10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

xQuarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2013 or

oTransition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                              to                         .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Kansas	44-0236370
(State of Incorporation)	(I.R.S. Employer Identification No.)
602 S. Joplin Avenue, Joplin, Missouri	64801
(Address of principal executive offices)	(zip code)

Registrant’s telephone number: (417) 625-5100

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  x  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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x  No  o

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.

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

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

As of October 31, 2013, 42,968,104 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

		PAGE
	Forward Looking Statements	3
Part I -	Financial Information:
Item 1.	Financial Statements:
	a. Consolidated Statements of Income	5
	b. Consolidated Balance Sheets	8
	c. Consolidated Statements of Cash Flows	10
	d. Notes to Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
	Executive Summary	32
	Results of Operations	35
	Rate Matters	43
	Competition and Markets	44
	Liquidity and Capital Resources	45
	Contractual Obligations	49
	Dividends	50
	Off-Balance Sheet Arrangements	51
	Critical Accounting Policies and Estimates	51
	Recently Issued Accounting Standards	51
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	53
Part II-	Other Information:
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds - (none)
Item 3.	Defaults Upon Senior Securities - (none)
Item 4.	Mine Safety Disclosures — (none)
Item 5.	Other Information	54
Item 6.	Exhibits	54
	Signatures	55

2

FORWARD LOOKING STATEMENTS

Certain matters discussed in this quarterly 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, impacts from the 2011 tornado, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like “anticipate”, “believe”, “expect”, “project”, “objective” or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:

·weather, business and economic conditions, recovery and rebuilding efforts relating to the 2011 tornado and other factors which may impact sales volumes and customer growth;

·the costs and other impacts resulting from natural disasters, such as tornados and ice storms;

·the amount, terms and timing of rate relief we seek and related matters;

·the results of prudency and similar reviews by regulators of costs we incur, including capital expenditures, fuel and purchased power costs and Southwest Power Pool (SPP) regional transmission organization (RTO) expansion costs, including any regulatory disallowances that could result from prudency reviews;

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

·competition and markets, including the SPP Energy Imbalance Services Market and SPP Day-Ahead Market and the impact of energy efficiency and alternative energy sources;

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

·volatility in the credit, equity and other financial markets and the resulting impact on our short term debt costs and our ability to issue debt or equity securities, or otherwise secure funds to meet our capital expenditure, dividend and liquidity needs;

·the effect of changes in our credit ratings on the availability and cost of funds;

·the performance of our pension assets and other post employment benefit plan assets and the resulting impact on our related funding commitments;

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

·our exposure to the credit risk of our hedging counterparties;

·changes in accounting requirements (including the potential consequences of being required to report in accordance with IFRS rather than U. S. GAAP);

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

·the timing of accretion estimates, and integration costs relating to completed and contemplated acquisitions and the performance of acquired businesses;

·rate regulation, growth rates, discount rates, capital spending rates, terminal value calculations and other factors integral to the calculations utilized to test the impairment of goodwill, in addition to market and economic conditions which could adversely affect the analysis and ultimately negatively impact earnings;

·the success of efforts to invest in and develop new opportunities;

·the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs;

·interruptions or changes in our coal delivery, gas transportation or storage agreements or arrangements;

·operation of our electric generation facilities and electric and gas transmission and distribution systems, including the performance of our joint owners;

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

·other circumstances affecting anticipated rates, revenues and costs.

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

We caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual results, performance or achievements to

3

differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements.

4

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended
	September 30
	2013			2012
	(000’s except per share amounts)
Operating revenues:
Electric	$	150,370		$	152,730
Gas	4,952			4,999
Other	2,164			1,473
	157,486			159,202
Operating revenue deductions:
Fuel and purchased power	44,864			48,036
Cost of natural gas sold and transported	1,191			1,251
Regulated operating expenses	26,100			24,038
Other operating expenses	805			776
Maintenance and repairs	10,674			10,972
Depreciation and amortization	17,735			15,108
Provision for income taxes	14,197			15,428
Other taxes	9,024			8,311
	124,590			123,920
Operating income	32,896			35,282
Other income and (deductions):
Allowance for equity funds used during construction	1,128			292
Interest income	5			265
Benefit/(provision) for other income taxes	47			(49		)
Other — non-operating expense, net	(333		)	(274		)
	847			234
Interest charges:
Long-term debt	10,102			9,950
Short-term debt	—			16
Allowance for borrowed funds used during construction	(606		)	(243		)
Other	251			251
	9,747			9,974
Net income	$	23,996		$	25,542
Weighted average number of common shares outstanding - basic	42,869			42,345
Weighted average number of common shares outstanding - diluted	42,898			42,374
Total earnings per weighted average share of common stock — basic and diluted	$	0.56		$	0.60
Dividends declared per share of common stock	$	0.25		$	0.25

See accompanying Notes to Consolidated Financial Statements.

5

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Nine Months Ended
	September 30,
	2013			2012
	(000’s except per share amounts)
Operating revenues:
Electric	$	406,158		$	396,546
Gas	33,222			26,486
Other	5,892			4,945
	445,272			427,977
Operating revenue deductions:
Fuel and purchased power	132,179			138,792
Cost of natural gas sold and transported	16,229			11,601
Regulated operating expenses	79,884			70,230
Other operating expenses	2,470			2,145
Maintenance and repairs	29,764			30,893
Loss on plant disallowance	2,409			—
Depreciation and amortization	51,471			45,111
Provision for income taxes	28,693			28,185
Other taxes	26,309			24,166
	369,408			351,123
Operating income	75,864			76,854
Other income and (deductions):
Allowance for equity funds used during construction	2,521			395
Interest income	522			568
Benefit/(provision) for other income taxes	12			(251		)
Other — non-operating expense, net	(912		)	(703		)
	2,143			9
Interest charges:
Long-term debt	30,243			30,242
Short-term debt	59			175
Allowance for borrowed funds used during construction	(1,383		)	(410		)
Other	805			802
	29,724			30,809
Net income	$	48,283		$	46,054
Weighted average number of common shares outstanding - basic	42,715			42,197
Weighted average number of common shares outstanding - diluted	42,737			42,220
Total earnings per weighted average share of common stock — basic and diluted	$	1.13		$	1.09
Dividends declared per share of common stock	$	0.75		$	0.75

See accompanying Notes to Consolidated Financial Statements.

6

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Twelve Months Ended
	September 30,
	2013			2012
	(000’s except per share amounts)
Operating revenues:
Electric	$	520,265		$	514,515
Gas	46,585			39,571
Other	7,542			6,657
	574,392			560,743
Operating revenue deductions:
Fuel and purchased power	172,283			183,288
Cost of natural gas sold and transported	23,262			18,384
Regulated operating expenses	104,024			93,572
Other operating expenses	3,056			2,763
Maintenance and repairs	39,315			42,261
Loss on plant disallowance	2,409			—
Depreciation and amortization	66,807			59,669
Provision for income taxes	34,603			33,727
Other taxes	33,402			30,722
	479,161			464,386
Operating income	95,231			96,357
Other income and (deductions):
Allowance for equity funds used during construction	3,273			537
Interest income	926			1,055
Benefit/(provision) for other income taxes	201			(531		)
Other — non-operating expense, net	(2,119		)	(1,005		)
	2,281			56
Interest charges:
Long-term debt	40,194			40,896
Short-term debt	71			192
Allowance for borrowed funds used during construction	(1,754		)	(470		)
Other	1,091			1,050
	39,602			41,668
Net income	$	57,910		$	54,745
Weighted average number of common shares outstanding — basic	42,644			42,141
Weighted average number of common shares outstanding — diluted	42,665			42,163
Total earnings per weighted average share of common stock — basic and diluted	$	1.36		$	1.30
Dividends declared per share of common stock	$	1.00		$	0.75

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	September 30, 2013		December 31, 2012
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	2,207,736	$	2,176,188
Gas	72,127		69,851
Other	39,095		37,983
Construction work in progress	129,219		56,347
	2,448,177		2,340,369
Accumulated depreciation and amortization	718,492		682,737
	1,729,685		1,657,632
Current assets:
Cash and cash equivalents	16,383		3,375
Restricted cash	1,773		4,357
Accounts receivable — trade, net of allowance $988 and $1,388, respectively	51,485		38,874
Accrued unbilled revenues	16,335		23,254
Accounts receivable — other	14,900		13,277
Fuel, materials and supplies	53,050		61,870
Prepaid expenses and other	20,360		21,806
Unrealized gain in fair value of derivative contracts	333		96
Regulatory assets	6,398		6,377
	181,017		173,286
Noncurrent assets and deferred charges:
Regulatory assets	231,950		243,958
Goodwill	39,492		39,492
Unamortized debt issuance costs	8,722		7,606
Unrealized gain in fair value of derivative contracts	—		191
Other	4,942		4,204
	285,106		295,451
Total Assets	$	2,195,808	$	2,126,369

(Continued)

See accompanying Notes to Consolidated Financial Statements.

8

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	September 30, 2013		December 31, 2012
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 42,939,207 and 42,484,363 shares issued and outstanding, respectively	$	42,939	$	42,484
Capital in excess of par value	637,003		628,199
Retained earnings	63,350		47,115
Total common stockholders’ equity	743,292		717,798
Long-term debt (net of current portion):
Obligations under capital lease	4,237		4,441
First mortgage bonds and secured debt	637,569		487,541
Unsecured debt	101,680		199,644
Total long-term debt	743,486		691,626
Total long-term debt and common stockholders’ equity	1,486,778		1,409,424
Current liabilities:
Accounts payable and accrued liabilities	55,281		66,559
Current maturities of long-term debt	327		714
Short-term debt	—		24,000
Regulatory liabilities	4,295		6,303
Customer deposits	12,518		12,001
Interest accrued	13,766		5,902
Other current liabilities	1,894		—
Unrealized loss in fair value of derivative contracts	3,078		3,403
Taxes accrued	16,781		2,992
	107,940		121,874
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	134,531		131,055
Deferred income taxes	320,042		301,967
Unamortized investment tax credits	18,708		18,897
Pension and other postretirement benefit obligations	107,299		120,808
Unrealized loss in fair value of derivative contracts	3,089		3,819
Other	17,421		18,525
	601,090		595,071
Total Capitalization and Liabilities	$	2,195,808	$	2,126,369

See accompanying Notes to Consolidated Financial Statements.

9

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended
	September 30,
	2013			2012
	($-000’s)
Operating activities:
Net income	$	48,283		$	46,054
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	53,048			55,043
Pension and other postretirement benefit costs, net of contributions	(5,458		)	1,486
Deferred income taxes and unamortized investment tax credit, net	21,579			26,906
Allowance for equity funds used during construction	(2,521		)	(395		)
Stock compensation expense	2,334			1,893
Loss on plant disallowance	2,409			—
Regulatory reversal of gain on sale of assets	1,236			—
Non-cash loss on derivatives	169			3,074
Other	—			(16		)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	(5,877		)	496
Fuel, materials and supplies	6,652			1,300
Prepaid expenses, other current assets and deferred charges	533			(8,953		)
Accounts payable and accrued liabilities	(21,708		)	(14,437		)
Asset retirement obligations	(363		)	—
Interest, taxes accrued and customer deposits	22,170			19,614
Other liabilities and other deferred credits	(4,845		)	4,001
Net cash provided by operating activities	117,641			136,066
Investing activities:
Capital expenditures — regulated	(107,074		)	(99,036		)
Capital expenditures and other investments — non-regulated	(1,290		)	(2,349		)
Decrease in restricted cash	2,585			—
Net cash used in investing activities	(105,779		)	(101,385		)
Financing activities:
Proceeds from first mortgage bonds, net	150,000			88,000
Long-term debt issuance costs	(1,607		)	(1,066		)
Proceeds from issuance of common stock, net of issuance costs	7,391			6,522
Repayment of first mortgage bonds	—			(88,029		)
Net short-term debt repayments	(24,000		)	(10,000		)
Redemption of senior notes	(98,000		)	—
Dividends	(32,048		)	(31,665		)
Other	(590		)	(680		)
Net cash provided by / (used in) financing activities	1,146			(36,918		)
Net increase (decrease) in cash and cash equivalents	13,008			(2,237		)
Cash and cash equivalents at beginning of period	3,375			5,408
Cash and cash equivalents at end of period	$	16,383		$	3,171

See accompanying Notes to Consolidated Financial Statements.

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

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 which provides natural gas distribution to customers in 48 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business.

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

The information furnished reflects all adjustments which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2012.

Note 2 - Recently Issued and Proposed Accounting Standards

Balance Sheet Offsetting:  The FASB amended the guidance governing the offsetting, or netting, of assets and liabilities on the balance sheet.  Under the revised guidance, an entity is required to disclose both the gross and net information about instruments and transactions that are eligible for offset on the balance sheet, as well as instruments or transactions subject to a master netting agreement. This standard was effective for annual periods beginning after January 1, 2013.  We implemented this standard in the first quarter of 2013 and it did not have a material impact on our results of operations, financial position or liquidity.

Note 3— Regulatory Matters

On February 27, 2013, the MPSC approved a joint settlement agreement for our 2012 Missouri rate case. 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. The agreement also included an increase in depreciation rates, recovery of deferred tornado costs over the next ten years 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.

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

11

Regulatory Assets and Liabilities

	September 30, 2013			December 31, 2012
Regulatory Assets:
Current:
Under recovered fuel costs(1)	$	302		$	2,885
Current portion of long-term regulatory assets(1)	6,096			3,492
Regulatory assets, current(1)	6,398			6,377
Long-term:
Pension and other postretirement benefits(2)	129,110			136,480
Income taxes	48,418			48,759
Deferred construction accounting costs	16,385			16,717
Unamortized loss on reacquired debt	11,246			12,142
Unsettled derivative losses — electric segment	5,613			6,557
System reliability — vegetation management	7,783			9,002
Storm costs(3)	5,084			4,828
Asset retirement obligation	4,616			4,430
Customer programs	4,785			4,356
Unamortized loss on interest rate derivative	1,001			1,147
Deferred operating and maintenance expense	1,863			2,049
Under recovered fuel costs	1,212			314
Current portion of long-term regulatory assets	(6,096		)	(3,492		)
Other	930			669
Regulatory assets, long-term	231,950			243,958
Total Regulatory Assets	$	238,348		$	250,335

	September 30, 2013			December 31, 2012
Regulatory Liabilities:
Current:
Over recovered fuel costs(1)	$	556		$	3,214
Current portion of long-term regulatory liabilities(1)	3,739			3,089
Regulatory liabilities, current(1)	4,295			6,303
Long-term:
Costs of removal	92,058			83,368
SWPA payment for Ozark Beach lost generation	20,105			22,242
Income taxes	11,736			11,972
Deferred construction accounting costs — fuel	8,047			8,156
Unamortized gain on interest rate derivative	3,414			3,541
Pension and other postretirement benefits(4)	2,377			2,007
Over recovered fuel costs	533			2,858
Current portion of long-term regulatory liabilities(1)	(3,739		)	(3,089		)
Regulatory liabilities, long-term	134,531			131,055
Total Regulatory Liabilities	$	138,826		$	137,358

(1)  Reflects over and under recovered costs of the current portion of regulatory assets or liabilities detailed in the long term sections below expected to be returned or recovered, as applicable, within the next 12 months in rates.

(2) Includes the effect of costs incurred that are more or less than those allowed in rates for Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs.

(3) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado.

(4) Includes the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs.

Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. 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 predictability. We recognize that if risk is not timely and adequately balanced or if

12

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 with the unrealized losses or gains from derivatives used to hedge our fuel costs in our electric segment 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 regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

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 instrument 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 clause.

As of September 30, 2013 and December 31, 2012, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

ASSET DERIVATIVES		September 30,		December 31,
Non-designated hedging		2013		2012
instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	11	$	3
	Non-current assets and deferred charges - other	—		17
Natural gas contracts, electric segment	Current assets	322		93
	Non-current assets and deferred charges	—		174
Total derivatives assets		$	333	$	287

		September 30,		December 31,
LIABILITY DERIVATIVES		2013		2012
Non-designated as hedging instruments due to regulatory accounting
Natural gas contracts, gas segment	Current liabilities	$	22	$	104
	Non-current liabilities and deferred credits	—		—
Natural gas contracts, electric segment	Current liabilities	3,056		3,299
	Non-current liabilities and deferred credits	3,089		3,819
Total derivatives liabilities		$	6,167	$	7,222

Electric

At September 30, 2013, approximately $3.1 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months.

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 periods ended September 30, (in thousands):

Non-Designated Hedging	Balance Sheet
Instruments - Due to	Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Regulatory Accounting	Gain / (Loss) on	Three Months Ended					Nine Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2013			2012		2013			2012			2013			2012
Commodity contracts	Regulatory (assets)/liabilities	$	(1,346	)	$	1,776	$	(1,778	)	$	(52	)	$	(4,174	)	$	(4,259	)
Total Electric Segment		$	(1,346	)	$	1,776	$	(1,778	)	$	(52	)	$	(4,174	)	$	(4,259	)

13

	Statement of
Non-Designated Hedging	Income
Instruments - Due to	Classification of	Amount of Gain / (Loss) Recognized in Income on Derivative
Regulatory Accounting	Gain / (Loss) on	Three Months Ended						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2013			2012			2013			2012			2013			2012
Commodity contracts	Fuel and purchased power expense	$	(1,951	)	$	(2,683	)	$	(2,472	)	$	(2,624	)	$	(3,833	)	$	(3,498	)
Total Electric Segment		$	(1,951	)	$	(2,683	)	$	(2,472	)	$	(2,624	)	$	(3,833	)	$	(3,498	)

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.

As of September 30, 2013, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2013 and for the next four years are shown below at the following average prices per Dekatherm (Dth).

Dth Hedged

Year	% Hedged		Physical	Financial	Average Price
Remainder 2013	14	%	420,000	410,000	$	5.62
2014	49	%	460,000	4,640,000	$	4.57
2015	41	%	—	4,010,000	$	4.58
2016	21	%	—	2,100,000	$	4.42
2017	10	%	—	1,050,000	$	4.43

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. These guidelines do not reflect any changes that might occur as a result of the implementation of the SPP Day-Ahead Market in 2014.

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

Gas

We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of September 30, 2013, we had 1.7 million Dths in storage on the three pipelines that serve our customers. This represents 83% 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 Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of September 30, 2013 (in thousands).

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Season	Minimum % Hedged	Dth Hedged Financial	Dth Hedged Physical	Dth in Storage	Actual % Hedged
Current	50%	220,000	127,721	1,671,231	63	%
Second	Up to 50%	—	—	—
Third	Up to 20%	—	—	—

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 each of the periods ended September 30, (in thousands).

	Balance Sheet
Non-Designated Hedging	Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain / (Loss) on	Three Months Ended					Nine Months Ended						Twelve Months Ended
Accounting - Gas Segment	Derivative	2013			2012		2013			2012			2013			2012
Commodity contracts	Regulatory (assets)/liabilities	$	(27	)	$	106	$	(45	)	$	(384	)	$	(122	)	$	(1,458	)
Total - Gas Segment		$	(27	)	$	106	$	(45	)	$	(384	)	$	(122	)	$	(1,458	)

Contingent Features

Certain of our derivative instruments contain provisions that require our senior unsecured debt to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position on September 30, 2013 is $0.4 million for which we have posted no collateral in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2013, we would have been required to post $0.4 million of collateral with one of our counterparties. 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 September 30, 2013 and December 31, 2012. There were no margin deposit liabilities at these dates.

(in millions)	September 30, 2013		December 31, 2012
Margin deposit assets	$	5.8	$	4.2

Offsetting of derivative assets and liabilities

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further,

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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 periods ended September 30, 2013 and December 31, 2012, 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.

Note 5— Fair Value Measurements

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

The guidance also requires that the fair value measurements 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.

The following fair value hierarchy table presents information about our assets measured at fair value using the market value approach on a recurring basis as of September 30, 2013 and December 31, 2012.

	Fair Value Measurements at Reporting Date Using
($ in 000’s) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable  Inputs (Level 3)
				September 30, 2013
Derivative assets	$	333		$	333		$	—	$	—
Derivative liabilities	$	(6,167	)	$	(6,167	)	$	—	$	—
				December 31, 2012
Derivative assets	$	287		$	287		$	—	$	—
Derivative liabilities	$	(7,222	)	$	(7,222	)	$	—	$	—

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 September 30, 2013, was $739.3 million as compared to $687.6 million at December 31, 2012. The fair market value at September 30, 2013 was approximately $716.5 million as compared to $747.2 million at December 31, 2012. 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

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estimated fair market value may not represent the actual value that could have been realized as of September 30, 2013 or that will be realizable in the future.

Note 6— Financing

On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. The delayed settlement of both series of bonds occurred on May 30, 2013. Interest is payable semi-annually on the bonds on each May 30 and November 30, commencing November 30, 2013. 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 bonds have not been registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage. 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. 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.

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

We have an unsecured revolving credit facility of $150 million in place through January 17, 2017. The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of September 30, 2013, we are in compliance with these ratios. Our total indebtedness is 50.0% of our total capitalization as of September 30, 2013 and our EBITDA is 5.0 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement and no outstanding commercial paper at September 30, 2013.

Note 7— Commitments and Contingencies

Legal Proceedings

We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided 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.

A lawsuit was filed in Jasper County Circuit Court (the Court) against us by three of our residential customers, purporting to act on behalf of all Empire customers. These customers were seeking a refund of certain amounts paid for service provided by Empire between January 1, 2007, and December 13, 2007. At all times, we charged the three plaintiffs, and all of our customers, the rates approved by and on file with the MPSC from our 2006 rate case. We filed a motion asking the Court to dismiss the case. On October 1, 2013, the Missouri Supreme Court denied the plaintiff’s appeal affirming the Court’s dismissal with prejudice which finalizes the case.

Coal, Natural Gas and Transportation Contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of September 30, 2013 (in millions).

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	Firm physical gas and transportation contracts		Coal and coal transportation contracts
October 1, 2013 through December 31, 2013	$	10.6	$	5.7
January 1, 2014 through December 31, 2015	30.5		34.3
January 1, 2016 through December 31, 2017	22.2		22.6
January 1, 2018 and beyond	8.3		22.6

Included in the table above is an agreement with Southern Star Central Pipeline, Inc., effective April 2011, to purchase one million Dths of firm gas storage service capacity for our electric business for a period of five years, expiring April 2016. The reservation charge for this storage capacity is approximately $1.1 million annually.

In addition to the above, subsequent to September 30, 2013, we extended our transportation contract with ANR Pipeline Company, expiring on March 31, 2014, for a period of ten years, expiring on March 31, 2024. Annual costs under this contract are expected to be approximately $0.5 million, depending on volume.

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 liquidated at market price. 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 September 30, 2013, are detailed in the table above.

Purchased Power

We currently supplement our on-system 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 capacity from Plum Point. We began receiving purchased power under this agreement on September 1, 2010. 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. While it is not currently our intention to exercise this option in 2015, we will continue to evaluate this purchase option through the exercise date as well as explore other options with the purchase power agreement holder, Plum Point Energy Associates (PPEA), related to the timing of this option. Commitments under this agreement are approximately $299.6 million through August 31, 2039, the end date of the agreement.

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 (formerly Horizon Wind Energy), Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. 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. 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. Although these agreements are

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considered operating leases under Generally Accepted Accounting Principles (GAAP), payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations. We do not own any portion of these windfarms.

New Construction

On July 9, 2013, we signed 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. See “Environmental Matters” below for additional information about this project and associated compliance measures.

On January 16, 2012, we signed a contract with a third party vendor to complete environmental retrofits at our Asbury plant. The retrofits include the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This equipment will enable us to comply with the Mercury and Air Toxics Standard (MATS). See “Environmental Matters” below for more information and for project costs.

Leases

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

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

Environmental Matters

We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and hazardous and other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. We believe that our operations are in material compliance with present environmental laws and regulations. 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.

Electric Segment

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) and hazardous air pollutants including mercury. In the future they will include limits on greenhouse gases (GHG) such as carbon dioxide (CO2).

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Permits

Under the CAA we have obtained, and renewed as necessary, site operating permits, which are valid for five years, for each of our plants. As stated above, on July 11, 2013, we received the Air Emission Source Construction Permit necessary to begin construction on the Riverton 12 Combined Cycle Conversion project.

Compliance Plan

In order to comply with forthcoming environmental regulations, Empire is taking actions to implement its compliance plan and strategy (Compliance Plan).  While the Cross State Air Pollution Rule (CSAPR — formerly the Clean Air Transport Rule, or CATR) that was set to take effect on January 1, 2012 was stayed in late December 2011 then vacated in August 2012 by the District of Columbia Circuit Court of Appeals, the Mercury Air Toxics Standard (MATS) was signed by the Environmental Protection Agency (EPA) Administrator on December 16, 2011 and became effective on April 16, 2012. MATS requires compliance by April 2015 (with flexibility for extensions for reliability reasons). Our Compliance Plan largely follows the preferred plan presented in our 2010 Integrated Resource Plan (IRP) and is further supported by our recent IRP filing. As described above under New Construction, we have begun the installation of a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant. The addition of this air quality control equipment is expected to be completed by early 2015 at a cost ranging from $112.0 million to $130.0 million, excluding AFUDC. Construction costs through September 30, 2013 were $43.2 million for 2013 and $73.5 million for the project to date, excluding AFUDC. The addition of this air quality control equipment will require the retirement of Asbury Unit 2, a steam turbine currently rated at 14 megawatts that is used for peaking purposes.

In September 2012, we completed the transition of our Riverton Units 7 and 8 from operation on coal to operating completely on natural gas. Riverton Units 7 and 8, along with Riverton Unit 9, a small combustion turbine that requires steam from Unit 7 or 8 for start-up, will 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 at a cost estimated to range from $165 million to $175 million, excluding AFUDC. This amount is included in our updated five-year capital expenditure plan disclosed in our 2013 third quarter 10-Q. Construction costs, consisting of pre-engineering and site preparation activities thus far, through September 30, 2013 were $5.3 million for 2013 and $5.9 million for the project to date, excluding AFUDC.

SO2 Emissions

The CAA regulates the amount of SO2 an affected unit can emit. Currently SO2 emissions are regulated by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). On January 1, 2012, CAIR was to have been replaced by the Cross-State Air Pollution Rule (CSAPR). But, as discussed above, CSAPR was subsequently vacated, and CAIR will remain in effect until the EPA develops a valid replacement.

On October 5, 2012, the Department of Justice, on behalf of the EPA, requested that the Court of Appeals grant a request for a re-hearing of CSAPR. On January 24, 2013, the request was denied by the Court of Appeals and on March 29, 2013, the EPA petitioned the United States Supreme Court (the Supreme Court) to review the D.C. Circuit Court’s decision. On June 24, 2013 the Supreme Court agreed to review the D.C. Circuit court’s decision with a hearing date set for December 6, 2013 and a decision expected by June 30, 2014.  In the meantime, both the Title IV Acid Rain Program and CAIR will remain in effect.

The Mercury Air Toxics Standards (MATS), discussed further below, was signed on December 16, 2011, and will affect SO2 emission rates at our facilities. In addition, the compliance date for the revised SO2 National Ambient Air Quality Standards (NAAQS) is August of 2017; this could also affect SO2 emissions at our facilities. The SO2 NAAQS is discussed in more detail below.

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Title IV Acid Rain Program:

Under the Title IV Acid Rain Program, each existing affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA).  Each allowance entitles the holder to emit one ton of SO2. Covered utilities, such as Empire, must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances in excess of the annual emissions are banked for future use. In 2012, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. We estimate our Title IV Acid Rain Program SO2 allowance bank plus annual allocations will be more than our projected emissions through 2017. Long-term compliance with this program will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We expect the cost of compliance to be fully recoverable in our rates.

CAIR:

In 2005, the EPA promulgated CAIR under the CAA. 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.

In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR and remanded it back to EPA for further consideration, but also stayed its vacatur. As a result, CAIR became effective for NOx on January 1, 2009 and for SO2 on January 1, 2010 and required covered states to develop State Implementation Plans (SIPs) to comply with specific SO2 state-wide annual budgets.

SO2 allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO2 Program. For our Missouri units, beginning in 2010, CAIR required the SO2 allowances to be utilized at a 2:1 ratio and, beginning in 2015, will require the SO2 allowances to be utilized at a 2.86:1 ratio. As a result, based on current SO2 allowance usage projections, we expect to have sufficient allowances to take us through 2017.

In order to meet CAIR requirements for SO2 and NOx emissions (NOx is discussed below in more detail) and as a requirement for the air permit for Iatan 2, a Selective Catalytic Reduction system (SCR), a Flue-Gas Desulfurization (FGD) scrubber system and baghouse were installed at our jointly-owned Iatan 1 plant and a SCR was placed in service at our Asbury plant in 2008. Our jointly-owned Iatan 2 and Plum Point plants were originally constructed with the above technology.

CSAPR- formerly the Clean Air Transport Rule:

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed and supplemented, the CATR included Missouri and Kansas under both the annual and ozone season for NOx as well as the SO2 program while Arkansas remained in the ozone season NOx program only. The final CATR was released on July 7, 2011 under the name of the CSAPR, and was set to become effective January 1, 2012. However, as mentioned above, the District of Columbia Circuit Court of Appeals vacated CSAPR on August 21, 2012, and the EPA has subsequently petitioned the Supreme Court to review the D.C. Circuit Court’s decision. On June 24, 2013 the Supreme Court agreed to review the D.C. Circuit court’s decision, which is set to occur December 6, 2013. The CAIR will be in effect until a valid replacement is developed by the EPA.

When it was published, the final CSAPR required a 73% reduction in SO2 from 2005 levels by 2014. The SO2 allowances allocated under the EPA’s Title IV Acid Rain Program could not be used for compliance with CSAPR but would continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO2 allowances would be allocated under CSAPR and retired at one allowance per ton of SO2 emissions emitted. Based on current projections, we would receive more SO2 allowances than would be emitted. Long-term compliance with this Rule will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We

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anticipate compliance costs associated with CAIR or its subsequent replacement to be recoverable in our rates.

Mercury Air Toxics Standard (MATS):

The MATS standard was fully implemented and effective as of April 16, 2012, thus requiring compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The MATS regulation does not include allowance mechanisms. Rather, it establishes alternative standards for certain pollutants, including SO2 (as a surrogate for hydrogen chloride (HCI)), which must be met to show compliance with hazardous air pollutant limits (see additional discussion in the MATS section below).

SO2 National Ambient Air Quality Standard (NAAQS):

In June 2010, the EPA finalized a new 1-hour SO2 NAAQS which, for areas with no ambient SO2 monitor, originally required modeling to determine attainment and non-attainment areas within each state. In April 2012, the EPA announced that it is reconsidering this approach. The modeling of emission sources was to have been completed by June 2013 with compliance with the SO2 NAAQS required by August 2017. Because the EPA is reconsidering the compliance determination approach for areas without ambient SO2 monitors, the compliance time-frame may be pushed back. Draft guidance for 1-hour SO2 NAAQS has been published by the EPA to assist states as they prepare their SIP submissions. The EPA is also planning a rulemaking called the Data Requirements Rule (DRR) to address some of the 1-hour SO2 NAAQS implementation program elements. It is likely that coal-fired generating units will need scrubbers to be capable of meeting the new 1-hour SO2 NAAQS. In addition, units will be required to include SO2 emissions limits in their Title V permits or execute consent decrees to assure attainment and future compliance.

NOx Emissions

The CAA regulates the amount of NOx an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx limits. Currently, revised NOx emissions are limited by the CAIR as a result of the vacated CSPAR rule and by ozone NAAQS rules (discussed below) which were established in 1997 and in 2008.

CAIR:

The CAIR required covered states to develop SIPs to comply with specific annual NOx state-wide allowance allocation budgets. Based on existing SIPs, we had excess NOx allowances during 2012 which were banked for future use and will be sufficient for compliance through at least the end of 2017. The CAIR NOx program also was to have been replaced by the CSAPR program January 1, 2012 but because the D.C. Circuit Court vacated CSAPR and the case is being re-heard by the Supreme Court, CAIR will remain in effect until the EPA develops a valid replacement.

CSAPR:

As published, the CSAPR would have required a 54% reduction in NOx from 2005 levels by 2014. The NOx annual and ozone season allowances that were allocated and banked under CAIR could not be used for compliance under CSAPR. New allowances would have been issued under CSAPR. However, as discussed above, CSPAR was vacated by the District of Columbia Circuit Court of Appeals on August 21, 2012 and the case is set to be re-heard by the Supreme Court on December 6, 2013.

Ozone NAAQS:

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. On January 6, 2010, to protect public health, the EPA proposed to lower the primary NAAQS for ozone to a range between 60 and 70 ppb and to set a separate secondary NAAQS for ozone to protect sensitive vegetation and ecosystems.

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On September 2, 2011, President Obama ordered the EPA to withdraw proposed air quality standards lowering the 2008 ozone standard pending the CAA 2013 scheduled reconsideration of the ozone NAAQS (the normal 5 year reconsideration period). States moved forward with area designations based on the 2008 75 ppb standard using 2008-2010 quality assured monitoring data. Our service territory is designated as attainment, meaning that it is in compliance with the standard.

A revised Ozone NAAQS is expected to be proposed by the EPA early 2014 and is anticipated to be between 60 and 70 ppb.

PM NAAQS:

Particulate matter (PM) is the term for particles found in the air which comes from a variety of sources. On January 15, 2013, the EPA finalized the PM 2.5 primary annual standard at 12 ug/m(3) (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 PM 2.5 ambient monitor results are below the required level. However, the proposed standards could impact future major modifications/construction projects that require a Prevention of Significant Deterioration (PSD) permit.

Mercury Air Toxics Standard (MATS)

In 2005, the EPA issued the Clean Air Mercury Rule (CAMR) under the CAA. It set limits on mercury emissions by power plants and created a market-based cap and trade system expected to reduce nationwide mercury emissions in two phases. New mercury emission limits for Phase 1 were to go into effect January 1, 2010. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR. This decision was appealed to the U.S. Supreme Court which denied the appeal on February 23, 2009.

The EPA issued Information Collection Requests (ICR) for determining the National Emission Standards for Hazardous Air Pollutants (NESHAP), including mercury, for coal and oil-fired electric steam generating units on December 24, 2009. The ICRs included our Iatan, Asbury and Riverton plants. All responses to the ICRs were submitted as required. The EPA ICRs were intended for use in developing regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of hazardous air pollutants (HAPs), including mercury. The EPA proposed the national mercury and air toxics standards (MATS) in March 2011, which became effective April 16, 2012. MATS establishes numerical emission limits to reduce emissions of heavy metals, including mercury (Hg), arsenic, chromium, and nickel, and acid gases, including HCl and hydrogen fluoride (HF). For all existing and new coal-fired electric utility steam generating units (EGUs), the proposed 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. On June 25, 2013, the startup, shutdown portion of the MATS was proposed for reconsideration in order to better define startup and shutdown periods (instances when the emission unit is on but the pollution control equipment is not in full operation) that will be excluded from emissions averaging for compliance purposes.

The MATS regulation of HAPs in combination with CSAPR is the driving regulation behind our Compliance Plan and its implementation schedule.  We expect compliance costs to be recoverable in our rates.

Greenhouse Gases

Our coal and gas plants, vehicles and other facilities, including EDG (our gas segment), emit CO2 and/or other Greenhouse Gases (GHGs) which are measured in Carbon Dioxide Equivalents (CO2e).

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually

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commencing in September 2011. EDE and EDG’s GHG emissions for 2011 and 2012 have been reported as required to the EPA.

On December 7, 2009, responding to a 2007 U.S. Supreme Court decision that determined that GHGs constitute “air pollutants” under the CAA, the EPA issued its final finding that GHGs threaten both the public health and the public welfare. This “endangerment” finding did not itself trigger any EPA regulations, but was a necessary predicate for the EPA to proceed with regulations to control GHGs. Since that time, a series of rules including the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule) have been issued by the EPA. Several parties have filed petitions with the EPA and lawsuits have been filed challenging these rules. On June 26, 2012, the D.C. Circuit Court issued its opinion in the principal litigation of the EPA GHG rules (Endangerment, the Tailoring Rule, GHG emission standards for light-duty vehicles, and the EPA’s rule on reconsideration of the PSD Interpretive Memorandum). The three-judge panel upheld the EPA’s interpretation of the Clean Air Act provisions as unambiguously correct. This opinion solidifies the EPA’s position that the CAA requires PSD and Title V permits for major emitters of greenhouse gases, such as Empire. Our ongoing projects are currently being evaluated for the projected increase or decrease of CO2e emissions as required by the Tailoring Rule.

As the result of an agreement to settle litigation pending in the U.S. Court of Appeals, on April 13, 2012, the EPA proposed a Carbon Pollution Standard for new power plants to limit the amount of carbon emitted by electric utility generating units (EGUs). In light of the more than 2.5 million comments received by the EPA, this standard was rescinded, and a re-proposal of standards of performance for affected fossil fuel-fired EGUs was issued on September 20, 2013 as required by President Obama. The proposed rule sets separate standards for natural gas-fired combustion turbines and for fossil fuel-fired utility boilers. Limiting CO2 output to 1,000 or 1,100 pounds per megawatt hour based on size and fuel type, the standards apply only to new EGUs. It is expected that most new natural gas-fired combined cycle units will meet the new standard. The EPA believes fossil-fuel fired boilers can meet the standard through efficient technology or some level of carbon capture and sequestration, but the high cost, technical feasibility, and long term liability of stored carbon are issues that have not been resolved and limit this option for Empire and all electric utilities.

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. In response to President Obama’s June 25, 2013 memorandum to the EPA Administrator, the EPA is engaging states and stakeholders in a process to identify approaches to establish carbon pollution standards for currently operating power plants.

President Obama’s memorandum to the EPA Administrator requested the EPA issue proposed carbon pollution standards, regulations, or guidelines for modified, reconstructed, and existing power plants by no later than June 1, 2014;  issue final standards, regulations, or guidelines, for modified, reconstructed, and existing power plants by no later than June 1, 2015; and include in the guidelines addressing existing power plants a requirement that states submit to the EPA implementation plans by no later than June 30, 2016. As of October 15, 2013, the U.S. Supreme Court agreed to review an appeals court decision that said the EPA could regulate greenhouse gas emissions from fixed sources based on a previous decision based on green house emissions from cars.

In addition, a variety of proposals have been and are likely to continue to be considered by Congress to reduce GHGs. Proposals are also being considered in the House and Senate that would delay, limit or eliminate the EPA’s authority to regulate GHGs. At this time, it is not possible to predict what legislation, if any, will ultimately emerge from Congress regarding control of GHGs.

Certain states have taken steps to develop cap and trade programs and/or other regulatory systems which may be more stringent than federal requirements. For example, Kansas is a participating member of the Midwestern Greenhouse Gas Reduction Accord (MGGRA), one purpose of which is to develop a market-based cap and trade mechanism to reduce GHG emissions. The MGGRA has announced, however, that it will not issue a CO2e regulatory system pending federal legislative developments. Missouri is not a participant in the MGGRA.

The ultimate cost of any GHG regulations cannot be determined at this time. However, we expect the cost of complying with any such regulations to be recoverable in our rates.

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Water Discharges

We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received 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. The regulations became final on February 16, 2004. In accordance with these regulations, we submitted sampling and summary reports to the Kansas Department of Health and Environment (KDHE) which indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. KCP&L, who operates Iatan Unit 1, submitted the appropriate sampling and summary reports to the Missouri Department of Natural Resources (MDNR).

In 2007 the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations to the EPA. As a result, the EPA suspended the regulations and revised and signed a pre-publication proposed regulation on March 28, 2011. The EPA has secured an additional year to finalize the standards for cooling water intake structures under a modified settlement agreement. Following a recent court approved delay, the EPA is now obligated to finalize the rule by November 4, 2013. We will not know the full impact of these rules until they are finalized. If adopted in their present form, we expect regulations of Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) to have a limited impact at Riverton. The retirement of units 7 and 8 is 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 impacted by the final rule.

Surface Impoundments

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. 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. 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.

On June 21, 2010, the EPA proposed a new regulation pursuant to the Federal Resource Conservation and Recovery Act (RCRA) governing the management and storage of Coal Combustion Residuals (CCR). In the proposal, the EPA presents 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. The public comment period closed in November 2010. It is anticipated that the final regulation will be published in 2014. We expect compliance with either option as proposed 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 and Riverton Power Plants. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

On September 23, 2010 and on November 4, 2010 EPA consultants conducted on-site inspections of our Riverton and Asbury coal ash impoundments, respectively. The consultants performed a visual inspection of the impoundments to assess the structural integrity of the berms surrounding the impoundments, requested documentation related to construction of the impoundments, and reviewed recently completed engineering evaluations of the impoundments and their structural integrity. In response to the inspection comments, the recommended geotechnical

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studies have been completed and new flow monitoring devices and settlement monuments at both coal ash impoundments have been installed. As a result of the transition from coal to natural gas, closure of the Riverton impoundment is in progress in compliance with KDHE Bureau of Waste Management regulations. We expect to complete the closure by late 2013. The final design for additional recommendations that will improve safety for slope stability at the Asbury impoundment is under review. We have received preliminary approval by the MDNR for the site permitting of a new utility waste landfill adjacent to the Asbury plant. Additionally, the work plan for the detailed site investigation (DSI) to include geologic and hydrologic investigations has been approved by the MDNR Division of Geology and Land Survey. Construction of the new landfill is expected in 2016.

Renewable Energy

As previously discussed, we have purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas. We do not own any portion of either windfarm.  More than 15% of the energy we put into the grid comes from these long-term Purchased Power Agreements (PPAs). Through these PPAs, we generate about 900,000 renewable energy certificates (RECs) each year. A REC represents one megawatt-hour of renewable energy that has been delivered into the bulk power grid and “unbundles” the renewable attributes from the associated energy. This unbundling is important because it cannot be determined where the renewable energy is ultimately delivered once it enters the bulk power grid. As a result, RECs provide an avenue for renewable energy tracking and compliance purposes.

Missouri regulations currently require us 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 RECs, at the rate of at least 2% of retail sales in 2012, increasing to at least 5% by 2014 and ultimately to at least 15% by 2021. We are currently in compliance with this regulatory requirement. The regulations require that 2% of the renewable energy source must be solar; however, we believe we are exempted from the solar requirement. A challenge to our exemption, brought by two of our customers and Power Source Solar, Inc., was dismissed on May 31, 2011 by the Missouri Western District Court of Appeals. The plaintiffs filed in the Missouri Supreme Court for transfer of the case from the Missouri Western District to the Missouri Supreme Court. The transfer was denied. On January 30, 2013, a complaint was filed with the MPSC by Renew Missouri and others regarding several points of our 2011 RES Compliance Report and the 2012-2014 Compliance Plan. The complaint, which was lodged against four investor-owned utilities (Ameren Missouri, Kansas City Power & Light Company (KCP&L), KCP&L Greater Missouri Operations, and Empire), is currently under consideration by the MPSC. On October 3, 2013, the MPSC issued an order denying motions for summary determination of Renew Missouri and KCP&L/GMO, but granting motion for summary determination of Empire. In this order, the MPSC determined the provisions of the rule exempt Empire from the obligation to provide a detailed explanation of the calculation of the RES retail impact limit for its 2012 Plan.  By granting Empire’s motion, the MPSC unconsolidated the complaint against Empire and ordered that it would proceed independently. Items remaining under consideration from the original complaint include the qualification of Empire’s Ozark Beach facility as a hydropower renewable energy resource, the use of early RECs for compliance and Empire’s exemption from the use of solar RECs for compliance.

Renewable energy standard compliance rules were published by the MPSC on July 7, 2010.  Missouri investor-owned utilities and others initiated litigation to challenge these rules. On June 30, 2011, a Cole County Circuit Court judge ruled that portions of the MPSC rules were unlawful and unreasonable, in conflict with Missouri statute and in violation of the Missouri Constitution. Subsequent to that decision, a portion of the appeal was dropped and the entire order was stayed.  On December 27, 2011 the judge issued another order identical to the one that was stayed except that the rulings with regard to the constitutionality issue had been omitted. The MPSC appealed this decision and in November of 2012 the court dismissed lawsuits brought against the RES and affirmed the MPSC rules that were finalized in July 2010. 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 20% by 2020.

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In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

We have been selling the majority of our RECs and plan to continue to sell all or a portion of them in the future. As a result of these REC sales, we cannot claim the underlying energy is renewable. Once a REC has been claimed or retired, it cannot be used for any other purpose. At the end of 2012, sufficient RECs, including hydro, were retired to comply with the Missouri and Kansas requirements through the end of November 2012. Additional RECs were retired in January of 2013 to complete the process for 2012. In the future, we will continue to retain a sufficient amount of RECs to meet any current or future requirements.

Gas Segment

The acquisition of Missouri Gas in June 2006 involved the property transfer of two former manufactured gas plant (FMGP) sites owned by predecessors. Site #1 in Chillicothe, Missouri is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. No remediation of this site is expected to be required in the near term.  We have received a letter stating no further action is required from the MDNR with respect to Site #2 in Marshall, Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two FMGP sites to be minimal.

Note 8 — Retirement Benefits

Net periodic benefit cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components and is shown for our noncontributory defined benefit pension plan, our supplemental retirement program (SERP) and other postretirement benefits (OPEB) (in thousands):

	Three months ended September 30,
	Pension Benefits						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	1,863		$	1,439		$	34		$	23		$	735		$	671
Interest cost	2,516			2,591			78			86			957			962
Expected return on plan assets	(3,107		)	(3,080		)	—			—			(1,088		)	(1,018		)
Amortization of prior service cost (1)	133			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,611			2,052			142			139			565			311
Net periodic benefit cost	$	4,016		$	3,135		$	252		$	246		$	916		$	673

	Nine months ended September 30,
	Pension Benefits						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	5,590		$	4,696		$	101		$	39		$	2,206		$	1,801
Interest cost	7,547			7,693			236			197			2,870			3,027
Expected return on plan assets	(9,321		)	(9,232		)	—			—			(3,265		)	(3,101		)
Amortization of prior service cost (1)	399			398			(6		)	(6		)	(758		)	(758		)
Amortization of net actuarial loss (1)	7,834			5,952			426			291			1,696			1,246
Net periodic benefit cost	$	12,049		$	9,507		$	757		$	521		$	2,749		$	2,215

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	Twelve months ended September 30,
	Pension Benefits						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	7,156		$	6,094		$	114		$	62		$	2,806		$	2,367
Interest cost	10,111			10,295			301			243			3,879			4,123
Expected return on plan assets	(12,398		)	(12,017		)	—			—			(4,299		)	(4,140		)
Amortization of prior service cost (1)	531			532			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,818			7,325			523			334			2,112			1,687
Net periodic benefit cost	$	15,218		$	12,229		$	930		$	631		$	3,487		$	3,026

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

In accordance with our regulatory agreements, our pension funding policy is to make contributions that are at least equal to the greater of either the minimum funding requirements of ERISA or the accrued cost of the plan. We made pension contributions of approximately $16.2 million in July 2013, which are expected to satisfy our funding requirements for the year. The actual minimum funding requirements will be determined based on the results of the actuarial valuations. Our OPEB funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits.

Note 9— Stock-Based Awards and Programs

Our performance-based restricted stock awards, stock options and their related dividend equivalents and time-vested restricted stock awards 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. Grants were made in the first quarter of 2013 (the effect of which is included in the table below) but did not have a material impact on our results of operations. We had unrecognized compensation expense of $0.7 million as of September 30, 2013.

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended September 30 (in thousands):

	Three Months Ended				Nine Months Ended				Twelve Months Ended
	2013		2012		2013		2012		2013		2012
Compensation Expense	$	363	$	431	$	2,057	$	1,629	$	2,305	$	2,077
Tax Benefit Recognized	127		148		743		575		821		730

Performance-Based Restricted Stock Awards

Performance-based restricted stock awards 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) are granted to qualified individuals. We estimate the fair value of outstanding restricted stock awards using a Monte Carlo option valuation model.

Time-Vested Restricted Stock Awards

Beginning in 2011, we began granting time-vested restricted stock awards that vest after a three-year period, to qualified individuals 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

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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.

Stock Options

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of September 30, 2013 and 2012, under a Black-Scholes methodology.

Note 10- Regulated Operating Expenses

The following table sets forth the major components comprising “regulated operating expenses” under “Operating Revenue Deductions” on our consolidated statements of income (in thousands) for all periods presented ended September 30:

	Three Months Ended		Three Months Ended		Nine Months Ended		Nine Months Ended		Twelve Months Ended		Twelve Months Ended
	2013		2012		2013		2012		2013		2012
Electric transmission and distribution expense	$	5,530	$	4,392	$	16,509	$	12,764	$	20,828	$	16,784
Natural gas transmission and distribution expense	681		554		1,803		1,870		2,376		2,463
Power operation expense (other than fuel)	3,942		4,129		11,953		11,232		15,766		14,898
Customer accounts and assistance expense	3,124		2,621		8,322		7,639		10,894		10,304
Employee pension expense (1)	2,662		2,562		8,062		7,637		10,605		10,118
Employee healthcare expense (1)	2,662		2,442		7,857		7,004		10,678		9,108
General office supplies and expense	2,997		2,530		9,589		7,805		12,560		10,445
Administrative and general expense	3,375		3,675		11,292		11,466		14,917		15,521
Allowance for uncollectible accounts	975		968		2,765		2,313		3,489		3,245
Regulatory reversal of gain on sale of assets	—		—		1,236		—		1,236		—
Miscellaneous expense	152		165		496		500		675		686
Total	$	26,100	$	24,038	$	79,884	$	70,230	$	104,024	$	93,572

(1) Does not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to and amortized from a regulatory asset and/or a regulatory liability for Missouri, Kansas and Oklahoma jurisdictions.

Note 11— Segment Information

We operate our business as three segments:  electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The other segment consists of our fiber optics business.

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

	For the quarter ended September 30, 2013
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	150,370	$	4,952		$	2,819	$	(655	)	$	157,486
Depreciation and amortization	16,328		928			479		—			17,735
Federal and state income taxes	13,939		(369		)	580		—			14,150
Operating income	31,589		364			943		—			32,896
Interest income	1		4			—		0			5
Interest expense	9,380		973			—		0			10,353
Income from AFUDC (debt and equity)	1,722		12			—		—			1,734
Net income	23,652		(599		)	943		—			23,996
Capital Expenditures	$	45,164	$	628		$	334				$	46,126

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	For the quarter ended September 30, 2012
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	152,730	$	4,999		$	1,621	$	(148	)	$	159,202
Depreciation and amortization	13,757		895			456		—			15,108
Federal and state income taxes	15,564		(232		)	145		—			15,477
Operating income	34,517		532			233		—			35,282
Interest income	261		88			2		(86		)	265
Interest expense	9,328		975			—		(86		)	10,217
Income from AFUDC (debt and equity)	532		3			—		—			535
Net income	25,705		(399		)	236		—			25,542
Capital Expenditures	$	39,794	$	783		$	715				$	41,292

	For the nine months ended September 30, 2013
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	406,158	$	33,222	$	6,844	$	(952	)	$	445,272
Depreciation and amortization	47,216		2,778		1,477		—			51,471
Federal and state income taxes	26,882		707		1,092		—			28,681
Operating income	70,097		4,004		1,763		—			75,864
Interest income	498		109		7		(92		)	522
Interest expense	28,273		2,926		—		(92		)	31,107
Income from AFUDC (debt and equity)	3,883		21		—		—			3,904
Net income	45,373		1,136		1,774		—			48,283
Capital Expenditures	$	114,734	$	2,824	$	1,276				$	118,834

	For the nine months ended September 30, 2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	396,546	$	26,486	$	5,389	$	(444	)	$	427,977
Depreciation and amortization	41,086		2,675		1,350		—			45,111
Federal and state income taxes	27,497		226		713		—			28,436
Operating income	72,594		3,120		1,140		—			76,854
Interest income	549		255		3		(239		)	568
Interest expense	28,530		2,928		—		(239		)	31,219
Income from AFUDC (debt and equity)	800		5		—		—			805
Net income	44,569		326		1,159		—			46,054
Capital Expenditures	$	103,361	$	2,352	$	2,253				$	107,966

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	For the twelve months ended September 30, 2013
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	520,265	$	46,585	$	8,641	$	(1,099	)	$	574,392
Depreciation and amortization	61,441		3,702		1,664		—			66,807
Federal and state income taxes	31,651		1,269		1,482		—			34,402
Operating income	86,948		5,889		2,394		—			95,231
Interest income	895		177		10		(156		)	926
Interest expense	37,610		3,902		—		(156		)	41,356
Income from AFUDC (debt and equity)	5,002		25		—		—			5,027
Net income	53,435		2,066		2,409		—			57,910
Capital Expenditures	$	151,490	$	4,043	$	1,622				$	157,155

	For the twelve months ended September 30, 2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	514,515	$	39,571	$	7,249	$	(592	)	$	560,743
Depreciation and amortization	54,295		3,552		1,822		—			59,669
Federal and state income taxes	32,464		791		1,003		—			34,258
Operating income	89,754		4,995		1,608		—			96,357
Interest income	1,035		310		4		(294		)	1,055
Interest expense	38,525		3,906		2		(294		)	42,139
Income from AFUDC (debt and equity)	1,000		7		—		—			1,007
Net Income	51,870		1,244		1,631		—			54,745
Capital Expenditures	$	126,176	$	3,599	$	2,909				$	132,684

	As of September 30, 2013
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,085,805	$	120,608	$	30,295	$	(40,900	)	$	2,195,808

(1) Includes goodwill of $39,492 and reflects the payment of a dividend and return of capital from the EDG subsidiary to the parent in the third quarter of 2013.

	As of December 31, 2012
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,034,399	$	148,814	$	28,871	$	(85,715	)	$	2,126,369

(1) Includes goodwill of $39,492.

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Note 12— Income Taxes

The following table shows our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended September 30:

	Three Months Ended						Nine Months Ended						Twelve Months Ended
	2013			2012			2013			2012			2013			2012
Consolidated provision for income taxes	$	14.1		$	15.5		$	28.7		$	28.4		$	34.4		$	34.3
Consolidated effective federal and state income tax rates	37.1		%	37.7		%	37.3		%	38.2		%	37.3		%	38.5		%

The effective income tax rate for the three, nine and twelve month periods ended September 30, 2013 is lower than comparable periods in 2012 primarily due to higher equity AFUDC income in 2013 compared with 2012.

On September 13, 2013, the Internal Revenue Service and the Treasury Department released final regulations under Code 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. We are currently analyzing their impact on our financial statements. We do not expect the regulations to have a material impact to our effective tax rate.

We do not have any unrecognized tax benefits as of September 30, 2013. 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.

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE SUMMARY

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE) is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas, including the sale of wholesale energy to four towns in Missouri and Kansas. 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 which provides natural gas distribution to customers in 48 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business.

During the twelve months ended September 30, 2013, our gross operating revenues were derived as follows:

Electric segment sales*	90.6	%
Gas segment sales	8.1
Other segment sales	1.3

*Sales from our electric segment include 0.4% from the sale of water.

Earnings

The following table represents our basic and diluted earnings per weighted average share of common stock for the applicable periods ended September 30 (in dollars):

	Three Months Ended				Nine Months Ended				Twelve Months Ended
	2013		2012		2013		2012		2013		2012
Basic and diluted earnings per weighted average share of common stock	$	0.56	$	0.60	$	1.13	$	1.09	$	1.36	$	1.30

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Increased electric and gas gross margins positively impacted net income for all three periods presented as of September 30, 2013. We define electric gross margins as electric revenues less fuel and purchased power costs. We define gas gross margins as gas operating revenues less cost of gas in rates.

Increases in electric customer rates resulting from the April 1, 2013 Missouri rate increase (see “Recent Activities — Regulatory Matters” below) and higher period over period customer counts drove increases in revenue and margin in each of the periods presented. AFUDC also increased during each of the periods due to higher levels of construction activity, positively impacting results.

Weather was a negative driver in each period. Weather that was cooler than normal and significantly cooler than the 2012 quarter offset the impact of increased customer rates during the 2013 quarter. The impact of favorable weather during the 2012-2013 winter cooling season was offset by the cooler third quarter 2013 weather discussed above.  As a result, revenue and gross margin were negatively affected during the nine and twelve month periods.  A change in our unbilled revenue estimate made in the third quarter of 2012 negatively impacted revenue and margin in all three periods ended September 30, 2013.

Increased regulatory operating expenses and depreciation and amortization expenses negatively impacted results in each period presented.  In addition, a regulatory write off of approximately $3.6 million (see “Recent Activities — Regulatory Matters” below) negatively impacted nine and twelve month results.

Factors impacting gross margin and net income for the quarter, nine months and twelve months ended September 30, 2013, are presented on a segment basis under “Results of Operations” below.

The table below sets forth a reconciliation of basic and diluted earnings per share between the three months, nine months and twelve months ended September 30, 2012 and September 30, 2013, which is a non-GAAP presentation. The economic substance behind our non-GAAP earnings per share (EPS) measure is to present the after tax impact of significant items and components of the statement of income on a per share basis before the impact of additional stock issuances.

We believe this presentation is useful to investors because the statement of income does not readily show the EPS impact of the various components. 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.

This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statement of income. 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. The dilutive effect of additional shares issued included in the table reflects the estimated impact of all shares issued during the periods ended September 30.

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	Three Months  Ended			Nine Months  Ended			Twelve Months  Ended
Earnings Per Share — 2012	$	0.60		$	1.09		$	1.30
Revenues
Electric segment	$	(0.04	)	$	0.14		$	0.09
Gas segment	0.00			0.10			0.10
Other segment	0.01			0.01			0.01
Total Revenue	(0.03		)	0.25			0.20
Electric fuel and purchased power	0.05			0.10			0.16
Cost of natural gas sold and transported	0.00			(0.07		)	(0.07		)
Margin	0.02			0.28			0.29
Operating — electric segment	(0.03		)	(0.15		)	(0.16		)
Operating —gas segment	0.00			0.01			0.00
Operating —other segment	0.00			(0.01		)	0.00
Maintenance and repairs	0.00			0.02			0.04
Depreciation and amortization	(0.04		)	(0.10		)	(0.10		)
Loss on plant disallowance	0.00			(0.03		)	(0.03		)
Other taxes	(0.01		)	(0.03		)	(0.04		)
Interest charges	0.00			0.00			0.01
AFUDC	0.02			0.04			0.06
Change in effective income tax rates	0.01			0.02			0.03
Other income and deductions	0.00			0.00			(0.02		)
Dilutive effect of additional shares issued	(0.01		)	(0.01		)	(0.02		)
Earnings Per Share — 2013	$	0.56		$	1.13		$	1.36

Recent Activities

Regulatory Matters

On September 17, 2013, we advised the Arkansas Public Service Commission of the intention to file an application for a general change or modification in our rates, charges and tariffs no sooner than 60 days and no later than 90 days from the date of notice.

On February 22, 2013, we filed a Nonunanimous Stipulation and Agreement (Agreement) with the Missouri Public Service Commission (MPSC) which issued an order approving the Agreement on February 27, 2013, effective March 6, 2013. The Agreement provided for an annual increase in base revenues for our Missouri electric customers in the amount of approximately $27.5 million, effective April 1, 2013, and the continuation of the current fuel adjustment mechanism. The Agreement also included an increase in depreciation rates, recovery of deferred tornado costs over the next ten years 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 had requested an annual increase in base rates for our Missouri electric customers in the amount of $30.7 million, or 7.56%, the continuation of the fuel adjustment clause, new depreciation rates and the recovery of various expenses.

On May 18, 2012, we filed a request with the Federal Energy Regulatory Commission (FERC) to implement a cost-based transmission formula rate (TFR) to be effective August 1, 2012. On July 31, 2012, the FERC suspended the TFR for five months and set the filing for hearing and settlement procedures. On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement includes a TFR that establishes an ROE of 10.0%. The

34

Agreement calls for the TFR to be updated annually with the new updated TFR rates effective on July 1 of each year. FERC action on the Agreement is pending.

For additional information, see “Rate Matters” below.

Integrated Resource Plan

We filed our Integrated Resource Plan (IRP) with the MPSC on July 1, 2013. The IRP analysis of future loads and resources is normally conducted once every three years. Our IRP supports our Compliance Plan discussed in Note 7 of “Notes to Consolidated Financial Statements (Unaudited)”.

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

Financings

As described in Note 6, on October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. The delayed settlement of both series of bonds occurred on May 30, 2013. Interest is payable semi-annually on the bonds on each May 30 and November 30, commencing November 30, 2013.

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

Union Contracts

In May 2013, Local 1464 of the International Brotherhood of Electrical Workers (IBEW) ratified a four-year agreement with EDG, effective June 1, 2013. At December 31, 2012, 34 EDG employees were members of Local 1464 of the IBEW.

The EDE contract with Local 1474 of the IBEW expired on October 31, 2013. Neither party chose to terminate the agreement, and, under its terms, the agreement has been automatically extended until October 31, 2014. At December 31, 2012, 331 EDE employees were members of Local 1474 of the IBEW.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month, nine-month and twelve-month periods ended September 30, 2013, compared to the same periods ended September 30, 2012.

The following table represents our results of operations by operating segment for the applicable periods ended September 30 (in millions):

	Quarter Ended						Nine Months Ended				Twelve Months Ended
	2013			2012			2013		2012		2013		2012
Electric	$	23.7		$	25.7		$	45.4	$	44.6	$	53.4	$	51.9
Gas	(0.6		)	(0.4		)	1.1		0.3		2.1		1.2
Other	0.9			0.2			1.8		1.2		2.4		1.6
Net income	$	24.0		$	25.5		$	48.3	$	46.1	$	57.9	$	54.7

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Electric Segment

Gross Margin

As shown in the table below, electric segment gross margin increased approximately $0.8 million, $16.3 million and $16.8 million for the quarter, nine months ended and twelve months ended September 30, 2013 periods, respectively, as compared to the corresponding periods in 2012. Increased electric rates for our Missouri customers and an increase in average customer counts positively impacted revenues and gross margin for all periods presented. These increases were offset in the third quarter of 2013 and partially offset in the nine months ended and twelve months ended September 30, 2013 periods by weather impacts. A change in our estimate for unbilled revenues made during the third quarter of 2012 also negatively impacted margin in all three periods.

The table below represents our electric gross margins for the applicable periods ended September 30 (dollars in millions):

	Three Months Ended						Nine Months Ended						Twelve Months Ended
	2013			2012			2013			2012			2013			2012
Electric segment revenues	$	150.4		$	152.7		$	406.2		$	396.5		$	520.3		$	514.5
Fuel and purchased power	44.9			48.0			132.2			138.8			172.3			183.3
Electric segment gross margins	$	105.5		$	104.7		$	274.0		$	257.7		$	348.0		$	331.2
Margin as % of total electric segment revenues	70.2		%	68.5		%	67.5		%	65.0		%	66.9		%	64.4		%

Although a non-GAAP presentation, we believe the presentation of gross margin 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. However, these margins may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Sales and Revenues

Electric operating revenues comprised approximately 95.5% of our total operating revenues during the third quarter of 2013.

The amounts and percentage changes from the prior periods in kilowatt-hour (“kWh”) sales by major customer class for on-system sales and for off-system sales for the applicable periods ended September 30, were as follows:

	kWh Sales
	(in millions)
	3 Months	3 Months			9 Months	9 Months			12 Months	12 Months
	Ended	Ended	%		Ended	Ended	%		Ended	Ended	%
Customer Class	2013	2012	Change(1)		2013	2012	Change(1)		2013	2012	Change(1)
Residential	495.2	573.3	(13.6	)%	1,453.5	1,438.9	1.0	%	1,865.4	1,852.0	0.7	%
Commercial	414.1	447.3	(7.4	)	1,150.8	1,184.5	(2.8	)	1,524.5	1,558.0	(2.1	)
Industrial	270.0	274.2	(1.5	)	775.0	785.5	(1.3	)	1,018.0	1,030.8	(1.2	)
Wholesale on-system	93.9	98.6	(4.7	)	262.3	272.1	(3.6	)	343.3	355.1	(3.3	)
Other(2)	33.6	33.6	(0.1	)	98.1	93.9	4.5		128.4	124.3	3.3
Total on-system sales	1,306.8	1,427.0	(8.4	)	3,739.7	3,774.9	(0.9	)	4,879.6	4,920.2	(0.8	)
Off-system	144.4	217.6	(33.7	)	479.7	525.8	(8.8	)	657.9	679.9	(3.2	)
Total KWh Sales	1,451.2	1,644.6	(11.8	)	4,219.4	4,300.7	(1.9	)	5,537.5	5,600.1	(1.1	)

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

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

KWh sales for our on-system customers decreased 8.4% during the quarter ended September 30, 2013, mainly due to milder weather as compared to the third quarter of 2012. Total cooling degree days (the cumulative number of degrees that the daily average temperature for each day during that period was above 65° F) for the third quarter of 2013 were 15.5% less than the same period last year and 1.9% less than the 30-year average. KWh sales for our residential and commercial customers

36

decreased during the third quarter of 2013 as compared to the third quarter of 2012 primarily due to the milder weather during the third quarter of 2013.

KWh sales for our on-system customers decreased slightly (0.9%) during the nine months ended September 30, 2013, as compared to the same period in 2012, reflecting the milder weather in the third quarter of 2013 and slightly more temperate than normal temperatures during the second quarter of 2013, partially offset by favorable first quarter weather. KWh sales for our residential customers, however, increased 1.0% during the nine months ended September 30, 2013, mainly due to an increase in the average residential customer count.  Commercial kWh sales decreased 2.8% reflecting the milder weather described above.

KWh sales for our on-system customers decreased slightly (0.8%) during the twelve months ended September 30, 2013, as compared to the same period in 2012, mainly due to the milder weather described above, partially offset by favorable first quarter weather. Residential kWh sales increased slightly (0.7%) primarily due to the increase in the average residential customer count while commercial kWh sales decreased 2.1% reflecting the milder weather described above.

Industrial sales decreased 1.5%, 1.3% and 1.2% during the quarter, nine month and twelve month periods ended September 30, 2013, respectively, due to operating reductions by several large industrial customers.

The amounts and percentage changes from the prior periods in electric segment operating revenues by major customer class for on-system and off-system sales for the applicable periods ended September 30, were as follows:

	Electric Segment Operating Revenues
	($ in millions)
	3 Months		3 Months				9 Months		9 Months				12 Months		12 Months
	Ended		Ended		%		Ended		Ended		%		Ended		Ended		%
Customer Class	2013		2012		Change(1)		2013		2012		Change(1)		2013		2012		Change(1)
Residential	$	62.9	$	66.9	(6.0	)%	$	172.1	$	168.4	2.2	%	$	218.2	$	215.8	1.1	%
Commercial	46.5		46.5		0.1		122.3		122.3		0.1		158.9		160.0		(0.7	)
Industrial	24.0		22.6		5.9		62.2		61.5		1.2		79.5		79.9		(0.4	)
Wholesale on-system	5.7		5.7		(0.5	)	15.3		14.3		6.7		19.5		18.5		5.3
Other(2)	4.1		3.8		7.7		11.4		10.7		6.3		14.7		14.0		4.5
Total on-system revenues	$	143.2	$	145.5	(1.6	)	$	383.3	$	377.2	1.6		$	490.8	$	488.2	0.5
Off-system	3.2		4.8		(33.8	)	11.1		11.6		(4.0	)	15.2		16.2		(5.8	)
Total revenues from kWh sales	146.4		150.3		(2.6	)	394.4		388.8		1.5		506.0		504.4		0.3
Miscellaneous revenues(3)	3.4		1.9		79.2		10.2		6.4		57.4		12.2		8.3		45.6
Total electric operating revenues	$	149.8	$	152.2	(1.6	)	$	404.6	$	395.2	2.4		$	518.2	$	512.7	1.1
Water revenues	0.6		0.5		15.7		1.6		1.3		19.2		2.1		1.8		15.5
Total electric segment operating revenues	$	150.4	$	152.7	(1.5	)	$	406.2	$	396.5	2.4		$	520.3	$	514.5	1.1

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

(2) Other operating revenues include street lighting, other public authorities and interdepartmental usage.

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

Revenues for our on-system customers decreased $2.3 million during the third quarter of 2013 as compared to the third quarter of 2012. Rate changes from the April 2013 Missouri rate increase increased revenues an estimated $9.9 million. Improved customer counts increased revenues an estimated $1.1 million. An increase in fuel recovery revenue (and corresponding reduction in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during the third quarter of 2013 increased revenues $1.1 million compared to the prior year quarter. The impact of weather and other related factors decreased revenues an estimated $11.0 million. Additionally, a change in our unbilled revenue estimate in the third quarter of 2012 (which added $3.4 million to revenues in 2012) decreased revenues $3.4 million in the third quarter of 2013.

Revenues for our on-system customers increased $6.1 million for the nine months ended September 30, 2013 as compared to the same period in 2012. Rate changes from the April 2013 Missouri rate increase contributed an estimated $18.8 million to revenues. Improved customer counts increased revenues an estimated $3.6 million. These revenue increases were partially offset by a $6.8 million decrease in fuel recovery revenue (and corresponding reduction in fuel expenses, resulting in

37

no net effect on gross margin) from Missouri customers during the nine months ended September 30, 2013 compared to the same period in 2012. Weather and other related factors decreased revenues an estimated $6.1 million during the nine months ended September 30, 2013. The change in our unbilled revenue estimate in the third quarter of 2012 decreased revenues $3.4 million during the nine months ended September 30, 2013. The cumulative effect of the revenue changes mentioned above had a favorable impact in gross margin for the nine months ended 2013 period.

Revenues for our on-system customers increased $2.6 million for the twelve months ended September 30, 2013 as compared to the same period in 2012. Rate changes, primarily the April 2013 Missouri rate increase and the January 2012 Kansas rate increase, contributed an estimated $18.4 million to revenues. Improved customer counts increased revenues an estimated $5.4 million. These revenue increases were partially offset by a $9.4 million decrease in fuel recovery revenue (and corresponding reduction in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during the twelve months ended September 30, 2013 compared to the same period in 2012. Weather and other related factors decreased revenues an estimated $8.4 million. The change in our unbilled revenue estimate in the third quarter of 2012 decreased revenues $3.4 million during the twelve months ended September 30, 2013. The cumulative year over year revenue changes mentioned above impacted gross margin positively.

Off-System Electric Transactions.

In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power Pool (SPP) Energy Imbalance Services (EIS) market. See “— Competition and Markets” below. The majority of our off-system sales margins are included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and our transmission rider in our Arkansas jurisdiction and generally adjust the fuel and purchased power expense. As a result, nearly all of the off-system sales margin flows back to the customer and has little effect on margin or net income.

Miscellaneous Revenues

Our miscellaneous revenues increased approximately $1.5 million, $3.7 million and $3.8 million during the quarter, nine month and twelve month periods ended September 30, 2013, respectively, primarily due to increased Southwest Power Pool (SPP) transmission revenues. These miscellaneous revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions — Fuel and Purchased Power

The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statements of income for the applicable periods ended September 30, 2013 and 2012.

38

	Three Months						Nine Months						Twelve Months
	Ended						Ended						Ended
(in millions)	2013			2012			2013			2012			2013			2012
Actual fuel and purchased power expenditures	$	46.0		$	51.3		$	137.5		$	131.9		$	179.2		$	172.5
Missouri fuel adjustment recovery (1)	(1.1		)	(2.2		)	(1.9		)	4.8			(3.3		)	6.1
Missouri fuel adjustment deferral(2)	0.6			(0.3		)	(1.2		)	4.7			(0.6		)	6.9
Kansas and Oklahoma regulatory adjustments(2)	0.1			0.4			0.0			1.2			(0.2		)	1.4
SWPA amortization(3)	(0.7		)	(0.8		)	(2.1		)	(2.1		)	(2.8		)	(2.8		)
Unrealized (gain)/loss on derivatives	(0.0		)	(0.4		)	(0.1		)	(1.7		)	0.0			(0.8		)
Total fuel and purchased power expense per income statement	$	44.9		$	48.0		$	132.2		$	138.8		$	172.3		$	183.3

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

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

(3) Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010.

Operating Revenue Deductions — Other Than Fuel and Purchased Power

The table below shows regulated operating expense increases/(decreases) for the applicable periods ended September 30, 2013 as compared to the same periods in 2012.

	Three Months			Nine Months			Twelve Months
	Ended			Ended			Ended
(in millions)	2013 vs. 2012			2013 vs. 2012			2013 vs. 2012
Transmission and distribution expense	$	1.1		$	3.7		$	4.0
General labor costs	0.6			1.6			1.9
Employee health care expense	0.2			0.7			1.5
Steam power other operating expense	0.0			0.6			0.8
Employee pension expense	0.1			0.4			0.5
Customer accounts expense	0.3			0.8			0.6
Other power supply expenses	0.5			0.5			0.5
Property insurance	0.1			0.4			0.6
Injuries and damages expense	(0.3		)	0.1			0.2
Customer assistance expense	0.1			0.2			0.1
Regulatory commission expense	0.1			0.2			(0.4		)
Banking fees	(0.1		)	(0.6		)	(0.8		)
General office expense	(0.1		)	0.2			0.3
Professional services	(0.1		)	(0.4		)	(0.3		)
Regulatory reversal of gain on prior period sale of assets(1)	0.0			1.2			1.2
Other miscellaneous accounts (netted)	(0.2		)	0.4			0.2
TOTAL	$	2.3		$	10.0		$	10.9

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

The table below shows maintenance and repairs expense increases/(decreases) for the applicable periods ended September 30, 2013 as compared to the same periods in 2012.

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	Three Months			Nine Months			Twelve Months
	Ended			Ended			Ended
(in millions)	2013 vs. 2012			2013 vs. 2012			2013 vs. 2012
Distribution and transmission maintenance costs	$	0.8		$	0.2		(0.6	)
Iatan deferred maintenance expense	0.3			0.3			0.6
Maintenance and repairs expense at the Asbury plant	(1.1		)	(1.1		)	(1.7	)
Maintenance and repairs expense at the SLCC	(0.3		)	(0.8		)	(1.3	)
Maintenance and repairs expense at the Iatan plant	(0.2		)	0.4			(0.1	)
Maintenance and repairs expense at the Riverton plant	0.0			(0.6		)	(0.6	)
Maintenance and repairs expense at the Energy Center	0.0			0.3			0.5
Other miscellaneous accounts (netted)	0.2			0.0			0.1
TOTAL	$	(0.3	)	(1.3		)	(3.1	)

Depreciation and amortization expense increased approximately $2.6 million (18.7%), $6.1 million (14.9%) and $7.1 million (13.2%) during the quarter, nine month and twelve month periods ended September 30, 2013, respectively, primarily due to increased depreciation rates resulting from our recent Missouri electric rate case settlement and increased plant in service.

Other taxes increased approximately $0.7 million, $1.7 million and $2.2 million during the quarter, nine month and twelve month periods ended September 30, 2013, respectively, due to increased property tax reflecting our additions to plant in service during all periods presented and increased municipal franchise taxes for the nine and twelve month ended periods.

Gas Segment

Gas Operating Revenues and Sales

The following table details our natural gas sales for the periods ended September 30:

Total Gas Delivered to Customers

	Three Months Ended		%		Nine Months Ended		%		Twelve Months Ended		%
(bcf sales)	2013	2012	change		2013	2012	change		2013	2012	change
Residential	0.10	0.10	(6.7	)%	1.76	1.22	44.8	%	2.56	1.99	28.3	%
Commercial	0.10	0.11	(6.3	)	0.89	0.69	28.9		1.25	1.04	19.6
Industrial	0.00	0.00	25.0		0.05	0.04	29.3		0.07	0.07	3.9
Other(1)	0.00	0.00	1.5		0.02	0.01	55.4		0.03	0.03	32.6
Total retail sales	0.20	0.21	(5.8	)	2.72	1.96	39.0		3.91	3.13	24.9
Transportation sales	0.86	0.90	(4.4	)	3.25	3.04	6.8		4.45	4.15	7.4
Total gas operating sales	1.06	1.11	(4.7	)	5.97	5.00	19.4		8.36	7.28	15.0

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

Gas retail sales mostly varied as a result of the various weather patterns experienced in each of the 2013 and 2012 periods shown below. Customer counts were fairly consistent throughout the periods and the gas segment did not implement any retail rate changes except for changes in the cost of gas sold.

The following table details our natural gas revenues for the periods ended September 30:

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Operating Revenues and Cost of Gas Sold

	Three Months Ended						Nine Months Ended						Twelve Months Ended
($ in millions)	2013		2012		% change		2013		2012		% change		2013		2012		% change
Residential	$	2.7	$	2.8	(2.2	)%	$	20.8	$	16.1	29.0	%	$	29.4	$	24.5	20.2	%
Commercial	1.4		1.4		(2.3	)	9.0		7.3		24.8		12.6		10.7		17.8
Industrial	0.1		0.0		15.5		0.3		0.3		6.9		0.5		0.5		(5.1	)
Other(1)	0.0		0.0		3.4		0.3		0.2		42.9		0.4		0.3		27.7
Total retail revenues	$	4.2	$	4.2	(2.0	)	$	30.4	$	23.9	27.6		$	42.9	$	36.0	19.2
Other revenues	0.1		0.1		18.7		0.3		0.3		9.1		0.4		0.4		4.2
Transportation revenues	0.7		0.7		2.9		2.5		2.3		5.7		3.3		3.2		3.3
Total gas operating revenues	$	5.0	$	5.0	(0.9	)	$	33.2	$	26.5	25.4		$	46.6	$	39.6	17.7
Cost of gas sold	1.2		1.3		(4.7	)	16.2		11.6		39.9		23.3		18.4		26.5
Gas segment gross margins	$	3.8	$	3.7	0.3		$	17.0	$	14.9	14.2		$	23.3	$	21.2	10.1

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

During the third quarter of 2013, gas segment revenues decreased slightly compared to the third quarter of 2012. However, our margin (defined as gas operating revenues less cost of gas in rates) for the third quarter of 2013 increased slightly compared to the third quarter of 2012.

During the nine and twelve month periods ended September 30, 2013, gas segment revenues increased approximately $6.6 million and $7.0 million, respectively, as compared to the corresponding periods ended September 30, 2012 mainly due to increased sales resulting from colder weather during the first and second quarters of 2013 as compared to the same periods in 2012. Our gas gross margin for the nine and twelve months ended September 30, 2013 increased $2.1 million in each period as compared to the corresponding 2012 periods reflecting increased sales resulting from colder weather during the first and second quarters of 2013.

We have a PGA clause in place that allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of September 30, 2013, we had unrecovered purchased gas costs of $0.3 million recorded as a current regulatory asset and $1.2 million recorded as a deferred regulatory asset.

Operating Revenue Deductions

The table below shows regulated operating expense increases/(decreases) for the applicable periods ended September 30, 2013 as compared to the same periods in 2012.

	Three Months		Nine Months			Twelve Months
	Ended		Ended			Ended
(in millions)	2013 vs. 2012		2013 vs. 2012			2013 vs. 2012
Distribution operation expense	$	0.1	$	0.1		$	0.1
Transmission operation expense	0.0		(0.1		)	(0.2		)
Customer accounts expense(1)	0.1		0.1			0.1
TOTAL	$	0.2	$	(0.1	)	$	0.0

(1)Primarily uncollectible accounts.

Our gas segment had a $0.6 million net loss for the third quarter of 2013 as compared to a $0.4 million net loss for the third quarter of 2012. These losses were expected due to the seasonality of the gas segment whose heating season runs from November to March of each year.

Our gas segment had net income of $1.1 million for the nine months ended September 30, 2013 and $2.1 million for the twelve months ended September 30, 2013, as compared to $0.3 million and $1.2 million, respectively, for the comparable periods ended September 30, 2012.

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Consolidated Company

Income Taxes

The following table shows our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended September 30:

	Three Months Ended						Nine Months Ended						Twelve Months Ended
	2013			2012			2013			2012			2013			2012
Consolidated provision for income taxes	$	14.1		$	15.5		$	28.7		$	28.4		$	34.4		$	34.3
Consolidated effective federal and state income tax rates	37.1		%	37.7		%	37.3		%	38.2		%	37.3		%	38.5		%

See Note 12 of “Notes to Consolidated Financial Statements (Unaudited)” for more information and discussion concerning our income tax provision and effective tax rates.

Nonoperating Items

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended September 30. AFUDC increased during all periods presented in 2013 reflecting the environmental retrofit project at our Asbury plant.

	Three Months Ended				Nine Months Ended				Twelve Months Ended
($ in millions)	2013		2012		2013		2012		2013		2012
Allowance for equity funds used during construction	$	1.1	$	0.3	$	2.5	$	0.4	$	3.3	$	0.5
Allowance for borrowed funds used during construction	0.6		0.2		1.4		0.4		1.7		0.5
Total AFUDC	$	1.7	$	0.5	$	3.9	$	0.8	$	5.0	$	1.0

Total interest charges on long-term and short-term debt for the periods ended September 30, are shown below. The changes in long-term debt interest for all periods reflect the financing discussed in Note 6 of “Notes to Consolidated Financial Statements (Unaudited)” and under “Liquidity and Capital Resources - Financing Activities” below. The change in the twelve months ended interest charges also reflects the redemption on April 1, 2012 of all $74.8 million aggregate principal amount of our First Mortgage Bonds, 7.00% Series due 2024, the redemption of all $5.2 million of our First Mortgage Bonds, 5.20% Pollution Control Series due 2013, and all $8.0 million of our First Mortgage Bonds, 5.30% Pollution Control Series due 2013. These bonds were replaced by a private placement of $88.0 million aggregate principal amount of 3.58% First Mortgage Bonds due April 2, 2027. The first settlement of $38.0 million occurred on April 2, 2012 and the second settlement of $50.0 million occurred on June 1, 2012. The changes in short-term debt interest primarily reflect lower levels of borrowing during all comparative periods presented.

	Interest Charges
	($ in millions)
	Third		Third				9 Months		9 Months				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%		Ended		Ended		%
	2013		2012		Change		2013		2012		Change		2013		2012		Change
Long-term debt interest	$	10.1	$	9.9	1.5	%	$	30.2	$	30.2	0.0	%	$	40.2	$	40.9	(1.7	)%
Short-term debt interest	—		0.0		(100.0	)	0.1		0.2		(66.5	)	0.1		0.2		(63.3	)
Other interest*	0.3		0.3		(0.1	)	0.8		0.8		0.5		1.1		1.0		3.9
Total interest charges	$	10.4	$	10.2	1.3		$	31.1	$	31.2	(0.4	)	$	41.4	$	42.1	(1.9	)

*Includes deferred Iatan 1 and Iatan 2 carrying charges to reflect construction accounting in accordance with our agreement with the MPSC. Deferral ended when the plants were placed in rates. See Note 3 and Rate Matters below for additional information regarding carrying charges.

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RATE MATTERS

We continually 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, 2010:

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted		Date Effective
Missouri — Electric	July 6, 2012	$	27,500,000	6.78	%	April 1, 2013
Missouri — Water	May 21, 2012	$	450,000	25.5	%	November 23, 2012
Missouri — Electric	September 28, 2010	$	18,700,000	4.70	%	June 15, 2011
Missouri — Electric	October 29, 2009	$	46,800,000	13.40	%	September 10, 2010
Kansas — Electric	June 17, 2011	$	1,250,000	5.20	%	January 1, 2012
Kansas — Electric	November 4, 2009	$	2,800,000	12.40	%	July 1, 2010
Oklahoma — Electric	June 30, 2011	$	240,722	1.66	%	January 4, 2012
Oklahoma — Electric	January 28, 2011	$	1,063,100	9.32	%	March 1, 2011
Oklahoma — Electric	March 25, 2010	$	1,456,979	15.70	%	September 1, 2010
Arkansas - Electric	August 19, 2010	$	2,104,321	19.00	%	April 13, 2011
Missouri — Gas	June 5, 2009	$	2,600,000	4.37	%	April 1, 2010

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. The Agreement also included an increase in depreciation rates, recovery of deferred tornado costs over the next ten years 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. This request was primarily designed to recover operation and maintenance expenses and capital costs associated with the May 22, 2011 tornado, Southwest Power Pool transmission charges allocated to us, operating systems replacement costs for new software systems, vegetation management costs, new depreciation rates and amortization of a regulatory asset related to the tax benefits of cost of removal, the balance of which was approximately $9.6 million at December 31, 2012.

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On May 18, 2012, we filed a request with the FERC to implement a TFR to be effective August 1, 2012. On July 31, 2012, the FERC suspended the TFR for five months and set the filing for hearing and settlement procedures. On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement includes a TFR that establishes an ROE of 10.0%. The Agreement calls for the TFR to be updated annually with the new updated TFR rates effective on July 1 of each year. FERC action on the Agreement is pending.

Our other rate cases, as we reported in our Annual Report on Form 10-K for the year ended December 31, 2012, remain unchanged. See Note 3, “Regulatory Matters” in our Annual Report on Form 10-K for the year ended December 31, 2012 for additional information.

On September 17, 2013, we advised the Arkansas Public Service Commission of the intention to file an application for a general change or modification in our rates, charges and tariffs no sooner than 60 days and no later than 90 days from the date of notice.

COMPETITION AND MARKETS

Electric Segment

SPP Regional Transmission Development: On June 17, 2010, the FERC approved the new highway/byway cost allocation method, a new transmission cost allocation method to replace the existing FERC accepted cost allocation method for new transmission facilities needed to continue to reliably and economically serve SPP customers, including ours, well into the future. To date, the SPP’s Board of Directors (BOD) has approved over $8 billion in transmission projects for the 2006 through 2022 time period of which over $4 billion is in planned highway/byway transmission projects. As these projects are constructed, we will be allocated a share of the costs of the projects pursuant to the FERC accepted highway/byway regional costs allocation method. We expect that these operating costs will be material, but that they will be recoverable in future rates. On September 11, 2013, the MPSC unanimously approved a stipulation and agreement regarding our continued participation in the SPP through 2019, including the scheduled Day 2 organized markets in April 2014, This agreement requires us to file a report in May 2018 regarding whether or not continued participation in the SPP or stand alone operations beyond 2019 is in the public interest.

Other FERC Activity

On April 23, 2012, we intervened in the SPP’s Petition for Review (Case No. 12-1158) of FERC’s Orders on Declaratory Order and Rehearing (Docket No. EL11-34-000) on the interpretation of the SPP/MISO Joint Operating Agreement (JOA) at the United States Court of Appeals for the District of Columbia. We are in agreement with SPP and other SPP members that the FERC was incorrect in its determination that MISO’s interpretation of the Joint Operating Agreement appropriately enables MISO and Entergy to utilize ours and other SPP members transmission systems to integrate Entergy into the MISO RTO without compensation or consideration of the negative impacts to us and the other SPP members. On June 25, 2012, the SPP interveners made a joint intervention filing at the DC court, a joint brief in October 2012, reply brief on January 14, 2013, and oral arguments on October 18, 2013. The decision of the DC Court is expected by or before the end of the first quarter of 2014. It is in our best interests that the review of the Joint Operating Agreement between SPP and MISO be remanded back to the FERC to reevaluate its Orders. 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. In late 2012, ITC Holdings and Entergy announced the sale of transmission assets to ITC and formation of new ITC transmission only companies. Subsequently, ITC, Entergy, and MISO made multiple filings at the FERC and various state Commissions, including the MPSC, for the transfer of ownership of Entergy’s transmission facilities as well as full integration into the MISO RTO. We and several other SPP members jointly filed in protest of the filings on January 11, 2013, based on Entergy and MISO’s planned utilization of our and the other SPP members’ system without mitigation or resolution of the

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current and expected harm of MISO’s interpretation/use of the joint operating agreement to implement the integration. On June 20, 2013, the FERC issued several Orders, with some conditions, approving Entergy joining MISO and the purchase of Entergy transmission assets by a newly created subsidiary of ITC Holdings, ITC South. Many of the SPP joint protestors made joint filings at the FERC for clarification and/or rehearing of the FERC’s orders on ITC/Entergy/MISO with an emphasis on the FERC’s lack of requirement for SPP and MISO to resolve their JOA issues of dispute prior to Entergy joining MISO in late December 2013. FERC’s ITC/Energy Order is subject to Entergy securing all necessary state and federal regulatory approvals.

We and several other SPP members intervened at the Missouri and Arkansas commissions in opposition to the transfer of control of Entergy Arkansas transmission assets to MISO, as well as the sale/transfer of transmission assets of Entergy Arkansas (EAI) to ITC South. We believe the sale of Entergy’s transmission facilities to ITC and joining MISO has not been shown to be in the public interest and will negatively impact and increase cost to our customers. The transfer of transmission asset cases were delayed by the Arkansas and the Missouri commissions pending rulings from Entergy’s other commissions, specifically Texas. Entergy has refiled those transfer requests in Texas.  On October 9, 2013, the MPSC conditionally approved EAI’s transfer of transmission assets and participation in MISO based upon development and FERC approval of a revised Joint Operating Agreement between SPP and MISO that addresses at a minimum, loop flow issues and other altered flows related to the Missouri seams between SPP/MISO and upon a requirement that EAI and/or ITC hold harmless non-MISO Missouri retail customers from “all” increased costs due to Entergy’s potential transfer of functional control of its transmission assets to MISO.  We believe this is a very positive order for our customers but anticipate an EAI, MISO, and ITC appeal of the MPSC order or other regulatory efforts to challenge such action by the MPSC.

See Note 3, “Regulatory Matters - Competition” in our Annual Report on Form 10-K for the year ended December 31, 2012 for additional information.

LIQUIDITY AND CAPITAL RESOURCES

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

Our issuance of various securities, including equity, long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the SEC. We estimate that internally generated funds (funds provided by operating activities less dividends paid) will provide approximately 39% to 44%  of the funds required for the remainder of our budgeted 2013 capital expenditures (as discussed in “Capital Requirements and Investing Activities” below). We believe the amounts available to us under our credit facilities and the issuance of debt and equity securities together with this cash provided by operating activities will allow us to meet our needs for working capital, pension contributions, our continuing construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the timing of our construction programs and other factors. See Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012 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 nine months ended September 30:

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Summary of Cash Flows

	Nine Months Ended September 30,
(in millions)	2013			2012			Change
Cash provided by/(used in):
Operating activities	$	117.6		$	136.1		$	(18.5	)
Investing activities	(105.8		)	(101.4		)	(4.4		)
Financing activities	1.2			(36.9		)	38.1
Net change in cash and cash equivalents	$	13.0		$	(2.2	)	$	15.2

Cash flow from Operating Activities

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

Period-over-period 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.

Nine Months Ended September 30, 2013 Compared to 2012.  During the nine months ended September 30, 2013 our net cash flows provided from operating activities decreased $18.4 million or 13.5% from 2012. This change resulted from the following:

·Increase in net income - $2.2 million.

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

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

·Working capital changes for accounts receivable, accounts payable and other current assets and liabilities - $1.2 million.

·Change in pension contributions net of expense accruals — $(6.9) million

·Tax timing differences mostly related to depreciation and amortizations - $(5.3) million.

·Increase in equity AFUDC mostly attributable to higher construction work in progress balances - $(2.1) million.

·Lower fuel related amortizations partially offset by increased plant in service depreciation - $(2.0) million.

·Long-term regulatory fuel adjustment deferrals - $(7.1) million.

·Deferred revenues - $(1.2) million.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities increased $4.4 million during the nine months ended September 30, 2013, as compared to the same period in 2012, due to an $8.1 million increase in regulated capital expenditures, a $1.1 million decrease in non-regulated capital expenditures and a $2.6 million decrease in restricted cash.

Our capital expenditures incurred totaled approximately $118.9 million during the nine months ended September 30, 2013, compared to $108.0 million for the nine months ended September 30, 2012. The increase was primarily the result of an increase in electric plant additions and replacements, mainly due to the environmental retrofit in progress at our Asbury plant.

A breakdown of the capital expenditures for the nine months ended September 30, 2013 and 2012 is as follows:

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	Capital Expenditures
(in millions)	2013			2012
Distribution and transmission system additions	$	43.5		$	43.9
New Generation — Iatan 2	0.2			1.0
Storms	0.3			4.6
Additions and replacements — electric plant	59.9			35.1
Gas segment additions and replacements	2.6			2.1
Transportation	1.9			2.9
Other (including retirements, insurance proceeds and salvage -net) (1)	9.2			16.0
Subtotal	117.6			105.6
Non-regulated capital expenditures (primarily fiber optics)	1.3			2.4
Subtotal capital expenditures incurred (2)	118.9			108.0
Adjusted for capital expenditures payable (3)	(10.5		)	(6.6		)
Total cash outlay	$	108.4		$	101.4

(1) Other includes equity AFUDC of $(2.5) million and $(0.4) million for 2013 and 2012, respectively.

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

(3) The amount of expenditures paid/(unpaid) at the end of the reporting period to adjust to actual cash outlay reflected in the Investing Activities section of the Statement of Cash Flows.

All of our cash requirements for capital expenditures during the nine months ended September 30, 2013 were satisfied from internally generated funds (funds provided by operating activities less dividends paid).

We estimate that our capital expenditures (excluding AFUDC) for the remainder of 2013 will range from approximately $40.0 million to $45.0 million and for 2014 through 2018 will be as follows (in millions):

	2014		2015		2016		2017		2018
Estimated capital expenditures	$	213.7	$	175.9	$	110.1	$	99.2	$	95.9

As noted in the Purchased Power section of Note 7, it is not currently our intention to exercise the Plum Point ownership option and, as such, no expenditures are included for such purpose in the 2015 projection.

We estimate that internally generated funds will provide approximately 39% to 44% of the funds required for the remainder of our budgeted 2013 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. For further information see Note 6 of “Notes to Consolidated Financial Statements (Unaudited).”

Financing Activities

Nine Months Ended September 30, 2013 Compared to  2012.

Our net cash flows provided by financing activities was $1.2 million in the nine months ended September 30, 2013, an increase of $38.1 million as compared to a $36.9 million use of cash during the nine months ended September 30, 2012, primarily due to the following:

·Issuance of $150.0 million of first mortgage bonds in the nine months ended September 30, 2013 compared to $88.0 million in the nine months ended September 30, 2012

·Repayment of $98.0 million of senior notes in the nine months ended September 30, 2013 compared to $88.0 million of first mortgage bonds in the nine months ended September 30, 2012.

·Repayment of $24.0 million in short-term debt in the nine months ended September 30, 2013 as compared to repayment of $10.0 million in the nine months ended September 30, 2012.

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See the financing discussion in Note 6 of “Notes to Consolidated Financial Statements (Unaudited).”

Shelf Registration

We have a $400.0 million shelf registration statement with the SEC, effective for a three-year period beginning February 7, 2011, covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. We have received regulatory approval for the issuance of securities under this shelf from all four states in our electric service territory, but we may only issue up to $250.0 million of such securities in the form of first mortgage bonds, of which $12.0 million remains available after giving effect to the $150.0 million of new first mortgage bonds issued on May 30, 2013. We plan to use proceeds from offerings made pursuant to this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs.

Credit Agreements

On January 17, 2012, we entered into the Third Amended and Restated Unsecured Credit Agreement which amended and restated our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010. This agreement extended the termination date of the revolving credit facility from January 26, 2013 to January 17, 2017. The agreement also removed the letter of credit facility and includes a swingline loan facility with a $15 million swingline loan sublimit. The aggregate amount of the revolving credit commitments remains $150 million, inclusive of the $15 million swingline loan sublimit. In addition, the pricing and fees under the facility were amended. Interest on borrowings under the facility accrues at a rate equal to, at our option, (i) the highest of (A) the bank’s prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three 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 1.25%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings, which fee is currently 0.25%. In addition, upon entering into the amended and restated facility, we paid an upfront fee to the revolving credit banks of $262,500 in the aggregate. There were no other material changes to the terms of the facility.

The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of September 30, 2013, we are in compliance with these ratios. Our total indebtedness is 50.0% of our total capitalization as of September 30, 2013 and our EBITDA is 5.0 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at September 30, 2013 and no outstanding commercial paper.

EDE Mortgage Indenture

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1.0 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended September 30, 2013 would permit us to

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issue approximately $511.9 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 September 30, 2013, we had retired bonds and net property additions which would enable the issuance of at least $837.3 million principal amount of bonds if the annual interest requirements are met. As of September 30, 2013, we are in compliance with all restrictive covenants of the EDE Mortgage.

EDG Mortgage Indenture

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of September 30, 2013, this test would allow us to issue approximately $14.7 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.

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

	Fitch	Moody’s	Standard & Poor’s
Corporate Credit Rating	n/r*	Baa2	BBB
EDE First Mortgage Bonds	BBB+	A3	A-
Senior Notes	BBB	Baa2	BBB
Commercial Paper	F3	P-2	A-2
Outlook	Stable	Stable	Stable

*Not rated

On March 6, 2013, Standard & Poor’s upgraded our corporate credit rating to BBB from BBB-, senior secured debt to A- from BBB+, senior unsecured debt to BBB from BBB- and our commercial paper rating to A-2 from A-3. Standard & Poor’s outlook for Empire is stable. On May 26, 2011 after the May 22, 2011 tornado, and again on April 25, 2012, Moody’s reaffirmed all of our ratings. On March 24, 2011, Fitch revised our commercial paper rating from F2 to F3 and reaffirmed our other ratings. The rating action was not based on a specific action or event on our part, but reflected their traditional linkage of long-term and short-term Issuer Default Ratings. On May 24, 2013, Fitch reaffirmed our ratings.

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

CONTRACTUAL OBLIGATIONS

Material changes to our contractual obligations at September 30, 2013, compared to December 31, 2012, consist of the following:

·On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. The delayed settlement of both series of bonds occurred on May 30, 2013.

·On June 15, 2013, we redeemed all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013.

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·On July 9, 2013, we signed 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. This conversion is currently scheduled to be completed in 2016 at a cost estimated to range from $165 million to $175 million, excluding AFUDC.

See “Financing Activities” above  and Note 7 of “Notes to Consolidated Financial Statements (Unaudited)” under “Environmental” for details.

In addition, on October 1, 2013, we extended our transportation contract with ANR Pipeline Company, expiring on March 31, 2014, for a period of ten years, expiring on March 31, 2024. Annual costs under this contract are expected to be approximately $0.5 million, depending on volume.

DIVIDENDS

Our diluted earnings per share were $1.13 for the nine months ended September 30, 2013 and were $1.32 and $1.31 for the years ended December 31, 2012 and 2011, respectively. Dividends paid per share were $0.75 for the nine months ended September 30, 2013, $1.00 for the year ended December 31, 2012 and $0.64 for the year ended December 31, 2011.

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.

In response to the expected loss of revenues resulting from the May 22, 2011 tornado, our level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. On February 2, 2012, the Board of Directors re-established the dividend and declared a quarterly dividend of $0.25 per share on common stock payable on March 15, 2012 to holders of record as of March 1, 2012. Dividends were paid during all four quarters of 2012. As of September 30, 2013, our retained earnings balance was $63.4 million, compared to $48.1 million as of September 30, 2012 and a retained earnings balance of $47.1 million as of December 31, 2012, after paying out $32.0 million in dividends during the first nine months of 2013. On October 31, 2013, the Board of Directors declared a quarterly dividend of $0.255 per share on common stock payable on December 16, 2013 to holders of record as of December 2, 2013, reflecting a 2.0% increase over the previous quarter’s dividend.

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

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payment of any dividend or distribution on, or purchase of, shares of its common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1.

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2012 for a discussion of additional critical accounting policies. There were no changes in these policies in the quarter ended September 30, 2013.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Note 2 of “Notes to Consolidated Financial Statements (Unaudited)”.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

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

Market Risk and Hedging Activities.

Prices in the wholesale power markets often are 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 and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Commodity Price Risk.

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

We satisfied 65.6% of our 2012 generation fuel supply need through coal. This includes the remaining coal used at Riverton as part of its transition to natural gas. Approximately 96% of our 2012 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2015. These contracts satisfy approximately 100% of our anticipated fuel requirements for 2013, 58% for 2014 and 26% for our 2015 requirements for our Asbury coal

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plant. 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 September 30, 2013, 14%, or 0.8 million Dths, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2013 is hedged.

Based on our expected natural gas purchases for our electric operations for the next twelve months, if average natural gas prices should increase 10% more than the price at September 30, 2013, our natural gas cost would increase by approximately $1.7 million based on our September 30, 2013 total hedged positions for the next twelve months. However, this is 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 September 30, 2013, we have 1.7 million Dths in storage on the three pipelines that serve our customers. This represents 83% of our storage capacity.

See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” 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 4 of “Notes to Consolidated Financial Statements (Unaudited)” 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 September 30, 2013 and December 31, 2012. There were no margin deposit liabilities at these dates.

(in millions)	September 30, 2013		December 31, 2012
Margin deposit assets	$	5.8	$	4.2

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a small 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 September 30, 2013, 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)
Net unrealized mark-to-market losses for physical forward natural gas contracts	$	2.1
Net unrealized mark-to-market losses for financial natural gas contracts	6.0
Net credit exposure	$	8.1

The $6.0 million net unrealized mark-to-market loss for financial natural gas contracts is comprised of $6.0 million that our counterparties are exposed to Empire for unrealized losses. We are

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holding no collateral from any counterparty since they are below the $10.0 million mark-to-market collateral threshold in our agreements. As noted above, as of September 30, 2013, we have $5.8 million on deposit for NYMEX contract exposure to Empire, of which $5.6 million represents our collateral requirement. In addition, if NYMEX gas prices decreased 25% from their September 30, 2013 levels, we would be required to post an additional $10.0 million in collateral. If these prices increased 25%, our collateral requirement would decrease $4.4 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.

If market interest rates average 1% more in 2013 than in 2012, our interest expense would increase, and income before taxes would decrease by less than $0.6 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2012. 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.

Item 4.Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2013.

There have been no changes in our internal control over financial reporting that occurred during the third quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II.OTHER INFORMATION

Item 1.Legal Proceedings

See Note 7 of “Notes to Consolidated Financial Statements (Unaudited)” under “Legal Proceedings”, which description is incorporated herein by reference.

Item 1A.Risk Factors.

There have been no material changes to the factors disclosed in Part I, Item 1-A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2012.

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Item 5.Other Information.

For the twelve months ended September 30, 2013, our ratio of earnings to fixed charges was 2.84x.  See Exhibit (12) hereto.

Item 6.Exhibits.

(a)Exhibits.

(12) Computation of Ratio of Earnings to Fixed Charges.

(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 Quarterly Report on Form 10-Q for the period ended September 30, 2013, filed with the SEC on November 8, 2013, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three, nine and twelve month periods ended September 30, 2013 and 2012, (ii) the Consolidated Balance Sheets at September 30, 2013 and December 31, 2012, (iii) the Consolidated Statements of Cash Flows for the nine-month periods ended September 30, 2013 and 2012, and (iv) Notes to Consolidated Financial Statements.**

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

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	THE EMPIRE DISTRICT ELECTRIC COMPANY
		Registrant
	By	/s/ Laurie A. Delano
		Laurie A. Delano
		Vice President — Finance and Chief Financial Officer
	By	/s/ Robert W. Sager
		Robert W. Sager
		Controller, Assistant Secretary and Assistant Treasurer
November 8, 2013

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EX-12

EXHIBIT (12)

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve
	Months Ended
	September 30, 2013
Income before provision for income taxes and fixed charges (Note A)	$	142,401,189
Fixed charges:
Interest on long-term debt	$	40,193,783
Interest on short-term debt	70,560
Other interest	1,091,330
Rental expense representative of an interest factor (Note B)	8,732,962
Total fixed charges	$	50,088,635
Ratio of earnings to fixed charges	2.84		x

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

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

EX-31.(A)

Exhibit (31)(a)

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Bradley P. Beecher, certify that:

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

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

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

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

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

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

c)  Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

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

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

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

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

Date: November 8, 2013
By:	/s/Bradley P. Beecher
	Name: Bradley P. Beecher
	Title: President and Chief Executive Officer

EX-31.(B)

Exhibit (31)(b)

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Laurie A. Delano, certify that:

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

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

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

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

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

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

c)  Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

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

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

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

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

Date: November 8, 2013
By:	/s/ Laurie A. Delano
	Name: Laurie A. Delano
	Title: Vice President - Finance and Chief Financial Officer

EX-32.(A)

Exhibit (32)(a)

Certification Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Bradley P. Beecher, as Chief Executive Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

By	/s/ Bradley P. Beecher
Name: Bradley P. Beecher
Title: President and Chief Executive Officer
Date:		November 8, 2013

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

EX-32.(B)

Exhibit (32)(b)

Certification Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Laurie A. Delano, as Chief Financial Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

By	/s/ Laurie A. Delano
Name: Laurie A. Delano
Title: Vice President - Finance and Chief Financial Officer
Date: November 8, 2013

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

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Income Taxes

9 Months Ended

Sep. 30, 2013

Income Taxes

Income Taxes

Note 12— Income Taxes

The following table shows our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended September 30:

	Three Months Ended						Nine Months Ended						Twelve Months Ended
	2013			2012			2013			2012			2013			2012
Consolidated provision for income taxes	$	14.1		$	15.5		$	28.7		$	28.4		$	34.4		$	34.3
Consolidated effective federal and state income tax rates	37.1		%	37.7		%	37.3		%	38.2		%	37.3		%	38.5		%

The effective income tax rate for the three, nine and twelve month periods ended September 30, 2013 is lower than comparable periods in 2012 primarily due to higher equity AFUDC income in 2013 compared with 2012.

On September 13, 2013, the Internal Revenue Service and the Treasury Department released final regulations under Code 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. We are currently analyzing their impact on our financial statements. We do not expect the regulations to have a material impact to our effective tax rate.

We do not have any unrecognized tax benefits as of September 30, 2013. 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.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
CONSOLIDATED BALANCE SHEETS
Accounts receivable - trade, allowance (in dollars)	$ 988	$ 1,388
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares issued	42,939,207	42,484,363
Common stock, shares outstanding	42,939,207	42,484,363

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Fair Value Measurements

9 Months Ended

Sep. 30, 2013

Fair Value Measurements

Fair Value Measurements

Note 5— Fair Value Measurements

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

The guidance also requires that the fair value measurements 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.

The following fair value hierarchy table presents information about our assets measured at fair value using the market value approach on a recurring basis as of September 30, 2013 and December 31, 2012.

	Fair Value Measurements at Reporting Date Using
($ in 000’s) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable  Inputs (Level 3)
				September 30, 2013
Derivative assets	$	333		$	333		$	—	$	—
Derivative liabilities	$	(6,167	)	$	(6,167	)	$	—	$	—
				December 31, 2012
Derivative assets	$	287		$	287		$	—	$	—
Derivative liabilities	$	(7,222	)	$	(7,222	)	$	—	$	—

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 September 30, 2013, was $739.3 million as compared to $687.6 million at December 31, 2012. The fair market value at September 30, 2013 was approximately $716.5 million as compared to $747.2 million at December 31, 2012. 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 September 30, 2013 or that will be realizable in the future.

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Regulated Operating Expenses (Tables)

9 Months Ended

Sep. 30, 2013

Regulated Operating Expenses

Schedule of regulated operating expenses

The following table sets forth the major components comprising “regulated operating expenses” under “Operating Revenue Deductions” on our consolidated statements of income (in thousands) for all periods presented ended September 30:

	Three Months Ended		Three Months Ended		Nine Months Ended		Nine Months Ended		Twelve Months Ended		Twelve Months Ended
	2013		2012		2013		2012		2013		2012
Electric transmission and distribution expense	$	5,530	$	4,392	$	16,509	$	12,764	$	20,828	$	16,784
Natural gas transmission and distribution expense	681		554		1,803		1,870		2,376		2,463
Power operation expense (other than fuel)	3,942		4,129		11,953		11,232		15,766		14,898
Customer accounts and assistance expense	3,124		2,621		8,322		7,639		10,894		10,304
Employee pension expense (1)	2,662		2,562		8,062		7,637		10,605		10,118
Employee healthcare expense (1)	2,662		2,442		7,857		7,004		10,678		9,108
General office supplies and expense	2,997		2,530		9,589		7,805		12,560		10,445
Administrative and general expense	3,375		3,675		11,292		11,466		14,917		15,521
Allowance for uncollectible accounts	975		968		2,765		2,313		3,489		3,245
Regulatory reversal of gain on sale of assets	—		—		1,236		—		1,236		—
Miscellaneous expense	152		165		496		500		675		686
Total	$	26,100	$	24,038	$	79,884	$	70,230	$	104,024	$	93,572

(1) Does not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to and amortized from a regulatory asset and/or a regulatory liability for Missouri, Kansas and Oklahoma jurisdictions.

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Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2013

Regulatory Matters

Components of regulatory assets and liabilities

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

Regulatory Assets and Liabilities

	September 30, 2013			December 31, 2012
Regulatory Assets:
Current:
Under recovered fuel costs(1)	$	302		$	2,885
Current portion of long-term regulatory assets(1)	6,096			3,492
Regulatory assets, current(1)	6,398			6,377
Long-term:
Pension and other postretirement benefits(2)	129,110			136,480
Income taxes	48,418			48,759
Deferred construction accounting costs	16,385			16,717
Unamortized loss on reacquired debt	11,246			12,142
Unsettled derivative losses — electric segment	5,613			6,557
System reliability — vegetation management	7,783			9,002
Storm costs(3)	5,084			4,828
Asset retirement obligation	4,616			4,430
Customer programs	4,785			4,356
Unamortized loss on interest rate derivative	1,001			1,147
Deferred operating and maintenance expense	1,863			2,049
Under recovered fuel costs	1,212			314
Current portion of long-term regulatory assets	(6,096		)	(3,492		)
Other	930			669
Regulatory assets, long-term	231,950			243,958
Total Regulatory Assets	$	238,348		$	250,335

	September 30, 2013			December 31, 2012
Regulatory Liabilities:
Current:
Over recovered fuel costs(1)	$	556		$	3,214
Current portion of long-term regulatory liabilities(1)	3,739			3,089
Regulatory liabilities, current(1)	4,295			6,303
Long-term:
Costs of removal	92,058			83,368
SWPA payment for Ozark Beach lost generation	20,105			22,242
Income taxes	11,736			11,972
Deferred construction accounting costs — fuel	8,047			8,156
Unamortized gain on interest rate derivative	3,414			3,541
Pension and other postretirement benefits(4)	2,377			2,007
Over recovered fuel costs	533			2,858
Current portion of long-term regulatory liabilities(1)	(3,739		)	(3,089		)
Regulatory liabilities, long-term	134,531			131,055
Total Regulatory Liabilities	$	138,826		$	137,358

(1)  Reflects over and under recovered costs of the current portion of regulatory assets or liabilities detailed in the long term sections below expected to be returned or recovered, as applicable, within the next 12 months in rates.

(2) Includes the effect of costs incurred that are more or less than those allowed in rates for Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs.

(3) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado.

(4) Includes the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs.

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended						30 Months Ended			9 Months Ended	1 Months Ended	9 Months Ended			1 Months Ended	9 Months Ended
	Sep. 30, 2013 item	Sep. 30, 2013 Electric Compliance Plan MW	Sep. 30, 2013 Electric Power Plant Mercury And Air Toxics Rule	Sep. 30, 2013 Electric Maximum Power Plant Mercury And Air Toxics Rule	Sep. 30, 2013 Electric Minimum Power Plant Mercury And Air Toxics Rule	Sep. 30, 2013 Southern Star Central Pipeline, Inc. Electric	Sep. 30, 2013 Southern Star Central Pipeline, Inc. Electric Dth	Sep. 30, 2013 Firm Physical gas and transportation contracts	Sep. 30, 2013 Coal and coal transportation contracts	Sep. 30, 2013 Purchased power Plum Point Energy Station MW	Dec. 31, 2008 Purchased power Cloud County Windfarm	Sep. 30, 2013 Purchased power Cloud County Windfarm MW	Sep. 30, 2013 Purchased power Cloud County Windfarm Maximum	Sep. 30, 2013 Purchased power Cloud County Windfarm Minimum	Dec. 31, 2005 Purchased power Elk River Windfarm	Sep. 30, 2013 Purchased power Elk River Windfarm MW	Sep. 30, 2013 Purchased power Elk River Windfarm Maximum	Sep. 30, 2013 Purchased power Elk River Windfarm Minimum	Sep. 30, 2013 Leases Electric train	Sep. 30, 2013 Leases Gas office	Sep. 30, 2013 Leases Plum Point Energy Station railcar	Sep. 30, 2013 Transportation contracts ANR Pipeline Company
Commitments and Contingencies
October 1, 2013 through December 31, 2013								$ 10.6	$ 5.7
January 1, 2014 through December 31, 2015								30.5	34.3
January 1, 2016 through December 31, 2017								22.2	22.6
January 1, 2018 and beyond								8.3	22.6
Term of long-term contract agreement							5 years			30 years	20 years				20 years
Agreement to purchase firm gas storage capacity (in Dths)							1,000,000
Amount of annual storage capacity reservation						1.1
Extension period of contract																						10 years
Contractual annual payment																						0.5
Amount of long-term contract obligation										299.6
Amount of annual payments contingent upon output of the facility													14.6	0			16.9	0
Period of the average cost that is used as a basis for determining annual payments												20 years				20 years
Energy capacity (in megawatts)										670		105				150
Amount of energy capacity owned (in megawatts)										50
Amount of energy capacity under option to purchase (in megawatts)										50
Amount of total power capacity of generating facility (in megawatts)		14
Number of unit trains under short-term operating leases																			2
Number of office facilities under short-term operating leases																				1
Number of railcars under capital leases																					108
Estimated project cost				175	165
Term of long-term contract agreement			5 years
Cost related to pre-engineering and site preparation activities year to date		5.3
Project to date costs related to pre-engineering and site preparation activities		$ 5.9
Number of plaintiffs	3

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Summary of Significant Accounting Policies (Details)	9 Months Ended
	Sep. 30, 2013 town segment item
Summary of Significant Accounting Policies
Number of business segments	3
Number of towns to which water service is provided	3
Number of communities provided natural gas distribution	48

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2013

Income Taxes

Schedule of provision for income taxes and consolidated effective federal and state income tax rates

The following table shows our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended September 30:

	Three Months Ended						Nine Months Ended						Twelve Months Ended
	2013			2012			2013			2012			2013			2012
Consolidated provision for income taxes	$	14.1		$	15.5		$	28.7		$	28.4		$	34.4		$	34.3
Consolidated effective federal and state income tax rates	37.1		%	37.7		%	37.3		%	38.2		%	37.3		%	38.5		%

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Fair Value Measurements (Details) (Recurring basis, USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Assets/(Liabilities) at Fair Value
Fair Value Measurements at Reporting Date
Derivative assets	$ 333	$ 287
Derivative liabilities	(6,167)	(7,222)
Quoted Prices in Active Markets for Identical Liabilities (Level 1)
Fair Value Measurements at Reporting Date
Derivative assets	333	287
Derivative liabilities	$ (6,167)	$ (7,222)

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Retirement Benefits (Details) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended
	Jul. 31, 2013	Sep. 30, 2013 Pension Benefits	Sep. 30, 2012 Pension Benefits	Sep. 30, 2013 Pension Benefits	Sep. 30, 2012 Pension Benefits	Sep. 30, 2013 Pension Benefits	Sep. 30, 2012 Pension Benefits	Sep. 30, 2013 SERP	Sep. 30, 2012 SERP	Sep. 30, 2013 SERP	Sep. 30, 2012 SERP	Sep. 30, 2013 SERP	Sep. 30, 2012 SERP	Sep. 30, 2013 OPEB	Sep. 30, 2012 OPEB	Sep. 30, 2013 OPEB	Sep. 30, 2012 OPEB	Sep. 30, 2013 OPEB	Sep. 30, 2012 OPEB
Net Periodic Pension Benefit Cost:
Service cost		$ 1,863,000	$ 1,439,000	$ 5,590,000	$ 4,696,000	$ 7,156,000	$ 6,094,000	$ 34,000	$ 23,000	$ 101,000	$ 39,000	$ 114,000	$ 62,000	$ 735,000	$ 671,000	$ 2,206,000	$ 1,801,000	$ 2,806,000	$ 2,367,000
Interest cost		2,516,000	2,591,000	7,547,000	7,693,000	10,111,000	10,295,000	78,000	86,000	236,000	197,000	301,000	243,000	957,000	962,000	2,870,000	3,027,000	3,879,000	4,123,000
Expected return on plan assets		(3,107,000)	(3,080,000)	(9,321,000)	(9,232,000)	(12,398,000)	(12,017,000)							(1,088,000)	(1,018,000)	(3,265,000)	(3,101,000)	(4,299,000)	(4,140,000)
Amortization of prior service cost		133,000	133,000	399,000	398,000	531,000	532,000	(2,000)	(2,000)	(6,000)	(6,000)	(8,000)	(8,000)	(253,000)	(253,000)	(758,000)	(758,000)	(1,011,000)	(1,011,000)
Amortization of net actuarial loss		2,611,000	2,052,000	7,834,000	5,952,000	9,818,000	7,325,000	142,000	139,000	426,000	291,000	523,000	334,000	565,000	311,000	1,696,000	1,246,000	2,112,000	1,687,000
Net periodic benefit cost		4,016,000	3,135,000	12,049,000	9,507,000	15,218,000	12,229,000	252,000	246,000	757,000	521,000	930,000	631,000	916,000	673,000	2,749,000	2,215,000	3,487,000	3,026,000
Employer contribution	$ 16,200,000

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Risk Management and Derivative Financial Instruments (Details 2) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Electric
Gain / (Loss) on derivatives
Unrealized losses applicable to financial instruments which will settle in next twelve months	$ 3,100,000		$ 3,100,000		$ 3,100,000
Period within which financial instruments will settle			12 months
Amount of Gain/(Loss) Recognized on Balance Sheet	(1,346,000)	1,776,000	(1,778,000)	(52,000)	(4,174,000)	(4,259,000)
Amount of Gain / (Loss) Recognized in Income on Derivative	(1,951,000)	(2,683,000)	(2,472,000)	(2,624,000)	(3,833,000)	(3,498,000)
Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(27,000)	106,000	(45,000)	(384,000)	(122,000)	(1,458,000)
Commodity contracts | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(1,346,000)	1,776,000	(1,778,000)	(52,000)	(4,174,000)	(4,259,000)
Amount of Gain / (Loss) Recognized in Income on Derivative	(1,951,000)	(2,683,000)	(2,472,000)	(2,624,000)	(3,833,000)	(3,498,000)
Commodity contracts | Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	$ (27,000)	$ 106,000	$ (45,000)	$ (384,000)	$ (122,000)	$ (1,458,000)

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 segment town	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment Information
Number of business segments			3
Number of towns to which water service is provided			3
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues	$ 157,486	$ 159,202	$ 445,272	$ 427,977	$ 574,392	$ 560,743
Depreciation and amortization	17,735	15,108	51,471	45,111	66,807	59,669
Federal and state income taxes	14,150	15,477	28,681	28,436	34,402	34,258
Operating income	32,896	35,282	75,864	76,854	95,231	96,357
Interest income	5	265	522	568	926	1,055
Interest expense	10,353	10,217	31,107	31,219	41,356	42,139
Income from AFUDC (debt and equity)	1,734	535	3,904	805	5,027	1,007
Net income	23,996	25,542	48,283	46,054	57,910	54,745
Capital Expenditures	46,126	41,292	118,834	107,966	157,155	132,684
Total assets	2,195,808		2,195,808		2,195,808		2,126,369
Goodwill	39,492		39,492		39,492		39,492
Electric
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues	150,370	152,730	406,158	396,546	520,265	514,515
Depreciation and amortization	16,328	13,757	47,216	41,086	61,441	54,295
Federal and state income taxes	13,939	15,564	26,882	27,497	31,651	32,464
Operating income	31,589	34,517	70,097	72,594	86,948	89,754
Interest income	1	261	498	549	895	1,035
Interest expense	9,380	9,328	28,273	28,530	37,610	38,525
Income from AFUDC (debt and equity)	1,722	532	3,883	800	5,002	1,000
Net income	23,652	25,705	45,373	44,569	53,435	51,870
Capital Expenditures	45,164	39,794	114,734	103,361	151,490	126,176
Total assets	2,085,805		2,085,805		2,085,805		2,034,399
Gas
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues	4,952	4,999	33,222	26,486	46,585	39,571
Depreciation and amortization	928	895	2,778	2,675	3,702	3,552
Federal and state income taxes	(369)	(232)	707	226	1,269	791
Operating income	364	532	4,004	3,120	5,889	4,995
Interest income	4	88	109	255	177	310
Interest expense	973	975	2,926	2,928	3,902	3,906
Income from AFUDC (debt and equity)	12	3	21	5	25	7
Net income	(599)	(399)	1,136	326	2,066	1,244
Capital Expenditures	628	783	2,824	2,352	4,043	3,599
Total assets	120,608		120,608		120,608		148,814
Other
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues	2,819	1,621	6,844	5,389	8,641	7,249
Depreciation and amortization	479	456	1,477	1,350	1,664	1,822
Federal and state income taxes	580	145	1,092	713	1,482	1,003
Operating income	943	233	1,763	1,140	2,394	1,608
Interest income		2	7	3	10	4
Interest expense						2
Net income	943	236	1,774	1,159	2,409	1,631
Capital Expenditures	334	715	1,276	2,253	1,622	2,909
Total assets	30,295		30,295		30,295		28,871
Eliminations
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues	(655)	(148)	(952)	(444)	(1,099)	(592)
Interest income	0	(86)	(92)	(239)	(156)	(294)
Interest expense	0	(86)	(92)	(239)	(156)	(294)
Total assets	$ (40,900)		$ (40,900)		$ (40,900)		$ (85,715)

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Information

Schedule of statement of income information, balance sheet information and capital expenditures by business segments

	For the quarter ended September 30, 2013
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	150,370	$	4,952		$	2,819	$	(655	)	$	157,486
Depreciation and amortization	16,328		928			479		—			17,735
Federal and state income taxes	13,939		(369		)	580		—			14,150
Operating income	31,589		364			943		—			32,896
Interest income	1		4			—		0			5
Interest expense	9,380		973			—		0			10,353
Income from AFUDC (debt and equity)	1,722		12			—		—			1,734
Net income	23,652		(599		)	943		—			23,996
Capital Expenditures	$	45,164	$	628		$	334				$	46,126

	For the quarter ended September 30, 2012
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	152,730	$	4,999		$	1,621	$	(148	)	$	159,202
Depreciation and amortization	13,757		895			456		—			15,108
Federal and state income taxes	15,564		(232		)	145		—			15,477
Operating income	34,517		532			233		—			35,282
Interest income	261		88			2		(86		)	265
Interest expense	9,328		975			—		(86		)	10,217
Income from AFUDC (debt and equity)	532		3			—		—			535
Net income	25,705		(399		)	236		—			25,542
Capital Expenditures	$	39,794	$	783		$	715				$	41,292

	For the nine months ended September 30, 2013
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	406,158	$	33,222	$	6,844	$	(952	)	$	445,272
Depreciation and amortization	47,216		2,778		1,477		—			51,471
Federal and state income taxes	26,882		707		1,092		—			28,681
Operating income	70,097		4,004		1,763		—			75,864
Interest income	498		109		7		(92		)	522
Interest expense	28,273		2,926		—		(92		)	31,107
Income from AFUDC (debt and equity)	3,883		21		—		—			3,904
Net income	45,373		1,136		1,774		—			48,283
Capital Expenditures	$	114,734	$	2,824	$	1,276				$	118,834

	For the nine months ended September 30, 2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	396,546	$	26,486	$	5,389	$	(444	)	$	427,977
Depreciation and amortization	41,086		2,675		1,350		—			45,111
Federal and state income taxes	27,497		226		713		—			28,436
Operating income	72,594		3,120		1,140		—			76,854
Interest income	549		255		3		(239		)	568
Interest expense	28,530		2,928		—		(239		)	31,219
Income from AFUDC (debt and equity)	800		5		—		—			805
Net income	44,569		326		1,159		—			46,054
Capital Expenditures	$	103,361	$	2,352	$	2,253				$	107,966

	For the twelve months ended September 30, 2013
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	520,265	$	46,585	$	8,641	$	(1,099	)	$	574,392
Depreciation and amortization	61,441		3,702		1,664		—			66,807
Federal and state income taxes	31,651		1,269		1,482		—			34,402
Operating income	86,948		5,889		2,394		—			95,231
Interest income	895		177		10		(156		)	926
Interest expense	37,610		3,902		—		(156		)	41,356
Income from AFUDC (debt and equity)	5,002		25		—		—			5,027
Net income	53,435		2,066		2,409		—			57,910
Capital Expenditures	$	151,490	$	4,043	$	1,622				$	157,155

	For the twelve months ended September 30, 2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	514,515	$	39,571	$	7,249	$	(592	)	$	560,743
Depreciation and amortization	54,295		3,552		1,822		—			59,669
Federal and state income taxes	32,464		791		1,003		—			34,258
Operating income	89,754		4,995		1,608		—			96,357
Interest income	1,035		310		4		(294		)	1,055
Interest expense	38,525		3,906		2		(294		)	42,139
Income from AFUDC (debt and equity)	1,000		7		—		—			1,007
Net Income	51,870		1,244		1,631		—			54,745
Capital Expenditures	$	126,176	$	3,599	$	2,909				$	132,684

	As of September 30, 2013
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,085,805	$	120,608	$	30,295	$	(40,900	)	$	2,195,808

(1) Includes goodwill of $39,492 and reflects the payment of a dividend and return of capital from the EDG subsidiary to the parent in the third quarter of 2013.

	As of December 31, 2012
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,034,399	$	148,814	$	28,871	$	(85,715	)	$	2,126,369

(1) Includes goodwill of $39,492.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Note 1 - Summary of Significant Accounting Policies

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 which provides natural gas distribution to customers in 48 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business.

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

The information furnished reflects all adjustments which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2012.

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Regulatory Matters

9 Months Ended

Sep. 30, 2013

Regulatory Matters

Regulatory Matters

Note 3— Regulatory Matters

On February 27, 2013, the MPSC approved a joint settlement agreement for our 2012 Missouri rate case. 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. The agreement also included an increase in depreciation rates, recovery of deferred tornado costs over the next ten years 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.

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

Regulatory Assets and Liabilities

	September 30, 2013			December 31, 2012
Regulatory Assets:
Current:
Under recovered fuel costs(1)	$	302		$	2,885
Current portion of long-term regulatory assets(1)	6,096			3,492
Regulatory assets, current(1)	6,398			6,377
Long-term:
Pension and other postretirement benefits(2)	129,110			136,480
Income taxes	48,418			48,759
Deferred construction accounting costs	16,385			16,717
Unamortized loss on reacquired debt	11,246			12,142
Unsettled derivative losses — electric segment	5,613			6,557
System reliability — vegetation management	7,783			9,002
Storm costs(3)	5,084			4,828
Asset retirement obligation	4,616			4,430
Customer programs	4,785			4,356
Unamortized loss on interest rate derivative	1,001			1,147
Deferred operating and maintenance expense	1,863			2,049
Under recovered fuel costs	1,212			314
Current portion of long-term regulatory assets	(6,096		)	(3,492		)
Other	930			669
Regulatory assets, long-term	231,950			243,958
Total Regulatory Assets	$	238,348		$	250,335

	September 30, 2013			December 31, 2012
Regulatory Liabilities:
Current:
Over recovered fuel costs(1)	$	556		$	3,214
Current portion of long-term regulatory liabilities(1)	3,739			3,089
Regulatory liabilities, current(1)	4,295			6,303
Long-term:
Costs of removal	92,058			83,368
SWPA payment for Ozark Beach lost generation	20,105			22,242
Income taxes	11,736			11,972
Deferred construction accounting costs — fuel	8,047			8,156
Unamortized gain on interest rate derivative	3,414			3,541
Pension and other postretirement benefits(4)	2,377			2,007
Over recovered fuel costs	533			2,858
Current portion of long-term regulatory liabilities(1)	(3,739		)	(3,089		)
Regulatory liabilities, long-term	134,531			131,055
Total Regulatory Liabilities	$	138,826		$	137,358

(1)  Reflects over and under recovered costs of the current portion of regulatory assets or liabilities detailed in the long term sections below expected to be returned or recovered, as applicable, within the next 12 months in rates.

(2) Includes the effect of costs incurred that are more or less than those allowed in rates for Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs.

(3) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado.

(4) Includes the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs.

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Financing

9 Months Ended

Sep. 30, 2013

Financing

Financing

Note 6— Financing

On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. The delayed settlement of both series of bonds occurred on May 30, 2013. Interest is payable semi-annually on the bonds on each May 30 and November 30, commencing November 30, 2013. 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 bonds have not been registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage. 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. 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.

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

We have an unsecured revolving credit facility of $150 million in place through January 17, 2017. The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of September 30, 2013, we are in compliance with these ratios. Our total indebtedness is 50.0% of our total capitalization as of September 30, 2013 and our EBITDA is 5.0 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement and no outstanding commercial paper at September 30, 2013.

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Risk Management and Derivative Financial Instruments

9 Months Ended

Sep. 30, 2013

Risk Management and Derivative Financial Instruments

Risk Management and Derivative Financial Instruments

Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. 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 predictability. 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 with the unrealized losses or gains from derivatives used to hedge our fuel costs in our electric segment 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 regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

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 instrument 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 clause.

As of September 30, 2013 and December 31, 2012, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

ASSET DERIVATIVES		September 30,		December 31,
Non-designated hedging		2013		2012
instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	11	$	3
	Non-current assets and deferred charges - other	—		17
Natural gas contracts, electric segment	Current assets	322		93
	Non-current assets and deferred charges	—		174
Total derivatives assets		$	333	$	287

		September 30,		December 31,
LIABILITY DERIVATIVES		2013		2012
Non-designated as hedging instruments due to regulatory accounting
Natural gas contracts, gas segment	Current liabilities	$	22	$	104
	Non-current liabilities and deferred credits	—		—
Natural gas contracts, electric segment	Current liabilities	3,056		3,299
	Non-current liabilities and deferred credits	3,089		3,819
Total derivatives liabilities		$	6,167	$	7,222

Electric

At September 30, 2013, approximately $3.1 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months.

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 periods ended September 30, (in thousands):

Non-Designated Hedging	Balance Sheet
Instruments - Due to	Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Regulatory Accounting	Gain / (Loss) on	Three Months Ended					Nine Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2013			2012		2013			2012			2013			2012
Commodity contracts	Regulatory (assets)/liabilities	$	(1,346	)	$	1,776	$	(1,778	)	$	(52	)	$	(4,174	)	$	(4,259	)
Total Electric Segment		$	(1,346	)	$	1,776	$	(1,778	)	$	(52	)	$	(4,174	)	$	(4,259	)

	Statement of
Non-Designated Hedging	Income
Instruments - Due to	Classification of	Amount of Gain / (Loss) Recognized in Income on Derivative
Regulatory Accounting	Gain / (Loss) on	Three Months Ended						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2013			2012			2013			2012			2013			2012
Commodity contracts	Fuel and purchased power expense	$	(1,951	)	$	(2,683	)	$	(2,472	)	$	(2,624	)	$	(3,833	)	$	(3,498	)
Total Electric Segment		$	(1,951	)	$	(2,683	)	$	(2,472	)	$	(2,624	)	$	(3,833	)	$	(3,498	)

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.

As of September 30, 2013, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2013 and for the next four years are shown below at the following average prices per Dekatherm (Dth).

Dth Hedged

Year	% Hedged		Physical	Financial	Average Price
Remainder 2013	14	%	420,000	410,000	$	5.62
2014	49	%	460,000	4,640,000	$	4.57
2015	41	%	—	4,010,000	$	4.58
2016	21	%	—	2,100,000	$	4.42
2017	10	%	—	1,050,000	$	4.43

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. These guidelines do not reflect any changes that might occur as a result of the implementation of the SPP Day-Ahead Market in 2014.

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

Gas

We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of September 30, 2013, we had 1.7 million Dths in storage on the three pipelines that serve our customers. This represents 83% 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 Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of September 30, 2013 (in thousands).

Season	Minimum % Hedged	Dth Hedged Financial	Dth Hedged Physical	Dth in Storage	Actual % Hedged
Current	50%	220,000	127,721	1,671,231	63	%
Second	Up to 50%	—	—	—
Third	Up to 20%	—	—	—

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 each of the periods ended September 30, (in thousands).

	Balance Sheet
Non-Designated Hedging	Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain / (Loss) on	Three Months Ended					Nine Months Ended						Twelve Months Ended
Accounting - Gas Segment	Derivative	2013			2012		2013			2012			2013			2012
Commodity contracts	Regulatory (assets)/liabilities	$	(27	)	$	106	$	(45	)	$	(384	)	$	(122	)	$	(1,458	)
Total - Gas Segment		$	(27	)	$	106	$	(45	)	$	(384	)	$	(122	)	$	(1,458	)

Contingent Features

Certain of our derivative instruments contain provisions that require our senior unsecured debt to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position on September 30, 2013 is $0.4 million for which we have posted no collateral in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2013, we would have been required to post $0.4 million of collateral with one of our counterparties. 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 September 30, 2013 and December 31, 2012. There were no margin deposit liabilities at these dates.

(in millions)	September 30, 2013		December 31, 2012
Margin deposit assets	$	5.8	$	4.2

Offsetting of derivative assets and liabilities

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, 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 periods ended September 30, 2013 and December 31, 2012, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

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Stock-Based Awards and Programs (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Stock-Based Awards and Programs
Unrecognized Compensation Expense	$ 700,000		$ 700,000		$ 700,000
Compensation Expense	363,000	431,000	2,057,000	1,629,000	2,305,000	2,077,000
Tax Benefit Recognized	$ 127,000	$ 148,000	$ 743,000	$ 575,000	$ 821,000	$ 730,000
Time-Vested Restricted Stock Awards
Assumptions used for estimating fair value of grants outstanding
Vesting period			3 years
Period from the date of termination of employment due to death, retirement or disability during which the pro-rata portion of the awards are distributed			6 months

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Regulatory Matters (Details) (USD $)	9 Months Ended	12 Months Ended	0 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Feb. 27, 2013 Missouri Public Service Commission (MPSC) Missouri 2012 Rate Case	Sep. 30, 2013 Missouri Public Service Commission (MPSC) Missouri 2012 Rate Case	Sep. 30, 2013 Missouri Public Service Commission (MPSC) Missouri 2012 Rate Case Iatan 2	Feb. 27, 2013 Missouri Public Service Commission (MPSC) Electric Missouri 2012 Rate Case
RATE MATTERS
Approved amount of annual increase in base rate						$ 27,500,000
Deferred tornado costs recovery period			10 years
Write-off of various items including disallowance for the prudency of certain construction expenditures				3,600,000
Write-off of various items	2,409,000	2,409,000			2,400,000
Reverse gain on sale of Asbury unit train	$ 1,236,000	$ 1,236,000		$ 1,200,000

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Risk Management and Derivative Financial Instruments (Details 3) (Electric)	9 Months Ended
	Sep. 30, 2013 Dth
Natural Gas Usage - Remainder 2013
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	14.00%
Physical	420,000
Financial	410,000
Average Price (in dollars per dth)	5.62
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	14.00%
Natural Gas Usage - 2014
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	49.00%
Physical	460,000
Financial	4,640,000
Average Price (in dollars per dth)	4.57
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	49.00%
Natural Gas Usage - 2015
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	41.00%
Financial	4,010,000
Average Price (in dollars per dth)	4.58
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	41.00%
Natural Gas Usage - 2016
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	21.00%
Financial	2,100,000
Average Price (in dollars per dth)	4.42
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	21.00%
Natural Gas Usage - 2017
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Financial	1,050,000
Average Price (in dollars per dth)	4.43
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	10.00%
Current Year Procurement Guidelines
Procurement guidelines
Maximum flexibility to hedge any future year's expected requirements (as a percent)	80.00%
Maximum percentage of volume to be hedged in any given month	100.00%
First Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	60.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	60.00%
Second Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	40.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	40.00%
Third Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	20.00%
Fourth Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	10.00%
Maximum | Current Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	100.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged	100.00%

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Financing (Details 2) (USD $)	9 Months Ended
	Sep. 30, 2013 item
Unsecured revolving credit facility
SHORT-TERM BORROWINGS
Unsecured revolving credit facility	$ 150,000,000
Maximum percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement	0.625
Minimum interest coverage ratio based on EBITDA under the financial covenants of the credit facility agreement	2
Number of trailing fiscal quarters used for calculating the interest coverage ratio based on EBITDA under the financial covenants of the credit facility agreement	4
Total indebtedness as a percent of total capitalization	50.00%
EBITDA coverage ratio over interest charges	5.0
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.	10,000,000
Outstanding borrowings	0
Commercial paper
SHORT-TERM BORROWINGS
Outstanding borrowings	$ 0

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Plant and property, at original cost:
Electric	$ 2,207,736	$ 2,176,188
Gas	72,127	69,851
Other	39,095	37,983
Construction work in progress	129,219	56,347
Total plant and property, Gross	2,448,177	2,340,369
Accumulated depreciation and amortization	718,492	682,737
Total plant and property, Net	1,729,685	1,657,632
Current assets:
Cash and cash equivalents	16,383	3,375
Restricted cash	1,773	4,357
Accounts receivable - trade, net of allowance $988 and $1,388, respectively	51,485	38,874
Accrued unbilled revenues	16,335	23,254
Accounts receivable - other	14,900	13,277
Fuel, materials and supplies	53,050	61,870
Prepaid expenses and other	20,360	21,806
Unrealized gain in fair value of derivative contracts	333	96
Regulatory assets	6,398	6,377
Total current assets	181,017	173,286
Noncurrent assets and deferred charges:
Regulatory assets	231,950	243,958
Goodwill	39,492	39,492
Unamortized debt issuance costs	8,722	7,606
Unrealized gain in fair value of derivative contracts		191
Other	4,942	4,204
Total noncurrent assets and deferred charges	285,106	295,451
Total Assets	2,195,808	2,126,369
Capitalization and Liabilities
Common stock, $1 par value, 42,939,207 and 42,484,363 shares issued and outstanding, respectively	42,939	42,484
Capital in excess of par value	637,003	628,199
Retained earnings	63,350	47,115
Total common stockholders' equity	743,292	717,798
Long-term debt (net of current portion):
Obligations under capital lease	4,237	4,441
First mortgage bonds and secured debt	637,569	487,541
Unsecured debt	101,680	199,644
Total long-term debt	743,486	691,626
Total long-term debt and common stockholders' equity	1,486,778	1,409,424
Current liabilities:
Accounts payable and accrued liabilities	55,281	66,559
Current maturities of long-term debt	327	714
Short-term debt		24,000
Regulatory liabilities	4,295	6,303
Customer deposits	12,518	12,001
Interest accrued	13,766	5,902
Other current liabilities	1,894
Unrealized loss in fair value of derivative contracts	3,078	3,403
Taxes accrued	16,781	2,992
Total current liabilities	107,940	121,874
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	134,531	131,055
Deferred income taxes	320,042	301,967
Unamortized investment tax credits	18,708	18,897
Pension and other postretirement benefit obligations	107,299	120,808
Unrealized loss in fair value of derivative contracts	3,089	3,819
Other	17,421	18,525
Total noncurrent liabilities and deferred credits	601,090	595,071
Total Capitalization and Liabilities	$ 2,195,808	$ 2,126,369

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Stock-Based Awards and Programs

9 Months Ended

Sep. 30, 2013

Stock-Based Awards and Programs

Stock-Based Awards and Programs

Note 9— Stock-Based Awards and Programs

Our performance-based restricted stock awards, stock options and their related dividend equivalents and time-vested restricted stock awards 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. Grants were made in the first quarter of 2013 (the effect of which is included in the table below) but did not have a material impact on our results of operations. We had unrecognized compensation expense of $0.7 million as of September 30, 2013.

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended September 30 (in thousands):

	Three Months Ended				Nine Months Ended				Twelve Months Ended
	2013		2012		2013		2012		2013		2012
Compensation Expense	$	363	$	431	$	2,057	$	1,629	$	2,305	$	2,077
Tax Benefit Recognized	127		148		743		575		821		730

Performance-Based Restricted Stock Awards

Performance-based restricted stock awards 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) are granted to qualified individuals. We estimate the fair value of outstanding restricted stock awards using a Monte Carlo option valuation model.

Time-Vested Restricted Stock Awards

Beginning in 2011, we began granting time-vested restricted stock awards that vest after a three-year period, to qualified individuals 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.

Stock Options

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of September 30, 2013 and 2012, under a Black-Scholes methodology.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Operating activities:
Net income	$ 48,283	$ 46,054
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	53,048	55,043
Pension and other postretirement benefit costs, net of contributions	(5,458)	1,486
Deferred income taxes and unamortized investment tax credit, net	21,579	26,906
Allowance for equity funds used during construction	(2,521)	(395)
Stock compensation expense	2,334	1,893
Loss on plant disallowance	2,409
Regulatory reversal of gain on sale of assets	1,236
Non-cash loss on derivatives	169	3,074
Other		(16)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	(5,877)	496
Fuel, materials and supplies	6,652	1,300
Prepaid expenses, other current assets and deferred charges	533	(8,953)
Accounts payable and accrued liabilities	(21,708)	(14,437)
Asset retirement obligations	(363)
Interest, taxes accrued and customer deposits	22,170	19,614
Other liabilities and other deferred credits	(4,845)	4,001
Net cash provided by operating activities	117,641	136,066
Investing activities:
Capital expenditures - regulated	(107,074)	(99,036)
Capital expenditures and other investments - non-regulated	(1,290)	(2,349)
Decrease in restricted cash	2,585
Net cash used in investing activities	(105,779)	(101,385)
Financing activities:
Proceeds from first mortgage bonds, net	150,000	88,000
Long-term debt issuance costs	(1,607)	(1,066)
Proceeds from issuance of common stock, net of issuance costs	7,391	6,522
Repayment of first mortgage bonds		(88,029)
Net short-term debt repayments	(24,000)	(10,000)
Redemption of senior notes	(98,000)
Dividends	(32,048)	(31,665)
Other	(590)	(680)
Net cash provided by / (used in) financing activities	1,146	(36,918)
Net increase (decrease) in cash and cash equivalents	13,008	(2,237)
Cash and cash equivalents at beginning of period	3,375	5,408
Cash and cash equivalents at end of period	$ 16,383	$ 3,171

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating revenues:
Electric	$ 150,370	$ 152,730	$ 406,158	$ 396,546	$ 520,265	$ 514,515
Gas	4,952	4,999	33,222	26,486	46,585	39,571
Other	2,164	1,473	5,892	4,945	7,542	6,657
Total operating revenues	157,486	159,202	445,272	427,977	574,392	560,743
Operating revenue deductions:
Fuel and purchased power	44,864	48,036	132,179	138,792	172,283	183,288
Cost of natural gas sold and transported	1,191	1,251	16,229	11,601	23,262	18,384
Regulated operating expenses	26,100	24,038	79,884	70,230	104,024	93,572
Other operating expenses	805	776	2,470	2,145	3,056	2,763
Maintenance and repairs	10,674	10,972	29,764	30,893	39,315	42,261
Loss on plant disallowance			2,409		2,409
Depreciation and amortization	17,735	15,108	51,471	45,111	66,807	59,669
Provision for income taxes	14,197	15,428	28,693	28,185	34,603	33,727
Other taxes	9,024	8,311	26,309	24,166	33,402	30,722
Total operating revenue deductions	124,590	123,920	369,408	351,123	479,161	464,386
Operating income	32,896	35,282	75,864	76,854	95,231	96,357
Other income and (deductions):
Allowance for equity funds used during construction	1,128	292	2,521	395	3,273	537
Interest income	5	265	522	568	926	1,055
Benefit/(provision) for other income taxes	47	(49)	12	(251)	201	(531)
Other - non-operating expense, net	(333)	(274)	(912)	(703)	(2,119)	(1,005)
Total other income and (deductions)	847	234	2,143	9	2,281	56
Interest charges:
Long-term debt	10,102	9,950	30,243	30,242	40,194	40,896
Short-term debt		16	59	175	71	192
Allowance for borrowed funds used during construction	(606)	(243)	(1,383)	(410)	(1,754)	(470)
Other	251	251	805	802	1,091	1,050
Total interest charges	9,747	9,974	29,724	30,809	39,602	41,668
Net income	$ 23,996	$ 25,542	$ 48,283	$ 46,054	$ 57,910	$ 54,745
Weighted average number of common shares outstanding - basic (in shares)	42,869	42,345	42,715	42,197	42,644	42,141
Weighted average number of common shares outstanding - diluted (in shares)	42,898	42,374	42,737	42,220	42,665	42,163
Total earnings per weighted average share of common stock - basic and diluted (in dollars per share)	$ 0.56	$ 0.60	$ 1.13	$ 1.09	$ 1.36	$ 1.30
Dividends declared per share of common stock (in dollars per share)	$ 0.25	$ 0.25	$ 0.75	$ 0.75	$ 1.00	$ 0.75

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Regulatory Matters (Details 2) (USD $) In Thousands, unless otherwise specified			9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Current Recovery Period	Sep. 30, 2013 Cost of removal	Dec. 31, 2012 Cost of removal	Sep. 30, 2013 SWPA payment for Ozark Beach lost generation	Dec. 31, 2012 SWPA payment for Ozark Beach lost generation	Sep. 30, 2013 Income taxes	Dec. 31, 2012 Income taxes	Sep. 30, 2013 Deferred construction accounting costs - fuel	Dec. 31, 2012 Deferred construction accounting costs - fuel	Sep. 30, 2013 Unamortized gain on interest rate derivative	Dec. 31, 2012 Unamortized gain on interest rate derivative	Sep. 30, 2013 Pension and other postretirement benefits	Dec. 31, 2012 Pension and other postretirement benefits	Sep. 30, 2013 Over recovered fuel costs	Dec. 31, 2012 Over recovered fuel costs	Sep. 30, 2013 Current portion of long-term regulatory liabilities	Dec. 31, 2012 Current portion of long-term regulatory liabilities	Sep. 30, 2013 Pension and other postretirement benefits	Dec. 31, 2012 Pension and other postretirement benefits	Sep. 30, 2013 Income taxes	Dec. 31, 2012 Income taxes	Sep. 30, 2013 Deferred construction accounting costs	Dec. 31, 2012 Deferred construction accounting costs	Sep. 30, 2013 Unamortized loss on reacquired debt	Dec. 31, 2012 Unamortized loss on reacquired debt	Sep. 30, 2013 System reliability - vegetation management	Dec. 31, 2012 System reliability - vegetation management	Sep. 30, 2013 Storm costs	Dec. 31, 2012 Storm costs	Sep. 30, 2013 Asset retirement obligation	Dec. 31, 2012 Asset retirement obligation	Sep. 30, 2013 Customer programs	Dec. 31, 2012 Customer programs	Sep. 30, 2013 Unamortized loss on interest rate derivative	Dec. 31, 2012 Unamortized loss on interest rate derivative	Sep. 30, 2013 Deferred operating and maintenance expense	Dec. 31, 2012 Deferred operating and maintenance expense	Sep. 30, 2013 Under recovered fuel costs	Dec. 31, 2012 Under recovered fuel costs	Sep. 30, 2013 Current portion of long-term regulatory assets	Dec. 31, 2012 Current portion of long-term regulatory assets	Sep. 30, 2013 Other	Dec. 31, 2012 Other	Sep. 30, 2013 Electric Unsettled derivative losses	Dec. 31, 2012 Electric Unsettled derivative losses
Regulatory Assets:
Regulatory assets, current	$ 6,398	$ 6,377																																						$ 302	$ 2,885	$ 6,096	$ 3,492
Regulatory assets, long-term	231,950	243,958																		129,110	136,480	48,418	48,759	16,385	16,717	11,246	12,142	7,783	9,002	5,084	4,828	4,616	4,430	4,785	4,356	1,001	1,147	1,863	2,049	1,212	314	(6,096)	(3,492)	930	669	5,613	6,557
Regulatory assets, total	238,348	250,335
Period to recover costs in Missouri, Kansas and Oklahoma rates			12 months
Regulatory Liabilities:
Regulatory liabilities, current	4,295	6,303														556	3,214	3,739	3,089
Regulatory liabilities, long-term	134,531	131,055		92,058	83,368	20,105	22,242	11,736	11,972	8,047	8,156	3,414	3,541	2,377	2,007	533	2,858	(3,739)	(3,089)
Regulatory liabilities, total	$ 138,826	$ 137,358

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Stock-Based Awards and Programs (Tables)

9 Months Ended

Sep. 30, 2013

Stock-Based Awards and Programs

Schedule of compensation expense and tax benefits for stock-based awards and programs

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended September 30 (in thousands):

	Three Months Ended				Nine Months Ended				Twelve Months Ended
	2013		2012		2013		2012		2013		2012
Compensation Expense	$	363	$	431	$	2,057	$	1,629	$	2,305	$	2,077
Tax Benefit Recognized	127		148		743		575		821		730

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Taxes
Consolidated provision for income taxes	$ 14.1	$ 15.5	$ 28.7	$ 28.4	$ 34.4	$ 34.3
Consolidated effective federal and state income tax rates (as a percent)	37.10%	37.70%	37.30%	38.20%	37.30%	38.50%

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Commitments and Contingencies (Details 2) (USD $) In Millions, unless otherwise specified	1 Months Ended	9 Months Ended				0 Months Ended	9 Months Ended					9 Months Ended										0 Months Ended	1 Months Ended	9 Months Ended		1 Months Ended	9 Months Ended
	Jun. 30, 2006 Gas site	Sep. 30, 2013 Gas	Sep. 30, 2013 Permits Electric	Sep. 30, 2013 Title IV Acid Rain Program Electric T	Sep. 30, 2013 Clean Air Interstate Rule Electric MW state	Jan. 15, 2013 NAAQS Electric item	Sep. 30, 2013 NAAQS Electric ppb	Sep. 30, 2013 NAAQS Electric Minimum ppb	Jan. 06, 2010 NAAQS Electric Minimum ppb	Sep. 30, 2013 NAAQS Electric Maximum ppb	Jan. 06, 2010 NAAQS Electric Maximum ppb	Sep. 30, 2013 Power Plant Mercury And Air Toxics Rule Electric phase	Sep. 30, 2013 Power Plant Mercury And Air Toxics Rule Electric Minimum	Sep. 30, 2013 Power Plant Mercury And Air Toxics Rule Electric Maximum	Sep. 30, 2013 Surface Impoundments Electric option	Sep. 30, 2013 Surface Impoundments Electric Maximum	Sep. 30, 2013 Surface Impoundments Iatan Electric	Sep. 30, 2013 Surface Impoundments Plum point Electric	Sep. 30, 2013 Green House Gases Minimum	Sep. 30, 2013 Green House Gases Maximum	Sep. 22, 2009 Green House Gases Electric t	Apr. 13, 2012 Green House Gases Electric Minimum item	Nov. 30, 2010 Renewable Energy Electric	Sep. 30, 2013 Renewable Energy Electric MWh certificate customer	Sep. 30, 2013 Renewable Energy Electric Investor-owned utilities item	Mar. 31, 2011 National Emission Standards for Hazardous Air Pollutants Electric	Sep. 30, 2013 Compliance Plan Electric	Sep. 30, 2013 Clean Air Transport Rule Electric T
Environmental Laws And Regulations
Number of years site operating permits are valid			5 years
Expected cost of adding Carbon injection system													$ 112.0	$ 130.0
Construction costs year to date																											43.2
Construction costs project to date																											73.5
Amount of SO2 emission permitted under each SO2 allowance per affected unit (in tons)				1																								1
Minimum capacity of power plant called to reduce emission levels of SO2 and NOx (in megawatts)					25
Number of states in which fossil-fueled power plants are required to reduce emission levels of SO2 and NOx as per CAIR					28
Ratio of S02 allowances that to be utilized in beginning of 2010					2
Ratio of S02 allowances that to be utilized in beginning of 2015					2.86
Percentage of SO2 reduction from 2005 levels by 2014, required by the proposed CATR																												73.00%
Percentage of NOx reduction from 2005 levels by 2014, required by the proposed CSAPR																												54.00%
Proposed primary standard								60	60	70	70
Normal reconsideration period for ozone standards							5 years
2008 standard at which states will continue to identify and designate all non-attainment areas							75
Phase-in period for proposed standards																										3 years
Period for compliance																										4 years
Number of phases expected to reduce nationwide mercury emissions												2
Minimum emission threshold of CO2e from power generating and certain other facilities requires to report Greenhouse Gases (in metric tons)																					25,000
Particulate matter primary annual standard (in micrograms per cubic meter of air)						12
Number of comments on proposed regulation for Carbon Pollution Standards for new power plants																						2,500,000
Limit of CO2 emissions																			1,000	1,100
Percentage of ownership in a coal ash impoundment at a generating facility																	12.00%	7.52%
Number of options in the EPA proposal															2
Potential cost for construction of new landfill and conversion of existing ash handling from wet to dry system(s)																15
Minimum percentage of energy purchased through long-term Purchased Power Agreements																								15.00%
Amount of renewable energy certificates generated each year																								900,000
Represents the megawatt-hour of renewable energy per renewable energy certificate (REC)																								1
Minimum percentage of Missouri retail sales required to generate or purchase electricity in 2012																								2.00%
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2014																								5.00%
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2021																								15.00%
Number of customers who have challenged exemption from solar requirement																								2
Percentage of Missouri retail sales required to generate or purchase solar energy																								2.00%
Number of investor-owned utilities for whom complaint was lodged regarding several points of the entity's 2011 RES Compliance Report and the 2012-2014 Compliance Plan																									4
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy in 2012																							10.00%
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2016																							15.00%
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2020																							20.00%
Number of former manufactured plant sites with potential future remediation	2
Remediation costs		$ 0.2

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Long-Term Debt
Carrying amount of total long-term debt exclusive of capital leases	$ 739.3	$ 687.6
Fair market value	$ 716.5	$ 747.2

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Financing (Details) (USD $)	9 Months Ended	0 Months Ended			0 Months Ended		0 Months Ended
	Sep. 30, 2013 First mortgage bonds EDE	Jun. 15, 2013 4.50% Series due 2013	Sep. 30, 2013 4.50% Series due 2013	Sep. 30, 2013 3.73% First Mortgage Bonds due May 30, 2033	Oct. 30, 2012 3.73% First Mortgage Bonds due May 30, 2033 Issuance of debt	Sep. 30, 2013 4.32% First Mortgage Bonds due May 30, 2043	Oct. 30, 2012 4.32% First Mortgage Bonds due May 30, 2043 Issuance of debt
Financing
Interest rate, stated percentage			4.50%	3.73%		4.32%
Aggregate principal amount of debt entered into in private placement					$ 30,000,000		$ 120,000,000
Maximum principal amount outstanding at any one time	1,000,000,000
Principal amount of debt redeemed		$ 98,000,000

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Retirement Benefits

9 Months Ended

Sep. 30, 2013

Retirement Benefits

Retirement Benefits

Note 8 — Retirement Benefits

Net periodic benefit cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components and is shown for our noncontributory defined benefit pension plan, our supplemental retirement program (SERP) and other postretirement benefits (OPEB) (in thousands):

	Three months ended September 30,
	Pension Benefits						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	1,863		$	1,439		$	34		$	23		$	735		$	671
Interest cost	2,516			2,591			78			86			957			962
Expected return on plan assets	(3,107		)	(3,080		)	—			—			(1,088		)	(1,018		)
Amortization of prior service cost (1)	133			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,611			2,052			142			139			565			311
Net periodic benefit cost	$	4,016		$	3,135		$	252		$	246		$	916		$	673

	Nine months ended September 30,
	Pension Benefits						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	5,590		$	4,696		$	101		$	39		$	2,206		$	1,801
Interest cost	7,547			7,693			236			197			2,870			3,027
Expected return on plan assets	(9,321		)	(9,232		)	—			—			(3,265		)	(3,101		)
Amortization of prior service cost (1)	399			398			(6		)	(6		)	(758		)	(758		)
Amortization of net actuarial loss (1)	7,834			5,952			426			291			1,696			1,246
Net periodic benefit cost	$	12,049		$	9,507		$	757		$	521		$	2,749		$	2,215

	Twelve months ended September 30,
	Pension Benefits						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	7,156		$	6,094		$	114		$	62		$	2,806		$	2,367
Interest cost	10,111			10,295			301			243			3,879			4,123
Expected return on plan assets	(12,398		)	(12,017		)	—			—			(4,299		)	(4,140		)
Amortization of prior service cost (1)	531			532			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,818			7,325			523			334			2,112			1,687
Net periodic benefit cost	$	15,218		$	12,229		$	930		$	631		$	3,487		$	3,026

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

In accordance with our regulatory agreements, our pension funding policy is to make contributions that are at least equal to the greater of either the minimum funding requirements of ERISA or the accrued cost of the plan. We made pension contributions of approximately $16.2 million in July 2013, which are expected to satisfy our funding requirements for the year. The actual minimum funding requirements will be determined based on the results of the actuarial valuations. Our OPEB funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits.

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Risk Management and Derivative Financial Instruments (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Fair value of derivative financial instruments
Current assets	$ 333,000	$ 96,000
Total derivatives assets	333,000	287,000
Current liabilities	3,078,000	3,403,000
Non-current liabilities and deferred credits	3,089,000	3,819,000
Total derivatives liabilities	6,167,000	7,222,000
Contingent Features
Margin deposit assets	5,800,000	4,200,000
Deposit liability
Margin deposit liabilities	0	0
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Gas
Fair value of derivative financial instruments
Current assets	11,000	3,000
Non-current assets and deferred charges- other		17,000
Current liabilities	22,000	104,000
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Electric
Fair value of derivative financial instruments
Current assets	322,000	93,000
Non-current assets and deferred charges- other		174,000
Current liabilities	3,056,000	3,299,000
Non-current liabilities and deferred credits	$ 3,089,000	$ 3,819,000

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Regulated Operating Expenses (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Regulated Operating Expenses
Electric transmission and distribution expense	$ 5,530	$ 4,392	$ 16,509	$ 12,764	$ 20,828	$ 16,784
Natural gas transmission and distribution expense	681	554	1,803	1,870	2,376	2,463
Power operation expense (other than fuel)	3,942	4,129	11,953	11,232	15,766	14,898
Customer accounts and assistance expense	3,124	2,621	8,322	7,639	10,894	10,304
Employee pension expense	2,662	2,562	8,062	7,637	10,605	10,118
Employee healthcare expense	2,662	2,442	7,857	7,004	10,678	9,108
General office supplies and expense	2,997	2,530	9,589	7,805	12,560	10,445
Administrative and general expense	3,375	3,675	11,292	11,466	14,917	15,521
Allowance for uncollectible accounts	975	968	2,765	2,313	3,489	3,245
Regulatory reversal of gain on sale of assets			1,236		1,236
Miscellaneous expense	152	165	496	500	675	686
Total	$ 26,100	$ 24,038	$ 79,884	$ 70,230	$ 104,024	$ 93,572

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Segment Information

9 Months Ended

Sep. 30, 2013

Segment Information

Segment Information

Note 11— Segment Information

We operate our business as three segments:  electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The other segment consists of our fiber optics business.

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

	For the quarter ended September 30, 2013
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	150,370	$	4,952		$	2,819	$	(655	)	$	157,486
Depreciation and amortization	16,328		928			479		—			17,735
Federal and state income taxes	13,939		(369		)	580		—			14,150
Operating income	31,589		364			943		—			32,896
Interest income	1		4			—		0			5
Interest expense	9,380		973			—		0			10,353
Income from AFUDC (debt and equity)	1,722		12			—		—			1,734
Net income	23,652		(599		)	943		—			23,996
Capital Expenditures	$	45,164	$	628		$	334				$	46,126

	For the quarter ended September 30, 2012
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	152,730	$	4,999		$	1,621	$	(148	)	$	159,202
Depreciation and amortization	13,757		895			456		—			15,108
Federal and state income taxes	15,564		(232		)	145		—			15,477
Operating income	34,517		532			233		—			35,282
Interest income	261		88			2		(86		)	265
Interest expense	9,328		975			—		(86		)	10,217
Income from AFUDC (debt and equity)	532		3			—		—			535
Net income	25,705		(399		)	236		—			25,542
Capital Expenditures	$	39,794	$	783		$	715				$	41,292

	For the nine months ended September 30, 2013
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	406,158	$	33,222	$	6,844	$	(952	)	$	445,272
Depreciation and amortization	47,216		2,778		1,477		—			51,471
Federal and state income taxes	26,882		707		1,092		—			28,681
Operating income	70,097		4,004		1,763		—			75,864
Interest income	498		109		7		(92		)	522
Interest expense	28,273		2,926		—		(92		)	31,107
Income from AFUDC (debt and equity)	3,883		21		—		—			3,904
Net income	45,373		1,136		1,774		—			48,283
Capital Expenditures	$	114,734	$	2,824	$	1,276				$	118,834

	For the nine months ended September 30, 2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	396,546	$	26,486	$	5,389	$	(444	)	$	427,977
Depreciation and amortization	41,086		2,675		1,350		—			45,111
Federal and state income taxes	27,497		226		713		—			28,436
Operating income	72,594		3,120		1,140		—			76,854
Interest income	549		255		3		(239		)	568
Interest expense	28,530		2,928		—		(239		)	31,219
Income from AFUDC (debt and equity)	800		5		—		—			805
Net income	44,569		326		1,159		—			46,054
Capital Expenditures	$	103,361	$	2,352	$	2,253				$	107,966

	For the twelve months ended September 30, 2013
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	520,265	$	46,585	$	8,641	$	(1,099	)	$	574,392
Depreciation and amortization	61,441		3,702		1,664		—			66,807
Federal and state income taxes	31,651		1,269		1,482		—			34,402
Operating income	86,948		5,889		2,394		—			95,231
Interest income	895		177		10		(156		)	926
Interest expense	37,610		3,902		—		(156		)	41,356
Income from AFUDC (debt and equity)	5,002		25		—		—			5,027
Net income	53,435		2,066		2,409		—			57,910
Capital Expenditures	$	151,490	$	4,043	$	1,622				$	157,155

	For the twelve months ended September 30, 2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	514,515	$	39,571	$	7,249	$	(592	)	$	560,743
Depreciation and amortization	54,295		3,552		1,822		—			59,669
Federal and state income taxes	32,464		791		1,003		—			34,258
Operating income	89,754		4,995		1,608		—			96,357
Interest income	1,035		310		4		(294		)	1,055
Interest expense	38,525		3,906		2		(294		)	42,139
Income from AFUDC (debt and equity)	1,000		7		—		—			1,007
Net Income	51,870		1,244		1,631		—			54,745
Capital Expenditures	$	126,176	$	3,599	$	2,909				$	132,684

	As of September 30, 2013
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,085,805	$	120,608	$	30,295	$	(40,900	)	$	2,195,808

(1) Includes goodwill of $39,492 and reflects the payment of a dividend and return of capital from the EDG subsidiary to the parent in the third quarter of 2013.

	As of December 31, 2012
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,034,399	$	148,814	$	28,871	$	(85,715	)	$	2,126,369

(1) Includes goodwill of $39,492.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies

Commitments and Contingencies

Note 7— Commitments and Contingencies

Legal Proceedings

We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided 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.

A lawsuit was filed in Jasper County Circuit Court (the Court) against us by three of our residential customers, purporting to act on behalf of all Empire customers. These customers were seeking a refund of certain amounts paid for service provided by Empire between January 1, 2007, and December 13, 2007. At all times, we charged the three plaintiffs, and all of our customers, the rates approved by and on file with the MPSC from our 2006 rate case. We filed a motion asking the Court to dismiss the case. On October 1, 2013, the Missouri Supreme Court denied the plaintiff’s appeal affirming the Court’s dismissal with prejudice which finalizes the case.

Coal, Natural Gas and Transportation Contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of September 30, 2013 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
October 1, 2013 through December 31, 2013	$	10.6	$	5.7
January 1, 2014 through December 31, 2015	30.5		34.3
January 1, 2016 through December 31, 2017	22.2		22.6
January 1, 2018 and beyond	8.3		22.6

Included in the table above is an agreement with Southern Star Central Pipeline, Inc., effective April 2011, to purchase one million Dths of firm gas storage service capacity for our electric business for a period of five years, expiring April 2016. The reservation charge for this storage capacity is approximately $1.1 million annually.

In addition to the above, subsequent to September 30, 2013, we extended our transportation contract with ANR Pipeline Company, expiring on March 31, 2014, for a period of ten years, expiring on March 31, 2024. Annual costs under this contract are expected to be approximately $0.5 million, depending on volume.

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 liquidated at market price. 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 September 30, 2013, are detailed in the table above.

Purchased Power

We currently supplement our on-system 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 capacity from Plum Point. We began receiving purchased power under this agreement on September 1, 2010. 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. While it is not currently our intention to exercise this option in 2015, we will continue to evaluate this purchase option through the exercise date as well as explore other options with the purchase power agreement holder, Plum Point Energy Associates (PPEA), related to the timing of this option. Commitments under this agreement are approximately $299.6 million through August 31, 2039, the end date of the agreement.

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 (formerly Horizon Wind Energy), Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. 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. 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. Although these agreements are considered operating leases under Generally Accepted Accounting Principles (GAAP), payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations. We do not own any portion of these windfarms.

New Construction

On July 9, 2013, we signed 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. See “Environmental Matters” below for additional information about this project and associated compliance measures.

On January 16, 2012, we signed a contract with a third party vendor to complete environmental retrofits at our Asbury plant. The retrofits include the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This equipment will enable us to comply with the Mercury and Air Toxics Standard (MATS). See “Environmental Matters” below for more information and for project costs.

Leases

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

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

Environmental Matters

We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and hazardous and other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. We believe that our operations are in material compliance with present environmental laws and regulations. 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.

Electric Segment

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) and hazardous air pollutants including mercury. In the future they will include limits on greenhouse gases (GHG) such as carbon dioxide (CO2).

Permits

Under the CAA we have obtained, and renewed as necessary, site operating permits, which are valid for five years, for each of our plants. As stated above, on July 11, 2013, we received the Air Emission Source Construction Permit necessary to begin construction on the Riverton 12 Combined Cycle Conversion project.

Compliance Plan

In order to comply with forthcoming environmental regulations, Empire is taking actions to implement its compliance plan and strategy (Compliance Plan).  While the Cross State Air Pollution Rule (CSAPR — formerly the Clean Air Transport Rule, or CATR) that was set to take effect on January 1, 2012 was stayed in late December 2011 then vacated in August 2012 by the District of Columbia Circuit Court of Appeals, the Mercury Air Toxics Standard (MATS) was signed by the Environmental Protection Agency (EPA) Administrator on December 16, 2011 and became effective on April 16, 2012. MATS requires compliance by April 2015 (with flexibility for extensions for reliability reasons). Our Compliance Plan largely follows the preferred plan presented in our 2010 Integrated Resource Plan (IRP) and is further supported by our recent IRP filing. As described above under New Construction, we have begun the installation of a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant. The addition of this air quality control equipment is expected to be completed by early 2015 at a cost ranging from $112.0 million to $130.0 million, excluding AFUDC. Construction costs through September 30, 2013 were $43.2 million for 2013 and $73.5 million for the project to date, excluding AFUDC. The addition of this air quality control equipment will require the retirement of Asbury Unit 2, a steam turbine currently rated at 14 megawatts that is used for peaking purposes.

In September 2012, we completed the transition of our Riverton Units 7 and 8 from operation on coal to operating completely on natural gas. Riverton Units 7 and 8, along with Riverton Unit 9, a small combustion turbine that requires steam from Unit 7 or 8 for start-up, will 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 at a cost estimated to range from $165 million to $175 million, excluding AFUDC. This amount is included in our updated five-year capital expenditure plan disclosed in our 2013 third quarter 10-Q. Construction costs, consisting of pre-engineering and site preparation activities thus far, through September 30, 2013 were $5.3 million for 2013 and $5.9 million for the project to date, excluding AFUDC.

SO2 Emissions

The CAA regulates the amount of SO2 an affected unit can emit. Currently SO2 emissions are regulated by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). On January 1, 2012, CAIR was to have been replaced by the Cross-State Air Pollution Rule (CSAPR). But, as discussed above, CSAPR was subsequently vacated, and CAIR will remain in effect until the EPA develops a valid replacement.

On October 5, 2012, the Department of Justice, on behalf of the EPA, requested that the Court of Appeals grant a request for a re-hearing of CSAPR. On January 24, 2013, the request was denied by the Court of Appeals and on March 29, 2013, the EPA petitioned the United States Supreme Court (the Supreme Court) to review the D.C. Circuit Court’s decision. On June 24, 2013 the Supreme Court agreed to review the D.C. Circuit court’s decision with a hearing date set for December 6, 2013 and a decision expected by June 30, 2014.  In the meantime, both the Title IV Acid Rain Program and CAIR will remain in effect.

The Mercury Air Toxics Standards (MATS), discussed further below, was signed on December 16, 2011, and will affect SO2 emission rates at our facilities. In addition, the compliance date for the revised SO2 National Ambient Air Quality Standards (NAAQS) is August of 2017; this could also affect SO2 emissions at our facilities. The SO2 NAAQS is discussed in more detail below.

Title IV Acid Rain Program:

Under the Title IV Acid Rain Program, each existing affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA).  Each allowance entitles the holder to emit one ton of SO2. Covered utilities, such as Empire, must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances in excess of the annual emissions are banked for future use. In 2012, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. We estimate our Title IV Acid Rain Program SO2 allowance bank plus annual allocations will be more than our projected emissions through 2017. Long-term compliance with this program will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We expect the cost of compliance to be fully recoverable in our rates.

CAIR:

In 2005, the EPA promulgated CAIR under the CAA. 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.

In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR and remanded it back to EPA for further consideration, but also stayed its vacatur. As a result, CAIR became effective for NOx on January 1, 2009 and for SO2 on January 1, 2010 and required covered states to develop State Implementation Plans (SIPs) to comply with specific SO2 state-wide annual budgets.

SO2 allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO2 Program. For our Missouri units, beginning in 2010, CAIR required the SO2 allowances to be utilized at a 2:1 ratio and, beginning in 2015, will require the SO2 allowances to be utilized at a 2.86:1 ratio. As a result, based on current SO2 allowance usage projections, we expect to have sufficient allowances to take us through 2017.

In order to meet CAIR requirements for SO2 and NOx emissions (NOx is discussed below in more detail) and as a requirement for the air permit for Iatan 2, a Selective Catalytic Reduction system (SCR), a Flue-Gas Desulfurization (FGD) scrubber system and baghouse were installed at our jointly-owned Iatan 1 plant and a SCR was placed in service at our Asbury plant in 2008. Our jointly-owned Iatan 2 and Plum Point plants were originally constructed with the above technology.

CSAPR- formerly the Clean Air Transport Rule:

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed and supplemented, the CATR included Missouri and Kansas under both the annual and ozone season for NOx as well as the SO2 program while Arkansas remained in the ozone season NOx program only. The final CATR was released on July 7, 2011 under the name of the CSAPR, and was set to become effective January 1, 2012. However, as mentioned above, the District of Columbia Circuit Court of Appeals vacated CSAPR on August 21, 2012, and the EPA has subsequently petitioned the Supreme Court to review the D.C. Circuit Court’s decision. On June 24, 2013 the Supreme Court agreed to review the D.C. Circuit court’s decision, which is set to occur December 6, 2013. The CAIR will be in effect until a valid replacement is developed by the EPA.

When it was published, the final CSAPR required a 73% reduction in SO2 from 2005 levels by 2014. The SO2 allowances allocated under the EPA’s Title IV Acid Rain Program could not be used for compliance with CSAPR but would continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO2 allowances would be allocated under CSAPR and retired at one allowance per ton of SO2 emissions emitted. Based on current projections, we would receive more SO2 allowances than would be emitted. Long-term compliance with this Rule will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We anticipate compliance costs associated with CAIR or its subsequent replacement to be recoverable in our rates.

Mercury Air Toxics Standard (MATS):

The MATS standard was fully implemented and effective as of April 16, 2012, thus requiring compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The MATS regulation does not include allowance mechanisms. Rather, it establishes alternative standards for certain pollutants, including SO2 (as a surrogate for hydrogen chloride (HCI)), which must be met to show compliance with hazardous air pollutant limits (see additional discussion in the MATS section below).

SO2 National Ambient Air Quality Standard (NAAQS):

In June 2010, the EPA finalized a new 1-hour SO2 NAAQS which, for areas with no ambient SO2 monitor, originally required modeling to determine attainment and non-attainment areas within each state. In April 2012, the EPA announced that it is reconsidering this approach. The modeling of emission sources was to have been completed by June 2013 with compliance with the SO2 NAAQS required by August 2017. Because the EPA is reconsidering the compliance determination approach for areas without ambient SO2 monitors, the compliance time-frame may be pushed back. Draft guidance for 1-hour SO2 NAAQS has been published by the EPA to assist states as they prepare their SIP submissions. The EPA is also planning a rulemaking called the Data Requirements Rule (DRR) to address some of the 1-hour SO2 NAAQS implementation program elements. It is likely that coal-fired generating units will need scrubbers to be capable of meeting the new 1-hour SO2 NAAQS. In addition, units will be required to include SO2 emissions limits in their Title V permits or execute consent decrees to assure attainment and future compliance.

NOx Emissions

The CAA regulates the amount of NOx an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx limits. Currently, revised NOx emissions are limited by the CAIR as a result of the vacated CSPAR rule and by ozone NAAQS rules (discussed below) which were established in 1997 and in 2008.

CAIR:

The CAIR required covered states to develop SIPs to comply with specific annual NOx state-wide allowance allocation budgets. Based on existing SIPs, we had excess NOx allowances during 2012 which were banked for future use and will be sufficient for compliance through at least the end of 2017. The CAIR NOx program also was to have been replaced by the CSAPR program January 1, 2012 but because the D.C. Circuit Court vacated CSAPR and the case is being re-heard by the Supreme Court, CAIR will remain in effect until the EPA develops a valid replacement.

CSAPR:

As published, the CSAPR would have required a 54% reduction in NOx from 2005 levels by 2014. The NOx annual and ozone season allowances that were allocated and banked under CAIR could not be used for compliance under CSAPR. New allowances would have been issued under CSAPR. However, as discussed above, CSPAR was vacated by the District of Columbia Circuit Court of Appeals on August 21, 2012 and the case is set to be re-heard by the Supreme Court on December 6, 2013.

Ozone NAAQS:

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. On January 6, 2010, to protect public health, the EPA proposed to lower the primary NAAQS for ozone to a range between 60 and 70 ppb and to set a separate secondary NAAQS for ozone to protect sensitive vegetation and ecosystems.

On September 2, 2011, President Obama ordered the EPA to withdraw proposed air quality standards lowering the 2008 ozone standard pending the CAA 2013 scheduled reconsideration of the ozone NAAQS (the normal 5 year reconsideration period). States moved forward with area designations based on the 2008 75 ppb standard using 2008-2010 quality assured monitoring data. Our service territory is designated as attainment, meaning that it is in compliance with the standard.

A revised Ozone NAAQS is expected to be proposed by the EPA early 2014 and is anticipated to be between 60 and 70 ppb.

PM NAAQS:

Particulate matter (PM) is the term for particles found in the air which comes from a variety of sources. On January 15, 2013, the EPA finalized the PM 2.5 primary annual standard at 12 ug/m(3) (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 PM 2.5 ambient monitor results are below the required level. However, the proposed standards could impact future major modifications/construction projects that require a Prevention of Significant Deterioration (PSD) permit.

Mercury Air Toxics Standard (MATS)

In 2005, the EPA issued the Clean Air Mercury Rule (CAMR) under the CAA. It set limits on mercury emissions by power plants and created a market-based cap and trade system expected to reduce nationwide mercury emissions in two phases. New mercury emission limits for Phase 1 were to go into effect January 1, 2010. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR. This decision was appealed to the U.S. Supreme Court which denied the appeal on February 23, 2009.

The EPA issued Information Collection Requests (ICR) for determining the National Emission Standards for Hazardous Air Pollutants (NESHAP), including mercury, for coal and oil-fired electric steam generating units on December 24, 2009. The ICRs included our Iatan, Asbury and Riverton plants. All responses to the ICRs were submitted as required. The EPA ICRs were intended for use in developing regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of hazardous air pollutants (HAPs), including mercury. The EPA proposed the national mercury and air toxics standards (MATS) in March 2011, which became effective April 16, 2012. MATS establishes numerical emission limits to reduce emissions of heavy metals, including mercury (Hg), arsenic, chromium, and nickel, and acid gases, including HCl and hydrogen fluoride (HF). For all existing and new coal-fired electric utility steam generating units (EGUs), the proposed 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. On June 25, 2013, the startup, shutdown portion of the MATS was proposed for reconsideration in order to better define startup and shutdown periods (instances when the emission unit is on but the pollution control equipment is not in full operation) that will be excluded from emissions averaging for compliance purposes.

The MATS regulation of HAPs in combination with CSAPR is the driving regulation behind our Compliance Plan and its implementation schedule.  We expect compliance costs to be recoverable in our rates.

Greenhouse Gases

Our coal and gas plants, vehicles and other facilities, including EDG (our gas segment), emit CO2 and/or other Greenhouse Gases (GHGs) which are measured in Carbon Dioxide Equivalents (CO2e).

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually commencing in September 2011. EDE and EDG’s GHG emissions for 2011 and 2012 have been reported as required to the EPA.

On December 7, 2009, responding to a 2007 U.S. Supreme Court decision that determined that GHGs constitute “air pollutants” under the CAA, the EPA issued its final finding that GHGs threaten both the public health and the public welfare. This “endangerment” finding did not itself trigger any EPA regulations, but was a necessary predicate for the EPA to proceed with regulations to control GHGs. Since that time, a series of rules including the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule) have been issued by the EPA. Several parties have filed petitions with the EPA and lawsuits have been filed challenging these rules. On June 26, 2012, the D.C. Circuit Court issued its opinion in the principal litigation of the EPA GHG rules (Endangerment, the Tailoring Rule, GHG emission standards for light-duty vehicles, and the EPA’s rule on reconsideration of the PSD Interpretive Memorandum). The three-judge panel upheld the EPA’s interpretation of the Clean Air Act provisions as unambiguously correct. This opinion solidifies the EPA’s position that the CAA requires PSD and Title V permits for major emitters of greenhouse gases, such as Empire. Our ongoing projects are currently being evaluated for the projected increase or decrease of CO2e emissions as required by the Tailoring Rule.

As the result of an agreement to settle litigation pending in the U.S. Court of Appeals, on April 13, 2012, the EPA proposed a Carbon Pollution Standard for new power plants to limit the amount of carbon emitted by electric utility generating units (EGUs). In light of the more than 2.5 million comments received by the EPA, this standard was rescinded, and a re-proposal of standards of performance for affected fossil fuel-fired EGUs was issued on September 20, 2013 as required by President Obama. The proposed rule sets separate standards for natural gas-fired combustion turbines and for fossil fuel-fired utility boilers. Limiting CO2 output to 1,000 or 1,100 pounds per megawatt hour based on size and fuel type, the standards apply only to new EGUs. It is expected that most new natural gas-fired combined cycle units will meet the new standard. The EPA believes fossil-fuel fired boilers can meet the standard through efficient technology or some level of carbon capture and sequestration, but the high cost, technical feasibility, and long term liability of stored carbon are issues that have not been resolved and limit this option for Empire and all electric utilities.

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. In response to President Obama’s June 25, 2013 memorandum to the EPA Administrator, the EPA is engaging states and stakeholders in a process to identify approaches to establish carbon pollution standards for currently operating power plants.

President Obama’s memorandum to the EPA Administrator requested the EPA issue proposed carbon pollution standards, regulations, or guidelines for modified, reconstructed, and existing power plants by no later than June 1, 2014;  issue final standards, regulations, or guidelines, for modified, reconstructed, and existing power plants by no later than June 1, 2015; and include in the guidelines addressing existing power plants a requirement that states submit to the EPA implementation plans by no later than June 30, 2016. As of October 15, 2013, the U.S. Supreme Court agreed to review an appeals court decision that said the EPA could regulate greenhouse gas emissions from fixed sources based on a previous decision based on green house emissions from cars.

In addition, a variety of proposals have been and are likely to continue to be considered by Congress to reduce GHGs. Proposals are also being considered in the House and Senate that would delay, limit or eliminate the EPA’s authority to regulate GHGs. At this time, it is not possible to predict what legislation, if any, will ultimately emerge from Congress regarding control of GHGs.

Certain states have taken steps to develop cap and trade programs and/or other regulatory systems which may be more stringent than federal requirements. For example, Kansas is a participating member of the Midwestern Greenhouse Gas Reduction Accord (MGGRA), one purpose of which is to develop a market-based cap and trade mechanism to reduce GHG emissions. The MGGRA has announced, however, that it will not issue a CO2e regulatory system pending federal legislative developments. Missouri is not a participant in the MGGRA.

The ultimate cost of any GHG regulations cannot be determined at this time. However, we expect the cost of complying with any such regulations to be recoverable in our rates.

Water Discharges

We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received 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. The regulations became final on February 16, 2004. In accordance with these regulations, we submitted sampling and summary reports to the Kansas Department of Health and Environment (KDHE) which indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. KCP&L, who operates Iatan Unit 1, submitted the appropriate sampling and summary reports to the Missouri Department of Natural Resources (MDNR).

In 2007 the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations to the EPA. As a result, the EPA suspended the regulations and revised and signed a pre-publication proposed regulation on March 28, 2011. The EPA has secured an additional year to finalize the standards for cooling water intake structures under a modified settlement agreement. Following a recent court approved delay, the EPA is now obligated to finalize the rule by November 4, 2013. We will not know the full impact of these rules until they are finalized. If adopted in their present form, we expect regulations of Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) to have a limited impact at Riverton. The retirement of units 7 and 8 is 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 impacted by the final rule.

Surface Impoundments

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. 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. 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.

On June 21, 2010, the EPA proposed a new regulation pursuant to the Federal Resource Conservation and Recovery Act (RCRA) governing the management and storage of Coal Combustion Residuals (CCR). In the proposal, the EPA presents 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. The public comment period closed in November 2010. It is anticipated that the final regulation will be published in 2014. We expect compliance with either option as proposed 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 and Riverton Power Plants. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

On September 23, 2010 and on November 4, 2010 EPA consultants conducted on-site inspections of our Riverton and Asbury coal ash impoundments, respectively. The consultants performed a visual inspection of the impoundments to assess the structural integrity of the berms surrounding the impoundments, requested documentation related to construction of the impoundments, and reviewed recently completed engineering evaluations of the impoundments and their structural integrity. In response to the inspection comments, the recommended geotechnical studies have been completed and new flow monitoring devices and settlement monuments at both coal ash impoundments have been installed. As a result of the transition from coal to natural gas, closure of the Riverton impoundment is in progress in compliance with KDHE Bureau of Waste Management regulations. We expect to complete the closure by late 2013. The final design for additional recommendations that will improve safety for slope stability at the Asbury impoundment is under review. We have received preliminary approval by the MDNR for the site permitting of a new utility waste landfill adjacent to the Asbury plant. Additionally, the work plan for the detailed site investigation (DSI) to include geologic and hydrologic investigations has been approved by the MDNR Division of Geology and Land Survey. Construction of the new landfill is expected in 2016.

Renewable Energy

As previously discussed, we have purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas. We do not own any portion of either windfarm.  More than 15% of the energy we put into the grid comes from these long-term Purchased Power Agreements (PPAs). Through these PPAs, we generate about 900,000 renewable energy certificates (RECs) each year. A REC represents one megawatt-hour of renewable energy that has been delivered into the bulk power grid and “unbundles” the renewable attributes from the associated energy. This unbundling is important because it cannot be determined where the renewable energy is ultimately delivered once it enters the bulk power grid. As a result, RECs provide an avenue for renewable energy tracking and compliance purposes.

Missouri regulations currently require us 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 RECs, at the rate of at least 2% of retail sales in 2012, increasing to at least 5% by 2014 and ultimately to at least 15% by 2021. We are currently in compliance with this regulatory requirement. The regulations require that 2% of the renewable energy source must be solar; however, we believe we are exempted from the solar requirement. A challenge to our exemption, brought by two of our customers and Power Source Solar, Inc., was dismissed on May 31, 2011 by the Missouri Western District Court of Appeals. The plaintiffs filed in the Missouri Supreme Court for transfer of the case from the Missouri Western District to the Missouri Supreme Court. The transfer was denied. On January 30, 2013, a complaint was filed with the MPSC by Renew Missouri and others regarding several points of our 2011 RES Compliance Report and the 2012-2014 Compliance Plan. The complaint, which was lodged against four investor-owned utilities (Ameren Missouri, Kansas City Power & Light Company (KCP&L), KCP&L Greater Missouri Operations, and Empire), is currently under consideration by the MPSC. On October 3, 2013, the MPSC issued an order denying motions for summary determination of Renew Missouri and KCP&L/GMO, but granting motion for summary determination of Empire. In this order, the MPSC determined the provisions of the rule exempt Empire from the obligation to provide a detailed explanation of the calculation of the RES retail impact limit for its 2012 Plan.  By granting Empire’s motion, the MPSC unconsolidated the complaint against Empire and ordered that it would proceed independently. Items remaining under consideration from the original complaint include the qualification of Empire’s Ozark Beach facility as a hydropower renewable energy resource, the use of early RECs for compliance and Empire’s exemption from the use of solar RECs for compliance.

Renewable energy standard compliance rules were published by the MPSC on July 7, 2010.  Missouri investor-owned utilities and others initiated litigation to challenge these rules. On June 30, 2011, a Cole County Circuit Court judge ruled that portions of the MPSC rules were unlawful and unreasonable, in conflict with Missouri statute and in violation of the Missouri Constitution. Subsequent to that decision, a portion of the appeal was dropped and the entire order was stayed.  On December 27, 2011 the judge issued another order identical to the one that was stayed except that the rulings with regard to the constitutionality issue had been omitted. The MPSC appealed this decision and in November of 2012 the court dismissed lawsuits brought against the RES and affirmed the MPSC rules that were finalized in July 2010. 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 20% by 2020. In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

We have been selling the majority of our RECs and plan to continue to sell all or a portion of them in the future. As a result of these REC sales, we cannot claim the underlying energy is renewable. Once a REC has been claimed or retired, it cannot be used for any other purpose. At the end of 2012, sufficient RECs, including hydro, were retired to comply with the Missouri and Kansas requirements through the end of November 2012. Additional RECs were retired in January of 2013 to complete the process for 2012. In the future, we will continue to retain a sufficient amount of RECs to meet any current or future requirements.

Gas Segment

The acquisition of Missouri Gas in June 2006 involved the property transfer of two former manufactured gas plant (FMGP) sites owned by predecessors. Site #1 in Chillicothe, Missouri is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. No remediation of this site is expected to be required in the near term.  We have received a letter stating no further action is required from the MDNR with respect to Site #2 in Marshall, Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two FMGP sites to be minimal.

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Recently Issued and Proposed Accounting Standards

9 Months Ended

Sep. 30, 2013

Recently Issued and Proposed Accounting Standards

Recently Issued and Proposed Accounting Standards

Note 2 - Recently Issued and Proposed Accounting Standards

Balance Sheet Offsetting:  The FASB amended the guidance governing the offsetting, or netting, of assets and liabilities on the balance sheet.  Under the revised guidance, an entity is required to disclose both the gross and net information about instruments and transactions that are eligible for offset on the balance sheet, as well as instruments or transactions subject to a master netting agreement. This standard was effective for annual periods beginning after January 1, 2013.  We implemented this standard in the first quarter of 2013 and it did not have a material impact on our results of operations, financial position or liquidity.

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Risk Management and Derivative Financial Instruments (Details 4) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013 season pipeline Dth
Contingent Features
Aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position	$ 0.4
Collateral posted	0
Collateral which the entity would have been required to post with the counterparty if the credit-risk-related contingent features were triggered	$ 0.4
Gas
Price Risk Mitigation for Gas Segment
Target percentage of storage capacity utilization	95.00%
Volume of storage in pipelines that serve customers (in Dth)	1,700,000
Number of pipelines that serve customers (in units)	3
Storage capacity utilized (as a percent)	83.00%
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	2
Gas | Current Winter Season
Gas Usage Hedged By Winter Season
End of Year Minimum % Hedged	50.00%
Dth Hedged Financial	220,000,000
Dth Hedged Physical	127,721,000
Dth in Storage	1,671,231,000
Actual % Hedged	63.00%
Gas | Maximum | Second Winter Season
Gas Usage Hedged By Winter Season
End of Year Minimum % Hedged	50.00%
Gas | Maximum | Third Winter Season
Gas Usage Hedged By Winter Season
End of Year Minimum % Hedged	20.00%

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Risk Management and Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Risk Management and Derivative Financial Instruments

Schedule of fair value of derivative financial instruments, balance sheet classification

As of September 30, 2013 and December 31, 2012, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

ASSET DERIVATIVES		September 30,		December 31,
Non-designated hedging		2013		2012
instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	11	$	3
	Non-current assets and deferred charges - other	—		17
Natural gas contracts, electric segment	Current assets	322		93
	Non-current assets and deferred charges	—		174
Total derivatives assets		$	333	$	287

		September 30,		December 31,
LIABILITY DERIVATIVES		2013		2012
Non-designated as hedging instruments due to regulatory accounting
Natural gas contracts, gas segment	Current liabilities	$	22	$	104
	Non-current liabilities and deferred credits	—		—
Natural gas contracts, electric segment	Current liabilities	3,056		3,299
	Non-current liabilities and deferred credits	3,089		3,819
Total derivatives liabilities		$	6,167	$	7,222

Schedule of mark-to-market pre-tax gains/(losses) from non-designated derivative instruments - electric segment

The following tables set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended September 30, (in thousands):

Non-Designated Hedging	Balance Sheet
Instruments - Due to	Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Regulatory Accounting	Gain / (Loss) on	Three Months Ended					Nine Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2013			2012		2013			2012			2013			2012
Commodity contracts	Regulatory (assets)/liabilities	$	(1,346	)	$	1,776	$	(1,778	)	$	(52	)	$	(4,174	)	$	(4,259	)
Total Electric Segment		$	(1,346	)	$	1,776	$	(1,778	)	$	(52	)	$	(4,174	)	$	(4,259	)

	Statement of
Non-Designated Hedging	Income
Instruments - Due to	Classification of	Amount of Gain / (Loss) Recognized in Income on Derivative
Regulatory Accounting	Gain / (Loss) on	Three Months Ended						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2013			2012			2013			2012			2013			2012
Commodity contracts	Fuel and purchased power expense	$	(1,951	)	$	(2,683	)	$	(2,472	)	$	(2,624	)	$	(3,833	)	$	(3,498	)
Total Electric Segment		$	(1,951	)	$	(2,683	)	$	(2,472	)	$	(2,624	)	$	(3,833	)	$	(3,498

Schedule of volumes and percentage of anticipated volume of natural gas usage for entity's electric operations

Dth Hedged

Year	% Hedged		Physical	Financial	Average Price
Remainder 2013	14	%	420,000	410,000	$	5.62
2014	49	%	460,000	4,640,000	$	4.57
2015	41	%	—	4,010,000	$	4.58
2016	21	%	—	2,100,000	$	4.42
2017	10	%	—	1,050,000	$	4.43

Schedule of minimum percentage hedged by year in the entity's procurement guidelines

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

Schedule of minimum percentage of winter season usage hedged by year of the entity's gas operations

The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of September 30, 2013 (in thousands).

Season	Minimum % Hedged	Dth Hedged Financial	Dth Hedged Physical	Dth in Storage	Actual % Hedged
Current	50%	220,000	127,721	1,671,231	63	%
Second	Up to 50%	—	—	—
Third	Up to 20%	—	—	—

Schedule of mark-to-market pre-tax gains/(losses) from non-designated derivative instruments - gas segment

The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended September 30, (in thousands).

	Balance Sheet
Non-Designated Hedging	Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain / (Loss) on	Three Months Ended					Nine Months Ended						Twelve Months Ended
Accounting - Gas Segment	Derivative	2013			2012		2013			2012			2013			2012
Commodity contracts	Regulatory (assets)/liabilities	$	(27	)	$	106	$	(45	)	$	(384	)	$	(122	)	$	(1,458	)
Total - Gas Segment		$	(27	)	$	106	$	(45	)	$	(384	)	$	(122	)	$	(1,458	)

Schedule of margin deposit assets

(in millions)	September 30, 2013		December 31, 2012
Margin deposit assets	$	5.8	$	4.2

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Regulated Operating Expenses

9 Months Ended

Sep. 30, 2013

Regulated Operating Expenses

Regulated Operating Expenses

Note 10- Regulated Operating Expenses

The following table sets forth the major components comprising “regulated operating expenses” under “Operating Revenue Deductions” on our consolidated statements of income (in thousands) for all periods presented ended September 30:

	Three Months Ended		Three Months Ended		Nine Months Ended		Nine Months Ended		Twelve Months Ended		Twelve Months Ended
	2013		2012		2013		2012		2013		2012
Electric transmission and distribution expense	$	5,530	$	4,392	$	16,509	$	12,764	$	20,828	$	16,784
Natural gas transmission and distribution expense	681		554		1,803		1,870		2,376		2,463
Power operation expense (other than fuel)	3,942		4,129		11,953		11,232		15,766		14,898
Customer accounts and assistance expense	3,124		2,621		8,322		7,639		10,894		10,304
Employee pension expense (1)	2,662		2,562		8,062		7,637		10,605		10,118
Employee healthcare expense (1)	2,662		2,442		7,857		7,004		10,678		9,108
General office supplies and expense	2,997		2,530		9,589		7,805		12,560		10,445
Administrative and general expense	3,375		3,675		11,292		11,466		14,917		15,521
Allowance for uncollectible accounts	975		968		2,765		2,313		3,489		3,245
Regulatory reversal of gain on sale of assets	—		—		1,236		—		1,236		—
Miscellaneous expense	152		165		496		500		675		686
Total	$	26,100	$	24,038	$	79,884	$	70,230	$	104,024	$	93,572

(1) Does not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to and amortized from a regulatory asset and/or a regulatory liability for Missouri, Kansas and Oklahoma jurisdictions.

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Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2013

Retirement Benefits

Schedule of net periodic benefit cost

Net periodic benefit cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components and is shown for our noncontributory defined benefit pension plan, our supplemental retirement program (SERP) and other postretirement benefits (OPEB) (in thousands):

	Three months ended September 30,
	Pension Benefits						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	1,863		$	1,439		$	34		$	23		$	735		$	671
Interest cost	2,516			2,591			78			86			957			962
Expected return on plan assets	(3,107		)	(3,080		)	—			—			(1,088		)	(1,018		)
Amortization of prior service cost (1)	133			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,611			2,052			142			139			565			311
Net periodic benefit cost	$	4,016		$	3,135		$	252		$	246		$	916		$	673

	Nine months ended September 30,
	Pension Benefits						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	5,590		$	4,696		$	101		$	39		$	2,206		$	1,801
Interest cost	7,547			7,693			236			197			2,870			3,027
Expected return on plan assets	(9,321		)	(9,232		)	—			—			(3,265		)	(3,101		)
Amortization of prior service cost (1)	399			398			(6		)	(6		)	(758		)	(758		)
Amortization of net actuarial loss (1)	7,834			5,952			426			291			1,696			1,246
Net periodic benefit cost	$	12,049		$	9,507		$	757		$	521		$	2,749		$	2,215

	Twelve months ended September 30,
	Pension Benefits						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	7,156		$	6,094		$	114		$	62		$	2,806		$	2,367
Interest cost	10,111			10,295			301			243			3,879			4,123
Expected return on plan assets	(12,398		)	(12,017		)	—			—			(4,299		)	(4,140		)
Amortization of prior service cost (1)	531			532			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,818			7,325			523			334			2,112			1,687
Net periodic benefit cost	$	15,218		$	12,229		$	930		$	631		$	3,487		$	3,026

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

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Measurements

Schedule of assets measured at fair value using the market value approach on a recurring basis

	Fair Value Measurements at Reporting Date Using
($ in 000’s) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable  Inputs (Level 3)
				September 30, 2013
Derivative assets	$	333		$	333		$	—	$	—
Derivative liabilities	$	(6,167	)	$	(6,167	)	$	—	$	—
				December 31, 2012
Derivative assets	$	287		$	287		$	—	$	—
Derivative liabilities	$	(7,222	)	$	(7,222	)	$	—	$	—

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 31, 2013
Document and Entity Information
Entity Registrant Name	EMPIRE DISTRICT ELECTRIC CO
Entity Central Index Key	0000032689
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		42,968,104
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies

Schedule of coal, natural gas and transportation contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of September 30, 2013 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
October 1, 2013 through December 31, 2013	$	10.6	$	5.7
January 1, 2014 through December 31, 2015	30.5		34.3
January 1, 2016 through December 31, 2017	22.2		22.6
January 1, 2018 and beyond	8.3		22.6