Empire District Electric (EDE) 10-K 20 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 02, 2015	Jun. 30, 2014
Document and Entity Information
Entity Registrant Name	EMPIRE DISTRICT ELECTRIC CO
Entity Central Index Key	32689
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$1,112,837,946
Entity Common Stock, Shares Outstanding		43,517,285
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Plant and property, at original cost:
Electric	$2,420,824	$2,219,605
Gas	79,364	72,834
Other	41,394	39,902
Construction work in progress	112,097	152,330
Total plant and property, Gross	2,653,679	2,484,671
Accumulated depreciation and amortization	743,407	732,737
Total plant and property, Net	1,910,272	1,751,934
Current assets:
Cash and cash equivalents	2,105	3,475
Restricted cash	4,726	2,872
Accounts receivable - trade, net of allowance of $1,021 and $1,025, respectively	45,444	50,137
Accrued unbilled revenues	25,945	26,694
Accounts receivable - other	41,256	13,101
Fuel, materials and supplies	57,799	48,811
Prepaid expenses and other	27,879	15,954
Unrealized gain in fair value of derivative contracts	3,901	2,469
Regulatory assets	10,752	7,743
Total current assets	219,807	171,256
Noncurrent assets and deferred charges:
Regulatory assets	209,717	169,333
Goodwill	39,492	39,492
Unamortized debt issuance costs	8,821	8,826
Unrealized gain in fair value of derivative contracts		41
Other	2,147	4,163
Total noncurrent assets and deferred charges	260,177	221,855
Total Assets	2,390,256	2,145,045
Capitalization and liabilities
Common stock, $1 par value, 100,000,000 shares authorized, 43,479,186 and 43,044,185 shares issued and outstanding, respectively	43,479	43,044
Capital in excess of par value	649,543	639,525
Retained earnings	90,276	67,554
Total common stockholders' equity	783,298	750,123
Long-term debt (net of current portion):
Obligations under capital lease	3,875	4,167
First mortgage bonds and secured debt	697,615	637,578
Unsecured debt	101,699	101,683
Total long-term debt	803,189	743,428
Total long-term debt and common stockholders' equity	1,586,487	1,493,551
Current liabilities:
Accounts payable and accrued liabilities	83,420	71,375
Current maturities of long-term debt	292	274
Short-term debt	44,000	4,000
Regulatory liabilities	7,898	5,681
Customer deposits	13,747	12,543
Interest accrued	6,565	6,352
Unrealized loss in fair value of derivative contracts	6,469	1,889
Taxes accrued	3,380	3,386
Other current liabilities	356	299
Total current liabilities	166,127	105,799
Commitments and contingencies (Note 11)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	128,471	132,012
Deferred income taxes	377,452	324,266
Unamortized investment tax credits	18,367	18,431
Pension and other postretirement benefit obligations	93,863	51,405
Unrealized loss in fair value of derivative contracts	3,243	2,799
Other	16,246	16,782
Total noncurrent liabilities and deferred credits	637,642	545,695
Total capitalization and liabilities	$2,390,256	$2,145,045

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Consolidated Balance Sheets
Accounts receivable - trade, allowance (in dollars)	$1,021	$1,025
Common stock, par value (in dollars per share)	$1	$1
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	43,479,186	43,044,185
Common stock, shares outstanding	43,479,186	43,044,185

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenues:
Electric	$592,491	$536,413	$510,653
Gas	51,842	50,041	39,849
Other	7,997	7,876	6,595
Total operating revenues	652,330	594,330	557,097
Operating revenue deductions:
Fuel and purchased power	215,086	175,406	178,896
Cost of natural gas sold and transported	27,025	25,795	18,633
Regulated operating expenses	110,691	105,333	94,371
Other operating expenses	2,987	3,142	2,730
Maintenance and repairs	46,775	40,873	40,444
Loss on plant disallowance	86	2,409
Depreciation and amortization	73,185	69,306	60,447
Provision for income taxes	39,398	37,465	34,096
Other taxes	37,098	34,938	31,259
Total operating revenue deductions	552,331	494,667	460,876
Operating income	99,999	99,663	96,221
Other income and (deductions):
Allowance for equity funds used during construction	-6,420	-3,853	-1,147
Interest income	51	566	972
Provision for other income taxes	178	-27	-63
Other - non-operating expense, net	-1,302	-1,218	-1,910
Total other income and (deductions)	5,347	3,174	146
Interest charges:
Long-term debt	40,637	40,354	40,192
Short-term debt	113	60	187
Allowance for borrowed funds used during construction	-3,497	-2,087	-781
Other	990	1,065	1,088
Total interest charges	38,243	39,392	40,686
Net income	$67,103	$63,445	$55,681
Weighted average number of common shares outstanding - basic (in shares)	43,291	42,781	42,257
Weighted average number of common shares outstanding - diluted (in shares)	43,314	42,803	42,284
Total earnings per weighted average share of common stock - basic and diluted (in dollars per share)	$1.55	$1.48	$1.32
Dividends paid per share common stock (in dollars per share)	$1.02	$1.00	$1

Consolidated_Statements_of_Com

Consolidated Statements of Common Stockholders' Equity (USD $)	Common Stock	Capital in excess of Par	Retained earnings	Total
In Thousands, unless otherwise specified
Balance at Dec. 31, 2011	$41,978	$618,304	$33,707	$693,989
Increase (Decrease) in Stockholders' Equity
Net income			55,681	55,681
Stock/stock units issued through:
Stock purchase and reinvestment plans	506	9,895		10,401
Dividends declared			-42,273	-42,273
Balance at Dec. 31, 2012	42,484	628,199	47,115	717,798
Increase (Decrease) in Stockholders' Equity
Net income			63,445	63,445
Stock/stock units issued through:
Stock purchase and reinvestment plans	560	11,326		11,886
Dividends declared			-43,006	-43,006
Balance at Dec. 31, 2013	43,044	639,525	67,554	750,123
Increase (Decrease) in Stockholders' Equity
Net income			67,103	67,103
Stock/stock units issued through:
Stock purchase and reinvestment plans	435	10,018		10,453
Dividends declared			-44,381	-44,381
Balance at Dec. 31, 2014	$43,479	$649,543	$90,276	$783,298

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities:
Net income	$67,103	$63,445	$55,681
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	82,754	71,734	71,160
Pension and other postretirement benefit costs, net of contributions	1,973	-1,888	1,689
Deferred income taxes and unamortized investment tax credit, net	41,693	28,272	31,899
Allowance for equity funds used during construction	-6,420	-3,853	-1,147
Stock compensation expense	4,057	2,984	2,285
Loss on plant disallowance	86	2,409
Non-cash loss on derivatives	1,245	14	4,174
Regulatory reversal of gain on sale of assets	44	1,236
Other			-16
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	-24,174	-14,312	-688
Fuel, materials and supplies	-8,121	10,891	369
Prepaid expenses, other current assets and deferred charges	-6,051	689	-9,238
Accounts payable and accrued liabilities	1,141	-880	-1,297
Asset retirement obligation	-1,326	-734
Interest, taxes accrued and customer deposits	1,411	1,386	875
Other liabilities and other deferred credits	-4,192	-3,942	3,360
Net cash provided by operating activities	151,223	157,451	159,106
Investing activities:
Capital expenditures - regulated	-211,429	-152,524	-134,272
Capital expenditures and other investments - non-regulated	-1,998	-2,259	-2,670
Restricted cash	-1,854	1,485	-1
Total net cash used in investing activities	-215,281	-153,298	-136,943
Financing activities:
Proceeds from first mortgage bonds, net	60,000	150,000	88,000
Long-term debt issuance costs	-651	-1,879	-1,074
Proceeds from issuance of common stock, net of issuance costs	7,994	9,546	8,114
Repayment of first mortgage bonds			-88,029
Redemption of senior notes		-98,000
Net short-term borrowings/(repayments)	40,000	-20,000	12,000
Dividends	-44,381	-43,006	-42,273
Other	-274	-714	-934
Net cash provided by / (used) in financing activities	62,688	-4,053	-24,196
Net increase (decrease) in cash and cash equivalents	-1,370	100	-2,033
Cash and cash equivalents, beginning of year	3,475	3,375	5,408
Cash and cash equivalents, end of year	2,105	3,475	3,375
Supplemental cash flow information:
Interest paid	40,127	39,033	38,802
Income taxes (refunded) paid, net of refund	23,103	10,584	-592
Supplementary non-cash investing activities:
Change in accrued additions to property, plant and equipment not reported above	$9,427	$5,420	$9,345

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary engaged in the distribution of natural gas in Missouri. Our other segment consists of our fiber optics business. See Note 12. Our gross operating revenues in 2014 were derived as follows:

Electric segment sales*

90.8

%

Gas segment sales

8.0

Other segment sales

1.2

*

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

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

Our electric operations serve approximately 170,000 customers as of December 31, 2014, and the 2014 electric operating revenues were derived as follows:

Customer

% of revenue

Residential

40.0

%

Commercial

29.2

Industrial

14.4

Wholesale on-system

3.8

Wholesale off-system

7.6

Miscellaneous sources, primarily public authorities

2.6

Other electric revenues

2.4

Our retail electric revenues for 2014 by jurisdiction were as follows:

Jurisdiction

% of revenue

Missouri

89.7

%

Kansas

4.8

Arkansas

2.7

Oklahoma

2.8

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

Customer

% of revenue

Residential

63.4

%

Commercial

26.3

Industrial

1.0

Other

9.3

Basis of Presentation

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

Use of Estimates

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

Accounting for the Effects of Regulation

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

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

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

Revenue Recognition

For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer classes. During 2012, we recorded an increase in electric unbilled revenues as a result of certain changes to the assumptions used in determining estimated unbilled revenues.

Municipal Franchise Taxes

Municipal franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other taxes in the Consolidated Statements of Income. Municipal franchise taxes of $11.8 million, $11.2 million and $10.4 million were recorded for each of the years ended December 31, 2014, 2013 and 2012, respectively.

Accounts Receivable

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

Property, Plant & Equipment

The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material, an allocation of general and administrative costs, and an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of and the costs of removal are charged to accumulated depreciation, unless the removed property constitutes an operating unit or system. In this case a gain or loss is recognized upon the disposal of the asset. Maintenance expenditures and the removal of minor property items are charged to income as incurred. A liability is created for any additions to electric or gas utility property that are paid for by advances from developers. For a period of five years we refund to the developer a pro rata amount of the original cost of the extension for each new customer added to the extension. Nonrefundable payments at the end of the five year period are applied as a reduction to the cost of the plant in service. The liability as of December 31, 2014 and 2013 was $1.9 million and $4.2 million, respectively.

Depreciation

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

As of December 31, 2014 and 2013, we had recorded accrued cost of removal of $82.8 million and $81.3 million, respectively, for our electric operating segment. This represents an estimated cost of dismantling and removing plant from service upon retirement, accrued as part of our depreciation rates. We accrue cost of removal in depreciation rates for mass property (including transmission, distribution and general plant assets). These accruals are not considered an asset retirement obligation under the guidance provided on asset retirement obligations within the ASC. We reclassify the accrued cost of dismantling and removing plant from service upon retirement from accumulated depreciation to a regulatory liability. We have a similar cost of removal regulatory liability for our gas operating segment. This amount at December 31, 2014 and 2013 was $7.7 million and $7.2 million, respectively. These amounts are net of our actual cost of removal expenditures.

Asset Retirement Obligation

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

We have identified asset retirement obligations associated with the future removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We also have a solid waste land fill at the Plum Point Energy Station, and asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. As a result of the fuel use transition from coal to natural gas at the Riverton Power Plant, the closure of the Riverton ash landfill was completed, and the related asset retirement obligation was settled during 2014 (Note 11).

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

All of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 4.5% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. During 2014 the liability for asbestos at the Riverton Power Plant was re-evaluated, and during 2012 the liabilities for both the ash landfill at the Riverton Power Plant, and PCB contaminants were re-evaluated. Changes in the cost estimates and timing resulted in cash flow revisions for these liabilities.

The balances at the end of 2013 and 2014 are shown below.

(000's)

Liability

Liabilities

Liabilities

Accretion

Cash Flow

Liability

Balance

Recognized

Settled

Revisions

Balance at

12/31/13

12/31/14

Asset Retirement Obligation

$

4,190

$

—

$

(1,175

)

$

172

$

1,660

$

4,847

(000's)

Liability

Liabilities

Liabilities

Accretion

Cash Flow

Liability

Balance

Recognized

Settled

Revisions

Balance at

12/31/12

12/31/13

Asset Retirement Obligation

$

4,711

$

—

$

(734

)

$

213

$

—

$

4,190

Upon adoption of the standards on the retirement of long lived assets and conditional asset retirement obligations, we recorded a liability and regulatory asset because we expect to recover these costs of removal in electric and gas rates either through depreciation accruals or direct expenses. We also defer the liability accretion and depreciation expense as a regulatory asset. At December 31, 2014 and 2013, our regulatory assets relating to asset retirement obligations totaled $5.1 million and $4.7 million, respectively.

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

Allowance for Funds Used During Construction

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

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

In accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 6.6% for 2014, 7.3% for 2013, and 5.6% for 2012, compounded semiannually.

Asset Impairments (excluding goodwill)

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on undiscounted forecasted cash flows to assess the recoverability of the assets and, if necessary, the fair value is determined to measure the impairment amount. None of our assets were impaired as of December 31, 2014 and 2013.

Goodwill

As of December 31, 2014, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and income approaches is used to estimate the fair value of goodwill.

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

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

We weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of October 2014 indicated the estimated fair market value of the gas reporting unit to be $10 – $14 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future.

Fuel and Purchased Power

Electric Segment

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

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

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

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

At December 31, 2014 and 2013, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net under-recovered position by $3.1 million and a net over-recovered position of $0.6 million, respectively, which are reflected in our regulatory assets and liabilities.

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

We have a Stipulation and Agreement with the MPSC granting us authority to manage our SO2 allowance inventory in accordance with our SO2 Allowance Management Policy (SAMP). The SAMP allows us to exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. We have not yet exchanged or sold any allowances. We classify our allowances as inventory and they are recorded at cost, with allocated allowances being recorded at zero cost. The allowances are removed from inventory on a FIFO basis, and used allowances are considered to be a part of fuel expense (See Note 11). We had 872 and 1,834 SO2 allowances in inventory at December 31, 2014 and 2013, respectively.

Gas Segment

Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery allowed in rates. A Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and related carrying costs associated with the Company's use of natural gas financial instruments to hedge the purchase price of natural gas. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.

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

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

Derivatives

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

Electric Segment

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

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

Gas Segment

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

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

Pension and Other Postretirement Benefits

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

Pensions

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

Other Postretirement Benefits (OPEB)

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

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

Unamortized Debt Discount, Premium and Expense

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

Liability Insurance

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

Other Noncurrent Liabilities

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

Cash & Cash Equivalents

Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities and were $28.3 million and $22.1 million at December 31, 2014 and 2013, respectively.

Restricted Cash

As part of our Plum Point ownership agreement, we are required to have funds available in an escrow account which guarantees payment of certain operating and construction costs. The cash is held at a financial institution and restricted as to withdrawal or use. The restrictions on these funds related to construction costs, which were approximately $2.5 million at December 31, 2012, were released by all parties in January 2013. The amounts restricted for operating costs, which were $1.8 million at December 31, 2014 and 2013, may increase or decrease based on an annual review.

We are required to post cash collateral with Southwest Power Pool (SPP) to participate in Transmission Congestion Rights (TCR) auctions. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $2.5 million and $1.1 million at December 31, 2014 and 2013, respectively.

Due to our Plum Point energy station interconnection with Midcontinent Independent System Operator (MISO), we participate in Financial Transmission Rights (FTR) auctions which require us to post cash collateral. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $0.5 million and $0 at December 31, 2014 and 2013, respectively.

Fuel, Materials and Supplies

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

2014

2013

Electric fuel inventory

$

26,454

$

17,003

Natural gas inventory

5,040

3,584

Materials and supplies

26,305

28,224

TOTAL

$

57,799

$

48,811

Income Taxes

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

Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. The longest remaining amortization period for investment tax credits is approximately 50 years.

Accounting for Uncertainty in Income Taxes

In 2006, the FASB issued guidance which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with the ASC guidance on accounting for income taxes. We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2009. At December 31, 2014 and 2013, our balance sheet did not include any unrecognized tax benefits. We do not expect any material changes to unrecognized tax benefits within the next twelve months. We recognize interest and penalties, if any, related to unrecognized tax benefits in other expenses.

Computations of Earnings Per Share

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

2014

2013

2012

Weighted Average Number Of Shares

Basic

43,291,031

42,781,382

42,256,641

Dilutive Securities:

Performance-based restricted stock awards

8,809

12,142

14,500

Dividend equivalents

—

—

6,329

Employee stock purchase plan

3,422

1,729

1,996

Stock options

—

61

3,160

Time-based restricted stock awards

10,666

7,907

1,820

Total dilutive securities

22,897

21,839

27,805

Diluted weighted average number of shares

43,313,928

42,803,221

42,284,446

Antidilutive Shares

25,259

107,100

128,500

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

Stock-Based Compensation

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

Recently Issued and Proposed Accounting Standards

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

Revenue from contracts with customers:    In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard is effective for interim and annual reporting periods beginning after December 15, 2016. We are evaluating the impact of the adoption of this standard.

PROPERTY_PLANT_AND_EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2014
PROPERTY, PLANT AND EQUIPMENT
PROPERTY, PLANT AND EQUIPMENT
	2.     PROPERTY, PLANT AND EQUIPMENT
	Our total property, plant and equipment are summarized below (in thousands).
			December 31,
			2014			2013
	Electric plant
	Production		$	1,159,140		$	1,035,095
	Transmission			288,542			263,398
	Distribution			840,761			793,024
	General(1)			119,572			115,427
	Electric plant			2,408,015			2,206,944
	Less accumulated depreciation and amortization			704,596			697,128
	Electric plant net of depreciation and amortization			1,703,419			1,509,816
	Construction work in progress			110,500			150,636
	Net electric plant			1,813,919			1,660,452
	Water plant			12,809			12,661
	Less accumulated depreciation and amortization			5,102			4,806
	Water plant net of depreciation and amortization			7,707			7,855
	Construction work in progress			146			—
	Net water plant			7,853			7,855
	Net electric segment plant			1,821,772			1,668,307
	Gas plant
	Transmission			11,198			10,550
	Distribution			89,712			84,157
	General(2)			(21,546	)		(21,873	)
	Gas Plant			79,364			72,834
	Less accumulated depreciation and amortization			16,405			15,204
	Gas plant net of accumulated depreciation			62,959			57,630
	Construction work in progress			379			1,156
	Net gas plant			63,338			58,786
	Other
	Fiber			41,394			39,902
	Less accumulated depreciation and amortization			17,304			15,599
	Non-regulated net of depreciation and amortization			24,090			24,303
	Construction work in progress			1,072			538
	Net non-regulated property			25,162			24,841
	TOTAL NET PLANT AND PROPERTY		$	1,910,272		$	1,751,934
	-1	Includes intangible property of $41.2 and $38.1 million as of December 31, 2014 and 2013, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2014 and 2013 was $15.7 and $13.1 million, respectively.
	-2	Includes intangible property of $0.7 and $0.7 million as of December 31, 2014 and 2013, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2014 and 2013 was $0.5 million and $0.5 million, respectively.
	The table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended December 31 (in thousands):
			2014			2013			2012
	Provision for depreciation
	Regulated — Electric and Water		$	66,600		$	63,192		$	57,467
	Regulated — Gas			3,851			3,763			3,602
	Non-Regulated			1,891			1,938			1,538
	TOTAL			72,342			68,893			62,607
	Amortization			2,692			2,492			1,041
	TOTAL		$	75,034		$	71,385		$	63,648
			2014			2013			2012
	Annual depreciation rates
	Electric and water			3.0	%		3.0	%		2.8	%
	Gas			5.2	%		5.4	%		5.4	%
	Non-Regulated			4.7	%		5.0	%		4.2	%
	TOTAL COMPANY			3.0	%		3.1	%		2.9	%
	The table below sets forth the average depreciation rate for each class of assets for each period presented:
			2014			2013			2012
	Annual Weighted Average Depreciation Rate
	Electric fixed assets:
	Production plant			2.4	%		2.4	%		2.0	%
	Transmission plant			2.4	%		2.4	%		2.4	%
	Distribution plant			3.6	%		3.6	%		3.6	%
	General plant			5.8	%		5.8	%		5.9	%
	Water			2.7	%		2.8	%		2.7	%
	Gas			5.2	%		5.4	%		5.4	%
Non-regulated			4.7	%		5.0	%		4.2	%

REGULATORY_MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2014
Regulatory Matters
Regulatory Matters	3.     REGULATORY MATTERS
	Regulatory Assets and Liabilities and Other Deferred Credits
	Changes
	There were no changes to regulatory assets and liabilities with regards to their rate base inclusion or amortizable lives from December 31, 2013 to December 31, 2014. Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives from December 31, 2012 to December 31, 2013 resulted from our 2012 Missouri rate case. As a result of this case, deferred costs from the tornado that hit our service territory on May 22, 2011 will be recovered over the next ten years. In addition, the order also included the continuation of tracking mechanisms for expenses related to employee pension, retiree health care, vegetation management, and Iatan 2, Iatan Common and Plum Point operating and maintenance costs as well as the capitalization of banking and line of credit fees.
	The following table sets forth the components of our regulatory assets and regulatory liabilities on our consolidated balance sheet (in thousands).
			December 31,
			2014			2013
	Regulatory Assets:
	Current:
	Under recovered fuel costs		$	2,618		$	1,411
	Current portion of long-term regulatory assets			8,134			6,332
	Regulatory assets, current			10,752			7,743
	Long-term:
	Pension and other postretirement benefits(1)			111,121			70,035
	Income taxes			47,177			48,033
	Deferred construction accounting costs(2)			15,521			16,275
	Unamortized loss on reacquired debt			10,405			11,078
	Unsettled derivative losses — electric segment			9,037			4,269
	System reliability — vegetation management			5,337			7,539
	Storm costs(3)			4,183			4,911
	Asset retirement obligation			5,145			4,673
	Customer programs			5,253			4,935
	Unamortized loss on interest rate derivative			943			989
	Deferred operating and maintenance expense			910			2,095
	Under recovered fuel costs			640			—
	Current portion of long-term regulatory assets			(8,134	)		(6,332	)
	Other			2,179			833
	Regulatory assets, long-term			209,717			169,333
	Total Regulatory Assets		$	220,469		$	177,076
	Regulatory Liabilities
	Current:
	Over recovered fuel costs		$	4,227		$	2,212
	Current portion of long-term regulatory liabilities			3,671			3,469
	Regulatory liabilities, current			7,898			5,681
	Long-term:
	Costs of removal			90,527			88,469
	SWPA payment for Ozark Beach lost generation			16,744			19,405
	Income taxes			11,451			11,677
	Deferred construction accounting costs — fuel(4)			7,849			8,011
	Unamortized gain on interest rate derivative			3,201			3,371
	Pension and other postretirement benefits			2,369			2,177
	Over recovered fuel costs			1			2,371
	Current portion of long-term regulatory liabilities			(3,671	)		(3,469	)
	Regulatory liabilities, long-term			128,471			132,012
	Total Regulatory Liabilities		$	136,369		$	137,693
	-1	Primarily consists of unfunded pension and OPEB liability. See Note 7.
	-2	Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants.
	-3	Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $3.3 million at December 31, 2014.
	-4	Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.
	Unamortized losses on debt and losses on interest rate derivatives are not included in rate base, but are included in our capital structure for rate base purposes. The remainder of our regulatory assets are not included in rate base, generally because they are not cash items. However, as of December 31, 2014, the costs of all of our regulatory assets are currently being recovered except for approximately $103.5 million of pension and other postretirement costs primarily related to the unfunded liabilities for future pension and OPEB costs. The amount and timing of recovery of this item will be based on the changing funded status of the pension and OPEB plans in future periods.
	The regulatory income tax assets and liabilities are generally amortized over the average depreciable life of the related assets. The loss on reacquired debt and the loss and gain on interest rate derivatives are amortized over the life of the related new debt issue, which currently ranges from 6 to 26 years. The unrecovered fuel costs are generally recovered within a year following their recognition. Severe storm costs and the Asbury maintenance outage costs are recovered over five years. Pension and other postretirement benefit tracking mechanisms are recovered over a five year period. The cost of removal regulatory liability is amortized as removal costs are incurred.
	RATE MATTERS
	We routinely assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.
	Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a "cost of service" basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable return on "rate base." "Rate base" is generally determined by reference to the original cost (net of accumulated depreciation and amortization) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, amortization and retirement of utility plant or write-off's as ordered by the utility commissions. In general, a request of new rates is made on the basis of a "rate base" as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag (commonly referred to as "regulatory lag") between the time we incur costs and the time when we can start recovering the costs through rates.
	The following table sets forth information regarding electric and water rate increases since January 1, 2012:
	Jurisdiction		Date Requested		Annual			Percent			Date Effective
					Increase			Increase
					Granted			Granted
	Arkansas — Electric		December 3, 2013		$	1,366,809			11.34	%		September 26, 2014
	Missouri — Electric		July 6, 2012		$	27,500,000			6.78	%		April 1, 2013
	Missouri — Water		May 21, 2012		$	450,000			25.5	%		November 23, 2012
	Kansas — Electric		June 17, 2011		$	1,250,000			5.20	%		January 1, 2012
	Oklahoma — Electric		June 30, 2011		$	240,722			1.66	%		January 4, 2012
	Electric Segment
Missouri
2014 Rate Case
On August 29, 2014, we filed a request with the MPSC for changes in rates for our Missouri electric customers. We requested an annual increase in total revenue of approximately $24.3 million, or approximately 5.5%. The main cost drivers in the rate increase are the costs associated with our investment in Air Quality Control Facilities at our Asbury power plant (See Note 11 — New Construction) that were incurred to comply with the Environmental Protection Agency's (EPA) rules governing the continued operation of the plant, increases in property taxes, increases in ongoing maintenance expenses and increases in Regional Transmission Organization transmission fees.
2012 Rate Cases
On February 22, 2013, we filed a Nonunanimous Stipulation and Agreement (Agreement) with the MPSC which issued an order approving the Agreement on February 27, 2013. The Agreement provided for an annual increase in base revenues for our Missouri electric customers in the amount of approximately $27.5 million, effective April 1, 2013, and the continuation of the current fuel adjustment mechanism. In 2011 the MPSC permitted us to defer actual incremental operating and maintenance expenses associated with the repair, restoration and rebuilding activities resulting from the May 2011 tornado. In addition, depreciation related to the capital expenditures was allowed to be deferred and a carrying charge accrued. Approximately $4.0 million was deferred in total for the tornado costs. Recovery of these costs over the ten years was included in the Agreement
The Agreement also included an increase in depreciation rates, and the continuation of tracking mechanisms for expenses related to employee pension, retiree health care, vegetation management, and Iatan 2, Iatan Common and Plum Point operating and maintenance costs. In addition, the Agreement included a write-off of approximately $3.6 million, consisting of a $2.4 million disallowance for the prudency of certain construction expenditures for Iatan 2 and a $1.2 million regulatory reversal of a prior period gain on sale of our Asbury unit train, which is included in regulated operating expenses. We also agreed not to implement a Missouri general rate increase prior to October 1, 2014. As initially filed on July 6, 2012, we requested an annual increase in base rates for our Missouri electric customers in the amount of $30.7 million, or 7.56%, and the continuation of the fuel adjustment clause.
On May 21, 2012, we filed a rate increase request with the MPSC for an annual increase in revenues for our Missouri water customers in the amount of approximately $516,400, or 29.6%. On October 18, 2012, we, the MPSC staff and the Office of the Public Counsel filed a unanimous agreement with the MPSC for an increase of $450,000. The MPSC issued an order approving the agreement on October 31, 2012, with rates effective November 23, 2012.
Kansas
2014 Environmental Cost Recovery Rider
On December 5, 2014, we filed for approval of an environmental cost recovery rider designed to recover the costs associated with our investment in Air Quality Control Facilities at our Asbury generating unit. As proposed, the rider would recover $859,674 during the first twelve months of the tariffs operation.
2011 Rate Case
On November 10, 2011 a joint settlement agreement was filed, and approved by the KCC on December 21, 2011, resulting in an increase in annual revenues of $1.25 million, or approximately 5.2%. The new rates became effective on January 1, 2012. On June 17, 2011, we filed an application with the KCC seeking a rate increase of $1.5 million, or 6.39%. The rate increase was requested to recover the costs associated with our investment in the Iatan 1, Iatan 2 and Plum Point generating units and the depreciation and operation and maintenance costs deferred since the in-service dates of the units. The June 17, 2011 filing was made under the KCC's abbreviated rate case rules which the KCC authorized in our 2009 Kansas rate case. The case included a request to recover the Iatan and Plum Point cost deferrals over a 3-year period.
Oklahoma
On June 30, 2011, we filed a request with the Oklahoma Corporation Commission (OCC) for an annual increase in base rates for our Oklahoma electric customers in the amount of $0.6 million, or 4.1% over the base rate and Capital Reliability Rider (CRR) revenues that were currently in effect. A stipulation and agreement, reached by all parties participating in the case, was filed on November 16, 2011. This agreement, which was approved by the OCC on January 4, 2012, made rates previously collected under the CRR permanent, and will result in a net overall increase of total annual revenues of $0.2 million, or approximately 1.66%. The agreement also removed fuel and purchase power costs from base rates. Fuel and purchase power costs are now listed as a separate line item, identified as the Fuel Adjustment Charge, on customer bills.
Arkansas
On May 20, 2014, we filed a settlement agreement with the Arkansas Public Service Commission (APSC) for an increase of $1.375 million, or approximately 11%. A hearing was held on the settlement agreement on July 22, 2014. On September 16, 2014, the APSC issued an order approving the settlement with a modification that reduced the overall revenue increase to $1.367 million. The new rates were effective September 26, 2014. We had filed a request on December 3, 2013, with the APSC seeking an annual increase in total revenue of approximately $2.2 million, or approximately 18%. The rate increase was requested to recover costs incurred to ensure continued reliable service for our customers, including capital investments, operating systems replacement costs and ongoing increases in other operation and maintenance expenses and capital costs.
FERC
We have in place a cost-based transmission formula rate (TFR). On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement included a TFR that would establish an ROE of 10.0%. The Agreement calls for the TFR to be updated annually with the new updated TFR rates effective on July 1 of each year. FERC conditionally approved the Agreement on November 18, 2013, and we made a compliance filing with FERC on December 18, 2013 in connection with this conditional approval. The FERC approved our compliance filing on June 12, 2014.
We have in place a cost-based generation formula rate (GFR). Our GFR requires an update to be completed annually for rates effective June 1. On October 29, 2014, Empire made a "limited" Section 205 filing to request some minor changes in the existing GFR formula to incorporate the impact of the recent implementation of the Southwest Power Pool Integrated Marketplace (IM). As a result of this filing, our customers' share of the margins we receive from sales into the IM will be passed on to them through the monthly fuel and purchased power cost adjustment mechanism rather than making one-time adjustments at each annual update. This filing was approved by FERC on January 13, 2015.
MARKETS AND TRANSMISSION
Electric Segment
Day Ahead Market:    On March 1, 2014, the SPP RTO implemented its Integrated Marketplace (or Day-Ahead Market), which replaced the Energy Imbalance Services (EIS) market. The SPP RTO created a single NERC-approved balancing authority (BA) that took over balancing authority responsibilities for its members, including Empire.
As part of the Integrated Marketplace (IM), we and other SPP members submit generation offers to sell our power and bids to purchase power into the SPP market, with the SPP serving as a centralized dispatch of SPP members' generation resources. The SPP matches offers and bids based upon operating and reliability considerations. It is expected that 90% – 95% of all next day generation needed throughout the SPP territory will be cleared through this IM. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we will purchase from the IM. The activity for each market participant is settled in various time increments. When we sell more generation to the market than we purchase, based on the prescribed time increments, the net sale is included as part of electric revenues. When we purchase more generation from the market than we sell, based on the prescribed time increments, the net purchase is recorded as a component of fuel and purchased power on our financial statements. The net financial effect of these Integrated Marketplace transactions is included in our fuel adjustment mechanisms.
FERC Order No. 1000:    In July 2011, the FERC issued Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities) which requires all public utility transmission providers to allow transmission developers outside their retail distribution service territory to participate in regional transmission planning. Order No. 1000 eliminates the federal right of first refusal for entities that develop transmission projects within their own retail distribution service territories to construct transmission facilities selected in a regional transmission plan. This order will directly affect our rights to build 161kV and above transmission facilities within our retail service territory.
Order No. 1000 also directed transmission providers to develop policy and procedures for regional and interregional transmission planning as well as regional and interregional transmission cost allocation (see "SPP Regional Transmission Development" below) for approved transmission projects. We continue to participate in the SPP processes to understand the impact of these FERC orders on our ability to construct new facilities within our service territory as well as their influence on promoting construction of transmission projects on or near our borders with our neighbors. SPP has completed and filed with the FERC a required interregional policy and procedure compliance filing, with implementation to occur once FERC has approved the filing. FERC's decision on SPP's Order No. 1000 interregional compliance filing is pending.
SPP Regional Transmission Development:    In 2010, SPP received FERC approval to implement a new highway/byway cost allocation methodology for new SPP approved transmission projects. We actively monitor SPP's policy to allocate the costs of transmission projects to its members. We estimate our net transmission costs will increase between $3 and $4 million in 2015 over what we currently recover in rates as a result of SPP's allocation methodology. We have cost recovery mechanisms in place in our Arkansas and Oklahoma jurisdictions that allow us to recover the additional SPP transmission costs outside the traditional rate case process. Currently no mechanism is in place to timely recover additional costs resulting from the portion of these transmission projects allocated to us other than through the traditional rate case process in our Missouri and Kansas jurisdictions. Within our current rate case proceeding in Missouri, we have requested a transmission recovery mechanism to be implemented effective August 2015.
The highway/byway allocation methodology requires the costs of SPP approved transmission projects to be allocated to 1) members across the entire SPP region; 2) members within certain localized service territories or zones; or 3) a combination of both regional and zonal allocation. The allocation is based on project voltage, as follows:
Transmission Project Voltage		Regional Funding Percentage			Zonal Funding Percentage
300 kV and Above			100.0	%		0.0	%
100kV to 299kV			33.3	%		66.7	%
Below 100 kV			0.0	%		100.0	%
SPP's formal regional cost allocation review and benefit to cost imbalance analysis process is ongoing and being formalized within SPP's Open Access Transmission Tariff in 2015. This process will evaluate the long term projected benefits against the allocated costs of transmission projects to determine if remedies (cost reductions or benefit increases due to specific transmission projects) are needed for our customers. SPP will evaluate potential equity improvement remedies in its Integrated Transmission Planning (ITP), Inter-regional Transmission Planning (Order 1000) and regional cost allocation review (RCAR) processes with recommendations expected in July 2015.
SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement and Plum Point Delivery:    On December 19, 2013, Entergy voluntarily integrated its generation, transmission, and load into the MISO regional transmission organization. Based on the current terms and conditions of MISO membership, Entergy's participation in MISO will not be beneficial to our customers as it will increase transmission delivery costs for our Plum Point power station as well as utilize our transmission system without compensation.
As a result, SPP and its members have undertaken certain actions with FERC to address these issues and reduce the costs to our customers. FERC has set settlement evidentiary hearings for these issues. The dispute is likely to move into litigation hearings before the FERC if the settlement process is unsuccessful.
Gas Segment
Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers.
Other — Rate Matters
In accordance with ASC guidance on regulated operations, we currently have deferred approximately $0.5 million of expense related to rate cases under other non-current assets and deferred charges. These amounts will be amortized over varying periods based upon the completion of the specific cases. Based on past history, we expect all these expenses to be recovered in rates.

SHAREHOLDERS_EQUITY

SHAREHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2014
SHAREHOLDERS' EQUITY
Shareholders' Equity	4.     Shareholders' Equity
	Shelf Registration
	We have a $200.0 million shelf registration statement with the SEC, effective December 13, 2013, covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. As of December 31, 2014, $200.0 million remains available for issuance under this shelf registration statement. However, as a result of our regulatory approvals, of the original $200.0 million, $150.0 million was available for first mortgage bonds with $90.0 million remaining available after the issuance of $60 million in first mortgage bonds on December 1, 2014. We plan to use proceeds from offerings made pursuant to this shelf to fund capital expenditures, refinance existing debt or general corporate needs during the three-year effective period.
	Employee Benefit Plans
	Our Employee Stock Purchase Plan permits the grant to eligible employees of options to purchase our common stock at a discounted price. As of December 31, 2014 and 2013, there were 820,838 and 127,774 shares available for issuance in this plan, respectively. Under our Employee 401(k) Plan and ESOP we match a percentage of each employee's deferrals by contributing shares of our common stock. At December 31, 2014 and 2013 there were 196,399 and 256,448 shares available to be issued respectively. (See Note 7 for further discussion of these plans).
	Equity Based Compensation
	We have several stock-based awards programs, which are described in Note 8. Our 2015 Stock Incentive Plan provides for grants of up to 500,000 shares of common stock through January 2025.
	Dividends
	Holders of our common stock are entitled to dividends if, as and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.
	The following table shows our diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance for the years ended December 31, 2014, 2013 and 2012:
	(in millions, except per share amounts)	2014		2013		2012
	Diluted earnings per share	$	1.55	$	1.48	$	1.32
	Dividends paid per share	$	1.025	$	1.005	$	1.00
	Total dividends paid	$	44.4	$	43.0	$	42.3
	Retained earnings year-end balance	$	90.3	$	67.6	$	47.1
	Under Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax. However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the Federal Power Act (FPA) prohibits the payment by a utility of dividends from any funds "properly included in capital account". There are no additional rules or regulations issued by the FERC under the FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive analysis of the specific facts and circumstances surrounding the utility and the dividend in question, with particular focus on the impact of the proposed dividend on the liquidity and financial condition of the utility.
	In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. The EDE Mortgage permits the payment of any dividend or distribution on, or purchase of, shares of our common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1.
	Preferred and Preference Stock
	We have 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A Participating Preference Stock, none of which have been issued. We have 5 million shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2014 or 2013.

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2014
LONG-TERM DEBT.
LONG-TERM DEBT	5.     LONG-TERM DEBT
	At December 31, 2014 and 2013, the balance of long-term debt outstanding was as follows (in thousands):
			2014			2013
	First mortgage bonds (EDE):
	7.20% Series due 2016		$	25,000		$	25,000
	6.375% Series due 2018(1)			90,000			90,000
	4.65% Series due 2020(1)			100,000			100,000
	3.58% Series due 2027(1)			88,000			88,000
	3.73% Series due 2033(1)			30,000			30,000
	5.875% Series due 2037(1)			80,000			80,000
	5.20% Series due 2040(1)			50,000			50,000
	4.32% Series due 2043(1)			120,000			120,000
	4.27% Series due 2044(1)			60,000			—
	First mortgage bonds (EDG):
	6.82% Series due 2036(1)			55,000			55,000
				698,000			638,000
	Senior Notes, 6.70% Series due 2033(1)			62,000			62,000
	Senior Notes, 5.80% Series due 2035(1)			40,000			40,000
	Other			4,167			4,441
	Less unamortized net discount			(686	)		(739	)
				803,481			743,702
	Less current obligations under capital lease			(292	)		(274	)
	TOTAL LONG-TERM DEBT		$	803,189		$	743,428
	-1	We may redeem some or all of the notes at any time at 100% of their principal amount, plus a make-whole premium, plus accrued and unpaid interest to the redemption date.
	Debt Financing Activities
	On October 15, 2014, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 4.27% First Mortgage Bonds due December 1, 2044. A delayed settlement occurred on December 1, 2014. Interest is payable semi-annually on the bonds on each December 1 and June 1, commencing June 1, 2015. The bonds may be redeemed at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for general corporate purposes. The bonds have not been, and will not be, registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage.
	On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due 2033 and $120.0 million of 4.32% First Mortgage Bonds due 2043. The delayed settlement occurred on May 30, 2013. The interest is payable semi-annually on the bonds on each May 30 and November 30, commencing November 30, 2013. The bonds may be redeemed at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. A portion of the proceeds were used to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013. The remaining proceeds were used for general corporate purposes. The bonds have not been registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage.
	Shelf Registration
	We have a $200 million shelf registration statement with the SEC that is effective for three years from December 13, 2013. See Note 4.
	EDE Mortgage Indenture
	Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) are subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Based on this limit and our current level of outstanding first mortgage bonds, we are limited to the issuance of $357 million of new first mortgage bonds. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the year ended December 31, 2014 would permit us to issue approximately $615.9 million of new first mortgage bonds based on this test with an assumed interest rate of 5.5%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2014, we had retired bonds and net property additions which would enable the issuance of at least $952.5 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2014, we are in compliance with all restrictive covenants of the EDE Mortgage.
	EDG Mortgage Indenture
	The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300 million. Substantially all of the property, plant and equipment of The Empire District Gas Company are subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2 to 1. As of December 31, 2014, this test would allow us to issue approximately $19.7 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.
	Our long-term debt obligations over the next five years are as follows (in thousands):
			Payments Due By Period
	Long-Term Debt Payout Schedule		Total			Regulated			Capital Lease
	(Excluding Unamortized Discount					Entity Debt			Obligations
	(in thousands)					Obligations
	2015		$	292		$	—		$	292
	2016			25,308			25,000			308
	2017			325			—			325
	2018			90,347			90,000			347
	2019			371			—			371
	Thereafter			687,524			685,000			2,524
	Total long-term debt obligations			804,167		$	800,000		$	4,167
	Less current obligations and unamortized discount			978
	TOTAL LONG-TERM DEBT		$	803,189

SHORTTERM_BORROWINGS

SHORT-TERM BORROWINGS	12 Months Ended
	Dec. 31, 2014
SHORT-TERM BORROWINGS
SHORT-TERM BORROWINGS	6.     SHORT-TERM BORROWINGS
	At December 31, 2014, total short-term borrowings consisted of $44.0 million in commercial paper and no borrowings from our line of credit. During 2014 and 2013 our short-term borrowings outstanding averaged (in millions)
		2014			2013
	Average borrowings outstanding	$	30.0		$	8.7
	Highest month end balance	$	77.0		$	29.0
	The weighted average interest rates and the weighted average interest rate of borrowings outstanding at December 31, 2014 and 2013 were:.
		2014			2013
	Weighted average interest rate		0.38	%		0.69	%
	Weighted average interest rate of borrowings outstanding		0.44	%		0.33	%
	On October 20, 2014, we entered into a new $200 million 5-year Credit Agreement replacing the former $150 million Third Amended and Restated Unsecured Credit Agreement dated January 17, 2012 which had a January 2017 expiration date. This new agreement may be used for working capital, commercial paper back-up and general corporate purposes. The credit facility includes a $20 million swingline loan sublimit, a $20 million sublimit for letters of credit issuance and, subject to bank approval, a $75 million accordion feature and two one-year extensions of the credit facility's maturity date.
	Interest on borrowings under the new facility accrues at a rate equal to, at our option, (i) the highest of (A) the agent prime rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, in each case, plus a margin or (ii) one month, two month, three month or six month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility is 1.025%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings, which is currently 0.175%. In addition, upon entering into the new credit facility, we paid upfront fees to the revolving credit banks of $0.3 million in the aggregate.
	The new credit facility requires our total indebtedness to be less than 65.0% of our total capitalization at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2014, we were in compliance with this covenant as our ratio of total indebtedness to total capitalization was 0.52 to 1.0. The new credit facility is also subject to cross-default if we default on more than $25 million in the aggregate on our other indebtedness. As of December 31, 2014, we were not in default under any of our debt obligations.
	The new credit agreement does not legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under the agreement at December 31, 2014; however, $44.0 million was used to back up our outstanding commercial paper.

RETIREMENT_AND_OTHER_EMPLOYEE_

RETIREMENT AND OTHER EMPLOYEE BENEFITS	12 Months Ended
	Dec. 31, 2014
Retirement and other employee benefits
Retirement and other employee benefits	7.     RETIREMENT AND OTHER EMPLOYEE BENEFITS
	We record retirement benefits in accordance with the ASC guidance on accounting for pension and other postretirement benefits, and have recorded the appropriate liabilities to reflect the unfunded status of our benefit plans, with offsetting entries to a regulatory asset, because we believe it is probable the unfunded amount of these plans will be afforded rate recovery. Additionally, the MPSC agreed that the effects of purchase accounting entries related to pension and other post-retirement benefits would be recoverable in future rate proceedings. These amounts, which are related to EDG, were recorded as regulatory assets and are being amortized. The tax effects of these entries are reflected as deferred tax assets and liabilities and regulatory liabilities.
	Annually we evaluate the discount rate, retirement age, compensation rate increases, expected return on plan assets, healthcare cost trend rate, and other actuarial assumptions related to pension benefit and post-retirement medical plan. We utilize an interest rate yield curve to determine an appropriate discount rate. The yield curve is constructed based on the yields on over 500 high-quality, non-callable corporate bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of the Empire pension plan and develop a single point discount rate matching the plan's payout structure. In evaluating these assumptions, many factors are considered, including, current market conditions, asset allocations, changes in demographics and the views of leading financial advisors and economists. In evaluating the expected retirement age assumption, we consider the retirement ages of past employees eligible for pension and medical benefits together with expectations of future retirement ages. It is reasonably possible that changes in these assumptions will occur in the near term and, due to the uncertainties inherent in setting assumptions, the effect of such changes could be material to the Company's consolidated financial statements. A roll forward technique is used to value the year ending pension obligations. The roll forward technique values the year-end obligation by rolling forward the beginning-of-year obligation using the demographic assumptions disclosed below. The economic assumptions are updated as of the end of the year. All of the benefit plans have been measured as of December 31, 2014, consistent with previous years. See Note 1.
	Pensions
	Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. Effective on January 1, 2014, the plan was amended to include a cash balance benefit formula. Employees hired on or after January 1, 2014 will accrue benefits based on a cash balance methodology. Employees hired prior to January 1, 2014 were given a one-time option to convert to the cash balance methodology, or remain with our traditional average annual basic earnings formula, by December 31, 2014. Both benefit formulas allow for a lump sum distribution of vested benefits. Lump sum distributions totaled approximately $9.0 million and $7.0 million during 2014 and 2013, respectively, and did not require settlement accounting according to ASC 715.
	Annual contributions to the plan are at least equal to the greater of either minimum funding requirements of ERISA or the accrued cost of the Plan, as required by the Missouri Public Service Commission. We also have a supplemental retirement program ("SERP") for designated officers of the Company, which we fund from Company funds as the benefits are paid.
	Our net pension liability increased $20.6 million in 2014, which was recorded as an increase in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The increase in the liability is primarily due to a significant actuarial loss resulting from decreases in discount rates and the adoption of a new mortality table. Our contribution is estimated to be approximately $12.8 million for 2015. We expect future pension funding commitments to continue at least at the level of our accrued cost, as required by our regulator. The actual minimum funding requirements will be determined based on the results of the actuarial valuations and, in the case of 2016, the performance of our pension assets during 2015.
	Expected benefit payments are as follows (in millions):
	Year		Payments from			Payments from
			Trust			Company Funds
	2015		$	25.0		$	0.5
	2016			22.0			0.5
	2017			22.1			0.5
	2018			20.8			0.5
	2019			19.5			0.5
	2020 – 2024			97.3			3.0
	Other Postretirement Benefits (OPEB)
	We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors through trusts we have established. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service. Employees hired after January 1, 2014 will be offered unsubsidized retiree healthcare benefits upon retirement.
	Our net liability increased $19.9 million in 2014, which was recorded as an increase in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The increase in the liability is primarily due to a significant actuarial loss resulting from decreases in discount rates and the adoption of a new mortality table. Our funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. We expect to be required to fund approximately $5.0 million in 2015.
	Estimated benefit payments are as follows (in millions):
	Year		Payments from			Expected Federal			Payments from
			Trust			Subsidy			Company Funds
	2015		$	2.8		$	0.3		$	0.1
	2016			3.1			0.4			0.2
	2017			3.4			0.4			0.1
	2018			3.7			0.5			0.2
	2019			4.0			0.5			0.1
	2020 – 2024			24.4			3.3			0.8
	The following tables set forth the Company's benefit plans' projected benefit obligations, the fair value of the plans' assets and the funded status (in thousands).
	Reconciliation of Projected Benefit Obligations:
			Pension						SERP						OPEB
			2014			2013			2014			2013			2014			2013
	Benefit obligation at beginning of year		$	225,131		$	248,004		$	7,108		$	6,365		$	85,332		$	94,738
	Service cost			6,467			7,454			153			135			2,601			2,941
	Interest cost			10,819			10,063			387			315			4,360			3,827
	Amendments			(7,753	)					(45	)					—
	Net actuarial (gain)/loss			36,742			(23,300	)		1,890			604			20,347			(12,767	)
	Plan participant's contribution			—			—			—			—			850			949
	Benefits and expenses paid			(19,527	)		(17,090	)		(338	)		(311	)		(3,897	)		(4,396	)
	Federal subsidy			—			—			—			—			306			40
	Benefit obligation at end of year		$	251,879		$	225,131		$	9,155		$	7,108		$	109,899		$	85,332
	Reconciliation of Fair Value of Plan Assets:
			Pension						SERP						OPEB
			2014			2013			2014			2013			2014			2013
	Fair value of plan assets at beginning of year		$	186,547		$	160,175		$	—		$	—		$	79,098		$	67,667
	Actual return on plan assets — gain/(loss)			14,319			27,260			—			—			5,030			10,361
	Employer contribution			11,335			16,202			—			—			2,258			4,360
	Benefits paid			(19,527	)		(17,090	)		—			—			(3,707	)		(4,229	)
	Plan participant's contribution			—			—			—			—			804			901
	Federal subsidy			—			—			—			—			293			38
	Fair value of plan assets at end of year		$	192,674		$	186,547		$	—		$	—		$	83,776		$	79,098
	Reconciliation of Funded Status:
			Pension						SERP						OPEB
			2014			2013			2014			2013			2014			2013
	Fair value of plan assets		$	192,674		$	186,547		$	—		$	—		$	83,776		$	79,098
	Projected benefit obligations			(251,879	)		(225,131	)		(9155	)		(7,108	)		(109,899	)		(85,332	)
	Funded status		$	(59,205	)	$	(38,584	)	$	(9,155	)	$	(7,108	)	$	(26,123	)	$	(6,234	)
	The employee pension plan accumulated benefit obligation at December 31, 2014 and 2013 is presented in the following table (in thousands):
			Pension Benefits						SERP
			2014			2013			2014			2013
	Accumulated benefit obligation		$	227,928		$	201,258		$	7,160		$	5,702
	Amounts recognized in the balance sheet consist of (in thousands):
			Pension						SERP						OPEB
			2014			2013			2014			2013			2014			2013
Accounts Payable and Accrued Liabilities		$	—		$	—		$	481		$	372		$	139		$	147
Pension and other postretirement benefit obligation		$	59,205		$	38,584		$	8,674		$	6,736		$	25,984		$	6,087
Net periodic benefit pension cost for 2014, 2013 and 2012, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset (see Note 3), is comprised of the following components (in thousands):
Net Periodic Pension Benefit Cost:
		Pension									OPEB
		2014			2013			2012			2014			2013			2012
Service cost		$	6,467		$	7,454		$	6,261		$	2,601		$	2,941		$	2,401
Interest cost			10,819			10,063			10,258			4,360			3,827			4,037
Expected return on plan assets			(13,105	)		(12,428	)		(12,309	)		(4,801	)		(4,353	)		(4,135	)
Amortization of prior service cost/(benefit)(1)			418			532			531			(1,011	)		(1,011	)		(1,011	)
Amortization of actuarial loss(1)			6,611			10,445			7,935			967			2,261			1,661
Net periodic benefit cost		$	11,210		$	16,066		$	12,676		$	2,116		$	3,665		$	2,953
Net Periodic Pension Benefit Cost:
		SERP
		2014			2013			2012
Service cost		$	153		$	135		$	51
Interest cost			387			315			263
Expected return on plan assets			—			—			—
Amortization of prior service cost/(benefit)(1)			(8	)		(8	)		(8	)
Amortization of actuarial loss(1)			504			567			389
Net periodic benefit cost		$	1,036		$	1,009		$	695
-1	Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.
The tables below present other changes in plan assets and benefit obligations recognized in the regulatory asset accounts for the year (in thousands).
					Amount Recognized
Regulatory Assets		Beginning			Current Year			Amortization			Current Year			Amortization of			Ending
		Balance			Actuarial Loss			of Actuarial			Prior Service			Prior Service			Balance
		12/31/13						Loss			Credit			(Cost)/Credit			12/31/14
Pension		$	56,709			35,529			(6,611	)		(7,753	)		(418	)	$	77,456
SERP		$	4,188			1,890			(504	)		(45	)		8		$	5,537
OPEB		$	285			20,117			(967	)		—			1,011		$	20,446
					Amount Recognized
Regulatory Assets		Beginning			Current Year			Amortization			Amortization of			Ending
		Balance			Actuarial			of Actuarial			Prior Service			Balance
		12/31/12			(Gain)/Loss			Loss			(Cost)/Credit			12/31/13
Pension		$	105,818			(38,132	)		(10,445	)		(532	)	$	56,709
SERP		$	4,143			604			(567	)		8		$	4,188
OPEB		$	20,311			(18,776	)		(2,261	)		1,011		$	285
The following table presents the amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost. It also shows the amounts expected to be recognized in the subsequent year. The following table presents those items for the employee pension plan and other benefits plan at December 31, 2014, and the subsequent twelve-month period (in thousands):
		Pension Benefits						SERP						OPEB
		2014			Subsequent			2014			Subsequent			2014			Subsequent
					Period						Period						Period
Net actuarial loss		$	84,178		$	9,380		$	5,595		$	560		$	23,030		$	2,725
Prior service cost (benefit)			(6,722	)		(630	)		(58	)		(43	)		(2,584	)		(1,011	)
Total		$	77,456		$	8,750		$	5,537		$	517		$	20,446		$	1,714
The measurement date used to determine the pension and other postretirement benefits is December 31. The assumptions used to determine the benefit obligation and the periodic costs are as follows:
Weighted-average assumptions used to determine the benefit obligation as of December 31:
		Pension						OPEB
		Benefits
		2014			2013			2014			2013
Discount rate			4.06	%		4.90	%		4.15	%		5.00	%
Rate of compensation increase			3.50	%		3.50	%		3.50	%		3.50	%
Weighted-average assumptions used to determine the net benefit cost (income) as of January 1:
		Pension Benefits									OPEB
		2014			2013			2012			2014			2013			2012
Discount rate			4.90	%		4.00	%		4.70	%		5.00	%		4.11	%		4.90	%
Expected return on plan assets			7.75	%		7.75	%		7.90	%		6.52	%		6.52	%		6.65	%
Rate of compensation increase			3.50	%		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%
The expected long-term rate of return assumption was based on historical return and adjusted to estimate the potential range of returns for the current asset allocation. The assumed 2014 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 7.0%. Each trend rate decreases 0.50% through 2019 to an ultimate rate of 5.0% in 2019 and subsequent years.
The healthcare cost trend rate affects projected benefit obligations. A 1% change in assumed healthcare cost growth rates would have the following effects (in thousands):
		1% Increase			1% Decrease
Effect on total of service and interest cost		$	1,395		$	(1,084	)
Effect on post-retirement benefit obligation		$	19,135		$	(14,983	)
Fair value measurements of plan assets
See Note 15 for a discussion of fair value measurements. The Company believes that it is appropriate for the pension fund to assume a moderate degree of investment risk with diversification of fund assets among different classes (or types) of investments, as appropriate, as a means of reducing risk. Although the pension fund can and will tolerate some variability in market value and rates of return in order to achieve a greater long-term rate of return, primary emphasis is placed on preserving the pension fund's principal. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company's Investment Committee. The following is a description of the valuation methodologies used for assets measured at fair value using significant other observable, or significant unobservable inputs.
Short-term investments:    Valued at cost, which approximates fair value.
Common/Collective trusts:    Valued at the fair value based on audited financials of the trusts.
U.S. corporate and foreign issue debt:    Valued at quoted market prices when available in an active market. If quoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows.
Equity long/short hedge funds:    Valued at the net asset value reported in the annual audited financial statements and updated monthly based on changes in the value of the underlying funds reported by the fund manager.
Pension plan assets
We utilize fair value in determining the market-related values for the different classes of our pension plan assets. The market-related value is determined based on smoothing actual asset returns in excess of (or less than) expected return on assets over a 5-year period.
The Company's primary investment goals for pension fund assets are based around four basic elements:
1	Preserve capital,
2	Maintain a minimum level of return equal to the actuarial interest rate assumption,
3	Maintain a high degree of flexibility and a low degree of volatility, and
4	Maximize the rate of return while operating within the confines of prudence and safety.
Asset Allocation
We have adopted an investment strategy referred to as a de-risking glide path to increase the fixed income allocation as the plan's funded status improves. As the pension plan reaches set funded status milestones, the plan's assets will be rebalanced to shift more assets from equity to fixed income. Based on the plan's progress with this strategy, the target investment allocation for pension fund assets is approximately 72% equities and 28% fixed income securities. However, these allocations are permitted to vary within the following ranges: 60% – 80% for equities and 20% – 40% for fixed income securities. Money market funds are permitted within the fixed income category. Investment managers may generally hold up to 10% cash in their portfolios although this limit may be exceeded if market conditions warrant.
The following fair value hierarchy table presents information about the pension fund assets measured at fair value as of December 31, 2014 and December 31, 2013 (in thousands):
		Fair Value Measurements as of December 31, 2014
		Quoted Prices			Significant			Significant			Total			Percentage
		in Active			Other			Unobservable						of Plan
		Markets for			Observable			Inputs						Assets
		Identical			Inputs			(Level 3)
		Assets			(Level 2)
		(Level 1)
Short term investments		$	—		$	70		$	—		$	70			0.0	%
Equity securities
Common collective trusts			—			91,530			—			91,530			47.5	%
Fixed income
Common collective trust			—			62,646			—			62,646			32.5	%
Other types of investments
Equity long/short hedge funds			—			—			38,428			38,428			20.0	%
		$	—		$	154,246		$	38,428		$	192,674			100.0	%
		Fair Value Measurements as of December 31, 2013
		Quoted Prices			Significant			Significant			Total			Percentage
		in Active			Other			Unobservable						of Plan
		Markets for			Observable			Inputs						Assets
		Identical			Inputs			(Level 3)
		Assets			(Level 2)
		(Level 1)
Short term investments		$	74		$	—		$	—		$	74			0.1	%
Equity securities
Common collective trusts			—			104,713			—			104,713			56.1	%
Fixed income
Common collective trust			—			45,031			—			45,031			24.1	%
Other types of investments
Equity long/short hedge funds			—						36,729			36,729			19.7	%
		$	74		$	149,744		$	36,729		$	186,547			100.0	%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — December 31,
		2014			2013
		Equity long/short			Equity long/short
		hedge funds			hedge funds
Beginning Balance, January 1,		$	36,729		$	28,885
Actual return on plan assets:
Relating to assets still held at the reporting date			1,382			(356	)
Relating to assets sold during the period			1,491			4,583
Purchases			9,700			26,500
Sales			(10,874	)		(22,883	)
Settlements			—			—
Transfers into and (out of) Level 3			—			—
Ending Balance, December 31,		$	38,428		$	36,729
Permissible Investments
Listed below are the investment vehicles specifically permitted:
Permissible Investments
Equity Oriented		Fixed Income Oriented and Real Estate
		
Common Stocks		Bonds (including US Government and Agencies)
		
Preferred Stocks (minimum "A-rated" by Moody's or S&P)		Corporate Bonds (minimum quality rating of Baa by Moody's or BBB by S&P)
		
American Depository Receipts		Comingled bond funds (25% max. allocation to high yield)
		
Convertible Preferred Stocks		Foreign Government Bonds
		
Convertible Bonds		GIC's, BIC's
		
Covered Options		Commercial Paper (rated A1 by S&P or P1 by Moody's)
		
Hedged Equity Funds of Funds		Certificates of Deposit in institutions with FDIC/FSLIC protection
		
		Money Market Funds/Bank STIF Funds
		
		Real Estate — Publicly Traded
The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.
Those investments prohibited by the Investment Committee without prior approval are:
Prohibited Investments Requiring Pre-approval
		
Privately Placed Securities		Warrants
		
Commodities Futures		Short Sales
		
Securities of Empire District (except in the hedged equity funds of funds or commingled funds)		Index Options
		
Restricted Stock		Letter Stock
OPEB plan assets
The Company's primary investment goals for the component of the OPEB fund used to pay current benefits are liquidity and safety. The primary investment goals for the component of the OPEB fund used to accumulate funds to provide for payment of benefits after the retirement of plan participants are preservation of the fund with a reasonable rate of return. The target allocation for plan assets is 60% equities and 40% fixed income, although, at any given time, up to 10% of either category may be invested in cash equivalents. The 10% cash limitation may be exceeded if market conditions warrant. Allocations may also vary within the following ranges: 44% – 76% equities and 36% – 44% fixed income securities. The following fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2014 and December 31, 2013 (in thousands):
		Fair Value Measurements as of December 31, 2014
		Quoted Prices			Significant			Significant			Total			Percentage
		in Active			Other			Unobservable						of Plan
		Markets for			Observable			Inputs						Assets
		Identical			Inputs			(Level 3)
		Assets			(Level 2)
		(Level 1)
Equity securities
Common collective trusts		$	—		$	47,690		$	—		$	47,690			56.9	%
Fixed income
Common collective trusts			—			33,708			—			33,708			40.2	%
Other types of investments
Common collective trusts			—			2,453			—			2,453			2.9	%
		$	—		$	83,851		$	—		$	83,851
Payable for securities purchased												(75	)		0	%
											$	83,776			100	%
		Fair Value Measurements as of December 31, 2013
		Quoted Prices			Significant			Significant			Total			Percentage
		in Active			Other			Unobservable						of Plan
		Markets for			Observable			Inputs						Assets
		Identical			Inputs			(Level 3)
		Assets			(Level 2)
		(Level 1)
Cash and cash equivalents		$	1,317		$	—		$	—		$	1,317			1.7	%
Fixed income
U.S. corporate debt			—			17,592			—			17,592			22.2	%
Foreign debt			—			2,871			—			2,871			3.6	%
Mutual funds — fixed income			8,325			—			—			8,325			10.5	%
Equity securities
U.S. equity			27,779			—			—			27,779			35.1	%
International equity			9,316			—			—			9,316			11.8	%
Mutual funds — equity			11,633			—			—			11,633			14.7	%
		$	58,370		$	20,463		$	—			78,833
Accrued interest & dividends												265			0.4	%
											$	79,098			100	%
The Company's guideline in the management of this fund is to endorse a long-term approach, but not expose the fund to levels of volatility that might adversely affect the value of the assets. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company's Investment Committee.
Permissible Investments
Listed below are the investment vehicles specifically permitted:
Permissible Investments
Equity		Fixed Income
		
Common Stocks		Cash-Equivalent Securities with a maturity of one-year or less, including: money market funds, US Government and Agency securities, certificates of deposit or banker's acceptances issued by domestic banks with FDIC protection and commercial paper rated A1 by S&P or P1 by Moody's
		
Preferred Stocks		Government Bonds
		
		Money Market Funds / Bank STIF Funds
		
		Certificates of Deposit in institutions with FDIC protection
		
		Corporate Bonds (minimum quality rating of A Baa by Moody's or BBB by S&P at time of issuance)
The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.
Listed below are those investments prohibited by the Investment Committee:
Prohibited Investments
		
Privately Placed Securities		Margin Transactions
		
Securities of Empire District		Options (other than "covered call options")
		
Derivatives		Lettered or Restricted Stock
		
Instrumentalities in violation of the Prohibited Transactions Standards of ERISA		Any other investment security which, in the opinion of the investment manager produces an imprudent risk to the fund
Employee Stock Purchase Plan
Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of December 31, 2014 and 2013, there were 820,838 and 127,774 shares available for issuance in this plan, respectively.
		2014			2013			2012
Subscriptions outstanding at December 31,			57,369			60,413			70,850
Maximum subscription price		$	21.43	-1	$	19.58		$	17.95
Shares of stock issued			56,942			68,099			65,919
Stock issuance price		$	19.58		$	17.95		$	17.27
-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			2012
Weighted average fair value of grants		$	3.07		$	2.78		$	3.19
Risk-free interest rate			0.10	%		0.14	%		0.17	%
Dividend yield			4.30	%		4.60	%		5.00	%
Expected volatility(1)			14.00	%		14.00	%		24.00	%
Expected life in months			12			12			12
Grant date			6/2/14			6/1/13			6/1/12
-1	One-year historic volatility
401(k) Plan and ESOP
Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to 25% of their annual compensation up to an Internal Revenue Service specified limit. For employees participating in the cash balance formula of the pension plan, discussed above, we match 100% of their deferrals, not to exceed 6% of the employee's eligible compensation. The first 3% of the matching contribution is made in shares of our common stock with the remaining portion made by contributing cash. For employees remaining with the traditional average annual basic earnings formula of the pension plan, we match 50% of their deferrals by contributing shares of our common stock, with such matching contributions not to exceed 3% of the employee's eligible compensation. We record the compensation expense at the time the quarterly matching contributions are made to the plan. At December 31, 2014 and 2013, there were 196,399 and 256,448 shares available to be issued, respectively.
		2014			2013			2012
Shares contributed			60,049			64,128			65,502
Deferred Compensation
Effective January 2015, we established a non-qualified Deferred Compensation Plan for the purpose of allowing executive officers who elect to participate in the qualifying cash balance option of the Pension plan to obtain retirement savings that are not available to them under the 401(k) plan.

EQUITY_COMPENSATION

EQUITY COMPENSATION	12 Months Ended
	Dec. 31, 2014
EQUITY COMPENSATION
Equity Compensation
	8.     Equity Compensation
	We have several stock-based awards and programs, which are described below. Performance-based restricted stock awards, time-vested restricted stock and stock options are valued as liability awards, in accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award.
	We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in thousands):
		2014			2013		2012
	Compensation expense	$	3,688		$	2,577	$	1,863
	Tax benefit recognized		1,359			929		649
	Stock Incentive Plans
	Our 2006 Stock Incentive Plan (the 2006 Incentive Plan), which was set to expire on December 31, 2015, was replaced by the 2015 Stock Incentive Plan (the 2015 Incentive Plan). The 2015 Incentive Plan was adopted by shareholders at the annual meeting on May 1, 2014 and provides for grants of up to 500,000 shares of common stock through January 2025. The 2015 Stock Incentive Plan permits (and the 2006 Incentive Plan permitted) grants of stock options and restricted stock to qualified employees and permits Directors and, if approved by the Compensation Committee of the Board of Directors, qualified employees to receive common stock in lieu of cash. Certain executive officers and other senior managers applied to receive annual incentive awards related to 2012, 2013 and 2014 performance in the form of Empire common stock rather than cash. These requests were granted by the Compensation Committee of the Board of Directors under the terms of our 2006 Stock Incentive Plan. The terms and conditions of any option or stock grant are determined by the Board of Directors Compensation Committee, within the provisions of these Stock Incentive Plans.
	Time-Vested Restricted Stock Awards
	Beginning in 2011, we began granting, to qualified individuals, time-vested restricted stock awards that vest after a three-year period, in lieu of stock options. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminates during the vesting period because of death, retirement or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned, which is distributed six months following the date of termination, with the remainder of the award forfeited. If employment is terminated during the vesting period for reasons other than those listed above, the time-vested restricted stock awards will be forfeited on the date of the termination, unless the Board of Directors' Compensation Committee determines, in its sole discretion, that the participant is entitled to a pro-rata portion of the award.
	The fair value measurements for each grant year are noted in the following table:
		Fair Value of Grants Outstanding at
		December 31
		2014		2013
	Total unrecognized compensation cost (in millions)	$0.40		$0.20
	Recognition period	1.1 years to 2.1 years		0.1 years to 2.1 years
	Fair value	$26.82		$19.88
	No shares of time-vested restricted stock were granted in 2012 as a result of the limitation on incentive compensation in effect in 2011 given our 2011 dividend suspension. A summary of time vested restricted stock activity under the plan for 2014, 2013 and 2012 is presented in the table below:
		2014					2013					2012
		Number of			Weighted		Number of			Weighted		Number Of			Weighted
		Shares			Average		Shares			Average		Shares			Average
					Grant Date					Grant Date					Grant Date
					Fair Value					Fair Value					Fair Value
	Outstanding at January 1,		24,900		$	21.42		3,300		$	21.84		3,433		$	21.84
	Granted		22,600		$	22.4		21,600		$	21.36		—			—
	Distributed		(4,010	)	$	21.77		—			—		(133	)	$	20.13
	Forfeited		(2,490	)	$	21.99		—			—		—			—
	Outstanding at December 31,		41,000		$	21.89		24,900		$	21.42		3,300		$	21.84
	Vested during the year		6,500		$	21.86		—			—		—			—
	Performance-Based Restricted Stock Awards
	Performance-based restricted stock awards are granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of the restricted period assuming performance criteria are met. The performance measure for the award is the total return to our shareholders over a three-year period compared with an investor-owned utility peer group. The threshold level of performance under the 2012, 2013 and 2014 grants was set at the 20th percentile level of the peer group, target at the 50th percentile level, and the maximum at the 80th percentile level. Shares would be earned at the end of the three-year performance period as follows: 100% of the target number of shares if the target level of performance is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above the maximum, with the number of shares interpolated between these levels. However, no shares would be payable if the threshold level is not reached. The fair value of the outstanding restricted stock awards was estimated as of December 31, 2014, 2013 and 2012 using a Monte Carlo option valuation model. The assumptions used in the model for each grant year are noted in the following table:
		Fair Value of Grants Outstanding at December 31,
		2014		2013		2012
	Risk-free interest rate	0.25% to 0.67%		0.13% to 0.38%		0.16% to 0.25%
	Expected volatility of Empire stock	14.50%		20.20%		20.60%
	Expected volatility of peer group stock	12.4% to 24.8%		12.3% to 27.5%		12.4% to 29.2%
	Expected dividend yield on Empire stock	3.50%		4.50%		4.90%
	Expected forfeiture rates	3%		3%		3%
	Plan cycle	3 years		3 years		3 years
	Fair value percentage	140.0% to 157.0%		0.0% to 108.0%		18.0% to 96.0%
	Weighted average fair value per share	$43.80		$18.47		$10.94
	Non-vested performance-based restricted stock awards (based on target number) as of December 31, 2014, 2013 and 2012 and changes during the year ended December 31, 2014, 2013 and 2012 were as follows:
		2014					2013					2012
		Number of			Weighted		Number of			Weighted		Number Of			Weighted
		Shares			Average		Shares			Average		Shares			Average
					Grant Date					Grant Date					Grant Date
					Fair Value					Fair Value					Fair Value
	Outstanding at January 1,		47,200		$	21.39		33,900		$	20.25		37,400		$	19.28
	Granted		27,000		$	22.4		26,300		$	21.36		10,000		$	20.97
	Awarded		—			—		(4,460	)	$	18.36		(7,823	)	$	18.12
	Not awarded		(10,900	)	$	21.84		(8,540	)	$	18.36		(5,677	)	$	18.12
	Nonvested at December 31,		63,300		$	21.74		47,200		$	21.39		33,900		$	20.25
	At December 31, 2014 and 2013, unrecognized compensation expense related to estimated outstanding awards was $1.1 million and $0.5 million, respectively.
	Stock Options
	Beginning in 2011, we began issuing time-vested restricted stock in lieu of stock options and dividend equivalents. Prior to 2011 stock options were issued with an exercise price equal to the fair market value of the shares on the date of grant. They became exercisable after three years and expired ten years after the date granted. Dividend equivalent awards, under which dividend equivalents accumulated during the vesting period, were also issued to recipients of the stock options. Participants' options and dividend equivalents that were not vested were forfeited when participants left Empire, except for terminations of employment under certain specified circumstances. There were no stock options or dividend equivalents granted in 2014, 2013, or 2012, and all outstanding options were exercised prior to December 31, 2014.
	Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. There were no outstanding options at December 31, 2014. The fair value of the outstanding options was estimated as of December 31, 2013 and 2012, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:
		Fair Value of Grants Outstanding at December 31,
		2014		2013		2012
	Risk-free interest rate	—		0.10% to 0.38%		0.11% to 0.44%
	Dividend yield	—		4.50%		4.90%
	Expected volatility	—		24.00%		24.00%
	Expected life in months	—		6.5 to 24.5		78
	Market value	—		$22.69		$20.38
Weighted average fair value per option	—		$1.57		$1.34
A summary of option activity under the plan during the years ended December 31, 2014, 2013 and 2012 is presented below:
	2014					2013					2012
	Options			Weighted		Options			Weighted		Options			Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
				Price					Price					Price
Outstanding at January 1,		112,500		$	23.27		163,300		$	22.13		190,300		$	21.56
Granted		—			—				$	—		0		$	—
Exercised		112,500		$	24.58		(50,800	)	$	21.78		(27,000	)	$	18.12
Outstanding at December 31,		—					112,500		$	23.27		163,300		$	22.13
Exercisable, end of year		—					112,500		$	23.27		128,500		$	23.15
The intrinsic value of the unexercised options is the difference between the Company's closing stock price on the last day of the period and the exercise price multiplied by the number of in-the-money options, had all option holders exercised their options on the last day of the period. The intrinsic value is zero if such closing price is less than the exercise price. The table below shows the aggregate intrinsic values at December 31, 2014, 2013, and 2012:
	2014		2013		2012
Aggregate intrinsic value (in millions)	—		Less than $0.1		$0.10
Weighted-average remaining contractual life of outstanding options	—		2.1 years		3.2 years
Range of exercise prices	—		$21.92 to $23.81		$18.36 to $23.81
Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	—		—		Less than $0.1
Recognition period	—		—		1 month
Stock Unit Plan for Directors
Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based compensation program for directors. This plan enhances our ability to attract and retain competent and experienced directors and allows the directors the opportunity to accumulate compensation in the form of common stock units. The Stock Unit Plan also provides directors the opportunity to convert previously earned cash retirement benefits to common stock units. All eligible directors who had benefits under the prior cash retirement plan converted their cash retirement benefits to common stock units.
As of December 31, 2014, a total of 900,000 shares were authorized under this plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock. The number of units granted annually is computed by dividing an annual credit (determined by the Compensation Committee) by the fair market value of our common stock on January 1 of the year the units are granted. Common stock unit dividends are computed based on the fair market value of our stock on the dividend's record date. We record the related compensation expense at the time we make the accrual for the directors' benefits as the directors provide services. Shares accrued to directors' accounts and shares available for issuance under this plan at December 31 are shown in the table below:
	2014			2013
Shares accrued to directors' accounts		164,085			154,402
Shares available for issuance		714,978			236,056
Units accrued for service and dividends as well as units redeemed for common stock at December 31 are shown in the table below:
	2014			2013		2012
Units accrued for service and dividends		30,765			34,252		30,426
Units redeemed for common stock		21,083			22,908		21,324

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2014
Income Taxes.
Income Taxes	9.     INCOME TAXES
	Income tax expense components for the years ended December 31 are as follows (in thousands):
			2014			2013			2012
	Current income taxes:
	Federal		$	(2,350	)	$	6,726		$	1,552
	State			(123	)		2,495			708
	TOTAL			(2,473	)		9,221			2,260
	Deferred income taxes:
	Federal			36,620			24,954			28,210
	State			5,216			3,554			4,018
	TOTAL			41,836			28,508			32,228
	Investment tax credit amortization			(143			(237			(329
					)			)			)
	TOTAL INCOME TAX EXPENSE		$	39,220		$	37,492		$	34,159
	Deferred Income Taxes
	Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows (in thousands):
			December 31,
	Deferred Income Taxes		2014			2013
	Current deferred tax assets, net(1)		$	19,200		$	7,222
	Non-current deferred tax liabilities, net			377,452			324,266
	NET DEFERRED TAX LIABILITIES		$	358,252		$	317,044
	-1	Current deferred tax assets are included in prepaid expenses and other on the balance sheets.
	Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows (in thousands):
			December 31,
	Temporary Differences		2014			2013
	Deferred tax assets:
	Plant related basis differences		$	25,349		$	23,344
	Net operating loss (NOL)			22,000			—
	Regulated liabilities related to income taxes			13,350			13,576
	Disallowed plant costs			1,754			1,841
	Gains on hedging transactions			1,260			1,324
	Pensions and other post-retirement benefits			1,175			544
	Carry forward of income tax credit			6,367			6,374
	Other			1,633			1,633
	Total deferred tax assets		$	72,888		$	48,636
	Deferred tax liabilities:
	Depreciation, amortization and other plant related differences		$	363,337		$	297,175
	Regulated assets related to income			37,180			37,806
	Loss on reacquired debt			3,828			4,085
	Amortization of intangibles			9,168			8,089
	Deferred construction accounting costs			6,082			6,977
	Other			11,545			11,548
	Total deferred tax liabilities			431,140			365,680
	NET DEFERRED TAX LIABILITIES		$	358,252		$	317,044
	Effective Income Tax Rates
	The difference between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing operations were as follows:
	Effective Income Tax Rates		2014			2013			2012
	Federal statutory income tax rate			35	%		35	%		35	%
	Increase (decrease) in income tax rate resulting from:
	State income tax (net of federal benefit)			3.1			3.1			3.1
	Investment tax credit amortization			(0.1	)		(0.2	)		(0.4	)
	Effect of ratemaking on property related differences			(1.7	)		(1.1	)		(0.2	)
	Other			0.6			0.3			0.5
	EFFECTIVE INCOME TAX RATE			36.9	%		37.1	%		38	%
	We do not have any unrecognized tax benefits as of December 31, 2014. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.
	The Tax Increase Prevention Act (the "Act") was signed into law on December 19, 2014. The Act restored several expired business tax provisions, including bonus depreciation for 2014. Our 2015 tax payments are expected to be higher than 2014 due to the expiration of bonus depreciation. However, we expect to utilize investment tax credits and net operating losses (NOLs) discussed below to partially offset the 2015 payments.
	We generated $22.0 million of tax NOLs during 2014, mainly due to bonus depreciation. These losses may be carried back two years and are also available to offset future taxable income until 2034.
	In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2. We utilized $0.7 million and $9.0 million of these credits on our 2012 and 2013 tax returns, respectively. Due to the passage of the Act, we were unable to use these credits on our 2014 tax return. We expect to use the remaining credits on our 2015 tax return. The tax credits will have no significant income statement impact because they will flow to our customers as we amortize the tax credits over the life of the plant.
	On September 13, 2013, the IRS and the Treasury Department released final regulations under Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014, and we plan to file a Form 3115 with the IRS with our 2014 income tax return to change our tax accounting method to comply with the regulations. It is anticipated that we will deduct approximately $33 million on our 2014 income tax return under IRS Code Section 481(a) as an adjustment required by the change in method of accounting. We plan to utilize the book capitalization method as allowable under the final regulations which we expect will have an immaterial impact on the effective tax rate.

COMMONLY_OWNED_FACILITIES

COMMONLY OWNED FACILITIES	12 Months Ended
	Dec. 31, 2014
COMMONLY OWNED FACILITIES
COMMONLY OWNED FACILITIES	10.   COMMONLY OWNED FACILITIES
	Iatan
	We own a 12% undivided interest in the coal-fired Units No. 1 and No. 2 at the Iatan Generating Station located near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. We are entitled to 12% of each unit's available capacity and are obligated to pay for that percentage of the operating costs of the units. KCP&L and KCP&L Greater Missouri Operations Co. own 70% and 18% respectively, of Unit 1, and 54% and 18%, respectively, of Unit 2. KCP&L operates the units for the joint owners.
	At December 31, 2014 and 2013, our property, plant and equipment accounts included the amounts in the following chart (in millions):
	Iatan		2014		2013
	Cost of ownership in plant in service		$	373.3	$	367.1
	Accumulated Depreciation		$	99.1	$	91.1
	Expenditures(1)		$	27.8	$	31.6
	-1	Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.
	State Line Combined Cycle Unit
	We and Westar Generating, Inc, ("WGI"), a subsidiary of Westar Energy, Inc., share joint ownership of a nominal 500-megawatt combined cycle unit at the State Line Power Plant (the "State Line Combined Cycle Unit"). We are responsible for the operation and maintenance of the State Line Combined Cycle Unit, and are entitled to 60% of the available capacity and are responsible for approximately 60% of its costs. At December 31, 2014 and 2013, our property, plant and equipment accounts included the amounts in the following chart (in millions):
	State Line Combined Cycle Unit		2014		2013
	Cost of ownership in plant in service		$	161.5	$	163.3
	Accumulated Depreciation		$	40.0	$	37.0
	Expenditures(1)		$	47.1	$	52.6
	-1	Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.
	Plum Point Energy Station
	We own a 7.52% undivided interest in the coal-fired Plum Point Energy Station located near Osceola, Arkansas. We are entitled to 7.52% of the station's capacity, and are obligated to pay for that percentage of the station's operating costs. At December 31, 2014 and 2013, our property, plant and equipment accounts included the amounts in the following chart (in millions):
	Plum Point Energy Station		2014		2013
	Cost of ownership in plant in service		$	108.3	$	108.2
	Accumulated Depreciation		$	9.4	$	7.3
	Expenditures(1)		$	8.1	$	11.3
	-1	Recognized in operating, maintenance and fuel expenditures excluding depreciation expense.
	All of the dollar amounts listed above represent our ownership share of costs.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies
Commitments and Contingencies	11.   COMMITMENTS AND CONTINGENCIES
	We are a party to various claims and legal proceedings arising out of the normal course of our business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company's defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.
	Coal, Natural Gas and Transportation Contracts
	The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of December 31, 2014 (in millions).
		Firm physical gas		Coal and coal
		and transportation		transportation
		contracts		contracts
	January 1, 2015 through December 31, 2015	$	26.6	$	26.2
	January 1, 2016 through December 31, 2017	$	42.9	$	29.5
	January 1, 2018 through December 31, 2019	$	33.3	$	22.8
	January 1, 2020 and beyond	$	49.6		—
	We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be placed in storage. The firm physical gas and transportation commitments are detailed in the table above.
	We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of December 31, 2014 are detailed in the table above.
	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 an additional 50 megawatts of capacity from Plum Point. Commitments under this agreement are approximately $289.9 million through August 31, 2039, the end date of the agreement. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the MPSC on July 1, 2013. It is not currently our intention to exercise this option in 2015.
	We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.
	We also have a 20-year contract, which began on December 15, 2005, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. We do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost.
	Payments for these agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations shown below.
	New Construction
	In December 2014 we completed an environmental retrofit at our Asbury plant. The retrofit project included the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This new equipment enables us to comply with the Mercury and Air Toxics Standard (MATS). Construction costs through December 31, 2014 were $110.9 million for the project to date, excluding AFUDC. Final cost is expected to be approximately $112 million, excluding AFUDC.
	We also have in place a contract with a third party vendor to complete engineering, procurement, and construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion will include the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. The Air Emission Source Construction Permit necessary for this project was issued by Kansas Department of Health and Environment on July 11, 2013. This conversion is currently scheduled to be completed in mid-2016 at a cost estimated to range from $165 million to $175 million, excluding AFUDC. This amount is included in our five-year capital expenditure plan. Construction costs, consisting of pre-engineering, site preparation activities and contract costs incurred project to date through December 31, 2014 were $88.5 million, excluding AFUDC.
	See "Environmental Matters" below for more information on both of these projects.
	Leases
	We have purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these agreements are disclosed in the Purchased Power section of this note.
	We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.
	The gross amount of assets recorded under capital leases total $5.3 million at December 31, 2014.
	Our lease obligations over the next five years are as follows (in thousands):
		Capital		Operating
		Leases		Leases
	2015	$	553	$	730
	2016		549		720
	2017		547		682
	2018		547		645
	2019		546		485
	Thereafter		3,006		—
	Total minimum payments		5,748	$	3,262
	Less amount representing interest		1,581
	Present value of net minimum lease payments	$	4,167
	Expenses incurred related to operating leases were $0.8 million, $0.8 million and $0.9 million for 2014, 2013, and 2012, respectively, excluding payments for wind generated purchased power agreements. The accumulated amount of amortization for our capital leases was $1.5 million and $1.3 million at December 31, 2014 and 2013, respectively.
	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), replaced by the Cross State Air Pollution Rule (CSAPR), which we discuss further below, are the drivers behind our Compliance Plan and its implementation schedule. The MATS require reductions in mercury, acid gases and other emissions considered hazardous air pollutants (HAPS). They became effective in April 2012 and require full compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The CSAPR was first proposed by the Environmental Protection Agency (EPA) in July 2010 as a replacement of CAIR and came into effect on January 1, 2015. We anticipate compliance costs associated with the MATS, CAIR and CSAPR regulations to be recoverable in our rates.
	Our Compliance Plan largely follows the preferred plan presented in our Integrated Resource Plan (IRP), filed in mid-2013 with the MPSC. As described above under New Construction, the process of installing a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant has been completed. This addition required the retirement of Asbury Unit 2, a steam turbine rated at 14 megawatts that was used for peaking purposes. Asbury Unit 2 was retired on December 31, 2013.
	In September 2012, we completed the transition of our Riverton Units 7 and 8 from operation on coal and natural gas to operation solely on natural gas. Riverton Unit 7 was permanently removed from service on June 30, 2014. Riverton Unit 8 and Riverton Unit 9, a small combustion turbine that requires steam from Unit 8 for start-up, are planned to be retired upon the conversion of Riverton Unit 12, a simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in mid-2016.
	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. Through the end of 2014, NOx emissions were regulated by the CAIR and National Ambient Air Quality Standard (NAAQS) rules for ozone (discussed below). Beginning January 1, 2015, NOx emissions are regulated by CSAPR and NAAQS rules for ozone. Through the end of 2014, SO2 emissions were regulated by the Title IV Acid Rain Program and the CAIR. Beginning January 1, 2015, SO2 emissions are regulated by the Title IV Acid Rain Program and the CSAPR.
	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. At this time we believe we are in compliance with CAIR, which was in its final year in 2014.
	CSAPR:
	The CSAPR requires 23 states to reduce annual SO2 and NOx emissions to help downwind areas attain NAAQS for fine particulate matter. Twenty-five states are required to reduce ozone season NOx emissions to help downwind states attain NAAQS for ozone. The CSAPR NOx annual program impacts our Missouri and Kansas units while the CSAPR NOx ozone season program impacts our units in these two states plus our unit in Arkansas.
	The CSAPR divides the states required to reduce SO2 into two groups. Both groups must reduce their SO2 emissions in Phase 1. Group 1 states, which include our sources in Missouri and Arkansas, must make additional SO2 reductions for Phase 2 in order to eliminate their significant contribution to air quality problems in downwind areas. Empire's units in Kansas are in Group 2 of the CSAPR SO2 program.
	Under the CSAPR Program, in our most current five-year business plan (2015 – 2019), which assumes normal operations while maintaining compliance with permit conditions, we anticipate that it may be economically beneficial to purchase allowances for some of these pollutants if needed, but at the time of this writing the allowance markets have not been fully developed. We are in position to comply with CSAPR in 2015.
	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. We are in position to comply with MATS in 2015.
	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/m3 (micrograms per cubic meter of air). States are required to meet the primary standard in 2020. The standard should have no impact on our existing generating fleet because the regional ambient monitor results are below the PM 2.5 required level. However, the PM 2.5 standards could impact future major modifications/construction projects that require additional permits.
	Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. Based on the current standard, our service territory is designated as attainment, meaning that it is in compliance with the standard. A revised ozone NAAQS was proposed by the EPA on November 25, 2014 and the final rule is expected in October 2015. We believe this revised Ozone NAAQS would affect our region but it's too early to determine what, if any, impact it would have on our generating plants at this time.
	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, since 2013, have been reported to the EPA as required.
A series of actions and decisions including the Tailoring Rule, which regulates carbon dioxide and other GHG emissions from certain stationary sources, have further set the foundation for the regulation of GHGs. However, because of the uncertainties regarding the final outcome of the GHG regulations (discussed below), the ultimate cost of compliance cannot be determined at this time. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates.
In April 2012, the EPA proposed a Carbon Pollution Standard for new power plants to limit the amount of carbon emitted by EGUs. This standard was rescinded, and a re-proposal of standards of performance for affected fossil fuel-fired EGUs was published in January 2014. The proposed rule applies only to new EGUs and sets separate standards for natural gas-fired combustion turbines and for fossil fuel-fired utility boilers. The proposal would not apply to existing units, including modifications such as those required to meet other air pollution standards which are currently being undertaken at our Asbury facility and at the Riverton facility with the conversion of simple cycle Unit 12 to combined cycle. The final rule is expected in the summer of 2015.
On June 2, 2014, the EPA released the proposed rule for limiting carbon emissions from existing power plants. The "Clean Power Plan" requires a 30% carbon emission reduction from 2005 baseline levels by 2030 and requires fossil-fuel fired power plants across the nation, including those in Empire's fleet, to meet state-specific goals to lower carbon levels. The EPA has identified four building block strategies to achieve the best system of emission reduction (BSER). Included in these strategies are the following: efficiency improvements at fossil fuel power plants; using lower-emitting sources (such as natural gas combined cycle units); using more renewables and keeping nuclear sources; and using power more efficiently. States will use the building blocks to craft their compliance plans or may work with other states in developing a regional approach to compliance, in which case additional time is given for implementation.
The EPA is scheduled to issue the final rule for existing power plants by summer of 2015. Each state must submit its initial compliance plan by the summer of 2016 with additional time available by request until the summer of 2017 for a single state or the summer of 2018 for a multi-state approach. The EPA received greater than 2 million public comments by the December 1, 2014 closure of the comment period. State, federal and industry representatives voiced their concerns with the regulation as written and the potential impact on electric grid reliability and the cost to implement. State and industry representatives including Empire continue to evaluate potential paths forward if the rule is finalized as proposed by the EPA.
Also, on June 2, 2014, the EPA released the proposed carbon pollution standards for modified and reconstructed stationary EGUs. The proposed rule focuses on electric utility steam generating units and natural gas-fired stationary combustion turbines. The comment period ended October 16, 2014 and the EPA anticipates issuing a final rule in June 2015.
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 published the final rule on August 15, 2014 with an effective date of October 14, 2014. Court challenges are expected. We expect the regulations to have a limited impact at Riverton given the planned retirement of unit 8 scheduled in 2016. A new intake structure design and cooling tower will be constructed as part of the Unit 12 conversion at Riverton. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally affected by the final rule.
Surface Impoundments
We own and maintain a coal ash impoundment located at our Asbury Power Plant. Additionally, we own a 12% interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. As a result of the transition from coal to natural gas fuel for Riverton Units 7 and 8, the former Riverton ash impoundment has been capped and closed. Final closure as an industrial (coal combustion waste) landfill was approved on June 30, 2014 by the Kansas Department of Health and Environment (KDHE).
On April 19, 2013, the EPA signed a notice of proposed rulemaking to revise its wastewater effluent limitation guidelines and standards under the CWA for coal-fired power plants. The proposal calls for updates to operating permits beginning in July 2017. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs that might result from any new standards. All of our coal ash impoundments are compliant with existing state and federal regulations.
In June 2010, the EPA proposed to regulate coal combustion residuals (CCRs) under the Federal Resource Conservation and Recovery Act (RCRA). In the proposal, the EPA presented two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. On December 19, 2014 the EPA finalized the requirements under the subtitle D solid waste provisions. We expect compliance to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury Power Plant. This preliminary estimate was developed before the rule was finalized and will be updated to conform to the final rule. We expect resulting costs to be recoverable in our rates.
We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. Our Detailed Site Investigation (DSI) has been completed and was submitted to MDNR for review and approval in on January 21, 2015. Receipt of the final construction permit for the waste landfill is expected in early 2016.
Renewable Energy
On November 4, 2008 Missouri voters approved the Clean Energy Initiative (Proposition C) which currently requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas, and Elk River Windfarm, LLC, located in Butler County, Kansas. Proposition C also requires that 2% of the energy from renewable energy sources must be solar; however, we believed that we were exempted by statute from the solar requirement. On January 20, 2013 the Earth Island Institute, d/b/a Renew Missouri, and others challenged our solar exemption by filing a complaint with the MPSC. The MPSC dismissed the complaint and Renew Missouri filed a notice of appeal seeking review by the Missouri Supreme Court. On February 10, 2015 the Missouri Supreme Court issued an opinion holding that the legislature had the authority to adopt the statute providing the exemption but reversed the MPSC's holding that the two laws could be harmonized. The statute providing the exemption (which was enacted in August 2008) was impliedly repealed by the adoption of Proposition C because it conflicted with the latter law. We believe the matter will return to the MPSC for further action. While we are not in a position to accurately estimate the impact of this requirement, we expect any future costs to be recoverable in rates.
Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables in 2012, increasing to 15% by 2016, and to 20% by 2020. We are currently in compliance with this regulatory requirement as a result of purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas.

SEGMENT_INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2014
Segment Information
Segment Information	12.   SEGMENT INFORMATION
	We operate our business as three segments: electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company is our wholly owned subsidiary formed to provide gas distribution service in Missouri. The other segment consists of our non-regulated businesses which is primarily our fiber optics business.
	The tables below present statement of income information, balance sheet information and capital expenditures of our business segments.
			For the year ended December 31,
			2014
			Electric		Gas		Other		Eliminations			Total
	Statement of Income Information:
	Revenues(1)		$	592,491	$	51,842	$	9,302	$	(1,305	)	$	652,330
	Depreciation and amortization			67,534		3,760		1,891		—			73,185
	Federal and state income taxes			35,737		1,840		1,643		—			39,220
	Operating income			90,488		6,775		2,736		—			99,999
	Interest income			37		25		21		(32	)		51
	Interest expense			37,911		3,861		—		(32	)		41,740
	Income from AFUDC (debt and equity)			9,833		84		—		—			9,917
	Income from continuing operations		$	61,467	$	2,965	$	2,671	$	—		$	67,103
	Capital Expenditures			212,866		7,836		2,151					222,853
			$		$		$		$	—		$
	-1	The Electric Segment includes SPP Integrated Marketplace net revenues of $41.9 million.
			2013
			Electric		Gas		Other		Eliminations			Total
	Statement of Income Information:
	Revenues		$	536,413	$	50,041	$	9,147	$	(1,271	)	$	594,330
	Depreciation and amortization			63,659		3,709		1,938		—			69,306
	Federal and state income taxes			34,478		1,484		1,530		—			37,492
	Operating income			90,984		6,194		2,485		—			99,663
	Interest income			537		115		8		(94	)		566
	Interest expense			37,683		3,890		—		(94	)		41,479
	Income from AFUDC (debt and equity)			5,910		30		—		—			5,940
	Income from continuing operations		$	58,603	$	2,355	$	2,487	$	—		$	63,445
	Capital Expenditures			153,401		4,419		2,388					160,208
			$		$		$		$	—		$
			2012
			Electric		Gas		Other		Eliminations			Total
	Statement of Income Information:
	Revenues		$	510,653	$	39,849	$	7,187	$	(592	)	$	557,097
	Depreciation and amortization			55,312		3,598		1,537		—			60,447
	Federal and state income taxes			32,266		789		1,104		—			34,159
	Operating income			89,445		5,005		1,771		—			96,221
	Interest income			946		323		7		(304	)		972
	Interest expense			37,866		3,905		—		(304	)		41,467
	Income from AFUDC (debt and equity)			1,918		10		—		—			1,928
	Income from continuing operations		$	52,631	$	1,256	$	1,794	$	—		$	55,681
	Capital Expenditures			140,117		3,571		2,599					146,287
			$		$		$		$	—		$
			December 31, 2014
			Electric		Gas(1)		Other		Eliminations			Total
	Balance Sheet Information:
	Total assets		$	2,271,539	$	130,856	$	34,655	$	(46,794	)	$	2,390,256
			December 31, 2013
			Electric		Gas(1)		Other		Eliminations			Total
	Balance Sheet Information:
	Total assets		$	2,034,234	$	123,736	$	31,306	$	(44,231	)	$	2,145,045
	-1	Includes goodwill of $39,492 at December 31, 2014 and 2013.

SELECTED_QUARTERLY_INFORMATION

SELECTED QUARTERLY INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2014
SELECTED QUARTERLY INFORMATION (UNAUDITED)
SELECTED QUARTERLY INFORMATION (UNAUDITED)	13.   SELECTED QUARTERLY INFORMATION (UNAUDITED)
	The following is a summary of quarterly results for 2014 and 2013 (dollars in thousands except per share amounts):
			Quarters
	Quarterly Results for 2014		First		Second		Third		Fourth
	Operating revenues(1)		$	179,673	$	149,782	$	171,512	$	151,363
	Operating income		$	29,488	$	19,502	$	31,709	$	19,300
	Net Income			20,905		11,194		23,892		11,112
			$		$		$		$
	Basic and Diluted Earnings Per Share			0.48		0.26		0.55		0.26
			$		$		$		$
	-1	Operating revenue for the first, second, third and fourth quarters of 2014 include SPP IM net revenues of $6.2 million, $16.5 million, $11.5 million, and $7.5 million, respectively.
			Quarters
	Quarterly Results for 2013		First		Second		Third		Fourth
	Operating revenues		$	151,140	$	136,646	$	157,486	$	149,058
	Operating income		$	21,858	$	21,110	$	32,896	$	23,799
	Net Income			12,630		11,658		23,996		15,162
			$		$		$		$
	Basic and Diluted Earnings Per Share			0.30		0.27		0.56		0.35
			$		$		$		$
	The sum of the net income and quarterly earnings per share of common stock may not equal the net income and earnings per share of common stock as computed on an annual basis due to rounding.

RISK_MANAGEMENT_AND_DERIVATIVE

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2014
Risk Management and Derivative Financial Instruments
Risk Management and Derivative Financial Instruments	14.   RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS
	We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain cost predictability.
	We began acquiring Transmission Congestion Rights (TCR) in 2013 in an effort to mitigate the cost of power we purchase from the SPP IM due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.
	All derivative instruments are recognized at fair value on the balance sheet. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the Accounting Standards Codification (ASC) guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms.
	Risks and uncertainties affecting the determination of fair value include: market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instruments in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income and subject to our fuel adjustment mechanism.
	As of December 31, 2014 and 2013, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of December 31, (in thousands):
	ASSET DERIVATIVES
	Non-designated hedging instruments due to regulatory accounting			2014			2013
		Balance Sheet Classification		Fair			Fair
				Value			Value
	Natural gas contracts, gas segment	Current assets		$	—		$	35
		Non-current assets and deferred charges — Other			—			—
	Natural gas contracts, electric segment	Current assets			1			467
		Non-current assets and deferred charges — Other			—			41
	Transmission congestion rights, electric segment	Current assets			3,900			1,967
	Total derivatives assets			$	3,901		$	2,510
	LIABILITY DERIVATIVES
	Non-designated as hedging instruments due to regulatory accounting			2014			2013
		Balance Sheet Classification		Fair			Fair
				Value			Value
	Natural gas contracts, gas segment	Current liabilities		$	476		$	8
		Non-current liabilities and deferred credits			—			—
	Natural gas contracts, electric segment	Current liabilities			5,993			1,881
		Non-current liabilities and deferred credits			3,243			2,799
	Transmission congestion rights, electric segment	Current liabilities
					—			—
	Total derivatives liabilities			$	9,712		$	4,688
	Electric
	At December 31, 2014, approximately $6.0 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months.
	There were no "mark-to-market" pre-tax gains/ (losses) from ineffective portions of our hedging activities for the electric segment for the years ended December 31, 2014 and 2013, respectively.
	The following tables set forth "mark-to-market" pre-tax gains/ (losses) from non-designated derivative instruments for the electric segment for each of the years ended December 31 (in thousands):
	Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment
				Amount of
				Gain/(Loss)
				Recognized on
				Balance Sheet
		Balance Sheet Classification		2014			2013
		of Gain/(Loss) on Derivative
	Commodity contracts — electric segment	Regulatory (assets)/liabilities		$	(6,780	)	$	(338	)
	Transmission congestion rights — electric segment	Regulatory (assets)/liabilities			12,958			1,967
	Total — Electric Segment			$	6,178		$	1,629
	Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment
				Amount of
				Gain/(Loss)
				Recognized in
				Income on
				Derivative
		Statement of Operations Classification		2014			2013
		of Loss on Derivative
	Commodity contracts	Fuel and purchased power expense		$	(1,659	)	$	(2,725	)
	Transmission congestion rights — electric segment	Fuel and purchased power expense			11,106			81
	Total — Electric Segment			$	9,447		$	(2,644	)
	We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to fair value accounting because they qualify for the normal purchase normal sale exemption. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchase normal sale exception contain a price adjustment feature and will account for these contracts accordingly.
	At December 31, 2014, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for 2015 and the next four years are hedged at the following average prices per Dekatherm (Dth):
	Year	% Hedged			Dth Hedged			Dth Hedged		Average Price
					Physical			Financial
	2015		63	%		1,550,000			4,510,000	$	4.351
	2016		43	%		1,976,000			2,100,000	$	4.103
	2017		20	%		782,900			1,300,000	$	4.133
	2018		11	%		456,000			500,000	$	4.202
	2019		—			—			—		—
	We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year's and 80% of any future year's expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.
	Year	End of Year
		Minimum % Hedged
Current	Up to 100%
First	60%
Second	40%
Third	20%
Fourth	10%
At December 31, 2014, the following transmission congestion rights (TCR) have been obtained from TCR auctions to hedge congestion costs in the SPP Integrated Marketplace:
Year	Monthly			$ Value
	MWH
	Hedged
2015		3,483		$	3,899,526
Gas
We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of December 31, 2014 we had 1.2 million Dths in storage on the three pipelines that serve our customers. This represents 58% of our storage capacity.
The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the ACA year at September 1 and illustrates our hedged position as of December 31, 2014 (Dth in thousands).
Season	Minimum %			Dth Hedged			Dth Hedged		Dth in		Actual %
	Hedged			Financial			Physical		Storage		Hedged
Current		50	%		430,000			341,000		1,178,367		97	%
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 the years ended December 31 (in thousands):
Non-Designated Hedging Instruments Due to Regulatory Accounting — Gas Segment
			Amount of
			Loss
			Recognized on
			Balance Sheet
	Balance Sheet Classification of Loss on Derivative		2014			2013
Commodity contracts	Regulatory assets		$	(511	)	$	(5	)
				—
Total — Gas Segment			$	(511	)	$	(5	)
Contingent Features
Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. We had no derivative instruments with the credit-risk-related contingent features in a net liability position on December 31, 2014 and have posted no collateral in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at the dates shown. There were no margin deposit liabilities at these dates.
(in millions)	December 31,			December 31,
	2014			2013
Margin deposit assets	$	9.1		$	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 years ended December 31, 2014 and December 31, 2013, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

FAIR_VALUE_MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements
Fair Value Measurements	15.   FAIR VALUE MEASUREMENTS
	The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data.
	The guidance also requires that the fair value measurement of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.
	Our Transmission congestion rights positions (TCR), which are acquired on the SPP Integrated Marketplace, are valued using the most recent monthly auction clearing prices. Our commodity contracts are valued using the market value approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of December 31, 2013:
	Fair Value Measurements at Reporting Date Using
	($ in 000's)		Assets/(Liabilities)			Quoted Prices			Significant		Significant
	Description		at Fair Value			in Active			Other		Unobservable
						Markets			Observable		Inputs
						for Identical			Inputs		(Level 3)
						Assets			(Level 2)
						(Level 1)
	December 31, 2014
	Derivative assets		$	3,901		$	1		$	3,900	$	—
	Derivative liabilities		$	(9,712	)	$	(9,712	)	$	—	$	—
	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 December 31, 2014 and 2013 was $799 million and $739 million, compared to a fair market value of approximately $829 million and $715 million, respectively. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of December 31, 2014 or that will be realizable in the future.

REGULATED_OPERATING_EXPENSE

REGULATED OPERATING EXPENSE	12 Months Ended
	Dec. 31, 2014
Regulated Operating Expenses
Regulated operating expenses	16.   REGULATED OPERATING EXPENSE
	The following table sets forth the major components comprising "regulated operating expenses" under "Operating Revenue Deductions" on our consolidated statements of income for the years ended (in thousands):
			December 31,
			2014		2013		2012
	Power operation expense (other than fuel)		$	16,089	$	15,643	$	15,045
	Electric transmission and distribution expense			27,919		21,863		17,083
	Natural gas transmission and distribution expense			2,362		2,498		2,443
	Customer accounts & assistance expense			11,239		11,180		10,211
	Employee pension expense(1)			10,590		10,736		10,180
	Employee healthcare plan(1)			9,147		10,190		9,825
	General office supplies and expense			15,024		12,850		10,776
	Administrative and general expense			14,385		14,800		15,091
	Bad debt expense			3,420		3,665		3,038
	Regulatory reversal of gain on sale of assets			44		1,236		—
	Miscellaneous expense			472		672		679
	TOTAL		$	110,691	$	105,333	$	94,371
	-1	Does not include the capitalized portion of actuarially calculated costs, but reflects the GAAP expensed portion of these costs plus or minus costs deferred to a regulatory asset or recognized as a regulatory liability for Missouri and Kansas jurisdictions.

SCHEDULE_II_Valuation_and_Qual

SCHEDULE II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2014
SCHEDULE II - Valuation and Qualifying Accounts
SCHEDULE II - Valuation and Qualifying Accounts	SCHEDULE II
	Valuation and Qualifying Accounts
	Years ended December 31, 2014, 2013 and 2012:
				Additions Charged to Other Accounts					Deductions From
									Reserve
		Balance At		Charged		Description	Amount		Description	Amount		Balance At
		Beginning		To Income								Close of
		Of Period										Period
	Year ended December 31, 2014:
	Reserve deducted from assets: accumulated provision for uncollectible accounts.		1,025,177		3,463,797	Recovery of		2,128,325	Accounts		5,596,662		1,020,637
		$		$		amounts previously	$		written off	$		$
						written off
	Year ended December 31, 2013:
	Reserve deducted from assets: accumulated provision for uncollectible accounts.		1,387,673		2,213,988	Recovery of		2,013,959	Accounts		4,590,443		1,025,177
		$		$		amounts previously	$		written off	$		$
						written off
	Year ended December 31, 2012:
	Reserve deducted from assets: accumulated provision for uncollectible accounts.		1,137,644		3,052,397	Recovery of		1,956,549	Accounts		4,758,917		1,387,673
		$		$		amounts previously	$		written off	$		$
						written off

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies

Basis of Presentation

Basis of Presentation

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

Use of Estimates

Use of Estimates

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

Accounting for the Effects of Regulation

Accounting for the Effects of Regulation

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

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

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

Revenue Recognition

Revenue Recognition

For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer classes. During 2012, we recorded an increase in electric unbilled revenues as a result of certain changes to the assumptions used in determining estimated unbilled revenues.

Municipal Franchise Taxes

Municipal Franchise Taxes

Municipal franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other taxes in the Consolidated Statements of Income. Municipal franchise taxes of $11.8 million, $11.2 million and $10.4 million were recorded for each of the years ended December 31, 2014, 2013 and 2012, respectively.

Accounts Receivable

Accounts Receivable

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

Property, Plant & Equipment

Property, Plant & Equipment

The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material, an allocation of general and administrative costs, and an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of and the costs of removal are charged to accumulated depreciation, unless the removed property constitutes an operating unit or system. In this case a gain or loss is recognized upon the disposal of the asset. Maintenance expenditures and the removal of minor property items are charged to income as incurred. A liability is created for any additions to electric or gas utility property that are paid for by advances from developers. For a period of five years we refund to the developer a pro rata amount of the original cost of the extension for each new customer added to the extension. Nonrefundable payments at the end of the five year period are applied as a reduction to the cost of the plant in service. The liability as of December 31, 2014 and 2013 was $1.9 million and $4.2 million, respectively.

Depreciation

Depreciation

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

As of December 31, 2014 and 2013, we had recorded accrued cost of removal of $82.8 million and $81.3 million, respectively, for our electric operating segment. This represents an estimated cost of dismantling and removing plant from service upon retirement, accrued as part of our depreciation rates. We accrue cost of removal in depreciation rates for mass property (including transmission, distribution and general plant assets). These accruals are not considered an asset retirement obligation under the guidance provided on asset retirement obligations within the ASC. We reclassify the accrued cost of dismantling and removing plant from service upon retirement from accumulated depreciation to a regulatory liability. We have a similar cost of removal regulatory liability for our gas operating segment. This amount at December 31, 2014 and 2013 was $7.7 million and $7.2 million, respectively. These amounts are net of our actual cost of removal expenditures.

Asset Retirement Obligation

Asset Retirement Obligation

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

We have identified asset retirement obligations associated with the future removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We also have a solid waste land fill at the Plum Point Energy Station, and asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. As a result of the fuel use transition from coal to natural gas at the Riverton Power Plant, the closure of the Riverton ash landfill was completed, and the related asset retirement obligation was settled during 2014 (Note 11).

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

All of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 4.5% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. During 2014 the liability for asbestos at the Riverton Power Plant was re-evaluated, and during 2012 the liabilities for both the ash landfill at the Riverton Power Plant, and PCB contaminants were re-evaluated. Changes in the cost estimates and timing resulted in cash flow revisions for these liabilities.

The balances at the end of 2013 and 2014 are shown below.

(000's)

Liability

Liabilities

Liabilities

Accretion

Cash Flow

Liability

Balance

Recognized

Settled

Revisions

Balance at

12/31/13

12/31/14

Asset Retirement Obligation

$

4,190

$

—

$

(1,175

)

$

172

$

1,660

$

4,847

(000's)

Liability

Liabilities

Liabilities

Accretion

Cash Flow

Liability

Balance

Recognized

Settled

Revisions

Balance at

12/31/12

12/31/13

Asset Retirement Obligation

$

4,711

$

—

$

(734

)

$

213

$

—

$

4,190

Upon adoption of the standards on the retirement of long lived assets and conditional asset retirement obligations, we recorded a liability and regulatory asset because we expect to recover these costs of removal in electric and gas rates either through depreciation accruals or direct expenses. We also defer the liability accretion and depreciation expense as a regulatory asset. At December 31, 2014 and 2013, our regulatory assets relating to asset retirement obligations totaled $5.1 million and $4.7 million, respectively.

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

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction

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

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

In accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 6.6% for 2014, 7.3% for 2013, and 5.6% for 2012, compounded semiannually.

Asset Impairments (excluding goodwill)

Asset Impairments (excluding goodwill)

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on undiscounted forecasted cash flows to assess the recoverability of the assets and, if necessary, the fair value is determined to measure the impairment amount. None of our assets were impaired as of December 31, 2014 and 2013.

Goodwill

Goodwill

As of December 31, 2014, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and income approaches is used to estimate the fair value of goodwill.

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

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

We weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of October 2014 indicated the estimated fair market value of the gas reporting unit to be $10 – $14 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future.

Fuel and Purchased Power

Fuel and Purchased Power

Electric Segment

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

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

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

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

At December 31, 2014 and 2013, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net under-recovered position by $3.1 million and a net over-recovered position of $0.6 million, respectively, which are reflected in our regulatory assets and liabilities.

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

We have a Stipulation and Agreement with the MPSC granting us authority to manage our SO2 allowance inventory in accordance with our SO2 Allowance Management Policy (SAMP). The SAMP allows us to exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. We have not yet exchanged or sold any allowances. We classify our allowances as inventory and they are recorded at cost, with allocated allowances being recorded at zero cost. The allowances are removed from inventory on a FIFO basis, and used allowances are considered to be a part of fuel expense (See Note 11). We had 872 and 1,834 SO2 allowances in inventory at December 31, 2014 and 2013, respectively.

Gas Segment

Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery allowed in rates. A Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and related carrying costs associated with the Company's use of natural gas financial instruments to hedge the purchase price of natural gas. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.

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

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

Derivatives

Derivatives

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

Electric Segment

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

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

Gas Segment

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

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

Pension and Other Postretirement Benefits

Pension and Other Postretirement Benefits

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

Pensions

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

Other Postretirement Benefits (OPEB)

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

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

Unamortized Debt Discount, Premium and Expense

Unamortized Debt Discount, Premium and Expense

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

Liability Insurance

Liability Insurance

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

Other Noncurrent Liabilities

Other Noncurrent Liabilities

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

Cash & Cash Equivalents

Cash & Cash Equivalents

Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities and were $28.3 million and $22.1 million at December 31, 2014 and 2013, respectively.

Restricted Cash

Restricted Cash

As part of our Plum Point ownership agreement, we are required to have funds available in an escrow account which guarantees payment of certain operating and construction costs. The cash is held at a financial institution and restricted as to withdrawal or use. The restrictions on these funds related to construction costs, which were approximately $2.5 million at December 31, 2012, were released by all parties in January 2013. The amounts restricted for operating costs, which were $1.8 million at December 31, 2014 and 2013, may increase or decrease based on an annual review.

We are required to post cash collateral with Southwest Power Pool (SPP) to participate in Transmission Congestion Rights (TCR) auctions. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $2.5 million and $1.1 million at December 31, 2014 and 2013, respectively.

Due to our Plum Point energy station interconnection with Midcontinent Independent System Operator (MISO), we participate in Financial Transmission Rights (FTR) auctions which require us to post cash collateral. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $0.5 million and $0 at December 31, 2014 and 2013, respectively.

Fuel, Materials and Supplies

Fuel, Materials and Supplies

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

2014

2013

Electric fuel inventory

$

26,454

$

17,003

Natural gas inventory

5,040

3,584

Materials and supplies

26,305

28,224

TOTAL

$

57,799

$

48,811

Income Taxes

Income Taxes

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

Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. The longest remaining amortization period for investment tax credits is approximately 50 years.

Accounting for Uncertainty in Income Taxes

Accounting for Uncertainty in Income Taxes

In 2006, the FASB issued guidance which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with the ASC guidance on accounting for income taxes. We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2009. At December 31, 2014 and 2013, our balance sheet did not include any unrecognized tax benefits. We do not expect any material changes to unrecognized tax benefits within the next twelve months. We recognize interest and penalties, if any, related to unrecognized tax benefits in other expenses.

Computations of Earnings Per Share

Computations of Earnings Per Share

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

2014

2013

2012

Weighted Average Number Of Shares

Basic

43,291,031

42,781,382

42,256,641

Dilutive Securities:

Performance-based restricted stock awards

8,809

12,142

14,500

Dividend equivalents

—

—

6,329

Employee stock purchase plan

3,422

1,729

1,996

Stock options

—

61

3,160

Time-based restricted stock awards

10,666

7,907

1,820

Total dilutive securities

22,897

21,839

27,805

Diluted weighted average number of shares

43,313,928

42,803,221

42,284,446

Antidilutive Shares

25,259

107,100

128,500

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

Stock-Based Compensation

Stock-Based Compensation

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

Recently Issued and Proposed Accounting Standards

Recently Issued and Proposed Accounting Standards

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

Revenue from contracts with customers:    In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard is effective for interim and annual reporting periods beginning after December 15, 2016. We are evaluating the impact of the adoption of this standard.

SUMMARY_OF_SIGNIFICANT_ACCOUNT2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2014
Summary of Significant Accounting Policies
Schedule of gross operating revenues by segments
	Our gross operating revenues in 2014 were derived as follows:
	Electric segment sales*			90.8	%
	Gas segment sales			8.0
	Other segment sales			1.2
	*	Sales from our electric segment include 0.3% from the sale of water.
Operating revenues
Schedule of asset retirement obligation
	(000's)		Liability			Liabilities		Liabilities			Accretion		Cash Flow		Liability
			Balance			Recognized		Settled					Revisions		Balance at
			12/31/13												12/31/14
	Asset Retirement Obligation		$	4,190		$	—	$	(1,175	)	$	172	$	1,660	$	4,847
	(000's)		Liability			Liabilities		Liabilities			Accretion		Cash Flow		Liability
			Balance			Recognized		Settled					Revisions		Balance at
			12/31/12												12/31/13
	Asset Retirement Obligation		$	4,711		$	—	$	(734	)	$	213	$	—	$	4,190
Schedule of fuel, materials and supplies
	These balances are as follows (in thousands):
			2014			2013
	Electric fuel inventory		$	26,454		$	17,003
	Natural gas inventory			5,040			3,584
	Materials and supplies			26,305			28,224
	TOTAL		$	57,799		$	48,811
Schedule of weighted average number of shares
			2014			2013		2012
	Weighted Average Number Of Shares
	Basic			43,291,031			42,781,382		42,256,641
	Dilutive Securities:
	Performance-based restricted stock awards			8,809			12,142		14,500
	Dividend equivalents			—			—		6,329
	Employee stock purchase plan			3,422			1,729		1,996
	Stock options			—			61		3,160
	Time-based restricted stock awards			10,666			7,907		1,820
	Total dilutive securities			22,897			21,839		27,805
	Diluted weighted average number of shares			43,313,928			42,803,221		42,284,446
	Antidilutive Shares			25,259			107,100		128,500
Electric
Operating revenues
Schedule of operating revenues by major customer classes
	Our electric operations serve approximately 170,000 customers as of December 31, 2014, and the 2014 electric operating revenues were derived as follows:
	Customer		% of revenue
	Residential			40.0	%
	Commercial			29.2
	Industrial			14.4
	Wholesale on-system			3.8
	Wholesale off-system			7.6
	Miscellaneous sources, primarily public authorities			2.6
	Other electric revenues			2.4
Schedule of operating revenues, by jurisdiction	Our retail electric revenues for 2014 by jurisdiction were as follows:
	Jurisdiction		% of revenue
	Missouri			89.7	%
	Kansas			4.8
	Arkansas			2.7
	Oklahoma			2.8
Gas
Operating revenues
Schedule of operating revenues by major customer classes	Our gas operations serve approximately 43,500 customers as of December 31, 2014, and the 2014 gas operating revenues were derived as follows:
	Customer		% of revenue
	Residential			63.4	%
	Commercial			26.3
	Industrial			1.0
	Other			9.3

PROPERTY_PLANT_AND_EQUIPMENT_T

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2014
PROPERTY, PLANT AND EQUIPMENT
Summary of property, plant and equipment
	Our total property, plant and equipment are summarized below (in thousands).
			December 31,
			2014			2013
	Electric plant
	Production		$	1,159,140		$	1,035,095
	Transmission			288,542			263,398
	Distribution			840,761			793,024
	General(1)			119,572			115,427
	Electric plant			2,408,015			2,206,944
	Less accumulated depreciation and amortization			704,596			697,128
	Electric plant net of depreciation and amortization			1,703,419			1,509,816
	Construction work in progress			110,500			150,636
	Net electric plant			1,813,919			1,660,452
	Water plant			12,809			12,661
	Less accumulated depreciation and amortization			5,102			4,806
	Water plant net of depreciation and amortization			7,707			7,855
	Construction work in progress			146			—
	Net water plant			7,853			7,855
	Net electric segment plant			1,821,772			1,668,307
	Gas plant
	Transmission			11,198			10,550
	Distribution			89,712			84,157
	General(2)			(21,546	)		(21,873	)
	Gas Plant			79,364			72,834
	Less accumulated depreciation and amortization			16,405			15,204
	Gas plant net of accumulated depreciation			62,959			57,630
	Construction work in progress			379			1,156
	Net gas plant			63,338			58,786
	Other
	Fiber			41,394			39,902
	Less accumulated depreciation and amortization			17,304			15,599
	Non-regulated net of depreciation and amortization			24,090			24,303
	Construction work in progress			1,072			538
	Net non-regulated property			25,162			24,841
	TOTAL NET PLANT AND PROPERTY		$	1,910,272		$	1,751,934
	-1	Includes intangible property of $41.2 and $38.1 million as of December 31, 2014 and 2013, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2014 and 2013 was $15.7 and $13.1 million, respectively.
	-2	Includes intangible property of $0.7 and $0.7 million as of December 31, 2014 and 2013, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2014 and 2013 was $0.5 million and $0.5 million, respectively.
Summary of total provision for depreciation and the depreciation rates for continuing operations
	The table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended December 31 (in thousands):
			2014			2013			2012
	Provision for depreciation
	Regulated — Electric and Water		$	66,600		$	63,192		$	57,467
	Regulated — Gas			3,851			3,763			3,602
	Non-Regulated			1,891			1,938			1,538
	TOTAL			72,342			68,893			62,607
	Amortization			2,692			2,492			1,041
	TOTAL		$	75,034		$	71,385		$	63,648
			2014			2013			2012
	Annual depreciation rates
	Electric and water			3.0	%		3.0	%		2.8	%
	Gas			5.2	%		5.4	%		5.4	%
	Non-Regulated			4.7	%		5.0	%		4.2	%
	TOTAL COMPANY			3.0	%		3.1	%		2.9	%
Summary of average depreciation rate for each class of assets
			2014			2013			2012
	Annual Weighted Average Depreciation Rate
	Electric fixed assets:
	Production plant			2.4	%		2.4	%		2.0	%
	Transmission plant			2.4	%		2.4	%		2.4	%
	Distribution plant			3.6	%		3.6	%		3.6	%
	General plant			5.8	%		5.8	%		5.9	%
	Water			2.7	%		2.8	%		2.7	%
	Gas			5.2	%		5.4	%		5.4	%
	Non-regulated			4.7	%		5.0	%		4.2	%

REGULATORY_MATTERS_Tables

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2014
Regulatory Matters
Components of regulatory assets and liabilities
	The following table sets forth the components of our regulatory assets and regulatory liabilities on our consolidated balance sheet (in thousands).
			December 31,
			2014			2013
	Regulatory Assets:
	Current:
	Under recovered fuel costs		$	2,618		$	1,411
	Current portion of long-term regulatory assets			8,134			6,332
	Regulatory assets, current			10,752			7,743
	Long-term:
	Pension and other postretirement benefits(1)			111,121			70,035
	Income taxes			47,177			48,033
	Deferred construction accounting costs(2)			15,521			16,275
	Unamortized loss on reacquired debt			10,405			11,078
	Unsettled derivative losses — electric segment			9,037			4,269
	System reliability — vegetation management			5,337			7,539
	Storm costs(3)			4,183			4,911
	Asset retirement obligation			5,145			4,673
	Customer programs			5,253			4,935
	Unamortized loss on interest rate derivative			943			989
	Deferred operating and maintenance expense			910			2,095
	Under recovered fuel costs			640			—
	Current portion of long-term regulatory assets			(8,134	)		(6,332	)
	Other			2,179			833
	Regulatory assets, long-term			209,717			169,333
	Total Regulatory Assets		$	220,469		$	177,076
	Regulatory Liabilities
	Current:
	Over recovered fuel costs		$	4,227		$	2,212
	Current portion of long-term regulatory liabilities			3,671			3,469
	Regulatory liabilities, current			7,898			5,681
	Long-term:
	Costs of removal			90,527			88,469
	SWPA payment for Ozark Beach lost generation			16,744			19,405
	Income taxes			11,451			11,677
	Deferred construction accounting costs — fuel(4)			7,849			8,011
	Unamortized gain on interest rate derivative			3,201			3,371
	Pension and other postretirement benefits			2,369			2,177
	Over recovered fuel costs			1			2,371
	Current portion of long-term regulatory liabilities			(3,671	)		(3,469	)
	Regulatory liabilities, long-term			128,471			132,012
	Total Regulatory Liabilities		$	136,369		$	137,693
	-1	Primarily consists of unfunded pension and OPEB liability. See Note 7.
	-2	Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants.
	-3	Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $3.3 million at December 31, 2014.
	-4	Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.
Schedule of electric and water rate increases
	The following table sets forth information regarding electric and water rate increases since January 1, 2012:
	Jurisdiction		Date Requested		Annual			Percent			Date Effective
					Increase			Increase
					Granted			Granted
	Arkansas — Electric		December 3, 2013		$	1,366,809			11.34	%		September 26, 2014
	Missouri — Electric		July 6, 2012		$	27,500,000			6.78	%		April 1, 2013
	Missouri — Water		May 21, 2012		$	450,000			25.5	%		November 23, 2012
	Kansas — Electric		June 17, 2011		$	1,250,000			5.20	%		January 1, 2012
	Oklahoma — Electric		June 30, 2011		$	240,722			1.66	%		January 4, 2012
Schedule of new highway/byway cost allocation methodology
	Transmission Project Voltage		Regional Funding Percentage			Zonal Funding Percentage
	300 kV and Above			100.0	%		0.0	%
	100kV to 299kV			33.3	%		66.7	%
	Below 100 kV			0.0	%		100.0	%

SHAREHOLDERS_EQUITY_Tables

SHAREHOLDERS' EQUITY (Tables)	12 Months Ended
	Dec. 31, 2014
SHAREHOLDERS' EQUITY
Schedule of diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance
	(in millions, except per share amounts)	2014		2013		2012
	Diluted earnings per share	$	1.55	$	1.48	$	1.32
	Dividends paid per share	$	1.025	$	1.005	$	1.00
	Total dividends paid	$	44.4	$	43.0	$	42.3
	Retained earnings year-end balance	$	90.3	$	67.6	$	47.1

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2014
LONG-TERM DEBT.
Schedule of long-term debt outstanding
	At December 31, 2014 and 2013, the balance of long-term debt outstanding was as follows (in thousands):
			2014			2013
	First mortgage bonds (EDE):
	7.20% Series due 2016		$	25,000		$	25,000
	6.375% Series due 2018(1)			90,000			90,000
	4.65% Series due 2020(1)			100,000			100,000
	3.58% Series due 2027(1)			88,000			88,000
	3.73% Series due 2033(1)			30,000			30,000
	5.875% Series due 2037(1)			80,000			80,000
	5.20% Series due 2040(1)			50,000			50,000
	4.32% Series due 2043(1)			120,000			120,000
	4.27% Series due 2044(1)			60,000			—
	First mortgage bonds (EDG):
	6.82% Series due 2036(1)			55,000			55,000
				698,000			638,000
	Senior Notes, 6.70% Series due 2033(1)			62,000			62,000
	Senior Notes, 5.80% Series due 2035(1)			40,000			40,000
	Other			4,167			4,441
	Less unamortized net discount			(686	)		(739	)
				803,481			743,702
	Less current obligations under capital lease			(292	)		(274	)
	TOTAL LONG-TERM DEBT		$	803,189		$	743,428
	-1	We may redeem some or all of the notes at any time at 100% of their principal amount, plus a make-whole premium, plus accrued and unpaid interest to the redemption date.
Long-term Debt Payout Schedule (Excluding Unamortized Discount)	Our long-term debt obligations over the next five years are as follows (in thousands):
			Payments Due By Period
	Long-Term Debt Payout Schedule		Total			Regulated			Capital Lease
	(Excluding Unamortized Discount					Entity Debt			Obligations
	(in thousands)					Obligations
	2015		$	292		$	—		$	292
	2016			25,308			25,000			308
	2017			325			—			325
	2018			90,347			90,000			347
	2019			371			—			371
	Thereafter			687,524			685,000			2,524
	Total long-term debt obligations			804,167		$	800,000		$	4,167
	Less current obligations and unamortized discount			978
	TOTAL LONG-TERM DEBT		$	803,189

SHORTTERM_BORROWINGS_Tables

SHORT-TERM BORROWINGS (Tables)	12 Months Ended
	Dec. 31, 2014
SHORT-TERM BORROWINGS
Schedule of the entity's average short-term borrowings outstanding	At December 31, 2014, total short-term borrowings consisted of $44.0 million in commercial paper and no borrowings from our line of credit. During 2014 and 2013 our short-term borrowings outstanding averaged (in millions)
		2014			2013
	Average borrowings outstanding	$	30.0		$	8.7
	Highest month end balance	$	77.0		$	29.0
Schedule of weighted average interest rates and the weighted average interest rate of borrowings outstanding
		2014			2013
	Weighted average interest rate		0.38	%		0.69	%
	Weighted average interest rate of borrowings outstanding		0.44	%		0.33	%

RETIREMENT_AND_OTHER_EMPLOYEE_1

RETIREMENT AND OTHER EMPLOYEE BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2014
Retirement and other employee benefits
Schedule of the Company's benefit plans' projected benefit obligations
	Reconciliation of Projected Benefit Obligations:
			Pension						SERP						OPEB
			2014			2013			2014			2013			2014			2013
	Benefit obligation at beginning of year		$	225,131		$	248,004		$	7,108		$	6,365		$	85,332		$	94,738
	Service cost			6,467			7,454			153			135			2,601			2,941
	Interest cost			10,819			10,063			387			315			4,360			3,827
	Amendments			(7,753	)					(45	)					—
	Net actuarial (gain)/loss			36,742			(23,300	)		1,890			604			20,347			(12,767	)
	Plan participant's contribution			—			—			—			—			850			949
	Benefits and expenses paid			(19,527	)		(17,090	)		(338	)		(311	)		(3,897	)		(4,396	)
	Federal subsidy			—			—			—			—			306			40
	Benefit obligation at end of year		$	251,879		$	225,131		$	9,155		$	7,108		$	109,899		$	85,332
Schedule of fair value of the plans' assets
	Reconciliation of Fair Value of Plan Assets:
			Pension						SERP						OPEB
			2014			2013			2014			2013			2014			2013
	Fair value of plan assets at beginning of year		$	186,547		$	160,175		$	—		$	—		$	79,098		$	67,667
	Actual return on plan assets — gain/(loss)			14,319			27,260			—			—			5,030			10,361
	Employer contribution			11,335			16,202			—			—			2,258			4,360
	Benefits paid			(19,527	)		(17,090	)		—			—			(3,707	)		(4,229	)
	Plan participant's contribution			—			—			—			—			804			901
	Federal subsidy			—			—			—			—			293			38
	Fair value of plan assets at end of year		$	192,674		$	186,547		$	—		$	—		$	83,776		$	79,098
Schedule of the funded status
	Reconciliation of Funded Status:
			Pension						SERP						OPEB
			2014			2013			2014			2013			2014			2013
	Fair value of plan assets		$	192,674		$	186,547		$	—		$	—		$	83,776		$	79,098
	Projected benefit obligations			(251,879	)		(225,131	)		(9155	)		(7,108	)		(109,899	)		(85,332	)
	Funded status		$	(59,205	)	$	(38,584	)	$	(9,155	)	$	(7,108	)	$	(26,123	)	$	(6,234	)
Schedule of employee pension plan accumulated benefit obligation
	The employee pension plan accumulated benefit obligation at December 31, 2014 and 2013 is presented in the following table (in thousands):
			Pension Benefits						SERP
			2014			2013			2014			2013
	Accumulated benefit obligation		$	227,928		$	201,258		$	7,160		$	5,702
Schedule of amounts recognized in the balance sheet
	Amounts recognized in the balance sheet consist of (in thousands):
			Pension						SERP						OPEB
			2014			2013			2014			2013			2014			2013
	Accounts Payable and Accrued Liabilities		$	—		$	—		$	481		$	372		$	139		$	147
	Pension and other postretirement benefit obligation		$	59,205		$	38,584		$	8,674		$	6,736		$	25,984		$	6,087
Schedule of net periodic benefit pension cost
	Net periodic benefit pension cost for 2014, 2013 and 2012, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset (see Note 3), is comprised of the following components (in thousands):
	Net Periodic Pension Benefit Cost:
			Pension									OPEB
			2014			2013			2012			2014			2013			2012
	Service cost		$	6,467		$	7,454		$	6,261		$	2,601		$	2,941		$	2,401
	Interest cost			10,819			10,063			10,258			4,360			3,827			4,037
	Expected return on plan assets			(13,105	)		(12,428	)		(12,309	)		(4,801	)		(4,353	)		(4,135	)
	Amortization of prior service cost/(benefit)(1)			418			532			531			(1,011	)		(1,011	)		(1,011	)
	Amortization of actuarial loss(1)			6,611			10,445			7,935			967			2,261			1,661
	Net periodic benefit cost		$	11,210		$	16,066		$	12,676		$	2,116		$	3,665		$	2,953
	Net Periodic Pension Benefit Cost:
			SERP
			2014			2013			2012
	Service cost		$	153		$	135		$	51
	Interest cost			387			315			263
	Expected return on plan assets			—			—			—
	Amortization of prior service cost/(benefit)(1)			(8	)		(8	)		(8	)
	Amortization of actuarial loss(1)			504			567			389
	Net periodic benefit cost		$	1,036		$	1,009		$	695
	-1	Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.
Schedule of activity in the regulatory asset accounts
	The tables below present other changes in plan assets and benefit obligations recognized in the regulatory asset accounts for the year (in thousands).
						Amount Recognized
	Regulatory Assets		Beginning			Current Year			Amortization			Current Year			Amortization of			Ending
			Balance			Actuarial Loss			of Actuarial			Prior Service			Prior Service			Balance
			12/31/13						Loss			Credit			(Cost)/Credit			12/31/14
	Pension		$	56,709			35,529			(6,611	)		(7,753	)		(418	)	$	77,456
	SERP		$	4,188			1,890			(504	)		(45	)		8		$	5,537
	OPEB		$	285			20,117			(967	)		—			1,011		$	20,446
						Amount Recognized
	Regulatory Assets		Beginning			Current Year			Amortization			Amortization of			Ending
			Balance			Actuarial			of Actuarial			Prior Service			Balance
			12/31/12			(Gain)/Loss			Loss			(Cost)/Credit			12/31/13
	Pension		$	105,818			(38,132	)		(10,445	)		(532	)	$	56,709
	SERP		$	4,143			604			(567	)		8		$	4,188
	OPEB		$	20,311			(18,776	)		(2,261	)		1,011		$	285
Schedule of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost and the amounts expected to be recognized in the subsequent year
	The following table presents those items for the employee pension plan and other benefits plan at December 31, 2014, and the subsequent twelve-month period (in thousands):
			Pension Benefits						SERP						OPEB
			2014			Subsequent			2014			Subsequent			2014			Subsequent
						Period						Period						Period
	Net actuarial loss		$	84,178		$	9,380		$	5,595		$	560		$	23,030		$	2,725
	Prior service cost (benefit)			(6,722	)		(630	)		(58	)		(43	)		(2,584	)		(1,011	)
	Total		$	77,456		$	8,750		$	5,537		$	517		$	20,446		$	1,714
Schedule of assumptions used to determine the benefit obligation
	Weighted-average assumptions used to determine the benefit obligation as of December 31:
			Pension						OPEB
			Benefits
			2014			2013			2014			2013
	Discount rate			4.06	%		4.90	%		4.15	%		5.00	%
	Rate of compensation increase			3.50	%		3.50	%		3.50	%		3.50	%
Schedule of assumptions used to determine the periodic costs
	Weighted-average assumptions used to determine the net benefit cost (income) as of January 1:
			Pension Benefits									OPEB
			2014			2013			2012			2014			2013			2012
	Discount rate			4.90	%		4.00	%		4.70	%		5.00	%		4.11	%		4.90	%
	Expected return on plan assets			7.75	%		7.75	%		7.90	%		6.52	%		6.52	%		6.65	%
	Rate of compensation increase			3.50	%		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%
Schedule of employee stock purchase plan
			2014			2013			2012
	Subscriptions outstanding at December 31,			57,369			60,413			70,850
	Maximum subscription price		$	21.43	-1	$	19.58		$	17.95
	Shares of stock issued			56,942			68,099			65,919
	Stock issuance price		$	19.58		$	17.95		$	17.27
	-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			2012
	Weighted average fair value of grants		$	3.07		$	2.78		$	3.19
	Risk-free interest rate			0.10	%		0.14	%		0.17	%
	Dividend yield			4.30	%		4.60	%		5.00	%
	Expected volatility(1)			14.00	%		14.00	%		24.00	%
	Expected life in months			12			12			12
	Grant date			6/2/14			6/1/13			6/1/12
	-1	One-year historic volatility
Schedule of shares contributed under 401(k) plan and ESOP
			2014			2013			2012
	Shares contributed			60,049			64,128			65,502
Pension Benefits
Retirement and other employee benefits
Schedule of expected benefit payments
	Expected benefit payments are as follows (in millions):
	Year		Payments from			Payments from
			Trust			Company Funds
	2015		$	25.0		$	0.5
	2016			22.0			0.5
	2017			22.1			0.5
	2018			20.8			0.5
	2019			19.5			0.5
	2020 – 2024			97.3			3.0
Schedule of fund assets measured at fair value
	The following fair value hierarchy table presents information about the pension fund assets measured at fair value as of December 31, 2014 and December 31, 2013 (in thousands):
			Fair Value Measurements as of December 31, 2014
			Quoted Prices			Significant			Significant			Total			Percentage
			in Active			Other			Unobservable						of Plan
			Markets for			Observable			Inputs						Assets
			Identical			Inputs			(Level 3)
			Assets			(Level 2)
			(Level 1)
	Short term investments		$	—		$	70		$	—		$	70			0.0	%
	Equity securities
	Common collective trusts			—			91,530			—			91,530			47.5	%
	Fixed income
	Common collective trust			—			62,646			—			62,646			32.5	%
	Other types of investments
	Equity long/short hedge funds			—			—			38,428			38,428			20.0	%
			$	—		$	154,246		$	38,428		$	192,674			100.0	%
			Fair Value Measurements as of December 31, 2013
			Quoted Prices			Significant			Significant			Total			Percentage
			in Active			Other			Unobservable						of Plan
			Markets for			Observable			Inputs						Assets
			Identical			Inputs			(Level 3)
			Assets			(Level 2)
			(Level 1)
	Short term investments		$	74		$	—		$	—		$	74			0.1	%
	Equity securities
	Common collective trusts			—			104,713			—			104,713			56.1	%
	Fixed income
	Common collective trust			—			45,031			—			45,031			24.1	%
	Other types of investments
	Equity long/short hedge funds			—						36,729			36,729			19.7	%
			$	74		$	149,744		$	36,729		$	186,547			100.0	%
Schedule of fair value measurements using significant unobservable inputs (level 3)
	Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — December 31,
			2014			2013
			Equity long/short			Equity long/short
			hedge funds			hedge funds
	Beginning Balance, January 1,		$	36,729		$	28,885
	Actual return on plan assets:
	Relating to assets still held at the reporting date			1,382			(356	)
	Relating to assets sold during the period			1,491			4,583
	Purchases			9,700			26,500
	Sales			(10,874	)		(22,883	)
	Settlements			—			—
	Transfers into and (out of) Level 3			—			—
	Ending Balance, December 31,		$	38,428		$	36,729
Schedule of permissible investments
	Permissible Investments
	Listed below are the investment vehicles specifically permitted:
	Permissible Investments
	Equity Oriented		Fixed Income Oriented and Real Estate
			
	Common Stocks		Bonds (including US Government and Agencies)
			
	Preferred Stocks (minimum "A-rated" by Moody's or S&P)		Corporate Bonds (minimum quality rating of Baa by Moody's or BBB by S&P)
			
	American Depository Receipts		Comingled bond funds (25% max. allocation to high yield)
			
	Convertible Preferred Stocks		Foreign Government Bonds
			
	Convertible Bonds		GIC's, BIC's
			
	Covered Options		Commercial Paper (rated A1 by S&P or P1 by Moody's)
			
	Hedged Equity Funds of Funds		Certificates of Deposit in institutions with FDIC/FSLIC protection
			
			Money Market Funds/Bank STIF Funds
			
			Real Estate — Publicly Traded
	The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.
	Those investments prohibited by the Investment Committee without prior approval are:
	Prohibited Investments Requiring Pre-approval
			
	Privately Placed Securities		Warrants
			
	Commodities Futures		Short Sales
			
	Securities of Empire District (except in the hedged equity funds of funds or commingled funds)		Index Options
			
	Restricted Stock		Letter Stock
OPEB
Retirement and other employee benefits
Schedule of expected benefit payments
	Estimated benefit payments are as follows (in millions):
	Year		Payments from			Expected Federal			Payments from
			Trust			Subsidy			Company Funds
	2015		$	2.8		$	0.3		$	0.1
	2016			3.1			0.4			0.2
	2017			3.4			0.4			0.1
	2018			3.7			0.5			0.2
	2019			4.0			0.5			0.1
	2020 – 2024			24.4			3.3			0.8
Schedule of effect of 1% change in assumed healthcare cost growth rates	The healthcare cost trend rate affects projected benefit obligations. A 1% change in assumed healthcare cost growth rates would have the following effects (in thousands):
			1% Increase			1% Decrease
	Effect on total of service and interest cost		$	1,395		$	(1,084	)
	Effect on post-retirement benefit obligation		$	19,135		$	(14,983	)
Schedule of fund assets measured at fair value
	The following fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2014 and December 31, 2013 (in thousands):
			Fair Value Measurements as of December 31, 2014
			Quoted Prices			Significant			Significant			Total			Percentage
			in Active			Other			Unobservable						of Plan
			Markets for			Observable			Inputs						Assets
			Identical			Inputs			(Level 3)
			Assets			(Level 2)
			(Level 1)
	Equity securities
	Common collective trusts		$	—		$	47,690		$	—		$	47,690			56.9	%
	Fixed income
	Common collective trusts			—			33,708			—			33,708			40.2	%
	Other types of investments
	Common collective trusts			—			2,453			—			2,453			2.9	%
			$	—		$	83,851		$	—		$	83,851
	Payable for securities purchased												(75	)		0	%
												$	83,776			100	%
			Fair Value Measurements as of December 31, 2013
			Quoted Prices			Significant			Significant			Total			Percentage
			in Active			Other			Unobservable						of Plan
			Markets for			Observable			Inputs						Assets
			Identical			Inputs			(Level 3)
			Assets			(Level 2)
			(Level 1)
	Cash and cash equivalents		$	1,317		$	—		$	—		$	1,317			1.7	%
	Fixed income
	U.S. corporate debt			—			17,592			—			17,592			22.2	%
	Foreign debt			—			2,871			—			2,871			3.6	%
	Mutual funds — fixed income			8,325			—			—			8,325			10.5	%
	Equity securities
	U.S. equity			27,779			—			—			27,779			35.1	%
	International equity			9,316			—			—			9,316			11.8	%
	Mutual funds — equity			11,633			—			—			11,633			14.7	%
			$	58,370		$	20,463		$	—			78,833
	Accrued interest & dividends												265			0.4	%
												$	79,098			100	%
Schedule of permissible investments
	Permissible Investments
	Equity		Fixed Income
			
	Common Stocks		Cash-Equivalent Securities with a maturity of one-year or less, including: money market funds, US Government and Agency securities, certificates of deposit or banker's acceptances issued by domestic banks with FDIC protection and commercial paper rated A1 by S&P or P1 by Moody's
			
	Preferred Stocks		Government Bonds
			
			Money Market Funds / Bank STIF Funds
			
			Certificates of Deposit in institutions with FDIC protection
			
			Corporate Bonds (minimum quality rating of A Baa by Moody's or BBB by S&P at time of issuance)
	The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.
	Listed below are those investments prohibited by the Investment Committee:
	Prohibited Investments
			
	Privately Placed Securities		Margin Transactions
			
	Securities of Empire District		Options (other than "covered call options")
			
	Derivatives		Lettered or Restricted Stock
			
	Instrumentalities in violation of the Prohibited Transactions Standards of ERISA		Any other investment security which, in the opinion of the investment manager produces an imprudent risk to the fund

EQUITY_COMPENSATION_Tables

EQUITY COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2014
EQUITY COMPENSATION
Schedule of compensation expense and tax benefits for stock-based awards and programs
	We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in thousands):
		2014			2013		2012
	Compensation expense	$	3,688		$	2,577	$	1,863
	Tax benefit recognized		1,359			929		649
Schedule of fair value measurements for each grant year
		Fair Value of Grants Outstanding at
		December 31
		2014		2013
	Total unrecognized compensation cost (in millions)	$0.40		$0.20
	Recognition period	1.1 years to 2.1 years		0.1 years to 2.1 years
	Fair value	$26.82		$19.88
Schedule of time vested restricted stock activity
		2014					2013					2012
		Number of			Weighted		Number of			Weighted		Number Of			Weighted
		Shares			Average		Shares			Average		Shares			Average
					Grant Date					Grant Date					Grant Date
					Fair Value					Fair Value					Fair Value
	Outstanding at January 1,		24,900		$	21.42		3,300		$	21.84		3,433		$	21.84
	Granted		22,600		$	22.4		21,600		$	21.36		—			—
	Distributed		(4,010	)	$	21.77		—			—		(133	)	$	20.13
	Forfeited		(2,490	)	$	21.99		—			—		—			—
	Outstanding at December 31,		41,000		$	21.89		24,900		$	21.42		3,300		$	21.84
	Vested during the year		6,500		$	21.86		—			—		—			—
Schedule of assumptions used in valuation of performance-based restricted stock awards
		Fair Value of Grants Outstanding at December 31,
		2014		2013		2012
	Risk-free interest rate	0.25% to 0.67%		0.13% to 0.38%		0.16% to 0.25%
	Expected volatility of Empire stock	14.50%		20.20%		20.60%
	Expected volatility of peer group stock	12.4% to 24.8%		12.3% to 27.5%		12.4% to 29.2%
	Expected dividend yield on Empire stock	3.50%		4.50%		4.90%
	Expected forfeiture rates	3%		3%		3%
	Plan cycle	3 years		3 years		3 years
	Fair value percentage	140.0% to 157.0%		0.0% to 108.0%		18.0% to 96.0%
	Weighted average fair value per share	$43.80		$18.47		$10.94
Schedule of non-vested performance-based restricted stock awards (based on target number) and changes during the reporting period
		2014					2013					2012
		Number of			Weighted		Number of			Weighted		Number Of			Weighted
		Shares			Average		Shares			Average		Shares			Average
					Grant Date					Grant Date					Grant Date
					Fair Value					Fair Value					Fair Value
	Outstanding at January 1,		47,200		$	21.39		33,900		$	20.25		37,400		$	19.28
	Granted		27,000		$	22.4		26,300		$	21.36		10,000		$	20.97
	Awarded		—			—		(4,460	)	$	18.36		(7,823	)	$	18.12
	Not awarded		(10,900	)	$	21.84		(8,540	)	$	18.36		(5,677	)	$	18.12
	Nonvested at December 31,		63,300		$	21.74		47,200		$	21.39		33,900		$	20.25
Schedule of assumptions used in the valuations of stock options
		Fair Value of Grants Outstanding at December 31,
		2014		2013		2012
	Risk-free interest rate	—		0.10% to 0.38%		0.11% to 0.44%
	Dividend yield	—		4.50%		4.90%
	Expected volatility	—		24.00%		24.00%
	Expected life in months	—		6.5 to 24.5		78
	Market value	—		$22.69		$20.38
	Weighted average fair value per option	—		$1.57		$1.34
Schedule of stock options activity
		2014					2013					2012
		Options			Weighted		Options			Weighted		Options			Weighted
					Average					Average					Average
					Exercise					Exercise					Exercise
					Price					Price					Price
	Outstanding at January 1,		112,500		$	23.27		163,300		$	22.13		190,300		$	21.56
	Granted		—			—				$	—		0		$	—
	Exercised		112,500		$	24.58		(50,800	)	$	21.78		(27,000	)	$	18.12
	Outstanding at December 31,		—					112,500		$	23.27		163,300		$	22.13
	Exercisable, end of year		—					112,500		$	23.27		128,500		$	23.15
Schedule of aggregate intrinsic values of stock options
		2014		2013		2012
	Aggregate intrinsic value (in millions)	—		Less than $0.1		$0.10
	Weighted-average remaining contractual life of outstanding options	—		2.1 years		3.2 years
	Range of exercise prices	—		$21.92 to $23.81		$18.36 to $23.81
	Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	—		—		Less than $0.1
	Recognition period	—		—		1 month
Schedule of shares accrued to directors' accounts and shares available for issuance under Stock Unit Plan for directors
		2014			2013
	Shares accrued to directors' accounts		164,085			154,402
	Shares available for issuance		714,978			236,056
Schedule of units accrued and redeemed under Stock Unit Plan for directors
		2014			2013		2012
	Units accrued for service and dividends		30,765			34,252		30,426
	Units redeemed for common stock		21,083			22,908		21,324

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes.
Schedule of income tax expense components
	Income tax expense components for the years ended December 31 are as follows (in thousands):
			2014			2013			2012
	Current income taxes:
	Federal		$	(2,350	)	$	6,726		$	1,552
	State			(123	)		2,495			708
	TOTAL			(2,473	)		9,221			2,260
	Deferred income taxes:
	Federal			36,620			24,954			28,210
	State			5,216			3,554			4,018
	TOTAL			41,836			28,508			32,228
	Investment tax credit amortization			(143			(237			(329
					)			)			)
	TOTAL INCOME TAX EXPENSE		$	39,220		$	37,492		$	34,159
Schedule of deferred tax assets and liabilities as reflected on consolidated balance sheet
	Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows (in thousands):
			December 31,
	Deferred Income Taxes		2014			2013
	Current deferred tax assets, net(1)		$	19,200		$	7,222
	Non-current deferred tax liabilities, net			377,452			324,266
	NET DEFERRED TAX LIABILITIES		$	358,252		$	317,044
	-1	Current deferred tax assets are included in prepaid expenses and other on the balance sheets.
Summary of temporary differences related to deferred tax assets and deferred tax liabilities
	Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows (in thousands):
			December 31,
	Temporary Differences		2014			2013
	Deferred tax assets:
	Plant related basis differences		$	25,349		$	23,344
	Net operating loss (NOL)			22,000			—
	Regulated liabilities related to income taxes			13,350			13,576
	Disallowed plant costs			1,754			1,841
	Gains on hedging transactions			1,260			1,324
	Pensions and other post-retirement benefits			1,175			544
	Carry forward of income tax credit			6,367			6,374
	Other			1,633			1,633
	Total deferred tax assets		$	72,888		$	48,636
	Deferred tax liabilities:
	Depreciation, amortization and other plant related differences		$	363,337		$	297,175
	Regulated assets related to income			37,180			37,806
	Loss on reacquired debt			3,828			4,085
	Amortization of intangibles			9,168			8,089
	Deferred construction accounting costs			6,082			6,977
	Other			11,545			11,548
	Total deferred tax liabilities			431,140			365,680
	NET DEFERRED TAX LIABILITIES		$	358,252		$	317,044
Schedule of difference between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing operations
	Effective Income Tax Rates		2014			2013			2012
	Federal statutory income tax rate			35	%		35	%		35	%
	Increase (decrease) in income tax rate resulting from:
	State income tax (net of federal benefit)			3.1			3.1			3.1
	Investment tax credit amortization			(0.1	)		(0.2	)		(0.4	)
	Effect of ratemaking on property related differences			(1.7	)		(1.1	)		(0.2	)
	Other			0.6			0.3			0.5
	EFFECTIVE INCOME TAX RATE			36.9	%		37.1	%		38	%

COMMONLY_OWNED_FACILITIES_Tabl

COMMONLY OWNED FACILITIES (Tables)	12 Months Ended
	Dec. 31, 2014
Iatan
Commonly Owned Facilities
Schedule of property, plant and equipment
	At December 31, 2014 and 2013, our property, plant and equipment accounts included the amounts in the following chart (in millions):
	Iatan		2014		2013
	Cost of ownership in plant in service		$	373.3	$	367.1
	Accumulated Depreciation		$	99.1	$	91.1
	Expenditures(1)		$	27.8	$	31.6
	-1	Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.
State Line Combined Cycle Unit
Commonly Owned Facilities
Schedule of property, plant and equipment
	At December 31, 2014 and 2013, our property, plant and equipment accounts included the amounts in the following chart (in millions):
	State Line Combined Cycle Unit		2014		2013
	Cost of ownership in plant in service		$	161.5	$	163.3
	Accumulated Depreciation		$	40.0	$	37.0
	Expenditures(1)		$	47.1	$	52.6
	-1	Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.
Plum point
Commonly Owned Facilities
Schedule of property, plant and equipment
	At December 31, 2014 and 2013, our property, plant and equipment accounts included the amounts in the following chart (in millions):
	Plum Point Energy Station		2014		2013
	Cost of ownership in plant in service		$	108.3	$	108.2
	Accumulated Depreciation		$	9.4	$	7.3
	Expenditures(1)		$	8.1	$	11.3
	-1	Recognized in operating, maintenance and fuel expenditures excluding depreciation expense.

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 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 December 31, 2014 (in millions).
		Firm physical gas		Coal and coal
		and transportation		transportation
		contracts		contracts
	January 1, 2015 through December 31, 2015	$	26.6	$	26.2
	January 1, 2016 through December 31, 2017	$	42.9	$	29.5
	January 1, 2018 through December 31, 2019	$	33.3	$	22.8
	January 1, 2020 and beyond	$	49.6		—
Schedule of lease obligations over the next five years
	Our lease obligations over the next five years are as follows (in thousands):
		Capital		Operating
		Leases		Leases
	2015	$	553	$	730
	2016		549		720
	2017		547		682
	2018		547		645
	2019		546		485
	Thereafter		3,006		—
	Total minimum payments		5,748	$	3,262
	Less amount representing interest		1,581
	Present value of net minimum lease payments	$	4,167

SEGMENT_INFORMATION_Tables

SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Information
Schedule of statement of income information, balance sheet information and capital expenditures by business segments
			For the year ended December 31,
			2014
			Electric		Gas		Other		Eliminations			Total
	Statement of Income Information:
	Revenues(1)		$	592,491	$	51,842	$	9,302	$	(1,305	)	$	652,330
	Depreciation and amortization			67,534		3,760		1,891		—			73,185
	Federal and state income taxes			35,737		1,840		1,643		—			39,220
	Operating income			90,488		6,775		2,736		—			99,999
	Interest income			37		25		21		(32	)		51
	Interest expense			37,911		3,861		—		(32	)		41,740
	Income from AFUDC (debt and equity)			9,833		84		—		—			9,917
	Income from continuing operations		$	61,467	$	2,965	$	2,671	$	—		$	67,103
	Capital Expenditures			212,866		7,836		2,151					222,853
			$		$		$		$	—		$
	-1	The Electric Segment includes SPP Integrated Marketplace net revenues of $41.9 million.
			2013
			Electric		Gas		Other		Eliminations			Total
	Statement of Income Information:
	Revenues		$	536,413	$	50,041	$	9,147	$	(1,271	)	$	594,330
	Depreciation and amortization			63,659		3,709		1,938		—			69,306
	Federal and state income taxes			34,478		1,484		1,530		—			37,492
	Operating income			90,984		6,194		2,485		—			99,663
	Interest income			537		115		8		(94	)		566
	Interest expense			37,683		3,890		—		(94	)		41,479
	Income from AFUDC (debt and equity)			5,910		30		—		—			5,940
	Income from continuing operations		$	58,603	$	2,355	$	2,487	$	—		$	63,445
	Capital Expenditures			153,401		4,419		2,388					160,208
			$		$		$		$	—		$
			2012
			Electric		Gas		Other		Eliminations			Total
	Statement of Income Information:
	Revenues		$	510,653	$	39,849	$	7,187	$	(592	)	$	557,097
	Depreciation and amortization			55,312		3,598		1,537		—			60,447
	Federal and state income taxes			32,266		789		1,104		—			34,159
	Operating income			89,445		5,005		1,771		—			96,221
	Interest income			946		323		7		(304	)		972
	Interest expense			37,866		3,905		—		(304	)		41,467
	Income from AFUDC (debt and equity)			1,918		10		—		—			1,928
	Income from continuing operations		$	52,631	$	1,256	$	1,794	$	—		$	55,681
	Capital Expenditures			140,117		3,571		2,599					146,287
			$		$		$		$	—		$
			December 31, 2014
			Electric		Gas(1)		Other		Eliminations			Total
	Balance Sheet Information:
	Total assets		$	2,271,539	$	130,856	$	34,655	$	(46,794	)	$	2,390,256
			December 31, 2013
			Electric		Gas(1)		Other		Eliminations			Total
	Balance Sheet Information:
	Total assets		$	2,034,234	$	123,736	$	31,306	$	(44,231	)	$	2,145,045
	-1	Includes goodwill of $39,492 at December 31, 2014 and 2013.

SELECTED_QUARTERLY_INFORMATION1

SELECTED QUARTERLY INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2014
SELECTED QUARTERLY INFORMATION (UNAUDITED)
Summary of quarterly results
	The following is a summary of quarterly results for 2014 and 2013 (dollars in thousands except per share amounts):
			Quarters
	Quarterly Results for 2014		First		Second		Third		Fourth
	Operating revenues(1)		$	179,673	$	149,782	$	171,512	$	151,363
	Operating income		$	29,488	$	19,502	$	31,709	$	19,300
	Net Income			20,905		11,194		23,892		11,112
			$		$		$		$
	Basic and Diluted Earnings Per Share			0.48		0.26		0.55		0.26
			$		$		$		$
	-1	Operating revenue for the first, second, third and fourth quarters of 2014 include SPP IM net revenues of $6.2 million, $16.5 million, $11.5 million, and $7.5 million, respectively.
			Quarters
	Quarterly Results for 2013		First		Second		Third		Fourth
	Operating revenues		$	151,140	$	136,646	$	157,486	$	149,058
	Operating income		$	21,858	$	21,110	$	32,896	$	23,799
	Net Income			12,630		11,658		23,996		15,162
			$		$		$		$
	Basic and Diluted Earnings Per Share			0.30		0.27		0.56		0.35
			$		$		$		$

RISK_MANAGEMENT_AND_DERIVATIVE1

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Risk Management and Derivative Financial Instruments
Schedule of fair value of derivative financial instruments, balance sheet classification
	As of December 31, 2014 and 2013, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of December 31, (in thousands):
	ASSET DERIVATIVES
	Non-designated hedging instruments due to regulatory accounting			2014			2013
		Balance Sheet Classification		Fair			Fair
				Value			Value
	Natural gas contracts, gas segment	Current assets		$	—		$	35
		Non-current assets and deferred charges — Other			—			—
	Natural gas contracts, electric segment	Current assets			1			467
		Non-current assets and deferred charges — Other			—			41
	Transmission congestion rights, electric segment	Current assets			3,900			1,967
	Total derivatives assets			$	3,901		$	2,510
	LIABILITY DERIVATIVES
	Non-designated as hedging instruments due to regulatory accounting			2014			2013
		Balance Sheet Classification		Fair			Fair
				Value			Value
	Natural gas contracts, gas segment	Current liabilities		$	476		$	8
		Non-current liabilities and deferred credits			—			—
	Natural gas contracts, electric segment	Current liabilities			5,993			1,881
		Non-current liabilities and deferred credits			3,243			2,799
	Transmission congestion rights, electric segment	Current liabilities
					—			—
	Total derivatives liabilities			$	9,712		$	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 years ended December 31 (in thousands):
	Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment
				Amount of
				Gain/(Loss)
				Recognized on
				Balance Sheet
		Balance Sheet Classification		2014			2013
		of Gain/(Loss) on Derivative
	Commodity contracts — electric segment	Regulatory (assets)/liabilities		$	(6,780	)	$	(338	)
	Transmission congestion rights — electric segment	Regulatory (assets)/liabilities			12,958			1,967
	Total — Electric Segment			$	6,178		$	1,629
	Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment
				Amount of
				Gain/(Loss)
				Recognized in
				Income on
				Derivative
		Statement of Operations Classification		2014			2013
		of Loss on Derivative
	Commodity contracts	Fuel and purchased power expense		$	(1,659	)	$	(2,725	)
	Transmission congestion rights — electric segment	Fuel and purchased power expense			11,106			81
	Total — Electric Segment			$	9,447		$	(2,644	)
Schedule of volumes and percentage of anticipated volume of natural gas usage for entity's electric operations with procurement guidelines
	Year	% Hedged			Dth Hedged			Dth Hedged		Average Price
					Physical			Financial
	2015		63	%		1,550,000			4,510,000	$	4.351
	2016		43	%		1,976,000			2,100,000	$	4.103
	2017		20	%		782,900			1,300,000	$	4.133
	2018		11	%		456,000			500,000	$	4.202
	2019		—			—			—		—
Schedule of minimum percentage hedged by year in the entity's procurement guidelines
	Year	End of Year
		Minimum % Hedged
	Current	Up to 100%
	First	60%
	Second	40%
	Third	20%
	Fourth	10%
Schedule of transmission congestion rights (TCR)
	Year	Monthly			$ Value
		MWH
		Hedged
	2015		3,483		$	3,899,526
Schedule of minimum percentage of winter season usage hedged by year of the entity's gas operations
	The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the ACA year at September 1 and illustrates our hedged position as of December 31, 2014 (Dth in thousands).
	Season	Minimum %			Dth Hedged			Dth Hedged		Dth in		Actual %
		Hedged			Financial			Physical		Storage		Hedged
	Current		50	%		430,000			341,000		1,178,367		97	%
	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 the years ended December 31 (in thousands):
	Non-Designated Hedging Instruments Due to Regulatory Accounting — Gas Segment
				Amount of
				Loss
				Recognized on
				Balance Sheet
		Balance Sheet Classification of Loss on Derivative		2014			2013
	Commodity contracts	Regulatory assets		$	(511	)	$	(5	)
					—
	Total — Gas Segment			$	(511	)	$	(5	)
Schedule of margin deposit assets
	(in millions)	December 31,			December 31,
		2014			2013
	Margin deposit assets	$	9.1		$	5.2

FAIR_VALUE_MEASUREMENTS_Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 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			Significant		Significant
	Description		at Fair Value			in Active			Other		Unobservable
						Markets			Observable		Inputs
						for Identical			Inputs		(Level 3)
						Assets			(Level 2)
						(Level 1)
	December 31, 2014
	Derivative assets		$	3,901		$	1		$	3,900	$	—
	Derivative liabilities		$	(9,712	)	$	(9,712	)	$	—	$	—
	December 31, 2013
	Derivative assets		$	2,510		$	543		$	1,967		—
	Derivative liabilities		$	(4,688	)	$	(4,688	)	$	—		—
	*	The only recurring measurements are derivative related.

REGULATED_OPERATING_EXPENSE_Ta

REGULATED OPERATING EXPENSE (Tables)	12 Months Ended
	Dec. 31, 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 the years ended (in thousands):
			December 31,
			2014		2013		2012
	Power operation expense (other than fuel)		$	16,089	$	15,643	$	15,045
	Electric transmission and distribution expense			27,919		21,863		17,083
	Natural gas transmission and distribution expense			2,362		2,498		2,443
	Customer accounts & assistance expense			11,239		11,180		10,211
	Employee pension expense(1)			10,590		10,736		10,180
	Employee healthcare plan(1)			9,147		10,190		9,825
	General office supplies and expense			15,024		12,850		10,776
	Administrative and general expense			14,385		14,800		15,091
	Bad debt expense			3,420		3,665		3,038
	Regulatory reversal of gain on sale of assets			44		1,236		—
	Miscellaneous expense			472		672		679
	TOTAL		$	110,691	$	105,333	$	94,371
	-1	Does not include the capitalized portion of actuarially calculated costs, but reflects the GAAP expensed portion of these costs plus or minus costs deferred to a regulatory asset or recognized as a regulatory liability for Missouri and Kansas jurisdictions.

SUMMARY_OF_SIGNIFICANT_ACCOUNT3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2014
	item
	segment
Summary of Significant Accounting Policies
Number of business segments	3
Number of towns to which water service is provided	3
Electric
Operating revenues
% of revenue (as a percent)	90.80%
Number of customers	170,000
Electric | Water
Operating revenues
% of revenue (as a percent)	0.30%
Electric | Missouri
Operating revenues
% of revenue (as a percent)	89.70%
Electric | Kansas
Operating revenues
% of revenue (as a percent)	4.80%
Electric | Arkansas
Operating revenues
% of revenue (as a percent)	2.70%
Electric | Oklahoma
Operating revenues
% of revenue (as a percent)	2.80%
Electric | Residential
Operating revenues
% of revenue (as a percent)	40.00%
Electric | Commercial
Operating revenues
% of revenue (as a percent)	29.20%
Electric | Industrial
Operating revenues
% of revenue (as a percent)	14.40%
Electric | Wholesale on-system
Operating revenues
% of revenue (as a percent)	3.80%
Electric | Wholesale off-system
Operating revenues
% of revenue (as a percent)	7.60%
Electric | Miscellaneous sources, primarily public authorities
Operating revenues
% of revenue (as a percent)	2.60%
Electric | Other electric revenues
Operating revenues
% of revenue (as a percent)	2.40%
Gas
Operating revenues
% of revenue (as a percent)	8.00%
Number of customers	43,500
Gas | Residential
Operating revenues
% of revenue (as a percent)	63.40%
Gas | Commercial
Operating revenues
% of revenue (as a percent)	26.30%
Gas | Industrial
Operating revenues
% of revenue (as a percent)	1.00%
Gas | Other electric revenues
Operating revenues
% of revenue (as a percent)	9.30%
Others
Operating revenues
% of revenue (as a percent)	1.20%

SUMMARY_OF_SIGNIFICANT_ACCOUNT4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Municipal Franchise Taxes
Municipal franchise taxes	$11.80	$11.20	$10.40
Property, Plant and Equipment
Period for refund of pro rata amount of the original cost of the extension to developers	5 years
Liability for refund of pro rata amount of the original cost of the extension to developers	$1.90	$4.20

SUMMARY_OF_SIGNIFICANT_ACCOUNT5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 3) (USD $)	0 Months Ended		12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2014
			item
Asset Retirement Obligation
Proportionate ownership interest (as a percent)	12.00%		12.00%
Change in asset retirement obligation
Opening balance of asset retirement obligation	$4,847,000	$4,190,000	$4,190,000	$4,711,000
Liabilities settled			-1,175,000	-734,000
Accretion			-172,000	-213,000
Cash Flow Revisions			1,660,000
Closing balance of asset retirement obligation	4,847,000	4,190,000	4,847,000	4,190,000	4,711,000
Allowance for Funds Used During Construction
Aggregate rates (on a before-tax basis)			6.60%	7.30%	5.60%
Asset Impairments (excluding goodwill)
Assets impaired	0	0
Goodwill
Number of assumptions whose negative charge will affect impairment			1
Number of approaches used to estimate the fair value			2
Fuel and Purchased Power
Inventory allowances	0		0
Pension and Other Postretirement Benefits
Percentage that unrecognized gains or losses must exceed postretirement benefit obligation or fair value of plan assets for recognition of additional income or expense			10.00%
Amortization period of unrecognized gains or losses into actuarial expense			10 years
Cash & Cash Equivalents
Checks and electronic fund transfers that have been issued but not cleared through bank	28,300,000	22,100,000	28,300,000	22,100,000
Restricted Cash
Amounts restricted for construction costs					2,500,000
Amounts restricted for operating costs	1,800,000	1,800,000	1,800,000	1,800,000
Electric
Fuel and Purchased Power
Number of SO2 allowances in inventory			872	1,834
Electric | Missouri Public Service Commission (MPSC)
Fuel and Purchased Power
Percentage of changes in fuel and purchased power costs from the base cost permitted for distribution to customers under fuel adjustment clause			95.00%
Gas
Fuel and Purchased Power
Maximum number of rate changes allowed by PGA clause throughout the year			4
SPP
Restricted Cash
Amounts restricted for secured collateral	2,500,000	1,100,000	2,500,000	1,100,000
MISO
Restricted Cash
Amounts restricted for secured collateral	500,000	0	500,000	0
Low end of range
Asset Retirement Obligation
Credit adjusted risk-free rate (as a percent)	4.50%		4.50%
Low end of range | Gas
Goodwill
Excess fair value of the reporting unit over carrying value						10,000,000
High end of range
Asset Retirement Obligation
Credit adjusted risk-free rate (as a percent)	5.52%		5.52%
High end of range | Gas
Goodwill
Excess fair value of the reporting unit over carrying value						$14,000,000

SUMMARY_OF_SIGNIFICANT_ACCOUNT6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 4) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fuel, Materials and Supplies
Total	$57,799	$48,811
Income taxes
Longest remaining amortization period for investment tax credits	50 years
Accounting for Uncertainty in Income Taxes
No material changes to unrecognized tax benefits in other expenses	12 months
Weighted Average Number Of Shares
Basic (in shares)	43,291,000	42,781,000	42,257,000
Dilutive Securities:
Performance-based restricted stock awards (in shares)	8,809	12,142	14,500
Dividend equivalents (in shares)			6,329
Employee stock purchase plan (in shares)	3,422	1,729	1,996
Stock options (in shares)		61	3,160
Time-based restricted stock awards (in shares)	10,666	7,907	1,820
Total dilutive securities (in shares)	22,897	21,839	27,805
Diluted weighted average number of shares	43,314,000	42,803,000	42,284,000
Antidilutive Shares	25,259	107,100	128,500
Electric fuel inventory
Fuel, Materials and Supplies
Total	26,454	17,003
Natural gas inventory
Fuel, Materials and Supplies
Total	5,040	3,584
Materials and supplies
Fuel, Materials and Supplies
Total	$26,305	$28,224

PROPERTY_PLANT_AND_EQUIPMENT_D

PROPERTY, PLANT AND EQUIPMENT (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, plant and equipment
Less accumulated depreciation and amortization	$743,407	$732,737
Construction work in progress	112,097	152,330
Total plant and property, Net	1,910,272	1,751,934
Plant and property, Gross	79,364	72,834
Plant and property, Gross	41,394	39,902
Provision for depreciation	72,342	68,893	62,607
Amortization	2,692	2,492	1,041
Total depreciation and amortization	75,034	71,385	63,648
Annual depreciation rates (as a percent)	3.00%	3.10%	2.90%
Regulated
Property, plant and equipment
Total plant and property, Net	1,821,772	1,668,307
Non-Regulated
Property, plant and equipment
Provision for depreciation	1,891	1,938	1,538
Annual depreciation rates (as a percent)	4.70%	5.00%	4.20%
Electric plant | Regulated
Property, plant and equipment
Plant and property, Gross	2,408,015	2,206,944
Less accumulated depreciation and amortization	704,596	697,128
Plant and property, net of depreciation and amortization	1,703,419	1,509,816
Construction work in progress	110,500	150,636
Total plant and property, Net	1,813,919	1,660,452
Electric plant | Intangible property, primarily capitalized software and investments in facility upgrades | Regulated
Property, plant and equipment
Plant and property, Gross	41,200	38,100
Less accumulated depreciation and amortization	15,700	13,100
Production | Regulated
Property, plant and equipment
Plant and property, Gross	1,159,140	1,035,095
Annual depreciation rates (as a percent)	2.40%	2.40%	2.00%
Transmission. | Regulated
Property, plant and equipment
Plant and property, Gross	288,542	263,398
Annual depreciation rates (as a percent)	2.40%	2.40%	2.40%
Distribution. | Regulated
Property, plant and equipment
Plant and property, Gross	840,761	793,024
Annual depreciation rates (as a percent)	3.60%	3.60%	3.60%
General | Regulated
Property, plant and equipment
Plant and property, Gross	119,572	115,427
Annual depreciation rates (as a percent)	5.80%	5.80%	5.90%
Gas plant | Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	16,405	15,204
Plant and property, net of depreciation and amortization	62,959	57,630
Construction work in progress	379	1,156
Total plant and property, Net	63,338	58,786
Plant and property, Gross	79,364	72,834
Provision for depreciation	3,851	3,763	3,602
Annual depreciation rates (as a percent)	5.20%	5.40%	5.40%
Transmission | Regulated
Property, plant and equipment
Plant and property, Gross	11,198	10,550
Distribution | Regulated
Property, plant and equipment
Plant and property, Gross	89,712	84,157
General | Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	500	500
Plant and property, Gross	-21,546	-21,873
General | Intangible property, primarily capitalized software and investments in facility upgrades | Regulated
Property, plant and equipment
Plant and property, Gross	700	700
Water plant | Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	5,102	4,806
Plant and property, net of depreciation and amortization	7,707	7,855
Construction work in progress	146
Total plant and property, Net	7,853	7,855
Plant and property, Gross	12,809	12,661
Annual depreciation rates (as a percent)	2.70%	2.80%	2.70%
Other | Non-Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	17,304	15,599
Plant and property, net of depreciation and amortization	24,090	24,303
Construction work in progress	1,072	538
Total plant and property, Net	25,162	24,841
Fiber | Non-Regulated
Property, plant and equipment
Plant and property, Gross	41,394	39,902
Electric and Water | Regulated
Property, plant and equipment
Provision for depreciation	$66,600	$63,192	$57,467
Annual depreciation rates (as a percent)	3.00%	3.00%	2.80%

REGULATORY_MATTERS_Details

REGULATORY MATTERS (Details) (USD $)	0 Months Ended	12 Months Ended
	22-May-11	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets:
Regulatory assets, current		10,752,000	$7,743,000
Regulatory assets, long-term		209,717,000	169,333,000
Regulatory assets, total		220,469,000	177,076,000
Regulatory Liabilities:
Regulatory liabilities, current		7,898,000	5,681,000
Regulatory liabilities, long-term		128,471,000	132,012,000
Regulatory liabilities, total		136,369,000	137,693,000
Missouri 2012 Rate Case
Regulatory Assets and Liabilities
Deferred tornado costs recovery period	10 years
Over recovered fuel costs
Regulatory Liabilities:
Regulatory liabilities, current		4,227,000	2,212,000
Current portion of long-term regulatory liabilities
Regulatory Liabilities:
Regulatory liabilities, current		3,671,000	3,469,000
Regulatory liabilities, long-term		-3,671,000	-3,469,000
Cost of removal
Regulatory Liabilities:
Regulatory liabilities, long-term		90,527,000	88,469,000
SWPA payment for Ozark Beach lost generation
Regulatory Liabilities:
Regulatory liabilities, long-term		16,744,000	19,405,000
Income taxes
Regulatory Liabilities:
Regulatory liabilities, long-term		11,451,000	11,677,000
Deferred construction accounting costs - fuel
Regulatory Liabilities:
Regulatory liabilities, long-term		7,849,000	8,011,000
Unamortized gain on interest rate derivative
Regulatory Liabilities:
Regulatory liabilities, long-term		3,201,000	3,371,000
Unamortized gain on interest rate derivative | Low end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		6 years
Unamortized gain on interest rate derivative | High end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		26 years
Pension and other postretirement benefits
Regulatory Liabilities:
Regulatory liabilities, long-term		2,369,000	2,177,000
Over recovered electric fuel and purchased power costs
Regulatory Assets:
Regulatory assets, total		3,100,000	600,000
Regulatory Liabilities:
Regulatory liabilities, long-term		1,000	2,371,000
Regulatory liabilities, total		3,100,000	600,000
Under recovered fuel costs
Regulatory Assets:
Regulatory assets, current		2,618,000	1,411,000
Regulatory assets, long-term		640,000
Current portion of long-term regulatory assets
Regulatory Assets:
Regulatory assets, current		8,134,000	6,332,000
Regulatory assets, long-term		-8,134,000	-6,332,000
Pension and other postretirement benefits
Regulatory Assets:
Regulatory assets, long-term		111,121,000	70,035,000
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		5 years
Portion of regulatory assets expected to be recoverable in future periods		103,500,000
Income taxes
Regulatory Assets:
Regulatory assets, long-term		47,177,000	48,033,000
Deferred construction accounting costs
Regulatory Assets:
Regulatory assets, long-term		15,521,000	16,275,000
Unamortized loss on reacquired debt
Regulatory Assets:
Regulatory assets, long-term		10,405,000	11,078,000
Unamortized loss on reacquired debt | Low end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		6 years
Unamortized loss on reacquired debt | High end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		26 years
System reliability - vegetation management
Regulatory Assets:
Regulatory assets, long-term		5,337,000	7,539,000
Storm costs
Regulatory Assets:
Regulatory assets, long-term		4,183,000	4,911,000
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		5 years
Asset retirement obligation Member
Regulatory Assets:
Regulatory assets, long-term		5,145,000	4,673,000
Regulatory assets, total		5,100,000	4,700,000
Customer programs
Regulatory Assets:
Regulatory assets, long-term		5,253,000	4,935,000
Unamortized loss on interest rate derivative
Regulatory Assets:
Regulatory assets, long-term		943,000	989,000
Deferred operating and maintenance expense
Regulatory Assets:
Regulatory assets, long-term		910,000	2,095,000
Other
Regulatory Assets:
Regulatory assets, long-term		2,179,000	833,000
Ice storm and tornado cost
Regulatory Assets:
Regulatory assets, long-term		3,300,000
Under recovered electric fuel and purchased gas costs | Missouri
Regulatory Liabilities:
Period to recover costs		12 months
Asbury five-year maintenance
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		5 years
Electric | Cost of removal
Regulatory Liabilities:
Regulatory liabilities, total		82,800,000	81,300,000
Electric | Unsettled derivative losses
Regulatory Assets:
Regulatory assets, long-term		9,037,000	4,269,000
Gas | Cost of removal
Regulatory Liabilities:
Regulatory liabilities, total		7,700,000	$7,200,000

REGULATORY_MATTERS_Details_2

REGULATORY MATTERS (Details 2) (USD $)

12 Months Ended

0 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 05, 2014

Jun. 17, 2011

Apr. 01, 2012

Jun. 13, 2012

Jul. 06, 2012

Apr. 02, 2013

Aug. 29, 2014

Nov. 23, 2012

Oct. 18, 2012

21-May-12

Jan. 02, 2012

Jan. 04, 2012

Jun. 30, 2011

Sep. 26, 2014

Dec. 03, 2013

RATE MATTERS

Plant Disallowance

$86,000

$2,409,000

Utilities Operating Expense Reverse Gain on Sale of Assets

44,000

1,236,000

Missouri Public Service Commission (MPSC) | Missouri 2012 Rate Case

RATE MATTERS

Write-off of various items including disallowance for the prudency of certain construction expenditures

3,600,000

Utilities Operating Expense Reverse Gain on Sale of Assets

1,200,000

Requested amount of annual increase in electric base rate

30,700,000

Percentage of annual base rate increase requested

7.56%

Missouri Public Service Commission (MPSC) | Missouri 2012 Rate Case | Iatan2

RATE MATTERS

Plant Disallowance

2,400,000

Missouri Public Service Commission (MPSC) | Electric

RATE MATTERS

Approved amount of annual increase in base rate

27,500,000

Approved percentage of annual increase in base rate

6.78%

Missouri Public Service Commission (MPSC) | Electric | Missouri 2014 Rate Case

RATE MATTERS

Requested amount of annual increase in base rate

24,300,000

Requested percentage of annual increase in base rate

5.50%

Missouri Public Service Commission (MPSC) | Electric | Tornado Recovery

RATE MATTERS

Deferred depreciation, operations and maintenance, and carrying costs related to capital expenditure

4,000,000

Amortization period for deferred asset related to the tax benefits of cost of removal

10 years

Missouri Public Service Commission (MPSC) | Water

RATE MATTERS

Approved amount of annual increase in base rate

450,000

Approved percentage of annual increase in base rate

25.50%

Missouri Public Service Commission (MPSC) | Water | Missouri 2012 Rate Case

RATE MATTERS

Requested amount of annual increase in electric base rate

516,400

Percentage of annual base rate increase requested

29.60%

Amount of increase in base rate for which unanimous agreement filed

450,000

Kansas Corporation Commission (KCC) | 2014 Environmental Cost Recovery Rider Member

RATE MATTERS

Proposed recover costs

859,674

Kansas Corporation Commission (KCC) | Electric

RATE MATTERS

Approved amount of annual increase in base rate

1,250,000

Approved percentage of annual increase in base rate

5.20%

Kansas Corporation Commission (KCC) | Electric | Kansas 2011 Rate Case

RATE MATTERS

Requested amount of annual increase in electric base rate

1,500,000

Percentage of annual base rate increase requested

6.39%

Period to recover costs

3 years

Oklahoma Corporation Commission (OCC) | Electric

RATE MATTERS

Approved amount of annual increase in base rate

240,722

Approved percentage of annual increase in base rate

1.66%

Requested amount of annual increase in electric base rate

600,000

Percentage of annual base rate increase requested

4.10%

Base rate revenue included in authorized amount of increase in annual revenues

200,000

Arkansas Public Service Commission (APSC) | Electric

RATE MATTERS

Approved amount of annual increase in base rate

1,366,809

Approved percentage of annual increase in base rate

11.34%

Arkansas Public Service Commission (APSC) | Electric | Arkansas 2013 Rate Case

RATE MATTERS

Requested amount of annual increase in electric base rate

$1,375,000

$2,200,000

Percentage of annual base rate increase requested

11.00%

18.00%

Federal Energy Regulatory Commission (FERC) | TFR rate case

RATE MATTERS

Percentage of ROE

10.00%

REGULATORY_MATTERS_Details_3

REGULATORY MATTERS (Details 3) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Oct. 31, 2012	Dec. 31, 2014	Dec. 31, 2010
	item
RATE MATTERS
Deferred expenses related to rate cases		$0.50
SPP Regional Transmission Development | Low end of range
RATE MATTERS
Transmission Project Voltage (in kV)	161
Estimated increase in net transmission cost in 2014 as a result of SPP's allocation methodology		3
SPP Regional Transmission Development | High end of range
RATE MATTERS
Estimated increase in net transmission cost in 2014 as a result of SPP's allocation methodology		$4
SPP Regional Transmission Development | Transmission projects between 100 kV and 299 kV | Electric
RATE MATTERS
Regional Funding Percentage			33.30%
Zonal Funding Percentage			66.70%
SPP Regional Transmission Development | Transmission projects 300 kV or above | Electric
RATE MATTERS
Regional Funding Percentage			100.00%
Zonal Funding Percentage			0.00%
SPP Regional Transmission Development | Transmission projects below 100 kV | Electric
RATE MATTERS
Regional Funding Percentage			0.00%
Zonal Funding Percentage			100.00%
SPP Day-Ahead Market | Low end of range
RATE MATTERS
Percentage of generation needed for next day throughout SPP territory that will be cleared through Integrated Marketplace		90.00%
SPP Day-Ahead Market | High end of range
RATE MATTERS
Percentage of generation needed for next day throughout SPP territory that will be cleared through Integrated Marketplace		95.00%

SHAREHOLDERS_EQUITY_Details

SHAREHOLDERS' EQUITY (Details) (USD $)	0 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 13, 2013	Dec. 31, 2014	Dec. 31, 2013
SHAREHOLDERS' EQUITY
Shelf registration statement, amount	$200	$200
Maximum amount of securities to be issued in the form of first mortgage bonds		150
Amount that would remain available after giving effect to issuance of first mortgage bonds		90
Issuance of first mortgage bonds		$60
Effective period to use proceeds under shelf to fund capital expenditures, refinancings of existing debt or general corporate needs	3 years	3 years
Employee Stock Purchase Plan
Stock-Based Awards and Programs
Shares available for issuance		820,838	127,774
2015 Stock Incentive Plan
Stock-Based Awards and Programs
Number of shares of common stock provided for grant		500,000
401 (k) plan and ESOP
Stock-Based Awards and Programs
Shares available to be issued		196,399	256,448

SHAREHOLDERS_EQUITY_Details_2

SHAREHOLDERS' EQUITY (Details 2) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Dividends
Diluted earnings per share (in dollars per share)	$0.26	$0.55	$0.26	$0.48	$0.35	$0.56	$0.27	$0.30	$1.55	$1.48	$1.32
Dividends paid per share (in dollars per share)									$1.02	$1.00	$1
Total dividends paid									$44,381,000	$43,006,000	$42,273,000
Retained earnings year-end balance	90,276,000				67,554,000				90,276,000	67,554,000	47,100,000
First quarterly dividend paid excluded from EDE Mortgage covenant									98,000
Cumulative aggregate amount up to which the entity may declare or pay any dividends as per EDE Mortgage covenant									$10,750,000
Maximum period for payment of dividend after the related date of declaration or notice of dividend as per EDE Mortgage covenant									60 days
Ratio of total indebtedness to total capitalization	0.625								0.625

SHAREHOLDERS_EQUITY_Details_3

SHAREHOLDERS' EQUITY (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Preferred stock issued (in shares)	0	0
Preferred stock outstanding (in shares)	0	0
Preferred stock
Preferred stock authorized (in shares)	2,500,000
Series A Participating Preference Stock
Preferred stock authorized (in shares)	500,000
Cumulative preferred stock
Preferred stock authorized (in shares)	5,000,000
Preferred stock, par value per share (in dollars per share)	10

LONGTERM_DEBT_Details

LONG-TERM DEBT (Details) (USD $)	0 Months Ended	12 Months Ended	0 Months Ended
	Dec. 13, 2013	Dec. 31, 2014	Oct. 30, 2012	Oct. 15, 2014	Dec. 31, 2013
LONG-TERM DEBT
Less unamortized net discount		($686,000)			($739,000)
Total long-term debt, current and non current		803,481,000			743,702,000
Total long-term debt, current and non current		804,167,000
Current obligations under capital lease		-292,000			-274,000
Total long-term debt		803,189,000			743,428,000
Shelf registration statement, amount	200,000,000	200,000,000
Effective period to use proceeds under shelf to fund capital expenditures, refinancings of existing debt or general corporate needs	3 years	3 years
EDE
LONG-TERM DEBT
Debt permitted to be issued on compliance of interest coverage ratio covenant		615,900,000
First mortgage bonds
LONG-TERM DEBT
Total long-term debt, current and non current		698,000,000			638,000,000
First mortgage bonds | EDE
LONG-TERM DEBT
Number of consecutive months within the fifteen months preceding issuance to determine net earnings to annual interest requirement ratio		12 months
Number of months preceding issuance to determine net earnings to annual interest requirement ratio		15 months
Net earnings to annual interest requirement ratio		2
Maximum principal amount outstanding at any one time		1,000,000,000
Interest rate assumed on debt permitted to be issued on compliance of interest coverage ratio covenant (as a percent)		5.50%
New bonds to be issued as a percentage of net property additions		60.00%
First mortgage bonds | EDE | Low end of range
LONG-TERM DEBT
Debt permitted to be issued on compliance of amount of retired bonds and percentage of net property additions covenant		952,500,000
First mortgage bonds | EDG
LONG-TERM DEBT
Maximum principal amount outstanding at any one time		300,000,000
Interest rate assumed on debt permitted to be issued on compliance of interest coverage ratio covenant (as a percent)		5.50%
Debt permitted to be issued on compliance of amount of retired bonds and percentage of net property additions covenant		19,700,000
Number of most recent fiscal quarters used in calculating the interest coverage ratio as per the terms of debt instrument covenants		12 months
Ratio of EBITDA to interest charges, minimum		2
First mortgage bonds | EDG | High end of range
LONG-TERM DEBT
New bonds to be issued as a percentage of net property additions		75.00%
7.20% Series due 2016 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current		25,000,000			25,000,000
Interest rate, stated percentage		7.20%			7.20%
5.875% Series due 2037 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current		80,000,000			80,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		5.88%
6.375% Series due 2018 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current		90,000,000			90,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		6.38%			6.38%
4.65% Series due 2020 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current		100,000,000			100,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		4.65%			4.65%
5.20% Series due 2040 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current		50,000,000			50,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		5.20%
3.58% Series Due 2027 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current		88,000,000			88,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		3.58%			3.58%
3.73% Series due 2033
LONG-TERM DEBT
Aggregate principal amount of debt entered into in private placement			30,000,000
Interest rate, stated percentage		3.73%
3.73% Series due 2033 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current		30,000,000			30,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		3.73%
4.32% Series due 2043
LONG-TERM DEBT
Aggregate principal amount of debt entered into in private placement			120,000,000
Interest rate, stated percentage		4.32%
4.32% Series due 2043 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current		120,000,000			120,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		4.32%
4.27% Series due 2044
LONG-TERM DEBT
Aggregate principal amount of debt entered into in private placement				60,000,000
Interest rate, stated percentage		4.27%
4.27% Series due 2044 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current		60,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		4.27%
6.82% Series due 2036 | EDG
LONG-TERM DEBT
Total long-term debt, current and non current		55,000,000			55,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		6.82%			6.82%
Senior Notes, 4.50% Series due 2013
LONG-TERM DEBT
Debt to be redeemed		98,000,000
Interest rate, stated percentage		4.50%
Senior Notes, 6.70% Series due 2033
LONG-TERM DEBT
Total long-term debt, current and non current		62,000,000			62,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		6.70%			6.70%
Senior Notes, 5.80% Series due 2035
LONG-TERM DEBT
Total long-term debt, current and non current		40,000,000			40,000,000
Percentage of principal amount at which the entity may redeem all the notes		100.00%
Interest rate, stated percentage		5.80%			5.80%
Other.
LONG-TERM DEBT
Total long-term debt, current and non current		4,167,000			4,441,000
New first mortgage bonds | EDE | High end of range
LONG-TERM DEBT
Debt permitted to be issued based on the limit on the principal amount and current level of outstanding bonds		$357,000,000

LONGTERM_DEBT_Details_2

LONG-TERM DEBT (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Long-Term Debt Payout Schedule
2015	$292
2016	25,308
2017	325
2018	90,347
2019	371
Thereafter	687,524
Total long-term debt obligations	804,167
Less current obligations and unamortized discount	978
Total long-term debt	803,189	743,428
Regulated Entity Debt Obligations
Long-Term Debt Payout Schedule
2016	25,000
2018	90,000
Thereafter	685,000
Total long-term debt obligations	800,000
Capital Lease Obligations
Long-Term Debt Payout Schedule
2015	292
2016	308
2017	325
2018	347
2019	371
Thereafter	2,524
Total long-term debt obligations	$4,167

SHORTTERM_BORROWINGS_Details

SHORT-TERM BORROWINGS (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 20, 2014	Oct. 19, 2014
				item
Short-Term Borrowings
Short-term borrowings	$44,000,000	$4,000,000
Average borrowings outstanding	30,000,000	8,700,000
Highest month-end balances	77,000,000	29,000,000
Weighted average interest rate during period (as a percent)	0.38	0.69
Weighted average interest rate at year end (as a percent)	0.44%	0.33%
Debt issuance costs	651,000	1,879,000	1,074,000
Commercial paper
Short-Term Borrowings
Short-term borrowings	44,000,000
Outstanding borrowings	0
Amount of credit facility used to back up outstanding commercial paper borrowings	44,000,000
Unsecured revolving credit facility
Short-Term Borrowings
Unsecured revolving credit facility				200,000,000	150,000,000
Maturity term				5 years
Number of extensions				2
Extension period				1 year
Facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings (as a percent)	0.18%
Debt issuance costs	300,000
Maximum percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement	65
Minimum interest coverage ratio based on EBITDA under the financial covenants of the credit facility agreement	0.52
EBITDA coverage ratio over interest charges	1
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.	25,000,000
Outstanding borrowings	0
Unsecured revolving credit facility | Federal fund effective rate
Short-Term Borrowings
Margin over the base rate (as a percent)	0.50%
Unsecured revolving credit facility | One month LIBOR
Short-Term Borrowings
Description of interest rate basis	one month LIBOR
Margin over the base rate (as a percent)	1.00%
Unsecured revolving credit facility | One month, two month or three month LIBOR
Short-Term Borrowings
Description of interest rate basis	one month, two month, three month or six month LIBOR
Margin over the base rate (as a percent)	1.03%
Letters of credit
Short-Term Borrowings
Unsecured revolving credit facility				20,000,000
Additional borrowing capacity	75,000,000
Swingline loan
Short-Term Borrowings
Unsecured revolving credit facility				$20,000,000

RETIREMENT_BENEFITS_Details

RETIREMENT BENEFITS (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Amounts recognized in the balance sheet
Accounts payable and accrued liabilities	$83,420,000	$71,375,000
Pension and other postretirement benefit obligations	93,863,000	51,405,000
Effect of 1% change in assumed healthcare cost growth rates
Number of non-callable corporate bonds	500
Low end of range
Retirement and other employee benefits
Maturity of non-cancellable corporate bonds	0 years
High end of range
Retirement and other employee benefits
Maturity of non-cancellable corporate bonds	30 years
Pension Benefits
Retirement and other employee benefits
Lump sum distribution	9,000,000	7,000,000
Increase (decrease) in net liability	20,600,000
Estimated contribution in next fiscal year	12,800,000
Reconciliation of Projected Benefit Obligations:
Benefit obligation at beginning of year	225,131,000	248,004,000
Service cost	6,467,000	7,454,000	6,261,000
Interest cost	10,819,000	10,063,000	10,258,000
Amendments	-7,753,000
Net actuarial (gain)/loss	36,742,000	-23,300,000
Benefits and expenses paid	-19,527,000	-17,090,000
Benefit obligation at end of year	251,879,000	225,131,000	248,004,000
Reconciliation of Fair Value of Plan Assets:
Fair value of plan assets at beginning of year	186,547,000	160,175,000
Actual return on plan assets gain/(loss)	14,319,000	27,260,000
Employer contribution	11,335,000	16,202,000
Benefits paid	-19,527,000	-17,090,000
Fair value of plan assets at end of year	192,674,000	186,547,000	160,175,000
Reconciliation of Funded Status:
Fair value of plan assets	192,674,000	186,547,000	160,175,000
Projected benefit obligations	-251,879,000	-225,131,000	-248,004,000
Funded status	-59,205,000	-38,584,000
Employee pension plan accumulated benefit obligation
Accumulated benefit obligation	227,928,000	201,258,000
Amounts recognized in the balance sheet
Pension and other postretirement benefit obligations	59,205,000	38,584,000
Net Periodic Pension Benefit Cost:
Expected return on plan assets	-13,105,000	-12,428,000	-12,309,000
Amortization of prior service cost	418,000	532,000	531,000
Amortization of net actuarial loss	6,611,000	10,445,000	7,935,000
Net periodic benefit cost	11,210,000	16,066,000	12,676,000
Activity in the regulatory asset accounts
Beginning Balance	56,709,000	105,818,000
Current Year Actuarial (Gain)/Loss	35,529,000	-38,132,000
Amortization of Actuarial Loss	-6,611,000	-10,445,000
Current Year Prior Service Credit	-7,753,000
Amortization of Prior Service (Cost)/Credit	-418,000	-532,000
Ending Balance	77,456,000	56,709,000	105,818,000
Amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost
Net actuarial loss	84,178,000
Prior service cost (benefit)	-6,722,000
Total	77,456,000	56,709,000	105,818,000
Amounts expected to be recognized in the subsequent year
Net actuarial loss	9,380,000
Prior service cost (benefit)	-630,000
Total	8,750,000
Weighted-average assumptions used to determine the benefit obligation
Discount rate (as a percent)	4.06%	4.90%
Rate of compensation increase (as a percent)	3.50%	3.50%
Weighted-average assumptions used to determine the net benefit cost (income)
Discount rate (as a percent)	4.90%	4.00%	4.70%
Expected return on plan assets (as a percent)	7.75%	7.75%	7.90%
Rate of compensation increase (as a percent)	3.50%	3.50%	3.50%
Pension Benefits | Payments from Trust
Expected benefit payments
2015	25,000,000
2016	22,000,000
2017	22,100,000
2018	20,800,000
2019	19,500,000
2020 - 2024	97,300,000
Pension Benefits | Payments from Company Funds
Expected benefit payments
2015	500,000
2016	500,000
2017	500,000
2018	500,000
2019	500,000
2020 - 2024	3,000,000
SERP
Reconciliation of Projected Benefit Obligations:
Benefit obligation at beginning of year	7,108,000	6,365,000
Service cost	153,000	135,000	51,000
Interest cost	387,000	315,000	263,000
Amendments	-45,000
Net actuarial (gain)/loss	1,890,000	604,000
Benefits and expenses paid	-338,000	-311,000
Benefit obligation at end of year	9,155,000	7,108,000	6,365,000
Reconciliation of Funded Status:
Projected benefit obligations	-9,155,000	-7,108,000	-6,365,000
Funded status	-9,155,000	-7,108,000
Employee pension plan accumulated benefit obligation
Accumulated benefit obligation	7,160,000	5,702,000
Amounts recognized in the balance sheet
Accounts payable and accrued liabilities	481,000	372,000
Pension and other postretirement benefit obligations	8,674,000	6,736,000
Net Periodic Pension Benefit Cost:
Amortization of prior service cost	-8,000	-8,000	-8,000
Amortization of net actuarial loss	504,000	567,000	389,000
Net periodic benefit cost	1,036,000	1,009,000	695,000
Activity in the regulatory asset accounts
Beginning Balance	4,188,000	4,143,000
Current Year Actuarial (Gain)/Loss	1,890,000	604,000
Amortization of Actuarial Loss	-504,000	-567,000
Current Year Prior Service Credit	-45,000
Amortization of Prior Service (Cost)/Credit	8,000	8,000
Ending Balance	5,537,000	4,188,000	4,143,000
Amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost
Net actuarial loss	5,595,000
Prior service cost (benefit)	-58,000
Total	5,537,000	4,188,000	4,143,000
Amounts expected to be recognized in the subsequent year
Net actuarial loss	560,000
Prior service cost (benefit)	-43,000
Total	517,000
OPEB
Retirement and other employee benefits
Increase (decrease) in net liability	19,900,000
Estimated contribution in next fiscal year	5,000,000
Expected benefit payments
Eligible age	55 years
Minimum service period for eligibility	5 years
Reconciliation of Projected Benefit Obligations:
Benefit obligation at beginning of year	85,332,000	94,738,000
Service cost	2,601,000	2,941,000	2,401,000
Interest cost	4,360,000	3,827,000	4,037,000
Net actuarial (gain)/loss	20,347,000	-12,767,000
Plan participant's contribution	850,000	949,000
Benefits and expenses paid	-3,897,000	-4,396,000
Federal subsidy	306,000	40,000
Benefit obligation at end of year	109,899,000	85,332,000	94,738,000
Reconciliation of Fair Value of Plan Assets:
Fair value of plan assets at beginning of year	79,098,000	67,667,000
Actual return on plan assets gain/(loss)	5,030,000	10,361,000
Employer contribution	2,258,000	4,360,000
Benefits paid	-3,707,000	-4,229,000
Plan participant's contribution	804,000	901,000
Federal subsidy	293,000	38,000
Fair value of plan assets at end of year	83,776,000	79,098,000	67,667,000
Reconciliation of Funded Status:
Fair value of plan assets	83,776,000	79,098,000	67,667,000
Projected benefit obligations	-109,899,000	-85,332,000	-94,738,000
Funded status	-26,123,000	-6,234,000
Amounts recognized in the balance sheet
Accounts payable and accrued liabilities	139,000	147,000
Pension and other postretirement benefit obligations	25,984,000	6,087,000
Net Periodic Pension Benefit Cost:
Expected return on plan assets	-4,801,000	-4,353,000	-4,135,000
Amortization of prior service cost	-1,011,000	-1,011,000	-1,011,000
Amortization of net actuarial loss	967,000	2,261,000	1,661,000
Net periodic benefit cost	2,116,000	3,665,000	2,953,000
Activity in the regulatory asset accounts
Beginning Balance	285,000	20,311,000
Current Year Actuarial (Gain)/Loss	20,117,000	-18,776,000
Amortization of Actuarial Loss	-967,000	-2,261,000
Amortization of Prior Service (Cost)/Credit	1,011,000	1,011,000
Ending Balance	20,446,000	285,000	20,311,000
Amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost
Net actuarial loss	23,030,000
Prior service cost (benefit)	-2,584,000
Total	20,446,000	285,000	20,311,000
Amounts expected to be recognized in the subsequent year
Net actuarial loss	2,725,000
Prior service cost (benefit)	-1,011,000
Total	1,714,000
Weighted-average assumptions used to determine the benefit obligation
Discount rate (as a percent)	4.15%	5.00%
Rate of compensation increase (as a percent)	3.50%	3.50%
Weighted-average assumptions used to determine the net benefit cost (income)
Discount rate (as a percent)	5.00%	4.11%	4.90%
Expected return on plan assets (as a percent)	6.52%	6.52%	6.65%
Rate of compensation increase (as a percent)	3.50%	3.50%	3.50%
Cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation
Cost trend rate assumed (as a percent)	7.00%
Decrease in trend rate through 2019 (as a percent)	0.50%
Ultimate rate (as a percent)	5.00%
Effect of 1% change in assumed healthcare cost growth rates
Effect of 1% increase on total of service and interest cost	1,395,000
Effect of 1% decrease on total of service and interest cost	-1,084,000
Effect of 1% increase on post-retirement benefit obligation	19,135,000
Effect of 1% decrease on post-retirement benefit obligation	-14,983,000
OPEB | Payments from Trust
Expected benefit payments
2015	2,800,000
2016	3,100,000
2017	3,400,000
2018	3,700,000
2019	4,000,000
2020 - 2024	24,400,000
OPEB | Expected Federal Subsidy
Estimated benefit payments
2015	300,000
2016	400,000
2017	400,000
2018	500,000
2019	500,000
2020 - 2024	3,300,000
OPEB | Payments from Company Funds
Expected benefit payments
2015	100,000
2016	200,000
2017	100,000
2018	200,000
2019	100,000
2020 - 2024	$800,000

RETIREMENT_BENEFITS_Details_2

RETIREMENT BENEFITS (Details 2) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Fair value measurements of plan assets
Period over which the market-related value is determined	5 years
Number of basic elements on which primary investment goals of the company for pension fund assets are based (in counts)	4
Target allocations for plan assets
Cash investment managers generally hold in their portfolios (as a percent)	10.00%
Fund assets measured at fair value
Fair value of plan assets	$192,674		$160,175
Percentage of Plan Assets	100.00%	100.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	186,547
Actual return on plan assets:
Fair value of plan assets at end of year	192,674		160,175
Pension Benefits | Equity securities
Target allocations for plan assets
Target allocation (as a percent)	72.00%
Pension Benefits | Equity securities | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	80.00%
Pension Benefits | Equity securities | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	60.00%
Pension Benefits | Common collective trust
Fund assets measured at fair value
Fair value of plan assets	91,530	104,713
Percentage of Plan Assets	47.50%	56.10%
Actual return on plan assets:
Fair value of plan assets at end of year	91,530	104,713
Pension Benefits | Short term investments
Fund assets measured at fair value
Fair value of plan assets	70	74
Percentage of Plan Assets	0.00%	0.10%
Actual return on plan assets:
Fair value of plan assets at end of year	70	74
Pension Benefits | Equity long/short hedge funds
Fund assets measured at fair value
Fair value of plan assets	38,428	36,729
Percentage of Plan Assets	20.00%	19.70%
Actual return on plan assets:
Fair value of plan assets at end of year	38,428	36,729
Pension Benefits | Fixed income
Target allocations for plan assets
Target allocation (as a percent)	28.00%
Pension Benefits | Fixed income | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	40.00%
Pension Benefits | Fixed income | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	20.00%
Pension Benefits | Common collective trust
Fund assets measured at fair value
Fair value of plan assets	62,646	45,031
Percentage of Plan Assets	32.50%	24.10%
Actual return on plan assets:
Fair value of plan assets at end of year	62,646	45,031
Pension Benefits | Comingled bond funds
Fund assets measured at fair value
Maximum high yield	25.00%
Pension Benefits | Quoted Prices in Active Markets for Identical Liabilities (Level 1)
Fund assets measured at fair value
Fair value of plan assets		74
Actual return on plan assets:
Fair value of plan assets at end of year		74
Pension Benefits | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | Short term investments
Fund assets measured at fair value
Fair value of plan assets		74
Actual return on plan assets:
Fair value of plan assets at end of year		74
Pension Benefits | Significant Other Observable Inputs (Level 2)
Fund assets measured at fair value
Fair value of plan assets	154,246	149,744
Actual return on plan assets:
Fair value of plan assets at end of year	154,246	149,744
Pension Benefits | Significant Other Observable Inputs (Level 2) | Common collective trust
Fund assets measured at fair value
Fair value of plan assets	91,530	104,713
Actual return on plan assets:
Fair value of plan assets at end of year	91,530	104,713
Pension Benefits | Significant Other Observable Inputs (Level 2) | Short term investments
Fund assets measured at fair value
Fair value of plan assets	70
Actual return on plan assets:
Fair value of plan assets at end of year	70
Pension Benefits | Significant Other Observable Inputs (Level 2) | Common collective trust
Fund assets measured at fair value
Fair value of plan assets	62,646	45,031
Actual return on plan assets:
Fair value of plan assets at end of year	62,646	45,031
Pension Benefits | Significant Unobservable Inputs (Level 3)
Fund assets measured at fair value
Fair value of plan assets	38,428	36,729
Actual return on plan assets:
Fair value of plan assets at end of year	38,428	36,729
Pension Benefits | Significant Unobservable Inputs (Level 3) | Equity long/short hedge funds
Fund assets measured at fair value
Fair value of plan assets	38,428	36,729
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	36,729	28,885
Actual return on plan assets:
Relating to assets still held at the reporting date	1,382	-356
Relating to assets sold during the period	1,491	4,583
Purchases	9,700	26,500
Sales	-10,874	-22,883
Fair value of plan assets at end of year	38,428	36,729
OPEB
Fund assets measured at fair value
Fair value of plan assets	83,776	79,098	67,667
Percentage of Plan Assets	100.00%	100.00%
Actual return on plan assets:
Fair value of plan assets at end of year	83,776	79,098	67,667
OPEB | Debt securities
Target allocations for plan assets
Target allocation (as a percent)	40.00%
OPEB | Equity securities
Target allocations for plan assets
Target allocation (as a percent)	60.00%
OPEB | Equity securities | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	76.00%
OPEB | Equity securities | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	44.00%
OPEB | Common collective trust
Fund assets measured at fair value
Fair value of plan assets	47,690
Percentage of Plan Assets	56.90%
Actual return on plan assets:
Fair value of plan assets at end of year	47,690
OPEB | Fund assets
Fund assets measured at fair value
Fair value of plan assets	83,851	78,833
Actual return on plan assets:
Fair value of plan assets at end of year	83,851	78,833
OPEB | U.S. equity
Fund assets measured at fair value
Fair value of plan assets		27,779
Percentage of Plan Assets		35.10%
Actual return on plan assets:
Fair value of plan assets at end of year		27,779
OPEB | International equity
Fund assets measured at fair value
Fair value of plan assets		9,316
Percentage of Plan Assets		11.80%
Actual return on plan assets:
Fair value of plan assets at end of year		9,316
OPEB | Cash and cash equivalents
Fund assets measured at fair value
Fair value of plan assets		1,317
Percentage of Plan Assets		1.70%
Actual return on plan assets:
Fair value of plan assets at end of year		1,317
OPEB | Cash and cash equivalents | High end of range
Target allocations for plan assets
Target allocation (as a percent)	10.00%
OPEB | Mutual funds - fixed income
Fund assets measured at fair value
Fair value of plan assets		8,325
Percentage of Plan Assets		10.50%
Actual return on plan assets:
Fair value of plan assets at end of year		8,325
OPEB | Mutual funds - equity
Fund assets measured at fair value
Fair value of plan assets		11,633
Percentage of Plan Assets		14.70%
Actual return on plan assets:
Fair value of plan assets at end of year		11,633
OPEB | Fixed income | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	44.00%
OPEB | Fixed income | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	36.00%
OPEB | Common collective trust
Fund assets measured at fair value
Fair value of plan assets	33,708
Percentage of Plan Assets	40.20%
Actual return on plan assets:
Fair value of plan assets at end of year	33,708
OPEB | U.S. corporate debt
Fund assets measured at fair value
Fair value of plan assets		17,592
Percentage of Plan Assets		22.20%
Actual return on plan assets:
Fair value of plan assets at end of year		17,592
OPEB | Foreign debt
Fund assets measured at fair value
Fair value of plan assets		2,871
Percentage of Plan Assets		3.60%
Actual return on plan assets:
Fair value of plan assets at end of year		2,871
OPEB | Common collective trusts
Fund assets measured at fair value
Fair value of plan assets	2,453
Percentage of Plan Assets	2.90%
Actual return on plan assets:
Fair value of plan assets at end of year	2,453
OPEB | Accrued interest & dividends
Fund assets measured at fair value
Fair value of plan assets		265
Percentage of Plan Assets		0.40%
Actual return on plan assets:
Fair value of plan assets at end of year		265
OPEB | Payable for securities purchased
Fund assets measured at fair value
Fair value of plan assets	-75
Percentage of Plan Assets	0.00%
Actual return on plan assets:
Fair value of plan assets at end of year	-75
OPEB | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | Fund assets
Fund assets measured at fair value
Fair value of plan assets		58,370
Actual return on plan assets:
Fair value of plan assets at end of year		58,370
OPEB | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | U.S. equity
Fund assets measured at fair value
Fair value of plan assets		27,779
Actual return on plan assets:
Fair value of plan assets at end of year		27,779
OPEB | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | International equity
Fund assets measured at fair value
Fair value of plan assets		9,316
Actual return on plan assets:
Fair value of plan assets at end of year		9,316
OPEB | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | Cash and cash equivalents
Fund assets measured at fair value
Fair value of plan assets		1,317
Actual return on plan assets:
Fair value of plan assets at end of year		1,317
OPEB | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | Mutual funds - fixed income
Fund assets measured at fair value
Fair value of plan assets		8,325
Actual return on plan assets:
Fair value of plan assets at end of year		8,325
OPEB | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | Mutual funds - equity
Fund assets measured at fair value
Fair value of plan assets		11,633
Actual return on plan assets:
Fair value of plan assets at end of year		11,633
OPEB | Significant Other Observable Inputs (Level 2) | Common collective trust
Fund assets measured at fair value
Fair value of plan assets	47,690
Actual return on plan assets:
Fair value of plan assets at end of year	47,690
OPEB | Significant Other Observable Inputs (Level 2) | Fund assets
Fund assets measured at fair value
Fair value of plan assets	83,851	20,463
Actual return on plan assets:
Fair value of plan assets at end of year	83,851	20,463
OPEB | Significant Other Observable Inputs (Level 2) | Common collective trust
Fund assets measured at fair value
Fair value of plan assets	33,708
Actual return on plan assets:
Fair value of plan assets at end of year	33,708
OPEB | Significant Other Observable Inputs (Level 2) | U.S. corporate debt
Fund assets measured at fair value
Fair value of plan assets		17,592
Actual return on plan assets:
Fair value of plan assets at end of year		17,592
OPEB | Significant Other Observable Inputs (Level 2) | Foreign debt
Fund assets measured at fair value
Fair value of plan assets		2,871
Actual return on plan assets:
Fair value of plan assets at end of year		2,871
OPEB | Significant Other Observable Inputs (Level 2) | Common collective trusts
Fund assets measured at fair value
Fair value of plan assets	2,453
Actual return on plan assets:
Fair value of plan assets at end of year	$2,453
Employee Stock Purchase Plan
Actual return on plan assets:
Common stock purchase price to eligible employees (as a percent)	90.00%
Percentage of Black-Scholes methodology used as a component to calculate value of lookback feature	90.00%
Percentage of maximum subscription price used as a component to calculate value of lookback feature	10.00%
Shares available for issuance	820,838	127,774
Subscriptions outstanding (in shares)	57,369	60,413	70,850
Maximum subscription price (in dollars per share)	$21.43	$19.58	$17.95
Shares of stock issued	56,942	68,099	65,919
Stock issuance price (in dollars per share)	$19.58	$17.95	$17.27
Assumptions for valuation of shares
Weighted average fair value of grants (in dollars per share)	$3.07	$2.78	$3.19
Risk-free interest rate (as a percent)	0.10%	0.14%	0.17%
Dividend yield (as a percent)	4.30%	4.60%	5.00%
Expected volatility (as a percent)	14.00%	14.00%	24.00%
Expected life in months	12 months	12 months	12 months
401 (k) plan and ESOP
401 (k) plan and ESOP
Maximum percentage of annual compensation to be deferred by participating employees	25.00%
Shares available to be issued	196,399	256,448
Shares contributed	60,049	64,128	65,502
Cash balance formula
401 (k) plan and ESOP
Percentage of each employee's deferrals to be matched	100.00%
Maximum matching contribution as a percentage of employee's eligible compensation	6.00%
Percentage of matching contribution made in shares	3.00%
Average annual basic earnings formula
401 (k) plan and ESOP
Percentage of each employee's deferrals to be matched	50.00%
Maximum matching contribution as a percentage of employee's eligible compensation	3.00%

EQUITY_COMPENSATION_Details

EQUITY COMPENSATION (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
EQUITY COMPENSATION
Compensation Expense	$3,688,000	$2,577,000	$1,863,000
Tax Benefit Recognized	1,359,000	929,000	649,000
2015 Stock Incentive Plan
Fair value
Number of shares of common stock provided for grant	500,000
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	3,300	3,433
Granted (in shares)	22,600	21,600
Distributed (in shares)	-4,010		-133
Forfeited (in shares)	-2,490
Nonvested, balance at the end of the period (in shares)	41,000	24,900	3,300
Vested (in shares)	6,500
Weighted Average Grant Date Price
Nonvested, balance at the beginning of the period (in dollars per share)	$21.42	$21.84	$21.84
Granted (in dollars per share)	$22.40	$21.36
Distributed (in dollars per share)	$21.77		$20.13
Not Awarded (in dollars per share)	$21.99
Nonvested, balance at the end of the period (in dollars per share)	$21.89	$21.42	$21.84
Vested (in dollars per share)	$21.86
Fair value
Unrecognized compensation expense	400,000	200,000
Recognition period	1 year 1 month 6 days
Fair value (in dollars per share)	$26.82	$19.88
Time-Vested Restricted Stock Awards | Low end of range
Fair value
Recognition period		1 month 6 days
Time-Vested Restricted Stock Awards | High end of range
Fair value
Recognition period	2 years 1 month 6 days	2 years 1 month 6 days
Performance-Based Restricted Stock Awards
Assumptions used for estimating fair value of grants outstanding
Vesting period	3 years
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)	47,200	33,900	37,400
Granted (in shares)	27,000	26,300	10,000
Awarded (in shares)		-4,460	-7,823
Not Awarded (in shares)	-10,900	-8,540	-5,677
Nonvested, balance at the end of the period (in shares)	63,300	47,200	33,900
Weighted Average Grant Date Price
Nonvested, balance at the beginning of the period (in dollars per share)	$21.39	$20.25	$19.28
Granted (in dollars per share)	$22.40	$21.36	$20.97
Awarded (in dollars per share)		$18.36	$18.12
Not Awarded (in dollars per share)	$21.84	$18.36	$18.12
Nonvested, balance at the end of the period (in dollars per share)	$21.74	$21.39	$20.25
Assumptions for valuation of shares
Risk-free interest rate, low end of range (as a percent)	0.25%	0.13%	0.16%
Risk-free interest rate, high end of range (as a percent)	0.67%	0.38%	0.25%
Expected dividend yield (as a percent)	3.50%	4.50%	4.90%
Expected forfeiture rates (as a percent)	3.00%	3.00%	3.00%
Plan cycle	3 years	3 years	3 years
Weighted average fair value per share (in dollars per share)	$43.80	$18.47	$10.94
Expected volatility (as a percent)	14.50%	20.20%	20.60%
Fair value
Unrecognized compensation expense	$1,100,000	$500,000
Threshold performance level set at percentile level of peer group (as a percent)	20.00%	20.00%	20.00%
Target performance level set at percentile level of peer group (as a percent)	50.00%	50.00%	50.00%
Maximum performance level set at percentile level of peer group (as a percent)	80.00%	80.00%	80.00%
Percentage of shares granted on reaching target performance level	100.00%
Percentage of shares granted on reaching threshold performance level	50.00%
Percentage of shares granted on reaching maximum performance level	200.00%
Performance-Based Restricted Stock Awards | Low end of range
Assumptions for valuation of shares
Expected volatility of peer group stock (as a percent)	12.40%	12.30%	12.40%
Fair value percentage	140.00%	0.00%	18.00%
Performance-Based Restricted Stock Awards | High end of range
Assumptions for valuation of shares
Expected volatility of peer group stock (as a percent)	24.80%	27.50%	29.20%
Fair value percentage	157.00%	108.00%	96.00%
Stock Options
Assumptions used for estimating fair value of grants outstanding
Vesting period	3 years
Stock options, expiration term	10 years
Assumptions for valuation of shares
Risk-free interest rate, low end of range (as a percent)		0.10%	0.11%
Risk-free interest rate, high end of range (as a percent)		0.38%	0.44%
Expected dividend yield (as a percent)		4.50%	4.90%
Expected volatility (as a percent)		24.00%	24.00%
Expected life in months			78 months
Market value (in dollars per share)		$22.69	$20.38
Weighted average fair value per option (in dollars per share)		$1.57	$1.34
Fair value
Recognition period			1 month
Stock Options | Low end of range
Assumptions for valuation of shares
Expected life in months		6 months 15 days
Stock Options | High end of range
Assumptions for valuation of shares
Expected life in months		24 months 15 days

EQUITY_COMPENSATION_Details_2

EQUITY COMPENSATION (Details 2) (Stock Options, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock options
Outstanding, balance at the beginning of the period (in shares)	112,500	163,300	190,300
Exercised (in shares)	112,500	-50,800	-27,000
Outstanding, balance at the end of the period (in shares)		112,500	163,300
Exercisable (in shares)		112,500	128,500
Weighted Average Exercise Price
Outstanding, balance at the beginning of the period (in dollars per option)	$23.27	$22.13	$21.56
Exercised (in dollars per share)	$24.58	$21.78	$18.12
Outstanding, balance at the end of the period (in dollars per option)		$23.27	$22.13
Exercisable (in dollars per share)		$23.27	$23.15
Intrinsic value of unexercised options if closing price of stock is less than the exercise price (in dollars per share)	$0
Aggregate intrinsic value
Aggregate intrinsic value of unexercised options			$0.10
Weighted-average remaining contractual life of outstanding options		2 years 1 month 6 days	3 years 2 months 12 days
Range of exercise prices, low end of range (in dollars per share)		$21.92	$18.36
Range of exercise prices, high end of range (in dollars per share)		$23.81	$23.81
Recognition period			1 month
High end of range
Aggregate intrinsic value
Aggregate intrinsic value of unexercised options		0.1
Total unrecognized compensation expense related to non-vested options and related dividend equivalents granted under the plan			$0.10

EQUITY_COMPENSATION_Details_3

EQUITY COMPENSATION (Details 3) (Stock Unit Plan for directors)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Unit Plan for directors
Assumptions used for estimating fair value of grants outstanding
Number of shares authorized under the plan	900,000
Number of shares accrued in director's accounts	164,085	154,402
Shares available for issuance	714,978	236,056
Units accrued for service and dividends (in shares)	30,765	34,252	30,426
Units redeemed for common stock (in shares)	21,083	22,908	21,324

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010
Current income taxes:
Federal	($2,350,000)	$6,726,000	$1,552,000
State	-123,000	2,495,000	708,000
TOTAL	-2,473,000	9,221,000	2,260,000
Deferred income taxes:
Federal	36,620,000	24,954,000	28,210,000
State	5,216,000	3,554,000	4,018,000
TOTAL	41,836,000	28,508,000	32,228,000
Investment tax credit amortization	-143,000	-237,000	-329,000
TOTAL INCOME TAX EXPENSE	39,220,000	37,492,000	34,159,000
Deferred tax assets and liabilities as reflected on consolidated balance sheet
Current deferred tax assets, net	19,200,000	7,222,000
Non-current deferred tax liabilities, net	377,452,000	324,266,000
NET DEFERRED TAX LIABILITIES	358,252,000	317,044,000
Deferred tax assets:
Plant related basis differences	25,349,000	23,344,000
Net operating loss	22,000,000
Disallowed plant costs	1,754,000	1,841,000
Gains on hedging transactions	1,260,000	1,324,000
Regulated liabilities related to income taxes	13,350,000	13,576,000
Pensions and other post-retirement benefits	1,175,000	544,000
Carry forward of income tax credit	6,367,000	6,374,000
Other	1,633,000	1,633,000
Total deferred tax assets	72,888,000	48,636,000
Deferred tax liabilities:
Depreciation, amortization and other plant related differences	363,337,000	297,175,000
Regulated assets related to income	37,180,000	37,806,000
Loss on reacquired debt	3,828,000	4,085,000
Amortization of intangibles	9,168,000	8,089,000
Deferred construction accounting costs	6,082,000	6,977,000
Other	11,545,000	11,548,000
Total deferred tax liabilities	431,140,000	365,680,000
NET DEFERRED TAX LIABILITIES	358,252,000	317,044,000
Effective Income Tax Rates
Federal statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (as a percent)	3.10%	3.10%	3.10%
Investment tax credit amortization (as a percent)	-0.10%	-0.20%	-0.40%
Effect of ratemaking on property related differences (as a percent)	-1.70%	-1.10%	-0.20%
Other (as a percent)	0.60%	0.30%	0.50%
Consolidated effective federal and state income tax rates (as a percent)	36.90%	37.10%	38.00%
Loss carry back period	2 years
Advanced coal investment tax credit				17,700,000
Maximum tax credit utilized		9,000,000	700,000
Adjustment due to change in accounting method	$33,000,000

COMMONLY_OWNED_FACILITIES_Deta

COMMONLY OWNED FACILITIES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Commonly Owned Facilities
Proportionate ownership interest (as a percent)	12.00%
Distance of Iatan Generating Facility from Kansas city (in miles)	35
Ownership interest in the site (as a percent)	3.00%
EDE
Commonly Owned Facilities
Ownership interest in certain common facilities (as a percent)	12.00%
Iatan
Commonly Owned Facilities
Proportionate ownership interest (as a percent)	12.00%
Amounts included in property, plant and equipment
Cost of ownership in plant in service	$373.30	$367.10
Accumulated Depreciation	99.1	91.1
Expenditures	27.8	31.6
Iatan1 | KCP&L
Commonly Owned Facilities
Ownership interest in the site (as a percent)	70.00%
Iatan1 | KCP&L Greater Missouri Operations Co.
Commonly Owned Facilities
Ownership interest in the site (as a percent)	18.00%
Iatan2 | KCP&L
Commonly Owned Facilities
Ownership interest in the site (as a percent)	54.00%
Iatan2 | KCP&L Greater Missouri Operations Co.
Commonly Owned Facilities
Ownership interest in the site (as a percent)	18.00%
State Line Combined Cycle Unit
Amounts included in property, plant and equipment
Cost of ownership in plant in service	161.5	163.3
Accumulated Depreciation	40	37
Expenditures	47.1	52.6
Power capacity (in megawatts)	500
State Line Combined Cycle Unit | EDE
Commonly Owned Facilities
Percentage share in available capacity	60.00%
Plum point
Amounts included in property, plant and equipment
Cost of ownership in plant in service	108.3	108.2
Accumulated Depreciation	9.4	7.3
Expenditures	$8.10	$11.30
Plum point | EDE
Commonly Owned Facilities
Proportionate ownership interest (as a percent)	7.52%

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	0 Months Ended	12 Months Ended	0 Months Ended	12 Months Ended
	Dec. 15, 2005	Dec. 31, 2014	Dec. 15, 2008	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies
Period of the average cost that is used as a basis for determining the maximum annual payments	20 years
Amount of total power capacity of generating facility (in megawatts)		14
Electric | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Cost related to pre-engineering, site preparation activities and contract cost year to date		$110,900,000
Expected cost of adding carbon injection system		112,000,000
Term of Capital Expenditure Plan		5 years
Electric | Low end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost		165,000,000
Electric | High end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost		175,000,000
Coal and coal transportation contracts
Commitments and Contingencies
January 1, 2015 through December 31, 2015		26,200,000
January 1, 2016 through December 31, 2017		29,500,000
January 1, 2018 through December 31, 2019		22,800,000
Purchased power | Plum Point Energy Station
Commitments and Contingencies
Energy capacity (in megawatts)		670
Amount of energy capacity owned (in megawatts)		50
Term of long-term contract agreement		30 years
Amount of energy capacity under option to purchase (in megawatts)		50
Additional capacity under long-term contract agreement (in megawatts)		50
Amount of long-term contract obligation		289,900,000
Purchased power | Cloud County Windfarm
Commitments and Contingencies
Energy capacity (in megawatts)		105
Term of long-term contract agreement			20 years
Period of the average cost that is used as a basis for determining the maximum annual payments			20 years
Purchased power | Cloud County Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility		0
Purchased power | Cloud County Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility		14,600,000
Purchased power | Elk River Windfarm
Commitments and Contingencies
Energy capacity (in megawatts)		150
Term of long-term contract agreement	20 years
Purchased power | Elk River Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility		0
Purchased power | Elk River Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility		16,900,000
Leases
Commitments and Contingencies
Gross amount of assets recorded under capital leases		5,300,000
Capital leases, 2015		553,000
Capital leases, 2016		549,000
Capital leases, 2017		547,000
Capital leases, 2018		547,000
Capital leases, 2019		546,000
Capital leases, thereafter		3,006,000
Capital leases, total minimum payments		5,748,000
Capital leases, amount representing interest		1,581,000
Capital leases, present value of net minimum lease payments		4,167,000
Operating leases, 2015		730,000
Operating leases, 2016		720,000
Operating leases, 2017		682,000
Operating leases, 2018		645,000
Operating leases, 2019		485,000
Operating leases, total minimum payments		3,262,000
Expenses incurred related to operating leases		800,000		800,000	900,000
Accumulated amount of amortization of capital leases		1,500,000		1,300,000
Leases | Electric
Commitments and Contingencies
Number of unit trains under short-term operating leases		2
Leases | Gas
Commitments and Contingencies
Number of office facilities under short-term operating leases		1
Leases | Plum Point Energy Station
Commitments and Contingencies
Number of railcars under capital leases		108
Firm Physical gas and transportation contracts
Commitments and Contingencies
January 1, 2015 through December 31, 2015		26,600,000
January 1, 2016 through December 31, 2017		42,900,000
January 1, 2018 through December 31, 2019		33,300,000
January 1, 2020 and beyond		$49,600,000

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details 2) (USD $)	1 Months Ended	12 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Apr. 30, 2012	Dec. 31, 2014	Jan. 31, 2013	Nov. 30, 2010
		MW	item
		state
Electric
Environmental Laws And Regulations
Period for compliance	4 years
Phase-in period for proposed standards	3 years
Clean Air Interstate Rule | Electric
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
Cross State Air Pollution Rule
Environmental Laws And Regulations
Period of business plan		5 years
Cross State Air Pollution Rule | Electric
Environmental Laws And Regulations
Number of states in which fossil-fueled power plants are required to reduce emission levels of SO2 and NOx as per CAIR		23
Number of groups required to reduce SO2		2
NAAQS | Electric
Environmental Laws And Regulations
Number of states in which fossil-fueled power plants are required to reduce emission levels of SO2 and NOx as per CAIR		25
Particulate matter primary annual standard (in micrograms per cubic meter of air)			12
Surface Impoundments | Electric
Environmental Laws And Regulations
Number of options in the EPA proposal		2
Surface Impoundments | Electric | High end of range
Environmental Laws And Regulations
Potential cost for construction of new landfill and conversion of existing ash handling from wet to dry system(s)		15
Surface Impoundments | Iatan | Electric
Environmental Laws And Regulations
Percentage of ownership in a coal ash impoundment at a generating facility		12.00%
Surface Impoundments | Plum point | Electric
Environmental Laws And Regulations
Percentage of ownership in a coal ash impoundment at a generating facility		7.52%
Renewable Energy | Electric
Environmental Laws And Regulations
Minimum percentage of Missouri retail sales required to generate or purchase electricity in 2014		5
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%
Green House Gases
Environmental Laws And Regulations
Percentage of carbon emission reduction from 2005 baseline levels by 2030, required by the proposed Clean Power Plan		30.00%
Number of strategies to achieve the best system of emission reduction identified by EPA		4
Number of comments on proposed regulation for Carbon Pollution Standards for new power plants		2,000,000
Power Plant Mercury And Air Toxics Rule | Electric
Environmental Laws And Regulations
Construction costs year to date		88.5

SEGMENT_INFORMATION_Details

SEGMENT INFORMATION (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
									segment
									item
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	$151,363	$171,512	$149,782	$179,673	$149,058	$157,486	$136,646	$151,140	$652,330	$594,330	$557,097
Depreciation and amortization									73,185	69,306	60,447
Federal and state income taxes									39,220	37,492	34,159
Operating income	19,300	31,709	19,502	29,488	23,799	32,896	21,110	21,858	99,999	99,663	96,221
Interest income									51	566	972
Interest expense									41,740	41,479	41,467
Income from AFUDC (debt and equity)									9,917	5,940	1,928
Net income	11,112	23,892	11,194	20,905	15,162	23,996	11,658	12,630	67,103	63,445	55,681
Capital Expenditures									222,853	160,208	146,287
Total assets	2,390,256				2,145,045				2,390,256	2,145,045
Goodwill	39,492				39,492				39,492	39,492
Income from continuing operations									67,103	63,445	55,681
SPP Integrated Market [Member]
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues	7,500	11,500	16,500	6,200
Electric
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues									592,491	536,413	510,653
Depreciation and amortization									67,534	63,659	55,312
Federal and state income taxes									35,737	34,478	32,266
Operating income									90,488	90,984	89,445
Interest income									37	537	946
Interest expense									37,911	37,683	37,866
Income from AFUDC (debt and equity)									9,833	5,910	1,918
Capital Expenditures									212,866	153,401	140,117
Total assets	2,271,539				2,034,234				2,271,539	2,034,234
Income from continuing operations									61,467	58,603	52,631
Electric | SPP Integrated Market [Member]
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues									41,900
Gas
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues									51,842	50,041	39,849
Depreciation and amortization									3,760	3,709	3,598
Federal and state income taxes									1,840	1,484	789
Operating income									6,775	6,194	5,005
Interest income									25	115	323
Interest expense									3,861	3,890	3,905
Income from AFUDC (debt and equity)									84	30	10
Capital Expenditures									7,836	4,419	3,571
Total assets	130,856				123,736				130,856	123,736
Goodwill	39,492				39,492				39,492	39,492
Income from continuing operations									2,965	2,355	1,256
Others
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues									9,302	9,147	7,187
Depreciation and amortization									1,891	1,938	1,537
Federal and state income taxes									1,643	1,530	1,104
Operating income									2,736	2,485	1,771
Interest income									21	8	7
Capital Expenditures									2,151	2,388	2,599
Total assets	34,655				31,306				34,655	31,306
Income from continuing operations									2,671	2,487	1,794
Eliminations
Statement of Income Information, balance sheet information and capital expenditures of business segments
Revenues									-1,305	-1,271	-592
Interest income									-32	-94	-304
Interest expense									-32	-94	-304
Total assets	($46,794)				($44,231)				($46,794)	($44,231)

SELECTED_QUARTERLY_INFORMATION2

SELECTED QUARTERLY INFORMATION (UNAUDITED) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenues	$151,363	$171,512	$149,782	$179,673	$149,058	$157,486	$136,646	$151,140	$652,330	$594,330	$557,097
Operating income	19,300	31,709	19,502	29,488	23,799	32,896	21,110	21,858	99,999	99,663	96,221
Net income	11,112	23,892	11,194	20,905	15,162	23,996	11,658	12,630	67,103	63,445	55,681
Basic and Diluted Earnings Per Share (in dollars per share)	$0.26	$0.55	$0.26	$0.48	$0.35	$0.56	$0.27	$0.30	$1.55	$1.48	$1.32
SPP Integrated Market [Member]
Operating revenues	$7,500	$11,500	$16,500	$6,200

RISK_MANAGEMENT_AND_DERIVATIVE2

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair value of derivative financial instruments
Current assets	$3,901	$2,469
Total derivatives assets	3,901	2,510
Current liabilities	6,469	1,889
Non-current liabilities and deferred credits	3,243	2,799
Total derivatives liabilities	9,712	4,688
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Gas
Fair value of derivative financial instruments
Current assets		35
Current liabilities	476	8
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Electric
Fair value of derivative financial instruments
Current assets	1	467
Non-current assets and deferred charges- other		41
Current liabilities	5,993	1,881
Non-current liabilities and deferred credits	3,243	2,799
Non-designated as hedging instruments due to regulatory accounting | Transmission congestion rights (TCR) | Electric
Fair value of derivative financial instruments
Current assets	$3,900	$1,967

RISK_MANAGEMENT_AND_DERIVATIVE3

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Electric
Gain / (Loss) on derivatives
Unrealized net losses applicable to financial instruments which will settle in next twelve months	$6,000,000
Period within which financial instruments will settle	12 months
Amount of Gain/(Loss) Recognized on Balance Sheet	6,178,000	1,629,000
Amount of Gain / (Loss) Recognized in Income on Derivative	9,447,000	-2,644,000
Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	-511,000	-5,000
Commodity contracts | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	-6,780,000	-338,000
Amount of Gain / (Loss) Recognized in Income on Derivative	-1,659,000	-2,725,000
Commodity contracts | Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	-511,000	-5,000
Transmission congestion rights (TCR) | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	12,958,000	1,967,000
Amount of Gain / (Loss) Recognized in Income on Derivative	$11,106,000	$81,000

RISK_MANAGEMENT_AND_DERIVATIVE4

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2014
	MWh
Transmission congestion rights (TCR) - 2015
Procurement guidelines
Monthly MWH Hedged	3,483
Monthly MWH Hedged, estimated fair value	$3,899,526
Electric | Natural Gas Usage - 2015
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	63.00%
Dth Hedged Physical	1,550,000
Dth Hedged Financial	4,510,000
Average Price (in dollars per dth)	4.351
Electric | 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
Electric | Natural Gas Usage - 2017
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Dth Hedged Physical	782,900
Dth Hedged Financial	1,300,000
Average Price (in dollars per dth)	4.133
Electric | Natural Gas Usage - 2018
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	11.00%
Dth Hedged Physical	456,000
Dth Hedged Financial	500,000
Average Price (in dollars per dth)	4.202
Electric | 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%
Electric | First Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	60.00%
Electric | Second Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	40.00%
Electric | Third Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Electric | Fourth Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Electric | High end of range | Current Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	100.00%

RISK_MANAGEMENT_AND_DERIVATIVE5

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	item
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
Margin deposit assets
Margin deposit assets	9.1	$5.20
Gas
Price Risk Mitigation for Gas Segment
Target percentage of storage capacity utilization	95.00%
Volume of storage in pipelines that serve customers (in Dth)	1,200,000
Number of pipelines that serve customers (in units)	3
Storage capacity utilized (as a percent)	58.00%
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	2
Gas | Current Winter Season
Gas Usage Hedged By Winter Season
End of Year Minimum % Hedged	50.00%
Dth Hedged Financial	430,000,000
Dth in Storage	1,178,367,000
Actual % Hedged	97.00%
Dth Hedged Physical	341,000,000
Gas | High end of range | Second Winter Season
Gas Usage Hedged By Winter Season
End of Year Minimum % Hedged	50.00%
Gas | High end of range | Third Winter Season
Gas Usage Hedged By Winter Season
End of Year Minimum % Hedged	20.00%

FAIR_VALUE_MEASUREMENTS_Detail

FAIR VALUE MEASUREMENTS (Details) (Recurring basis, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Assets/(Liabilities) at Fair Value
Fair Value Measurements at Reporting Date
Derivative assets	$3,901	$2,510
Derivative liabilities	-9,712	-4,688
Quoted Prices in Active Markets for Identical Liabilities (Level 1)
Fair Value Measurements at Reporting Date
Derivative assets	1	543
Derivative liabilities	-9,712	-4,688
Significant Other Observable Inputs (Level 2)
Fair Value Measurements at Reporting Date
Derivative assets	$3,900	$1,967

FAIR_VALUE_MEASUREMENTS_Detail1

FAIR VALUE MEASUREMENTS (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Long-Term Debt
Carrying amount of total long-term debt exclusive of capital leases	$799	$739
Fair market value	$829	$715

REGULATED_OPERATING_EXPENSE_De

REGULATED OPERATING EXPENSE (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Regulated Operating Expenses
Power operation expense (other than fuel)	$16,089	$15,643	$15,045
Electric transmission and distribution expense	27,919	21,863	17,083
Natural gas transmission and distribution expense	2,362	2,498	2,443
Customer accounts and assistance expense	11,239	11,180	10,211
Employee pension expense	10,590	10,736	10,180
Employee healthcare expense	9,147	10,190	9,825
General office supplies and expense	15,024	12,850	10,776
Administrative and general expense	14,385	14,800	15,091
Bad Debt Expense	3,420	3,665	3,038
Regulatory reversal of gain on sale of assets	44	1,236
Miscellaneous expense	472	672	679
Total	$110,691	$105,333	$94,371

SCHEDULE_II_Valuation_and_Qual1

SCHEDULE II - Valuation and Qualifying Accounts (Details) (Reserve deducted from assets: accumulated provision for uncollectible accounts., USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reserve deducted from assets: accumulated provision for uncollectible accounts.
Valuation and Qualifying Accounts
Balance At Beginning Of Period	$1,025,177	$1,387,673	$1,137,644
Charged To Income	3,463,797	2,213,988	3,052,397
Charged to Other Accounts	2,128,325	2,013,959	1,956,549
Deductions From Reserve	5,596,662	4,590,443	4,758,917
Balance At Close of Period	$1,020,637	$1,025,177	$1,387,673