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

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):

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

The aggregate market value of the registrant's voting common stock held by nonaffiliates of the registrant, based on the closing price on the New York Stock Exchange on June 30, 2014, was approximately $1,112,837,946.

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

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

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

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

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.

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

We supply electric service at retail to 119 incorporated communities as of December 31, 2014, and to various unincorporated areas and at wholesale to four municipally owned distribution systems. The largest urban area we serve is the city of Joplin, Missouri, and its immediate vicinity, with a population of approximately 160,000. We operate under franchises having original terms of twenty years or longer in virtually all of the incorporated communities. Approximately 55% of our electric operating revenues in 2014 were derived from incorporated communities with franchises having at least ten years remaining and approximately 15% were derived from incorporated communities in which our franchises have remaining terms of ten years or less. Although our franchises contain no renewal provisions, in recent years we have obtained renewals of all of our expiring electric franchises prior to the expiration dates.

Our three largest classes of on-system customers are residential, commercial and industrial, which provided 40.0%, 29.2%, and 14.4%, respectively, of our electric operating revenues in 2014.

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

Our gas operations serve customers in northwest, north central and west central Missouri. As of December 31, 2014, our gas operations served approximately 43,500 customers. We provide natural gas distribution to 48 communities and 422 transportation customers as of December 31, 2014. The largest urban area we serve is the city of Sedalia with a population of over 20,000. We operate under franchises having original terms of twenty years in virtually all of the incorporated communities. Eighteen of the

franchises have 10 years or more remaining on their term and 26 of the franchises have less than 10 years remaining on their term. Although our franchises contain no renewal provisions, since our acquisition we have obtained renewals of all our expiring gas franchises prior to the expiration dates.

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

Our generating capacity consists of 66.1% natural gas, 32.7% coal and 1.2% hydro. We currently supplement our on-system generating capacity with purchases of capacity and energy from other sources in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council rules. The Southwest Power Pool (SPP) requires its members (including Empire) to maintain a minimum 12% capacity margin.

We have a long-term (30 year) agreement for the purchase of 50 megawatts of capacity from the Plum Point Energy Station (Plum Point), a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We began receiving purchased power under this agreement on September 1, 2010. We also own, through an undivided interest, 50 megawatts of the unit's capacity. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the Missouri Public Service Commission (MPSC) in mid-2013. It is not currently our intention to exercise this option in 2015.

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

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

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

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

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.

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

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

Total property additions (including construction work in progress but excluding AFUDC) for the three years ended December 31, 2014, totaled $505.1 million and retirements during the same period totaled $72.0 million. Please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources" for more information.

Our total capital expenditures, excluding AFUDC and expenditures to retire assets, were $207.2 million in 2014 and for the next three years are estimated for planning purposes to be as follows:

	Estimated Capital Expenditures (amounts in millions)

	2015		2016		2017		Total
New electric generating facilities:
Riverton Unit 12 combined cycle conversion	$	62.5	$	17.1	$	0.0	$	79.6
Additions to existing electric generating facilities:
Asbury		4.5		2.2		1.8		8.5
Environmental upgrades — Asbury		2.3		0.0		1.1		3.4
Other		11.3		7.6		15.8		34.7
Electric transmission facilities		33.1		30.3		25.6		89.0
Electric distribution system additions		40.8		37.0		45.9		123.7
General and other additions		11.6		8.8		8.9		29.3
Gas system additions		4.1		4.1		4.1		12.3
Non-regulated additions		2.5		2.1		2.3		6.9

TOTAL	$	172.7	$	109.2	$	105.5	$	387.4

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

Estimated capital expenditures are reviewed and adjusted for, among other things, revised estimates of future capacity needs, the cost of funds necessary for construction, replacement of aged infrastructure, costs to recover from natural disasters and the availability and cost of alternative power. Actual capital expenditures may vary significantly from the estimates due to a number of factors including changes in customer requirements, construction delays, changes in equipment delivery schedules, ability to raise capital, environmental matters, the extent to which we receive timely and adequate rate increases, the extent of competition from independent power producers and cogenerators, other changes in business conditions and changes in legislation and regulation, including those relating to the energy industry. See "— Regulation" below and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Markets and Transmission."

Our total system output for 2014 and 2013, based on kilowatt-hours generated, was as follows:

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

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

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

All of the Western coal used at our Asbury plant is shipped by rail, a distance of approximately 800 miles. We have a coal transportation agreement with the BNSF Railway Company and the Kansas City Southern Railway Company which runs through 2019. We currently lease one aluminum unit train full time to deliver Western coal to the Asbury Plant. Additional train capacity is leased on an as needed basis.

Unit 1 and Unit 2 at the Iatan Plant are coal-fired generating units which are jointly-owned by KCP&L, a subsidiary of Great Plains Energy, Inc., Missouri Joint Municipal Electric Utility Commission, Kansas Electric Power Cooperative (KEPCO) and us, with our share of ownership being 12% in each plant. KCP&L is the operator of these plants and is responsible for arranging their fuel supply. KCP&L has secured contracts for low sulfur Western coal in quantities sufficient to meet 85% of Iatan's requirements for 2015 and approximately 40% for 2016 and 10% for 2017. Coal is transported to Iatan by rail. Their rail contract provides transportation services through December 31, 2018.

The Plum Point Energy Station is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the plant's capacity. North America Energy Services is the operator of this plant. Plum Point Services Company, LLC (PPSC), the project

management company acting on behalf of the joint owners, is responsible for arranging its fuel supply. PPSC has secured contracts for low sulfur Western coal in quantities sufficient to meet approximately 87% of Plum Point's requirements for 2015, 87% for 2016 and 48% for 2017. We have a 15-year lease agreement, expiring in 2024, for 54 railcars for our ownership share of Plum Point and another 15-year lease agreement, expiring in 2025, for an additional 54 railcars associated with our Plum Point purchased power agreement.

Since its transition from coal in 2012, our Riverton Plant is fueled primarily by natural gas with oil available as backup for Units 9, 10 and 11. Units 8 and 12 are fueled 100% by natural gas. Unit 7 was retired on June 30, 2014. Based on kilowatt hours generated during 2014, Riverton's generation was 100% natural gas.

Our Energy Center and State Line Unit No.1 combustion turbine facilities (not including the State Line Combined Cycle (SLCC) Unit, which is fueled 100% by natural gas) are fueled primarily by natural gas with oil also available for use primarily as backup. Based on kilowatt hours generated during 2014, 96.1% of the Energy Center generation was produced from natural gas and 65% of the State Line Unit 1 generation came from natural gas with the remainder being fuel oil. As of December 31, 2014, oil inventories were sufficient for approximately 5 days of full load operation on Units No. 1, 2, 3 and 4 at the Energy Center and 5 days of full load operation for State Line Unit No. 1. As typical oil usage is minimal, these inventories are sufficient for our current requirements.

We have firm transportation agreements with Southern Star Central Pipeline, Inc. with current expiration dates of July 30, 2017, for the transportation of natural gas to the SLCC. This date is adjusted for periods of contract suspension by us during outages of the SLCC. We have reached agreement with Southern Star to replace these firm transportation agreements effective April 1, 2016 with a new agreement that runs through October 2022. We have additional firm transportation agreements that provide firm transportation to our Riverton plant sufficient to supply our Riverton Unit 12 through August, 2019. These transportation agreements can also supply natural gas to State Line Unit No.1, the Empire Energy Center or the Riverton Plant, as elected by us on a secondary basis. We expect that these transportation agreements will serve nearly all of our natural gas transportation needs for our generating plants over the next several years. Any remaining gas transportation requirements, although small, will be met by utilizing capacity release on other holder contracts, interruptible transport, or delivered to the plants by others.

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

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:

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:

At December 31, 2014, we had 751 full-time employees, including 50 employees of EDG. 327 of the EDE employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW). On December 10, 2013, the Local 1474 IBEW voted to ratify a new five-year agreement, effective December 2, 2013, which will extend through October 31, 2018. At December 31, 2014, 33 EDG employees were members of Local 1464 of the IBEW. In May 2013, Local 1464 of the IBEW ratified a four-year agreement with EDG, effective June 1, 2013.

	2014			2013			2012			2011			2010

Electric Operating Revenues (000's):
Residential	$	236,468		$	227,656		$	214,526		$	221,687		$	204,900
Commercial		172,274			162,444			158,837			157,435			146,310
Industrial		84,734			80,497			78,786			78,925			69,684
Public authorities⁽²⁾		14,863			14,707			13,755			13,653			12,099
Wholesale on-system		22,326			20,036			18,555			19,140			19,254
Interdepartmental		388			229			197			201			199

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



Electricity generated and purchased (000's of kWh):
Steam		2,407,914			2,813,441			2,865,037			2,805,744			2,650,042
Hydro		60,652			57,449			57,719			48,898			88,104
Combustion turbine		1,361,860			1,452,936			1,486,643			1,484,472			1,566,074

Total generated		3,830,426			4,323,826			4,409,399			4,339,114			4,304,220
Purchased		1,254,416			1,660,193			1,545,327			1,870,901			2,085,550

Total generated and purchased		5,084,842			5,984,019			5,954,726			6,210,015			6,389,770
Interchange (net)		(1	)		432			(87	)		(1,298	)		(1,716	)

Total system output		5,084,841			5,984,451			5,954,639			6,208,717			6,388,054
Transmission by others losses⁽³⁾		—			(15,817	)		(17,300	)		(16,597	)		(5,688	)
Total for resale — non-system (prior to SPP IM)⁽⁴⁾		(100,158	)		(653,996	)		(704,028	)		(740,009	)		(798,084	)
Net (sales)/purchases to/from SPP IM compared to native load⁽⁴⁾		386,267			—			—			—			—

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



Maximum hourly system demand (Kw)		1,162,000			1,080,000			1,142,000			1,198,000			1,199,000
Owned capacity (end of period) (Kw)		1,326,000			1,377,000			1,391,000			1,392,000			1,409,000
Annual load factor (%)		52.76			56.18			52.17			51.95			53.17

Electric sales (000's of kWh):
Residential		1,950,416			1,936,603			1,850,813			1,982,704			2,060,368
Commercial		1,583,843			1,541,717			1,558,297			1,576,342			1,644,917
Industrial		1,031,555			1,015,492			1,028,416			1,022,765			1,007,033
Public authorities⁽²⁾		124,287			127,370			122,369			126,724			124,554
Wholesale on-system		336,314			343,045			353,075			364,866			355,807

Total system		5,026,415			4,964,227			4,912,970			5,073,401			5,192,679
Wholesale off-system		—			653,996			704,028			740,009			798,084
SPP EIS Resettlements, Other⁽⁴⁾		1,445			—			—			—			—
Total Electric Sales		5,027,860			5,618,223			5,616,998			5,813,410			5,990,763
Company use (000's of kWh)⁽⁵⁾		10,725			9,049			9,066			9,371			9,598
kWh losses (000's of kWh)⁽⁷⁾		332,365			341,362			311,275			369,339			382,005
Wholesale off-system⁽⁴⁾		—			(653,996	)		(704,028	)		(740,009	)		(798,084	)

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



Customers (average number):
Residential		141,838			141,376			140,602			139,641			141,693
Commercial		24,146			24,080			24,036			24,155			24,505
Industrial		346			345			353			357			358
Public authorities⁽²⁾		2,175			2,214			2,124			2,021			2,003
Wholesale on-system		4			4			4			4			4

Total System		168,509			168,019			167,119			166,178			168,563
Wholesale off-system		4			22			22			25			22

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



Average annual sales per residential customer (kWh)		13,751			13,698			13,163			14,199			14,541
Average annual revenue per residential customer	$	1,667		$	1,610		$	1,526		$	1,588		$	1,446
Average residential revenue per kWh		12.12	¢		11.76	¢		11.59	¢		11.18	¢		9.94	¢
Average commercial revenue per kWh		10.88	¢		10.54	¢		10.19	¢		9.99	¢		8.89	¢
Average industrial revenue per kWh		8.21	¢		7.93	¢		7.66	¢		7.72	¢		6.92	¢

	2014		2013		2012		2011			2010

Gas Operating Revenues (000's):
Residential	$	32,873	$	31,561	$	24,744	$	28,999		$	32,245
Commercial		13,640		13,673		10,797		12,506			13,336
Industrial		537		515		464		682			812
Public authorities		365		342		247		324			342

Total retail sales revenues		47,415		46,091		36,252		42,511			46,735
Miscellaneous⁽²⁾		457		435		400		464			436
Transportation revenues		3,970		3,515		3,197		3,455			3,714

Total Gas Operating Revenues	$	51,842	$	50,041	$	39,849	$	46,430		$	50,885



Maximum Daily Flow (mcf)		72,912		60,118		58,281		67,789			73,280



Gas delivered to customers (000's of mcf sales)⁽³⁾
Residential		2,760		2,744		2,012		2,560			2,675
Commercial		1,275		1,349		1,050		1,268			1,265
Industrial		62		72		58		102			108
Public authorities		37		35		23		33			33

Total retail sales		4,134		4,200		3,143		3,963			4,081
Transportation sales		4,918		4,528		4,249		4,528			4,829

Total gas operating and transportation sales		9,052		8,728		7,392		8,491			8,910

Company use⁽³⁾		2		2		2		4			4
Transportation sales (cash outs)		—		—		—		—			—
Mcf losses		68		96		27		(47	)		70

Total system sales		9,122		8,826		7,421		8,448			8,984



Customers (average number):
Residential		37,572		37,777		37,897		38,051			38,277
Commercial		4,872		4,917		4,921		4,951			4,968
Industrial		22		24		23		26			26
Public authorities		138		140		138		136			137

Total retail customers		42,604		42,858		42,979		43,164			43,408
Transportation customers		422		340		326		311			313

Total gas customers		43,026		43,198		43,305		43,475			43,721

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

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		Positions With the Company

Bradley P. Beecher	49	President and Chief Executive Officer (2011). Executive Vice President (2011), Executive Vice President and Chief Operating Officer — Electric (2010), Vice President and Chief Operating Officer — Electric (2006)	2001	2001
Laurie A. Delano	59	Vice President — Finance and Chief Financial Officer, (2011), Controller, Assistant Secretary and Assistant Treasurer and Principal Accounting Officer (2005)	2002	2005
Ronald F. Gatz	64	Vice President and Chief Operating Officer — Gas (2006)	2001	2001
Blake Mertens⁽¹⁾	37	Vice President — Energy Supply (2011), General Manager — Energy Supply (2010), Director of Strategic Projects, Safety and Environmental Services (2010), Associate Director of Strategic Projects (2009)	2001	2011
Martin O. Penning⁽²⁾	59	Vice President — Commercial Operations, (2011), Director of Commercial Operations (2006)	1980	2011
Kelly S. Walters	49	Vice President and Chief Operating Officer — Electric (2011), Vice President — Regulatory and Services (2006)	2001	2006
Janet S. Watson⁽³⁾	62	Secretary (2014), Secretary — Treasurer (1995)	1994	1995
Mark T. Timpe⁽⁴⁾	55	Treasurer (2014), Director of Financial Services (2014)	2014	2014
Robert W. Sager	40	Controller, Assistant Secretary, Assistant Treasurer and Principal Accounting Officer (2011), Director of Financial Services (2006)	2006	2011
Dale W. Harrington⁽⁵⁾	53	Director of Investor Relations and Assistant Secretary (2014), Director of Investor Relations (2014), Director of Financial Services (2011), Assistant Director of Human Resources (2002)	2002	2014

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

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

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.

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.

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

Our EDE Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the EDE Mortgage), and our Restated Articles of Incorporation (Restated Articles), specify earnings coverage and other conditions which must be complied with in connection with the issuance of additional first mortgage bonds or cumulative preferred stock, or the incurrence of unsecured indebtedness. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $357.0 million of new first mortgage bonds. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the year ended December 31, 2014, would permit us to issue approximately $615.9 million of new first mortgage bonds based on this test at an assumed interest rate of 5.5%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2014, we had retired bonds and net property additions which would enable the issuance of at least $952.5 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2014, we are in compliance with all restrictive covenants of the EDE Mortgage.

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

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Indenture of Mortgage and Deed of Trust, dated as of June 1, 2006, as amended and supplemented (the EDG Mortgage) is limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of December 31, 2014, this test would allow us to issue approximately $19.7 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.

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

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.

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

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

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

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

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

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

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

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.

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

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

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

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

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

We are subject to regulation in the jurisdictions in which we operate, including the rates that we can charge customers.

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

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.

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.

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

The SPP RTO is mandated by the FERC to ensure a reliable power supply, an adequate transmission infrastructure and competitive wholesale electricity prices. The SPP RTO functions as reliability coordinator, tariff administrator and regional scheduler for its member utilities, including us. Essentially, the SPP RTO independently operates our transmission system as it interfaces and coordinates with the regional power grid. SPP RTO activities directly impact our control of owned generating assets and the development and cost of transmission infrastructure projects within the SPP RTO region. The cost allocation methodology applied to these transmission infrastructure projects will increase our operating expenses.

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

Information concerning recent and pending SPP RTO and other FERC activities can be found under Note 3 of "Notes to Consolidated Financial Statements" under Item 8.

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

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

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

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

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:

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

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

Our capital expenditure budget for the next three years is estimated to be $387.4 million. This includes expenditures for environmental upgrades to our existing facilities and additions to our transmission and distribution systems. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than planned, the scope and timing of projects may change, and other

events beyond our control may occur that may materially affect the schedule, budget, cost and performance of projects. To the extent the completion of projects is delayed, we expect that the timing of receipt of increases in base rates reflecting our investment in such projects will be correspondingly delayed. Costs associated with these projects will also be subject to prudency review by regulators as part of future rate case filings and all costs may not be allowed recovery.

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

We estimate our capital expenditures to be $172.7 million in 2015. Although we believe it is unlikely we will have difficulty accessing the markets for the capital needed to complete these projects (if such a need arises), financing costs could fluctuate. Financial market disruptions and volatility in discount rates could lead to increased funding obligations due to reduced asset values and increased benefit obligations. During 2014, our net pension and OPEB liability increased $40.5 million. Our funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. The actual minimum pension funding requirements will be determined based on the results of the actuarial valuations and the performance of our pension assets during the current year. Future market changes could result in increased pension and OPEB liabilities and funding obligations.

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

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

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

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

Our generating facilities consist of three coal-fired generating plants, four natural gas generating plants and one hydroelectric generating plant. At December 31, 2014, we owned generating facilities with an aggregate generating capacity of 1,326 megawatts. We retired the 14-megawatt Unit 2 at our Asbury Plant on December 31, 2013, as required by the addition of air quality control equipment being installed at our Asbury plant (discussed below) in order to comply with forthcoming environmental regulations.

The Asbury Plant, located near Asbury, Missouri, is a coal-fired generating station with a current generating capacity of 194 megawatts. The plant consisted of two steam turbine generating units with 203 megawatts of generating capacity until the end of 2013 when we retired Unit 2. In 2014, the plant accounted for approximately 15% of our owned generating capacity and accounted for approximately 27.7% of the energy generated by us. As part of our environmental Compliance Plan, discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8, we installed a scrubber, fabric filter and powder activated carbon injection system at our Asbury plant. The addition of this air quality control system (AQCS) equipment was completed in December 2014 and required the retirement of Asbury Unit 2 at the end of 2013. Routine plant maintenance, during which the entire plant is taken out of service, is scheduled annually, normally for approximately three to four weeks in the spring. Approximately every fifth year, the maintenance outage is scheduled to be extended to approximately six weeks to permit inspection of the Unit No. 1 turbine. When the Asbury Plant is out of service, we typically experience increased purchased power and fuel expenditures associated with replacement energy, which is likely to be recovered through our fuel adjustment clauses. The Asbury Plant went on outage as planned on September 12, 2014 and remained on outage through October while the AQCS tie in work was completed. Asbury returned to service and began testing in early November. All in-service testing was completed and results verified for the Asbury AQCS by December 15, 2014. The MPSC staff determined that as of December 15, 2014, the Asbury AQCS had met the in-service criteria.

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

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

Our generating plant located at Riverton, Kansas, has four gas-fired combustion turbine units (Units 9, 10, 11 and 12) and one gas-fired steam generating unit (Unit 8) with an aggregate generating capacity of 226 megawatts. In September 2012, Units 7 and 8 were transitioned from operation on coal to full operation on natural gas. Riverton Unit 7 was permanently removed from service on June 30, 2014. Unit 12 is being converted from a simple cycle combustion turbine to a combined cycle unit, with scheduled completion in mid-2016.

Our State Line Power Plant, which is located west of Joplin, Missouri, consists of Unit No. 1, a combustion turbine unit with generating capacity of 93 megawatts and a Combined Cycle Unit with generating capacity of 495 megawatts of which we are entitled to 60%, or 297 megawatts. The Combined Cycle Unit consists of the combination of two combustion turbines, two heat recovery steam generators, a steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with Westar Generating Inc., a subsidiary of Westar Energy, Inc., which owns the remaining 40% of the unit. We are the operator of the Combined Cycle Unit and Westar reimburses us for a percentage of the operating costs

per our joint ownership agreement. All units at our State Line Power Plant burn natural gas as a primary fuel with Unit No. 1 having the additional capability of burning oil.

We have four combustion turbine peaking units at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 260 megawatts. These peaking units operate on natural gas, as well as oil.

Our hydroelectric generating plant (FERC Project No. 2221), located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We have a long-term license from the FERC to operate this plant which forms Lake Taneycomo in southwestern Missouri. As part of the Energy and Water Development Appropriations Act of 2006 (the Appropriations Act), a new minimum flow pattern was established with the intent of increasing minimum flows on recreational streams in Arkansas. To accomplish this, the level of Bull Shoals Lake was increased an average of 5 feet. The increase at Bull Shoals will decrease the net head waters available for generation at Ozark Beach by 5 feet and, thus, reduce our electrical output. We estimate the lost production to be up to 16% of our average annual energy production for this unit. The Appropriations Act required the Southwest Power Administration (SWPA), in coordination with us and our relevant public service commissions, to determine our economic detriment assuming a January 1, 2011 implementation date. On September 16, 2010, we received a $26.6 million payment from the SWPA, which was deferred and recorded as a noncurrent liability. The SWPA payment, net of taxes, is being used to reduce fuel expense for our customers in all our jurisdictions. It is our understanding that the lake level change for Bull Shoals was implemented in July of 2013.

At December 31, 2014, our transmission system consisted of approximately 22 miles of 345 kV lines, 441 miles of 161 kV lines, 745 miles of 69 kV lines and 81 miles of 34.5 kV lines. Our distribution system consisted of approximately 6,911 miles of line at December 31, 2014 and 6,882 miles as of December 31, 2013.

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

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

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

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

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

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

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

Our common stock is listed on the New York Stock Exchange (ticker symbol: EDE). On February 2, 2015, there were 4,198 record holders and 28,605 individual participants in security position listings. The following table presents the high and low sales prices (and quarter end closing sales prices) for our common stock as reported by the New York Stock Exchange for composite transactions, and the amount per share of quarterly dividends declared and paid on the common stock for each quarter during 2014 and 2013.

Holders of our common stock are entitled to dividends, if, as, and when declared by the Board of Directors, out of funds legally available therefore subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts).

In the fourth quarter of 2014, the Board of Directors increased the dividend by 2%, from $0.255 per share on common stock to $0.26 per share. In the first quarter of 2015, the Board of Directors declared a quarterly dividend of $0.26 per share on common stock payable on March 16, 2015 to holders of record as of March 2, 2015. As of December 31, 2014, our retained earnings balance was $90.3 million, compared to $67.6 million at December 31, 2013. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.

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

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.

The following graph and table indicates the value at the end of the specified years of a $100 investment made on December 31, 2009, in our common stock and similar investments made in the securities of the companies in the Standard & Poor's 500 Composite Index (S&P 500 Index) and the Standard & Poor's Electric Utilities Index (S&P Electric Utility). The graph and table assume that dividends were reinvested when received.

	2014			2013			2012			2011			2010

Operating revenues⁽¹⁾	$	652,330		$	594,330		$	557,097		$	576,870		$	541,276
Operating income	$	99,999		$	99,663		$	96,221		$	96,934		$	80,495
Total allowance for funds used during construction	$	9,917		$	5,940		$	1,928		$	512		$	10,174
Net income	$	67,103		$	63,445		$	55,681		$	54,971		$	47,396
Weighted average number of common shares outstanding — basic		43,291			42,781			42,257			41,852			40,545
Weighted average number of common shares outstanding — diluted		43,314			42,803			42,284			41,887			40,580
Earnings from continuing operations per weighted average share of common stock — basic and diluted	$	1.55		$	1.48		$	1.32		$	1.31		$	1.17
Total earnings per weighted average share of common stock — basic and diluted	$	1.55		$	1.48		$	1.32		$	1.31		$	1.17
Cash dividends per share	$	1.025		$	1.005		$	1.00		$	0.64		$	1.28
Common dividends paid as a percentage of net income		66.1	%		67.8	%		75.9	%		48.6	%		109.7	%
Allowance for funds used during construction as a percentage of net income		14.8	%		9.4	%		3.5	%		0.9	%		21.5	%
Book value per common share (actual) outstanding at end of year	$	18.02		$	17.43		$	16.90		$	16.53		$	15.82
Capitalization:
Common equity	$	783,298		$	750,123		$	717,798		$	693,989		$	657,624
Long-term debt	$	803,189		$	743,428		$	691,626		$	692,259		$	693,072
Ratio of earnings to fixed charges		3.02X			2.97X			2.89X			2.87X			2.63X
Total assets	$	2,390,256		$	2,145,045		$	2,126,369		$	2,021,835		$	1,921,311
Plant in service at original cost	$	2,541,582		$	2,332,341		$	2,284,022		$	2,176,650		$	2,108,115
Capital expenditures (including AFUDC)	$	222,852		$	160,196		$	146,287		$	101,177		$	108,157

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

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

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

Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our electric customer and sales growth to be less than 1.0% annually over the next several years. Our electric customer growth for the year ended December 31, 2014 was 0.3%. We define electric sales growth to be growth in kWh sales period over period excluding the estimated impact of weather. The primary drivers of electric sales growth are customer growth, customer usage and general economic conditions.

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

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

Customer growth, which is the growth in the number of customers, contributes to the demand for gas. Our annual customer growth is calculated by comparing the number of customers at the end of a year to the number of customers at the end of the prior year. Our gas segment customer count decreased 0.2% for the year ended December 31, 2014, which we believe was due to population losses in the rural communities we serve. We expect gas customer growth to be flat during the next several years. We define gas sales growth to be growth in mcf sales excluding the impact of weather. The primary drivers of gas sales growth are customer growth and general economic conditions.

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

For the year ended December 31, 2014, basic and diluted earnings per weighted average share of common stock were $1.55 on $67.1 million of net income compared to $1.48 on $63.4 million of net income for the year ended December 31, 2013. Increased electric gross margins positively impacted net income for 2014 as compared to 2013 mainly due to increased electric rates for our Missouri customers effective April 1, 2013 and for our wholesale on-system customers in June 2014. Favorable weather and increased

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

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

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

In addition, although a non-GAAP presentation, we believe the presentation of gross margin (in the table below and elsewhere in this report) is useful to investors and others in understanding and analyzing changes in our electric operating performance from one period to the next, and have included the analysis as a complement to the financial information we provide in accordance with GAAP. This reconciliation and margin information may not be comparable to other companies' presentations or more useful than the GAAP presentation included in the statements of income or elsewhere in this report. We also note that this presentation does not purport to be an alternative to earnings per share determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone.


Earnings Per Share — 2013	$	1.48
Gross Margins
Electric segment		0.24
Gas segment		0.01
Other segment		0.00

Total Gross Margin		0.25
Operating expenses — electric segment		(0.09	)
Operating expenses — gas segment		0.01
Operating expenses — other segment		0.00
Maintenance and repairs		(0.09	)
Depreciation and amortization		(0.05	)
Loss on plant disallowance		0.03
Other taxes		(0.03	)
AFUDC		0.06
Change in effective income tax rates		0.01
Other income and deductions		(0.01	)
Dilutive effect on additional shares issues		(0.02	)

Earnings Per Share — 2014	$	1.55

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

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

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

On December 5, 2014, we filed a request with the Kansas Corporation Commission (KCC) to implement an Environmental Cost Recovery Rider for costs associated with the new environmental facilities installed at our Asbury generating unit. We have requested an effective date of March 1, 2015 for the recovery rider.

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

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

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

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

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

We filed our Integrated Resource Plan (IRP) with the MPSC on July 1, 2013. The IRP analysis of future loads and resources is normally conducted once every three years. Our IRP supports our Compliance Plan discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8. On March 12, 2014, the MPSC issued an order approving our IRP, effective March 12, 2014.

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

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

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

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

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

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

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

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

KWh sales for our on-system customers increased during 2014 as compared to 2013 primarily due to increased demand due to weather impacts, increased commercial demand and increased customer counts. Residential and commercial kWh sales increased 0.7% and 2.7%, respectively, primarily due to these weather impacts and increased customer counts. Industrial sales increased 1.6% during 2014 as compared to 2013 due to increased usage. On-system wholesale kWh sales decreased during 2014 as compared to 2013 reflecting the closure of a large dairy facility in Monett, Missouri during the second half of 2013. Total heating degree days (the sum of the number of degrees that the daily average temperature for each day during that period was below 65° F) for 2014 were 1.2% more than 2013 and 6.3% more than the 30-year average. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65° F) for 2014 were 3.7% more than 2013 and 5.8% more than the 30-year average.

KWh sales for our on-system customers increased slightly during 2013 as compared to 2012 primarily due to increased demand due to colder temperatures in the first and fourth quarters of 2013 as compared to the same periods in 2012. Residential kWh sales, the most weather sensitive class, increased 4.6% primarily due to these weather impacts and an increase in the average residential customer count. Commercial sales decreased 1.1% primarily due to a net unbilled sales adjustment recorded in 2012. Industrial sales decreased 1.3% during 2013 as compared to 2012 due to operating reductions by several large industrial customers. On-system wholesale kWh sales decreased during 2013 as compared to 2012 reflecting the closure of a large dairy facility in Monett, Missouri during the second half of 2013. Total heating degree days for 2013 were 31.7% more than 2012 and 5.0% more than the 30-year average. Total cooling degree days for 2013 were 19.7% less than 2012 although they were 2.1% more than the 30-year average. The weather was unseasonably hot in June and July of 2012.

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

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

	Electric Segment Operating Revenues and Gross Margin

Customer Class	2014			2013			% Change⁽¹⁾			2013			2012			% Change⁽¹⁾
Residential	$	236.5		$	227.7			3.9	%	$	227.7		$	214.5			6.1	%
Commercial		172.3			162.4			6.1			162.4			158.8			2.3
Industrial		84.7			80.5			5.3			80.5			78.8			2.2
Wholesale on-system		22.3			20.0			11.4			20.0			18.6			8.0
Other⁽²⁾		15.2			15.0			2.1			15.0			14.0			7.0

Total on-system revenues		531.0			505.6			5.0			505.6			484.7			4.3
Off-system wholesale⁽³⁾		3.2			15.5			(79.2	)		15.5			15.7			(1.3	)
SPP IM net revenues⁽³⁾		41.9			—			100.0			—			—			—

Total revenues from KWh sales		576.1			521.1			10.6			521.1			500.4			4.1
Miscellaneous revenues⁽⁴⁾		14.3			13.2			8.2			13.2			8.5			55.2

Total electric operating revenues	$	590.4		$	534.3			10.5		$	534.3		$	508.9			5.0
Water revenues		2.1			2.1			(3.3	)		2.1			1.8			19.2

Total electric segment operating revenues	$	592.5		$	536.4			10.5		$	536.4		$	510.7			5.0
Actual fuel and purchased power expenditures	$	165.2		$	182.1			(9.3	)	$	182.1		$	173.6			4.9
SPP IM net purchases⁽³⁾		55.9			—			100.0			—			—			—
Net fuel recovery and deferral		(3.8	)		(3.6	)		6.2			(3.6	)		9.7			(137.1	)
SWPA amortization⁽⁵⁾		(2.6	)		(2.8	)		(5.4	)		(2.8	)		(2.8	)		0.0
Unrealized (gain)/loss on derivatives		0.4			(0.3	)		(237.4	)		(0.3	)		(1.6	)		81.3

Total fuel and purchased power expense per income statement		215.1			175.4			22.6			175.4			178.9			(2.0	)

Total Gross Margin	$	377.4		$	361.0			4.5		$	361.0		$	331.8			8.8

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.

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

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

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

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

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

Transmission expense⁽¹⁾	$	5.0		$	4.4
Distribution expense		1.0			0.4
General labor expense		2.3			2.0
Regulatory reversal of gain on prior period sale of assets⁽²⁾		(1.2	)		1.2
Customer accounts expense		(0.3	)		0.9
Steam power other operating expense		0.2			0.6
Regulatory commission expense		(0.1	)		0.5
Other power supply expense		0.1			0.7
Hydro power operating expense		0.3			(0.4	)
Employee pension expense		(0.1	)		0.5
Employee health care expense		(1.0	)		0.2
Property insurance		0.1			0.5
Customer assistance expense		0.7			0.4
Professional services		(0.3	)		(0.5	)
Banking fees		(0.1	)		(0.7	)
Injuries and damages		(0.1	)		0.0
Other miscellaneous accounts (netted)		(0.3	)		0.4

TOTAL	$	6.2		$	11.1

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

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

Distribution maintenance expense	$	2.8		$	0.4
Transmission maintenance expense		0.3			0.7
Maintenance and repairs expense at the Energy Center		1.3			0.0
Maintenance and repairs expense at the Asbury plant		1.2			(0.9	)
Maintenance and repairs expense to SLCC		(0.6	)		(1.1	)
Maintenance and repairs expense at the State Line plant		(0.3	)		0.5
Maintenance and repairs expense at the Iatan plant		0.2			0.4
Maintenance and repairs expense at the Plum Point plant		(0.1	)		0.4
Maintenance and repairs expense at the Riverton plant — steam		0.1			(0.2	)
Maintenance and repairs expense at the Riverton plant — gas		0.7			(0.5	)
Iatan deferred maintenance expense		0.1			0.5
Hydro maintenance expense		(0.1	)		0.2
Other miscellaneous accounts (netted)		0.3			0.0

TOTAL	$	5.9		$	0.4

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

Other taxes increased approximately $1.8 million in 2014 and $3.3 million in 2013 due to increased property tax (reflecting our additions to plant in service) and increased municipal franchise taxes.

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

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

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.

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

We have a PGA clause in place that allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of December 31, 2014, we had unrecovered purchased gas costs of $0.6 million recorded as a non-current regulatory asset and $0.5 million recorded as a current regulatory liability as compared to unrecovered purchased gas costs of $1.0 million recorded as a current regulatory asset and $1.2 million recorded as a non-current regulatory liability as of December 31, 2013.

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

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

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

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:

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

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

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended December 31. AFUDC increased in 2014 as compared to 2013 and 2012 reflecting construction for the environmental retrofit project at our Asbury plant and the Riverton 12 combined cycle project. See Note 1 of "Notes to Consolidated Financial Statements" under Item 8.

Total interest charges on long-term and short-term debt for 2014, 2013 and 2012 are shown below. The changes in long-term debt interest for 2014 compared to 2013 and 2013 compared to 2012 reflect the issuance, on May 30, 2013, of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. We used a portion of the proceeds from the sale of these bonds to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013.

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

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, 2012:

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

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

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

Information concerning recent and pending SPP RTO and other FERC activities can be found under Note 3 of "Notes to Consolidated Financial Statements" under Item 8.

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

Our issuance of various securities, including equity, long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the SEC. We believe the cash provided by operating activities, together with the amounts available to us under our credit facilities and the issuance of debt and equity securities, will allow us to meet our needs for working capital, pension contributions, our continuing construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash

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.

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

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

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

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

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

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

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

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

	Capital Expenditures

(in millions)	2014			2013			2012
Distribution and transmission system additions	$	57.7		$	58.5		$	63.3
New generation — Riverton 12 combined cycle		77.5			13.2			0.6
Additions and replacements — electric plant		61.4			61.8			46.9
Storms		2.3			1.0			5.0
Transportation		3.6			4.5			3.7
Gas segment additions and replacements		7.1			4.1			3.3
Other (including retirements and salvage — net)⁽¹⁾		11.0			14.7			20.7

Subtotal	$	220.6		$	157.8		$	143.5
Non-regulated capital expenditures (primarily fiber optics)		2.2			2.4			2.8

Subtotal capital expenditures incurred⁽²⁾	$	222.8		$	160.2		$	146.3

Adjusted for capital expenditures payable⁽³⁾		(9.4	)		(5.4	)		(9.3	)

Total cash outlay	$	213.4		$	154.8		$	137.0

Approximately 50%, 74% and 85% of our cash requirements for capital expenditures for 2014, 2013 and 2012, respectively, were satisfied from internally generated funds (funds provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and debt securities discussed below.

Our estimated capital expenditures (excluding AFUDC) for 2015, 2016 and 2017 are detailed below. See Item 1, "Business — Construction Program." We anticipate that we will spend the following amounts over the next three years for the following projects:

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

We estimate that internally generated funds will provide approximately 78% of the funds required in 2015 for our budgeted capital expenditures. We intend to utilize short-term debt to finance any additional amounts needed beyond those provided by operating activities for such capital expenditures. If additional financing is needed, we intend to utilize a combination of debt and equity securities. The estimates herein may be changed because of changes we make in our construction program, unforeseen construction costs, our ability to obtain financing, regulation and for other reasons. See further discussion under "Financing Activities" below.

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:

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

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

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

Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $357.0 million of new first mortgage bonds. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the year ended December 31, 2014 would permit us to issue approximately $615.9 million of new first mortgage bonds based on this test with an assumed interest rate of 5.5%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2014, we had retired bonds and net property additions which would enable the issuance of at least $952.5 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2014, we are in compliance with all restrictive covenants of the EDE Mortgage.

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

On January 30, 2014, Moody's upgraded our corporate credit rating to Baa1 from Baa2, senior secured debt to A2 from A3, senior unsecured debt to Baa1 from Baa2 and affirmed our commercial paper rating at P-2. Standard & Poor's and Fitch reaffirmed our ratings on March 20, 2014 and September 30, 2014, respectively.

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

Set forth below is information summarizing our contractual obligations as of December 31, 2014. Other pension and postretirement benefit plans are funded on an ongoing basis to match their corresponding costs, per regulatory requirements, and have been estimated for 2015 – 2019 as noted below.

	Payments Due By Period (in millions)

Contractual Obligations⁽¹⁾	Total		Less Than 1 Year		1 – 3 Years		3 – 5 Years		More Than 5 Years
Long-term debt (w/o discount)	$	800.0	$	—	$	25.0	$	90.0	$	685.0
Interest on long-term debt		703.5		41.7		81.5		70.3		510.0
Short-term debt		44.0		44.0		—		—		—
Capital lease obligations		5.8		0.6		1.1		1.1		3.0
Operating lease obligations⁽²⁾		3.2		0.7		1.4		1.1		—
Electric purchase obligations⁽³⁾		472.4		52.9		77.7		61.3		280.5
Gas purchase obligations⁽⁴⁾		90.7		13.5		19.3		19.3		38.6
Open purchase orders		114.9		29.5		85.4		—		—
Postretirement benefit obligation funding		17.2		5.0		7.1		5.1		—
Pension benefit funding		52.3		12.8		23.8		15.7		—
Other long-term liabilities⁽⁵⁾		3.0		0.1		0.3		0.3		2.3

TOTAL CONTRACTUAL OBLIGATIONS	$	2,307.0	$	200.8	$	322.6	$	264.2	$	1,519.4

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, 2014, 2013 and 2012:

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

In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other 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.

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.

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

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

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, 2014, we have recorded $220.5 million in regulatory assets and $136.4 million as regulatory liabilities. See Note 3 of "Notes to Consolidated Financial Statements" under Item 8 for detailed information regarding our regulatory assets and liabilities.

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

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

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

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

Contingent Liabilities. We are a party to various claims and legal proceedings arising in the ordinary course of our business, which are primarily related to workers' compensation and public liability. We regularly assess our insurance deductibles, analyze litigation information with our attorneys and evaluate our loss experience. Based on our evaluation as of the end of 2013, we believe that we have accrued liabilities in accordance with ASC accounting guidance sufficient to meet potential liabilities that could result from these claims. This liability at December 31, 2014 and 2013 was 3.6 million and $4.0 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, 2014, 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 to some extent. 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 2014 indicated the estimated fair market value of the gas reporting unit to be $10 – 14 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future.

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

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

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

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

We engage in physical and financial trading activities with the goals of reducing risk from market fluctuations. In accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions, we attempt to mitigate our commodity market risk. Derivatives are utilized to manage our gas commodity market risk. 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 63.7% of our 2014 generation fuel supply need through coal. Approximately 96% of our 2014 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 92% of our anticipated fuel requirements for 2015, 35% for 2016 and 18% for 2017 for our Asbury coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of December 31, 2014, 63%, or 6.1 million Dths, of our anticipated volume of natural gas usage for our electric operations for 2015 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 2015, if average natural gas prices should increase 10% more in 2015 than the price at December 31, 2014, our natural gas expenditures would increase by approximately $0.9 million based on our December 31, 2014 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, 2014, we have 1.2 million Dths in storage on the three pipelines that serve our customers. This represents 58% of our storage capacity. We have an additional 0.8 million Dths hedged through financial derivatives and physical contracts.

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, 2014 and December 31, 2013 (in millions).

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, 2014, reflecting that our counterparties are exposed to Empire for the net unrealized mark-to-market losses for physical forward and financial natural gas contracts carried at fair value (in millions).

The $10.3 million net unrealized mark-to-market loss for financial natural gas contracts is comprised entirely of $10.3 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, 2014, we have $9.1 million on deposit for NYMEX contract exposure to Empire, of which $9.1 million represents our collateral requirement. If NYMEX gas prices decreased 25% from their December 31, 2014 levels, our collateral requirement would increase $7.1 million. If these prices increased 25%, our collateral requirement would decrease $6.6 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 2015 than in 2014, our interest expense would increase, and income before taxes would decrease by less than $0.8 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2014. 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.

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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, 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.

	December 31,

	2014		2013
	($-000's)
Assets
Plant and property, at original cost:
Electric	$	2,420,824	$	2,219,605
Gas		79,364		72,834
Other		41,394		39,902
Construction work in progress		112,097		152,330

		2,653,679		2,484,671
Accumulated depreciation and amortization		743,407		732,737

		1,910,272		1,751,934

Current assets:
Cash and cash equivalents		2,105		3,475
Restricted cash		4,726		2,872
Accounts receivable — trade, net of allowance of $1,021 and $1,025, respectively		45,444		50,137
Accrued unbilled revenues		25,945		26,694
Accounts receivable — other		41,256		13,101
Fuel, materials and supplies		57,799		48,811
Prepaid expenses and other		27,879		15,954
Unrealized gain in fair value of derivative contracts		3,901		2,469
Regulatory assets		10,752		7,743

		219,807		171,256

Noncurrent assets and deferred charges:
Regulatory assets		209,717		169,333
Goodwill		39,492		39,492
Unamortized debt issuance costs		8,821		8,826
Unrealized gain in fair value of derivative contracts		—		41
Other		2,147		4,163

		260,177		221,855

Total assets	$	2,390,256	$	2,145,045

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

	December 31,

	2014		2013
	($-000's)
Capitalization and liabilities
Common stock, $1 par value, 100,000,000 shares authorized, 43,479,186 and 43,044,185 shares issued and outstanding, respectively	$	43,479	$	43,044
Capital in excess of par value		649,543		639,525
Retained earnings		90,276		67,554

Total common stockholders' equity		783,298		750,123

Long-term debt (net of current portion)
Obligations under capital lease		3,875		4,167
First mortgage bonds and secured debt		697,615		637,578
Unsecured debt		101,699		101,683

Total long-term debt		803,189		743,428

Total long-term debt and common stockholders' equity		1,586,487		1,493,551

Current liabilities:
Accounts payable and accrued liabilities		83,420		71,375
Current maturities of long-term debt		292		274
Short-term debt		44,000		4,000
Regulatory liabilities		7,898		5,681
Customer deposits		13,747		12,543
Interest accrued		6,565		6,352
Unrealized loss in fair value of derivative contracts		6,469		1,889
Taxes accrued		3,380		3,386
Other current liabilities		356		299

		166,127		105,799

Commitments and contingencies (Note 11)
Noncurrent liabilities and deferred credits:
Regulatory liabilities		128,471		132,012
Deferred income taxes		377,452		324,266
Unamortized investment tax credits		18,367		18,431
Pension and other postretirement benefit obligations		93,863		51,405
Unrealized loss in fair value of derivative contracts		3,243		2,799
Other		16,246		16,782

		637,642		545,695

Total capitalization and liabilities	$	2,390,256	$	2,145,045

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

	Year Ended December 31,

	2014			2013			2012
	(000's, except per share amounts)
Operating revenues:
Electric	$	592,491		$	536,413		$	510,653
Gas		51,842			50,041			39,849
Other		7,997			7,876			6,595

		652,330			594,330			557,097

Operating revenue deductions:
Fuel and purchased power		215,086			175,406			178,896
Cost of natural gas sold and transported		27,025			25,795			18,633
Regulated operating expenses		110,691			105,333			94,371
Other operating expenses		2,987			3,142			2,730
Maintenance and repairs		46,775			40,873			40,444
Loss on plant disallowance		86			2,409			—
Depreciation and amortization		73,185			69,306			60,447
Provision for income taxes		39,398			37,465			34,096
Other taxes		37,098			34,938			31,259

		552,331			494,667			460,876

Operating income		99,999			99,663			96,221
Other income and (deductions):
Allowance for equity funds used during construction		6,420			3,853			1,147
Interest income		51			566			972
Benefit/(provision) for other income taxes		178			(27	)		(63	)
Other — non-operating expense, net		(1,302	)		(1,218	)		(1,910	)

		5,347			3,174			146

Interest charges:
Long-term debt		40,637			40,354			40,192
Short-term debt		113			60			187
Allowance for borrowed funds used during construction		(3,497	)		(2,087	)		(781	)
Other		990			1,065			1,088

		38,243			39,392			40,686

Net income	$	67,103		$	63,445		$	55,681



Weighted average number of common shares outstanding — basic		43,291			42,781			42,257

Weighted average number of common shares outstanding — diluted		43,314			42,803			42,284

Total earnings per weighted average share of common stock — basic and diluted	$	1.55		$	1.48		$	1.32



Dividends declared per share of common stock	$	1.025		$	1.005		$	1.000

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

	Common Stock		Capital in excess of Par		Retained earnings			Total

	($-000's)
Balance at December 31, 2011	$	41,978	$	618,304	$	33,707		$	693,989
Net income						55,681			55,681
Stock/stock units issued through:
Stock purchase and reinvestment plans		506		9,895					10,401
Dividends declared						(42,273	)		(42,273	)

Balance at December 31, 2012		42,484		628,199		47,115			717,798
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

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

	Year Ended December 31,

	2014			2013			2012
	($-000's)
Operating activities:
Net income	$	67,103		$	63,445		$	55,681
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items		82,754			71,734			71,160
Pension and other postretirement benefit costs, net of contributions		1,973			(1,888	)		1,689
Deferred income taxes and unamortized investment tax credit, net		41,693			28,272			31,899
Allowance for equity funds used during construction		(6,420	)		(3,853	)		(1,147	)
Stock compensation expense		4,057			2,984			2,285
Loss on plant disallowance		86			2,409			—
Non-cash loss on derivatives		1,245			14			4,174
Regulatory reversal of gain on sale of assets		44			1,236			—
Other		—			—			(16	)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues		(24,174	)		(14,312	)		(688	)
Fuel, materials and supplies		(8,121	)		10,891			369
Prepaid expenses, other current assets and deferred charges		(6,051	)		689			(9,238	)
Accounts payable and accrued liabilities		1,141			(880	)		(1,297	)
Asset retirement obligation		(1,326	)		(734	)		—
Interest, taxes accrued and customer deposits		1,411			1,386			875
Other liabilities and other deferred credits		(4,192	)		(3,942	)		3,360

Net cash provided by operating activities		151,223			157,451			159,106

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

	Year Ended December 31,

	2014			2013			2012
	($-000's)
Investing activities:
Capital expenditures — regulated	$	(211,429	)	$	(152,524	)	$	(134,272	)
Capital expenditures and other investments — non-regulated		(1,998	)		(2,259	)		(2,670	)
Restricted cash		(1,854	)		1,485			(1	)

Total net cash used in investing activities		(215,281	)		(153,298	)		(136,943	)

Financing activities:
Proceeds from first mortgage bonds, net		60,000			150,000			88,000
Long-term debt issuance costs		(651	)		(1,879	)		(1,074	)
Proceeds from issuance of common stock, net of issuance costs		7,994			9,546			8,114
Repayment of first mortgage bonds		—			—			(88,029	)
Redemption of senior notes		—			(98,000	)		—
Net short-term borrowings (repayments)		40,000			(20,000	)		12,000
Dividends		(44,381	)		(43,006	)		(42,273	)
Other		(274	)		(714	)		(934	)

Net cash provided by / (used) in financing activities		62,688			(4,053	)		(24,196	)

Net increase (decrease) in cash and cash equivalents		(1,370	)		100			(2,033	)
Cash and cash equivalents, beginning of year		3,475			3,375			5,408

Cash and cash equivalents, end of year	$	2,105		$	3,475			3,375

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

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

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, 2014, and the 2014 electric operating revenues were derived as follows:

Our gas operations serve approximately 43,500 customers as of December 31, 2014, and the 2014 gas operating revenues were derived as follows:

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.

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, tax provisions and derivatives. Actual amounts could differ from those estimates.

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)

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. During 2012, we recorded an increase in electric unbilled revenues as a result of certain changes to the assumptions used in determining estimated unbilled revenues.

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 $11.8 million, $11.2 million and $10.4 million were recorded for each of the years ended December 31, 2014, 2013 and 2012, respectively.

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.

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, 2014 and 2013 was $1.9 million and $4.2 million, respectively.

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, 2014 and 2013, we had recorded accrued cost of removal of $82.8 million and $81.3 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, 2014 and 2013 was $7.7 million and $7.2 million, respectively. These amounts are net of our actual cost of removal expenditures.

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).

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, and during 2012 the liabilities for both the ash landfill at the Riverton Power Plant, and PCB contaminants were re-evaluated. Changes in the cost estimates and timing resulted in cash flow revisions for these liabilities.

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, 2014 and 2013, our regulatory assets relating to asset retirement obligations totaled $5.1 million and $4.7 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.

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 6.6% for 2014, 7.3% for 2013, and 5.6% for 2012, compounded semiannually.

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, 2014 and 2013.

As of December 31, 2014, 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 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 2014 indicated the estimated fair market value of the gas reporting unit to be $10 – $14 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 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 effect 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). 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, 2014 and 2013, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net under-recovered position by $3.1 million and a net over-recovered position of $0.6 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 SO2 allowance inventory in accordance with our SO2 Allowance Management Policy (SAMP). The SAMP allows us to exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. We have not yet exchanged or sold any allowances. 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 872 and 1,834 SO2 allowances in inventory at December 31, 2014 and 2013, respectively.

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.

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).

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.

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.

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.

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.

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).

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.

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 are comprised of accruals and other accounting estimates not sufficiently large enough to merit individual disclosure. At December 31, 2014, the balance of other noncurrent liabilities is primarily comprised of accruals for self-insurance, customer advances for construction and asset retirement obligations.

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 $28.3 million and $22.1 million at December 31, 2014 and 2013, respectively.

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 and construction costs. The cash is held at a financial institution and restricted as to withdrawal or use. The restrictions on these funds related to construction costs, which were approximately $2.5 million at December 31, 2012, were released by all parties in January 2013. The amounts restricted for operating costs, which were $1.8 million at December 31, 2014 and 2013, 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 and $1.1 million at December 31, 2014 and 2013, respectively.

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 and $0 at December 31, 2014 and 2013, respectively.

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):

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 50 years.

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 2009. At December 31, 2014 and 2013, 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.

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.

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

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.

Presentation of an unrecognized tax benefit: In July 2013, The FASB issued new guidance on the presentation of unrecognized tax benefits. Under this guidance, an unrecognized tax benefit would be presented as a reduction to a deferred tax asset when a tax credit carryforward, net operating loss carryforward, or similar tax loss exists. To the extent that the loss or credit carryforward is not available at the reporting date or the entity does not intend to use the deferred tax asset for such a purpose, the unrecognized tax benefit should be presented as a liability and not be combined with deferred tax assets. This standard is effective for annual periods beginning after December 15, 2013. The application of this standard did not have a material impact on our results of operations, financial position or liquidity.

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. The new standard is effective for interim and annual reporting periods beginning after December 15, 2016. We are evaluating the impact of the adoption of this standard.

	December 31,

	2014			2013
Electric plant
Production	$	1,159,140		$	1,035,095
Transmission		288,542			263,398
Distribution		840,761			793,024
General⁽¹⁾		119,572			115,427

Electric plant		2,408,015			2,206,944
Less accumulated depreciation and amortization		704,596			697,128

Electric plant net of depreciation and amortization		1,703,419			1,509,816
Construction work in progress		110,500			150,636

Net electric plant		1,813,919			1,660,452
Water plant		12,809			12,661
Less accumulated depreciation and amortization		5,102			4,806

Water plant net of depreciation and amortization		7,707			7,855
Construction work in progress		146			—

Net water plant		7,853			7,855

Net electric segment plant		1,821,772			1,668,307
Gas plant
Transmission		11,198			10,550
Distribution		89,712			84,157
General⁽²⁾		(21,546	)		(21,873	)

Gas Plant		79,364			72,834
Less accumulated depreciation and amortization		16,405			15,204

Gas plant net of accumulated depreciation		62,959			57,630
Construction work in progress		379			1,156

Net gas plant		63,338			58,786
Other
Fiber		41,394			39,902
Less accumulated depreciation and amortization		17,304			15,599

Non-regulated net of depreciation and amortization		24,090			24,303
Construction work in progress		1,072			538

Net non-regulated property		25,162			24,841

TOTAL NET PLANT AND PROPERTY	$	1,910,272		$	1,751,934

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):

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

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. Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives from December 31, 2012 to December 31, 2013 resulted from our 2012 Missouri rate case. As a result of this case, deferred costs from the tornado that hit our service territory on May 22, 2011 will be recovered over the next ten years. In addition, the

order also included the continuation of tracking mechanisms for expenses related to employee pension, retiree health care, vegetation management, and Iatan 2, Iatan Common and Plum Point operating and maintenance costs as well as the capitalization of banking and line of credit fees.

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

	December 31,

	2014			2013
Regulatory Assets:
Current:
Under recovered fuel costs	$	2,618		$	1,411
Current portion of long-term regulatory assets		8,134			6,332

Regulatory assets, current		10,752			7,743

Long-term:
Pension and other postretirement benefits⁽¹⁾		111,121			70,035
Income taxes		47,177			48,033
Deferred construction accounting costs⁽²⁾		15,521			16,275
Unamortized loss on reacquired debt		10,405			11,078
Unsettled derivative losses — electric segment		9,037			4,269
System reliability — vegetation management		5,337			7,539
Storm costs⁽³⁾		4,183			4,911
Asset retirement obligation		5,145			4,673
Customer programs		5,253			4,935
Unamortized loss on interest rate derivative		943			989
Deferred operating and maintenance expense		910			2,095
Under recovered fuel costs		640			—
Current portion of long-term regulatory assets		(8,134	)		(6,332	)
Other		2,179			833

Regulatory assets, long-term		209,717			169,333

Total Regulatory Assets	$	220,469		$	177,076



Regulatory Liabilities
Current:
Over recovered fuel costs	$	4,227		$	2,212
Current portion of long-term regulatory liabilities		3,671			3,469

Regulatory liabilities, current		7,898			5,681

Long-term:
Costs of removal		90,527			88,469
SWPA payment for Ozark Beach lost generation		16,744			19,405
Income taxes		11,451			11,677
Deferred construction accounting costs — fuel⁽⁴⁾		7,849			8,011
Unamortized gain on interest rate derivative		3,201			3,371
Pension and other postretirement benefits		2,369			2,177
Over recovered fuel costs		1			2,371
Current portion of long-term regulatory liabilities		(3,671	)		(3,469	)

Regulatory liabilities, long-term		128,471			132,012

Total Regulatory Liabilities	$	136,369		$	137,693

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, 2014, the costs of all of our regulatory assets are currently being recovered except for approximately $103.5 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 6 to 26 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.

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, 2012:

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) 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 February 22, 2013, we filed a Nonunanimous Stipulation and Agreement (Agreement) with the MPSC which issued an order approving the Agreement on February 27, 2013. The Agreement provided for an annual increase in base revenues for our Missouri electric customers in the amount of approximately $27.5 million, effective April 1, 2013, and the continuation of the current fuel adjustment mechanism. In 2011 the MPSC permitted us to defer actual incremental operating and maintenance expenses associated with the repair, restoration and rebuilding activities resulting from the May 2011 tornado. In addition, depreciation related to the capital expenditures was allowed to be deferred and a carrying charge accrued. Approximately $4.0 million was deferred in total for the tornado costs. Recovery of these costs over the ten years was included in the Agreement

The Agreement also included an increase in depreciation rates, and the continuation of tracking mechanisms for expenses related to employee pension, retiree health care, vegetation management, and Iatan 2, Iatan Common and Plum Point operating and maintenance costs. In addition, the Agreement included a write-off of approximately $3.6 million, consisting of a $2.4 million disallowance for the prudency of certain construction expenditures for Iatan 2 and a $1.2 million regulatory reversal of a prior period gain on sale of our Asbury unit train, which is included in regulated operating expenses. We also agreed not to implement a Missouri general rate increase prior to October 1, 2014. As initially filed on July 6, 2012, we requested an annual increase in base rates for our Missouri electric customers in the amount of $30.7 million, or 7.56%, and the continuation of the fuel adjustment clause.

On May 21, 2012, we filed a rate increase request with the MPSC for an annual increase in revenues for our Missouri water customers in the amount of approximately $516,400, or 29.6%. On October 18, 2012, we, the MPSC staff and the Office of the Public Counsel filed a unanimous agreement with the

MPSC for an increase of $450,000. The MPSC issued an order approving the agreement on October 31, 2012, with rates effective November 23, 2012.

On December 5, 2014, we filed for approval of an environmental cost recovery rider designed to recover the costs associated with our investment in Air Quality Control Facilities at our Asbury generating unit. As proposed, the rider would recover $859,674 during the first twelve months of the tariffs operation.

On November 10, 2011 a joint settlement agreement was filed, and approved by the KCC on December 21, 2011, resulting in an increase in annual revenues of $1.25 million, or approximately 5.2%. The new rates became effective on January 1, 2012. On June 17, 2011, we filed an application with the KCC seeking a rate increase of $1.5 million, or 6.39%. The rate increase was requested to recover the costs associated with our investment in the Iatan 1, Iatan 2 and Plum Point generating units and the depreciation and operation and maintenance costs deferred since the in-service dates of the units. The June 17, 2011 filing was made under the KCC's abbreviated rate case rules which the KCC authorized in our 2009 Kansas rate case. The case included a request to recover the Iatan and Plum Point cost deferrals over a 3-year period.

On June 30, 2011, we filed a request with the Oklahoma Corporation Commission (OCC) for an annual increase in base rates for our Oklahoma electric customers in the amount of $0.6 million, or 4.1% over the base rate and Capital Reliability Rider (CRR) revenues that were currently in effect. A stipulation and agreement, reached by all parties participating in the case, was filed on November 16, 2011. This agreement, which was approved by the OCC on January 4, 2012, made rates previously collected under the CRR permanent, and will result in a net overall increase of total annual revenues of $0.2 million, or approximately 1.66%. The agreement also removed fuel and purchase power costs from base rates. Fuel and purchase power costs are now listed as a separate line item, identified as the Fuel Adjustment Charge, on customer bills.

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.

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.

Day Ahead Market: On March 1, 2014, the SPP RTO implemented its Integrated Marketplace (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 Integrated Marketplace (IM), we and other SPP members submit generation offers to sell our power and bids to purchase power into the SPP market, with the SPP serving as a centralized dispatch of SPP members' generation resources. The SPP matches offers and bids based upon operating and reliability considerations. It is expected that 90% – 95% of all next day generation needed throughout the SPP territory will be cleared through this IM. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we will purchase from the IM. The activity for each market participant is settled in various time increments. When we sell more generation to the market than we purchase, based on the prescribed time increments, the net sale is included as part of electric revenues. When we purchase more generation from the market than we sell, based on the prescribed time increments, the net purchase is recorded as a component of fuel and purchased power on our financial statements. The net financial effect of these Integrated Marketplace transactions is included in our fuel adjustment mechanisms.

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 has completed and filed with the FERC a required interregional policy and procedure compliance filing, with implementation to occur once FERC has approved the filing. FERC's decision on SPP's Order No. 1000 interregional compliance filing is pending.

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. We estimate our net transmission costs will increase between $3 and $4 million in 2015 over what we currently recover in rates as a result of SPP's allocation methodology. We have cost recovery mechanisms in place in our Arkansas and Oklahoma jurisdictions that allow us to recover the additional SPP transmission costs outside the traditional rate case process. Currently no mechanism is in place to timely recover additional costs resulting from the portion of these transmission projects allocated to us other than through the traditional rate case process in our Missouri and Kansas jurisdictions. Within our current rate case proceeding in Missouri, we have requested a transmission recovery mechanism to be implemented effective August 2015.

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:

SPP's formal regional cost allocation review and benefit to cost imbalance analysis process is ongoing and being formalized within SPP's Open Access Transmission Tariff in 2015. This process will evaluate the long term projected benefits against the allocated costs of transmission projects to determine if remedies (cost reductions or benefit increases due to specific transmission projects) are needed for our customers. SPP will evaluate potential equity improvement remedies in its Integrated Transmission Planning (ITP), Inter-regional Transmission Planning (Order 1000) and regional cost allocation review (RCAR) processes with recommendations expected in July 2015.

SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement and Plum Point 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 will not be beneficial to our customers as it will increase transmission delivery costs for our Plum Point power station as well as utilize our transmission system without compensation.

As a result, SPP and its members have undertaken certain actions with FERC to address these issues and reduce the costs to our customers. FERC has set settlement evidentiary hearings for these issues. The dispute is likely to move into litigation hearings before the FERC if the settlement process is unsuccessful.

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.

In accordance with ASC guidance on regulated operations, we currently have deferred approximately $0.5 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.

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, 2014 and 2013, there were 820,838 and 127,774 shares available for issuance in this plan, respectively. 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, 2014 and 2013 there were 196,399 and 256,448 shares available to be issued respectively. (See Note 7 for further discussion of these plans).

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.

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, 2014, 2013 and 2012:

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, 2014 or 2013.

At December 31, 2014 and 2013, the balance of long-term debt outstanding was as follows (in thousands):

	2014			2013

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
3.73% 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			—
First mortgage bonds (EDG):
6.82% Series due 2036⁽¹⁾		55,000			55,000

		698,000			638,000
Senior Notes, 6.70% Series due 2033⁽¹⁾		62,000			62,000
Senior Notes, 5.80% Series due 2035⁽¹⁾		40,000			40,000
Other		4,167			4,441
Less unamortized net discount		(686	)		(739	)

		803,481			743,702
Less current obligations under capital lease		(292	)		(274	)

TOTAL LONG-TERM DEBT	$	803,189		$	743,428

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.

On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due 2033 and $120.0 million of 4.32% First Mortgage Bonds due 2043. The delayed settlement occurred on May 30, 2013. The interest is payable semi-annually on the bonds on each May 30 and November 30, commencing November 30, 2013. 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. A portion of the proceeds were used to redeem all

$98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013. The remaining proceeds were used for general corporate purposes. The bonds have not been registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage.

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

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 EDE Mortgage is limited by terms of the mortgage to $1 billion. Based on this limit and our current level of outstanding first mortgage bonds, we are limited to the issuance of $357 million of new first mortgage bonds. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the year ended December 31, 2014 would permit us to issue approximately $615.9 million of new first mortgage bonds based on this test with an assumed interest rate of 5.5%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2014, we had retired bonds and net property additions which would enable the issuance of at least $952.5 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2014, we are in compliance with all restrictive covenants of the EDE Mortgage.

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300 million. Substantially all of the property, plant and equipment of The Empire District Gas Company are 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 to 1. As of December 31, 2014, this test would allow us to issue approximately $19.7 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.

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

At December 31, 2014, total short-term borrowings consisted of $44.0 million in commercial paper and no borrowings from our line of credit. During 2014 and 2013 our short-term borrowings outstanding averaged (in millions)

The weighted average interest rates and the weighted average interest rate of borrowings outstanding at December 31, 2014 and 2013 were:.

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, 2014, we were in compliance with this covenant as our ratio of total indebtedness to total capitalization was 0.52 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, 2014, 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, 2014; however, $44.0 million was used to back up our outstanding commercial paper.

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, 2014, consistent with previous years. See Note 1.

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 $9.0 million and $7.0 million during 2014 and 2013, 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. 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.

Our net pension liability increased $20.6 million in 2014, which was recorded as an increase in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The increase in the liability is primarily due to a significant actuarial loss resulting from decreases in discount rates and the adoption of a new mortality table. Our contribution is estimated to be approximately $12.8 million for 2015. 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 2016, the performance of our pension assets during 2015.

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 increased $19.9 million in 2014, which was recorded as an increase in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The increase in the liability is primarily due to a significant actuarial loss resulting from decreases in discount rates and the adoption of a new mortality table. 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 $5.0 million in 2015.

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).

The employee pension plan accumulated benefit obligation at December 31, 2014 and 2013 is presented in the following table (in thousands):

Net periodic benefit pension cost for 2014, 2013 and 2012, 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):

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

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, 2014, and the subsequent twelve-month period (in thousands):

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:

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

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 2014 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 2019 to an ultimate rate of 5.0% in 2019 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):

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.

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.

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:

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, 2014 and December 31, 2013 (in thousands):

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

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:

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, 2013

	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
Cash and cash equivalents	$	1,317	$	—	$	—	$	1,317		1.7	%
Fixed income
U.S. corporate debt		—		17,592		—		17,592		22.2	%
Foreign debt		—		2,871		—		2,871		3.6	%
Mutual funds — fixed income		8,325		—		—		8,325		10.5	%
Equity securities
U.S. equity		27,779		—		—		27,779		35.1	%
International equity		9,316		—		—		9,316		11.8	%
Mutual funds — equity		11,633		—		—		11,633		14.7	%

	$	58,370	$	20,463	$	—		78,833

Accrued interest & dividends								265		0.4	%

							$	79,098		100	%

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.

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.

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

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 lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the

maximum subscription price. As of December 31, 2014 and 2013, there were 820,838 and 127,774 shares available for issuance in this plan, respectively.

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, 2014 and 2013, there were 196,399 and 256,448 shares available to be issued, respectively.

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.

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):

Our 2006 Stock Incentive Plan (the 2006 Incentive Plan), which was set to expire 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. 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 2012, 2013 and 2014 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 Stock Incentive Plan. 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.

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 six months 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.

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

No shares of time-vested restricted stock were granted in 2012 as a result of the limitation on incentive compensation in effect in 2011 given our 2011 dividend suspension. A summary of time vested restricted stock activity under the plan for 2014, 2013 and 2012 is presented in the table below:

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 2012, 2013 and 2014 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. The fair value of the outstanding restricted stock awards was

estimated as of December 31, 2014, 2013 and 2012 using a Monte Carlo option valuation model. The assumptions used in the model for each grant year are noted in the following table:

Non-vested performance-based restricted stock awards (based on target number) as of December 31, 2014, 2013 and 2012 and changes during the year ended December 31, 2014, 2013 and 2012 were as follows:

At December 31, 2014 and 2013, unrecognized compensation expense related to estimated outstanding awards was $1.1 million and $0.5 million, respectively.

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 2014, 2013, or 2012, 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, 2014. The fair value of the outstanding options was estimated as of December 31, 2013 and 2012, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

A summary of option activity under the plan during the years ended December 31, 2014, 2013 and 2012 is presented below:

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, 2014, 2013, and 2012:

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, 2014, 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. 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:

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

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

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

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

	December 31,

Temporary Differences	2014		2013
Deferred tax assets:
Plant related basis differences	$	25,349	$	23,344
Net operating loss (NOL)		22,000		—
Regulated liabilities related to income taxes		13,350		13,576
Disallowed plant costs		1,754		1,841
Gains on hedging transactions		1,260		1,324
Pensions and other post-retirement benefits		1,175		544
Carry forward of income tax credit		6,367		6,374
Other		1,633		1,633

Total deferred tax assets	$	72,888	$	48,636

Deferred tax liabilities:
Depreciation, amortization and other plant related differences	$	363,337	$	297,175
Regulated assets related to income		37,180		37,806
Loss on reacquired debt		3,828		4,085
Amortization of intangibles		9,168		8,089
Deferred construction accounting costs		6,082		6,977
Other		11,545		11,548

Total deferred tax liabilities		431,140		365,680

NET DEFERRED TAX LIABILITIES	$	358,252	$	317,044

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

We do not have any unrecognized tax benefits as of December 31, 2014. 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 Tax Increase Prevention Act (the "Act") was signed into law on December 19, 2014. The Act restored several expired business tax provisions, including bonus depreciation for 2014. Our 2015 tax payments are expected to be higher than 2014 due to the expiration of bonus depreciation. However, we expect to utilize investment tax credits and net operating losses (NOLs) discussed below to partially offset the 2015 payments.

We generated $22.0 million of tax NOLs during 2014, mainly due to bonus depreciation. These losses may be carried back two years and are also available to offset future taxable income until 2034.

In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2. We utilized $0.7 million and $9.0 million of these credits on our 2012 and 2013 tax returns, respectively. Due to the passage of the Act, we were unable to use these credits on our 2014 tax return. We expect to use the remaining credits on our 2015 tax return. 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 apply to tax years beginning on or after January 1, 2014, and we plan to file a Form 3115 with the IRS with our 2014 income tax return to change our tax accounting method to comply with the regulations. It is anticipated that we will deduct approximately $33 million on our 2014 income tax return under IRS Code Section 481(a) as an adjustment required by the change in method of accounting. We plan to utilize the book capitalization method as allowable under the final regulations which we expect will have an immaterial impact on the effective tax rate.

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 that 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, 2014 and 2013, our property, plant and equipment accounts included the amounts in the following chart (in millions):

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, 2014 and 2013, our property, plant and equipment accounts included the amounts in the following chart (in millions):

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 that percentage of the station's operating costs. At December 31, 2014 and 2013, our property, plant and equipment accounts included the amounts in the following chart (in millions):

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.

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of December 31, 2014 (in millions).

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, 2014 are detailed in the table above.

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 (30 year) agreement for the purchase of an additional 50 megawatts of capacity from Plum Point. Commitments under this agreement are approximately $289.9 million through August 31, 2039, the end date of the agreement. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the MPSC on July 1, 2013. It is not currently our intention to exercise this option in 2015.

We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC, Houston, Texas to purchase the

energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We 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 20-year contract, which began on December 15, 2005, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. We do not own any portion of 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.

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). Construction costs through December 31, 2014 were $110.9 million for the project to date, excluding AFUDC. Final cost is expected to be approximately $112 million, excluding AFUDC.

We also 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 will include 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 mid-2016 at a cost estimated to range from $165 million to $175 million, excluding AFUDC. This amount is included in our five-year capital expenditure plan. Construction costs, consisting of pre-engineering, site preparation activities and contract costs incurred project to date through December 31, 2014 were $88.5 million, excluding AFUDC.

See "Environmental Matters" below for more information on both of these projects.

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, 2014.

Expenses incurred related to operating leases were $0.8 million, $0.8 million and $0.9 million for 2014, 2013, and 2012, respectively, excluding payments for wind generated purchased power agreements. The accumulated amount of amortization for our capital leases was $1.5 million and $1.3 million at December 31, 2014 and 2013, respectively.

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. Environmental requirements have changed frequently and become more stringent over time. We expect this trend to continue. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect any such costs to be material, although recoverable in rates.

The Federal Clean Air Act (CAA) and comparable state laws regulate air emissions from stationary sources such as electric power plants through permitting and/or emission control and related requirements. These requirements include maximum emission limits on our facilities for sulfur dioxide (SO2), particulate matter, nitrogen oxides (NOx), carbon monoxide (CO), and hazardous air pollutants including mercury. In the future they will include limits on greenhouse gases (GHG) such as carbon dioxide (CO₂).

In order to comply with current and forthcoming environmental regulations, we are taking actions to implement our compliance plan and strategy (Compliance Plan). The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), which we discuss further below, are the drivers behind our Compliance Plan and its implementation schedule. The MATS require reductions in mercury, acid gases and other emissions considered hazardous air pollutants (HAPS). They became effective in April 2012 and require full compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The CSAPR was first

proposed by the Environmental Protection Agency (EPA) in July 2010 as a replacement of CAIR and came into effect on January 1, 2015. We anticipate compliance costs associated with the MATS, CAIR and CSAPR regulations to be recoverable in our rates.

Our Compliance Plan largely follows the preferred plan presented in our Integrated Resource Plan (IRP), filed in mid-2013 with the MPSC. As described above under New Construction, the process of installing a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant has been completed. This addition required the retirement of Asbury Unit 2, a steam turbine rated at 14 megawatts that was used for peaking purposes. Asbury Unit 2 was retired on December 31, 2013.

In September 2012, we completed the transition of our Riverton Units 7 and 8 from operation on coal and natural gas to operation solely on natural gas. Riverton Unit 7 was permanently removed from service on June 30, 2014. Riverton Unit 8 and Riverton Unit 9, a small combustion turbine that requires steam from Unit 8 for start-up, are planned to be retired upon the conversion of Riverton Unit 12, a simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in mid-2016.

The CAA regulates the amount of NOx and SO2 an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx and SO2 limits. Through the end of 2014, NOx emissions were regulated by the CAIR and National Ambient Air Quality Standard (NAAQS) rules for ozone (discussed below). Beginning January 1, 2015, NOx emissions are regulated by CSAPR and NAAQS rules for ozone. Through the end of 2014, SO2 emissions were regulated by the Title IV Acid Rain Program and the CAIR. Beginning January 1, 2015, SO2 emissions are regulated by the Title IV Acid Rain Program and the CSAPR.

The CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of SO2 and/or NOx in 28 eastern states and the District of Columbia, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located. Kansas was not included in CAIR and our Riverton Plant was not affected. Arkansas, where our Plum Point Plant is located, was included for ozone season NOx but not for SO2. At this time we believe we are in compliance with CAIR, which was in its final year in 2014.

The CSAPR requires 23 states to reduce annual SO2 and NOx emissions to help downwind areas attain NAAQS for fine particulate matter. Twenty-five states are required to reduce ozone season NOx emissions to help downwind states attain NAAQS for ozone. The CSAPR NOx annual program impacts our Missouri and Kansas units while the CSAPR NOx ozone season program impacts our units in these two states plus our unit in Arkansas.

The CSAPR divides the states required to reduce SO2 into two groups. Both groups must reduce their SO2 emissions in Phase 1. Group 1 states, which include our sources in Missouri and Arkansas, must make additional SO2 reductions for Phase 2 in order to eliminate their significant contribution to air quality problems in downwind areas. Empire's units in Kansas are in Group 2 of the CSAPR SO2 program.

Under the CSAPR Program, in our most current five-year business plan (2015 – 2019), which assumes normal operations while maintaining compliance with permit conditions, we anticipate that it may be

economically beneficial to purchase allowances for some of these pollutants if needed, but at the time of this writing the allowance markets have not been fully developed. We are in position to comply with CSAPR in 2015.

As described above, the MATS standard became effective in April 2012, and requires compliance by April 2015 (with flexibility for extensions for reliability reasons). For all existing and new coal-fired electric utility steam generating units (EGUs), the MATS standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply. On March 28, 2013, the EPA finalized updates to certain emission limits for new power plants under the MATS. The new standards affect only new coal and oil-fired power plants that will be built in the future. The update does not change the final emission limits or other requirements for existing power plants. We are in position to comply with MATS in 2015.

Under the CAA, the EPA sets NAAQS for certain emissions considered harmful to public health and the environment, including particulate matter (PM), NOx, CO, SO2, and ozone which result from fossil fuel combustion. Our facilities are currently in compliance with all applicable NAAQS.

In January 2013, the EPA finalized the revised PM 2.5 primary annual standard at 12 ug/m³ (micrograms per cubic meter of air). States are required to meet the primary standard in 2020. The standard should have no impact on our existing generating fleet because the regional ambient monitor results are below the PM 2.5 required level. However, the PM 2.5 standards could impact future major modifications/construction projects that require additional permits.

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. Based on the current standard, our service territory is designated as attainment, meaning that it is in compliance with the standard. A revised ozone NAAQS was proposed by the EPA on November 25, 2014 and the final rule is expected in October 2015. We believe this revised Ozone NAAQS would affect our region but it's too early to determine what, if any, impact it would have on our generating plants at this time.

As the EPA began to prepare for future regulations, GHG emissions have been reported for several years under the Mandatory GHG Reporting Rule. EDE and EDG's GHG emissions for each year, since 2013, have been reported to the EPA as required.

A series of actions and decisions including the Tailoring Rule, which regulates carbon dioxide and other GHG emissions from certain stationary sources, have further set the foundation for the regulation of GHGs. However, because of the uncertainties regarding the final outcome of the GHG regulations (discussed below), the ultimate cost of compliance cannot be determined at this time. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates.

In April 2012, the EPA proposed a Carbon Pollution Standard for new power plants to limit the amount of carbon emitted by EGUs. This standard was rescinded, and a re-proposal of standards of performance for affected fossil fuel-fired EGUs was published in January 2014. The proposed rule applies only to new EGUs and sets separate standards for natural gas-fired combustion turbines and for fossil fuel-fired utility boilers. The proposal would not apply to existing units, including modifications such as those required to meet other air pollution standards which are currently being undertaken at our Asbury

facility and at the Riverton facility with the conversion of simple cycle Unit 12 to combined cycle. The final rule is expected in the summer of 2015.

On June 2, 2014, the EPA released the proposed rule for limiting carbon emissions from existing power plants. The "Clean Power Plan" requires a 30% 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. The EPA has identified four building block strategies to achieve the best system of emission reduction (BSER). Included in these strategies are the following: efficiency improvements at fossil fuel power plants; using lower-emitting sources (such as natural gas combined cycle units); using more renewables and keeping nuclear sources; and using power more efficiently. States will use the building blocks to craft their compliance plans or may work with other states in developing a regional approach to compliance, in which case additional time is given for implementation.

The EPA is scheduled to issue the final rule for existing power plants by summer of 2015. Each state must submit its initial compliance plan by the summer of 2016 with additional time available by request until the summer of 2017 for a single state or the summer of 2018 for a multi-state approach. The EPA received greater than 2 million public comments by the December 1, 2014 closure of the comment period. State, federal and industry representatives voiced their concerns with the regulation as written and the potential impact on electric grid reliability and the cost to implement. State and industry representatives including Empire continue to evaluate potential paths forward if the rule is finalized as proposed by the EPA.

Also, on June 2, 2014, the EPA released the proposed carbon pollution standards for modified and reconstructed stationary EGUs. The proposed rule focuses on electric utility steam generating units and natural gas-fired stationary combustion turbines. The comment period ended October 16, 2014 and the EPA anticipates issuing a final rule in June 2015.

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 Riverton Units 7 and 8 and Iatan Unit 1, which utilize once-through cooling water, were affected by regulations for Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) Phase II. In 2007, the United States Court of Appeals remanded key sections of these CWA regulations to the EPA. The EPA suspended the regulations. Following a series of court approved delays, the EPA published the final rule on August 15, 2014 with an effective date of October 14, 2014. Court challenges are expected. We expect the regulations to have a limited impact at Riverton given the planned retirement of unit 8 scheduled in 2016. A new intake structure design and cooling tower will be constructed as part of the Unit 12 conversion at Riverton. 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. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed 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.

We own and maintain a coal ash impoundment located at our Asbury Power Plant. Additionally, we own a 12% interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a

coal ash impoundment at Plum Point. As a result of the transition from coal to natural gas fuel for Riverton Units 7 and 8, the former Riverton ash impoundment has been capped and closed. Final closure as an industrial (coal combustion waste) landfill was approved on June 30, 2014 by the Kansas Department of Health and Environment (KDHE).

On April 19, 2013, the EPA signed a notice of proposed rulemaking to revise its wastewater effluent limitation guidelines and standards under the CWA for coal-fired power plants. The proposal calls for updates to operating permits beginning in July 2017. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs that might result from any new standards. All of our coal ash impoundments are compliant with existing state and federal regulations.

In June 2010, the EPA proposed to regulate coal combustion residuals (CCRs) under the Federal Resource Conservation and Recovery Act (RCRA). In the proposal, the EPA presented two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. On December 19, 2014 the EPA finalized the requirements under the subtitle D solid waste provisions. We expect compliance to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury Power Plant. This preliminary estimate was developed before the rule was finalized and will be updated to conform to the final rule. We expect resulting costs to be recoverable in our rates.

We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. Our Detailed Site Investigation (DSI) has been completed and was submitted to MDNR for review and approval in on January 21, 2015. Receipt of the final construction permit for the waste landfill is expected in early 2016.

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

Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables in 2012, increasing to 15% by 2016, and to 20% by 2020. We are currently in compliance with this regulatory requirement as a result of purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas.

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,

	2014
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information:
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

The following is a summary of quarterly results for 2014 and 2013 (dollars in thousands except per share amounts):

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.

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 Accounting Standards Codification (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, 2014 and 2013, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of December 31, (in thousands):

At December 31, 2014, approximately $6.0 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, 2014 and 2013, 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

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, 2014, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for 2015 and the next four years are hedged at the following average prices per Dekatherm (Dth):

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.

At December 31, 2014, the following transmission congestion rights (TCR) have been obtained from TCR auctions to hedge congestion costs in the SPP Integrated Marketplace:

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, 2014 we had 1.2 million Dths in storage on the three pipelines that serve our customers. This represents 58% 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, 2014 (Dth in thousands).

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

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, 2014 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.

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, 2014 and December 31, 2013, 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.

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 Transmission congestion rights positions (TCR), 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, 2013:

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, 2014 and 2013 was $799 million and $739 million, compared to a fair market value of approximately $829 million and $715 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, 2014 or that will be realizable in the future.

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,

	2014		2013		2012
Power operation expense (other than fuel)	$	16,089	$	15,643	$	15,045
Electric transmission and distribution expense		27,919		21,863		17,083
Natural gas transmission and distribution expense		2,362		2,498		2,443
Customer accounts & assistance expense		11,239		11,180		10,211
Employee pension expense⁽¹⁾		10,590		10,736		10,180
Employee healthcare plan⁽¹⁾		9,147		10,190		9,825
General office supplies and expense		15,024		12,850		10,776
Administrative and general expense		14,385		14,800		15,091
Bad debt expense		3,420		3,665		3,038
Regulatory reversal of gain on sale of assets		44		1,236		—
Miscellaneous expense		472		672		679

TOTAL	$	110,691	$	105,333	$	94,371

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

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, 2014.

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, 2014.

The effectiveness of our internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

There have been no changes in our internal control over financial reporting that occurred during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 30, 2015, 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.

Information required by this item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 30, 2015, 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 30, 2015, which is incorporated herein by reference.

There are no arrangements the operation of which may at a subsequent date result in a change in control of Empire.

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, 2014:

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 30, 2015 which is incorporated herein by reference.

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

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.


(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)		By-laws of Empire as amended February 6, 2014 (Incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K dated February 6, 2014 and filed February 7, 2014, 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).
(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 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)		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).
(q)		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).
(r)		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).
(s)		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).
(t)		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).
(u)		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).


(v)		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).
(w)		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).
(x)		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.†*
(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).†
(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.†*
(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)		Summary of Annual Incentive Plan.†*
(o)		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).†
(p)		Form of Notice of Award of Time-Based Restricted Stock. (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).
(q)		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).
(r)		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).†
(s)		Third Amended and Restated Unsecured Credit Agreement dated as of January 17, 2012, among The Empire District Electric Company, UMB Bank, N.A. as administrative agent, Bank of America, N.A., as syndication agent, Wells Fargo Bank, N.A., as documentation agent, and the lenders named therein (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated January 17, 2012 and filed January 19, 2012, File No. 1-3368).
(t)		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).
(12)		Computation of Ratios of Earnings to Fixed Charges.*
(21)		Subsidiaries of Empire.*
(23)		Consent of PricewaterhouseCoopers LLP.*
(24)		Powers of Attorney.*
(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, 2014, filed with the SEC on February 20, 2015, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for 2014, 2013 and 2012, (ii) the Consolidated Balance Sheets at December 31, 2014 and December 31, 2013, (iii) the Consolidated Statements of Cash Flows for 2014, 2013 and 2012, and (iv) Notes to Consolidated Financial Statements.**

Valuation and Qualifying Accounts

Years ended December 31, 2014, 2013 and 2012:

			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, 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
Year ended December 31, 2012:
Reserve deducted from assets: accumulated provision for uncollectible accounts.	$	1,137,644	$	3,052,397	Recovery of amounts previously written off	$	1,956,549	Accounts written off	$	4,758,917	$	1,387,673

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.

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.


(Mark One)
ý		Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2014
or
o		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to .


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)

Title of each class		Name of each exchange on which registered

Common Stock ($1 par value)		New York Stock Exchange


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


Electric segment sales*	90.8	%
Gas segment sales	8.0
Other segment sales	1.2


The Company's proxy statement, filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, for its Annual Meeting of Stockholders to be held on April 30, 2015		Part of Item 10 of Part III All of Item 11 of Part III Part of Item 12 of Part III All of Item 13 of Part III All of Item 14 of Part III

		Page

	Forward Looking Statements	3
PART I
ITEM 1.	BUSINESS	5
	General	5
	Electric Generating Facilities and Capacity	6
	Gas Facilities	7
	Construction Program	8
	Fuel and Natural Gas Supply	9
	Employees	11
	Electric Operating Statistics	12
	Gas Operating Statistics	13
	Executive Officers and other Officers of Empire	13
	Regulation	15
	Environmental Matters	16
	Conditions Respecting Financing	16
	Our Web Site	17
ITEM 1A.	RISK FACTORS	17
ITEM 1B.	UNRESOLVED STAFF COMMENTS	23
ITEM 2.	PROPERTIES	24
	Electric Segment Facilities	24
	Gas Segment Facilities	25
	Other Segment	25
ITEM 3.	LEGAL PROCEEDINGS	26
ITEM 4.	MINE SAFETY DISCLOSURES	26
PART II
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	27
ITEM 6.	SELECTED FINANCIAL DATA	29
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29
	Executive Summary	29
	Results of Operations	33
	Rate Matters	41
	Markets and Transmission	42
	Liquidity and Capital Resources	42
	Contractual Obligations	48
	Dividends	48
	Off-Balance Sheet Arrangements	49
	Critical Accounting Policies	49
	Recently Issued Accounting Standards	52
ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	53
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	56
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	124
ITEM 9A.	CONTROLS AND PROCEDURES	124
ITEM 9B.	OTHER INFORMATION	124
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	125
ITEM 11.	EXECUTIVE COMPENSATION	125
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	125
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	126
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	126
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	127
	SIGNATURES	133


Residential	63.4	%
Commercial	26.3
Industrial	1.0
Transportation	7.7
Miscellaneous	1.6

Plant			Primary Fuel

State Line Combined Cycle (60% ownership)	297	⁽²⁾	Natural Gas
Riverton — Natural Gas	226	⁽³⁾	Natural Gas
Empire Energy Center	260		Natural Gas
State Line Unit No. 1	93		Natural Gas
Asbury	194	⁽⁴⁾	Coal
Iatan (12% ownership)	190	⁽²⁾	Coal
Plum Point Energy Station (7.52% ownership)	50	⁽²⁾	Coal
Ozark Beach	16		Hydro

TOTAL	1,326

Year

2015	86	1326		1412
2016	86	1377	⁽²⁾	1463	⁽²⁾
2017	86	1377		1463
2018	86	1377		1463
2019	86	1377		1463

Service Area		Name of Pipeline

South		Southern Star Central Gas Pipeline
North		Panhandle Eastern Pipe Line Company
Northwest		ANR Pipeline Company



Steam generation units — coal	47.5	%	47.0	%
Combustion turbine generation units — natural gas	26.5		24.3
Hydro generation	1.2		1.0
Purchased power — windfarms	18.2		14.8
Purchased power — other	6.6		12.9



Coal	63.7	%	65.9	%
Natural gas	35.8		34.0
Fuel oil	0.4		0.1
Tire derived fuel	0.1		0.0

Fuel Type / Facility	2014		2013		2012

Coal — Iatan	$	1.738	$	1.756	$	1.760
Coal — Asbury		2.363		2.432		2.395
Coal — Riverton⁽¹⁾		0.000		0.000		2.541
Coal — Plum Point		2.314		2.123		1.804
Natural Gas		5.268		4.952		4.493
Oil		17.512		21.870		20.291

Weighted average cost of fuel burned per kilowatt-hour generated	$	2.9700	$	2.8074	$	2.6742

Service Area	Name of Pipeline	2014		2013		2012

South	Southern Star Central Gas Pipeline	$	4.6986	$	5.4998	$	6.4329
North	Panhandle Eastern Pipe Line Company		6.0201		5.9746		6.8990
Northwest	ANR Pipeline Company		4.8499		4.7589		5.0898
	Weighted average cost per mcf	$	4.9564	$	5.4949	$	6.3305

	High		Low		Close		Dividends Paid Per Share

2014 Quarter Ended:
March 31	$	24.50	$	22.04	$	24.32	$	0.255
June 30		25.70		23.23		25.68		0.255
September 30		26.00		24.00		24.15		0.255
December 31		31.20		24.09		29.74		0.260
2013 Quarter Ended:
March 31	$	22.41	$	20.57	$	22.40	$	0.250
June 30		23.35		21.26		22.31		0.250
September 30		24.32		20.77		21.66		0.250
December 31		23.26		21.27		22.69		0.255

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

The Empire District Electric Company	$	100.00	$	126.59	$	124.13	$	125.95	$	146.80	$	200.39
S&P Electric Utilities Index	$	100.00	$	103.43	$	125.12	$	124.43	$	134.13	$	176.00
S&P 500 Index	$	100.00	$	115.06	$	117.49	$	136.30	$	180.44	$	205.14

	Total Gas Delivered to Customers

(bcf sales)	2014		2013		% Change			2013		2012		% Change
Residential		2.76		2.74		0.6	%		2.74		2.01		36.4	%
Commercial⁽¹⁾		1.27		1.35		(5.5	)		1.35		1.05		28.5
Industrial		0.06		0.07		(13.5	)		0.07		0.06		23.9
Other⁽²⁾		0.04		0.04		3.1			0.04		0.02		44.8

Total retail sales		4.13		4.20		(1.6	)		4.20		3.14		33.6
Transportation sales⁽¹⁾		4.92		4.53		8.6			4.53		4.25		6.6

Total gas operating sales		9.05		8.73		3.7			8.73		7.39		18.1


Retail customers	92.7	%
Sales subject to FERC jurisdiction	6.5
Miscellaneous sources	0.8



Corporate Credit Rating	n/r*	Baa1	BBB
EDE First Mortgage Bonds	BBB+	A2	A-
Senior Notes	BBB	Baa1	BBB
Commercial Paper	F3	P-2	A-2
Outlook	Stable	Stable	Stable

	2014		2013		2012

Electric	$	61.5	$	58.6	$	52.6
Gas		2.9		2.3		1.3
Other		2.7		2.5		1.8

Net income	$	67.1	$	63.4	$	55.7



Residential	43.4	%	43.9	%	43.5	%
Commercial	31.6		31.3		32.2
Industrial	15.5		15.5		16.0
Wholesale on-system	4.1		3.9		3.8
Miscellaneous sources*	2.8		2.9		2.8
Other electric revenues	2.6		2.5		1.7

	Operating Revenues and Cost of Gas Sold

($ in millions)	2014		2013		% Change			2013		2012		% Change
Residential	$	32.9	$	31.6		4.2	%	$	31.6	$	24.7		27.6	%
Commercial⁽¹⁾		13.6		13.7		(0.2	)		13.7		10.8		26.6
Industrial		0.5		0.5		4.2			0.5		0.5		11.0
Other⁽²⁾		0.4		0.3		6.8			0.3		0.3		38.7

Total retail revenues	$	47.4	$	46.1		2.9		$	46.1	$	36.3		27.1
Other revenues		0.4		0.4		5.0			0.4		0.3		7.5
Transportation revenues⁽¹⁾		4.0		3.5		12.9			3.5		3.2		10.0

Total gas operating revenues	$	51.8	$	50.0		3.6		$	50.0	$	39.8		25.6
Cost of gas sold		27.0		25.8		4.8			25.8		18.6		38.4

Gas segment gross margins	$	24.8	$	24.2		2.4		$	24.2	$	21.2		14.3

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

Distribution operation expense	$	(0.2	)	$	0.2
Transmission operation expense		0.1			(0.1	)
Customer accounts expense		(0.6	)		0.3
Miscellaneous		(0.1	)		0.1

TOTAL	$	(0.8	)	$	0.5

	2014			2013			2012

Consolidated provision for income taxes	$	39.2		$	37.5		$	34.2
Consolidated effective federal and state income tax rates		36.9	%		37.1	%		38.0	%

($ in millions)	2014		2013		2012

Allowance for equity funds used during construction	$	6.4	$	3.8	$	1.1
Allowance for borrowed funds used during construction		3.5		2.1		0.8

Total AFUDC	$	9.9	$	5.9	$	1.9

	Interest Charges ($ in millions)

	2014		2013		Change			2013		2012		Change
Long-term debt interest	$	40.6	$	40.3		0.7	%	$	40.3	$	40.2		0.4	%
Short-term debt interest		0.1		0.1		90.5			0.1		0.2		(68.2	)
Other interest		1.0		1.1		(7.1	)		1.1		1.1		(2.1	)

Total interest charges	$	41.7	$	41.5		0.6		$	41.5	$	41.5		0.0

Jurisdiction	Date Requested	Annual Increase Granted				Date Effective

Arkansas — Electric	December 3, 2013	$	1,366,809	11.34	%	September 26, 2014
Missouri — Electric	July 6, 2012	$	27,500,000	6.78	%	April 1, 2013
Missouri — Water	May 21, 2012	$	450,000	25.5	%	November 23, 2012
Kansas — Electric	June 17, 2011	$	1,250,000	5.20	%	January 1, 2012
Oklahoma — Electric	June 30, 2011	$	240,000	1.66	%	January 4, 2012

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

Diluted earnings per share	$	1.55	$	1.48	$	1.32
Dividends paid per share	$	1.025	$	1.005	$	1.00
Total dividends paid	$	44.4	$	43.0	$	42.3
Retained earnings year-end balance	$	90.3	$	67.6	$	47.1


Net unrealized mark-to-market losses for physical forward natural gas contracts	$	2.8
Net unrealized mark-to-market losses for financial natural gas contracts		10.3

Net credit exposure	$	13.1


/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
St. Louis, Missouri February 20, 2015

	2014		2013		2012

Supplemental cash flow information:
Interest paid	$	40,127	$	39,033	$	38,802
Income taxes (refunded) paid, net of refund		23,103		10,584		(592	)
Supplementary non-cash investing activities:
Change in accrued additions to property, plant and equipment not reported above	$	9,427	$	5,420	$	9,345
Capital lease obligations for purchase of new equipment		—		—		—

Customer

Residential	40.0	%
Commercial	29.2
Industrial	14.4
Wholesale on-system	3.8
Wholesale off-system	7.6
Miscellaneous sources, primarily public authorities	2.6
Other electric revenues	2.4

(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

	2014		2013

Electric fuel inventory	$	26,454	$	17,003
Natural gas inventory		5,040		3,584
Materials and supplies		26,305		28,224

TOTAL	$	57,799	$	48,811



Weighted Average Number Of Shares
Basic	43,291,031	42,781,382	42,256,641
Dilutive Securities:
Performance-based restricted stock awards	8,809	12,142	14,500
Dividend equivalents	—	—	6,329
Employee stock purchase plan	3,422	1,729	1,996
Stock options	—	61	3,160
Time-based restricted stock awards	10,666	7,907	1,820

Total dilutive securities	22,897	21,839	27,805



Diluted weighted average number of shares	43,313,928	42,803,221	42,284,446



Antidilutive Shares	25,259	107,100	128,500

	2014		2013		2012

Provision for depreciation
Regulated — Electric and Water	$	66,600	$	63,192	$	57,467
Regulated — Gas		3,851		3,763		3,602
Non-Regulated		1,891		1,938		1,538

TOTAL		72,342		68,893		62,607
Amortization		2,692		2,492		1,041

TOTAL	$	75,034	$	71,385	$	63,648



Annual depreciation rates
Electric and water	3.0	%	3.0	%	2.8	%
Gas	5.2	%	5.4	%	5.4	%
Non-Regulated	4.7	%	5.0	%	4.2	%
TOTAL COMPANY	3.0	%	3.1	%	2.9	%