$ 134,557	$ 164,544	$ 151,363	$ 171,512	$ 149,782	$ 179,673	$ 605,573	$ 652,330	$ 594,330
Operating income	19,757	35,783	16,047	24,713	19,300	31,709	19,502	29,488	96,301	99,999	99,663
Net income	$ 9,905	$ 25,285	$ 6,770	$ 14,637	$ 11,112	$ 23,892	$ 11,194	$ 20,905	$ 56,597	$ 67,103	$ 63,445
Basic Earnings Per Share	$ 0.23	$ 0.58	$ 0.16	$ 0.34
Diluted Earnings Per Share	$ 0.23	$ 0.58	$ 0.15	$ 0.34
Basic and Diluted Earnings Per Share					$ 0.26	$ 0.55	$ 0.26	$ 0.48
SPP IM
Operating revenues	$ 2,900	$ 4,000	$ 3,400	$ 4,700	$ 7,500	$ 11,500	$ 16,500	$ 6,200

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RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair value of derivative financial instruments
Current assets	$ 1,295	$ 3,901
Total derivatives assets	1,311	3,901
Current liabilities	4,472	6,469
Non-current liabilities and deferred credits	3,696	3,243
Total derivatives liabilities	8,168	9,712
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Gas
Fair value of derivative financial instruments
Current assets	2
Non-current other assets	16
Current liabilities	282	476
Non-current liabilities and deferred credits	66
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Electric
Fair value of derivative financial instruments
Current assets		1
Current liabilities	4,190	5,993
Non-current liabilities and deferred credits	3,630	3,243
Non-designated as hedging instruments due to regulatory accounting | Transmission congestion rights (TCR) | Electric
Fair value of derivative financial instruments
Current assets	$ 1,293	$ 3,900

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RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Electric
Gain / (Loss) on derivatives
Unrealized net losses applicable to financial instruments which will settle in next twelve months	$ 4,200
Period within which financial instruments will settle	12 months
Amount of Gain/(Loss) Recognized on Balance Sheet	$ (1,883)	$ 6,178
Amount of Gain / (Loss) Recognized in Income on Derivative	(647)	9,447
Mark-to-market pre-tax gains/(losses) from ineffective portions	0	0
Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(447)	(511)
Commodity contracts | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(6,853)	(6,780)
Amount of Gain / (Loss) Recognized in Income on Derivative	(8,115)	(1,659)
Commodity contracts | Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(447)	(511)
Transmission congestion rights (TCR) | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	4,970	12,958
Amount of Gain / (Loss) Recognized in Income on Derivative	$ 7,468	$ 11,106

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RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 3)	12 Months Ended
	Dec. 31, 2015 USD ($) item MWh $ / item
Transmission congestion rights (TCR) - 2015
Procurement guidelines
Monthly MWH Hedged | MWh	3,212.00
Monthly MWH Hedged, estimated fair value | $	$ 1,292,943
Electric | Natural Gas Usage - 2016
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	61.00%
Dth Hedged Physical	2,706,000
Dth Hedged Financial	5,940,000
Average Price (in dollars per dth) | $ / item	3.372
Electric | Natural Gas Usage - 2017
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	41.00%
Dth Hedged Physical	782,900
Dth Hedged Financial	5,210,000
Average Price (in dollars per dth) | $ / item	3.347
Electric | Natural Gas Usage - 2018
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Dth Hedged Physical	565,000
Dth Hedged Financial	2,460,000
Average Price (in dollars per dth) | $ / item	3.334
Electric | Natural Gas Forward 2019
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Dth Hedged Financial	1,460,000
Average Price (in dollars per dth) | $ / item	2.955
Electric | Natural Gas Forward 2020
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	0.00%
Electric | Current Year Procurement Guidelines
Procurement guidelines
Maximum percentage of volume to be hedged in any given month	100.00%
Maximum flexibility to hedge any future year's expected requirements (as a percent)	80.00%
Electric | First Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	60.00%
Electric | Second Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	40.00%
Electric | Third Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Electric | Fourth Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Electric | High end of range | Current Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	100.00%

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RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 4) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($)
Contingent Features
Derivative instruments with the credit-risk-related contingent features that are in a liability position | $	$ 0.0
Collateral posted | $	0.0
Margin deposit liabilities | $	0.0
Margin deposit assets
Margin deposit assets | $	$ 11.2	$ 9.1
Gas
Price Risk Mitigation for Gas Segment
Target percentage of storage capacity utilization	95.00%
Volume of storage in pipelines that serve customers (in Dth)	1,400,000
Number of pipelines that serve customers (in units)	3
Storage capacity utilized (as a percent)	70.00%
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	2
Gas | Current Winter Season
Gas Usage Hedged By Winter Season
Minimum % Hedged	50.00%
Dth Hedged Financial	400,000,000
Dth in Storage	1,419,752,000
Actual % Hedged	93.00%
Gas | High end of range | Second Winter Season
Gas Usage Hedged By Winter Season
Minimum % Hedged	50.00%
Dth Hedged Financial	200,000,000
Actual % Hedged	6.00%
Gas | High end of range | Third Winter Season
Gas Usage Hedged By Winter Season
Minimum % Hedged	20.00%
Dth Hedged Financial	280,000,000
Actual % Hedged	9.00%

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FAIR VALUE MEASUREMENTS (Details) - Recurring basis - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Measurements at Reporting Date
Derivative assets	$ 1,311	$ 3,901
Derivative liabilities	(8,168)	(9,712)
Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)
Fair Value Measurements at Reporting Date
Derivative assets	18	1
Derivative liabilities	(8,168)	(9,712)
Significant Other Observable Inputs (Level 2)
Fair Value Measurements at Reporting Date
Derivative assets	$ 1,293	$ 3,900

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FAIR VALUE MEASUREMENTS (Details 2) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Long-Term Debt
Carrying amount of total long-term debt exclusive of capital leases	$ 859	$ 799
Fair market value	$ 815	$ 829

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REGULATED OPERATING EXPENSE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REGULATED OPERATING EXPENSE
Electric transmission and distribution expense	$ 28,893	$ 27,919	$ 21,863
Natural gas transmission and distribution expense	2,699	2,362	2,498
Power operation expense (other than fuel)	18,263	16,089	15,643
Customer accounts and assistance expense	10,937	11,239	11,180
Employee pension expense	10,786	10,590	10,736
Employee healthcare expense	10,162	9,147	10,190
General office supplies and expense	14,438	15,024	12,850
Administrative and general expense	14,863	14,385	14,800
Allowance for uncollectible accounts	2,080	3,420	3,665
Regulatory reversal of gain on sale of assets		44	1,236
Miscellaneous expense	430	472	672
Total	$ 113,551	$ 110,691	$ 105,333

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SUBSEQUENT EVENT - AGREEMENT AND PLAN OF MERGER (Details) - USD ($)	Feb. 09, 2016	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Subsequent event
Transaction costs				$ 200,000
Subsequent event
Subsequent event
Termination fee	$ 53,000,000
Subsequent event | Liberty Utilities (Central) Co
Subsequent event
Righ to receive in cash without interest	$ 34.00
Maximum period for extending regulatory approvals	6 months
Maximum period for exercising termination right	9 months
Forecast
Subsequent event
Transaction costs			$ 4,500,000
Percentage payable of transaction costs		50.00%
Forecast | High end of range
Subsequent event
Transaction costs		$ 17,000,000
Forecast | Low end of range
Subsequent event
Transaction costs		$ 15,000,000
Liberty Utilities (Central) Co | Subsequent event
Subsequent event
Termination fee	$ 65,000,000

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SCHEDULE II - Valuation and Qualifying Accounts (Details) - Reserve deducted from assets: accumulated provision for uncollectible accounts. - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Valuation and Qualifying Accounts
Balance At Beginning Of Period	$ 1,020,637	$ 1,025,177	$ 1,387,673
Charged To Income	2,266,976	3,463,797	2,213,988
Charged to Other Accounts	2,079,751	2,128,325	2,013,959
Deductions From Reserve	4,744,648	5,596,662	4,590,443
Balance At Close of Period	$ 622,716	$ 1,020,637	$ 1,025,177