Empire District Electric (EDE) 10-Q 8 Aug 14 2014 Q2 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Jul. 31, 2014
Document and Entity Information	'	'
Entity Registrant Name	'EMPIRE DISTRICT ELECTRIC CO	'
Entity Central Index Key	'0000032689	'
Document Type	'10-Q	'
Document Period End Date	30-Jun-14	'
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	'	43,354,196
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q2	'

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating revenues:	'	'	'	'	'	'
Electric	$140,767	$127,026	$293,856	$255,788	$574,481	$522,624
Gas	6,989	7,777	31,598	28,270	53,369	46,632
Other	2,026	1,843	4,001	3,728	8,148	6,851
Total operating revenues	149,782	136,646	329,455	287,786	635,998	576,107
Operating revenue deductions:	'	'	'	'	'	'
Fuel and purchased power	54,358	42,013	109,944	87,316	198,034	175,456
Cost of natural gas sold and transported	2,678	3,113	17,723	15,038	28,479	23,321
Regulated operating expenses	27,609	26,647	55,566	53,784	107,115	101,963
Other operating expenses	782	872	1,498	1,665	2,974	3,026
Maintenance and repairs	11,393	9,933	21,650	19,090	43,433	39,613
Loss on plant disallowance	'	'	'	2,409	'	2,409
Depreciation and amortization	18,157	17,635	36,097	33,736	71,668	64,180
Provision for income taxes	6,694	7,042	18,868	14,496	41,837	35,835
Other taxes	8,609	8,281	19,119	17,284	36,773	32,689
Total operating revenue deductions	130,280	115,536	280,465	244,818	530,313	478,492
Operating income	19,502	21,110	48,990	42,968	105,685	97,615
Other income and (deductions):	'	'	'	'	'	'
Allowance for equity funds used during construction	1,522	867	2,773	1,393	5,234	2,437
Interest income	3	10	44	517	92	1,187
Benefit/(provision) for other income taxes	45	-7	99	-35	106	105
Other - non-operating expense, net	-300	-290	-645	-579	-1,283	-2,060
Total other income and (deductions)	1,270	580	2,271	1,296	4,149	1,669
Interest charges:	'	'	'	'	'	'
Long-term debt	10,105	10,190	20,210	20,141	40,424	40,042
Short-term debt	13	12	18	59	18	87
Allowance for borrowed funds used during construction	-830	-472	-1,570	-777	-2,880	-1,392
Other	290	302	504	554	1,015	1,091
Total interest charges	9,578	10,032	19,162	19,977	38,577	39,828
Net income	$11,194	$11,658	$32,099	$24,287	$71,257	$59,456
Weighted average number of common shares outstanding - basic (in shares)	43,236	42,707	43,173	42,636	43,048	42,512
Weighted average number of common shares outstanding - diluted (in shares)	43,269	42,727	43,200	42,652	43,069	42,526
Total earnings per weighted average share of common stock - basic and diluted (in dollars per share)	$0.26	$0.27	$0.74	$0.57	'	'
Total earnings per weighted average share of common stock - basic (in dollars per share)	'	'	'	'	$1.66	$1.40
Total earnings per weighted average share of common stock - diluted (in dollars per share)	'	'	'	'	$1.65	$1.40
Dividends declared per share of common stock (in dollars per share)	$0.26	$0.25	$0.51	$0.50	$1.01	$1

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Plant and property, at original cost:	'	'
Electric	$2,253,657	$2,219,605
Natural gas	77,894	72,834
Other	41,051	39,902
Construction work in progress	184,580	152,330
Total plant and property, Gross	2,557,182	2,484,671
Accumulated depreciation and amortization	740,989	732,737
Total plant and property, Net	1,816,193	1,751,934
Current assets:	'	'
Cash and cash equivalents	2,939	3,475
Restricted cash	7,726	2,872
Accounts receivable - trade, net of allowance $944 and $1,025, respectively	48,824	50,137
Accrued unbilled revenues	19,299	26,694
Accounts receivable - other	16,238	13,101
Fuel, materials and supplies	48,800	48,811
Prepaid expenses and other	15,554	15,954
Unrealized gain in fair value of derivative contracts	9,153	2,469
Regulatory assets	10,229	7,743
Total current assets	178,762	171,256
Noncurrent assets and deferred charges:	'	'
Regulatory assets	161,389	169,333
Goodwill	39,492	39,492
Unamortized debt issuance costs	8,511	8,826
Unrealized gain in fair value of derivative contracts	39	41
Other	3,395	4,163
Total noncurrent assets and deferred charges	212,826	221,855
Total Assets	2,207,781	2,145,045
Capitalization and Liabilities	'	'
Common stock, $1 par value, 43,334,811 and 43,044,185 shares issued and outstanding, respectively	43,335	43,044
Capital in excess of par value	645,236	639,525
Retained earnings	77,626	67,554
Total common stockholders' equity	766,197	750,123
Long-term debt (net of current portion):	'	'
Obligations under capital lease	4,023	4,167
First mortgage bonds and secured debt	637,597	637,578
Unsecured debt	101,691	101,683
Total long-term debt	743,311	743,428
Total long-term debt and common stockholders' equity	1,509,508	1,493,551
Current liabilities:	'	'
Accounts payable and accrued liabilities	50,525	71,375
Current maturities of long-term debt	283	274
Short-term debt	52,500	4,000
Regulatory liabilities	11,869	5,681
Customer deposits	12,734	12,543
Interest accrued	6,592	6,352
Other current liabilities	2,894	299
Unrealized loss in fair value of derivative contracts	970	1,889
Taxes accrued	14,456	3,386
Total current liabilities	152,823	105,799
Commitments and contingencies (Note 7)	'	'
Noncurrent liabilities and deferred credits:	'	'
Regulatory liabilities	132,241	132,012
Deferred income taxes	324,663	324,266
Unamortized investment tax credits	18,474	18,431
Pension and other postretirement benefit obligations	52,206	51,405
Unrealized loss in fair value of derivative contracts	2,096	2,799
Other	15,770	16,782
Total noncurrent liabilities and deferred credits	545,450	545,695
Total Capitalization and Liabilities	$2,207,781	$2,145,045

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
CONSOLIDATED BALANCE SHEETS	'	'
Accounts receivable - trade, allowance (in dollars)	$944	$1,025
Common stock, par value (in dollars per share)	$1	$1
Common stock, shares issued	43,334,811	43,044,185
Common stock, shares outstanding	43,334,811	43,044,185

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Operating activities:	'	'
Net income	$32,099	$24,287
Adjustments to reconcile net income to cash flows from operating activities:	'	'
Depreciation and amortization including regulatory items	39,527	35,268
Pension and other postretirement benefit costs, net of contributions	5,154	7,174
Deferred income taxes and unamortized investment tax credit, net	3,513	12,096
Allowance for equity funds used during construction	-2,773	-1,393
Stock compensation expense	2,046	1,900
Loss on plant disallowance	'	2,409
Reverse gain on sale of assets	'	1,236
Non-cash (gain) on derivatives	-526	-67
Cash flows impacted by changes in:	'	'
Accounts receivable and accrued unbilled revenues	6,096	-7,140
Fuel, materials and supplies	11	8,138
Prepaid expenses, other current assets and deferred charges	-3,104	542
Accounts payable and accrued liabilities	-22,610	-20,639
Interest, taxes accrued and customer deposits	11,501	9,832
Asset retirement obligations	-1,234	'
Other liabilities and other deferred credits	-656	-2,638
Net cash provided by operating activities	69,044	71,005
Investing activities:	'	'
Capital expenditures - regulated	-94,783	-74,834
Capital expenditures and other investments - non-regulated	-784	-934
Restricted cash	-4,854	2,585
Net cash used in investing activities	-100,421	-73,183
Financing activities:	'	'
Proceeds from first mortgage bonds, net	'	150,000
Long-term debt issuance costs	'	-1,744
Redemption of senior notes	'	-98,000
Proceeds from issuance of common stock net of issuance costs	4,515	5,161
Net short-term borrowings/(repayments)	48,500	-24,000
Dividends	-22,027	-21,332
Other	-147	-432
Net cash provided by financing activities	30,841	9,653
Net increase/(decrease) in cash and cash equivalents	-536	7,475
Cash and cash equivalents at beginning of period	3,475	3,375
Cash and cash equivalents at end of period	$2,939	$10,850

Summary_of_Significant_Account

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2014
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, 2013.
	The information furnished reflects all adjustments, consisting only of normal recurring 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, 2013.

Recently_Issued_and_Proposed_A

Recently Issued and Proposed Accounting Standards	6 Months Ended
	Jun. 30, 2014
Recently Issued and Proposed Accounting Standards	'
Recently Issued and Proposed Accounting Standards	'
	Note 2 - Recently Issued and Proposed Accounting Standards
	Revenue from contracts with customers:  In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard is effective for interim and annual reporting periods beginning after December 15, 2016. We are evaluating the impact of the adoption of this standard.
	See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2013 for further information regarding recently issued and proposed accounting standards.

Regulatory_Matters

Regulatory Matters	6 Months Ended
	Jun. 30, 2014
Regulatory Matters	'
Regulatory Matters	'
	Note 3— Regulatory Matters
	The following table sets forth the components of our regulatory assets and liabilities on our consolidated balance sheets (in thousands).
	Regulatory Assets and Liabilities
		June 30, 2014			December 31, 2013
	Regulatory Assets:
	Current:
	Under recovered fuel costs	$	3,556		$	1,411
	Current portion of long-term regulatory assets	6,673			6,332
	Regulatory assets, current	10,229			7,743
	Long-term:
	Pension and other postretirement benefits(1)	65,755			70,035
	Income taxes	47,681			48,033
	Deferred construction accounting costs(2)	16,050			16,275
	Unamortized loss on reacquired debt	10,742			11,078
	Unsettled derivative losses — electric segment	3,276			4,269
	System reliability — vegetation management	5,803			7,539
	Storm costs(3)	4,565			4,911
	Asset retirement obligation	4,953			4,673
	Customer programs	5,033			4,935
	Unamortized loss on interest rate derivative	966			989
	Deferred operating and maintenance expense	1,346			2,095
	Under recovered fuel costs	1,219			—
	Current portion of long-term regulatory assets	(6,673		)	(6,332		)
	Other	673			833
	Regulatory assets, long-term	161,389			169,333
	Total Regulatory Assets	$	171,618		$	177,076
		June 30, 2014			December 31, 2013
	Regulatory Liabilities:
	Current:
	Over recovered fuel costs	$	8,596		$	2,212
	Current portion of long-term regulatory liabilities	3,273			3,469
	Regulatory liabilities, current	11,869			5,681
	Long-term:
	Costs of removal	90,043			88,469
	SWPA payment for Ozark Beach lost generation	18,034			19,405
	Income taxes	11,581			11,677
	Deferred construction accounting costs — fuel(4)	7,929			8,011
	Unamortized gain on interest rate derivative	3,286			3,371
	Pension and other postretirement benefits	2,324			2,177
	Over recovered fuel costs	2,317			2,371
	Current portion of long-term regulatory liabilities	(3,273		)	(3,469		)
	Regulatory liabilities, long-term	132,241			132,012
	Total Regulatory Liabilities	$	144,110		$	137,693
	(1)  Primarily consists of unfunded pension and other postretirement benefits (OPEB) liability. See Note 8.
	(2) Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants.
	(3)  Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $3.5 million at June 30, 2014.
	(4) Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.

Risk_Management_and_Derivative

Risk Management and Derivative Financial Instruments	6 Months Ended
	Jun. 30, 2014
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 the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain predictability. We began acquiring Transmission Congestion Rights (TCR) in 2013 in an attempt to mitigate the cost of power we purchase from the SPP Integrated Market due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.
	All derivative instruments are recognized at fair value on the balance sheet. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the Accounting Standards Codification (ASC) guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment 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 mechanism.
	As of June 30, 2014 and December 31, 2013, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):
				June 30,			December 31,
	ASSET DERIVATIVES			2014			2013
	Hedging instruments	Balance Sheet Classification		Fair Value			Fair Value
	Natural gas contracts, gas segment	Current assets		$	2		$	35
	Natural gas contracts, electric segment	Current assets		480			467
		Non-current assets and deferred charges - other		39			41
	Transmission congestion rights, electric segment(1)	Current assets		8,671			1,967
	Total derivatives assets			$	9,192		$	2,510
	(1)     We initially began acquiring transmission congestion rights during the fourth quarter of 2013. The first full year annual auction applicable to the June 1, 2014 through May 31, 2015 period occurred during the second quarter of 2014 causing an increase in derivative TCR positions.
				June 30,			December 31,
	LIABILITY DERIVATIVES			2014			2013
	Hedging instruments	Balance Sheet Classification
	Natural gas contracts, gas segment	Current liabilities		$	3		$	8
	Natural gas contracts, electric segment	Current liabilities		967			1,881
		Non-current liabilities and deferred credits		2,096			2,799
	Total derivatives liabilities			$	3,066		$	4,688
	Electric Segment
	At June 30, 2014, approximately $0.5 million of unrealized net losses are applicable to natural gas 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 June 30, (in thousands):
	Non-Designated Hedging	Balance Sheet		Amount of Gain / (Loss) Recognized on Balance Sheet
	Instruments - Due to	Classification of
	Regulatory Accounting	Gain / (Loss) on		Three Months Ended						Six Months Ended						Twelve Months Ended
	Electric Segment	Derivative		2014			2013			2014			2013			2014			2013
	Commodity contracts	Regulatory (assets)/liabilities		$	401		$	(2,852	)	$	2,159		$	(432	)	$	2,252		$	(1,052	)
	Transmission congestion rights	Regulatory (assets)/liabilities		11,024			—			11,652			—			13,619			—
	Total Electric Segment			$	11,425		$	(2,852	)	$	13,811		$	(432	)	$	15,871		$	(1,052	)
	Non-Designated Hedging	Statement of		Amount of Gain / (Loss) Recognized in Income on Derivative
	Instruments - Due to	Income
		Classification of
	Regulatory Accounting	Gain / (Loss) on		Three Months Ended						Six Months Ended						Twelve Months Ended
	Electric Segment	Derivative		2014			2013			2014			2013			2014			2013
	Commodity contracts	Fuel and purchased power expense		$	160		$	(407	)	$	915		$	(521	)	$	(1,289	)	$	(4,565	)
	Transmission congestion rights	Fuel and purchased power expense		4,422			—			5,222			—			5,303			—
	Total Electric Segment			$	4,582		$	(407	)	$	6,137		$	(521	)	$	4,014		$	(4,565	)
	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 June 30, 2014, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2014 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 2014	66	%	1,230,000		2,990,000		$	4.543
	2015	50	%	300,000		4,510,000		$	4.47
	2016	43	%	1,976,000		2,100,000		$	4.103
	2017	17	%	420,900		1,300,000		$	4.219
	2018	6	%	—		500,000		$	4.516
	We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year’s and 80% of any future year’s expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.
	Year	Minimum % Hedged
	Current	Up to 100%
	First	60%
	Second	40%
	Third	20%
	Fourth	10%
	At June 30, 2014, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP Integrated Market (dollars in thousands):
	Year	Monthly MWH Hedged		$ Value
	2014	4,354		$	8,671
	Gas Segment
	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 June 30, 2014, we had 0.8 million Dths in storage on the three pipelines that serve our customers. This represents 39% 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 June 30, 2014 (in thousands):
	Season	Minimum %		Dth Hedged		Dth Hedged		Dth in Storage		Actual % Hedged
		Hedged		Financial		Physical
Current	50%		120,000				785,809		28	%
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 June 30, (in thousands).
Non-Designated Hedging	Balance Sheet		Amount of Gain/(Loss) Recognized on Balance Sheet
	Classification of
Instruments Due to Regulatory	Gain / (Loss) on		Three Months Ended						Six Months Ended						Twelve Months Ended
Accounting - Gas Segment	Derivative		2014			2013			2014			2013			2014			2013
Commodity contracts	Regulatory (assets)/liabilities		$	(1	)	$	(71	)	$	(1	)	$	(18	)	$	137		$	12
Total - Gas Segment			$	(1	)	$	(71	)	$	(1	)	$	(18	)	$	137		$	12
Contingent Features
Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. We had no derivative instruments with the credit-risk-related contingent features in a liability position on June 30, 2014 and have posted no collateral in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at June 30, 2014 and December 31, 2013. There were no margin deposit liabilities at these dates.
(in millions)	June 30, 2014			December 31, 2013
Margin deposit assets	$	3.5		$	5.2
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. 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 June 30, 2014 and December 31, 2013, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

Fair_Value_Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2014
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.
	Our TCR positions, which are acquired on the SPP Integrated Market, are valued using the most recent monthly auction clearing prices.  Our commodity contracts are valued using the market value approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of June 30, 2014 and December 31, 2013.
		Fair Value Measurements at Reporting Date Using
	($ in 000’s)	Assets/(Liabilities)			Quoted Prices in			Significant Other		Significant
	Description	at Fair Value			Active Markets for			Observable		Unobservable
					Identical Liabilities			Inputs		Inputs
					(Level 1)			(Level 2)		(Level 3)
		June 30, 2014
	Derivative assets	$	9,192		$	521		$	8,671	$	—
	Derivative liabilities	$	(3,066	)	$	(3,066	)	$	—	$	—
		December 31, 2013
	Derivative assets	$	2,510		$	543		$	1,967	$	—
	Derivative liabilities	$	(4,688	)	$	(4,688	)	$	—	$	—
	*The only recurring measurements are derivative related.
	Other fair value considerations
	Our cash and cash equivalents approximate fair value because of the short-term nature of these instruments, and are classified as Level 1 in the fair value hierarchy. The carrying amount of our short-term debt, which is composed of Empire issued commercial paper or revolving credit borrowings, also approximates fair value because of their short-term nature. These instruments are classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions.
	The carrying amount of our total long-term debt exclusive of capital leases at June 30, 2014 was $739 million and at December 31, 2013 was $739 million. The fair market value at June 30, 2014 was approximately $767 million as compared to approximately $715 million at December 31, 2013. 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 June 30, 2014 or that will be realizable in the future.

Financing

Financing	6 Months Ended
	Jun. 30, 2014
Financing	'
Financing	'
	Note 6— Financing
	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 June 30, 2014, we are in compliance with these ratios. Our total indebtedness is 51.0% of our total capitalization as of June 30, 2014 and our EBITDA is 5.9 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 June 30, 2014, however, $52.5 million was used to back up our outstanding commercial paper.

Commitments_and_Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2014
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. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In our opinion, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.
	Coal, Natural Gas and Transportation Contracts
	The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of June 30, 2014 (in millions).
		Firm physical gas and		Coal and coal
		transportation contracts		transportation contracts
	July 1, 2014 through December 31, 2014	$	15	$	8
	January 1, 2015 through December 31, 2016	41.6		33.6
	January 1, 2017 through December 31, 2018	33.2		25.5
	January 1, 2019 and beyond	49.5		11.5
	We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be placed in storage. The firm physical gas and transportation commitments are detailed in the table above.
	We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of June 30, 2014, are detailed in the table above.
	Purchased Power
	We currently supplement our on-system (native load) generating capacity with purchases of capacity and energy from other entities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.
	The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit’s capacity. We also have a long-term (30 year) agreement for the purchase of capacity from Plum Point. Commitments under this agreement are approximately $292.4 million through August 31, 2039, the end date of the agreement. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the MPSC on July 1, 2013. 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.
	We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. 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.
	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.
	New Construction
	We have in place a contract with a third party vendor to complete environmental retrofits at our Asbury plant. The retrofits will 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). 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 June 30, 2014 were $97.4 million for the project to date, excluding AFUDC.
	We also have in place a contract with a third party vendor to complete engineering, procurement, and construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion will include the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. The Air Emission Source Construction Permit necessary for this project was issued by Kansas Department of Health and Environment on July 11, 2013. This conversion is currently scheduled to be completed in mid-2016 at a cost estimated to range from $165 million to $175 million, excluding AFUDC. This amount is included in our five-year capital expenditure plan. Construction costs, consisting of pre-engineering, site preparation activities and contract costs incurred project to date through June 30, 2014 were $42.4 million, excluding AFUDC.
	See “Environmental Matters” below for more information on both of these projects.
	Leases
	We have purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these agreements are disclosed in the Purchased Power section of this note.
	We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.
	The gross amount of assets recorded under capital leases total $5.3 million at June 30, 2014.
	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), carbon monoxide (CO), and hazardous air pollutants including mercury. In the future they will include limits on greenhouse gases (GHG) such as carbon dioxide (CO2).
	Compliance Plan
	In order to comply with current and forthcoming environmental regulations, we are taking actions to implement our compliance plan and strategy (Compliance Plan).  The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR) and its subsequent replacement rule, both regulations which we discuss further below, are the drivers behind our Compliance Plan and its implementation schedule.  The MATS require reductions in mercury, acid gases and other emissions considered hazardous air pollutants (HAPS). They became effective in April 2012 and require full compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The Cross State Air Pollution Rule (CSAPR — formerly the Clean Air Transport Rule, or CATR) was first proposed by the EPA in July 2010 as a replacement of CAIR and was set to take effect on January 1, 2012.  CSAPR was stayed by the D.C Circuit Court of Appeals in late December 2011, then vacated by court order in August 2012. On April 29, 2014, the U.S. Supreme Court (the Court) reversed the D.C Circuit Court of Appeals judgment, and remanded the case back to the D.C. Circuit Court for further proceedings consistent with the Court’s opinion. In light of the Supreme Court’s decision upholding the EPA’s approach to implementing the good neighbor provision in CSAPR, on June 26, 2014, the EPA moved to lift the stay entered in late December 2011. However, CAIR will remain in effect until proceedings become final. We anticipate compliance costs associated with the MATS and CAIR (or its subsequent replacement) regulations to be recoverable in our rates.
	Our Compliance Plan largely follows the preferred plan presented in our Integrated Resource Plan (IRP), filed in mid-2013 with the MPSC. As described above under New Construction, we are in the process of installing 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. This addition required the retirement of Asbury Unit 2, a steam turbine rated at 14 megawatts that was used for peaking purposes. Asbury Unit 2 was retired on December 31, 2013.
	In September 2012, we completed the transition of our Riverton Units 7 and 8 from operation on coal and natural gas to operation solely on natural gas. Riverton Unit 7 was permanently removed from service on June 30, 2014. Riverton Unit 8 and Riverton Unit 9, a small combustion turbine that requires steam from Unit 8 for start-up, are planned to be retired upon the conversion of Riverton Unit 12, a simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in mid-2016. Once our Asbury and Riverton projects are completed, our generating fleet aggregate emissions will be in compliance with CSAPR’s emission limits as originally proposed. However, the current version of CSAPR is likely to be revised to be consistent with the April 29, 2014 U.S. Supreme Court decision.
	See “New Construction” above for project costs for both of these projects.
	Air Emissions
	The CAA regulates the amount of NOx and SO2 an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx and SO2 limits. Currently, NOx emissions are regulated by the CAIR and National Ambient Air Quality Standard (NAAQS) rules for ozone (discussed below). SO2 emissions are currently regulated by the Title IV Acid Rain Program and the CAIR.
	CAIR:
	The CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of SO2 and/or NOx in 28 eastern states and the District of Columbia, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located. Kansas was not included in CAIR and our Riverton Plant was not affected. Arkansas, where our Plum Point Plant is located, was included for ozone season NOx but not for SO2.
	SO2 allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO2 Program. The alternate plans in our Integrated Resource Plan (IRP) assumed costs for other emissions such as SO2, NOx and mercury. In the most recent five-year business plan 2014-2018, which assumes normal operations, we do not anticipate the need to purchase any allowances for these pollutants. However, if economically beneficial, we could purchase minimal quantities of allowances in the future.
	Based on the April 29, 2014 U.S. Supreme Court decision, the current version of CSAPR (CAIR’s replacement) is likely to be revised to be consistent with the court’s opinion.
	Mercury Air Toxics Standard (MATS):
	As described above, the MATS standard became effective in April 2012, and requires compliance by April 2015 (with flexibility for extensions for reliability reasons). For all existing and new coal-fired electric utility steam generating units (EGUs), the MATS standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply. On March 28, 2013, the EPA finalized updates to certain emission limits for new power plants under the MATS. The new standards affect only new coal and oil-fired power plants that will be built in the future. The update does not change the final emission limits or other requirements for existing power plants.
	National Ambient Air Quality Standards (NAAQS):
	Under the CAA, the EPA sets NAAQS for certain emissions considered harmful to public health and the environment, including particulate matter (PM), NOx, CO, SO2, and ozone which result from fossil fuel combustion.  Our facilities are currently in compliance with all applicable NAAQS.
	In January 2013, the EPA finalized the revised PM 2.5 primary annual standard at 12 ug/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 regional ambient monitor results are below the PM 2.5 required level. However, the PM 2.5 standards could impact future major modifications/construction projects that require additional permits.
	Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. Based on the current standard, our service territory is designated as attainment, meaning that it is in compliance with the standard. A revised Ozone NAAQS is expected to be proposed by the EPA in early 2015 and the final rule is expected in November 2015.
	Greenhouse Gases (GHGs):
	As the EPA began to prepare for future regulations, GHG emissions have been reported for several years under the Mandatory GHG Reporting Rule.  EDE and EDG’s GHG emissions for each year, including 2013, have been reported to the EPA as required.
	A series of actions and decisions including the Tailoring Rule, which regulates carbon dioxide and other GHG emissions from certain stationary sources, have further set the foundation for the regulation of GHGs. However, because of the uncertainties regarding the final outcome of the GHG regulations (discussed below), the ultimate cost of compliance cannot be determined at this time. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates.
	In April 2012, the EPA proposed a Carbon Pollution Standard for new power plants to limit the amount of carbon emitted by EGUs. This standard was rescinded, and a re-proposal of standards of performance for affected fossil fuel-fired EGUs was published in January 2014. The comment period ended May 9, 2014. The proposed rule applies only to new EGUs and sets separate standards for natural gas-fired combustion turbines and for fossil fuel-fired utility boilers.  The proposal would not apply to existing units, including modifications such as those required to meet other air pollution standards which are currently being undertaken at our Asbury facility and at the Riverton facility with the conversion of simple cycle Unit 12 to combined cycle.
	On June 2, 2014, the EPA released the proposed rule for limiting carbon emissions from existing power plants. The “Clean Power Plan” requires a 30% carbon emission reduction from 2005 baseline levels by 2030 and requires fossil-fuel fired power plants across the nation, including those in Empire’s fleet, to meet state-specific goals to lower carbon levels. The EPA has identified four building block strategies to achieve the best system of emission reduction (BSER). Included in these strategies are the following:  making fossil fuel power plants more efficient; using lower-emitting sources (such as natural gas combined cycle units); using more renewables and keeping nuclear sources; and using power more efficiently. States will use the building blocks to craft their compliance plans or may work with other states in developing a regional approach to compliance, in which case additional time is given for implementation.
	The EPA is scheduled to issue the final rule for existing power plants by June 1, 2015. Each state must submit its initial plan by June 30, 2016 with additional time available by request until June 2017 for a single state or June 2018 for a multi-state approach. Currently, state and industry representatives including Empire are collaborating to evaluate future impacts of the rule as proposed by the EPA.
	Water Discharges
	We operate under the Kansas and Missouri Water Pollution Plans pursuant to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received all necessary discharge permits.
	The Riverton Units 7 and 8 and Iatan Unit 1, which utilize once-through cooling water, were affected by regulations for Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) Phase II. In 2007, the United States Court of Appeals remanded key sections of these CWA regulations to the EPA. The EPA suspended the regulations. Following a series of court approved delays, the EPA announced its final rule on May 19, 2014 but has not established an effective date of the regulation. We expect the regulations to have a limited impact at Riverton. The retirement of unit 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 affected 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.
	In June 2010, the EPA proposed to regulate coal combustion residuals (CCRs) under the Federal Resource Conservation and Recovery Act (RCRA). In the proposal, the EPA presented two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. It is anticipated that the final regulation will be published in late 2014. We expect compliance with either option to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury Power Plant. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.
	As a result of the transition from coal to natural gas fuel for Riverton Units 7 and 8, the former Riverton ash impoundment has been capped and closed. Final closure as an industrial (coal combustion waste) landfill was approved on June 30, 2014 by the Kansas Department of Health and Environment (KDHE).
	We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. Our Detailed Site Investigation (DSI) will be finalized in late 2014. Receipt of the final construction permit for the waste landfill is expected in late 2015.
	Renewable Energy
Missouri regulations currently require Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas, and Elk River Windfarm, LLC, located in Butler County, Kansas. The regulations also require that 2% of the energy from renewable energy sources must be solar; however, we are exempted by statute from that solar requirement. As noted in our Annual Report on Form 10-K for the year ended December 31, 2013, the Earth Island Institute, d/b/a Renew Missouri, and others challenged our solar exemption by filing a complaint with the MPSC. The MPSC dismissed the complaint and Renew Missouri filed a notice of appeal seeking review by the Missouri Supreme Court. The case has been briefed by the parties and is awaiting action by the Court.
Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables in 2012, increasing to 15% by 2016, and to 20% by 2020. We are currently in compliance with this regulatory requirement as a result of purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas.

Retirement_Benefits

Retirement Benefits	6 Months Ended
	Jun. 30, 2014
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 June 30,
		Pension Benefits						SERP						OPEB
		2014			2013			2014			2013			2014			2013
	Service cost	$	1,627		$	1,859		$	29		$	52		$	607		$	715
	Interest cost	2,733			2,523			87			94			1,081			922
	Expected return on plan assets	(3,322		)	(3,089		)	—			—			(1,197		)	(1,077		)
	Amortization of prior service cost (1)	105			133			(2		)	(2		)	(253		)	(253		)
	Amortization of net actuarial loss (1)	1,649			2,632			105			180			229			481
	Net periodic benefit cost	$	2,792		$	4,058		$	219		$	324		$	467		$	788
		Six months ended June 30,
		Pension Benefits						SERP						OPEB
		2014			2013			2014			2013			2014			2013
	Service cost	$	3,254		$	3,727		$	58		$	67		$	1,214		$	1,470
	Interest cost	5,467			5,031			173			157			2,161			1,913
	Expected return on plan assets	(6,644		)	(6,214		)	—			—			(2,393		)	(2,176		)
	Amortization of prior service cost (1)	209			266			(4		)	(4		)	(506		)	(505		)
	Amortization of net actuarial loss (1)	3,298			5,223			211			284			457			1,131
	Net periodic benefit cost	$	5,584		$	8,033		$	438		$	504		$	933		$	1,833
		Twelve months ended June 30,
		Pension Benefits						SERP						OPEB
		2014			2013			2014			2013			2014			2013
	Service cost	$	6,981		$	6,732		$	125		$	104		$	2,684		$	2,742
	Interest cost	10,498			10,187			330			308			4,074			3,885
	Expected return on plan assets	(12,858		)	(12,372		)	—			—			(4,569		)	(4,229		)
	Amortization of prior service cost (1)	475			531			(8		)	(8		)	(1,011		)	(1,011		)
	Amortization of net actuarial loss (1)	8,520			9,259			495			520			1,588			1,858
	Net periodic benefit cost	$	13,616		$	14,337		$	942		$	924		$	2,766		$	3,245
	(1) Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.
	We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors through trusts we have established. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service. For employees hired after June 1, 2014, retiree healthcare benefits received upon retirement will no longer be subsidized.
	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 expect to make pension contributions of approximately $12.0 million during 2014, of which we have made contributions of approximately $3.0 million as of July 15, 2014. 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. We expect to be required to fund approximately $3.0 million during 2014, of which we have made contributions of approximately $1.2 million as of July 1, 2014. The actual minimum funding requirements will be determined based on the results of the actuarial valuations.

StockBased_Awards_and_Programs

Stock-Based Awards and Programs	6 Months Ended
	Jun. 30, 2014
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 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 2014 (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 associated with issued, unvested awards of $1.3 million as of June 30, 2014.
	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 June 30 (in thousands):
		Three Months Ended						Six Months Ended					Twelve Months Ended
		2014			2013			2014			2013		2014		2013
	Compensation Expense	$	518		$	420		$	1,868		$	1,711	$	2,734	$	2,376
	Tax Benefit Recognized	187			146			690			622		997		844
	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.
	Non-vested performance-based restricted stock awards (based on target number) as of June 30, 2014 and 2013 and changes during the six months ended June 30, 2014 and 2013 were as follows:
		2014					2013
		Number		Weighted Average			Number		Weighted Average
		of shares		Grant Date Price			of shares		Grant Date Price
	Outstanding at January 1,	47,200		$	21.39		33,900		$	20.25
	Granted	27,000		$	22.4		26,300		$	21.36
	Awarded	0		$	21.84		(4,460	)	$	18.36
	Not Awarded	(10,900	)	$	21.84		(8,540	)	$	18.36
	Nonvested at June 30,	63,300		$	21.74		47,200		$	21.39
	Time-Vested Restricted Stock Awards
	Our time-vested restricted stock awards vest after a three-year period. 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.
	A summary of time vested restricted stock activity under the plan for 2013 and 2014 is presented in the table below:
		2014					2013
				Weighted					Weighted
		Number of		Average Fair			Number of		Average Fair
		shares		Market Value			shares		Market Value
	Outstanding at January 1,	24,900		$	22.68		3,300		$	20.38
	Granted	22,600		22.4			21,600		21.36
	Vested	710		24.29			—		—
	Distributed	(3,300	)	22.98
	Forfeited	(2,490	)	—			—		—
	Vested but not distributed	(710	)	—			—		—
	Outstanding at end of period	41,710		$	24.32		24,900		$	22.4
	All time-vested restricted stock awards are classified as liability instruments, which must be revalued each period until settled. The cost of the awards is generally recognized over the requisite (explicit) service period.
	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 June 30, 2014 and 2013, under a Black-Scholes methodology.
	A summary of option activity under the plan during the quarters ended June 30, 2014 and June 30, 2013 is presented below:
		2014					2013
				Weighted					Weighted
				Average					Average
		Options		Exercise Price			Options		Exercise Price
	Outstanding at January 1,	112,500		$	23.27		163,300		$	23.15
	Granted	—		—			—		—
	Exercised June 30,	67,000		$	23.98		40,200		$	21.66
	Outstanding at June 30,	45,500		$	23.81		123,100		$	23.19
	Exercisable at June 30,	45,500		$	23.81		123,100		$	23.19
	Employee Stock Purchase Plan
	Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of June 30, 2014, there were 70,838 shares available for issuance in this plan. On May 1, 2014, our shareholders approved an amended and restated ESPP to reserve an additional 750,000 shares.
		2014			2013
	Subscriptions outstanding at June 30	58,627			62,793
	Maximum subscription price(1)	$	21.43		$	19.58
	Shares of stock issued	56,942			68,099
	Stock issuance price	$	19.58		$	17.95
	(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2014 to May 31, 2015.
	Assumptions for valuation of these shares are shown in the table below.
		2014		2013
	Weighted average fair value of grants at June 30	$3.07		$2.78
	Risk-free interest rate	0.10%		0.14%
	Expected dividend yield	4.30%		4.60%
	Expected volatility	14.00%		14.00%
	Expected life in months	12		12
	Grant Date	6/2/14		6/1/13

Regulated_Operating_Expenses

Regulated Operating Expenses	6 Months Ended
	Jun. 30, 2014
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 for all periods presented ended June 30 (in thousands):
		Three		Three		Six		Six		Twelve		Twelve
		Months		Months		Months		Months		Months		Months
		Ended		Ended		Ended		Ended		Ended		Ended
		2014		2013		2014		2013		2014		2013
	Electric transmission and distribution expense	$	6,878	$	5,950	$	13,676	$	10,979	$	24,560	$	19,690
	Natural gas transmission and distribution expense	558		577		1,232		1,122		2,608		2,250
	Power operation expense (other than fuel)	4,021		4,367		8,012		8,011		15,644		15,953
	Customer accounts and assistance expense	2,884		2,619		5,720		5,198		11,701		10,391
	Employee pension expense (1)	2,602		2,757		5,228		5,399		10,565		10,505
	Employee healthcare plan (1)	2,607		2,408		4,332		5,195		9,327		10,458
	General office supplies and expense	3,185		3,163		7,376		6,592		13,635		12,093
	Administrative and general expense	3,438		3,603		7,664		7,918		14,546		15,217
	Allowance for uncollectible accounts	1,329		1,044		2,101		1,790		3,976		3,483
	Regulatory reversal of gain on sale of assets	—		—		—		1,236		—		1,236
	Miscellaneous expense	107		159		225		344		553		687
	Total	$	27,609	$	26,647	$	55,566	$	53,784	$	107,115	$	101,963
	(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.

Segment_Information

Segment Information	6 Months Ended
	Jun. 30, 2014
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 Empire District Gas Company is our wholly owned subsidiary formed to provide gas distribution service in Missouri. The other segment consists of our non-regulated businesses which is primarily our fiber optics business.
	The tables below present statement of income information, balance sheet information and capital expenditures of our business segments.
	($-000’s)	For the quarter ended June 30, 2014
	Statement of Income Information	Electric		Gas			Other		Eliminations			Total
	Revenues	$	140,767	$	6,989		$	2,346	$	(320	)	$	149,782
	Depreciation and amortization	16,791		913			453		—			18,157
	Federal and state income taxes	6,331		(90		)	408		—			6,649
	Operating income	18,185		624			693		—			19,502
	Interest income	—		7			5		(9		)	3
	Interest expense	9,454		963			—		(9		)	10,408
	Income from AFUDC (debt and equity)	2,301		51			—		—			2,352
	Net income	10,826		(295		)	663		—			11,194
	Capital Expenditures	$	44,911	$	1,249		$	382	—			$	46,542
		For the quarter ended June 30, 2013
		Electric		Gas			Other		Eliminations			Total
	($-000’s)
	Statement of Income Information
	Revenues	$	127,026	$	7,777		$	1,991	$	(148	)	$	136,646
	Depreciation and amortization	16,205		927			503		—			17,635
	Federal and state income taxes	6,948		(129		)	230		—			7,049
	Operating income	19,994		744			372		—			21,110
	Interest income	3		34			2		(29		)	10
	Interest expense	9,557		976			—		(29		)	10,504
	Income from AFUDC (debt and equity)	1,331		8			—		—			1,339
	Net income	11,498		(214		)	374		—			11,658
	Capital Expenditures	$	36,535	$	1,463		$	502	—			$	38,500
		For the six months ended June 30, 2014
		Electric		Gas			Other		Eliminations			Total
	($-000’s)
	Statement of Income Information
	Revenues	$	293,856	$	31,598		$	4,641	$	(640	)	$	329,455
	Depreciation and amortization	33,366		1,824			907		—			36,097
	Federal and state income taxes	16,578		1,358			833		—			18,769
	Operating income	43,711		3,899			1,380		—			48,990
	Interest income	32		19			8		(15		)	44
	Interest expense	18,821		1,926			—		(15		)	20,732
	Income from AFUDC (debt and equity)	4,267		76			—		—			4,343
	Net income	28,710		2,035			1,354		—			32,099
	Capital Expenditures	$	91,614	$	4,422		$	839	—			$	96,875
		For the six months ended June 30, 2013
		Electric		Gas			Other		Eliminations			Total
	($-000’s)
	Statement of Income Information
	Revenues	$	255,788	$	28,270		$	4,024	$	(296	)	$	287,786
	Depreciation and amortization	30,887		1,851			998		—			33,736
	Federal and state income taxes	12,943		1,076			512		—			14,531
	Operating income	38,509		3,639			820		—			42,968
	Interest income	497		105			7		(92		)	517
	Interest expense	18,893		1,953			—		(92		)	20,754
	Income from AFUDC (debt and equity)	2,161		9			—		—			2,170
	Net income	21,721		1,735			831		—			24,287
	Capital Expenditures	$	73,070	$	2,196		$	942	—			$	76,208
		For the twelve months ended June 30, 2014
		Electric		Gas			Other		Eliminations			Total
	($-000’s)
	Statement of Income Information
	Revenues	$	574,481	$	53,369		$	9,764	$	(1,616	)	$	635,998
	Depreciation and amortization	66,138		3,682			1,848		—			71,668
	Federal and state income taxes	38,113		1,766			1,852		—			41,731
	Operating income	96,187		6,453			3,045		—			105,685
	Interest income	71		29			9		(17		)	92
	Interest expense	37,612		3,862			—		(17		)	41,457
Income from AFUDC (debt and equity)	8,016		98			—		—			8,114
Net income	65,592		2,655			3,010		—			71,257
Capital Expenditures	$	175,445	$	6,645		$	2,285	—			$	184,375
	For the twelve months ended June 30, 2013
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	522,624	$	46,632		$	7,443	$	(592	)	$	576,107
Depreciation and amortization	58,869		3,669			1,642		—			64,180
Federal and state income taxes	33,277		1,406			1,047		—			35,730
Operating income	89,876		6,055			1,684		—			97,615
Interest income	1,155		262			13		(243		)	1,187
Interest expense	37,558		3,905			—		(243		)	41,220
Income from AFUDC (debt and equity)	3,811		18			—		—			3,829
Net Income	55,487		2,267			1,702		—			59,456
Capital Expenditures	$	149,619	$	4,198		$	2,003	—			$	155,820
	As of June 30, 2014
	Electric		Gas(1)			Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,098,131	$	122,304		$	31,965	$	(44,619	)	$	2,207,781
(1) Includes goodwill of $39,492.
	As of December 31, 2013
	Electric		Gas(1)			Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,034,234	$	123,736		$	31,306	$	(44,231	)	$	2,145,045
(1) Includes goodwill of $39,492.

Income_Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2014
Income Taxes	'
Income Taxes	'
	Note 12— Income Taxes
	The following table shows our provision for income taxes and our consolidated effective federal and state income tax rates for the applicable periods ended June 30 (dollars in millions):
		Three Months Ended						Six-Months Ended						Twelve Months Ended
		2014			2013			2014			2013			2014			2013
	Consolidated provision for income taxes	$	6.6		$	7		$	18.8		$	14.5		$	41.7		$	35.7
	Consolidated effective federal and state income tax rates	37.3		%	37.7		%	36.9		%	37.4		%	36.9		%	37.5		%
	The effective income tax rate for the three, six and twelve month periods ended June 30, 2014 is lower than comparable periods in 2013 primarily due to higher equity AFUDC income in 2014 compared with 2013.
	We do not have any unrecognized tax benefits as of June 30, 2014. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.
	In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2.  We utilized $0.7 million of these credits when preparing our 2012 tax return. We expect to utilize approximately $10.7 million of these credits on our 2013 tax return. We expect to use the remaining credits on our 2014 tax return. The tax credits will have no significant income statement impact because they will flow to our customers as we amortize the tax credits over the life of the plant.
	The American Taxpayer Relief Act of 2012 (the “Act”) was signed into law on January 2, 2013. The Act restored several expired business tax provisions, including bonus depreciation for 2013. Our 2014 tax payments are expected to be higher than 2013 due to the expiration of bonus depreciation.  However, we expect to utilize investment tax credits noted above to partially offset the 2014 payments.
	On September 13, 2013, the IRS and the Treasury Department released final regulations under Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014, and we plan to utilize the book capitalization method as allowable under the final regulations. We expect an immaterial impact to the effective tax rate based on the book capitalization method.

Recently_Issued_and_Proposed_A1

Recently Issued and Proposed Accounting Standards (Policies)	6 Months Ended
	Jun. 30, 2014
Recently Issued and Proposed Accounting Standards	'
Revenue from contracts with customers	'
	Revenue from contracts with customers:  In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard is effective for interim and annual reporting periods beginning after December 15, 2016. We are evaluating the impact of the adoption of this standard.
	See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2013 for further information regarding recently issued and proposed accounting standards.

Regulatory_Matters_Tables

Regulatory Matters (Tables)	6 Months Ended
	Jun. 30, 2014
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 sheets (in thousands).
	Regulatory Assets and Liabilities
		June 30, 2014			December 31, 2013
	Regulatory Assets:
	Current:
	Under recovered fuel costs	$	3,556		$	1,411
	Current portion of long-term regulatory assets	6,673			6,332
	Regulatory assets, current	10,229			7,743
	Long-term:
	Pension and other postretirement benefits(1)	65,755			70,035
	Income taxes	47,681			48,033
	Deferred construction accounting costs(2)	16,050			16,275
	Unamortized loss on reacquired debt	10,742			11,078
	Unsettled derivative losses — electric segment	3,276			4,269
	System reliability — vegetation management	5,803			7,539
	Storm costs(3)	4,565			4,911
	Asset retirement obligation	4,953			4,673
	Customer programs	5,033			4,935
	Unamortized loss on interest rate derivative	966			989
	Deferred operating and maintenance expense	1,346			2,095
	Under recovered fuel costs	1,219			—
	Current portion of long-term regulatory assets	(6,673		)	(6,332		)
	Other	673			833
	Regulatory assets, long-term	161,389			169,333
	Total Regulatory Assets	$	171,618		$	177,076
		June 30, 2014			December 31, 2013
	Regulatory Liabilities:
	Current:
	Over recovered fuel costs	$	8,596		$	2,212
	Current portion of long-term regulatory liabilities	3,273			3,469
	Regulatory liabilities, current	11,869			5,681
	Long-term:
	Costs of removal	90,043			88,469
	SWPA payment for Ozark Beach lost generation	18,034			19,405
	Income taxes	11,581			11,677
	Deferred construction accounting costs — fuel(4)	7,929			8,011
	Unamortized gain on interest rate derivative	3,286			3,371
	Pension and other postretirement benefits	2,324			2,177
	Over recovered fuel costs	2,317			2,371
	Current portion of long-term regulatory liabilities	(3,273		)	(3,469		)
	Regulatory liabilities, long-term	132,241			132,012
	Total Regulatory Liabilities	$	144,110		$	137,693
	(1)  Primarily consists of unfunded pension and other postretirement benefits (OPEB) liability. See Note 8.
	(2) Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants.
	(3)  Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $3.5 million at June 30, 2014.
	(4) Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.

Risk_Management_and_Derivative1

Risk Management and Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2014
Risk Management and Derivative Financial Instruments	'
Schedule of fair value of derivative financial instruments, balance sheet classification	'
	As of June 30, 2014 and December 31, 2013, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):
				June 30,			December 31,
	ASSET DERIVATIVES			2014			2013
	Hedging instruments	Balance Sheet Classification		Fair Value			Fair Value
	Natural gas contracts, gas segment	Current assets		$	2		$	35
	Natural gas contracts, electric segment	Current assets		480			467
		Non-current assets and deferred charges - other		39			41
	Transmission congestion rights, electric segment(1)	Current assets		8,671			1,967
	Total derivatives assets			$	9,192		$	2,510
	(1)     We initially began acquiring transmission congestion rights during the fourth quarter of 2013. The first full year annual auction applicable to the June 1, 2014 through May 31, 2015 period occurred during the second quarter of 2014 causing an increase in derivative TCR positions.
				June 30,			December 31,
	LIABILITY DERIVATIVES			2014			2013
	Hedging instruments	Balance Sheet Classification
	Natural gas contracts, gas segment	Current liabilities		$	3		$	8
	Natural gas contracts, electric segment	Current liabilities		967			1,881
		Non-current liabilities and deferred credits		2,096			2,799
	Total derivatives liabilities			$	3,066		$	4,688
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 June 30, (in thousands):
	Non-Designated Hedging	Balance Sheet		Amount of Gain / (Loss) Recognized on Balance Sheet
	Instruments - Due to	Classification of
	Regulatory Accounting	Gain / (Loss) on		Three Months Ended						Six Months Ended						Twelve Months Ended
	Electric Segment	Derivative		2014			2013			2014			2013			2014			2013
	Commodity contracts	Regulatory (assets)/liabilities		$	401		$	(2,852	)	$	2,159		$	(432	)	$	2,252		$	(1,052	)
	Transmission congestion rights	Regulatory (assets)/liabilities		11,024			—			11,652			—			13,619			—
	Total Electric Segment			$	11,425		$	(2,852	)	$	13,811		$	(432	)	$	15,871		$	(1,052	)
	Non-Designated Hedging	Statement of		Amount of Gain / (Loss) Recognized in Income on Derivative
	Instruments - Due to	Income
		Classification of
	Regulatory Accounting	Gain / (Loss) on		Three Months Ended						Six Months Ended						Twelve Months Ended
	Electric Segment	Derivative		2014			2013			2014			2013			2014			2013
	Commodity contracts	Fuel and purchased power expense		$	160		$	(407	)	$	915		$	(521	)	$	(1,289	)	$	(4,565	)
	Transmission congestion rights	Fuel and purchased power expense		4,422			—			5,222			—			5,303			—
	Total Electric Segment			$	4,582		$	(407	)	$	6,137		$	(521	)	$	4,014		$	(4,565	)
Schedule of volumes and percentage of anticipated volume of natural gas usage for entity's electric operations	'
	As of June 30, 2014, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2014 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 2014	66	%	1,230,000		2,990,000		$	4.543
	2015	50	%	300,000		4,510,000		$	4.47
	2016	43	%	1,976,000		2,100,000		$	4.103
	2017	17	%	420,900		1,300,000		$	4.219
	2018	6	%	—		500,000		$	4.516
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 transmission congestion rights (TCR)	'
	At June 30, 2014, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP Integrated Market (dollars in thousands):
	Year	Monthly MWH Hedged		$ Value
	2014	4,354		$	8,671
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 June 30, 2014 (in thousands):
	Season	Minimum %		Dth Hedged		Dth Hedged		Dth in Storage		Actual % Hedged
		Hedged		Financial		Physical
	Current	50%		120,000				785,809		28	%
	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 June 30, (in thousands).
	Non-Designated Hedging	Balance Sheet		Amount of Gain/(Loss) Recognized on Balance Sheet
		Classification of
	Instruments Due to Regulatory	Gain / (Loss) on		Three Months Ended						Six Months Ended						Twelve Months Ended
	Accounting - Gas Segment	Derivative		2014			2013			2014			2013			2014			2013
	Commodity contracts	Regulatory (assets)/liabilities		$	(1	)	$	(71	)	$	(1	)	$	(18	)	$	137		$	12
	Total - Gas Segment			$	(1	)	$	(71	)	$	(1	)	$	(18	)	$	137		$	12
Schedule of margin deposit assets	'
	(in millions)	June 30, 2014			December 31, 2013
	Margin deposit assets	$	3.5		$	5.2

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2014
Fair Value Measurements	'
Schedule of transmission congestion rights (TCR) and commodity contracts measured at fair value	'
		Fair Value Measurements at Reporting Date Using
	($ in 000’s)	Assets/(Liabilities)			Quoted Prices in			Significant Other		Significant
	Description	at Fair Value			Active Markets for			Observable		Unobservable
					Identical Liabilities			Inputs		Inputs
					(Level 1)			(Level 2)		(Level 3)
		June 30, 2014
	Derivative assets	$	9,192		$	521		$	8,671	$	—
	Derivative liabilities	$	(3,066	)	$	(3,066	)	$	—	$	—
		December 31, 2013
	Derivative assets	$	2,510		$	543		$	1,967	$	—
	Derivative liabilities	$	(4,688	)	$	(4,688	)	$	—	$	—
	*The only recurring measurements are derivative related.

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2014
Commitments and Contingencies	'
Schedule of physical gas, coal and transportation contracts	'
	The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of June 30, 2014 (in millions).
		Firm physical gas and		Coal and coal
		transportation contracts		transportation contracts
	July 1, 2014 through December 31, 2014	$	15	$	8
	January 1, 2015 through December 31, 2016	41.6		33.6
	January 1, 2017 through December 31, 2018	33.2		25.5
	January 1, 2019 and beyond	49.5		11.5

Retirement_Benefits_Tables

Retirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2014
Retirement Benefits	'
Schedule of net periodic benefit pension 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 June 30,
		Pension Benefits						SERP						OPEB
		2014			2013			2014			2013			2014			2013
	Service cost	$	1,627		$	1,859		$	29		$	52		$	607		$	715
	Interest cost	2,733			2,523			87			94			1,081			922
	Expected return on plan assets	(3,322		)	(3,089		)	—			—			(1,197		)	(1,077		)
	Amortization of prior service cost (1)	105			133			(2		)	(2		)	(253		)	(253		)
	Amortization of net actuarial loss (1)	1,649			2,632			105			180			229			481
	Net periodic benefit cost	$	2,792		$	4,058		$	219		$	324		$	467		$	788
		Six months ended June 30,
		Pension Benefits						SERP						OPEB
		2014			2013			2014			2013			2014			2013
	Service cost	$	3,254		$	3,727		$	58		$	67		$	1,214		$	1,470
	Interest cost	5,467			5,031			173			157			2,161			1,913
	Expected return on plan assets	(6,644		)	(6,214		)	—			—			(2,393		)	(2,176		)
	Amortization of prior service cost (1)	209			266			(4		)	(4		)	(506		)	(505		)
	Amortization of net actuarial loss (1)	3,298			5,223			211			284			457			1,131
	Net periodic benefit cost	$	5,584		$	8,033		$	438		$	504		$	933		$	1,833
		Twelve months ended June 30,
		Pension Benefits						SERP						OPEB
		2014			2013			2014			2013			2014			2013
	Service cost	$	6,981		$	6,732		$	125		$	104		$	2,684		$	2,742
	Interest cost	10,498			10,187			330			308			4,074			3,885
	Expected return on plan assets	(12,858		)	(12,372		)	—			—			(4,569		)	(4,229		)
	Amortization of prior service cost (1)	475			531			(8		)	(8		)	(1,011		)	(1,011		)
	Amortization of net actuarial loss (1)	8,520			9,259			495			520			1,588			1,858
	Net periodic benefit cost	$	13,616		$	14,337		$	942		$	924		$	2,766		$	3,245
	(1) Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.

StockBased_Awards_and_Programs1

Stock-Based Awards and Programs (Tables)	6 Months Ended
	Jun. 30, 2014
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 June 30 (in thousands):
		Three Months Ended						Six Months Ended					Twelve Months Ended
		2014			2013			2014			2013		2014		2013
	Compensation Expense	$	518		$	420		$	1,868		$	1,711	$	2,734	$	2,376
	Tax Benefit Recognized	187			146			690			622		997		844
Schedule of non-vested performance-based restricted stock awards (based on target number) and changes during the reporting period	'
	Non-vested performance-based restricted stock awards (based on target number) as of June 30, 2014 and 2013 and changes during the six months ended June 30, 2014 and 2013 were as follows:
		2014					2013
		Number		Weighted Average			Number		Weighted Average
		of shares		Grant Date Price			of shares		Grant Date Price
	Outstanding at January 1,	47,200		$	21.39		33,900		$	20.25
	Granted	27,000		$	22.4		26,300		$	21.36
	Awarded	0		$	21.84		(4,460	)	$	18.36
	Not Awarded	(10,900	)	$	21.84		(8,540	)	$	18.36
	Nonvested at June 30,	63,300		$	21.74		47,200		$	21.39
Schedule of time vested restricted stock activity	'
		2014					2013
				Weighted					Weighted
		Number of		Average Fair			Number of		Average Fair
		shares		Market Value			shares		Market Value
	Outstanding at January 1,	24,900		$	22.68		3,300		$	20.38
	Granted	22,600		22.4			21,600		21.36
	Vested	710		24.29			—		—
	Distributed	(3,300	)	22.98
	Forfeited	(2,490	)	—			—		—
	Vested but not distributed	(710	)	—			—		—
	Outstanding at end of period	41,710		$	24.32		24,900		$	22.4
Schedule of stock options activity	'
		2014					2013
				Weighted					Weighted
				Average					Average
		Options		Exercise Price			Options		Exercise Price
	Outstanding at January 1,	112,500		$	23.27		163,300		$	23.15
	Granted	—		—			—		—
	Exercised June 30,	67,000		$	23.98		40,200		$	21.66
	Outstanding at June 30,	45,500		$	23.81		123,100		$	23.19
	Exercisable at June 30,	45,500		$	23.81		123,100		$	23.19
Schedule of employee stock purchase plan	'
		2014			2013
	Subscriptions outstanding at June 30	58,627			62,793
	Maximum subscription price(1)	$	21.43		$	19.58
	Shares of stock issued	56,942			68,099
	Stock issuance price	$	19.58		$	17.95
	(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2014 to May 31, 2015.
Schedule of assumptions used in valuation of shares under employee stock purchase plan	'
		2014		2013
	Weighted average fair value of grants at June 30	$3.07		$2.78
	Risk-free interest rate	0.10%		0.14%
	Expected dividend yield	4.30%		4.60%
	Expected volatility	14.00%		14.00%
	Expected life in months	12		12
	Grant Date	6/2/14		6/1/13

Regulated_Operating_Expenses_T

Regulated Operating Expenses (Tables)	6 Months Ended
	Jun. 30, 2014
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 for all periods presented ended June 30 (in thousands):
		Three		Three		Six		Six		Twelve		Twelve
		Months		Months		Months		Months		Months		Months
		Ended		Ended		Ended		Ended		Ended		Ended
		2014		2013		2014		2013		2014		2013
	Electric transmission and distribution expense	$	6,878	$	5,950	$	13,676	$	10,979	$	24,560	$	19,690
	Natural gas transmission and distribution expense	558		577		1,232		1,122		2,608		2,250
	Power operation expense (other than fuel)	4,021		4,367		8,012		8,011		15,644		15,953
	Customer accounts and assistance expense	2,884		2,619		5,720		5,198		11,701		10,391
	Employee pension expense (1)	2,602		2,757		5,228		5,399		10,565		10,505
	Employee healthcare plan (1)	2,607		2,408		4,332		5,195		9,327		10,458
	General office supplies and expense	3,185		3,163		7,376		6,592		13,635		12,093
	Administrative and general expense	3,438		3,603		7,664		7,918		14,546		15,217
	Allowance for uncollectible accounts	1,329		1,044		2,101		1,790		3,976		3,483
	Regulatory reversal of gain on sale of assets	—		—		—		1,236		—		1,236
	Miscellaneous expense	107		159		225		344		553		687
	Total	$	27,609	$	26,647	$	55,566	$	53,784	$	107,115	$	101,963
	(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.

Segment_Information_Tables

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2014
Segment Information	'
Schedule of statement of income information, balance sheet information and capital expenditures by business segments	'
	($-000’s)	For the quarter ended June 30, 2014
	Statement of Income Information	Electric		Gas			Other		Eliminations			Total
	Revenues	$	140,767	$	6,989		$	2,346	$	(320	)	$	149,782
	Depreciation and amortization	16,791		913			453		—			18,157
	Federal and state income taxes	6,331		(90		)	408		—			6,649
	Operating income	18,185		624			693		—			19,502
	Interest income	—		7			5		(9		)	3
	Interest expense	9,454		963			—		(9		)	10,408
	Income from AFUDC (debt and equity)	2,301		51			—		—			2,352
	Net income	10,826		(295		)	663		—			11,194
	Capital Expenditures	$	44,911	$	1,249		$	382	—			$	46,542
		For the quarter ended June 30, 2013
		Electric		Gas			Other		Eliminations			Total
	($-000’s)
	Statement of Income Information
	Revenues	$	127,026	$	7,777		$	1,991	$	(148	)	$	136,646
	Depreciation and amortization	16,205		927			503		—			17,635
	Federal and state income taxes	6,948		(129		)	230		—			7,049
	Operating income	19,994		744			372		—			21,110
	Interest income	3		34			2		(29		)	10
	Interest expense	9,557		976			—		(29		)	10,504
	Income from AFUDC (debt and equity)	1,331		8			—		—			1,339
	Net income	11,498		(214		)	374		—			11,658
	Capital Expenditures	$	36,535	$	1,463		$	502	—			$	38,500
		For the six months ended June 30, 2014
		Electric		Gas			Other		Eliminations			Total
	($-000’s)
	Statement of Income Information
	Revenues	$	293,856	$	31,598		$	4,641	$	(640	)	$	329,455
	Depreciation and amortization	33,366		1,824			907		—			36,097
	Federal and state income taxes	16,578		1,358			833		—			18,769
	Operating income	43,711		3,899			1,380		—			48,990
	Interest income	32		19			8		(15		)	44
	Interest expense	18,821		1,926			—		(15		)	20,732
	Income from AFUDC (debt and equity)	4,267		76			—		—			4,343
	Net income	28,710		2,035			1,354		—			32,099
	Capital Expenditures	$	91,614	$	4,422		$	839	—			$	96,875
		For the six months ended June 30, 2013
		Electric		Gas			Other		Eliminations			Total
	($-000’s)
	Statement of Income Information
	Revenues	$	255,788	$	28,270		$	4,024	$	(296	)	$	287,786
	Depreciation and amortization	30,887		1,851			998		—			33,736
	Federal and state income taxes	12,943		1,076			512		—			14,531
	Operating income	38,509		3,639			820		—			42,968
	Interest income	497		105			7		(92		)	517
	Interest expense	18,893		1,953			—		(92		)	20,754
	Income from AFUDC (debt and equity)	2,161		9			—		—			2,170
	Net income	21,721		1,735			831		—			24,287
	Capital Expenditures	$	73,070	$	2,196		$	942	—			$	76,208
		For the twelve months ended June 30, 2014
		Electric		Gas			Other		Eliminations			Total
	($-000’s)
	Statement of Income Information
	Revenues	$	574,481	$	53,369		$	9,764	$	(1,616	)	$	635,998
	Depreciation and amortization	66,138		3,682			1,848		—			71,668
	Federal and state income taxes	38,113		1,766			1,852		—			41,731
	Operating income	96,187		6,453			3,045		—			105,685
	Interest income	71		29			9		(17		)	92
	Interest expense	37,612		3,862			—		(17		)	41,457
	Income from AFUDC (debt and equity)	8,016		98			—		—			8,114
	Net income	65,592		2,655			3,010		—			71,257
	Capital Expenditures	$	175,445	$	6,645		$	2,285	—			$	184,375
	For the twelve months ended June 30, 2013
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	522,624	$	46,632		$	7,443	$	(592	)	$	576,107
Depreciation and amortization	58,869		3,669			1,642		—			64,180
Federal and state income taxes	33,277		1,406			1,047		—			35,730
Operating income	89,876		6,055			1,684		—			97,615
Interest income	1,155		262			13		(243		)	1,187
Interest expense	37,558		3,905			—		(243		)	41,220
Income from AFUDC (debt and equity)	3,811		18			—		—			3,829
Net Income	55,487		2,267			1,702		—			59,456
Capital Expenditures	$	149,619	$	4,198		$	2,003	—			$	155,820
	As of June 30, 2014
	Electric		Gas(1)			Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,098,131	$	122,304		$	31,965	$	(44,619	)	$	2,207,781
(1) Includes goodwill of $39,492.
	As of December 31, 2013
	Electric		Gas(1)			Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,034,234	$	123,736		$	31,306	$	(44,231	)	$	2,145,045
(1) Includes goodwill of $39,492.

Income_Taxes_Tables

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2014
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 and our consolidated effective federal and state income tax rates for the applicable periods ended June 30 (dollars in millions):
		Three Months Ended						Six-Months Ended						Twelve Months Ended
		2014			2013			2014			2013			2014			2013
	Consolidated provision for income taxes	$	6.6		$	7		$	18.8		$	14.5		$	41.7		$	35.7
	Consolidated effective federal and state income tax rates	37.3		%	37.7		%	36.9		%	37.4		%	36.9		%	37.5		%

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Details)	6 Months Ended
	Jun. 30, 2014
	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

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Regulatory Assets:	'	'
Regulatory assets, current	$10,229	$7,743
Regulatory assets, long-term	161,389	169,333
Regulatory assets, total	171,618	177,076
Regulatory Liabilities:	'	'
Regulatory liabilities, current	11,869	5,681
Regulatory liabilities, long-term	132,241	132,012
Regulatory liabilities, total	144,110	137,693
Over recovered fuel costs	'	'
Regulatory Liabilities:	'	'
Regulatory liabilities, current	8,596	2,212
Regulatory liabilities, long-term	2,317	2,371
Current portion of long-term regulatory liabilities	'	'
Regulatory Liabilities:	'	'
Regulatory liabilities, current	3,273	3,469
Regulatory liabilities, long-term	-3,273	-3,469
Cost of removal	'	'
Regulatory Liabilities:	'	'
Regulatory liabilities, long-term	90,043	88,469
SWPA payment for Ozark Beach lost generation	'	'
Regulatory Liabilities:	'	'
Regulatory liabilities, long-term	18,034	19,405
Deferred construction accounting costs - fuel	'	'
Regulatory Liabilities:	'	'
Regulatory liabilities, long-term	7,929	8,011
Unamortized gain on interest rate derivative	'	'
Regulatory Liabilities:	'	'
Regulatory liabilities, long-term	3,286	3,371
Under recovered fuel costs	'	'
Regulatory Assets:	'	'
Regulatory assets, current	3,556	1,411
Regulatory assets, long-term	1,219	'
Current portion of long-term regulatory assets	'	'
Regulatory Assets:	'	'
Regulatory assets, current	6,673	6,332
Regulatory assets, long-term	-6,673	-6,332
Pension and other postretirement benefits	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	65,755	70,035
Regulatory Liabilities:	'	'
Regulatory liabilities, long-term	2,324	2,177
Income taxes	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	47,681	48,033
Regulatory Liabilities:	'	'
Regulatory liabilities, long-term	11,581	11,677
Deferred construction accounting costs	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	16,050	16,275
Unamortized loss on reacquired debt	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	10,742	11,078
System reliability - vegetation management	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	5,803	7,539
Storm costs	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	4,565	4,911
Asset retirement obligation	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	4,953	4,673
Customer programs	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	5,033	4,935
Unamortized loss on interest rate derivative	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	966	989
Deferred operating and maintenance expense	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	1,346	2,095
Other	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	673	833
Ice storm and tornado cost	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	3,500	'
Electric | Unsettled derivative losses	'	'
Regulatory Assets:	'	'
Regulatory assets, long-term	$3,276	$4,269

Risk_Management_and_Derivative2

Risk Management and Derivative Financial Instruments (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair value of derivative financial instruments	'	'
Current assets	$9,153	$2,469
Total derivatives assets	9,192	2,510
Current liabilities	970	1,889
Non-current liabilities and deferred credits	2,096	2,799
Total derivatives liabilities	3,066	4,688
Hedging instruments | Commodity contracts | Gas	'	'
Fair value of derivative financial instruments	'	'
Current assets	2	35
Current liabilities	3	8
Hedging instruments | Commodity contracts | Electric	'	'
Fair value of derivative financial instruments	'	'
Current assets	480	467
Non-current assets and deferred charges- other	39	41
Current liabilities	967	1,881
Non-current liabilities and deferred credits	2,096	2,799
Hedging instruments | Transmission congestion rights (TCR) | Electric	'	'
Fair value of derivative financial instruments	'	'
Current assets	$8,671	$1,967

Risk_Management_and_Derivative3

Risk Management and Derivative Financial Instruments (Details 2) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Electric Segment	'	'	'	'	'	'
Gain / (Loss) on derivatives	'	'	'	'	'	'
Unrealized net losses applicable to financial instruments which will settle in next twelve months	$500,000	'	$500,000	'	$500,000	'
Period within which financial instruments will settle	'	'	'12 months	'	'	'
Amount of Gain/(Loss) Recognized on Balance Sheet	11,425,000	-2,852,000	13,811,000	-432,000	15,871,000	-1,052,000
Amount of Gain / (Loss) Recognized in Income on Derivative	4,582,000	-407,000	6,137,000	-521,000	4,014,000	-4,565,000
Gas	'	'	'	'	'	'
Gain / (Loss) on derivatives	'	'	'	'	'	'
Amount of Gain/(Loss) Recognized on Balance Sheet	-1,000	-71,000	-1,000	-18,000	137,000	12,000
Commodity contracts | Electric Segment	'	'	'	'	'	'
Gain / (Loss) on derivatives	'	'	'	'	'	'
Amount of Gain/(Loss) Recognized on Balance Sheet	401,000	-2,852,000	2,159,000	-432,000	2,252,000	-1,052,000
Amount of Gain / (Loss) Recognized in Income on Derivative	160,000	-407,000	915,000	-521,000	-1,289,000	-4,565,000
Commodity contracts | Gas	'	'	'	'	'	'
Gain / (Loss) on derivatives	'	'	'	'	'	'
Amount of Gain/(Loss) Recognized on Balance Sheet	-1,000	-71,000	-1,000	-18,000	137,000	12,000
Transmission congestion rights (TCR) | Electric Segment	'	'	'	'	'	'
Gain / (Loss) on derivatives	'	'	'	'	'	'
Amount of Gain/(Loss) Recognized on Balance Sheet	11,024,000	'	11,652,000	'	13,619,000	'
Amount of Gain / (Loss) Recognized in Income on Derivative	$4,422,000	'	$5,222,000	'	$5,303,000	'

Risk_Management_and_Derivative4

Risk Management and Derivative Financial Instruments (Details 3) (Electric, USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014
	Dth
Natural Gas Usage - Remainder 2014	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	66.00%
Dth Hedged Physical	1,230,000
Dth Hedged Financial	2,990,000
Average Price (in dollars per dth)	4.543
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	66.00%
Natural Gas Usage - 2015	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	50.00%
Dth Hedged Physical	300,000
Dth Hedged Financial	4,510,000
Average Price (in dollars per dth)	4.47
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	50.00%
Natural Gas Usage - 2016	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	43.00%
Dth Hedged Physical	1,976,000
Dth Hedged Financial	2,100,000
Average Price (in dollars per dth)	4.103
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	43.00%
Natural Gas Usage - 2017	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	17.00%
Dth Hedged Physical	420,900
Dth Hedged Financial	1,300,000
Average Price (in dollars per dth)	4.219
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	17.00%
2018	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	6.00%
Dth Hedged Financial	500,000
Average Price (in dollars per dth)	4.516
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	6.00%
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%
Transmission congestion rights (TCR) - 2014	'
Minimum Percentage Hedged for Electric Segment	'
Monthly MWH Hedged	4,354,000
Monthly MWH Hedged, value	$8,671
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%

Risk_Management_and_Derivative5

Risk Management and Derivative Financial Instruments (Details 4) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014
In Millions, unless otherwise specified			Gas Segment	Gas Segment	Gas Segment	Gas Segment
			season	Current Winter Season	Maximum	Maximum
			pipeline	Dth	Second Winter Season	Third Winter Season
			Dth
Price Risk Mitigation for Gas Segment	'	'	'	'	'	'
Target percentage of storage capacity utilization	'	'	95.00%	'	'	'
Volume of storage in pipelines that serve customers (in Dth)	'	'	800,000	'	'	'
Number of pipelines that serve customers (in units)	'	'	3	'	'	'
Storage capacity utilized (as a percent)	'	'	39.00%	'	'	'
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	'	'	2	'	'	'
Gas Usage Hedged By Winter Season	'	'	'	'	'	'
End of Year Minimum % Hedged	'	'	'	50.00%	50.00%	20.00%
Dth Hedged Financial	'	'	'	120,000	'	'
Dth in Storage	'	'	'	785,809,000	'	'
Actual % Hedged	'	'	'	28.00%	'	'
Contingent Features	'	'	'	'	'	'
Derivative instruments with the credit-risk-related contingent features that are in a liability position	$0	'	'	'	'	'
Collateral posted	0	'	'	'	'	'
Margin deposit liabilities	0	0	'	'	'	'
Margin deposit assets	'	'	'	'	'	'
Margin deposit assets	$3.50	$5.20	'	'	'	'

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (Recurring basis, USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Assets/(Liabilities) at Fair Value	'	'
Fair Value Measurements at Reporting Date	'	'
Derivative assets	$9,192	$2,510
Derivative liabilities	-3,066	-4,688
Quoted Prices in Active Markets for Identical Liabilities (Level 1)	'	'
Fair Value Measurements at Reporting Date	'	'
Derivative assets	521	543
Derivative liabilities	-3,066	-4,688
Significant Other Observable Inputs (Level 2)	'	'
Fair Value Measurements at Reporting Date	'	'
Derivative assets	$8,671	$1,967

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details 2) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Long-Term Debt	'	'
Carrying amount of total long-term debt exclusive of capital leases	$739	$739
Fair market value	$767	$715

Financing_Details

Financing (Details) (USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014
	item
Unsecured revolving credit facility	'
Short-Term Borrowings	'
Unsecured revolving credit facility	$150
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 percentage of total capitalization	51.00%
EBITDA coverage ratio over interest charges	5.9
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.	10
Outstanding borrowings	0
Commercial paper	'
Short-Term Borrowings	'
Amount of credit facility used to back up outstanding commercial paper borrowings	$52.50

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Dec. 15, 2008

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Dec. 15, 2005

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

In Millions, unless otherwise specified

MW

Electric

Electric

Electric

Firm Physical gas and transportation contracts

Coal and coal transportation contracts

Purchased power

Purchased power

Purchased power

Purchased power

Purchased power

Purchased power

Purchased power

Purchased power

Purchased power

Leases

Leases

Leases

Leases

Power Plant Mercury And Air Toxics Rule

Minimum

Maximum

Plum Point Energy Station

Cloud County Windfarm

Cloud County Windfarm

Cloud County Windfarm

Cloud County Windfarm

Elk River Windfarm

Elk River Windfarm

Elk River Windfarm

Elk River Windfarm

Electric

Gas

Plum Point Energy Station

Power Plant Mercury And Air Toxics Rule

Power Plant Mercury And Air Toxics Rule

MW

MW

Minimum

Maximum

MW

Minimum

Maximum

train

office

railcar

Commitments and Contingencies

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

July 1, 2014 through December 31, 2014

'

'

'

'

$15

$8

'

'

'

'

'

'

'

'

'

'

'

'

'

January 1, 2015 through December 31, 2016

'

'

'

'

41.6

33.6

'

'

'

'

'

'

'

'

'

'

'

'

'

January 1, 2017 through December 31, 2018

'

'

'

'

33.2

25.5

'

'

'

'

'

'

'

'

'

'

'

'

'

January 1, 2019 and beyond

'

'

'

'

49.5

11.5

'

'

'

'

'

'

'

'

'

'

'

'

'

Term of long-term contract agreement

'

'

'

'

'

'

'30 years

'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 long-term contract obligation

'

'

'

'

'

'

292.4

'

'

'

'

'

'

'

'

'

'

'

'

Amount of total power capacity of generating facility (in megawatts)

14

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of annual payments contingent upon output of the facility

'

'

'

'

'

'

'

'

'

0

14.6

'

'

0

16.9

'

'

'

'

Period of the average cost that is used as a basis for determining the maximum annual payments

'

'

'

'

'

'

'

'20 years

'

'

'

'20 years

'

'

'

'

'

'

'

Estimated project cost

'

'

165

175

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Term of Capital Expenditure Plan

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost related to pre-engineering, site preparation activities and contract cost year to date

'

42.4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected cost of adding carbon injection system

'

'

112

130

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Construction costs project to date

'

97.4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

Gross amount of assets recorded under capital leases

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$5.30

'

'

'

Commitments_and_Contingencies_2

Commitments and Contingencies (Details 2) (USD $)	6 Months Ended	0 Months Ended	6 Months Ended				1 Months Ended		6 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jan. 15, 2013	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Nov. 30, 2010	Jun. 30, 2014	Jun. 30, 2014	Apr. 16, 2012
	Clean Air Interstate Rule	NAAQS	Surface Impoundments	Surface Impoundments	Surface Impoundments	Surface Impoundments	Renewable Energy	Renewable Energy	Green House Gases	Power Plant Mercury And Air Toxics Rule
	Electric	Electric	Electric	Electric	Iatan	Plum point	Electric	Electric	item
	state	item	option	Maximum	Electric	Electric
	MW
Environmental Laws And Regulations	'	'	'	'	'	'	'	'	'	'
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	'	'	'	'	'	'	'	'	'
Period of business plan	'5 years	'	'	'	'	'	'	'	'	'
Phase-in period for proposed standards	'	'	'	'	'	'	'	'	'	'3 years
Period for compliance	'	'	'	'	'	'	'	'	'	'4 years
Particulate matter primary annual standard (in micrograms per cubic meter of air)	'	12	'	'	'	'	'	'	'	'
Percentage of carbon emission reduction from 2005 baseline levels by 2030, required by the proposed Clean Power Plan	'	'	'	'	'	'	'	'	30.00%	'
Number of strategies to achieve the best system of emission reduction identified by EPA	'	'	'	'	'	'	'	'	4	'
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 Missouri retail sales required to generate or purchase electricity in 2014	'	'	'	'	'	'	'	0.05	'	'
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2021	'	'	'	'	'	'	'	15.00%	'	'
Percentage of Missouri retail sales required to generate or purchase solar energy	'	'	'	'	'	'	'	2.00%	'	'
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%	'	'	'

Retirement_Benefits_Details

Retirement Benefits (Details) (USD $)

0 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

6 Months Ended

Jul. 15, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jul. 02, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Pension Benefits

Pension Benefits

Pension Benefits

Pension Benefits

Pension Benefits

Pension Benefits

Pension Benefits

SERP

SERP

SERP

SERP

SERP

SERP

OPEB

OPEB

OPEB

OPEB

OPEB

OPEB

OPEB

Healthcare benefits

Net Periodic Pension Benefit Cost:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Service cost

'

$1,627,000

$1,859,000

$3,254,000

$3,727,000

$6,981,000

$6,732,000

$29,000

$52,000

$58,000

$67,000

$125,000

$104,000

'

$607,000

$715,000

$1,214,000

$1,470,000

$2,684,000

$2,742,000

'

Interest cost

'

2,733,000

2,523,000

5,467,000

5,031,000

10,498,000

10,187,000

87,000

94,000

173,000

157,000

330,000

308,000

'

1,081,000

922,000

2,161,000

1,913,000

4,074,000

3,885,000

'

Expected return on plan assets

'

-3,322,000

-3,089,000

-6,644,000

-6,214,000

-12,858,000

-12,372,000

'

'

'

'

'

'

'

-1,197,000

-1,077,000

-2,393,000

-2,176,000

-4,569,000

-4,229,000

'

Amortization of prior service cost

'

105,000

133,000

209,000

266,000

475,000

531,000

-2,000

-2,000

-4,000

-4,000

-8,000

-8,000

'

-253,000

-253,000

-506,000

-505,000

-1,011,000

-1,011,000

'

Amortization of net actuarial loss

'

1,649,000

2,632,000

3,298,000

5,223,000

8,520,000

9,259,000

105,000

180,000

211,000

284,000

495,000

520,000

'

229,000

481,000

457,000

1,131,000

1,588,000

1,858,000

'

Net periodic benefit cost

'

2,792,000

4,058,000

5,584,000

8,033,000

13,616,000

14,337,000

219,000

324,000

438,000

504,000

942,000

924,000

'

467,000

788,000

933,000

1,833,000

2,766,000

3,245,000

'

Eligible age

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'55 years

Minimum service period for eligibility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

Expected contributions for remaining current period

'

'

'

12,000,000

'

'

'

'

'

'

'

'

'

'

'

'

3,000,000

'

'

'

'

Employer contributions

$3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

$1,200,000

'

'

'

'

'

'

'

StockBased_Awards_and_Programs2

Stock-Based Awards and Programs (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Stock-Based Awards and Programs	'	'	'	'	'	'
Unrecognized compensation expense associated with issued, unvested awards	$1,300,000	'	$1,300,000	'	$1,300,000	'
Compensation Expense	518,000	420,000	1,868,000	1,711,000	2,734,000	2,376,000
Tax Benefit Recognized	$187,000	$146,000	$690,000	$622,000	$997,000	$844,000
Employee Stock Purchase Plan	'	'	'	'	'	'
Changes in restricted stock awards	'	'	'	'	'	'
Nonvested, balance at the end of the period (in shares)	58,627	62,793	58,627	62,793	58,627	62,793
Assumptions for valuation of shares	'	'	'	'	'	'
Weighted average fair value of grants (in dollars per share)	'	'	$3.07	$2.78	'	'
Risk-free interest rate (as a percent)	'	'	0.10%	0.14%	'	'
Expected dividend yield (as a percent)	'	'	4.30%	4.60%	'	'
Expected volatility (as a percent)	'	'	14.00%	14.00%	'	'
Expected life	'	'	'12 months	'12 months	'	'
Performance-Based Restricted Stock Awards	'	'	'	'	'	'
Changes in restricted stock awards	'	'	'	'	'	'
Nonvested, balance at the beginning of the period (in shares)	'	'	47,200,000	33,900,000	'	'
Granted (in shares)	'	'	27,000,000	26,300,000	'	'
Awarded (in shares)	'	'	0	-4,460,000	'	'
Not Awarded (in shares)	'	'	-10,900,000	-8,540,000	'	'
Nonvested, balance at the end of the period (in shares)	63,300,000	47,200,000	63,300,000	47,200,000	63,300,000	47,200,000
Weighted Average Grant Date Price	'	'	'	'	'	'
Nonvested, balance at the beginning of the period (in dollars per share)	'	'	$21.39	$20.25	'	'
Granted (in dollars per share)	'	'	$22.40	$21.36	'	'
Distributed (in dollars per share)	'	'	$21.84	$18.36	'	'
Not Awarded (in dollars per share)	'	'	$21.84	$18.36	'	'
Nonvested, balance at the end of the period (in dollars per share)	$21.74	$21.39	$21.74	$21.39	$21.74	$21.39
Time-Vested Restricted Stock Awards	'	'	'	'	'	'
Assumptions used for estimating fair value of grants outstanding	'	'	'	'	'	'
Vesting period	'	'	'3 years	'	'	'
Period from date of termination of employment due to death, retirement or disability during which the pro-rata portion of the awards are distributed	'	'	'6 months	'	'	'
Changes in restricted stock awards	'	'	'	'	'	'
Nonvested, balance at the beginning of the period (in shares)	'	'	24,900,000	3,300,000	'	'
Granted (in shares)	'	'	22,600,000	21,600,000	'	'
Vested (in shares)	'	'	710,000	'	'	'
Distributed (in shares)	'	'	-3,300,000	'	'	'
Forfeited (in shares)	'	'	-2,490,000	'	'	'
Vested but not distributed (in shares)	'	'	-710,000	'	'	'
Nonvested, balance at the end of the period (in shares)	41,710,000	24,900,000	41,710,000	24,900,000	41,710,000	24,900,000
Weighted Average Grant Date Price	'	'	'	'	'	'
Nonvested, balance at the beginning of the period (in dollars per share)	'	'	$22.68	$20.38	'	'
Granted (in dollars per share)	'	'	$22.40	$21.36	'	'
Vested (in dollars per share)	'	'	$24.29	'	'	'
Distributed (in dollars per share)	'	'	$22.98	'	'	'
Nonvested, balance at the end of the period (in dollars per share)	$24.32	$22.40	$24.32	$22.40	$24.32	$22.40

StockBased_Awards_and_Programs3

Stock-Based Awards and Programs (Details 2) (Stock Options, USD $)	6 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Stock Options	'	'
Stock options	'	'
Outstanding, balance at the beginning of the period (in shares)	112,500	163,300
Exercised (in shares)	67,000	40,200
Outstanding, balance at the end of the period (in shares)	45,500	123,100
Exercisable (in shares)	45,500	123,100
Weighted Average Exercise Price	'	'
Outstanding, balance at the beginning of the period (in dollars per option)	$23.27	$23.15
Exercised (in dollars per share)	$23.98	$21.66
Outstanding, balance at the end of the period (in dollars per option)	$23.81	$23.19
Exercisable (in dollars per share)	$23.81	$23.19

StockBased_Awards_and_Programs4

Stock-Based Awards and Programs (Details 3) (USD $)	6 Months Ended		0 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	1-May-14
	Employee Stock Purchase Plan	Employee Stock Purchase Plan	Amended and restated ESPP
Stock-Based Awards and Programs	'	'	'
Common stock purchase price to eligible employees (as a percent)	90.00%	'	'
Percentage of Black-Scholes methodology used as a component to calculate value of lookback feature	90.00%	'	'
Percentage of maximum subscription price used as a component to calculate value of lookback feature	10.00%	'	'
Shares available for issuance	70,838	'	'
Number of additional shares authorized	'	'	750,000
Subscriptions outstanding (in shares)	58,627	62,793	'
Maximum subscription price (in dollars per share)	$21.43	$19.58	'
Shares of stock issued	56,942	68,099	'
Stock issuance price (in dollars per share)	$19.58	$17.95	'

Regulated_Operating_Expenses_D

Regulated Operating Expenses (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Regulated Operating Expenses	'	'	'	'	'	'
Electric transmission and distribution expense	$6,878	$5,950	$13,676	$10,979	$24,560	$19,690
Natural gas transmission and distribution expense	558	577	1,232	1,122	2,608	2,250
Power operation expense (other than fuel)	4,021	4,367	8,012	8,011	15,644	15,953
Customer accounts and assistance expense	2,884	2,619	5,720	5,198	11,701	10,391
Employee pension expense	2,602	2,757	5,228	5,399	10,565	10,505
Employee healthcare plan	2,607	2,408	4,332	5,195	9,327	10,458
General office supplies and expense	3,185	3,163	7,376	6,592	13,635	12,093
Administrative and general expense	3,438	3,603	7,664	7,918	14,546	15,217
Allowance for uncollectible accounts	1,329	1,044	2,101	1,790	3,976	3,483
Regulatory reversal of gain on sale of assets	'	'	'	1,236	'	1,236
Miscellaneous expense	107	159	225	344	553	687
Total	$27,609	$26,647	$55,566	$53,784	$107,115	$101,963

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
			segment
			town
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	$149,782	$136,646	$329,455	$287,786	$635,998	$576,107	'
Depreciation and amortization	18,157	17,635	36,097	33,736	71,668	64,180	'
Federal and state income taxes	6,649	7,049	18,769	14,531	41,731	35,730	'
Operating income	19,502	21,110	48,990	42,968	105,685	97,615	'
Interest income	3	10	44	517	92	1,187	'
Interest expense	10,408	10,504	20,732	20,754	41,457	41,220	'
Income from AFUDC (debt and equity)	2,352	1,339	4,343	2,170	8,114	3,829	'
Net income	11,194	11,658	32,099	24,287	71,257	59,456	'
Capital Expenditures	46,542	38,500	96,875	76,208	184,375	155,820	'
Total assets	2,207,781	'	2,207,781	'	2,207,781	'	2,145,045
Goodwill	39,492	'	39,492	'	39,492	'	39,492
Operating segments | Electric	'	'	'	'	'	'	'
Statement of Income Information, balance sheet information and capital expenditures of business segments	'	'	'	'	'	'	'
Revenues	140,767	127,026	293,856	255,788	574,481	522,624	'
Depreciation and amortization	16,791	16,205	33,366	30,887	66,138	58,869	'
Federal and state income taxes	6,331	6,948	16,578	12,943	38,113	33,277	'
Operating income	18,185	19,994	43,711	38,509	96,187	89,876	'
Interest income	'	3	32	497	71	1,155	'
Interest expense	9,454	9,557	18,821	18,893	37,612	37,558	'
Income from AFUDC (debt and equity)	2,301	1,331	4,267	2,161	8,016	3,811	'
Net income	10,826	11,498	28,710	21,721	65,592	55,487	'
Capital Expenditures	44,911	36,535	91,614	73,070	175,445	149,619	'
Total assets	2,098,131	'	2,098,131	'	2,098,131	'	2,034,234
Operating segments | Gas	'	'	'	'	'	'	'
Statement of Income Information, balance sheet information and capital expenditures of business segments	'	'	'	'	'	'	'
Revenues	6,989	7,777	31,598	28,270	53,369	46,632	'
Depreciation and amortization	913	927	1,824	1,851	3,682	3,669	'
Federal and state income taxes	-90	-129	1,358	1,076	1,766	1,406	'
Operating income	624	744	3,899	3,639	6,453	6,055	'
Interest income	7	34	19	105	29	262	'
Interest expense	963	976	1,926	1,953	3,862	3,905	'
Income from AFUDC (debt and equity)	51	8	76	9	98	18	'
Net income	-295	-214	2,035	1,735	2,655	2,267	'
Capital Expenditures	1,249	1,463	4,422	2,196	6,645	4,198	'
Total assets	122,304	'	122,304	'	122,304	'	123,736
Goodwill	39,492	'	39,492	'	39,492	'	39,492
Operating segments | Other	'	'	'	'	'	'	'
Statement of Income Information, balance sheet information and capital expenditures of business segments	'	'	'	'	'	'	'
Revenues	2,346	1,991	4,641	4,024	9,764	7,443	'
Depreciation and amortization	453	503	907	998	1,848	1,642	'
Federal and state income taxes	408	230	833	512	1,852	1,047	'
Operating income	693	372	1,380	820	3,045	1,684	'
Interest income	5	2	8	7	9	13	'
Net income	663	374	1,354	831	3,010	1,702	'
Capital Expenditures	382	502	839	942	2,285	2,003	'
Total assets	31,965	'	31,965	'	31,965	'	31,306
Eliminations	'	'	'	'	'	'	'
Statement of Income Information, balance sheet information and capital expenditures of business segments	'	'	'	'	'	'	'
Revenues	-320	-148	-640	-296	-1,616	-592	'
Interest income	-9	-29	-15	-92	-17	-243	'
Interest expense	-9	-29	-15	-92	-17	-243	'
Total assets	($44,619)	'	($44,619)	'	($44,619)	'	($44,231)

Income_Taxes_Details

Income Taxes (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2010
Income Taxes	'	'	'	'	'	'	'
Consolidated provision for income taxes	$6,649,000	$7,049,000	$18,769,000	$14,531,000	$41,731,000	$35,730,000	'
Consolidated effective federal and state income tax rates (as a percent)	37.30%	37.70%	36.90%	37.40%	36.90%	37.50%	'
Advanced coal investment tax credit	'	'	'	'	'	'	17,700,000
Maximum tax credit utilized	'	'	'	'	'	'	700,000
Investment tax credit expected to be utilized	'	'	'	'	'	'	$10,700,000