Empire District Electric (EDE) 10-K21 Feb 142013 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2013	Feb. 03, 2014	Jun. 30, 2013
Document and Entity Information	'	'	'
Entity Registrant Name	'EMPIRE DISTRICT ELECTRIC CO	'	'
Entity Central Index Key	'0000032689	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$955,552,315
Entity Common Stock, Shares Outstanding	'	43,093,133	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Plant and property, at original cost:	'	'
Electric and water	$2,219,605	$2,176,188
Natural gas	72,834	69,851
Other	39,902	37,983
Construction work in progress	152,330	56,347
Total plant and property, Gross	2,484,671	2,340,369
Accumulated depreciation and amortization	732,737	682,737
Total plant and property, Net	1,751,934	1,657,632
Current assets:	'	'
Cash and cash equivalents	3,475	3,375
Restricted cash	2,872	4,357
Accounts receivable - trade, net of allowance of $1,025 and $1,388, respectively	50,137	38,874
Accrued unbilled revenues	26,694	23,254
Accounts receivable - other	13,101	13,277
Fuel, materials and supplies	48,811	61,870
Prepaid expenses and other	15,954	21,806
Unrealized gain in fair value of derivative contracts	2,469	96
Regulatory assets	7,743	6,377
Total current assets	171,256	173,286
Noncurrent assets and deferred charges:	'	'
Regulatory assets	169,333	243,958
Goodwill	39,492	39,492
Unamortized debt issuance costs	8,826	7,606
Unrealized gain in fair value of derivative contracts	41	191
Other	4,163	4,204
Total noncurrent assets and deferred charges	221,855	295,451
Total assets	2,145,045	2,126,369
Capitalization and liabilities	'	'
Common stock, $1 par value, 100,000,000 shares authorized, 43,044,185 and 42,484,363 shares issued and outstanding, respectively	43,044	42,484
Capital in excess of par value	639,525	628,199
Retained earnings	67,554	47,115
Total common stockholders' equity	750,123	717,798
Long-term debt (net of current portion)	'	'
Obligations under capital lease	4,167	4,441
First mortgage bonds and secured debt	637,578	487,541
Unsecured debt	101,683	199,644
Total long-term debt	743,428	691,626
Total long-term debt and common stockholders' equity	1,493,551	1,409,424
Current liabilities:	'	'
Accounts payable and accrued liabilities	71,375	66,559
Current maturities of long-term debt	274	714
Short-term debt	4,000	24,000
Regulatory liabilities	5,681	6,303
Customer deposits	12,543	12,001
Interest accrued	6,352	5,902
Unrealized loss in fair value of derivative contracts	1,889	3,403
Taxes accrued	3,386	2,992
Other current liabilities	299	'
Total current liabilities	105,799	121,874
Commitments and contingencies (Note 11)	'	'
Noncurrent liabilities and deferred credits:	'	'
Regulatory liabilities	132,012	131,055
Deferred income taxes	324,266	301,967
Unamortized investment tax credits	18,431	18,897
Pension and other postretirement benefit obligations	51,405	120,808
Unrealized loss in fair value of derivative contracts	2,799	3,819
Other	16,782	18,525
Total noncurrent liabilities and deferred credits	545,695	595,071
Total capitalization and liabilities	$2,145,045	$2,126,369

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Consolidated Balance Sheets	'	'
Accounts receivable - trade, allowance (in dollars)	$1,025	$1,388
Common stock, par value (in dollars per share)	$1	$1
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	43,044,185	42,484,363
Common stock, shares outstanding	43,044,185	42,484,363

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues:	'	'	'
Electric	$536,413	$510,653	$524,275
Gas	50,041	39,849	46,430
Other	7,876	6,595	6,165
Total operating revenues	594,330	557,097	576,870
Operating revenue deductions:	'	'	'
Fuel and purchased power	175,406	178,896	200,256
Cost of natural gas sold and transported	25,795	18,633	22,760
Regulated operating expenses	105,333	94,371	85,442
Other operating expenses	3,142	2,730	2,098
Maintenance and repairs	40,873	40,444	41,041
Loss on plant disallowance	2,409	'	150
Depreciation and amortization	69,306	60,447	63,537
Provision for income taxes	37,465	34,096	34,071
Other taxes	34,938	31,259	30,581
Total operating revenue deductions	494,667	460,876	479,936
Operating income	99,663	96,221	96,934
Other income and (deductions):	'	'	'
Allowance for equity funds used during construction	3,853	1,147	294
Interest income	566	972	555
Provision for other income taxes	-27	-63	-227
Other - non-operating expense, net	-1,218	-1,910	-1,283
Total other income and (deductions)	3,174	146	-661
Interest charges:	'	'	'
Long-term debt	40,354	40,192	42,581
Short-term debt	60	187	86
Allowance for borrowed funds used during construction	-2,087	-781	-218
Other	1,065	1,088	-1,147
Total interest charges	39,392	40,686	41,302
Net income	$63,445	$55,681	$54,971
Weighted average number of common shares outstanding - basic (in shares)	42,781	42,257	41,852
Weighted average number of common shares outstanding - diluted (in shares)	42,803	42,284	41,887
Total earnings per weighted average share of common stock - basic and diluted (in dollars per share)	$1.48	$1.32	$1.31
Dividends declared per share of common stock (in dollars per share)	$1.00	$1	$0.64

Consolidated_Statements_of_Com

Consolidated Statements of Common Stockholders' Equity (USD $)	Total	Common Stock	Capital in excess of Par	Retained earnings
In Thousands, unless otherwise specified	Total	Common Stock	Capital in excess of Par	Retained earnings
Balance at Dec. 31, 2010	$657,624	$41,577	$610,579	$5,468
Increase (Decrease) in Stockholders' Equity	'	'	'	'
Net income	54,971	'	'	54,971
Stock/stock units issued through:	'	'	'	'
Stock purchase and reinvestment plans	8,126	401	7,725	'
Dividends declared	-26,732	'	'	-26,732
Balance at Dec. 31, 2011	693,989	41,978	618,304	33,707
Increase (Decrease) in Stockholders' Equity	'	'	'	'
Net income	55,681	'	'	55,681
Stock/stock units issued through:	'	'	'	'
Stock purchase and reinvestment plans	10,401	506	9,895	'
Dividends declared	-42,273	'	'	-42,273
Balance at Dec. 31, 2012	717,798	42,484	628,199	47,115
Increase (Decrease) in Stockholders' Equity	'	'	'	'
Net income	63,445	'	'	63,445
Stock/stock units issued through:	'	'	'	'
Stock purchase and reinvestment plans	11,886	560	11,326	'
Dividends declared	-43,006	'	'	-43,006
Balance at Dec. 31, 2013	$750,123	$43,044	$639,525	$67,554

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities:	'	'	'
Net income	$63,445	$55,681	$54,971
Adjustments to reconcile net income to cash flows from operating activities:	'	'	'
Depreciation and amortization including regulatory items	71,734	71,160	79,751
Pension and other postretirement benefit costs, net of contributions	-1,888	1,689	-20,379
Deferred income taxes and unamortized investment tax credit, net	28,272	31,899	45,051
Allowance for equity funds used during construction	-3,853	-1,147	-294
Stock compensation expense	2,984	2,285	2,147
Loss on plant disallowance	2,409	'	'
Non-cash loss on derivatives	14	4,174	1,187
Regulatory reversal of gain on sale of assets	1,236	'	'
Other	'	-16	381
Cash flows impacted by changes in:	'	'	'
Accounts receivable and accrued unbilled revenues	-14,312	-688	10,342
Fuel, materials and supplies	10,891	369	-16,682
Prepaid expenses, other current assets and deferred charges	689	-9,238	-23,163
Accounts payable and accrued liabilities	-880	-1,297	-318
Asset retirement obligation	-734	'	'
Interest, taxes accrued and customer deposits	1,386	875	-980
Other liabilities and other deferred credits	-3,942	3,360	3,172
Accumulated provision - rate refunds	'	'	-578
Net cash provided by operating activities	157,451	159,106	134,608
Investing activities:	'	'	'
Capital expenditures - regulated	-152,524	-134,272	-99,162
Capital expenditures and other investments - non-regulated	-2,259	-2,670	-3,375
Restricted cash	1,485	-1	-2,586
Total net cash used in investing activities	-153,298	-136,943	-105,123
Financing activities:	'	'	'
Proceeds from first mortgage bonds, net	150,000	88,000	'
Long-term debt issuance costs	-1,879	-1,074	'
Proceeds from issuance of common stock, net of issuance costs	9,546	8,114	5,884
Repayment of first mortgage bonds	'	-88,029	'
Redemption of senior notes	-98,000	'	'
Net short-term borrowings (repayments)	-20,000	12,000	-12,000
Dividends	-43,006	-42,273	-26,732
Other	-714	-934	-1,754
Net cash used in financing activities	-4,053	-24,196	-34,602
Net increase (decrease) in cash and cash equivalents	100	-2,033	-5,117
Cash and cash equivalents, beginning of year	3,375	5,408	10,525
Cash and cash equivalents, end of year	3,475	3,375	5,408
Supplemental cash flow information:	'	'	'
Interest paid	39,033	38,802	41,088
Income taxes (refunded) paid, net of refund	10,584	-592	-14,300
Supplementary non-cash investing activities:	'	'	'
Change in accrued additions to property, plant and equipment not reported above	5,420	9,345	-1,387
Capital lease obligations for purchase of new equipment	'	'	$29

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2013

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 2013 were derived as follows:

Electric segment sales*

90.3

Gas segment sales

8.4

Other segment sales

1.3

Sales from our electric segment include 0.4% 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 168,800 customers as of December 31, 2013, and the 2013 electric operating revenues were derived as follows:

Customer

% of revenue

Residential

42.6

Commercial

30.4

Industrial

15.1

Wholesale on-system

3.7

Wholesale off-system

2.9

Miscellaneous sources, primarily public authorities

2.8

Other electric revenues

2.5

Our retail electric revenues for 2013 by jurisdiction were as follows:

Jurisdiction

% of revenue

Missouri

89.8

Kansas

4.8

Arkansas

2.5

Oklahoma

2.9

Our gas operations serve approximately 44,000 customers as of December 31, 2013, and the 2013 gas operating revenues were derived as follows:

Customer

% of revenue

Residential

63.1

Commercial

27.3

Industrial

Other

8.6

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, collectibility 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 say 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 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, the Company 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 $11.2 million, $10.4 million and $11.0 million were recorded for each of the years ended December 31, 2013, 2012 and 2011, 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 the Company refunds, 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, 2013 and 2012 was $4.2 million and $5.2 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, 2013 and 2012, we had recorded accrued cost of removal of $81.3 million and $77.3 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, 2013 and 2012 was $7.2 million and $6.1 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, and a liability for containment of the ash landfill at the Riverton Power Plant. 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 is underway (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 the 2012 year, 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 2012 and 2013 are shown below.

(000's)

Liability

Liabilities

Accretion

Cash Flow

Liability

Balance 12/31/12

Recognized

Settled

Revisions

Balance at

12/31/13

Asset Retirement Obligation

4,711

—

(734

)

213

—

4,190

(000's)

Liability

Liabilities

Accretion

Cash Flow

Liability

Balance 12/31/11

Recognized

Settled

Revisions

Balance at

12/31/12

Asset Retirement Obligation

3,944

—

252

515

4,711

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, 2013 and 2012, our regulatory assets relating to asset retirement obligations totaled $4.7 million and $4.4 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 our construction program 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 7.3% for 2013, 5.6% for 2012, and 5.2% for 2011, compounded semiannually.. The specific Iatan 2 AFUDC rate was a result of our Experimental Regulatory Plan approved by the MPSC on August 2, 2005, and it terminated on June 15, 2011. In this agreement, we were allowed to receive the regulatory amortization discussed above, in rates prior to the completion of Iatan 2. As a result, the equity portion of our AFUDC rate for the Iatan 2 project was reduced by 2.5 percentage points (See Note 3 for additional discussion of our regulatory plan).

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, 2013 and 2012.

Goodwill

As of December 31, 2013, 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 forecast anticipate 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 2013 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. This amount is adjusted to reflect regulatory treatment for our Missouri and Kansas fuel adjustment mechanisms discussed below.

In our Missouri jurisdiction, the MPSC established 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 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, 2013 and 2012, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net over-recovered position by $0.6 million and $4.0 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, which are considered inventory, and recorded at zero cost (See Note 11). Revenue from the sale of renewable energy credits 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 1,834 and 5,187 SO2 allowances in inventory at December 31, 2013 and 2012, 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 will purchase from the SPP Integrated Market (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 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.

PROPERTY_PLANT_AND_EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
PROPERTY, PLANT AND EQUIPMENT	Dec. 31, 2013
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,
			2013			2012
	Electric plant
	Production		$	1,035,095		$	1,034,114
	Transmission			263,398			251,769
	Distribution			793,024			766,026
	General⁽¹⁾			115,427			111,963


	Electric plant			2,206,944			2,163,872
	Less accumulated depreciation and amortization			697,128			651,627


	Electric plant net of depreciation and amortization			1,509,816			1,512,245
	Construction work in progress			150,636			55,957


	Net electric plant			1,660,452			1,568,202
	Gas plant			72,834			69,851
	Less accumulated depreciation and amortization			15,204			12,940


	Gas plant net of accumulated depreciation			57,630			56,911
	Construction work in progress			1,156			184


	Net gas plant			58,786			57,095
	Water plant			12,661			12,316
	Less accumulated depreciation and amortization			4,806			4,440


	Water plant net of depreciation and amortization			7,855			7,876
	Construction work in progress			—			1


	Net water plant			7,855			7,877
	Other
	Fiber			39,902			37,983
	Less accumulated depreciation and amortization			15,599			13,730


	Non-regulated net of depreciation and amortization			24,303			24,253
	Construction work in progress			538			205


	Net non-regulated property			24,841			24,458


	TOTAL NET PLANT AND PROPERTY		$	1,751,934		$	1,657,632






	-1
	Includes intangible property of $38.1 and $36.4 million as of December 31, 2013 and 2012, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2013 and 2012 was $13.6 and $10.7 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):


		2013			2012			2011
Provision for depreciation
Regulated — Electric and Water		$	63,192		$	57,467		$	54,628
Regulated — Gas			3,763			3,602			3,485
Non-Regulated			1,938			1,538			1,807


TOTAL			68,893			62,607			59,920
Amortization⁽¹⁾			2,492			1,041			7,445


TOTAL		$	71,385		$	63,648		$	67,365






-1
Includes $6.6 million of regulatory amortization for 2011. This was granted by the MPSC effective January 1, 2007 and updated August 23, 2008, and September 10, 2010. This regulatory amortization terminated as of June 15, 2011 as a result of our 2010 Missouri rate case.


		2013			2012			2011
Annual depreciation rates
Electric and water			3	%		2.8	%		2.7	%
Gas			5.4	%		5.4	%		5.5	%
Non-Regulated			5	%		4.2	%		5.4	%
TOTAL COMPANY			3.1	%		2.9	%		2.9	%

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


		2013			2012			2011
Annual Weighted Average Depreciation Rate
Electric fixed assets:
Production plant			2.4	%		2	%		2.1	%
Transmission plant			2.4	%		2.4	%		2.3	%
Distribution plant			3.6	%		3.6	%		3.6	%
General plant			5.8	%		5.9	%		6.1	%
Water			2.8	%		2.7	%		2.7	%
Gas			5.4	%		5.4	%		5.5	%
Non-regulated			5	%		4.2	%		5.4	%

REGULATORY_MATTERS

REGULATORY MATTERS	12 Months Ended
REGULATORY MATTERS	Dec. 31, 2013
REGULATORY MATTERS	'
REGULATORY MATTERS	'

	3. REGULATORY MATTERS

	Regulatory Assets and Liabilities and Other Deferred Credits

	Changes

	Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives from December 31, 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 and the capitalization of banking and line of credit fees. There were no changes to regulatory assets and liabilities with regards to their rate base inclusion or amortizable lives from December 31, 2011 to December 31, 2012.

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


			December 31,
			2013			2012
	Regulatory Assets:
	Current:
	Under recovered fuel costs		$	1,411		$	2,885


	Current portion of long-term regulatory assets			6,332			3,492


	Regulatory assets, current			7,743			6,377
	Long-term:
	Pension and other postretirement benefits⁽¹⁾			70,035			136,480
	Income taxes			48,033			48,759
	Deferred construction accounting costs⁽²⁾			16,275			16,717
	Unamortized loss on reacquired debt			11,078			12,142
	Unsettled derivative losses — electric segment			4,269			6,557
	System reliability — vegetation management			7,539			9,002
	Storm costs⁽³⁾			4,911			4,828
	Asset retirement obligation			4,673			4,430
	Customer programs			4,935			4,356
	Unamortized loss on interest rate derivative			989			1,147
	Deferred operating and maintenance expense			2,095			2,049
	Under recovered fuel costs			—			314
	Current portion of long-term regulatory assets			(6,332	)		(3,492	)
	Other			833			669


	Regulatory assets, long-term			169,333			243,958


	Total Regulatory Assets		$	177,076		$	250,335




	Regulatory Liabilities
	Current:
	Over recovered fuel costs		$	2,212		$	3,214
	Current portion of long-term regulatory liabilities			3,469			3,089


	Regulatory liabilities, current			5,681			6,303


	Long-term:
	Costs of removal			88,469			83,368
	SWPA payment for Ozark Beach lost generation			19,405			22,242
	Income taxes			11,677			11,972
	Deferred construction accounting costs — fuel⁽⁴⁾			8,011			8,156
	Unamortized gain on interest rate derivative			3,371			3,541
Pension and other postretirement benefits			2,177			2,007
Over recovered fuel costs			2,371			2,858
Current portion of long-term regulatory liabilities			(3,469	)		(3,089	)


Regulatory liabilities, long-term			132,012			131,055


Total Regulatory Liabilities		$	137,693		$	137,358






-1
Primarily consists of unfunded pension and OPEB liability. See Note 8.

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

-3
Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $3.7 million at December 31, 2013.

-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, 2013, the costs of all of our regulatory assets are currently being recovered except for approximately $61.2 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 1 to 28 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 for us to earn a reasonable return on "rate base." "Rate base" is generally determined by reference to the original cost (net of accumulated depreciation and amortization) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, amortization and retirement of utility plant or write-off's as ordered by the utility commissions. In general, a request of new rates is made on the basis of a "rate base" as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag (commonly referred to as "regulatory lag") between the time we incur costs and the time when we can start recovering the costs through rates.

The following table sets forth information regarding electric and water rate increases since January 1, 2011:


Jurisdiction		Date		Annual			Percent			Date
		Requested		Increase			Increase			Effective
				Granted			Granted
Missouri — Electric		July 6, 2012		$	27,500,000			6.78	%		April 1, 2013
Missouri — Water		May 21, 2012		$	450,000			25.5	%		November 23, 2012
Missouri — Electric		September 28, 2010		$	18,700,000			4.7	%		June 15, 2011
Kansas — Electric		June 17, 2011		$	1,250,000			5.2	%		January 1, 2012
Oklahoma — Electric		June 30, 2011		$	240,722			1.66	%		January 4, 2012
Oklahoma — Electric		January 28, 2011		$	1,063,100			9.32	%		March 1, 2011
Arkansas — Electric		August 19, 2010		$	2,104,321			19	%		April 13, 2011

Electric Segment

Missouri

2012 Rate Case

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 $3.7 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. This request was primarily designed to recover operation and maintenance expenses and capital costs associated with the May 22, 2011 tornado, Southwest Power Pool transmission charges allocated to us, operating systems replacement costs for new software systems, vegetation management costs, new depreciation rates and amortization of a regulatory asset related to the tax benefits of cost of removal, the balance of which was approximately $9.6 million at December 31, 2012.

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.

2010 Rate Case

On September 28, 2010, we filed a rate increase request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $36.5 million, or 9.2% to recover the Iatan 2 costs and other cost of service items not included in our 2009 Missouri rate case, effective September 10, 2010. A settlement agreement among the parties to the case was reached and filed with the MPSC on May 27, 2011 reflecting an overall annual increase in rates of $18.7 million, or approximately 4.7% effective on June 15, 2011. Due to rate design changes, this rate increase, however, primarily impacted our winter season rates which generally run from October through May. Also as part of the settlement, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011. The MPSC approved the settlement agreement on June 1, 2011 and the new rates were effective on June 15, 2011. The approved settlement included authorization of a tracker mechanism for the SWPA payment associated with the capacity restrictions to be implemented for our Ozark Beach hydro facility. We agreed to flow the SWPA payment, net of tax, back to our customers over a ten year period using a tracker mechanism resulting in an annual decrease to expenses of approximately $1.4 million. The settlement agreement also allowed for a tracker mechanism related to Plum Point, Iatan 2 and Iatan common plant operating expenses. We record a regulatory asset or liability for the difference between actual expenses (excluding fuel and fuel related expenses) and the amount of expense included in base rates.

Kansas

2011 Rate Case

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. A joint settlement agreement was filed on November 10, 2011 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.

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 December 3, 2013, we filed a request with the Arkansas Public Service Commission for changes in rates for our Arkansas electric customers. We are 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

On May 18, 2012, we filed a request with the FERC to implement a TFR to be effective August 1, 2012. On July 31, 2012, the FERC suspended the TFR for five months and set the filing for hearing and settlement procedures. On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement 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. Final FERC action on our compliance filing is pending.

On March 12, 2010, we filed new annual GFR tariffs with the FERC which we propose to be utilized for our wholesale customers. On May 28, 2010, the FERC issued an order that conditionally approved our GFR filing subject to refund effective June 1, 2010. On September 15, 2010, the parties agreed to a settlement in principle and on May 24, 2011, we, the Missouri Public Utility Alliance and the cities of Monett, Mt. Vernon and Lockwood, Missouri filed a Settlement Agreement and Offer of Settlement with the FERC. We refunded approximately $1.3 million, including interest, in November 2011 as a result of this settlement. A GFR update will be completed annually for rates effective June 1.

MARKETS AND TRANSMISSION

Electric Segment

Energy Imbalance Services: The Southwest Power Pool (SPP) regional transmission organization (RTO) energy imbalance services market (EIS) provides real time energy for most participating members within the SPP regional footprint. Imbalance energy prices are based on market bids and status of dispatchable generation and transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO performs a real time security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native load.

Day-Ahead Market: We continue to prepare for a March 1, 2014 implementation of the SPP Integrated Marketplace (or Day-Ahead Market), which will replace the existing EIS market described above. Prior to implementation of the Integrated Marketplace, the SPP RTO will create a single NERC-approved balancing authority to take over balancing authority responsibilities for its members, including Empire. This action is expected to provide operational and economic benefits for our customers.

As part of the Integrated Marketplace, SPP members will be able to offer their committed resources into the SPP market for a centralized dispatch. Members will submit offers to sell and bids to purchase power. SPP will match offers and bids based upon a security constrained analysis. It is expected that 90%-95% of all generation needed (for the next day) throughout the SPP territory will be cleared through this Integrated Marketplace. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we will purchase from the SPP Integrated Market (see Note 14). The net financial effect of these Integrated Marketplace transactions will be processed through 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 scheduled for January 2015. 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 Board of Directors (BOD) approved transmission projects, a number which are currently in progress. We are concerned with the SPP's policy to allocate to us the costs of transmission projects from which we would receive either no benefits or benefits that are not roughly commensurate with the allocated costs. We estimate net transmission costs will increase between $2 and $3 million in 2014 as a result of SPP's allocation methodology over what we currently recover in customer rates. 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.

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	%
100kV to 299kV			33.3	%		66.7	%
Below 100 kV			0	%		100	%

At the October 2013 SPP regional state committee meeting, SPP's regional cost allocation review and imbalance analysis indicated that our projected benefits (along with five other members) compared to the allocation of transmission costs over the next several years would be below the roughly commensurate benefit to cost threshold that initiates an equity remedy review by SPP staff. SPP will evaluate potential construction equity improvement remedies during the upcoming 2014 Integrated Transmission Planning (ITP) process with any recommendations expected in January 2015

SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement: On December 19, 2013, Entergy 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 significantly increase transmission delivery costs for our Plum Point power station as well as utilize our transmission system without compensation.

Prior to Entergy's integration into MISO, the SPP filed a Petition for Review of FERC's Orders on the interpretation of the SPP/MISO Joint Operating Agreement at the United States Court of Appeals for the District of Columbia (DC). In early December 2013, the DC Court vacated and remanded FERC's Orders that agreed with MISO regarding interpretation of the Joint Operating Agreement to utilize SPP's system to integrate Entergy into MISO. SPP believes MISO's intentional and free use of ours and the other SPP transmission owners systems is unjust and unreasonable. We and other SPP members have intervened in SPP's Petition and are actively involved in SPP stakeholder processes and other FERC dockets to address our concerns. FERC's actions regarding the remand and review of the FERC orders are pending.

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 $1.2 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.

COMMON_STOCK

COMMON STOCK	12 Months Ended
COMMON STOCK	Dec. 31, 2013
COMMON STOCK	'
COMMON STOCK	'

	4. COMMON STOCK

	Stock Based 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):


			2013			2012			2011
	Compensation expense		$	2,577		$	1,863		$	1,765
	Tax benefit recognized			929			649			614

	Stock Incentive Plans

	Our 2006 Stock Incentive Plan (the 2006 Incentive Plan) was adopted by shareholders at the annual meeting on April 28, 2005 and provides for grants of up to 650,000 shares of common stock through January 2016. The 2006 Stock Incentive Plan permits 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 2011, 2012 and 2013 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
			2013		2012
	Total unrecognized compensation cost (in millions)		$0.20		less than $0.1
	Recognition period		0.1 years to 2.1 years		1.6 years
	Fair value		$19.88		$18.38

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


			2013						2012						2011
			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,			3,300		$	20.38			3,433		$	21.84			—			—
	Granted			21,600		$	21.36			—			—			10,200		$	21.84
	Vested			—			—			—			—			794		$	19.32
	Distributed			—			—			(133	)	$	20.13			(661	)	$	21.02
	Forfeited			—			—			—			—			(6,106	)		—
	Vested but not distributed			—			—			—			—			133		$	20.13
	Outstanding at December 31,			24,900		$	22.69			3,300		$	20.38			3,433		$	21.84

	All time-vested restricted stock awards are classified as liability instruments, which must be revalued each period until settled. The cost of the awards is generally recognized over the requisite (explicit) service period.

	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 2011, 2012 and 2013 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. As noted previously, all performance-based restricted stock awards are classified as liability instruments, which must be revalued each period until settled. The fair value of the outstanding restricted stock awards was estimated as of December 31, 2013, 2012 and 2011 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,
			2013		2012		2011
	Risk-free interest rate		0.13% to 0.38%		0.16% to 0.25%		0.12% to 0.23%
	Expected volatility of Empire stock		20.20%		20.60%		23.80%
	Expected volatility of peer group stock		12.3% to 27.5%		12.4% to 29.2%		15.7% to 57.4%
	Expected dividend yield on Empire stock		4.50%		4.90%		4.70%
	Expected forfeiture rates		3%		3%		3%
	Plan cycle		3 years		3 years		3 years
Fair value percentage		0.0% to 108.0%		18.0% to 96.0%		51.0% to 75.0%
Weighted average fair value per share		$18.47		$10.94		$13.67

Non-vested performance-based restricted stock awards (based on target number) as of December 31, 2013, 2012 and 2011 and changes during the year ended December 31, 2013, 2012 and 2011 were as follows:


		2013						2012						2011
		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,			33,900		$	20.25			37,400		$	19.28			47,500		$	19.86
Granted			26,300		$	21.36			10,000		$	20.97			10,900		$	21.84
Awarded			(4,460	)	$	18.36			(7,823	)	$	18.12			(39,621	)	$	21.92
Awarded in excess of target									—		$	—			18,621		$	21.92
Not awarded			(8,540	)	$	18.36			(5,677	)	$	18.12			—		$	—


Nonvested at December 31,			47,200		$	21.39			33,900		$	20.25			37,400		$	19.28

At December 31, 2013 and 2012, unrecognized compensation expense related to estimated outstanding awards was $0.5 million and $0.1 million, respectively.

Stock Options

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, expire 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 2013, 2012, or 2011. Beginning in 2011, we began issuing time-vested restricted stock in lieu of stock options and dividend equivalents.

As noted previously, all outstanding stock option awards are classified as liability instruments, which must be revalued each period until settled. Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of December 31, 2013, 2012 and 2011, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:


		Fair Value of Grants Outstanding at December 31,
		2013		2012		2011
Risk-free interest rate		0.10% to 0.38%		0.11% to 0.44%		0.12% to 0.72%
Dividend yield		4.50%		4.90%		4.70%
Expected volatility		24.00%		24.00%		25.00%
Expected life in months		6.5 to 24.5		78		78
Market value		$22.69		$20.38		$21.09
Weighted average fair value per option		$1.57		$1.34		$2.08

A summary of option activity under the plan during the years ended December 31, 2013, 2012 and 2011 is presented below:


		2013						2012						2011
		Options			Weighted			Options			Weighted			Options			Weighted
					Average						Average						Average
					Exercise						Exercise						Exercise
					Price						Price						Price
Outstanding at January 1,			163,300		$	22.13			190,300		$	21.56			267,400		$	21.69
Granted					$	—			0		$	—			0		$	—
Exercised			(50,800	)	$	21.78			(27,000	)	$	18.12			(77,100	)	$	22.02


Outstanding at December 31,			112,500		$	23.27			163,300		$	22.13			190,300		$	21.56




Exercisable, end of year			112,500		$	23.27			128,500		$	23.15			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, 2013, 2012, and 2011:


		2013		2012		2011
Aggregate intrinsic value (in millions)		Less than $0.1		$0.10		$0.20
Weighted-average remaining contractual life of outstanding options		2.1 years		3.2 years		5.1 years
Range of exercise prices		$21.92 to $23.81		$18.36 to $23.81		$18.12 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		$0.10
Recognition period		—		1 month		1 year

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, 2013, there were 127,774 shares available for issuance in this plan.


		2013			2012			2011
Subscriptions outstanding at December 31,			60,413			70,850			70,756
Maximum subscription price		$	19.58	-1	$	17.95		$	17.27
Shares of stock issued			68,099			65,919			69,229
Stock issuance price		$	17.95		$	17.27		$	16.06


-1
Stock will be issued on the closing date of the purchase period, which runs from June 1, 2013 to May 31, 2014.

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


		2013			2012			2011
Weighted average fair value of grants		$	2.78		$	3.19		$	3.17
Risk-free interest rate			0.14	%		0.17	%		0.18	%
Dividend yield			4.6	%		5	%		2.6	%
Expected volatility⁽¹⁾			14	%		24	%		22	%
Expected life in months			12			12			12
Grant date			6/1/13			6/1/12			6/1/11


-1
One-year historic volatility

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, 2013, a total of 400,000 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:


		2013			2012
Shares accrued to directors' accounts			154,402			143,058
Shares available for issuance			236,056			258,960

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


		2013			2012			2011
Units accrued for service and dividends			34,252			30,426			25,287
Units redeemed for common stock			22,908			21,324			31,243

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. We match 50% of each employee's 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, 2013 and 2012, there were 256,448 and 320,576 shares available to be issued, respectively.


		2013			2012			2011
Shares contributed			64,128			65,502			68,523

Effective January 1, 2014, new employees, and on January 1, 2015, employees who have elected to convert from our average salary pension formula to a cash balance formula, will be eligible for an enhanced matching contribution. Under the enhancement, we will match 100% of the first 6% a participant defers in the 401(k) Plan. The first 3% of the match will be in shares of our common stock with the remaining portion of the match being in cash (see Note 8).

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, 2013, 2012 and 2011:


(in millions, except per share amounts)		2013			2012			2011
Diluted earnings per share		$	1.48		$	1.32		$	1.31
Dividends paid per share⁽¹⁾		$	1.005		$	1		$	0.64
Total dividends paid		$	43		$	42.3		$	26.7
Retained earnings year-end balance		$	67.6		$	47.1		$	33.7


-1
In response to the expected loss of revenues resulting from the May 22, 2011 tornado, our level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. On February 2, 2012, the Board of Directors re-established the dividend and declared a quarterly dividend of $0.25 per share on common stock payable on March 15, 2012 to holders of record as of March 1, 2012.

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. On June 9, 2011, we amended the EDE Mortgage in order to provide us with additional flexibility to pay dividends to our shareholders by permitting the payment of any dividend or distribution on, or purchase of, shares of its common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1.

PREFERRED_AND_PREFERENCE_STOCK

PREFERRED AND PREFERENCE STOCK	12 Months Ended
PREFERRED AND PREFERENCE STOCK	Dec. 31, 2013
PREFERRED AND PREFERENCE STOCK	'
PREFERRED AND PREFERENCE STOCK	'

	5. 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, 2013 or 2012.

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
LONG-TERM DEBT	Dec. 31, 2013
LONG-TERM DEBT	'
LONG-TERM DEBT	'

	6. LONG-TERM DEBT

	At December 31, 2013 and 2012, the balance of long-term debt outstanding was as follows (in thousands):


			2013			2012
	First mortgage bonds (EDE):
	7.20% Series due 2016		$	25,000		$	25,000
	5.875% Series due 2037⁽¹⁾			80,000			80,000
	6.375% Series due 2018⁽¹⁾			90,000			90,000
	4.65% Series due 2020⁽¹⁾			100,000			100,000
	5.20% Series due 2040⁽¹⁾			50,000			50,000
	3.58% Series due 2027⁽¹⁾			88,000			88,000
	3.73% Series due 2033⁽¹⁾			30,000			—
	4.32% Series due 2043⁽¹⁾			120,000			—
	First mortgage bonds (EDG):
	6.82% Series due 2036⁽¹⁾			55,000			55,000


				638,000			488,000
	Senior Notes, 4.50% Series due 2013⁽¹⁾			—			98,000
	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			4,441			5,155
	Less unamortized net discount			(739	)		(815	)


				743,702			692,340
	Less current obligations of long-term debt			—			(415	)
	Less current obligations under capital lease			(274	)		(299	)


	TOTAL LONG-TERM DEBT		$	743,428		$	691,626






	-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 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. 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, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The bonds were issued under the EDE Mortgage.

	On April 2, 2012, we entered into a Bond Purchase Agreement for a private placement of $88 million aggregate principal amount of 3.58% First Mortgage Bonds due April 2, 2027. The first settlement of $38 million occurred on April 2, 2012 and the second settlement of $50 million occurred on June 1, 2012. All bonds of this new series will mature on April 2, 2027. Interest is payable semi-annually on the bonds on each April 2 and October 2, commencing October 2, 2012. The bonds may be redeemed, at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The bonds have not been registered under the Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. We used the proceeds from the sale of these bonds to redeem the called bonds discussed above (including repaying short term debt initially used for such purpose). They were issued under the EDE Mortgage.

	On April 1, 2012, we redeemed all $74.8 million aggregate principal amount of our First Mortgage Bonds, 7.00% Series due 2024. All $5.2 million of our First Mortgage Bonds, 5.20% Pollution Control Series due 2013, and all $8.0 million of our First Mortgage Bonds, 5.30% Pollution Control Series due 2013 were also redeemed with payment made to the trustee prior to March 31, 2012.

	Shelf Registration

	On December 13, 2013, we filed a $200.0 million shelf registration statement on Form S-3 with the SEC covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. This shelf registration statement will be effective for a three-year period beginning with the date of filing. We plan to use the proceeds under this shelf to fund capital expenditures, refinance existing debt or general corporate needs during the effective period. The issuance of securities under this shelf is subject to the receipt of local regulatory approvals. We have filed applications for such approvals in all four state jurisdictions in our electric service territory.

	EDE Mortgage Indenture

	The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the year ended December 31, 2013 would permit us to issue approximately $599.1 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, 2013, we had retired bonds and net property additions which would enable the issuance of at least $856.7 million principal amount of bonds if the annual interest requirements are met. However, based on the $1 billion limit on the principal amount of first mortgage bonds outstanding set forth by the EDE mortgage, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $417 million of new first mortgage bonds. As of December 31, 2013, we are in compliance with all restrictive covenants of the EDE Mortgage.

	EDG Mortgage Indenture

	The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1. As of December 31, 2013, this test would allow us to issue approximately $15.8 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
2014		$	274		$	—		$	274
2015			292			—			292
2016			25,308			25,000			308
2017			325			—			325
2018			90,347			90,000			347
Thereafter			627,895			625,000			2,895


Total long-term debt obligations			744,441		$	740,000		$	4,441




Less current obligations and unamortized discount			1,013


TOTAL LONG-TERM DEBT		$	743,428

SHORTTERM_BORROWINGS

SHORT-TERM BORROWINGS	12 Months Ended
SHORT-TERM BORROWINGS	Dec. 31, 2013
SHORT-TERM BORROWINGS	'
SHORT-TERM BORROWINGS	'

	7. SHORT-TERM BORROWINGS

	At December 31, 2013, total short-term borrowings consisted of $4.0 million in commercial paper and no borrowings from our line of credit. During 2013 and 2012 our short-term borrowings outstanding averaged (in millions)


		2013			2012
	Average borrowings outstanding	$	8.7		$	17.8
	Highest month end balance	$	29		$	55.7

	The weighted average interest rates and the weighted average interest rate of borrowings outstanding at December 31, 2013 and 2012 were:.


		2013			2012
	Weighted average interest rate		0.69	%		1.05	%
	Weighted average interest rate of borrowings outstanding		0.33	%		0.91	%

	On January 17, 2012, we entered into the Third Amended and Restated Unsecured Credit Agreement which amended and restated our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010. This agreement extended the termination date of the revolving credit facility from January 26, 2013 to January 17, 2017. The agreement also removed the letter of credit facility and included a swingline loan facility with a $15 million swingline loan sublimit. The aggregate amount of the revolving credit commitments remains $150 million, inclusive of the $15 million swingline loan sublimit. In addition, the pricing and fees under the facility were amended. Interest on borrowings under the facility accrues at a rate equal to, at our option, (i) the highest of (A) the bank's prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility is 1.25%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings (the fee is currently 0.20%). In addition, upon entering into the amended and restated facility, we paid an upfront fee to the revolving credit banks of $262,500 in the aggregate. There were no other material changes to the terms of the facility.

	The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2013, we are in compliance with these ratios. Our total indebtedness was 49.8% of our total capitalization as of December 31, 2013 and our EBITDA for 2013 was 5.3 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at December 31, 2013. However, $4.0 million was used to back up our outstanding commercial paper.

RETIREMENT_BENEFITS

RETIREMENT BENEFITS	12 Months Ended
RETIREMENT BENEFITS	Dec. 31, 2013
RETIREMENT BENEFITS	'
RETIREMENT BENEFITS	'

	8. RETIREMENT 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 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 and healthcare cost trend rate 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 shown 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, 2013, consistent with previous years. See Note 1.

	Pensions

	Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. The benefits are based on years of service and the employee's average annual basic earnings. During 2013 changes were made to the benefits calculation for all employees hired after January 1, 2014. The benefit for employees hired after this date will accrue based on a cash balance methodology, with an enhanced 401(k) contribution. Additionally, employees hired prior to January 1, 2014 will be given the option to convert to the cash balance formula, or remain with the average annual basic earnings formula which will now allow for a lump sum distribution, with a decision to be made by December 31, 2014. Additionally, during 2013, for a limited period of time, we permitted former participants with a vested benefit in the plan, to take a lump sum distribution of their benefit. Our actuary has considered these changes in the calculations below.

	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 decreased $49.2 million in 2013. The decrease was recorded as a decrease in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. Our contribution is estimated to be approximately $12 million for 2014. 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 2015, the performance of our pension assets during 2014.

	Expected benefit payments are as follows (in millions):


	Year		Payments from Trust			Payments from
	Year		Payments from Trust			Company Funds
	2014		$	19.6		$	0.4
	2015			20.5			0.4
	2016			19.8			0.4
	2017			20.7			0.5
	2018			19.8			0.4
	2019 – 2023			92.4			2.5

	Other Postretirement Benefits (OPEB)

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

	Our net liability decreased $20.8 million in 2013. The decrease was recorded as a reduction in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. 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 $3.0 million in 2014.

	Estimated benefit payments are as follows (in millions):


	Year		Payments from Trust			Expected Federal			Payments from
	Year		Payments from Trust			Subsidy			Company Funds
	2014		$	2.5		$	0.3		$	0.1
	2015			2.9			0.3			0.2
	2016			3.2			0.4			0.2
	2017			3.5			0.4			0.2
	2018			3.8			0.5			0.2
	2019 – 2023			23.2			3.2			0.9

	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
			2013			2012			2013			2012			2013			2012
	Benefit obligation at beginning of year		$	248,004		$	215,088		$	6,365		$	4,863		$	94,738		$	83,226
	Service cost			7,454			6,261			135			51			2,941			2,401
	Interest cost			10,063			10,258			315			263			3,827			4,037
	Net actuarial (gain)/loss			(23,300	)		25,882			604			1,511			(12,767	)		6,955
	Plan participant's contribution			—			—			—			—			949			910
	Benefits and expenses paid			(17,090	)		(9,485	)		(311	)		(323	)		(4,396	)		(3,156	)
	Federal subsidy			—			—			—			—			40			365


	Benefit obligation at end of year		$	225,131		$	248,004		$	7,108		$	6,365		$	85,332		$	94,738





Reconciliation of Fair Value of Plan Assets:


		Pension						SERP						OPEB
		2013			2012			2013			2012			2013			2012
Fair value of plan assets at beginning of year		$	160,175		$	140,975		$	—		$	—		$	67,667		$	58,384
Actual return on plan assets — gain/(loss)			27,260			17,562			—			—			10,361			7,148
Employer contribution			16,202			11,123			—			—			4,360			3,970
Benefits paid			(17,090	)		(9,485	)		—			—			(4,229	)		(3,045	)
Plan participant's contribution			—			—			—			—			901			864
Federal subsidy			—			—			—			—			38			346


Fair value of plan assets at end of year		$	186,547		$	160,175		$	—		$	—		$	79,098		$	67,667





Reconciliation of Funded Status:


		Pension						SERP						OPEB
		2013			2012			2013			2012			2013			2012
Fair value of plan assets		$	186,547		$	160,175		$	—		$	—		$	79,098		$	67,667
Projected benefit obligations			(225,131	)		(248,004	)		(7,108	)		(6,365	)		(85,332	)		(94,738	)


Funded status		$	(38,584	)	$	(87,829	)	$	(7,108	)	$	(6,365	)	$	(6,234	)	$	(27,071	)





The employee pension plan accumulated benefit obligation at December 31, 2013 and 2012 is presented in the following table (in thousands):


		Pension Benefits						SERP
		2013			2012			2013			2012
Accumulated benefit obligation		$	201,258		$	219,659		$	5,702		$	6,014



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


		Pension						SERP						OPEB
		2013			2012			2013			2012			2013			2012
Accounts Payable and Accrued Liabilities		$	—		$	—		$	372		$	313		$	147		$	144
Pension and other postretirement benefit obligation		$	38,584		$	87,829		$	6,736		$	6,052		$	6,087		$	26,927

Net periodic benefit pension cost for 2013, 2012 and 2011, 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
		2013			2012			2011			2013			2012			2011
Service cost		$	7,454		$	6,261		$	5,596		$	2,941		$	2,401		$	2,266
Interest cost			10,063			10,258			10,405			3,827			4,037			4,383
Expected return on plan assets			(12,428	)		(12,309	)		(11,139	)		(4,353	)		(4,135	)		(4,157	)
Amortization of prior service cost⁽¹⁾			532			531			532			(1,011	)		(1,011	)		(1,011	)
Amortization of actuarial loss⁽¹⁾			10,445			7,935			5,494			2,261			1,661			1,762


Net periodic benefit cost		$	16,066		$	12,676		$	10,888		$	3,665		$	2,953		$	3,243





Net Periodic Pension Benefit Cost:


		SERP
		2013			2012			2011
Service cost		$	135		$	51		$	93
Interest cost			315			263			183
Expected return on plan assets			—			—			—
Amortization of prior service cost⁽¹⁾			(8	)		(8	)		(8	)
Amortization of actuarial loss⁽¹⁾			567			389			171


Net periodic benefit cost		$	1,009		$	695		$	439






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

The tables below present the activity in the regulatory asset accounts for the year (in thousands).


					Amount Recognized
Regulatory		Beginning			Current Year			Amortization			Amortization			Ending
Assets		Balance			Actuarial			of Actuarial			of Prior			Balance
		12/31/12			(Gain)/Loss			Loss			Service			12/31/13
											(Cost)/Credit
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





					Amount Recognized
Regulatory		Beginning			Current Year			Amortization			Amortization			Ending
Assets		Balance 12/31/11			Actuarial			of Actuarial			of Prior			Balance
					Loss			Loss			Service			12/31/12
											(Cost)/Credit
Pension		$	93,656			20,628			(7,935	)		(531	)	$	105,818
SERP		$	3,012			1,512			(389	)		8		$	4,143
OPEB		$	17,020			3,941			(1,661	)		1,011		$	20,311

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, 2013, and the subsequent twelve-month period (in thousands):


		Pension Benefits						SERP						OPEB
		2013			Subsequent			2013			Subsequent			2013			Subsequent
		2013			Period			2013			Period			2013			Period
Net actuarial loss		$	55,261		$	6,595		$	4,210		$	421		$	3,879		$	914
Prior service cost (benefit)			1,448			418			(22	)		(8	)		(3,594	)		(1,011	)


Total		$	56,709		$	7,013		$	4,188		$	413		$	285		$	(97	)





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						OPEB
		2013			2012			2013			2012
Discount rate			4.9	%		4	%		5	%		4.11	%
Rate of compensation increase			3.5	%		3.5	%		3.5	%		3.5	%

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


		Pension Benefits									OPEB
		2013			2012			2011			2013			2012			2011
Discount rate			4	%		4.7	%		5.5	%		4.11	%		4.9	%		5.5	%
Expected return on plan assets			7.75	%		7.9	%		8	%		6.52	%		6.65	%		7	%
Rate of compensation increase			3.5	%		3.5	%		4.5	%		3.5	%		3.5	%		4.5	%

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 2013 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 7.5%. 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		$	1,450		$	(1,115	)
Effect on post-retirement benefit obligation		$	14,027		$	(11,179	)

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

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.

During 2013 we approved a change in investment strategy for the pension plan. The strategy, referred to as a de-risking glide path, seeks 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. The current target allocations for plan assets are approximately 70% return seeking assets, and approximately 30% long duration bonds.

The following fair value hierarchy table presents information about the pension fund assets measured at fair value as of December 31, 2013 and December 31, 2012 (in thousands):


		Fair Value Measurements as of December 31, 2013
		Quoted			Significant			Significant			Total			Percentage
		Prices in			Other			Unobservable						of Plan
		Active			Observable			Inputs						Assets
		Markets			Inputs			(Level 3)
		for			(Level 2)
		Identical
		Assets
		(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	%









		Fair Value Measurements as of December 31, 2012
		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		$	—		$	2,398		$	—		$	2,398			1.5	%
Equity securities
U.S. equity			63,655			—			—			63,655			39.7	%
International equity			22,074			—			—			22,074			13.8	%
Fixed income
Common collective trust			—			26,110			—			26,110			16.3	%
U.S. corporate debt			—			15,518			—			15,518			9.7	%
U.S. government debt			1,535			—			—			1,535			1	%
Other types of investments
Equity long/short hedge funds			—			—			28,885			28,885			18	%


		$	87,264		$	44,026		$	28,885		$	160,175			100	%





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


		2013			2012
		Equity long/short			Equity long/short
		hedge funds			hedge funds
Beginning Balance, January 1,		$	28,885		$	27,419
Actual return on plan assets:
Relating to assets still held at the reporting date			(356	)		1,466
Relating to assets sold during the period			4,583			—
Purchases			26,500			—
Sales			(22,883	)		—
Settlements			—			—
Transfers into and (out of) Level 3			—			—


Ending Balance, December 31,		$	36,729		$	28,885





Permissible Investments

Listed below are the investment vehicles specifically permitted:

Permissible Investments


Equity Oriented				Fixed Income Oriented and Real Estate
•		Common Stocks		•		Bonds
•		Preferred Stocks		•		GICs, BICs
•		Convertible Preferred Stocks		•		Corporate Bonds (minimum quality rating
•		Convertible Bonds				of Baa or BBB)
•		Covered Options		•		Cash-Equivalent Securities (e.g., U.S.
•		Hedged Equity Funds of Funds				T-Bills, Commercial Paper, etc.)
				•		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		•		Index Options
•		Derivatives

OPEB

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 allocations for plan assets are 0% – 10% cash and cash equivalents, 40% – 60% fixed income securities and 40% – 60% in equity. The following fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2013 and December 31, 2012 (in thousands):


		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	%









		Fair Value Measurements as of December 31, 2012
		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		$	895		$	—		$	—		$	895			1.3	%
Fixed income
U.S. government debt			729			—			—			729			1.1	%
U.S. corporate debt			—			19,437			—			19,437			28.7	%
Foreign debt			—			2,250			—			2,250			3.3	%
Mutual funds — fixed income			3,914			—			—			3,914			5.8	%
Equity securities
U.S. equity			20,795			—			—			20,795			30.7	%
International equity			1,548			—			—			1,548			2.3	%
Mutual funds — equity			17,818			—			—			17,818			26.3	%


		$	45,699		$	21,687		$	—			67,386


Accrued interest & dividends												281			0.5	%


											$	67,667			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
•		Preferred Stocks				of one-year or less
				•		Bonds
				•		Money Market Funds / Bank STIF Funds
				•		Certificates of Deposit in institutions with FDIC protection
				•		Corporate Bonds (minimum quality rating of A)

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
•		Commodities Futures		•		Short Sales
•		Securities of Empire District		•		Index Options
•		Derivatives		•		Real Estate and Real Property
•		Instrumentalities in violation of the Prohibited Transactions Standards of ERISA		•		Restricted Stock

INCOME_TAXES

INCOME TAXES	12 Months Ended
INCOME TAXES	Dec. 31, 2013
INCOME TAXES	'
INCOME TAXES	'

	9. INCOME TAXES

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


			2013			2012			2011
	Current income taxes:
	Federal		$	6,726		$	1,552		$	(8,604	)
	State			2,495			708			(2,120	)


	TOTAL			9,221			2,260			(10,724	)
	Deferred income taxes:
	Federal			24,954			28,210			39,096
	State			3,554			4,018			6,297


	TOTAL			28,508			32,228			45,393
	Investment tax credit amortization			(237	)		(329	)		(371	)


	TOTAL INCOME TAX EXPENSE		$	37,492		$	34,159		$	34,298





	Deferred Income Taxes

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


			December 31,
	Deferred Income Taxes		2013			2012
	Current deferred tax assets, net⁽¹⁾		$	7,222		$	13,000
	Non-current deferred tax liabilities, net			324,266			301,967


	NET DEFERRED TAX LIABILITIES		$	317,044		$	288,967






	-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		2013			2012
	Deferred tax assets:
	Net operating loss		$	—		$	13,000
	Disallowed plant costs			1,841			1,010
	Gains on hedging transactions			1,324			1,389
	Plant related basis differences			23,344			21,571
	Regulated liabilities related to income taxes			13,576			13,871
	Pensions and other post-retirement benefits			544			693
	Carry forward of income tax credit			6,374			3,722
	Other			1,633			2,262


Total deferred tax assets		$	48,636		$	57,518


Deferred tax liabilities:
Depreciation, amortization and other plant related differences		$	297,175		$	279,604
Regulated assets related to income			37,806			39,553
Loss on reacquired debt			4,085			4,489
Amortization of intangibles			8,089			7,009
Deferred construction accounting costs			6,977			7,323
Other			11,548			8,507


Total deferred tax liabilities			365,680			346,485


NET DEFERRED TAX LIABILITIES		$	317,044		$	288,967





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		2013			2012			2011
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			(0.2	)		(0.4	)		(0.4	)
Effect of ratemaking on property related differences			(1.1	)		(0.2	)		0.2
Other			0.3			0.5			0.5


EFFECTIVE INCOME TAX RATE			37.1	%		38	%		38.4	%









Unrecognized Tax Benefits		2013			2012			2011
Unrecognized tax benefits — January 1,		$	—		$	—		$	359,000
The gross amounts of increases in unrecognized tax benefits taken during prior periods			—			—			—
The gross amounts of decreases in unrecognized tax benefits taken during the period relating to positions accepted by taxing authorities			—			—			—
Reductions to unrecognized tax benefits as a result of a lapse of the applicable statute of limitations			—			—			(359,000	)


UNRECOGNIZED TAX BENEFITS — December 31,		$	—		$	—		$	—





We do not expect any significant changes to our unrecognized tax benefits over the next twelve months. The reserve balance related to unrecognized tax benefits as of December 31, 2010 was $359,000. With the expiration of the statute of limitations on these unrecognized tax benefits on September 15, 2011, there are no unrecognized tax benefits at December 31, 2013, 2012 and 2011.

We received $17.7 million, of investment tax credits based on our investment in Iatan 2. We utilized $0.7 million of these credits when preparing our 2012 tax return. We expect to utilize approximately $10.7 million of these credits on our 2013 tax return. We expect to use the remaining credits on our 2014 tax return. The tax credit will have no significant income statement impact as the credits will flow to our customers as we amortize the tax credits over the life of the plant.

The American Taxpayer Relief Act of 2012 (the "Act") was signed into law on January 2, 2013. The Act restored several expired business tax provisions, including bonus depreciation for 2013. The Company's 2014 tax payments are expected to be higher than 2013 due to the expiration of bonus depreciation. However, the Company expects to utilize investment tax credits noted above to partially offset the 2014 payments.

On September 13, 2013, the IRS and the Treasury Department released final regulations under Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014, and the Company plans to utilize the book capitalization method as allowable under the final regulations. The Company expects an immaterial impact to the effective tax rate.

COMMONLY_OWNED_FACILITIES

COMMONLY OWNED FACILITIES	12 Months Ended
COMMONLY OWNED FACILITIES	Dec. 31, 2013
COMMONLY OWNED FACILITIES	'
COMMONLY OWNED FACILITIES	'

	10. COMMONLY OWNED FACILITIES

	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. At December 31, 2013 and 2012, our property, plant and equipment accounts included the amounts in the following chart (in millions):


	Iatan	2013		2012
	Cost of ownership in plant in service	$	367.1	$	364.1
	Accumulated Depreciation	$	91.1	$	83.2
	Expenditures⁽¹⁾	$	31.6	$	30


	-1
	Operating, maintenance, and fuel expenditures excluding depreciation expense.

	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.

	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, 2013 and 2012, our property, plant and equipment accounts included the amounts in the following chart (in millions):


	State Line Combined Cycle Unit	2013		2012
	Cost of ownership in plant in service	$	163.3	$	164.4
	Accumulated Depreciation	$	37	$	36.7
	Expenditures⁽¹⁾	$	52.6	$	42.7


	-1
	Operating, maintenance, and fuel expenditures excluding depreciation expense.

	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, 2013 and 2012, our property, plant and equipment accounts included the amounts in the following chart (in millions):


	Plum Point Energy Station	2013		2012
	Cost of ownership in plant in service	$	108.2	$	108
	Accumulated Depreciation	$	7.3	$	4.9
	Expenditures⁽¹⁾	$	11.3	$	7.8


	-1
	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, 2013
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. Management regularly analyzes this information, and has provided accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company's defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.


	(in millions)		Firm physical gas		Coal and coal
			and transportation		transportation
			contracts		contracts
	January 1, 2014 through December 31, 2014		$	24.9	$	23.8
	January 1, 2015 through December 31, 2016		$	31.4	$	28.8
	January 1, 2017 through December 31, 2018		$	30.2	$	22.6
	January 1, 2019 and beyond		$	45.9	$	11.3

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

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

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

	Purchased Power

	We currently supplement our on-system generating capacity with purchases of capacity and energy from other entities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.

	The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit's capacity. We also have a long-term (30 year) agreement for the purchase of capacity from Plum Point. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. At this time it is not our intention to exercise this option. Rather, we intend to continue to meet our demand and capacity requirements with the continuation of this long-term purchased power agreement. Commitments under this agreement are approximately $297.2 million through August 31, 2039, the end date of the agreement.

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

	On July 9, 2013, we signed a contract with a third party vendor to complete engineering, procurement, and construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion will include the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. The Air Emission Source Construction Permit necessary for this project was issued by Kansas Department of Health and Environment on July 11, 2013.

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

	See "Environmental Matters" below for more information and for project costs for 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 $5.5 million at December 31, 2013.

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


			Capital		Operating
			Leases		Leases
	2014		$	553	$	764
	2015			553		722
	2016			549		720
	2017			547		681
	2018			546		646
	Thereafter			3,553		485


	Total minimum payments			6,301	$	4,018
	Less amount representing interest			1,860


Present value of net minimum lease payments		$	4,441





Expenses incurred related to operating leases were $0.8 million, $0.9 million and $1.0 million for 2013, 2012, and 2011, respectively, excluding payments for wind generated purchased power agreements. The accumulated amount of amortization for our capital leases was $1.3 million and $1.0 million at December 31, 2013 and 2012, 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, Empire is taking actions to implement its compliance plan and strategy (Compliance Plan). The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR) and its subsequent replacement rule, both regulations which we discuss further below, are the drivers behind our Compliance Plan and its implementation schedule. The MATS, which was published for power plants by the Environmental Protection Agency (EPA) in 2011, requires reductions in mercury, acid gases and other emissions considered hazardous air pollutants (HAPS). It became effective in April 2012 and requires full compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The Cross State Air Pollution Rule (CSAPR — formerly the Clean Air Transport Rule, or CATR) was first proposed by the EPA in July 2010 as a replacement of CAIR and was set to take effect on January 1, 2012. CSAPR was stayed in late December 2011, then vacated by court order in August 2012. Consequently, CAIR will remain in effect until a valid replacement is developed by the EPA. We anticipate compliance costs associated with the MATS and CAIR (or its subsequent replacement) regulations to be recoverable in our rates.

Our Compliance Plan largely follows the preferred plan presented in our Integrated Resource Plan (IRP), filed in mid-2013 with the MPSC. As described above under New Construction, we are in the process of installing a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant. The addition of this air quality control equipment is expected to be completed by early 2015 at a cost ranging from $112.0 million to $130.0 million, excluding AFUDC. Construction costs through December 31, 2013 were $83.6 million for the project to date, excluding AFUDC. 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 operating completely on natural gas. Riverton Units 7 and 8, along with Riverton Unit 9, a small combustion turbine that requires steam from Unit 7 or 8 for start-up, will be retired upon the conversion of Riverton Unit 12, a simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in mid-2016 at a cost estimated to range from $165 million to $175 million, excluding AFUDC. This amount is included in our five-year capital expenditure plan. Construction costs, consisting of pre-engineering and site preparation activities thus far, through December 31, 2013 were $13 million for 2013 and $13.6 million for the project to date, excluding AFUDC.

Air Emissions

The CAA regulates the amount of NOx and SO2 an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx and SO2 limits. Currently, NOx emissions are regulated by the CAIR and National Ambient Air Quality Standard (NAAQS) rules for ozone (discussed below). SO2 emissions are currently regulated by the Title IV Acid Rain Program and the CAIR. The EPA is expected to propose a CSAPR replacement, which if finalized and upheld, would also replace CAIR. In the meantime, both the Title IV Acid Rain Program and CAIR will remain in effect.

CAIR:

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

SO2 allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO2 Program. Based on current SO2 allowance usage projections, we expect to have sufficient allowances to take us through 2018. Pursuant to the CAIR regulations, we had excess NOx allowances during 2013 which were banked for future use and will be sufficient for compliance through at least the middle of 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.

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 is expected to be proposed by the EPA in early 2014.

Greenhouse Gases (GHGs):

Under regulations known as the Tailoring Rule, the EPA regulates carbon dioxide and other GHG emissions from certain stationary sources. EDE and EDG's GHG emissions for 2011, 2012, and 2013 have been reported to the EPA as required by the Tailoring Rule.

In addition to the Tailoring Rule, there are a number of federal and state regulatory initiatives aimed at the regulation of GHGs. However, because of the uncertainties regarding future GHG regulation (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.

In response to President Obama's June 2013 memorandum to the EPA regarding carbon pollution standards for the power industry, the EPA is undertaking a process to identify approaches to establish GHG standards for currently operating power plants. The memorandum requested that the EPA issue proposed GHG standards, for modified, reconstructed, and existing power plants by June 1, 2014; issue final standards, regulations, or guidelines, for modified, reconstructed, and existing power plants by June 1, 2015; and include in the guidelines addressing existing power plants a requirement that states submit implementation plans to the EPA by June 30, 2016. In October 2013, the U.S. Supreme Court agreed to review an appeals court decision that said the EPA could regulate GHG emissions from fixed sources based on a previous decision on GHG emissions from cars.

In addition, certain states in which we have EGUs have taken steps to develop cap and trade programs and/or other regulatory systems to measure and report Carbon Dioxide Equivalent (CO2e) emissions that may or may not be more stringent than any federal requirements. However, at this time such states are not proposing regulatory systems pending federal legislative developments.

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 was obligated to finalize the rule by January 14, 2014, a deadline the EPA missed but which may again be extended. We will not know the full impact of these rules until they are finalized. If adopted in their present form, we expect the regulations to have a limited impact at Riverton. The retirement of units 7 and 8 is scheduled in 2016. A new intake structure design and cooling tower will be constructed as part of the Unit 12 conversion at Riverton. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally impacted by the final rule.

Surface Impoundments

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. Additionally, we own a 12% interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. On April 19, 2013, the EPA signed a notice of proposed rulemaking to revise its wastewater effluent limitation guidelines and standards under the CWA for coal-fired power plants. The proposal calls for updates to operating permits beginning in July 2017. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs that might result from any new standards. All of our coal ash impoundments are compliant with existing state and federal regulations.

In June 2010, the EPA proposed to regulate coal combustion residuals (CCRs) under the Federal Resource Conservation and Recovery Act (RCRA). In the proposal, the EPA presented two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. It is anticipated that the final regulation will be published in 2014. We expect compliance with either option to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury Power Plant. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

As a result of the transition from coal to natural gas fuel for Riverton Units 7 and 8, closure of the Riverton ash impoundment is in progress in compliance with Kansas regulations. We expect to complete the closure in early 2014. We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. Construction of the new landfill is expected in 2016.

Renewable Energy

Missouri regulations currently require Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas. The regulations also require that 2% of the energy from renewable energy sources must be solar; however, we are exempted by statute from that solar requirement. On January 30, 2013, a complaint was filed with the MPSC by Renew Missouri and others regarding several aspects of our 2011 Renewable Energy Standard (RES) Compliance Report and our 2012 – 2014 RES Compliance Plan. That complaint also again raised a challenge to our statutory exemption from the solar requirement. In two separate orders, in late 2013, the MPSC granted our motions to dismiss all counts of the complaint against Empire. On January 3, 2014, the Commission issued an order denying the complainants' application for rehearing on all issues related to their challenge of the solar exemption statute.

Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables in 2012, increasing to 15% by 2016, and 20% by 2020. 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. In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

SEGMENT_INFORMATION

SEGMENT INFORMATION	12 Months Ended
SEGMENT INFORMATION	Dec. 31, 2013
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,
			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





			2011
			Electric			Gas			Other			Eliminations			Total
	Statement of Income Information:
	Revenues		$	524,276		$	46,430		$	6,756		$	(592	)	$	576,870
	Depreciation and amortization			58,236			3,494			1,807			—			63,537
	Federal and state income taxes			31,643			1,676			979			—			34,298
	Operating income			88,590			6,514			1,830			—			96,934
	Interest income			554			259			—			(258	)		555
	Interest expense			37,860			3,910			8			(258	)		41,520
	Income from AFUDC (debt and equity)			509			3			—			—			512
	Income from continuing operations		$	50,670		$	2,709		$	1,592		$	—		$	54,971
	Capital Expenditures		$	93,499		$	4,122		$	3,556		$	—		$	101,177





			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





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


-1
Includes goodwill of $39,492 at December 31, 2013 and 2012.

SELECTED_QUARTERLY_INFORMATION

SELECTED QUARTERLY INFORMATION (UNAUDITED)	12 Months Ended
SELECTED QUARTERLY INFORMATION (UNAUDITED)	Dec. 31, 2013
SELECTED QUARTERLY INFORMATION (UNAUDITED)	'
SELECTED QUARTERLY INFORMATION (UNAUDITED)	'

	13. SELECTED QUARTERLY INFORMATION (UNAUDITED)

	The following is a summary of quarterly results for 2013 and 2012 (dollars in thousands except per share amounts):


		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	$	0.3	$	0.27	$	0.56	$	0.35





		Quarters
	Quarterly Results for 2012	First		Second		Third		Fourth
	Operating revenues	$	137,144	$	131,632	$	159,202	$	129,119
	Operating income	$	20,810	$	20,762	$	35,282	$	19,367
	Net Income	$	9,804	$	10,708	$	25,542	$	9,627
	Basic and Diluted Earnings Per Share	$	0.23	$	0.25	$	0.6	$	0.23

	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
RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS	Dec. 31, 2013
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 volatile natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain predictability. Beginning in 2013, we also acquire Transmission Congestion Rights (TCR) in an attempt to lessen the cost of power we will purchase from the SPP Integrated Market due to congestion costs. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the TCR 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 with the unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

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

	As of December 31, 2013 and 2012, 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				2013			2012
			Balance Sheet Classification		Fair			Fair
			Balance Sheet Classification		Value			Value
	Natural gas contracts, gas segment		Current assets		$	35		$	3
			Non-current assets and deferred charges — Other			—			17
	Natural gas contracts, electric segment		Current assets			467			93
			Non-current assets and deferred charges — Other			41			174
	Transmission congestion rights, electric segment		Current assets			1,967			—


	Total derivatives assets				$	2,510		$	287





	LIABILITY DERIVATIVES


	Non-designated as hedging instruments due to regulatory accounting				2013			2012
			Balance Sheet Classification		Fair			Fair
			Balance Sheet Classification		Value			Value
	Natural gas contracts, gas segment		Current liabilities		$	8		$	104
			Non-current liabilities and deferred credits			—			—
	Natural gas contracts, electric segment		Current liabilities			1,881			3,299
			Non-current liabilities and deferred credits			2,799			3,819
	Transmission congestion rights, electric segment		Current liabilities			—			—


	Total derivatives liabilities				$	4,688		$	7,222





	Electric

	At December 31, 2013, approximately $1.9 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, 2013 and 2012, 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		2013		2012
	of Gain/(Loss) on Derivative							2013		2012
Commodity contracts — electric segment		Regulatory (assets)/liabilities		$	(338	)	$	(2,448	)
Transmission congestion rights — electric segment		Regulatory (assets)/liabilities			1,967			—


Total — Electric Segment				$	1,629		$	(2,448	)





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


				Amount of
				Gain/(Loss)
				Recognized in
				Income
				on Derivative
		Statement of Operations Classification of Loss on Derivative		2013			2012
Commodity contracts		Fuel and purchased power expense		$	(2,725	)	$	(3,985	)
Transmission congestion rights — electric segment		Fuel and purchased power expense			81			—


Total — Electric Segment				$	(2,644	)	$	(3,985	)





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, 2013, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for 2014 and the next four years are hedged at the following average prices per Dekatherm (Dth):


Year		% Hedged			Dth Hedged			Dth Hedged		Average Price
Year		% Hedged			Physical			Financial		Average Price
2014			61	%		1,560,000			4,640,000	$	4.411
2015			41	%		—			4,010,000	$	4.578
2016			22	%		—			2,100,000	$	4.415
2017			10	%		—			1,050,000	$	4.43
2018			0	%		—			—	$	—

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


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

At December 31, 2013, the following transmission congestion rights (TCR) have been obtained from TCR auctions to hedge congestion costs in the SPP Integrated Market:


Year		Monthly			$ Value
		MWH
		Hedged
2014			1,918		$	1,966,846

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, 2013 we had 0.9 million Dths in storage on the three pipelines that serve our customers. This represents 47% 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, 2013 (Dth in thousands).


Season		Minimum %			Dth Hedged			Dth Hedged		Dth in		Actual %
Season		Hedged			Financial			Physical		Storage		Hedged
Current			50	%		240,000			—		948,850		59	%
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		2013			2012
		of Loss on Derivative		2013			2012
Commodity contracts		Regulatory assets		$	(5	)	$	(461	)


Total — Gas Segment				$	(5	)	$	(461	)

FAIR_VALUE_MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2013
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. Our Level 3 fair value measurements consist of both quoted price inputs and unobservable quoted inputs.

	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 Market, are valued using the most recent monthly auction clearing prices. Our commodity contracts are valued using the market value approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of 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, 2013
	Derivative assets	$	2,510		$	543		$	1,967		—
	Derivative liabilities	$	(4,688	)	$	(4,688	)	$	—		—
	December 31, 2012
	Derivative assets	$	287		$	287			—		—
	Derivative liabilities	$	(7,222	)	$	(7,222	)		—		—


	*
	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, 2013 and 2012 was $739 million and $688 million, compared to a fair market value of approximately $715 million and $747 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, 2013 or that will be realizable in the future.

REGULATED_OPERATING_EXPENSE

REGULATED OPERATING EXPENSE	12 Months Ended
REGULATED OPERATING EXPENSE	Dec. 31, 2013
REGULATED OPERATING EXPENSE	'
REGULATED OPERATING EXPENSE	'

	16. REGULATED OPERATING EXPENSE

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


		December 31,
		2013		2012		2011
	Power operation expense (other than fuel)	$	15,643	$	15,045	$	12,685
	Electric transmission and distribution expense		21,863		17,083		15,361
	Natural gas transmission and distribution expense		2,498		2,443		2,385
	Customer accounts & assistance expense		11,180		10,211		10,210
	Employee pension expense⁽¹⁾		10,736		10,180		8,805
	Employee healthcare plan⁽¹⁾		10,190		9,825		7,439
	General office supplies and expense		12,850		10,776		10,158
	Administrative and general expense		14,800		15,091		14,295
	Bad debt expense		3,665		3,038		3,425
	Regulatory reversal of gain on sale of assets		1,236		—		—
	Miscellaneous expense		672		679		679


	TOTAL	$	105,333	$	94,371	$	85,442






	-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, 2013

SCHEDULE II - Valuation and Qualifying Accounts

Valuation and Qualifying Accounts

Years ended December 31, 2013, 2012 and 2011:

Additions

Deductions From

Reserve

Charged to Other Accounts

Balance At

Charged

Description

Amount

Description

Amount

Balance At

Beginning

To Income

Close of

Of Period

Period

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

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

Year ended December 31, 2011:

Reserve deducted from assets: accumulated provision for uncollectible accounts.

865,236

3,737,630

Recovery of

1,847,527

Accounts

5,312,749

1,137,644

amounts previously

written off

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2013

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Use of Estimates

Accounting for the Effects of Regulation

Revenue Recognition

Municipal Franchise Taxes

Accounts Receivable

Property, Plant & Equipment

Depreciation

Asset Retirement Obligation.

Asset Retirement Obligation

The balances at the end of 2012 and 2013 are shown below.

(000's)

Liability

Liabilities

Accretion

Cash Flow

Liability

Balance 12/31/12

Recognized

Settled

Revisions

Balance at

12/31/13

Asset Retirement Obligation

4,711

—

(734

)

213

—

4,190

(000's)

Liability

Liabilities

Accretion

Cash Flow

Liability

Balance 12/31/11

Recognized

Settled

Revisions

Balance at

12/31/12

Asset Retirement Obligation

3,944

—

252

515

4,711

Allowance for Funds Used During Construction

Asset Impairments (excluding goodwill)

Goodwill

Fuel and Purchased Power

Electric Segment

Gas Segment

Derivatives

Electric Segment

Gas Segment

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

Pension and Other Postretirement Benefits

Pensions

SUMMARY_OF_SIGNIFICANT_ACCOUNT2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	Dec. 31, 2013
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
Schedule of gross operating revenues by segments	'

	Electric segment sales*		90.3	%
	Gas segment sales		8.4
	Other segment sales		1.3


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

Operating revenues	'
Schedule of asset retirement obligation	'

	(000's)	Liability			Liabilities		Liabilities			Accretion		Cash Flow		Liability
		Balance 12/31/12			Recognized		Settled					Revisions		Balance at
														12/31/13
	Asset Retirement Obligation	$	4,711		$	—	$	(734	)	$	213	$	—	$	4,190





	(000's)	Liability			Liabilities		Liabilities			Accretion		Cash Flow		Liability
		Balance 12/31/11			Recognized		Settled					Revisions		Balance at
														12/31/12
	Asset Retirement Obligation	$	3,944		$	—	$	—		$	252	$	515	$	4,711
Schedule of fuel, materials and supplies	'

	These balances are as follows (in thousands):


		2013			2012
	Electric fuel inventory	$	17,003		$	27,954
	Natural gas inventory		3,584			4,776
	Materials and supplies		28,224			29,140


	TOTAL	$	48,811		$	61,870




Schedule of weighted average number of shares	'

		2013			2012		2011
	Weighted Average Number Of Shares
	Basic		42,781,382			42,256,641		41,851,759
	Dilutive Securities:
	Performance-based restricted stock awards		12,142			14,500		18,222
	Dividend equivalents		—			6,329		9,585
	Employee stock purchase plan		1,729			1,996		3,815
	Stock options		61			3,160		3,240
	Time-based restricted stock awards		7,907			1,820		807


	Total dilutive securities		21,839			27,805		35,669




	Diluted weighted average number of shares		42,803,221			42,284,446		41,887,428




	Antidilutive Shares		107,100			128,500		128,500
Electric	'
Operating revenues	'
Schedule of operating revenues by major customer classes	'

	Customer	% of revenue
	Residential		42.6	%
	Commercial		30.4
	Industrial		15.1
	Wholesale on-system		3.7
	Wholesale off-system		2.9
	Miscellaneous sources, primarily public authorities		2.8
	Other electric revenues		2.5
Schedule of operating revenues, by jurisdiction	'

	Jurisdiction	% of revenue
	Missouri		89.8	%
	Kansas		4.8
	Arkansas		2.5
	Oklahoma		2.9
Gas	'
Operating revenues	'
Schedule of operating revenues by major customer classes	'

	Customer	% of revenue
	Residential		63.1	%
	Commercial		27.3
	Industrial		1
	Other		8.6

PROPERTY_PLANT_AND_EQUIPMENT_T

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
PROPERTY, PLANT AND EQUIPMENT (Tables)	Dec. 31, 2013
PROPERTY, PLANT AND EQUIPMENT	'
Summary of property, plant and equipment	'

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


		December 31,
		2013			2012
	Electric plant
	Production	$	1,035,095		$	1,034,114
	Transmission		263,398			251,769
	Distribution		793,024			766,026
	General⁽¹⁾		115,427			111,963


	Electric plant		2,206,944			2,163,872
	Less accumulated depreciation and amortization		697,128			651,627


	Electric plant net of depreciation and amortization		1,509,816			1,512,245
	Construction work in progress		150,636			55,957


	Net electric plant		1,660,452			1,568,202
	Gas plant		72,834			69,851
	Less accumulated depreciation and amortization		15,204			12,940


	Gas plant net of accumulated depreciation		57,630			56,911
	Construction work in progress		1,156			184


	Net gas plant		58,786			57,095
	Water plant		12,661			12,316
	Less accumulated depreciation and amortization		4,806			4,440


	Water plant net of depreciation and amortization		7,855			7,876
	Construction work in progress		—			1


	Net water plant		7,855			7,877
	Other
	Fiber		39,902			37,983
	Less accumulated depreciation and amortization		15,599			13,730


	Non-regulated net of depreciation and amortization		24,303			24,253
	Construction work in progress		538			205


	Net non-regulated property		24,841			24,458


	TOTAL NET PLANT AND PROPERTY	$	1,751,934		$	1,657,632






	-1
	Includes intangible property of $38.1 and $36.4 million as of December 31, 2013 and 2012, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2013 and 2012 was $13.6 and $10.7 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):


		2013			2012			2011
	Provision for depreciation
	Regulated — Electric and Water	$	63,192		$	57,467		$	54,628
	Regulated — Gas		3,763			3,602			3,485
	Non-Regulated		1,938			1,538			1,807


	TOTAL		68,893			62,607			59,920
	Amortization⁽¹⁾		2,492			1,041			7,445


	TOTAL	$	71,385		$	63,648		$	67,365






	-1
	Includes $6.6 million of regulatory amortization for 2011. This was granted by the MPSC effective January 1, 2007 and updated August 23, 2008, and September 10, 2010. This regulatory amortization terminated as of June 15, 2011 as a result of our 2010 Missouri rate case.


		2013			2012			2011
	Annual depreciation rates
	Electric and water		3	%		2.8	%		2.7	%
	Gas		5.4	%		5.4	%		5.5	%
	Non-Regulated		5	%		4.2	%		5.4	%
	TOTAL COMPANY		3.1	%		2.9	%		2.9	%
Summary of average depreciation rate for each class of assets	'
		2013			2012			2011
	Annual Weighted Average Depreciation Rate
	Electric fixed assets:
	Production plant		2.4	%		2	%		2.1	%
	Transmission plant		2.4	%		2.4	%		2.3	%
	Distribution plant		3.6	%		3.6	%		3.6	%
	General plant		5.8	%		5.9	%		6.1	%
	Water		2.8	%		2.7	%		2.7	%
	Gas		5.4	%		5.4	%		5.5	%
	Non-regulated		5	%		4.2	%		5.4	%

REGULATORY_MATTERS_Tables

REGULATORY MATTERS (Tables)	12 Months Ended
REGULATORY MATTERS (Tables)	Dec. 31, 2013
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,
			2013			2012
	Regulatory Assets:
	Current:
	Under recovered fuel costs		$	1,411		$	2,885


	Current portion of long-term regulatory assets			6,332			3,492


	Regulatory assets, current			7,743			6,377
	Long-term:
	Pension and other postretirement benefits⁽¹⁾			70,035			136,480
	Income taxes			48,033			48,759
	Deferred construction accounting costs⁽²⁾			16,275			16,717
	Unamortized loss on reacquired debt			11,078			12,142
	Unsettled derivative losses — electric segment			4,269			6,557
	System reliability — vegetation management			7,539			9,002
	Storm costs⁽³⁾			4,911			4,828
	Asset retirement obligation			4,673			4,430
	Customer programs			4,935			4,356
	Unamortized loss on interest rate derivative			989			1,147
	Deferred operating and maintenance expense			2,095			2,049
	Under recovered fuel costs			—			314
	Current portion of long-term regulatory assets			(6,332	)		(3,492	)
	Other			833			669


	Regulatory assets, long-term			169,333			243,958


	Total Regulatory Assets		$	177,076		$	250,335




	Regulatory Liabilities
	Current:
	Over recovered fuel costs		$	2,212		$	3,214
	Current portion of long-term regulatory liabilities			3,469			3,089


	Regulatory liabilities, current			5,681			6,303


	Long-term:
	Costs of removal			88,469			83,368
	SWPA payment for Ozark Beach lost generation			19,405			22,242
	Income taxes			11,677			11,972
	Deferred construction accounting costs — fuel⁽⁴⁾			8,011			8,156
	Unamortized gain on interest rate derivative			3,371			3,541
	Pension and other postretirement benefits			2,177			2,007
	Over recovered fuel costs			2,371			2,858
	Current portion of long-term regulatory liabilities			(3,469	)		(3,089	)


	Regulatory liabilities, long-term			132,012			131,055


Total Regulatory Liabilities		$	137,693		$	137,358






-1
Primarily consists of unfunded pension and OPEB liability. See Note 8.

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

-3
Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $3.7 million at December 31, 2013.

-4
Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.

Schedule of electric and water rate increases	'

	Jurisdiction		Date		Annual			Percent			Date
			Requested		Increase			Increase			Effective
					Granted			Granted
	Missouri — Electric		July 6, 2012		$	27,500,000			6.78	%		April 1, 2013
	Missouri — Water		May 21, 2012		$	450,000			25.5	%		November 23, 2012
	Missouri — Electric		September 28, 2010		$	18,700,000			4.7	%		June 15, 2011
	Kansas — Electric		June 17, 2011		$	1,250,000			5.2	%		January 1, 2012
	Oklahoma — Electric		June 30, 2011		$	240,722			1.66	%		January 4, 2012
	Oklahoma — Electric		January 28, 2011		$	1,063,100			9.32	%		March 1, 2011
	Arkansas — Electric		August 19, 2010		$	2,104,321			19	%		April 13, 2011
Schedule of new highway/byway cost allocation methodology	'

	Transmission Project Voltage		Regional Funding Percentage			Zonal Funding Percentage
	300 kV and Above			100	%		0	%
	100kV to 299kV			33.3	%		66.7	%
	Below 100 kV			0	%		100	%

COMMON_STOCK_Tables

COMMON STOCK (Tables)	12 Months Ended
COMMON STOCK (Tables)	Dec. 31, 2013
COMMON STOCK	'
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):


		2013			2012			2011
	Compensation expense	$	2,577		$	1,863		$	1,765
	Tax benefit recognized		929			649			614
Schedule of fair value measurements for each grant year	'
		Fair Value of Grants Outstanding at
		December 31
		2013		2012
	Total unrecognized compensation cost (in millions)	$0.20		less than $0.1
	Recognition period	0.1 years to 2.1 years		1.6 years
	Fair value	$19.88		$18.38
Schedule of shares of time-vested restricted stock granted to qualified individuals at the fair market value	'
		2013						2012					2011
		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,		3,300		$	20.38			3,433		$	21.84		—			—
	Granted		21,600		$	21.36			—			—		10,200		$	21.84
	Vested		—			—			—			—		794		$	19.32
	Distributed		—			—			(133	)	$	20.13		(661	)	$	21.02
	Forfeited		—			—			—			—		(6,106	)		—
	Vested but not distributed		—			—			—			—		133		$	20.13
	Outstanding at December 31,		24,900		$	22.69			3,300		$	20.38		3,433		$	21.84
Schedule of assumptions used in valuation of performance-based restricted stock awards	'
		Fair Value of Grants Outstanding at December 31,
		2013		2012		2011
	Risk-free interest rate	0.13% to 0.38%		0.16% to 0.25%		0.12% to 0.23%
	Expected volatility of Empire stock	20.20%		20.60%		23.80%
	Expected volatility of peer group stock	12.3% to 27.5%		12.4% to 29.2%		15.7% to 57.4%
	Expected dividend yield on Empire stock	4.50%		4.90%		4.70%
	Expected forfeiture rates	3%		3%		3%
	Plan cycle	3 years		3 years		3 years
	Fair value percentage	0.0% to 108.0%		18.0% to 96.0%		51.0% to 75.0%
	Weighted average fair value per share	$18.47		$10.94		$13.67
Schedule of non-vested performance-based restricted stock awards (based on target number) and changes during the reporting period	'

		2013						2012					2011
		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,		33,900		$	20.25			37,400		$	19.28		47,500		$	19.86
	Granted		26,300		$	21.36			10,000		$	20.97		10,900		$	21.84
	Awarded		(4,460	)	$	18.36			(7,823	)	$	18.12		(39,621	)	$	21.92
	Awarded in excess of target								—		$	—		18,621		$	21.92
	Not awarded		(8,540	)	$	18.36			(5,677	)	$	18.12		—		$	—


	Nonvested at December 31,		47,200		$	21.39			33,900		$	20.25		37,400		$	19.28
Schedule of assumptions used in the valuations of stock options	'

		Fair Value of Grants Outstanding at December 31,
		2013		2012		2011
	Risk-free interest rate	0.10% to 0.38%		0.11% to 0.44%		0.12% to 0.72%
	Dividend yield	4.50%		4.90%		4.70%
	Expected volatility	24.00%		24.00%		25.00%
	Expected life in months	6.5 to 24.5		78		78
	Market value	$22.69		$20.38		$21.09
	Weighted average fair value per option	$1.57		$1.34		$2.08
Schedule of stock options activity	'
		2013						2012					2011
		Options			Weighted			Options			Weighted		Options			Weighted
					Average						Average					Average
					Exercise						Exercise					Exercise
					Price						Price					Price
	Outstanding at January 1,		163,300		$	22.13			190,300		$	21.56		267,400		$	21.69
	Granted				$	—			0		$	—		0		$	—
	Exercised		(50,800	)	$	21.78			(27,000	)	$	18.12		(77,100	)	$	22.02


	Outstanding at December 31,		112,500		$	23.27			163,300		$	22.13		190,300		$	21.56




	Exercisable, end of year		112,500		$	23.27			128,500		$	23.15		128,500		$	23.15




Schedule of aggregate intrinsic values of stock options	'

		2013		2012		2011
	Aggregate intrinsic value (in millions)	Less than $0.1		$0.10		$0.20
	Weighted-average remaining contractual life of outstanding options	2.1 years		3.2 years		5.1 years
	Range of exercise prices	$21.92 to $23.81		$18.36 to $23.81		$18.12 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		$0.10
	Recognition period	—		1 month		1 year
Schedule of employee stock purchase plan	'
		2013			2012			2011
	Subscriptions outstanding at December 31,		60,413			70,850			70,756
	Maximum subscription price	$	19.58	-1	$	17.95		$	17.27
	Shares of stock issued		68,099			65,919			69,229
	Stock issuance price	$	17.95		$	17.27		$	16.06


	-1
	Stock will be issued on the closing date of the purchase period, which runs from June 1, 2013 to May 31, 2014.

Schedule of assumptions used in valuation of shares under employee stock purchase plan	'
		2013			2012			2011
	Weighted average fair value of grants	$	2.78		$	3.19		$	3.17
	Risk-free interest rate		0.14	%		0.17	%		0.18	%
	Dividend yield		4.6	%		5	%		2.6	%
	Expected volatility⁽¹⁾		14	%		24	%		22	%
	Expected life in months		12			12			12
	Grant date		6/1/13			6/1/12			6/1/11


	-1
	One-year historic volatility

Schedule of shares accrued to directors' accounts and shares available for issuance under Stock Unit Plan for directors	'
		2013			2012
	Shares accrued to directors' accounts		154,402			143,058
	Shares available for issuance		236,056			258,960
Schedule of units accrued and redeemed under Stock Unit Plan for directors	'
		2013			2012			2011
	Units accrued for service and dividends		34,252			30,426			25,287
	Units redeemed for common stock		22,908			21,324			31,243
Schedule of shares contributed under 401(k) plan and ESOP	'
		2013			2012			2011
	Shares contributed		64,128			65,502			68,523
Schedule of diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance	'

	(in millions, except per share amounts)	2013			2012			2011
	Diluted earnings per share	$	1.48		$	1.32		$	1.31
	Dividends paid per share⁽¹⁾	$	1.005		$	1		$	0.64
	Total dividends paid	$	43		$	42.3		$	26.7
	Retained earnings year-end balance	$	67.6		$	47.1		$	33.7


	-1
	In response to the expected loss of revenues resulting from the May 22, 2011 tornado, our level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. On February 2, 2012, the Board of Directors re-established the dividend and declared a quarterly dividend of $0.25 per share on common stock payable on March 15, 2012 to holders of record as of March 1, 2012.

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
LONG-TERM DEBT (Tables)	Dec. 31, 2013
LONG-TERM DEBT	'
Schedule of long-term debt outstanding	'

	At December 31, 2013 and 2012, the balance of long-term debt outstanding was as follows (in thousands):


		2013			2012
	First mortgage bonds (EDE):
	7.20% Series due 2016	$	25,000		$	25,000
	5.875% Series due 2037⁽¹⁾		80,000			80,000
	6.375% Series due 2018⁽¹⁾		90,000			90,000
	4.65% Series due 2020⁽¹⁾		100,000			100,000
	5.20% Series due 2040⁽¹⁾		50,000			50,000
	3.58% Series due 2027⁽¹⁾		88,000			88,000
	3.73% Series due 2033⁽¹⁾		30,000			—
	4.32% Series due 2043⁽¹⁾		120,000			—
	First mortgage bonds (EDG):
	6.82% Series due 2036⁽¹⁾		55,000			55,000


			638,000			488,000
	Senior Notes, 4.50% Series due 2013⁽¹⁾		—			98,000
	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		4,441			5,155
	Less unamortized net discount		(739	)		(815	)


			743,702			692,340
	Less current obligations of long-term debt		—			(415	)
	Less current obligations under capital lease		(274	)		(299	)


	TOTAL LONG-TERM DEBT	$	743,428		$	691,626






	-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
	2014	$	274		$	—		$	274
	2015		292			—			292
	2016		25,308			25,000			308
	2017		325			—			325
	2018		90,347			90,000			347
	Thereafter		627,895			625,000			2,895


	Total long-term debt obligations		744,441		$	740,000		$	4,441




	Less current obligations and unamortized discount		1,013


	TOTAL LONG-TERM DEBT	$	743,428

SHORTTERM_BORROWINGS_Tables

SHORT-TERM BORROWINGS (Tables)	12 Months Ended
SHORT-TERM BORROWINGS (Tables)	Dec. 31, 2013
SHORT-TERM BORROWINGS	'
Schedule of the entity's average short-term borrowings outstanding	'

	During 2013 and 2012 our short-term borrowings outstanding averaged (in millions)


		2013			2012
	Average borrowings outstanding	$	8.7		$	17.8
	Highest month end balance	$	29		$	55.7
Schedule of weighted average interest rates and the weighted average interest rate of borrowings outstanding	'

	The weighted average interest rates and the weighted average interest rate of borrowings outstanding at December 31, 2013 and 2012 were:.


		2013			2012
	Weighted average interest rate		0.69	%		1.05	%
	Weighted average interest rate of borrowings outstanding		0.33	%		0.91	%

RETIREMENT_BENEFITS_Tables

RETIREMENT BENEFITS (Tables)	12 Months Ended
RETIREMENT BENEFITS (Tables)	Dec. 31, 2013
Retirement benefits	'
Schedule of the Company's benefit plans' projected benefit obligations	'

	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
		2013			2012			2013			2012			2013			2012
	Benefit obligation at beginning of year	$	248,004		$	215,088		$	6,365		$	4,863		$	94,738		$	83,226
	Service cost		7,454			6,261			135			51			2,941			2,401
	Interest cost		10,063			10,258			315			263			3,827			4,037
	Net actuarial (gain)/loss		(23,300	)		25,882			604			1,511			(12,767	)		6,955
	Plan participant's contribution		—			—			—			—			949			910
	Benefits and expenses paid		(17,090	)		(9,485	)		(311	)		(323	)		(4,396	)		(3,156	)
	Federal subsidy		—			—			—			—			40			365


	Benefit obligation at end of year	$	225,131		$	248,004		$	7,108		$	6,365		$	85,332		$	94,738




Schedule of fair value of the plans' assets	'
		Pension						SERP						OPEB
		2013			2012			2013			2012			2013			2012
	Fair value of plan assets at beginning of year	$	160,175		$	140,975		$	—		$	—		$	67,667		$	58,384
	Actual return on plan assets — gain/(loss)		27,260			17,562			—			—			10,361			7,148
	Employer contribution		16,202			11,123			—			—			4,360			3,970
	Benefits paid		(17,090	)		(9,485	)		—			—			(4,229	)		(3,045	)
	Plan participant's contribution		—			—			—			—			901			864
	Federal subsidy		—			—			—			—			38			346


	Fair value of plan assets at end of year	$	186,547		$	160,175		$	—		$	—		$	79,098		$	67,667




Schedule of the funded status	'
		Pension						SERP						OPEB
		2013			2012			2013			2012			2013			2012
	Fair value of plan assets	$	186,547		$	160,175		$	—		$	—		$	79,098		$	67,667
	Projected benefit obligations		(225,131	)		(248,004	)		(7,108	)		(6,365	)		(85,332	)		(94,738	)


	Funded status	$	(38,584	)	$	(87,829	)	$	(7,108	)	$	(6,365	)	$	(6,234	)	$	(27,071	)




Schedule of employee pension plan accumulated benefit obligation	'

	The employee pension plan accumulated benefit obligation at December 31, 2013 and 2012 is presented in the following table (in thousands):


		Pension Benefits						SERP
		2013			2012			2013			2012
	Accumulated benefit obligation	$	201,258		$	219,659		$	5,702		$	6,014


Schedule of amounts recognized in the balance sheet	'

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


		Pension						SERP						OPEB
		2013			2012			2013			2012			2013			2012
	Accounts Payable and Accrued Liabilities	$	—		$	—		$	372		$	313		$	147		$	144
	Pension and other postretirement benefit obligation	$	38,584		$	87,829		$	6,736		$	6,052		$	6,087		$	26,927
Schedule of net periodic benefit pension cost	'

	Net periodic benefit pension cost for 2013, 2012 and 2011, 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
		2013			2012			2011			2013			2012			2011
	Service cost	$	7,454		$	6,261		$	5,596		$	2,941		$	2,401		$	2,266
	Interest cost		10,063			10,258			10,405			3,827			4,037			4,383
	Expected return on plan assets		(12,428	)		(12,309	)		(11,139	)		(4,353	)		(4,135	)		(4,157	)
	Amortization of prior service cost⁽¹⁾		532			531			532			(1,011	)		(1,011	)		(1,011	)
	Amortization of actuarial loss⁽¹⁾		10,445			7,935			5,494			2,261			1,661			1,762


	Net periodic benefit cost	$	16,066		$	12,676		$	10,888		$	3,665		$	2,953		$	3,243





	Net Periodic Pension Benefit Cost:


		SERP
		2013			2012			2011
	Service cost	$	135		$	51		$	93
	Interest cost		315			263			183
	Expected return on plan assets		—			—			—
	Amortization of prior service cost⁽¹⁾		(8	)		(8	)		(8	)
	Amortization of actuarial loss⁽¹⁾		567			389			171


	Net periodic benefit cost	$	1,009		$	695		$	439






	-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 the activity in the regulatory asset accounts for the year (in thousands).


					Amount Recognized
	Regulatory	Beginning			Current Year			Amortization			Amortization			Ending
	Assets	Balance			Actuarial			of Actuarial			of Prior			Balance
		12/31/12			(Gain)/Loss			Loss			Service			12/31/13
											(Cost)/Credit
	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





					Amount Recognized
	Regulatory	Beginning			Current Year			Amortization			Amortization			Ending
	Assets	Balance 12/31/11			Actuarial			of Actuarial			of Prior			Balance
					Loss			Loss			Service			12/31/12
											(Cost)/Credit
	Pension	$	93,656			20,628			(7,935	)		(531	)	$	105,818
	SERP	$	3,012			1,512			(389	)		8		$	4,143
	OPEB	$	17,020			3,941			(1,661	)		1,011		$	20,311
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, 2013, and the subsequent twelve-month period (in thousands):


		Pension Benefits						SERP						OPEB
		2013			Subsequent			2013			Subsequent			2013			Subsequent
		2013			Period			2013			Period			2013			Period
	Net actuarial loss	$	55,261		$	6,595		$	4,210		$	421		$	3,879		$	914
	Prior service cost (benefit)		1,448			418			(22	)		(8	)		(3,594	)		(1,011	)


	Total	$	56,709		$	7,013		$	4,188		$	413		$	285		$	(97	)




Schedule of assumptions used to determine the benefit obligation	'
		Pension						OPEB
		Benefits						OPEB
		2013			2012			2013			2012
	Discount rate		4.9	%		4	%		5	%		4.11	%
	Rate of compensation increase		3.5	%		3.5	%		3.5	%		3.5	%
Schedule of assumptions used to determine the periodic costs	'
		Pension Benefits									OPEB
		2013			2012			2011			2013			2012			2011
	Discount rate		4	%		4.7	%		5.5	%		4.11	%		4.9	%		5.5	%
	Expected return on plan assets		7.75	%		7.9	%		8	%		6.52	%		6.65	%		7	%
	Rate of compensation increase		3.5	%		3.5	%		4.5	%		3.5	%		3.5	%		4.5	%
Pension	'
Retirement benefits	'
Schedule of expected benefit payments	'

	Expected benefit payments are as follows (in millions):


	Year	Payments from Trust			Payments from
	Year	Payments from Trust			Company Funds
	2014	$	19.6		$	0.4
	2015		20.5			0.4
	2016		19.8			0.4
	2017		20.7			0.5
	2018		19.8			0.4
	2019 – 2023		92.4			2.5
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, 2013 and December 31, 2012 (in thousands):


		Fair Value Measurements as of December 31, 2013
		Quoted			Significant			Significant			Total			Percentage
		Prices in			Other			Unobservable						of Plan
		Active			Observable			Inputs						Assets
		Markets			Inputs			(Level 3)
		for			(Level 2)
		Identical
		Assets
		(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	%









		Fair Value Measurements as of December 31, 2012
		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	$	—		$	2,398		$	—		$	2,398			1.5	%
	Equity securities
	U.S. equity		63,655			—			—			63,655			39.7	%
	International equity		22,074			—			—			22,074			13.8	%
	Fixed income
	Common collective trust		—			26,110			—			26,110			16.3	%
	U.S. corporate debt		—			15,518			—			15,518			9.7	%
	U.S. government debt		1,535			—			—			1,535			1	%
	Other types of investments
	Equity long/short hedge funds		—			—			28,885			28,885			18	%


		$	87,264		$	44,026		$	28,885		$	160,175			100	%




Schedule of fair value measurements using significant unobservable inputs (level 3)	'
		2013			2012
		Equity long/short			Equity long/short
		hedge funds			hedge funds
	Beginning Balance, January 1,	$	28,885		$	27,419
	Actual return on plan assets:
	Relating to assets still held at the reporting date		(356	)		1,466
	Relating to assets sold during the period		4,583			—
	Purchases		26,500			—
	Sales		(22,883	)		—
	Settlements		—			—
	Transfers into and (out of) Level 3		—			—


	Ending Balance, December 31,	$	36,729		$	28,885




Schedule of permissible investments	'

	Permissible Investments


	Equity Oriented			Fixed Income Oriented and Real Estate
	•	Common Stocks		•		Bonds
	•	Preferred Stocks		•		GICs, BICs
	•	Convertible Preferred Stocks		•		Corporate Bonds (minimum quality rating
	•	Convertible Bonds				of Baa or BBB)
	•	Covered Options		•		Cash-Equivalent Securities (e.g., U.S.
	•	Hedged Equity Funds of Funds				T-Bills, Commercial Paper, etc.)
				•		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		•		Index Options
	•	Derivatives
OPEB	'
Retirement benefits	'
Schedule of expected benefit payments	'

	Estimated benefit payments are as follows (in millions):


	Year	Payments from Trust			Expected Federal			Payments from
	Year	Payments from Trust			Subsidy			Company Funds
	2014	$	2.5		$	0.3		$	0.1
	2015		2.9			0.3			0.2
	2016		3.2			0.4			0.2
	2017		3.5			0.4			0.2
	2018		3.8			0.5			0.2
	2019 – 2023		23.2			3.2			0.9
Schedule of effect of 1% change in assumed healthcare cost growth rates	'

	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	$	1,450		$	(1,115	)
	Effect on post-retirement benefit obligation	$	14,027		$	(11,179	)
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, 2013 and December 31, 2012 (in thousands):


		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	%









		Fair Value Measurements as of December 31, 2012
		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	$	895		$	—		$	—		$	895			1.3	%
	Fixed income
	U.S. government debt		729			—			—			729			1.1	%
	U.S. corporate debt		—			19,437			—			19,437			28.7	%
	Foreign debt		—			2,250			—			2,250			3.3	%
	Mutual funds — fixed income		3,914			—			—			3,914			5.8	%
	Equity securities
	U.S. equity		20,795			—			—			20,795			30.7	%
	International equity		1,548			—			—			1,548			2.3	%
	Mutual funds — equity		17,818			—			—			17,818			26.3	%


		$	45,699		$	21,687		$	—			67,386


	Accrued interest & dividends											281			0.5	%


										$	67,667			100	%




Schedule of permissible investments	'

	Permissible Investments


	Equity			Fixed Income
	•	Common Stocks		•		Cash-Equivalent Securities with a maturity
	•	Preferred Stocks				of one-year or less
				•		Bonds
				•		Money Market Funds / Bank STIF Funds
				•		Certificates of Deposit in institutions with FDIC protection
				•		Corporate Bonds (minimum quality rating of A)

	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
	•	Commodities Futures		•		Short Sales
	•	Securities of Empire District		•		Index Options
	•	Derivatives		•		Real Estate and Real Property
	•	Instrumentalities in violation of the Prohibited Transactions Standards of ERISA		•		Restricted Stock

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
INCOME TAXES (Tables)	Dec. 31, 2013
INCOME TAXES	'
Schedule of income tax expense components	'

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


		2013			2012			2011
	Current income taxes:
	Federal	$	6,726		$	1,552		$	(8,604	)
	State		2,495			708			(2,120	)


	TOTAL		9,221			2,260			(10,724	)
	Deferred income taxes:
	Federal		24,954			28,210			39,096
	State		3,554			4,018			6,297


	TOTAL		28,508			32,228			45,393
	Investment tax credit amortization		(237	)		(329	)		(371	)


	TOTAL INCOME TAX EXPENSE	$	37,492		$	34,159		$	34,298




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	2013			2012
	Current deferred tax assets, net⁽¹⁾	$	7,222		$	13,000
	Non-current deferred tax liabilities, net		324,266			301,967


	NET DEFERRED TAX LIABILITIES	$	317,044		$	288,967






	-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	2013			2012
	Deferred tax assets:
	Net operating loss	$	—		$	13,000
	Disallowed plant costs		1,841			1,010
	Gains on hedging transactions		1,324			1,389
	Plant related basis differences		23,344			21,571
	Regulated liabilities related to income taxes		13,576			13,871
	Pensions and other post-retirement benefits		544			693
	Carry forward of income tax credit		6,374			3,722
	Other		1,633			2,262


	Total deferred tax assets	$	48,636		$	57,518


	Deferred tax liabilities:
	Depreciation, amortization and other plant related differences	$	297,175		$	279,604
	Regulated assets related to income		37,806			39,553
	Loss on reacquired debt		4,085			4,489
	Amortization of intangibles		8,089			7,009
	Deferred construction accounting costs		6,977			7,323
	Other		11,548			8,507


	Total deferred tax liabilities		365,680			346,485


	NET DEFERRED TAX LIABILITIES	$	317,044		$	288,967




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	2013			2012			2011
	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		(0.2	)		(0.4	)		(0.4	)
	Effect of ratemaking on property related differences		(1.1	)		(0.2	)		0.2
	Other		0.3			0.5			0.5


	EFFECTIVE INCOME TAX RATE		37.1	%		38	%		38.4	%




Schedule of unrecognized tax benefits	'




	Unrecognized Tax Benefits	2013			2012			2011
	Unrecognized tax benefits — January 1,	$	—		$	—		$	359,000
	The gross amounts of increases in unrecognized tax benefits taken during prior periods		—			—			—
	The gross amounts of decreases in unrecognized tax benefits taken during the period relating to positions accepted by taxing authorities		—			—			—
	Reductions to unrecognized tax benefits as a result of a lapse of the applicable statute of limitations		—			—			(359,000	)


	UNRECOGNIZED TAX BENEFITS — December 31,	$	—		$	—		$	—

COMMONLY_OWNED_FACILITIES_Tabl

COMMONLY OWNED FACILITIES (Tables)	12 Months Ended
COMMONLY OWNED FACILITIES (Tables)	Dec. 31, 2013
Iatan	'
Commonly Owned Facilities	'
Schedule of property, plant and equipment	'

	At December 31, 2013 and 2012, our property, plant and equipment accounts included the amounts in the following chart (in millions):


	Iatan	2013		2012
	Cost of ownership in plant in service	$	367.1	$	364.1
	Accumulated Depreciation	$	91.1	$	83.2
	Expenditures⁽¹⁾	$	31.6	$	30


	-1
	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, 2013 and 2012, our property, plant and equipment accounts included the amounts in the following chart (in millions):


	State Line Combined Cycle Unit	2013		2012
	Cost of ownership in plant in service	$	163.3	$	164.4
	Accumulated Depreciation	$	37	$	36.7
	Expenditures⁽¹⁾	$	52.6	$	42.7


	-1
	Operating, maintenance, and fuel expenditures excluding depreciation expense.

Plum point	'
Commonly Owned Facilities	'
Schedule of property, plant and equipment	'

	At December 31, 2013 and 2012, our property, plant and equipment accounts included the amounts in the following chart (in millions):


	Plum Point Energy Station	2013		2012
	Cost of ownership in plant in service	$	108.2	$	108
	Accumulated Depreciation	$	7.3	$	4.9
	Expenditures⁽¹⁾	$	11.3	$	7.8


	-1
	Operating, maintenance and fuel expenditures excluding depreciation expense.

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
COMMITMENTS AND CONTINGENCIES (Tables)	Dec. 31, 2013
COMMITMENTS AND CONTINGENCIES	'
Schedule of coal, natural gas and transportation contracts	'

	(in millions)	Firm physical gas		Coal and coal
		and transportation		transportation
		contracts		contracts
	January 1, 2014 through December 31, 2014	$	24.9	$	23.8
	January 1, 2015 through December 31, 2016	$	31.4	$	28.8
	January 1, 2017 through December 31, 2018	$	30.2	$	22.6
	January 1, 2019 and beyond	$	45.9	$	11.3
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
	2014	$	553	$	764
	2015		553		722
	2016		549		720
	2017		547		681
	2018		546		646
	Thereafter		3,553		485


	Total minimum payments		6,301	$	4,018
	Less amount representing interest		1,860


	Present value of net minimum lease payments	$	4,441

SEGMENT_INFORMATION_Tables

SEGMENT INFORMATION (Tables)	12 Months Ended
SEGMENT INFORMATION (Tables)	Dec. 31, 2013
SEGMENT INFORMATION	'
Schedule of statement of income information, balance sheet information and capital expenditures by business segments	'
			For the year ended December 31,
			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





			2011
			Electric			Gas			Other			Eliminations			Total
	Statement of Income Information:
	Revenues		$	524,276		$	46,430		$	6,756		$	(592	)	$	576,870
	Depreciation and amortization			58,236			3,494			1,807			—			63,537
	Federal and state income taxes			31,643			1,676			979			—			34,298
	Operating income			88,590			6,514			1,830			—			96,934
	Interest income			554			259			—			(258	)		555
	Interest expense			37,860			3,910			8			(258	)		41,520
	Income from AFUDC (debt and equity)			509			3			—			—			512
	Income from continuing operations		$	50,670		$	2,709		$	1,592		$	—		$	54,971
	Capital Expenditures		$	93,499		$	4,122		$	3,556		$	—		$	101,177





			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





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


-1
Includes goodwill of $39,492 at December 31, 2013 and 2012.

SELECTED_QUARTERLY_INFORMATION1

SELECTED QUARTERLY INFORMATION (UNAUDITED) (Tables)	12 Months Ended
SELECTED QUARTERLY INFORMATION (UNAUDITED) (Tables)	Dec. 31, 2013
SELECTED QUARTERLY INFORMATION (UNAUDITED)	'
Summary of quarterly results	'

	The following is a summary of quarterly results for 2013 and 2012 (dollars in thousands except per share amounts):


		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	$	0.3	$	0.27	$	0.56	$	0.35





		Quarters
	Quarterly Results for 2012	First		Second		Third		Fourth
	Operating revenues	$	137,144	$	131,632	$	159,202	$	129,119
	Operating income	$	20,810	$	20,762	$	35,282	$	19,367
	Net Income	$	9,804	$	10,708	$	25,542	$	9,627
	Basic and Diluted Earnings Per Share	$	0.23	$	0.25	$	0.6	$	0.23

RISK_MANAGEMENT_AND_DERIVATIVE1

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2013
RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS	'
Schedule of fair value of derivative financial instruments, balance sheet classification	'

	As of December 31, 2013 and 2012, 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			2013			2012
		Balance Sheet Classification		Fair			Fair
		Balance Sheet Classification		Value			Value
	Natural gas contracts, gas segment	Current assets		$	35		$	3
		Non-current assets and deferred charges — Other			—			17
	Natural gas contracts, electric segment	Current assets			467			93
		Non-current assets and deferred charges — Other			41			174
	Transmission congestion rights, electric segment	Current assets			1,967			—


	Total derivatives assets			$	2,510		$	287





	LIABILITY DERIVATIVES


	Non-designated as hedging instruments due to regulatory accounting			2013			2012
		Balance Sheet Classification		Fair			Fair
		Balance Sheet Classification		Value			Value
	Natural gas contracts, gas segment	Current liabilities		$	8		$	104
		Non-current liabilities and deferred credits			—			—
	Natural gas contracts, electric segment	Current liabilities			1,881			3,299
		Non-current liabilities and deferred credits			2,799			3,819
	Transmission congestion rights, electric segment	Current liabilities			—			—


	Total derivatives liabilities			$	4,688		$	7,222




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

	The following tables set forth "mark-to-market" pre-tax gains/ (losses) from non-designated derivative instruments for the electric segment for each of the 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		2013			2012
		of Gain/(Loss) on Derivative		2013			2012
	Commodity contracts — electric segment	Regulatory (assets)/liabilities		$	(338	)	$	(2,448	)
	Transmission congestion rights — electric segment	Regulatory (assets)/liabilities			1,967			—


	Total — Electric Segment			$	1,629		$	(2,448	)





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


				Amount of
				Gain/(Loss)
				Recognized in
				Income
				on Derivative
		Statement of Operations Classification of Loss on Derivative		2013			2012
	Commodity contracts	Fuel and purchased power expense		$	(2,725	)	$	(3,985	)
	Transmission congestion rights — electric segment	Fuel and purchased power expense			81			—


	Total — Electric Segment			$	(2,644	)	$	(3,985	)




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

	At December 31, 2013, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for 2014 and the next four years are hedged at the following average prices per Dekatherm (Dth):


	Year	% Hedged			Dth Hedged			Dth Hedged		Average Price
	Year	% Hedged			Physical			Financial		Average Price
	2014		61	%		1,560,000			4,640,000	$	4.411
	2015		41	%		—			4,010,000	$	4.578
	2016		22	%		—			2,100,000	$	4.415
	2017		10	%		—			1,050,000	$	4.43
	2018		0	%		—			—	$	—
Schedule of minimum percentage hedged by year in the entity's procurement guidelines	'

	Year	End of Year
	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
	2014		1,918		$	1,966,846
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, 2013 (Dth in thousands).


	Season	Minimum %			Dth Hedged			Dth Hedged		Dth in		Actual %
	Season	Hedged			Financial			Physical		Storage		Hedged
	Current		50	%		240,000			—		948,850		59	%
	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		2013			2012
		of Loss on Derivative		2013			2012
	Commodity contracts	Regulatory assets		$	(5	)	$	(461	)


	Total — Gas Segment			$	(5	)	$	(461	)

FAIR_VALUE_MEASUREMENTS_Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
FAIR VALUE MEASUREMENTS (Tables)	Dec. 31, 2013
FAIR VALUE MEASUREMENTS	'
Schedule of transmission congestion rights (TCR) and commodity contracts measured at fair value	'

	($ 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, 2013
	Derivative assets	$	2,510		$	543		$	1,967		—
	Derivative liabilities	$	(4,688	)	$	(4,688	)	$	—		—
	December 31, 2012
	Derivative assets	$	287		$	287			—		—
	Derivative liabilities	$	(7,222	)	$	(7,222	)		—		—


	*
	The only recurring measurements are derivative related.

REGULATED_OPERATING_EXPENSE_Ta

REGULATED OPERATING EXPENSE (Tables)	12 Months Ended
REGULATED OPERATING EXPENSE (Tables)	Dec. 31, 2013
REGULATED OPERATING EXPENSE	'
Schedule of regulated operating expenses	'

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


		December 31,
		2013		2012		2011
	Power operation expense (other than fuel)	$	15,643	$	15,045	$	12,685
	Electric transmission and distribution expense		21,863		17,083		15,361
	Natural gas transmission and distribution expense		2,498		2,443		2,385
	Customer accounts & assistance expense		11,180		10,211		10,210
	Employee pension expense⁽¹⁾		10,736		10,180		8,805
	Employee healthcare plan⁽¹⁾		10,190		9,825		7,439
	General office supplies and expense		12,850		10,776		10,158
	Administrative and general expense		14,800		15,091		14,295
	Bad debt expense		3,665		3,038		3,425
	Regulatory reversal of gain on sale of assets		1,236		—		—
	Miscellaneous expense		672		679		679


	TOTAL	$	105,333	$	94,371	$	85,442






	-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, 2013
	town
	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)	90.30%
Number of customers	168,800
Electric \| Water	'
Operating revenues	'
% of revenue (as a percent)	0.40%
Electric \| Missouri	'
Operating revenues	'
% of revenue (as a percent)	89.80%
Electric \| Kansas	'
Operating revenues	'
% of revenue (as a percent)	4.80%
Electric \| Arkansas	'
Operating revenues	'
% of revenue (as a percent)	2.50%
Electric \| Oklahoma	'
Operating revenues	'
% of revenue (as a percent)	2.90%
Electric \| Residential	'
Operating revenues	'
% of revenue (as a percent)	42.60%
Electric \| Commercial	'
Operating revenues	'
% of revenue (as a percent)	30.40%
Electric \| Industrial	'
Operating revenues	'
% of revenue (as a percent)	15.10%
Electric \| Wholesale on-system	'
Operating revenues	'
% of revenue (as a percent)	3.70%
Electric \| Wholesale off-system	'
Operating revenues	'
% of revenue (as a percent)	2.90%
Electric \| Miscellaneous sources, primarily public authorities	'
Operating revenues	'
% of revenue (as a percent)	2.80%
Electric \| Other electric revenues	'
Operating revenues	'
% of revenue (as a percent)	2.50%
Gas	'
Operating revenues	'
% of revenue (as a percent)	8.40%
Number of customers	44,000
Gas \| Residential	'
Operating revenues	'
% of revenue (as a percent)	63.10%
Gas \| Commercial	'
Operating revenues	'
% of revenue (as a percent)	27.30%
Gas \| Industrial	'
Operating revenues	'
% of revenue (as a percent)	1.00%
Gas \| Other electric revenues	'
Operating revenues	'
% of revenue (as a percent)	8.60%
Other	'
Operating revenues	'
% of revenue (as a percent)	1.30%

SUMMARY_OF_SIGNIFICANT_ACCOUNT4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Municipal Franchise Taxes	'	'	'
Municipal franchise taxes	$11,200,000	$10,400,000	$11,000,000
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	4,200,000	5,200,000	'
Property, Plant and Equipment	'	'	'
Accrued cost of removal	137,693,000	137,358,000	'
Electric \| Cost of removal	'	'	'
Property, Plant and Equipment	'	'	'
Accrued cost of removal	81,300,000	77,300,000	'
Gas \| Cost of removal	'	'	'
Property, Plant and Equipment	'	'	'
Accrued cost of removal	$7,200,000	$6,100,000	'

SUMMARY_OF_SIGNIFICANT_ACCOUNT5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 3) (USD $)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Oct. 31, 2013

Dec. 31, 2013

Oct. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

item

Over recovered electric fuel and purchased power costs

Electric

Gas

Low end of range

High end of range

Asset retirement obligation

Iatan2

item

Missouri Public Service Commission (MPSC)

item

Gas

Asset Retirement Obligation

Proportionate ownership interest (as a percent)

12.00%

Credit adjusted risk-free rate (as a percent)

4.50%

5.52%

Change in asset retirement obligation

Opening balance of asset retirement obligation

$4,711,000

$3,944,000

Liabilities settled

-734,000

Accretion

213,000

252,000

Cash Flow Revisions

515,000

Closing balance of asset retirement obligation

4,190,000

4,711,000

3,944,000

Regulatory assets

177,076,000

250,335,000

600,000

4,000,000

4,700,000

4,400,000

Allowance for Funds Used During Construction

Aggregate rates (on a before-tax basis)

7.30%

5.60%

5.20%

Reduction in equity portion of AFUDC rate (as a percent)

2.50%

Asset Impairments (excluding goodwill)

Assets impaired

Goodwill

39,492,000

Number of assumptions whose negative charge will affect impairment

Number of approaches used to estimate the fair value

Excess fair value of the reporting unit over carrying value

10,000,000

14,000,000

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%

Regulatory liability

137,693,000

137,358,000

600,000

4,000,000

Inventory allowances

Number of SO2 allowances in inventory

1,834

5,187

Maximum number of rate changes allowed by PGA clause throughout the year

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

Federal subsidy as percentage of prescription drug costs

28.00%

Prescription drug costs for which the basis of the federal subsidy is calculated

250

5,000

Cash & Cash Equivalents

Checks and electronic fund transfers that have been issued but not cleared through bank

22,100,000

19,700,000

Restricted Cash

Amounts restricted for construction costs

2,500,000

Amounts restricted for operating costs

1,800,000

Amounts restricted for secured collateral

$1,100,000

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Fuel, Materials and Supplies	'	'	'
Total	$48,811	$61,870	'
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)	42,781,000	42,257,000	41,852,000
Dilutive Securities:	'	'	'
Performance-based restricted stock awards (in shares)	12,142	14,500	18,222
Dividend equivalents (in shares)	'	6,329	9,585
Employee stock purchase plan (in shares)	1,729	1,996	3,815
Stock options (in shares)	61	3,160	3,240
Time-based restricted stock awards (in shares)	7,907	1,820	807
Total dilutive securities (in shares)	21,839	27,805	35,669
Diluted weighted average number of shares	42,803,000	42,284,000	41,887,000
Antidilutive Shares	107,100	128,500	128,500
Electric fuel inventory	'	'	'
Fuel, Materials and Supplies	'	'	'
Total	17,003	27,954	'
Natural gas inventory	'	'	'
Fuel, Materials and Supplies	'	'	'
Total	3,584	4,776	'
Materials and supplies	'	'	'
Fuel, Materials and Supplies	'	'	'
Total	$28,224	$29,140	'

PROPERTY_PLANT_AND_EQUIPMENT_D

PROPERTY, PLANT AND EQUIPMENT (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, plant and equipment	'	'	'
Plant and property, Gross	$39,902	$37,983	'
Plant and property, Gross	72,834	69,851	'
Less accumulated depreciation and amortization	732,737	682,737	'
Construction work in progress	152,330	56,347	'
Total plant and property, Net	1,751,934	1,657,632	'
Provision for depreciation	68,893	62,607	59,920
Amortization	2,492	1,041	7,445
Total depreciation and amortization	71,385	63,648	67,365
Annual depreciation rates (as a percent)	3.10%	2.90%	2.90%
Non-Regulated	'	'	'
Property, plant and equipment	'	'	'
Provision for depreciation	1,938	1,538	1,807
Annual depreciation rates (as a percent)	5.00%	4.20%	5.40%
Electric plant \| Regulated	'	'	'
Property, plant and equipment	'	'	'
Plant and property, Gross	2,206,944	2,163,872	'
Less accumulated depreciation and amortization	697,128	651,627	'
Plant and property, net of depreciation and amortization	1,509,816	1,512,245	'
Construction work in progress	150,636	55,957	'
Total plant and property, Net	1,660,452	1,568,202	'
Electric plant \| Intangible property, primarily capitalized software and investments in facility upgrades \| Regulated	'	'	'
Property, plant and equipment	'	'	'
Plant and property, Gross	38,100	36,400	'
Less accumulated depreciation and amortization	13,600	10,700	'
Production \| Regulated	'	'	'
Property, plant and equipment	'	'	'
Plant and property, Gross	1,035,095	1,034,114	'
Annual depreciation rates (as a percent)	2.40%	2.00%	2.10%
Transmission \| Regulated	'	'	'
Property, plant and equipment	'	'	'
Plant and property, Gross	263,398	251,769	'
Annual depreciation rates (as a percent)	2.40%	2.40%	2.30%
Distribution \| Regulated	'	'	'
Property, plant and equipment	'	'	'
Plant and property, Gross	793,024	766,026	'
Annual depreciation rates (as a percent)	3.60%	3.60%	3.60%
General \| Regulated	'	'	'
Property, plant and equipment	'	'	'
Plant and property, Gross	115,427	111,963	'
Amortization	'	'	6,600
Annual depreciation rates (as a percent)	5.80%	5.90%	6.10%
Gas plant \| Regulated	'	'	'
Property, plant and equipment	'	'	'
Plant and property, Gross	72,834	69,851	'
Less accumulated depreciation and amortization	15,204	12,940	'
Plant and property, net of depreciation and amortization	57,630	56,911	'
Construction work in progress	1,156	184	'
Total plant and property, Net	58,786	57,095	'
Provision for depreciation	3,763	3,602	3,485
Annual depreciation rates (as a percent)	5.40%	5.40%	5.50%
Water plant \| Regulated	'	'	'
Property, plant and equipment	'	'	'
Plant and property, Gross	12,661	12,316	'
Less accumulated depreciation and amortization	4,806	4,440	'
Plant and property, net of depreciation and amortization	7,855	7,876	'
Construction work in progress	'	1	'
Total plant and property, Net	7,855	7,877	'
Annual depreciation rates (as a percent)	2.80%	2.70%	2.70%
Other \| Non-Regulated	'	'	'
Property, plant and equipment	'	'	'
Construction work in progress	538	205	'
Total plant and property, Net	24,841	24,458	'
Fiber \| Non-Regulated	'	'	'
Property, plant and equipment	'	'	'
Plant and property, Gross	39,902	37,983	'
Less accumulated depreciation and amortization	15,599	13,730	'
Plant and property, net of depreciation and amortization	24,303	24,253	'
Electric and Water \| Regulated	'	'	'
Property, plant and equipment	'	'	'
Provision for depreciation	$63,192	$57,467	$54,628
Annual depreciation rates (as a percent)	3.00%	2.80%	2.70%

REGULATORY_MATTERS_Details

REGULATORY MATTERS (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

22-May-11

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Missouri 2012 Rate Case

Missouri, Kansas and Oklahoma

Cost of removal

Unamortized gain on interest rate derivative

Deferred construction accounting costs - fuel

SWPA payment for Ozark Beach lost generation

Over recovered fuel costs

Current portion of long-term regulatory liabilities

Pension and other postretirement benefits

Income taxes

Storm costs

Unamortized loss on reacquired debt

Deferred operating and maintenance expense

Unamortized loss on interest rate derivative

Deferred construction accounting costs

Asset retirement obligation

Customer programs

System reliability - vegetation management

Other

Under recovered electric fuel and purchased gas costs

Ice storm and tornado cost

Under recovered fuel costs

Current portion of long-term regulatory assets

Asbury five-year maintenance

Gas

Electric

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Missouri

Cost of removal

Unsettled derivative losses

Regulatory Assets and Liabilities

Deferred tornado costs recovery period

'10 years

Regulatory Assets:

Regulatory assets, current

$7,743,000

$6,377,000

$1,411,000

$2,885,000

$6,332,000

$3,492,000

Regulatory assets, long-term

169,333,000

243,958,000

70,035,000

136,480,000

48,033,000

48,759,000

4,911,000

4,828,000

11,078,000

12,142,000

2,095,000

2,049,000

989,000

1,147,000

16,275,000

16,717,000

4,673,000

4,430,000

4,935,000

4,356,000

7,539,000

9,002,000

833,000

669,000

3,700,000

314,000

-6,332,000

-3,492,000

4,269,000

6,557,000

Regulatory assets, total

177,076,000

250,335,000

4,700,000

4,400,000

Regulatory Asset Noncurrent, Amortization Period

'1 year

'28 years

'5 years

'1 year

'28 years

'1 year

'28 years

'5 years

Period to recover costs in Missouri, Kansas and Oklahoma rates

'12 months

Portion of regulatory assets expected to be recoverable in future periods

61,200,000

Regulatory Liabilities:

Regulatory liabilities, current

5,681,000

6,303,000

2,212,000

3,214,000

3,469,000

3,089,000

Regulatory liabilities, long-term

132,012,000

131,055,000

88,469,000

83,368,000

3,371,000

3,541,000

8,011,000

8,156,000

19,405,000

22,242,000

2,371,000

2,858,000

-3,469,000

-3,089,000

2,177,000

2,007,000

11,677,000

11,972,000

Regulatory liabilities, total

$137,693,000

$137,358,000

$7,200,000

$6,100,000

$81,300,000

$77,300,000

REGULATORY_MATTERS_Details_2

REGULATORY MATTERS (Details 2) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Dec. 31, 2013

Dec. 31, 2011

22-May-11

Apr. 02, 2013

Dec. 31, 2013

Dec. 31, 2012

Apr. 02, 2013

Jul. 06, 2012

Jun. 15, 2011

Sep. 28, 2010

Dec. 31, 2013

Nov. 23, 2012

Oct. 18, 2012

21-May-12

Jun. 17, 2011

Jan. 02, 2012

Mar. 25, 2010

Jan. 04, 2012

Jun. 30, 2011

Mar. 02, 2011

Dec. 03, 2013

Apr. 13, 2011

Jul. 31, 2012

Jun. 13, 2013

Nov. 30, 2011

Missouri 2012 Rate Case

Missouri Public Service Commission (MPSC)

Kansas Corporation Commission (KCC)

Oklahoma Corporation Commission (OCC)

Arkansas Public Service Commission (APSC)

Federal Energy Regulatory Commission (FERC)

Missouri 2012 Rate Case

Electric

Water

Electric

TFR rate case

GFR rate case.

Iatan2

Missouri 2012 Rate Case

Missouri 2010 Rate Case

Tornado Recovery

Missouri 2012 Rate Case

Kansas 2011 Rate Case

Capital cost recovery rider (CCRR)

Oklahoma 2011 Rate Case

Capital Reliability Rider (CRR)

Phase 2 Capital Reliability Rider (CRR)

Arkansas 2013 Rate Case

Arkansas 2010 Rate Case

item

REGULATORY MATTERS

Test period for operating expense taken as a basis for increase in base rate

'12 months

RATE MATTERS

Approved amount of annual increase in base rate

$27,500,000

$18,700,000

$450,000

$1,250,000

$240,722

$1,063,100

$2,104,321

Approved percentage of annual increase in base rate

6.78%

4.70%

25.50%

5.20%

1.66%

9.32%

19.00%

Deferred tornado costs recovery period

'10 years

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

3,600,000

Loss on plant disallowance

2,409,000

150,000

2,400,000

Reverse gain on sale of Asbury unit train

1,236,000

1,200,000

Requested amount of annual increase in electric base rate

30,700,000

36,500,000

516,400

1,500,000

600,000

2,200,000

Period to recover costs in Kansas

'3 years

Percentage of annual base rate increase requested

7.56%

9.20%

29.60%

6.39%

4.10%

18.00%

Tax benefits of cost of removal to be flowed through to customers

9,600,000

Amount of increase in base rate for which unanimous agreement filed

450,000

Annual regulatory amortization expense terminated as a result of rate case settlement

14,500,000

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

200,000

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

3,700,000

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

'10 years

Number of steps requested under the capital cost recovery rider preceding a general rate case

Period for which rate suspended

'5 months

Percentage of ROE

10.00%

Accumulated provision - rate refunds

1,300,000

Period within which SWPA payment will be made to customers

'10 years

Base rate increase request annual decrease to expenses

$1,400,000

REGULATORY_MATTERS_Details_3

REGULATORY MATTERS (Details 3) (USD $)

Dec. 31, 2013

Oct. 31, 2012

Dec. 31, 2013

Dec. 31, 2010

Dec. 31, 2013

In Millions, unless otherwise specified

SPP Regional Transmission Development

SPP Day-Ahead Market

Minimum

Electric

Transmission projects 300 kV or above

Transmission projects between 100 kV and 299 kV

Transmission projects below 100 kV

Electric

Minimum

Maximum

Electric

Minimum

Maximum

Minimum

Maximum

RATE MATTERS

Percentage of generation needed for next day throughout SPP territory that will be cleared through Integrated Marketplace

90.00%

95.00%

Estimated increase in net transmission cost in 2014 as a result of SPP's allocation methodology

Deferred expenses related to rate cases

$1.20

Transmission Project Voltage (in kV)

161

300

100

299

100

Regional Funding Percentage

100.00%

33.00%

0.00%

Zonal Funding Percentage

0.00%

67.00%

100.00%

COMMON_STOCK_Details

COMMON STOCK (Details) (USD $)	12 Months Ended
COMMON STOCK (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
COMMON STOCK	'	'	'
Compensation expense	$2,577,000	$1,863,000	$1,765,000
Tax benefit recognized	929,000	649,000	614,000
Employee Stock Purchase Plan	'	'	'
Assumptions used in the model for each grant year	'	'	'
Weighted average fair value of grants (in dollars per share)	$2.78	$3.19	$3.17
Risk-free interest rate (as a percent)	0.14%	0.17%	0.18%
Expected volatility (as a percent)	14.00%	24.00%	22.00%
Dividend yield (as a percent)	4.60%	5.00%	2.60%
Expected life	'12 months	'12 months	'12 months
Number of historical years over which expected volatility is based	'1 year	'	'
Changes in restricted stock awards	'	'	'
Nonvested, balance at the beginning of the period (in shares)	70,850	70,756	'
Nonvested, balance at the end of the period (in shares)	60,413	70,850	70,756
2006 Stock Incentive Plan	'	'	'
Fair value	'	'	'
Number of shares of common stock provided for grant	650,000	'	'
Time-Vested Restricted Stock Awards	'	'	'
Fair value	'	'	'
Total unrecognized compensation cost	200,000	'	'
Recognition period	'	'1 year 7 months 6 days	'
Fair value (in dollars per share)	$19.88	$18.38	'
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	'	'
Unrecognized compensation expense related to estimated outstanding awards	200,000	'	'
Vesting period	'3 years	'	'
Changes in restricted stock awards	'	'	'
Nonvested, balance at the beginning of the period (in shares)	3,300	3,433	'
Granted (in shares)	21,600	'	10,200
Vested (in shares)	'	'	794
Distributed (in shares)	'	-133	-661
Forfeited (in shares)	'	'	-6,106
Vested but not distributed (in shares)	'	'	133
Nonvested, balance at the end of the period (in shares)	24,900	3,300	3,433
Weighted Average Grant Date Price	'	'	'
Nonvested, balance at the beginning of the period (in dollars per share)	$20.38	$21.84	'
Granted (in dollars per share)	$21.36	'	$21.84
Vested (in dollars per share)	'	'	$19.32
Distributed (in dollars per share)	'	$20.13	$21.02
Vested but not distributed (in dollars per share)	'	'	$20.13
Nonvested, balance at the end of the period (in dollars per share)	$22.69	$20.38	$21.84
Time-Vested Restricted Stock Awards \| Minimum	'	'	'
Fair value	'	'	'
Recognition period	'1 month 6 days	'	'
Time-Vested Restricted Stock Awards \| Maximum	'	'	'
Fair value	'	'	'
Total unrecognized compensation cost	'	100,000	'
Recognition period	'2 years 1 month 6 days	'	'
Unrecognized compensation expense related to estimated outstanding awards	'	100,000	'
Performance-Based Restricted Stock Awards	'	'	'
Fair value	'	'	'
Total unrecognized compensation cost	500,000	100,000	'
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%	'	'
Unrecognized compensation expense related to estimated outstanding awards	$500,000	$100,000	'
Vesting period	'3 years	'	'
Assumptions used in the model for each grant year	'	'	'
Risk-free interest rate, low end of range (as a percent)	0.13%	0.16%	0.12%
Risk-free interest rate, high end of range (as a percent)	0.38%	0.25%	0.23%
Expected volatility (as a percent)	20.20%	20.60%	23.80%
Dividend yield (as a percent)	4.50%	4.90%	4.70%
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)	$18.47	$10.94	$13.67
Changes in restricted stock awards	'	'	'
Nonvested, balance at the beginning of the period (in shares)	33,900	37,400	47,500
Granted (in shares)	26,300	10,000	10,900
Vested (in shares)	-4,460	-7,823	-39,621
Awarded in excess of target (in shares)	'	'	18,621
Not Awarded (in shares)	-8,540	-5,677	'
Nonvested, balance at the end of the period (in shares)	47,200	33,900	37,400
Weighted Average Grant Date Price	'	'	'
Nonvested, balance at the beginning of the period (in dollars per share)	$20.25	$19.28	$19.86
Granted (in dollars per share)	$21.36	$20.97	$21.84
Vested (in dollars per share)	$18.36	$18.12	$21.92
Awarded in Excess of target (in dollars per share)	'	'	$21.92
Not Awarded (in dollars per share)	$18.36	$18.12	'
Nonvested, balance at the end of the period (in dollars per share)	$21.39	$20.25	$19.28
Performance-Based Restricted Stock Awards \| Minimum	'	'	'
Assumptions used in the model for each grant year	'	'	'
Expected volatility of peer group stock (as a percent)	12.30%	12.40%	15.70%
Fair value percentage	0.00%	18.00%	51.00%
Performance-Based Restricted Stock Awards \| Maximum	'	'	'
Assumptions used in the model for each grant year	'	'	'
Expected volatility of peer group stock (as a percent)	27.50%	29.20%	57.40%
Fair value percentage	108.00%	96.00%	75.00%
Stock Options	'	'	'
Fair value	'	'	'
Recognition period	'	'1 month	'1 year
Vesting period	'3 years	'	'
Stock options, expiration term	'10 years	'	'
Assumptions used in the model for each grant year	'	'	'
Risk-free interest rate, low end of range (as a percent)	0.10%	0.11%	0.12%
Risk-free interest rate, high end of range (as a percent)	0.38%	0.44%	0.72%
Expected volatility (as a percent)	24.00%	24.00%	25.00%
Dividend yield (as a percent)	4.50%	4.90%	4.70%
Expected life	'	'78 months	'78 months
Market value (in dollars per share)	$22.69	$20.38	$21.09
Weighted average fair value per option (in dollars per share)	$1.57	$1.34	$2.08
Stock Options \| Minimum	'	'	'
Assumptions used in the model for each grant year	'	'	'
Expected life	'6 months 15 days	'	'
Stock Options \| Maximum	'	'	'
Assumptions used in the model for each grant year	'	'	'
Expected life	'24 months 15 days	'	'

COMMON_STOCK_Details_2

COMMON STOCK (Details 2) (Stock Options, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock options	'	'	'
Outstanding, balance at the beginning of the period (in shares)	163,300	190,300	267,400
Granted (in shares)	0	0	0
Exercised (in shares)	-50,800	-27,000	-77,100
Outstanding, balance at the end of the period (in shares)	112,500	163,300	190,300
Exercisable (in shares)	112,500	128,500	128,500
Weighted Average Exercise Price	'	'	'
Outstanding, balance at the beginning of the period (in dollars per option)	$22.13	$21.56	$21.69
Exercised (in dollars per share)	$21.78	$18.12	$22.02
Outstanding, balance at the end of the period (in dollars per option)	$23.27	$22.13	$21.56
Exercisable (in dollars per share)	$23.27	$23.15	$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	$0.20
Weighted-average remaining contractual life of outstanding options	'2 years 1 month 6 days	'3 years 2 months 12 days	'5 years 1 month 6 days
Range of exercise prices, low end of range (in dollars per share)	$21.92	$18.36	$18.12
Range of exercise prices, high end of range (in dollars per share)	$23.81	$23.81	$23.81
Total unrecognized compensation expense related to non-vested options and related dividend equivalents granted under the plan	'	'	0.1
Recognition period	'	'1 month	'1 year
Maximum	'	'	'
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	'

COMMON_STOCK_Details_3

COMMON STOCK (Details 3) (Employee Stock Purchase Plan, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Stock Purchase Plan	'	'	'
Stock-Based Awards and Programs	'	'	'
Common stock purchase price to eligible employees (as a percent)	90.00%	'	'
Percentage of Black-Scholes methodology used as a component to calculate value of lookback feature	90.00%	'	'
Percentage of maximum subscription price used as a component to calculate value of lookback feature	10.00%	'	'
Shares available for issuance	127,774	'	'
Subscriptions outstanding (in shares)	60,413	70,850	70,756
Maximum subscription price (in dollars per share)	$19.58	$17.95	$17.27
Shares of stock issued	68,099	65,919	69,229
Stock issuance price (in dollars per share)	$17.95	$17.27	$16.06

COMMON_STOCK_Details_4

COMMON STOCK (Details 4) (Stock Unit Plan for directors)	12 Months Ended
COMMON STOCK (Details 4) (Stock Unit Plan for directors)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock Unit Plan for directors	'	'	'
Assumptions used for estimating fair value of grants outstanding	'	'	'
Number of shares authorized under the plan	400,000	'	'
Number of shares accrued in director's accounts	154,402	143,058	'
Number of shares available for issuance under the plan	236,056	258,960	'
Units accrued for service and dividends (in shares)	34,252	30,426	25,287
Units redeemed for common stock (in shares)	22,908	21,324	31,243

COMMON_STOCK_Details_5

COMMON STOCK (Details 5) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 15, 2012

Jan. 02, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Subsequent event

401 (k) plan and ESOP

Maximum percentage of annual compensation to be deferred by participating employees

25.00%

Percentage of each employee's deferrals to be matched

50.00%

Maximum matching contribution as a percentage of employee's eligible compensation

3.00%

Shares available to be issued

256,448

320,576

Shares contributed

64,128

65,502

68,523

Disclosure of pension plan based on cash balance formula

Percentage of matching contribution from employer

100.00%

Percentage of employee contribution, which defers in the 401(k) Plan

6.00%

Percentage of matching contribution from employer in common stock

3.00%

Dividends

Diluted earnings per share (in dollars per share)

$0.35

$0.56

$0.27

$0.30

$0.23

$0.60

$0.25

$0.23

$1.48

$1.32

$1.31

Dividends paid per share (in dollars per share)

$1.00

$0.64

Total dividends paid

$43,006,000

$42,273,000

$26,732,000

Retained earnings year-end balance

67,554,000

47,115,000

67,554,000

47,115,000

33,700,000

Expected dividend payable per share after suspension period (in dollars per share)

$0.25

Period of suspension of dividend

'6 months

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

PREFERRED_AND_PREFERENCE_STOCK1

PREFERRED AND PREFERENCE STOCK (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Preferred stock	'	'
Preferred stock authorized (in shares)	2,500,000	'
Preferred stock issued (in shares)	0	0
Preferred stock outstanding (in shares)	0	0
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 $)

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 13, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Apr. 02, 2012

Jun. 30, 2012

Apr. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Oct. 30, 2012

Dec. 31, 2013

Oct. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Oct. 30, 2012

Apr. 02, 2012

Apr. 30, 2012

Dec. 31, 2013

Apr. 02, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

item

First mortgage bonds

7.20% Series due 2016

5.875% Series due 2037

6.375% Series due 2018

4.65% Series due 2020

5.20% Series due 2040

3.58% Series Due 2027

3.73% Series due 2033

4.32% Series due 2043

6.82% Series due 2036

4.50% Series due June 15 2013

7.0% Series due 2024

5.2% Pollution Control Series due 2013

5.3% Pollution Control Series due 2013

Senior Notes, 4.50% Series due 2013

Senior Notes, 6.70% Series due 2033

Senior Notes, 5.80% Series due 2035

Other

New first mortgage bonds

EDE

EDG

EDE

EDG

EDE

Minimum

Maximum

LONG-TERM DEBT

Interest rate, stated percentage

7.20%

5.88%

6.38%

4.65%

5.20%

3.58%

3.73%

4.32%

6.82%

5.20%

5.30%

4.50%

6.70%

5.80%

Less unamortized net discount

($739,000)

($815,000)

Total long-term debt, current and non current

743,702,000

692,340,000

Total long-term debt, current and non current

744,441,000

638,000,000

488,000,000

25,000,000

80,000,000

90,000,000

100,000,000

50,000,000

88,000,000

30,000,000

120,000,000

55,000,000

98,000,000

62,000,000

40,000,000

4,441,000

5,155,000

Current obligations of long term debt

-415,000

Current obligations under capital lease

-274,000

-299,000

Percentage of principal amount at which the entity may redeem all the notes

100.00%

Total long-term debt

743,428,000

691,626,000

Debt to be redeemed

98,000,000

Aggregate principal amount of debt entered into in private placement

88,000,000

30,000,000

120,000,000

Principal amount of first mortgage bonds issued

38,000,000

50,000,000

Debt redeemed

74,800,000

5,200,000

8,000,000

Shelf registration statement, amount

200,000,000

Effective period to use proceeds under shelf to fund capital expenditures, refinancings of existing debt or general corporate needs

'3 years

Number of states in the entity's electric service territory

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

Maximum principal amount outstanding at any one time

1,000,000,000

300,000,000

Net earnings to annual interest requirement ratio

Debt permitted to be issued on compliance of interest coverage ratio covenant

599,100,000

15,800,000

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%

75.00%

Debt permitted to be issued on compliance of amount of retired bonds and percentage of net property additions covenant

856,700,000

Debt permitted to be issued based on the limit on the principal amount and current level of outstanding bonds

$417,000,000

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

LONGTERM_DEBT_Details_2

LONG-TERM DEBT (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Long-Term Debt Payout Schedule	'	'
2014	$274	'
2015	292	'
2016	25,308	'
2017	325	'
2018	90,347	'
Thereafter	627,895	'
Total long-term debt obligations	744,441	'
Less current obligations and unamortized discount	1,013	'
Total long-term debt	743,428	691,626
Regulated Entity Debt Obligations	'	'
Long-Term Debt Payout Schedule	'	'
2016	25,000	'
2018	90,000	'
Thereafter	625,000	'
Total long-term debt obligations	740,000	'
Capital Lease Obligations	'	'
Long-Term Debt Payout Schedule	'	'
2014	274	'
2015	292	'
2016	308	'
2017	325	'
2018	347	'
Thereafter	2,895	'
Total long-term debt obligations	$4,441	'

SHORTTERM_BORROWINGS_Details

SHORT-TERM BORROWINGS (Details) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2013

Jan. 26, 2010

Dec. 31, 2013

Commercial paper

Unsecured revolving credit facility

Swingline loan

item

Federal fund effective rate

One month LIBOR

One month, two month or three month LIBOR

Short-Term Borrowings

Short-term borrowings

$4,000,000

$24,000,000

$4,000,000

Average borrowings outstanding

8,700,000

17,800,000

Highest month-end balances

29,000,000

55,700,000

Weighted average interest rate during period (as a percent)

0.69%

1.05%

Weighted average interest rate at year end (as a percent)

0.33%

0.91%

Unsecured revolving credit facility

150,000,000

15,000,000

Description of interest rate basis

'Federal funds effective rate

'one month LIBOR

'one month, two month or three month LIBOR

Margin over the base rate (as a percent)

0.50%

1.00%

1.25%

Facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings (as a percent)

0.20%

Debt issuance costs

1,879,000

1,074,000

262,500

Maximum percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement

0.625

Minimum interest coverage ratio based on EBITDA under the financial covenants of the credit facility agreement

Number of trailing fiscal quarters used for calculating the interest coverage ratio based on EBITDA under the financial covenants of the credit facility agreement

Total indebtedness as a percentage of total capitalization

49.80%

EBITDA coverage ratio over interest charges

5.3

Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.

10,000,000

Outstanding borrowings

Amount of credit facility used to back up outstanding commercial paper borrowings

$4,000,000

RETIREMENT_BENEFITS_Details

RETIREMENT BENEFITS (Details) (USD $)	12 Months Ended
RETIREMENT BENEFITS (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
RETIREMENT BENEFITS	'	'	'
Number of non-callable corporate bonds	500	'	'
Amounts recognized in the balance sheet	'	'	'
Accounts payable and accrued liabilities	$71,375,000	$66,559,000	'
Pension and other postretirement benefit obligations	51,405,000	120,808,000	'
Minimum	'	'	'
Retirement benefits	'	'	'
Maturity of non-callable corporate bonds	'0 years	'	'
Maximum	'	'	'
Retirement benefits	'	'	'
Maturity of non-callable corporate bonds	'30 years	'	'
Pension	'	'	'
Retirement benefits	'	'	'
Increase (decrease) in net liability	-49,200,000	'	'
Estimated contribution in next fiscal year	12,000,000	'	'
Reconciliation of Projected Benefit Obligations:	'	'	'
Benefit obligation at beginning of year	248,004,000	215,088,000	'
Service cost	7,454,000	6,261,000	5,596,000
Interest cost	10,063,000	10,258,000	10,405,000
Net actuarial (gain)/loss	-23,300,000	25,882,000	'
Benefits and expenses paid	-17,090,000	-9,485,000	'
Benefit obligation at end of year	225,131,000	248,004,000	215,088,000
Reconciliation of Fair Value of Plan Assets:	'	'	'
Fair value of plan assets at beginning of year	160,175,000	140,975,000	'
Actual return on plan assets gain/(loss)	27,260,000	17,562,000	'
Employer contribution	16,202,000	11,123,000	'
Benefits paid	-17,090,000	-9,485,000	'
Fair value of plan assets at end of year	186,547,000	160,175,000	140,975,000
Reconciliation of Funded Status:	'	'	'
Fair value of plan assets	186,547,000	160,175,000	140,975,000
Projected benefit obligations	-225,131,000	-248,004,000	-215,088,000
Funded status	-38,584,000	-87,829,000	'
Employee pension plan accumulated benefit obligation	'	'	'
Accumulated benefit obligation	201,258,000	219,659,000	'
Amounts recognized in the balance sheet	'	'	'
Pension and other postretirement benefit obligations	38,584,000	87,829,000	'
Net Periodic Pension Benefit Cost:	'	'	'
Service cost	7,454,000	6,261,000	5,596,000
Interest cost	10,063,000	10,258,000	10,405,000
Expected return on plan assets	-12,428,000	-12,309,000	-11,139,000
Amortization of prior service cost	532,000	531,000	532,000
Amortization of net actuarial loss	10,445,000	7,935,000	5,494,000
Net periodic benefit cost	16,066,000	12,676,000	10,888,000
Activity in the regulatory asset accounts	'	'	'
Beginning Balance	105,818,000	93,656,000	'
Current Year Actuarial (Gain)/Loss	-38,132,000	20,628,000	'
Amortization of Actuarial Loss	-10,445,000	-7,935,000	'
Amortization of Prior Service (Cost)/Credit	-532,000	-531,000	'
Ending Balance	56,709,000	105,818,000	93,656,000
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	55,261,000	'	'
Prior service cost (benefit)	1,448,000	'	'
Total	56,709,000	105,818,000	93,656,000
Amounts expected to be recognized in the subsequent year	'	'	'
Net actuarial loss	6,595,000	'	'
Prior service cost (benefit)	418,000	'	'
Total	7,013,000	'	'
Weighted-average assumptions used to determine the benefit obligation	'	'	'
Discount rate (as a percent)	4.90%	4.00%	'
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)	4.00%	4.70%	5.50%
Expected return on plan assets (as a percent)	7.75%	7.90%	8.00%
Rate of compensation increase (as a percent)	3.50%	3.50%	4.50%
Pension \| Payments from Trust	'	'	'
Expected benefit payments	'	'	'
2014	19,600,000	'	'
2015	20,500,000	'	'
2016	19,800,000	'	'
2017	20,700,000	'	'
2018	19,800,000	'	'
2019 - 2023	92,400,000	'	'
Pension \| Payments from Company Funds	'	'	'
Expected benefit payments	'	'	'
2014	400,000	'	'
2015	400,000	'	'
2016	400,000	'	'
2017	500,000	'	'
2018	400,000	'	'
2019 - 2023	2,500,000	'	'
SERP	'	'	'
Reconciliation of Projected Benefit Obligations:	'	'	'
Benefit obligation at beginning of year	6,365,000	4,863,000	'
Service cost	135,000	51,000	93,000
Interest cost	315,000	263,000	183,000
Net actuarial (gain)/loss	604,000	1,511,000	'
Benefits and expenses paid	-311,000	-323,000	'
Benefit obligation at end of year	7,108,000	6,365,000	4,863,000
Reconciliation of Funded Status:	'	'	'
Projected benefit obligations	-7,108,000	-6,365,000	-4,863,000
Funded status	-7,108,000	-6,365,000	'
Employee pension plan accumulated benefit obligation	'	'	'
Accumulated benefit obligation	5,702,000	6,014,000	'
Amounts recognized in the balance sheet	'	'	'
Accounts payable and accrued liabilities	372,000	313,000	'
Pension and other postretirement benefit obligations	6,736,000	6,052,000	'
Net Periodic Pension Benefit Cost:	'	'	'
Service cost	135,000	51,000	93,000
Interest cost	315,000	263,000	183,000
Amortization of prior service cost	-8,000	-8,000	-8,000
Amortization of net actuarial loss	567,000	389,000	171,000
Net periodic benefit cost	1,009,000	695,000	439,000
Activity in the regulatory asset accounts	'	'	'
Beginning Balance	4,143,000	3,012,000	'
Current Year Actuarial (Gain)/Loss	604,000	1,512,000	'
Amortization of Actuarial Loss	-567,000	-389,000	'
Amortization of Prior Service (Cost)/Credit	8,000	8,000	'
Ending Balance	4,188,000	4,143,000	3,012,000
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	4,210,000	'	'
Prior service cost (benefit)	-22,000	'	'
Total	4,188,000	4,143,000	3,012,000
Amounts expected to be recognized in the subsequent year	'	'	'
Net actuarial loss	421,000	'	'
Prior service cost (benefit)	-8,000	'	'
Total	413,000	'	'
OPEB	'	'	'
Retirement benefits	'	'	'
Increase (decrease) in net liability	-20,800,000	'	'
Estimated contribution in next fiscal year	3,000,000	'	'
Estimated benefit payments	'	'	'
Eligible age	'55 years	'	'
Minimum service period for eligibility	'5 years	'	'
Reconciliation of Projected Benefit Obligations:	'	'	'
Benefit obligation at beginning of year	94,738,000	83,226,000	'
Service cost	2,941,000	2,401,000	2,266,000
Interest cost	3,827,000	4,037,000	4,383,000
Net actuarial (gain)/loss	-12,767,000	6,955,000	'
Plan participant's contribution	949,000	910,000	'
Benefits and expenses paid	-4,396,000	-3,156,000	'
Federal subsidy	40,000	365,000	'
Benefit obligation at end of year	85,332,000	94,738,000	83,226,000
Reconciliation of Fair Value of Plan Assets:	'	'	'
Fair value of plan assets at beginning of year	67,667,000	58,384,000	'
Actual return on plan assets gain/(loss)	10,361,000	7,148,000	'
Employer contribution	4,360,000	3,970,000	'
Benefits paid	-4,229,000	-3,045,000	'
Plan participant's contribution	901,000	864,000	'
Federal subsidy	38,000	346,000	'
Fair value of plan assets at end of year	79,098,000	67,667,000	58,384,000
Reconciliation of Funded Status:	'	'	'
Fair value of plan assets	79,098,000	67,667,000	58,384,000
Projected benefit obligations	-85,332,000	-94,738,000	-83,226,000
Funded status	-6,234,000	-27,071,000	'
Amounts recognized in the balance sheet	'	'	'
Accounts payable and accrued liabilities	147,000	144,000	'
Pension and other postretirement benefit obligations	6,087,000	26,927,000	'
Net Periodic Pension Benefit Cost:	'	'	'
Service cost	2,941,000	2,401,000	2,266,000
Interest cost	3,827,000	4,037,000	4,383,000
Expected return on plan assets	-4,353,000	-4,135,000	-4,157,000
Amortization of prior service cost	-1,011,000	-1,011,000	-1,011,000
Amortization of net actuarial loss	2,261,000	1,661,000	1,762,000
Net periodic benefit cost	3,665,000	2,953,000	3,243,000
Activity in the regulatory asset accounts	'	'	'
Beginning Balance	20,311,000	17,020,000	'
Current Year Actuarial (Gain)/Loss	-18,776,000	3,941,000	'
Amortization of Actuarial Loss	-2,261,000	-1,661,000	'
Amortization of Prior Service (Cost)/Credit	1,011,000	1,011,000	'
Ending Balance	285,000	20,311,000	17,020,000
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	3,879,000	'	'
Prior service cost (benefit)	-3,594,000	'	'
Total	285,000	20,311,000	17,020,000
Amounts expected to be recognized in the subsequent year	'	'	'
Net actuarial loss	914,000	'	'
Prior service cost (benefit)	-1,011,000	'	'
Total	-97,000	'	'
Weighted-average assumptions used to determine the benefit obligation	'	'	'
Discount rate (as a percent)	5.00%	4.11%	'
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)	4.11%	4.90%	5.50%
Expected return on plan assets (as a percent)	6.52%	6.65%	7.00%
Rate of compensation increase (as a percent)	3.50%	3.50%	4.50%
Cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation	'	'	'
Cost trend rate assumed (as a percent)	7.50%	'	'
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	1,450,000	'	'
Effect of 1% decrease on total of service and interest cost	-1,115,000	'	'
Effect of 1% increase on post-retirement benefit obligation	14,027,000	'	'
Effect of 1% decrease on post-retirement benefit obligation	-11,179,000	'	'
OPEB \| Payments from Trust	'	'	'
Expected benefit payments	'	'	'
2014	2,500,000	'	'
2015	2,900,000	'	'
2016	3,200,000	'	'
2017	3,500,000	'	'
2018	3,800,000	'	'
2019 - 2023	23,200,000	'	'
OPEB \| Expected Federal Subsidy	'	'	'
Estimated benefit payments	'	'	'
2014	300,000	'	'
2015	300,000	'	'
2016	400,000	'	'
2017	400,000	'	'
2018	500,000	'	'
2019 - 2023	3,200,000	'	'
OPEB \| Payments from Company Funds	'	'	'
Expected benefit payments	'	'	'
2014	100,000	'	'
2015	200,000	'	'
2016	200,000	'	'
2017	200,000	'	'
2018	200,000	'	'
2019 - 2023	$900,000	'	'

RETIREMENT_BENEFITS_Details_2

RETIREMENT BENEFITS (Details 2) (USD $)

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Pension

OPEB

count

Return seeking assets

Long duration bonds

Common collective trust

Short term investments

U.S. equity

International equity

Equity long/short hedge funds

Common collective trust

U.S. government debt

U.S. corporate debt

Fair Value, Inputs, Level 1 [Member]

Significant Other Observable Inputs (Level 2)

Significant Unobservable Inputs (Level 3)

Debt securities

Equity securities

Fund assets

U.S. equity

International equity

Cash and cash equivalents

Mutual funds - fixed income

Mutual funds - equity

U.S. government debt

U.S. corporate debt

Foreign debt

Accrued interest & dividends

Fair Value, Inputs, Level 1 [Member]

Significant Other Observable Inputs (Level 2)

Short term investments

U.S. equity

International equity

U.S. government debt

Common collective trust

Short term investments

Common collective trust

U.S. corporate debt

Equity long/short hedge funds

Fund assets

U.S. equity

International equity

Cash and cash equivalents

Mutual funds - fixed income

Mutual funds - equity

U.S. government debt

Fund assets

U.S. corporate debt

Foreign debt

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)

Target allocations for plan assets

Target allocation, minimum (as a percent)

40.00%

0.00%

Target allocation, maximum (as a percent)

70.00%

30.00%

60.00%

10.00%

Fund assets measured at fair value

Fair value of plan assets

$186,547

$140,975

$104,713

$74

$2,398

$63,655

$22,074

$36,729

$28,885

$45,031

$26,110

$1,535

$15,518

$74

$87,264

$74

$63,655

$22,074

$1,535

$149,744

$44,026

$104,713

$2,398

$45,031

$26,110

$15,518

$36,729

$28,885

$36,729

$28,885

$79,098

$67,667

$58,384

$78,833

$67,386

$27,779

$20,795

$9,316

$1,548

$1,317

$8,325

$3,914

$11,633

$17,818

$729

$17,592

$19,437

$2,871

$2,250

$265

$281

$58,370

$45,699

$27,779

$20,795

$9,316

$1,548

$1,317

$895

$8,325

$3,914

$11,633

$17,818

$729

$20,463

$21,687

$17,592

$19,437

$2,871

$2,250

Percentage of Plan Assets

100.00%

24.10%

0.10%

1.50%

39.70%

13.80%

19.70%

18.00%

24.10%

16.30%

1.00%

9.70%

100.00%

35.10%

30.70%

11.80%

2.30%

1.70%

1.30%

10.50%

5.80%

14.70%

26.30%

1.10%

22.20%

28.70%

3.60%

3.30%

0.40%

0.50%

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

Fair value of plan assets at beginning of year

160,175

140,975

104,713

2,398

63,655

22,074

36,729

28,885

45,031

26,110

1,535

15,518

87,264

63,655

22,074

1,535

149,744

44,026

104,713

2,398

45,031

26,110

15,518

36,729

28,885

27,419

79,098

67,667

58,384

78,833

67,386

27,779

20,795

9,316

1,548

895

8,325

3,914

11,633

17,818

729

17,592

19,437

2,871

2,250

265

281

58,370

45,699

27,779

20,795

9,316

1,548

1,317

895

8,325

3,914

11,633

17,818

729

20,463

21,687

17,592

19,437

2,871

2,250

Actual return on plan assets:

Relating to assets still held at the reporting date

-356

1,466

Relating to assets sold during the period

4,583

Purchases

26,500

Sales

-22,883

Fair value of plan assets at end of year

$186,547

$140,975

$104,713

$74

$2,398

$63,655

$22,074

$36,729

$28,885

$45,031

$26,110

$1,535

$15,518

$74

$87,264

$74

$63,655

$22,074

$1,535

$149,744

$44,026

$104,713

$2,398

$45,031

$26,110

$15,518

$36,729

$28,885

$36,729

$28,885

$79,098

$67,667

$58,384

$78,833

$67,386

$27,779

$20,795

$9,316

$1,548

$1,317

$8,325

$3,914

$11,633

$17,818

$729

$17,592

$19,437

$2,871

$2,250

$265

$281

$58,370

$45,699

$27,779

$20,795

$9,316

$1,548

$1,317

$895

$8,325

$3,914

$11,633

$17,818

$729

$20,463

$21,687

$17,592

$19,437

$2,871

$2,250

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	12 Months Ended
INCOME TAXES (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current income taxes:	'	'	'
Federal	$6,726,000	$1,552,000	($8,604,000)
State	2,495,000	708,000	-2,120,000
TOTAL	9,221,000	2,260,000	-10,724,000
Deferred income taxes:	'	'	'
Federal	24,954,000	28,210,000	39,096,000
State	3,554,000	4,018,000	6,297,000
TOTAL	28,508,000	32,228,000	45,393,000
Investment tax credit amortization	-237,000	-329,000	-371,000
TOTAL INCOME TAX EXPENSE	37,492,000	34,159,000	34,298,000
Deferred tax assets and liabilities as reflected on consolidated balance sheet	'	'	'
Current deferred tax assets, net	7,222,000	13,000,000	'
Non-current deferred tax liabilities, net	324,266,000	301,967,000	'
NET DEFERRED TAX LIABILITIES	317,044,000	288,967,000	'
Deferred tax assets:	'	'	'
Net operating loss	'	13,000,000	'
Disallowed plant costs	1,841,000	1,010,000	'
Gains on hedging transactions	1,324,000	1,389,000	'
Plant related basis differences	23,344,000	21,571,000	'
Regulated liabilities related to income taxes	13,576,000	13,871,000	'
Pensions and other post-retirement benefits	544,000	693,000	'
Carry forward of income tax credit	6,374,000	3,722,000	'
Other	1,633,000	2,262,000	'
Total deferred tax assets	48,636,000	57,518,000	'
Deferred tax liabilities:	'	'	'
Depreciation, amortization and other plant related differences	297,175,000	279,604,000	'
Regulated assets related to income	37,806,000	39,553,000	'
Loss on reacquired debt	4,085,000	4,489,000	'
Amortization of intangibles	8,089,000	7,009,000	'
Deferred construction accounting costs	6,977,000	7,323,000	'
Other	11,548,000	8,507,000	'
Total deferred tax liabilities	365,680,000	346,485,000	'
NET DEFERRED TAX LIABILITIES	317,044,000	288,967,000	'
Effective Income Tax Rates	'	'	'
Federal statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
Increase (decrease) in income tax rate resulting from:	'	'	'
State income tax (net of federal benefit) (as a percent)	3.10%	3.10%	3.10%
Investment tax credit amortization (as a percent)	-0.20%	-0.40%	-0.40%
Effect of ratemaking on property related differences (as a percent)	-1.10%	-0.20%	0.20%
Other (as a percent)	0.30%	0.50%	0.50%
EFFECTIVE INCOME TAX RATE (as a percent)	37.10%	38.00%	38.40%
Unrecognized Tax Benefits	'	'	'
Unrecognized tax benefits, opening balance	0	0	359,000
Reductions to unrecognized tax benefits as a result of a lapse of the applicable statute of limitations	'	'	-359,000
UNRECOGNIZED TAX BENEFITS, closing balance	0	0	0
Advanced coal investment tax credit	17,700,000	'	'
Maximum tax credit utilized	700,000	'	'
Investment tax credit expected to be utilized	$10,700,000	'	'

COMMONLY_OWNED_FACILITIES_Deta

COMMONLY OWNED FACILITIES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
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	$367.10	$364.10
Accumulated Depreciation	91.1	83.2
Expenditures	31.6	30
Iatan1 \| KCP&L	'	'
Commonly Owned Facilities	'	'
Proportionate ownership interest (as a percent)	70.00%	'
Iatan1 \| KCP&L Greater Missouri Operations Co.	'	'
Commonly Owned Facilities	'	'
Proportionate ownership interest (as a percent)	18.00%	'
Iatan2 \| KCP&L	'	'
Commonly Owned Facilities	'	'
Proportionate ownership interest (as a percent)	54.00%	'
Iatan2 \| KCP&L Greater Missouri Operations Co.	'	'
Commonly Owned Facilities	'	'
Proportionate ownership interest (as a percent)	18.00%	'
State Line Combined Cycle Unit	'	'
Amounts included in property, plant and equipment	'	'
Cost of ownership in plant in service	163.3	164.4
Accumulated Depreciation	37	36.7
Expenditures	52.6	42.7
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	108.2	108
Accumulated Depreciation	7.3	4.9
Expenditures	$11.30	$7.80
Plum point \| EDE	'	'
Commonly Owned Facilities	'	'
Proportionate ownership interest (as a percent)	7.52%	'

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES (Details) (USD $)

Dec. 31, 2013

Dec. 15, 2008

Dec. 31, 2013

Dec. 15, 2005

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Electric

Southern Star Central Pipeline, Inc.

Firm Physical gas and transportation contracts

Coal and coal transportation contracts

Purchased power

Leases

Power Plant Mercury And Air Toxics Rule

Compliance Plan

Minimum

Maximum

Electric

Plum Point Energy Station

Cloud County Windfarm

Elk River Windfarm

Electric

Gas

Plum Point Energy Station

Power Plant Mercury And Air Toxics Rule

Dth

Minimum

Maximum

Minimum

Maximum

train

office

railcar

Commitments and Contingencies

January 1, 2014 through December 31, 2014

$24,900,000

$23,800,000

January 1, 2015 through December 31, 2016

31,400,000

28,800,000

January 1, 2017 through December 31, 2018

30,200,000

22,600,000

January 1, 2019 and beyond

45,900,000

11,300,000

Term of long-term contract agreement

'5 years

'30 years

'20 years

Agreement to purchase firm gas storage capacity (in Dths)

1,000,000

Amount of annual storage capacity reservation

1,100,000

Energy capacity (in megawatts)

670

105

150

Amount of energy capacity owned (in megawatts)

Amount of energy capacity under option to purchase (in megawatts)

Amount of long-term contract obligation

297,200,000

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

Amount of annual payments contingent upon output of the facility

14,600,000

16,900,000

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

'20 years

Number of unit trains under short-term operating leases

Number of office facilities under short-term operating leases

Number of railcars under capital leases

108

Gross amount of assets recorded under capital leases

5,500,000

Capital leases, 2014

553,000

Capital leases, 2015

553,000

Capital leases, 2016

549,000

Capital leases, 2017

547,000

Capital leases, 2018

546,000

Capital leases, thereafter

3,553,000

Capital leases, total minimum payments

6,301,000

Capital leases, amount representing interest

1,860,000

Capital leases, present value of net minimum lease payments

4,441,000

Operating leases, 2014

764,000

Operating leases, 2015

722,000

Operating leases, 2016

720,000

Operating leases, 2017

681,000

Operating leases, 2018

646,000

Operating leases, thereafter

485,000

Operating leases, total minimum payments

4,018,000

Expenses incurred related to operating leases

800,000

900,000

1,000,000

Accumulated amount of amortization of capital leases

1,300,000

1,000,000

Estimated project cost

165,000,000

175,000,000

Term of Capital Expenditure Plan

'5 years

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

13,000,000

Project to date costs related to pre-engineering and site preparation activities

$13,600,000

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details 2) (Electric, USD $)

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Apr. 16, 2012

Dec. 31, 2013

Jan. 15, 2013

Dec. 31, 2013

Nov. 30, 2010

Dec. 31, 2013

Clean Air Interstate Rule

NAAQS

Power Plant Mercury And Air Toxics Rule

Surface Impoundments

Renewable Energy

Compliance Plan

item

Minimum

Maximum

option

Maximum

Iatan

Plum point

item

state

Environmental Laws And Regulations

Expected cost of adding Carbon injection system

$112

$130

Construction costs project to date

83.6

Minimum capacity of power plant called to reduce emission levels of SO2 and NOx (in megawatts)

Number of states in which fossil-fueled power plants are required to reduce emission levels of SO2 and NOx as per CAIR

Phase-in period for proposed standards

'3 years

Period for compliance

'4 years

Particulate matter primary annual standard (in micrograms per cubic meter of air)

Percentage of ownership in a coal ash impoundment at a generating facility

12.00%

7.52%

Number of options in the EPA proposal

Potential cost for construction of new landfill and conversion of existing ash handling from wet to dry system(s)

$15

Minimum percentage of Missouri retail sales required to generate or purchase electricity in 2014

0.05

Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2021

15.00%

Percentage of Missouri retail sales required to generate or purchase solar energy

2.00%

Number of orders granted motions to dismiss all counts of the complaint

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%

SEGMENT_INFORMATION_Details

SEGMENT INFORMATION (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
									town
									segment
SEGMENT INFORMATION	'	'	'	'	'	'	'	'	'	'	'
Number of business segments	'	'	'	'	'	'	'	'	3	'	'
Number of towns to which water service is provided	'	'	'	'	'	'	'	'	3	'	'
Statement of Income Information, balance sheet information and capital expenditures of business segments	'	'	'	'	'	'	'	'	'	'	'
Revenues	$149,058	$157,486	$136,646	$151,140	$129,119	$159,202	$131,632	$137,144	$594,330	$557,097	$576,870
Depreciation and amortization	'	'	'	'	'	'	'	'	69,306	60,447	63,537
Federal and state income taxes	'	'	'	'	'	'	'	'	37,492	34,159	34,298
Operating income	23,799	32,896	21,110	21,858	19,367	35,282	20,762	20,810	99,663	96,221	96,934
Interest income	'	'	'	'	'	'	'	'	566	972	555
Interest expense	'	'	'	'	'	'	'	'	41,479	41,467	41,520
Income from AFUDC (debt and equity)	'	'	'	'	'	'	'	'	5,940	1,928	512
Income from continuing operations	'	'	'	'	'	'	'	'	63,445	55,681	54,971
Capital Expenditures	'	'	'	'	'	'	'	'	160,208	146,287	101,177
Total assets	2,145,045	'	'	'	2,126,369	'	'	'	2,145,045	2,126,369	'
Goodwill	39,492	'	'	'	39,492	'	'	'	39,492	39,492	'
Electric	'	'	'	'	'	'	'	'	'	'	'
Statement of Income Information, balance sheet information and capital expenditures of business segments	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	536,413	510,653	524,276
Depreciation and amortization	'	'	'	'	'	'	'	'	63,659	55,312	58,236
Federal and state income taxes	'	'	'	'	'	'	'	'	34,478	32,266	31,643
Operating income	'	'	'	'	'	'	'	'	90,984	89,445	88,590
Interest income	'	'	'	'	'	'	'	'	537	946	554
Interest expense	'	'	'	'	'	'	'	'	37,683	37,866	37,860
Income from AFUDC (debt and equity)	'	'	'	'	'	'	'	'	5,910	1,918	509
Income from continuing operations	'	'	'	'	'	'	'	'	58,603	52,631	50,670
Capital Expenditures	'	'	'	'	'	'	'	'	153,401	140,117	93,499
Total assets	2,034,234	'	'	'	2,034,399	'	'	'	2,034,234	2,034,399	'
Gas	'	'	'	'	'	'	'	'	'	'	'
Statement of Income Information, balance sheet information and capital expenditures of business segments	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	50,041	39,849	46,430
Depreciation and amortization	'	'	'	'	'	'	'	'	3,709	3,598	3,494
Federal and state income taxes	'	'	'	'	'	'	'	'	1,484	789	1,676
Operating income	'	'	'	'	'	'	'	'	6,194	5,005	6,514
Interest income	'	'	'	'	'	'	'	'	115	323	259
Interest expense	'	'	'	'	'	'	'	'	3,890	3,905	3,910
Income from AFUDC (debt and equity)	'	'	'	'	'	'	'	'	30	10	3
Income from continuing operations	'	'	'	'	'	'	'	'	2,355	1,256	2,709
Capital Expenditures	'	'	'	'	'	'	'	'	4,419	3,571	4,122
Total assets	123,736	'	'	'	148,814	'	'	'	123,736	148,814	'
Goodwill	39,492	'	'	'	39,492	'	'	'	39,492	39,492	'
Other	'	'	'	'	'	'	'	'	'	'	'
Statement of Income Information, balance sheet information and capital expenditures of business segments	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	9,147	7,187	6,756
Depreciation and amortization	'	'	'	'	'	'	'	'	1,938	1,537	1,807
Federal and state income taxes	'	'	'	'	'	'	'	'	1,530	1,104	979
Operating income	'	'	'	'	'	'	'	'	2,485	1,771	1,830
Interest income	'	'	'	'	'	'	'	'	8	7	'
Interest expense	'	'	'	'	'	'	'	'	'	'	8
Income from continuing operations	'	'	'	'	'	'	'	'	2,487	1,794	1,592
Capital Expenditures	'	'	'	'	'	'	'	'	2,388	2,599	3,556
Total assets	31,306	'	'	'	28,871	'	'	'	31,306	28,871	'
Eliminations	'	'	'	'	'	'	'	'	'	'	'
Statement of Income Information, balance sheet information and capital expenditures of business segments	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	-1,271	-592	-592
Interest income	'	'	'	'	'	'	'	'	-94	-304	-258
Interest expense	'	'	'	'	'	'	'	'	-94	-304	-258
Total assets	($44,231)	'	'	'	($85,715)	'	'	'	($44,231)	($85,715)	'

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, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
SELECTED QUARTERLY INFORMATION (UNAUDITED)	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	$149,058	$157,486	$136,646	$151,140	$129,119	$159,202	$131,632	$137,144	$594,330	$557,097	$576,870
Operating income	23,799	32,896	21,110	21,858	19,367	35,282	20,762	20,810	99,663	96,221	96,934
Net income	$15,162	$23,996	$11,658	$12,630	$9,627	$25,542	$10,708	$9,804	$63,445	$55,681	$54,971
Basic and Diluted Earnings Per Share (in dollars per share)	$0.35	$0.56	$0.27	$0.30	$0.23	$0.60	$0.25	$0.23	$1.48	$1.32	$1.31

RISK_MANAGEMENT_AND_DERIVATIVE2

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair value of derivative financial instruments	'	'
Current assets	$2,469	$96
Total derivatives assets	2,510	287
Current liabilities	1,889	3,403
Non-current liabilities and deferred credits	2,799	3,819
Total derivatives liabilities	4,688	7,222
Non-designated as hedging instruments due to regulatory accounting \| Commodity contracts \| Gas	'	'
Fair value of derivative financial instruments	'	'
Current assets	35	3
Non-current assets and deferred charges- other	'	17
Current liabilities	8	104
Non-designated as hedging instruments due to regulatory accounting \| Commodity contracts \| Electric	'	'
Fair value of derivative financial instruments	'	'
Current assets	467	93
Non-current assets and deferred charges- other	41	174
Current liabilities	1,881	3,299
Non-current liabilities and deferred credits	2,799	3,819
Non-designated as hedging instruments due to regulatory accounting \| Transmission congestion rights (TCR) \| Electric	'	'
Fair value of derivative financial instruments	'	'
Current assets	$1,967	'

RISK_MANAGEMENT_AND_DERIVATIVE3

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Electric	'	'
Gain / (Loss) on derivatives	'	'
Unrealized losses applicable to financial instruments which will settle in next twelve months	$1,900,000	'
Period within which financial instruments will settle	'12 months	'
Mark-to-market pre-tax gains/(losses) from ineffective portions	0	0
Amount of Gain/(Loss) Recognized on Balance Sheet	1,629,000	-2,448,000
Amount of Gain / (Loss) Recognized in Income on Derivative	-2,644,000	-3,985,000
Gas	'	'
Gain / (Loss) on derivatives	'	'
Amount of Gain/(Loss) Recognized on Balance Sheet	-5,000	-461,000
Commodity contracts \| Electric	'	'
Gain / (Loss) on derivatives	'	'
Amount of Gain/(Loss) Recognized on Balance Sheet	-338,000	-2,448,000
Amount of Gain / (Loss) Recognized in Income on Derivative	-2,725,000	-3,985,000
Commodity contracts \| Gas	'	'
Gain / (Loss) on derivatives	'	'
Amount of Gain/(Loss) Recognized on Balance Sheet	-5,000	-461,000
Transmission congestion rights (TCR) \| Electric	'	'
Gain / (Loss) on derivatives	'	'
Amount of Gain/(Loss) Recognized on Balance Sheet	1,967,000	'
Amount of Gain / (Loss) Recognized in Income on Derivative	$81,000	'

RISK_MANAGEMENT_AND_DERIVATIVE4

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013
	MWh
Transmission congestion rights (TCR) - 2014	'
Minimum Percentage Hedged for Electric Segment	'
Monthly MWH Hedged, value	1,918
Monthly MWH Hedged	$1,966,846
Electric \| Natural Gas Usage - 2014	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	61.00%
Dth Hedged Physical	1,560,000
Dth Hedged Financial	4,640,000
Average Price (in dollars per dth)	4.411
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	61.00%
Electric \| Natural Gas Usage - 2015	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	41.00%
Dth Hedged Financial	4,010,000
Average Price (in dollars per dth)	4.578
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	41.00%
Electric \| Natural Gas Usage - 2016	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	22.00%
Dth Hedged Financial	2,100,000
Average Price (in dollars per dth)	4.415
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	22.00%
Electric \| Natural Gas Usage - 2017	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	10.00%
Dth Hedged Financial	1,050,000
Average Price (in dollars per dth)	4.43
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	10.00%
Electric \| 2018	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	0.00%
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	0.00%
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%
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	60.00%
Electric \| Second Year Procurement Guidelines	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	40.00%
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	40.00%
Electric \| Third Year Procurement Guidelines	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	20.00%
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	20.00%
Electric \| Fourth Year Procurement Guidelines	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	10.00%
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	10.00%
Electric \| Maximum \| Current Year Procurement Guidelines	'
Volumes and percentage of anticipated volume of natural gas usage	'
% Hedged	100.00%
Minimum Percentage Hedged for Electric Segment	'
End of Year Minimum % Hedged	100.00%

RISK_MANAGEMENT_AND_DERIVATIVE5

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 4) (Gas)	12 Months Ended
	Dec. 31, 2013
	pipeline
	season
	Dth
Price Risk Mitigation for Gas Segment	'
Target percentage of storage capacity utilization	95.00%
Volume of storage in pipelines that serve customers (in Dth)	900,000
Number of pipelines that serve customers (in units)	3
Storage capacity utilized (as a percent)	47.00%
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	2
Current Winter Season	'
Gas Usage Hedged By Winter Season	'
End of Year Minimum % Hedged	50.00%
Dth Hedged Financial	240,000,000
Dth in Storage	948,850,000
Actual % Hedged	59.00%
Maximum \| Second Winter Season	'
Gas Usage Hedged By Winter Season	'
End of Year Minimum % Hedged	50.00%
Maximum \| 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, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Assets/(Liabilities) at Fair Value	'	'
Fair Value Measurements at Reporting Date	'	'
Derivative assets	$2,510	$287
Derivative liabilities	-4,688	-7,222
Quoted Prices in Active Markets for Identical Assets (Level 1)	'	'
Fair Value Measurements at Reporting Date	'	'
Derivative assets	543	287
Derivative liabilities	-4,688	-7,222
Significant Other Observable Inputs (Level 2)	'	'
Fair Value Measurements at Reporting Date	'	'
Derivative assets	$1,967	'

FAIR_VALUE_MEASUREMENTS_Detail1

FAIR VALUE MEASUREMENTS (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Long-Term Debt	'	'
Carrying amount of total long-term debt exclusive of capital leases	$739	$688
Fair market value	$715	$747

REGULATED_OPERATING_EXPENSE_De

REGULATED OPERATING EXPENSE (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REGULATED OPERATING EXPENSE	'	'	'
Power operation expense (other than fuel)	$15,643	$15,045	$12,685
Electric transmission and distribution expense	21,863	17,083	15,361
Natural gas transmission and distribution expense	2,498	2,443	2,385
Customer accounts and assistance expense	11,180	10,211	10,210
Employee pension expense	10,736	10,180	8,805
Employee healthcare plan	10,190	9,825	7,439
General office supplies and expense	12,850	10,776	10,158
Administrative and general expense	14,800	15,091	14,295
Bad debt expense	3,665	3,038	3,425
Regulatory reversal of gain on sale of assets	1,236	'	'
Miscellaneous expense	672	679	679
Total	$105,333	$94,371	$85,442

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Reserve deducted from assets: accumulated provision for uncollectible accounts.	'	'	'
Valuation and Qualifying Accounts	'	'	'
Balance At Beginning Of Period	$1,387,673	$1,137,644	$865,236
Charged To Income	2,213,988	3,052,397	3,737,630
Charged to Other Accounts	2,013,959	1,956,549	1,847,527
Deductions From Reserve	4,590,443	4,758,917	5,312,749
Balance At Close of Period	$1,025,177	$1,387,673	$1,137,644