Empire District Electric (EDE) 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 01, 2016	Jun. 30, 2015
Document and Entity Information
Entity Registrant Name	EMPIRE DISTRICT ELECTRIC CO
Entity Central Index Key	32,689
Document Type	10-K
Document Period End Date	Dec. 31, 2015
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			$ 952,425,061
Entity Common Stock, Shares Outstanding		43,860,337
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Plant and property, at original cost:
Electric	$ 2,473,927	$ 2,420,824
Gas	83,402	79,364
Other	44,263	41,394
Construction work in progress	183,689	112,097
Total plant and property, Gross	2,785,281	2,653,679
Accumulated depreciation and amortization	764,895	743,407
Total plant and property, Net	2,020,386	1,910,272
Current assets:
Cash and cash equivalents	1,753	2,105
Restricted cash	4,726	4,726
Accounts receivable - trade, net of allowance $623 and $1,021, respectively	40,162	45,444
Accrued unbilled revenues	20,653	25,945
Accounts receivable - other	28,320	41,256
Fuel, materials and supplies	60,950	57,799
Prepaid expenses and other	8,835	8,679
Unrealized gain in fair value of derivative contracts	1,295	3,901
Regulatory assets	7,052	10,752
Total current assets	173,746	200,607
Noncurrent assets and deferred charges:
Regulatory assets	209,708	209,717
Goodwill	39,492	39,492
Unamortized debt issuance costs	8,658	8,821
Unrealized gain in fair value of derivative contracts	16
Other	3,297	2,147
Total noncurrent assets and deferred charges	261,171	260,177
Total Assets	2,455,303	2,371,056
Capitalization and liabilities
Common stock, $1 par value, 43,820,726 and 43,479,186 shares issued and outstanding, respectively	43,821	43,479
Capital in excess of par value	657,466	649,543
Retained earnings	101,443	90,276
Total common stockholders' equity	802,730	783,298
Long-term debt (net of current portion):
Obligations under capital lease	3,580	3,875
First mortgage bonds and secured debt	732,653	697,615
Unsecured debt	101,714	101,699
Total long-term debt	837,947	803,189
Total long-term debt and common stockholders' equity	1,640,677	1,586,487
Current liabilities:
Accounts payable and accrued liabilities	66,946	83,420
Current maturities of long-term debt	25,310	292
Short-term debt	25,000	44,000
Regulatory liabilities	8,615	7,898
Customer deposits	14,623	13,747
Interest accrued	7,348	6,565
Unrealized loss in fair value of derivative contracts	4,472	6,469
Taxes accrued	2,832	3,380
Other current liabilities	323	206
Total current liabilities	$ 155,469	$ 165,977
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	$ 132,457	$ 128,471
Deferred income taxes	396,542	358,252
Unamortized investment tax credits	18,487	18,517
Pension and other postretirement benefit obligations	82,144	93,863
Unrealized loss in fair value of derivative contracts	3,696	3,243
Other	25,831	16,246
Total noncurrent liabilities	659,157	618,592
Total Capitalization and Liabilities	$ 2,455,303	$ 2,371,056

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Consolidated Balance Sheets
Accounts receivable - trade, allowance (in dollars)	$ 623	$ 1,021
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	43,820,726	43,479,186
Common stock, shares outstanding	43,820,726	43,479,186

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues:
Electric	$ 555,085	$ 592,491	$ 536,413
Gas	41,702	51,842	50,041
Other	8,786	7,997	7,876
Total operating revenues	605,573	652,330	594,330
Operating revenue deductions:
Fuel and purchased power	169,860	215,086	175,406
Cost of natural gas sold and transported	19,502	27,025	25,795
Regulated operating expenses	113,551	110,691	105,333
Other operating expenses	3,309	2,987	3,142
Maintenance and repairs	48,522	46,775	40,873
Loss on plant disallowance		86	2,409
Depreciation and amortization	80,550	73,185	69,306
Provision for income taxes	34,800	39,398	37,465
Other taxes	39,178	37,098	34,938
Total operating revenue deductions	509,272	552,331	494,667
Operating income	96,301	99,999	99,663
Other income and (deductions):
Allowance for equity funds used during construction	4,850	6,420	3,853
Interest income	145	51	566
Benefit for other income taxes	988	178	(27)
Other - non-operating expense, net	(3,429)	(1,302)	(1,218)
Total other income	2,554	5,347	3,174
Interest charges:
Long-term debt	43,802	40,637	40,354
Short-term debt	266	113	60
Allowance for borrowed funds used during construction	(2,845)	(3,497)	(2,087)
Other	1,035	990	1,065
Total interest charges	42,258	38,243	39,392
Net income	$ 56,597	$ 67,103	$ 63,445
Weighted average number of common shares outstanding - basic (in shares)	43,671	43,291	42,781
Weighted average number of common shares outstanding - diluted (in shares)	43,718	43,314	42,803
Total earnings per weighted average share of common stock - basic (in dollars per share)	$ 1.30	$ 1.55	$ 1.48
Total earnings per weighted average share of common stock - diluted (in dollars per share	1.29	1.55	1.48
Dividends declared per share of common stock (in dollars per share)	$ 1.04	$ 1.025	$ 1.005

Consolidated Statements of Comm

Consolidated Statements of Common Stockholders' Equity - USD ($) $ in Thousands	Common Stock	Capital in excess of Par	Retained earnings	Total
Balance at Dec. 31, 2012	$ 42,484	$ 628,199	$ 47,115	$ 717,798
Increase (Decrease) in Stockholders' Equity
Net income			63,445	63,445
Stock/stock units issued through:
Stock purchase and reinvestment plans	560	11,326		11,886
Dividends declared			(43,006)	(43,006)
Balance at Dec. 31, 2013	43,044	639,525	67,554	750,123
Increase (Decrease) in Stockholders' Equity
Net income			67,103	67,103
Stock/stock units issued through:
Stock purchase and reinvestment plans	435	10,018		10,453
Dividends declared			(44,381)	(44,381)
Balance at Dec. 31, 2014	43,479	649,543	90,276	783,298
Increase (Decrease) in Stockholders' Equity
Net income			56,597	56,597
Stock/stock units issued through:
Stock purchase and reinvestment plans	342	7,923		8,265
Dividends declared			(45,430)	(45,430)
Balance at Dec. 31, 2015	$ 43,821	$ 657,466	$ 101,443	$ 802,730

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income	$ 56,597	$ 67,103	$ 63,445
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	88,801	82,754	71,734
Pension and other postretirement benefit costs, net of contributions	(9,184)	1,973	(1,888)
Deferred income taxes and unamortized investment tax credit, net	36,617	41,693	28,272
Allowance for equity funds used during construction	(4,850)	(6,420)	(3,853)
Stock compensation expense	4,082	4,057	2,984
Other	(625)
Loss on plant disallowance		86	2,409
Reverse gain on sale of assets		44	1,236
Non-cash (gain)/loss on derivatives	6,994	1,245	14
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	16,514	(24,174)	(14,312)
Fuel, materials and supplies	(3,151)	(8,121)	10,891
Prepaid expenses, other current assets and deferred charges	(4,863)	(6,051)	689
Accounts payable and accrued liabilities	(8,630)	1,141	(880)
Asset retirement obligations	(73)	(1,326)	(734)
Interest, taxes accrued and customer deposits	1,111	1,411	1,386
Other liabilities and other deferred credits	5,492	(4,192)	(3,942)
Net cash provided by operating activities	184,832	151,223	157,451
Investing activities:
Capital expenditures - regulated	(183,206)	(211,429)	(152,524)
Capital expenditures and other investments - non-regulated	(2,243)	(1,998)	(2,259)
Restricted cash		(1,854)	1,485
Net cash used in investing activities	(185,449)	(215,281)	(153,298)
Financing activities:
Proceeds from first mortgage bonds, net	60,000	60,000	150,000
Long-term debt issuance costs	(818)	(651)	(1,879)
Proceeds from issuance of common stock, net of issuance costs	5,513	7,994	9,546
Redemption of senior notes			(98,000)
Net short-term debt borrowings/(repayments)	(19,000)	40,000	(20,000)
Dividends	(45,430)	(44,381)	(43,006)
Other		(274)	(714)
Net cash provided by financing activities	265	62,688	(4,053)
Net increase (decrease) in cash and cash equivalents	(352)	(1,370)	100
Cash and cash equivalents at beginning of period	2,105	3,475	3,375
Cash and cash equivalents at end of period	1,753	2,105	3,475
Supplemental cash flow information:
Interest paid	42,858	40,127	39,033
Income taxes (refunded) paid, net of refund	(17,256)	23,103	10,584
Supplementary non-cash investing activities:
Change in accrued additions to property, plant and equipment not reported above	(8,924)	$ 9,427	$ 5,420
Capital lease obligations for purchase of new equipment	$ 17

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary engaged in the distribution of natural gas in Missouri. Our other segment consists of our fiber optics business. See Note 12. Our gross operating revenues in 2015 were derived as follows: Electric segment sales* % On-system revenues % SPP IM revenues Other revenues Gas segment sales Other segment sales * Sales from our electric segment include 0.3% from the sale of water. The utility portions of our business are subject to regulation by the Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). Our accounting policies are in accordance with the ratemaking practices of the regulatory authorities and conform to generally accepted accounting principles as applied to regulated public utilities. Our electric operations serve approximately 170,000 customers as of December 31, 2015, and the 2015 electric operating revenues were derived as follows: Customer Class % of revenue Residential % Commercial Industrial Wholesale on-system Wholesale off-system Miscellaneous sources, primarily public authorities Other electric revenues Our retail electric revenues for 2015 by jurisdiction were as follows: Jurisdiction % of revenue Missouri % Kansas Oklahoma Arkansas Our gas operations serve approximately 43,200 customers as of December 31, 2015, and the 2015 gas operating revenues were derived as follows: Customer Class % of revenue Residential % Commercial Industrial Transportation Miscellaneous 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. Certain immaterial reclassifications have been made to prior year information to conform to the current year presentation. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include unbilled utility revenues, collectability of accounts receivable, depreciable lives, asset impairment and goodwill impairment evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation, and tax provisions. Actual amounts could differ from those estimates. Accounting for the Effects of Regulation In accordance with the Accounting Standard Codification (ASC) guidance for regulated operations, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the APSC and the FERC). We record a regulatory asset for all or part of an incurred cost that would otherwise be charged to expense in accordance with the ASC guidance for regulated operations which says that an asset should be recorded if it is probable that future revenue in an amount at least equal to the capitalized cost will be allowable for costs for rate making purposes and the current available evidence indicates that future revenue will be provided to permit recovery of the cost. This guidance also indicates that a liability should be recorded when a regulator has provided current recovery for a cost that is expected to be incurred in the future. We follow this guidance for incurred costs or credits that are subject to future recovery from or refund to our customers in accordance with the orders of our regulators. Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory assets and liabilities are ratably amortized through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues. We generally include amortization of regulatory assets and liabilities in the depreciation and amortization line of our statement of cash flows. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC guidance for regulated operations with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of this guidance based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations. (See Note 3 for further discussion of regulatory assets and liabilities) Revenue Recognition For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer classes. 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 $11.4 million, $11.8 million and $11.2 million were recorded for each of the years ended December 31, 2015, 2014 and 2013, respectively. Accounts Receivable Accounts receivable are recorded at the tariffed rates for customer usage, including applicable taxes and fees and do not bear interest. We review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. Property, Plant & Equipment The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material, an allocation of general and administrative costs, and an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of and the costs of removal are charged to accumulated depreciation, unless the removed property constitutes an operating unit or system. In this case a gain or loss is recognized upon the disposal of the asset. Maintenance expenditures and the removal of minor property items are charged to income as incurred. A liability is created for any additions to electric or gas utility property that are paid for by advances from developers. For a period of five years we refund to the developer a pro rata amount of the original cost of the extension for each new customer added to the extension. Nonrefundable payments at the end of the five year period are applied as a reduction to the cost of the plant in service. The liability as of December 31, 2015 and 2014 was $2.1 million and $1.9 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, 2015 and 2014, we had recorded accrued cost of removal of $85.4 million and $82.8 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, 2015 and 2014 was $8.8 million and $7.7 million, respectively. These amounts are net of our actual cost of removal expenditures. Asset Retirement Obligation We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value. We have identified asset retirement obligations associated with the future removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We also have a solid waste land fill at the Plum Point Energy Station, and asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. As a result of the fuel use transition from coal to natural gas at the Riverton Power Plant, the closure of the Riverton ash landfill was completed, and the related asset retirement obligation was settled during 2014 (Note 11). During 2015 the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs). As a result of these new rules, an asset retirement obligation of $5.4 million has been recorded for the final closure of the existing ash impoundment at our Asbury Power Plant. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station. In addition, we have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB) contaminants associated with our transformers and substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures for the removal of similar past liabilities. The potential costs of these future expenditures are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. This liability will be accreted over the period up to the estimated settlement date. All of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 4.5% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. During 2014 the liability for asbestos at the Riverton Power Plant was re-evaluated. Changes in the cost estimates and timing resulted in cash flow revisions for these liabilities. The balances at the end of 2015 and 2014 are shown below. (000's) Liability Balance 12/31/14 Liabilities Recognized Liabilities Settled Accretion Cash Flow Revisions Liability Balance at 12/31/15 Asset Retirement Obligation $ $ $ ) $ $ — $ (000's) Liability Balance 12/31/13 Liabilities Recognized Liabilities Settled Accretion Cash Flow Revisions Liability Balance at 12/31/14 Asset Retirement Obligation $ $ — $ ) $ $ $ 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, 2015 and 2014, our regulatory assets relating to asset retirement obligations totaled $7.7 million and $5.1 million, respectively. Also as noted previously under property, plant and equipment, we reclassify the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset retirement obligation under this guidance, from accumulated depreciation to a regulatory liability. This balance sheet reclassification has no impact on results of operations. Allowance for Funds Used During Construction As provided in the FERC regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction (AFUDC) when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds applicable to construction programs are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials. AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation. In accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 5.5% for 2015, 6.6% for 2014, and 7.3% for 2013, compounded semiannually. Asset Impairments (excluding goodwill) We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on undiscounted forecasted cash flows to assess the recoverability of the assets and, if necessary, the fair value is determined to measure the impairment amount. None of our assets were impaired as of December 31, 2015 and 2014. Goodwill As of December 31, 2015, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and income approaches is used to estimate the fair value of goodwill. We use the market approach which estimates fair value of the gas reporting unit by comparing certain financial metrics to comparable companies. Comparable companies whose securities are actively traded in the public market are judgmentally selected by management based on operational and economic similarities. We utilize EBITDA (earnings before interest, taxes, depreciation, and amortization) multiples of the comparable companies in relation to the EBITDA results of the gas reporting unit to determine an estimate of fair value. We also utilize a valuation technique under the income approach which estimates the discounted future cash flows of operations. Our procedures include developing a baseline test and performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering those assumptions which are subjective in nature and inherent to a discounted cash flows calculation. Other qualitative factors and comparisons to industry peers are also used to further support the assumptions and ultimately the overall evaluation. A key qualitative assumption considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for the gas reporting unit. Some of the key quantitative assumptions included in our tests involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. If negative changes occurred to one or more key assumptions, an impairment charge could result. With the exception of the capital spending rate, the key assumptions noted are significantly determined by market factors and significant changes in market factors that impact the gas reporting unit would somewhat be mitigated by our current and future regulatory rate design. Other risks and uncertainties affecting these assumptions include: changes in business, industry, laws, technology and economic conditions. Actual results for the gas reporting unit indicate a slight decline in gas customer count and demand. A continued decline in customer count or demand coupled with an increase in the discount rate would have adverse impacts on the valuation and could result in an impairment charge in the future. Our forecasts anticipate relatively flat customer counts over the next several years. We weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of October 2015 indicated the estimated fair market value of the gas reporting unit to be $18 – $22 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future. Fuel and Purchased Power Electric Segment Fuel and purchased power costs are recorded at the time the fuel is used, or the power purchased. SPP Integrated Marketplace purchased power is also included in fuel and purchased power costs. The net effects of our SPP IM activity, including SPP IM net revenue and net purchased power costs, flow through our fuel recovery mechanisms in each state. In our Missouri jurisdiction, the MPSC establishes a base cost for the recovery of fuel and purchased power expenses used to supply energy for our fuel adjustment clause (FAC). Beginning with our 2015 rate order, certain transmission costs are also included in the base cost. The FAC permits the distribution to customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, nearly the entire off-system sales margin flows back to the customer. Rates related to the fuel adjustment clause are modified twice a year subject to the review and approval by the MPSC. In accordance with the ASC guidance for regulated operations, 95% of the difference between the actual costs of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered from or refunded to our customers when the fuel adjustment clause is modified. In our Kansas jurisdiction, the costs of fuel are recovered from customers through a fuel adjustment clause, based upon estimated fuel costs and purchased power. The adjustments are subject to audit and final determination by regulators. The difference between the costs of fuel used and the cost of fuel recovered from our Kansas customers is recorded as a regulatory asset or a regulatory liability if the actual costs are higher or lower than the costs billed to customers, in accordance with the ASC guidance for regulated operations. Similar fuel recovery mechanisms are in place for our Oklahoma, Arkansas and FERC jurisdictions. At December 31, 2015 and 2014, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net over-recovered position by $5.9 million and a net under-recovered position of $3.1 million, respectively, which are reflected in our regulatory assets and liabilities. We receive the renewable attributes associated with the power purchased through our purchased power agreements with Elk River Windfarm LLC and Cloud County Windfarm, LLC. These renewable attributes are converted into renewable energy credits (REC), which are considered inventory, and recorded at zero cost (See Note 11). Revenue from the sale of RECs reduces fuel and purchased power expense. We have a Stipulation and Agreement with the MPSC granting us authority to manage our emissions allowance inventory in accordance with our Plan for Purchasing and Selling Emissions Allowances (PPSEMA). The PPSEMA allows us to purchase allowances needed for compliance, exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell allowances outright for monetary value. For compliance year 2015 we did not exchange or sell any allowances, and for compliance year 2014 we purchased 69 NOx annual allowances for compliance. 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 the following emissions allowances in inventory at December 31, 2015 and 2014: Emission Allowances in Inventory 2015 2014 Acid Rain SO2 CSAPR SO2 — CSAPR NOx (annual) — CSAPR NOx (seasonal) — Gas Segment Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery allowed in rates. A Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and related carrying costs associated with the Company's use of natural gas financial instruments to hedge the purchase price of natural gas. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year. We calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC. Elements considered part of the PGA factor include cost of gas supply, storage costs, hedging contracts, revenue and refunds, prior period adjustments and transportation costs. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and carrying costs associated with the use of financial instruments) are reflected as a regulatory asset or liability. The balance is amortized as amounts are reflected in customer billings. Derivatives We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel in our electric business or sold in our natural gas business, on the spot market and to manage certain interest rate exposure. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we purchase from the SPP Integrated Marketplace (see Note 14). Electric Segment Pursuant to the ASC guidance on accounting for derivative instruments and hedging activities, derivatives are required to be recognized on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability ("cash-flow" hedge); or (2) an instrument that is held for non-hedging purposes (a "non-hedging" instrument). We record the mark-to-market gains or losses on derivatives used to hedge our fuel and congestion costs as regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism. We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts, if they meet the definition of a derivative, are not subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions. If these transactions don't qualify for NPNS treatment, they would be marked to market for each reporting period through regulatory assets or liabilities. Gas Segment Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because we have a commission approved natural gas cost recovery mechanism (PGA), we record the mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/liability account. The regulatory asset/liability account tracks the difference between revenues billed to customers for natural gas costs and actual natural gas expense which is trued up at the end of August each year and included in the Actual Cost Adjustment (ACA) factor to be billed to customers during the next year. This is consistent with the ASC guidance on regulated operations, in that we will be recovering our costs after the annual true up period (subject to a prudency review by the MPSC). Cash flows from hedges for both electric and gas segments are classified within cash flows from operations. Pension and Other Postretirement Benefits We recognize expense related to pension and other postretirement benefits (OPEB) as earned during the employee's period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the projected benefit obligation. Our pension and OPEB expense or benefit includes amortization of previously unrecognized net gains or losses. Additional income or expense may be recognized when our unrecognized gains or losses as of the most recent measurement date exceed 10% of our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits and OPEB benefits, unrecognized net gains or losses as of the measurement date are amortized into actuarial expense over ten years. Pensions We have rate orders with Missouri, Kansas and Oklahoma that allow us to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate orders, we prospectively calculate the value of plan assets using a market-related value method as allowed by the ASC guidance on pension benefits. As a result, we are allowed to record the Missouri, Kansas and Oklahoma portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively. The MPSC has allowed us to adopt this pension cost recovery methodology for EDG as well. Other Postretirement Benefits (OPEB) We have regulatory treatment for our OPEB costs similar to the treatment described above for pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into actuarial expense over ten years and the recognition of regulatory assets and liabilities as described above. Additional guidance in the ASC on employers' accounting for defined benefit pension and other postretirement plans requires an employer to recognize the over funded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The guidance also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. Pension and other postretirement employee benefits tracking mechanisms are utilized to allow for future rate recovery of these obligations. We record these as regulatory assets on the balance sheet rather than as reductions of equity through comprehensive income (See Note 7). Unamortized Debt Discount, Premium and Expense Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices. Liability Insurance We are primarily self-insured for workers' compensation claims, general liabilities, benefits paid under employee healthcare programs and long-term disability benefits. Accruals are primarily based on the estimated undiscounted cost of claims. We self-insure up to certain limits that vary by segment and type of risk. Periodically, we evaluate the level of insurance coverage over the self-insured limits and adjust insurance levels based on risk tolerance and premium expense. We carry excess liability insurance for workers' compensation and public liability claims for our electric segment. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. Our gas segment is covered by excess liability insurance for public liability claims, and workers' compensation claims are covered by a guaranteed cost policy (See Note 11). Other Noncurrent Liabilities Other noncurrent liabilities are comprised of accruals and other accounting estimates not sufficiently large enough to merit individual disclosure. At December 31, 2015, the balance of other noncurrent liabilities is primarily comprised of accruals for self-insurance, customer advances for construction and asset retirement obligations. Cash & Cash Equivalents Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities and were $23.2 million and $28.3 million at December 31, 2015 and 2014, respectively. Restricted Cash As part of our Plum Point ownership agreement, we are required to have funds available in an escrow account which guarantees payment of certain operating costs. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts restricted, which were $1.8 million at December 31, 2015 and 2014, may increase or decrease based on an annual review. We are required to post cash collateral with Southwest Power Pool (SPP) to participate in Transmission Congest

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 Electric plant Production $ $ Transmission Distribution General (1) ​ ​ ​ ​ ​ ​ ​ ​ Electric plant Less accumulated depreciation and amortization (2) ​ ​ ​ ​ ​ ​ ​ ​ Electric plant net of depreciation and amortization Construction work in progress ​ ​ ​ ​ ​ ​ ​ ​ Net electric plant Water plant Less accumulated depreciation and amortization ​ ​ ​ ​ ​ ​ ​ ​ Water plant net of depreciation and amortization Construction work in progress ​ ​ ​ ​ ​ ​ ​ ​ Net water plant ​ ​ ​ ​ ​ ​ ​ ​ Net electric segment plant Gas plant Transmission Distribution General (3) ​ ​ ​ ​ ​ ​ ​ ​ Gas Plant Less accumulated depreciation and amortization ​ ​ ​ ​ ​ ​ ​ ​ Gas plant net of accumulated depreciation Construction work in progress ​ ​ ​ ​ ​ ​ ​ ​ Net gas plant Other Fiber Less accumulated depreciation and amortization ​ ​ ​ ​ ​ ​ ​ ​ Non-regulated net of depreciation and amortization Construction work in progress ​ ​ ​ ​ ​ ​ ​ ​ Net non-regulated property ​ ​ ​ ​ ​ ​ ​ ​ TOTAL NET PLANT AND PROPERTY $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Includes intangible property of $39.8 and $41.2 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2015 and 2014 was $15.6 and $15.7 million, respectively. (2) As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are not reflected here. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail. (3) Includes intangible property of $0.9 and $0.7 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2015 and 2014 was $0.6 million and $0.5 million, respectively. The table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended December 31 (in thousands): 2015 2014 2013 Provision for depreciation Regulated — Electric and Water (1) $ $ $ Regulated — Gas (1) Non-Regulated ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL Amortization ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) A portion of this amount is reclassified to a regulatory liability for the cost of removal. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail. 2015 2014 2013 Annual depreciation rates Electric and water % % % Gas % % % Non-Regulated % % % TOTAL COMPANY % % % The table below sets forth the average depreciation rate for each class of assets for each period presented: 2015 2014 2013 Annual Weighted Average Depreciation Rate Electric fixed assets: Production plant % % % Transmission plant % % % Distribution plant % % % General plant % % % Water % % % Gas % % % Non-regulated % % %

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2015
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, 2014 to December 31, 2015 resulted from our 2014 Missouri rate case, which was effective July 26, 2015. As a result of this case, a new tracking mechanism related to our Riverton Unit 12 Long Term Maintenance Agreement was established. The tracking mechanisms related to Iatan 2, Iatan Common and Plum Point operating and maintenance costs were discontinued. The balances accumulated through August 2014 from these tracking mechanisms are to be amortized over three years. The tracking mechanism related to vegetation management was also discontinued. Balances accumulated through August 2014 will be amortized over five years. The balances accumulated in these discontinued tracking mechanisms after August 2014 will be addressed during the next rate case. In addition to these changes, the order also included the continuation of tracking mechanisms for expenses related to employee pension and retiree health care. There were no changes to regulatory assets and liabilities with regards to their rate base inclusion or amortizable lives from December 31, 2013 to December 31, 2014. The following table sets forth the components of our regulatory assets and regulatory liabilities on our consolidated balance sheet (in thousands). December 31, 2015 2014 Regulatory Assets: Current: Under recovered fuel costs $ $ Current portion of long-term regulatory assets ​ ​ ​ ​ ​ ​ ​ ​ Regulatory assets, current ​ ​ ​ ​ ​ ​ ​ ​ Long-term: Pension and other postretirement benefits (1) Income taxes Deferred construction accounting costs (2) Unamortized loss on reacquired debt Unsettled derivative losses — electric segment System reliability — vegetation management Storm costs (3) Asset retirement obligation Customer programs Missouri solar initiative — Current portion of long-term regulatory assets ) ) Other ​ ​ ​ ​ ​ ​ ​ ​ Regulatory assets, long-term ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Liabilities Current: Over recovered fuel costs $ $ Current portion of long-term regulatory liabilities ​ ​ ​ ​ ​ ​ ​ ​ Regulatory liabilities, current ​ ​ ​ ​ ​ ​ ​ ​ Long-term: Costs of removal (4) SWPA payment for Ozark Beach lost generation Income taxes Deferred construction accounting costs — fuel (5) Unamortized gain on interest rate derivative Pension and other postretirement benefits Over recovered fuel costs System reliability — vegetation management — Current portion of long-term regulatory liabilities ) ) Other — ​ ​ ​ ​ ​ ​ ​ ​ Regulatory liabilities, long-term ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Primarily consists of unfunded pension and OPEB liability. See Note 7. (2) Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants. (3) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $2.9 million at December 31, 2015. (4) As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are reflected here. See the depreciation discussion under Note 1 and Note 2 Property, Plant and Equipment for more detail. (5) 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, 2015, the costs of all of our regulatory assets are currently being recovered except for approximately $99.0 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 4 to 25 years. The unrecovered fuel costs are generally recovered within a year following their recognition. Severe storm costs and the Asbury maintenance outage costs are recovered over five years. Pension and other postretirement benefit tracking mechanisms are recovered over a five year period. The cost of removal regulatory liability is amortized as removal costs are incurred. RATE MATTERS We routinely assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a "cost of service" basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable return on "rate base." "Rate base" is generally determined by reference to the original cost (net of accumulated depreciation and amortization) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, amortization and retirement of utility plant or write-off's as ordered by the utility commissions. In general, a request of new rates is made on the basis of a "rate base" as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag (commonly referred to as "regulatory lag") between the time we incur costs and the time when we can start recovering the costs through rates. The following table sets forth information regarding electric and water rate increases since January 1, 2013: Jurisdiction Date Requested Annual Increase Granted Percent Increase Granted Date Effective Missouri — Electric August 29, 2014 $ % July 26, 2015 Kansas — Electric December 5, 2014 $ % June 1, 2015 Arkansas — Electric February 23, 2015 $ % February 23, 2015 Kansas — Electric January 22, 2015 $ % February 23, 2015 Arkansas — Electric December 3, 2013 $ % September 26, 2014 Missouri — Electric July 6, 2012 $ % April 1, 2013 Electric Segment Missouri Rate Activity 2015 Rate Case: On October 16, 2015, we filed a request with the Missouri Public Service Commission (MPSC) for changes in rates for our Missouri electric customers. We are seeking an annual increase in total revenue of approximately $33.4 million, or approximately 7.3%. The most significant factor driving the rate request is the cost associated with the conversion of the Riverton Unit 12 natural gas combustion turbine to combined cycle operation. 2014 Rate Case: On August 29, 2014, we filed a request with the MPSC for changes in rates for our Missouri electric customers. We requested an annual increase in total revenue of approximately $24.3 million, or approximately 5.5%. The main cost drivers in the rate increase are the costs associated with our investment in Air Quality Control Facilities at our Asbury power plant (See Note 11 — New Construction of "Notes to Consolidated Financial Statements (Unaudited)") that were incurred to comply with the Environmental Protection Agency's (EPA) rules governing the continued operation of the plant, increases in property taxes, increases in ongoing maintenance expenses and increases in Regional Transmission Organization transmission fees. On June 24, 2015, the MPSC granted new rates for Missouri customers, effective on July 26, 2015. The order approved an annual increase in base revenues of about $17.1 million or 3.90%, which included a net reduction in base fuel and purchased power of $1.60 per MWh, consistent with the non-unanimous stipulation and agreement filed April 8, 2015. The order establishes a tracking mechanism for expenses related to the Riverton 12 long-term maintenance contract; continues tracking of pension and other post-employment benefit expenses; and discontinues tracking of vegetation management expenses and Iatan 2, Iatan Common and Plum Point operating and maintenance costs. In addition, the order provides for the tracking and recovery of certain future changes in total transmission expense through the Fuel Adjustment Charge, which we estimate at approximately 34% of such changes. 2015 Missouri Energy Efficiency Investment Act and Integrated Resource Plan On October 29, 2013 we filed an application with the Missouri Public Service Commission seeking approval, pursuant to the Missouri Energy Efficiency Investment Act (MEEIA), of a new Missouri demand-side management (DSM) portfolio, including four new DSM programs, and for the authority to establish a Demand Side Management Investment Mechanism (DSIM). On July 24, 2015, we filed a motion to withdraw our MEEIA filing. We will continue our current portfolio of Energy Efficiency programs, with recovery through base rates. We will review the need for a future MEEIA filing in conjunction with our 2016 Integrated Resource Plan (IRP). On July 31, 2015, we filed a notice updating our most recent IRP, with the MPSC. In the notice we indicated that Riverton Units 8 and 9 were retired on June 30, 2015. The notice also provides additional information on our MEEIA application withdrawal mentioned above. 2015 Solar Rebate Tariff On May 5, 2015, we filed a proposed solar rebate tariff with the MPSC and requested expedited treatment. On May 6, 2015, the MPSC ordered our request for expedited treatment of our tariff filing be granted and approved the tariff, effective May 16, 2015. The law provides a number of methods that may be utilized to recover the associated expenses. We expect these costs to be recoverable in rates. Kansas 2015 Ad Valorem Tax Surcharge On January 22, 2015, we filed an Application with the KCC requesting approval of our Ad Valorem Tax Surcharge (AVTS). The request sought approval for an annual increase of $0.27 million related to increases in Ad Valorem taxes which exceed amounts currently included in base rates. On February 19, 2015, the KCC approved the request. The new rate was effective on and after February 23, 2015. On January 21, 2016, we filed an Application with the KCC requesting approval for a revision to the AVTS. The request sought approval for an annual increase of an additional $0.20 million related to increases in Ad Valorem taxes which exceed amounts currently included in our AVTS rider currently in effect. 2014 Environmental Cost Recovery Rider On December 5, 2014, we filed an Application with the KCC requesting approval of our proposed Asbury Environmental Cost Recovery (AECR) tariff rider. The request sought approval for recovery of our jurisdictional portion of annual carrying costs (rate of return, income taxes, and depreciation) of approximately $0.86 million, associated with investment in the Asbury AQCS. A Commission Order was received April 15, 2015 approving the rider in the amount of $0.78 million effective June 1, 2015. Oklahoma On June 8, 2015, the governor of the state of Oklahoma approved an administrative ruling that provides customer rate reciprocity to electric companies who serve less than 10% of total customers within the state of Oklahoma. As a result, future increases in Missouri customer rates approved by the MPSC will be effective for our Oklahoma customers, subject to Oklahoma Corporation Commission (OCC) approval. On October 26, 2015, we filed a request with the OCC to adopt the Missouri customer electric rates requested in our October 16, 2015 Missouri rate filing discussed above for our Oklahoma customers once approval is granted by the MPSC. Arkansas 2015 Tariff Rider On February 23, 2015, we filed a notice with the Arkansas Public Service Commission (APSC) to implement the Alternative Generation Environmental Recovery Rider (GER) pursuant to the provision of Act 310 of 1981. The GER recovers reasonably incurred costs and expenditures as a direct result of legislative or regulatory requirements relating to the protection of the public health, safety, or the environment. Our implemented GER recovers our Arkansas jurisdictional share of investment associated with the Asbury AQCS. The new GER was effective upon notice (February 23, 2015) subject to refund. On August 5, 2015, the APSC approved the GER. 2014 Rate Case On May 20, 2014, we filed a settlement agreement with the Arkansas Public Service Commission (APSC) for an increase of $1.375 million, or approximately 11%. A hearing was held on the settlement agreement on July 22, 2014. On September 16, 2014, the APSC issued an order approving the settlement with a modification that reduced the overall revenue increase to $1.367 million. The new rates were effective September 26, 2014. We had filed a request on December 3, 2013, with the APSC seeking an annual increase in total revenue of approximately $2.2 million, or approximately 18%. The rate increase was requested to recover costs incurred to ensure continued reliable service for our customers, including capital investments, operating systems replacement costs and ongoing increases in other operation and maintenance expenses and capital costs. FERC We have in place a cost-based transmission formula rate (TFR). On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement included a TFR that would establish an ROE of 10.0%. The Agreement calls for the TFR to be updated annually with the new updated TFR rates effective on July 1 of each year. FERC conditionally approved the Agreement on November 18, 2013, and we made a compliance filing with FERC on December 18, 2013 in connection with this conditional approval. The FERC approved our compliance filing on June 12, 2014. We have in place a cost-based generation formula rate (GFR). Our GFR requires an update to be completed annually for rates effective June 1. On October 29, 2014, Empire made a "limited" Section 205 filing to request some minor changes in the existing GFR formula to incorporate the impact of the recent implementation of the Southwest Power Pool Integrated Marketplace (IM). As a result of this filing, our customers' share of the margins we receive from sales into the IM will be passed on to them through the monthly fuel and purchased power cost adjustment mechanism rather than making one-time adjustments at each annual update. This filing was approved by FERC on January 13, 2015. MARKETS AND TRANSMISSION Electric Segment Day Ahead Market: On March 1, 2014, the SPP RTO implemented its Integrated Marketplace (IM) (or Day-Ahead Market), which replaced the Energy Imbalance Services (EIS) market. The SPP RTO created a single NERC-approved balancing authority (BA) that took over balancing authority responsibilities for its members, including Empire. As part of the IM, we and other SPP members submit generation offers to sell our power and bids to purchase power into the SPP market, with the SPP serving as a centralized commitment and dispatch of SPP members' generation resources. The SPP matches offers and bids based upon operating and reliability considerations. The SPP reports that approximately 90% – 95% of all next day generation needed throughout the SPP territory is being cleared through the IM. We also acquire Transmission Congestion Rights (TCR) through annual and monthly processes in an attempt to mitigate congestion costs associated with the power we purchase from the IM. When we sell more generation to the market than we purchase for a given settlement period, the net sale is included as part of electric revenues. When we purchase more generation from the market than we sell, the net purchase is recorded as a component of fuel and purchased power on our financial statements. The net financial effect of these IM transactions is included in our fuel adjustment mechanisms and therefore has little impact on gross margin 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 completed and filed with the FERC a required interregional policy and procedure compliance filing, and while FERC partially approved SPP's compliance filing, remaining issues have been addressed in a subsequent filing that is currently waiting FERC approval. SPP Regional Transmission Development: In 2010, SPP received FERC approval to implement a new highway/byway cost allocation methodology for new SPP approved transmission projects. We actively monitor SPP's policy to allocate the costs of transmission projects to its members. 2015 net SPP transmission expenses were approximately $1.3 million above 2014 levels. Our Arkansas and Oklahoma jurisdictions have cost recovery mechanisms in place to fully recover additional transmission costs outside the traditional rate making process, and Missouri has a mechanism in place to recover a portion of transmission expense above the amount in base fuel. See "Rate Matters" above for more information. 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 % % 100kV to 299kV % % Below 100 kV % % SPP's formal regional cost allocation review and benefit to cost imbalance analysis process is ongoing. A filing to outline several possible remedies for entities not receiving adequate benefits from projects regionally funded was rejected by FERC and discussion continues in stakeholder groups to develop alternatives. SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement and Plum Point Delivery: Due to Plum Point's physical location and interconnection, transmission service from Entergy/MISO is required for delivery. On December 19, 2013, Entergy voluntarily integrated its generation, transmission, and load into the MISO regional transmission organization. Based on the current terms and conditions of MISO membership, Entergy's participation in MISO has increased transmission delivery costs for our Plum Point power station as well as utilizes our transmission system without compensation. As a result, we have participated with the SPP members and other impacted utilities in two separate FERC settlement proceedings in an effort to reduce the costs to our customers. On October 13, 2015, SPP members, SPP, MISO and MISO members filed a settlement at the FERC regarding MISO's unreserved and uncompensated use of the SPP members' systems. If approved by the FERC, the agreement will provide compensation and governance for the continued shared use of the transmission system among MISO, SPP and others impacted. However, the regional through and out transmission delivery rate (RTOR) dispute regarding Plum Point will go to hearing at the FERC. On May 20, 2015, we along with KCPL-GMO, AECI, and Southern Company filed a formal 206 complaint at the FERC that the ROTR rate was unjust and unreasonable. A procedural schedule was issued by the FERC on October 8, 2015 with hearings to commence on April 25, 2016 and an initial decision scheduled for August 10, 2016. Gas Segment Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers. Other — Rate Matters In accordance with ASC guidance on regulated operations, we currently have deferred approximately $0.4 million of expense related to rate cases under other non-current assets and deferred charges. These amounts will be amortized over varying periods based upon the completion of the specific cases. Based on past history, we expect all these expenses to be recovered in rates.

SHAREHOLDERS' EQUITY

SHAREHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2015
SHAREHOLDERS' EQUITY
SHAREHOLDERS' EQUITY	4. SHAREHOLDERS' EQUITY Shelf Registration We have a $200.0 million shelf registration statement with the SEC, effective December 13, 2013, covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. As of December 31, 2015, $200.0 million remains available for issuance under this shelf registration statement. However, as a result of our regulatory approvals, we may only issue up to $150.0 million of such securities in the form of first mortgage bonds, of which $30 million remains available after the issuance of $60 million in first mortgage bonds on August 20, 2015, and $60 million on December 1, 2014. Any proceeds from offerings made pursuant to this shelf would be used to fund capital expenditures, refinance existing debt or general corporate needs during the effective period through December 2016. Employee Benefit Plans Our Employee Stock Purchase Plan permits the grant to eligible employees of options to purchase our common stock at a discounted price. As of December 31, 2015 there were 764,645 shares available for issuance in this plan. Under our Employee 401(k) Plan and ESOP we match a percentage of each employee's deferrals by contributing shares of our common stock. At December 31, 2015 there were 129,616 shares available to be issued. (See Note 7 for further discussion of these plans). Equity Based Compensation We have several stock-based awards programs, which are described in Note 8. Our 2015 Stock Incentive Plan provides for grants of up to 500,000 shares of common stock through January 2025. At December 31, 2015 there were 496,766 shares available to be issued. 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, 2015, 2014 and 2013: (in millions, except per share amounts) 2015 2014 2013 Diluted earnings per share $ $ $ Dividends paid per share $ $ $ Total dividends paid $ $ $ Retained earnings year-end balance $ $ $ Under Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax. However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the Federal Power Act (FPA) prohibits the payment by a utility of dividends from any funds "properly included in capital account". There are no additional rules or regulations issued by the FERC under the FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive analysis of the specific facts and circumstances surrounding the utility and the dividend in question, with particular focus on the impact of the proposed dividend on the liquidity and financial condition of the utility. In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. The EDE Mortgage permits the payment of any dividend or distribution on, or purchase of, shares of our common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1. Preferred and Preference Stock We have 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A Participating Preference Stock, none of which have been issued. We have 5 million shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2015 or 2014.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2015
LONG-TERM DEBT.
LONG-TERM DEBT	5. LONG-TERM DEBT At December 31, 2015 and 2014, the balance of long-term debt outstanding was as follows (in thousands): 2015 2014 First mortgage bonds (EDE): 7.20% Series due 2016 $ $ 6.375% Series due 2018 (1) 4.65% Series due 2020 (1) 3.58% Series due 2027 (1) 3.59% Series due 2030 (1) — 3.73% Series due 2033 (1) 5.875% Series due 2037 (1) 5.20% Series due 2040 (1) 4.32% Series due 2043 (1) 4.27% Series due 2044 (1) First mortgage bonds (EDG): 6.82% Series due 2036 (1) ​ ​ ​ ​ ​ ​ ​ ​ Senior Notes, 6.70% Series due 2033 (1) Senior Notes, 5.80% Series due 2035 (1) Capital lease obligations Less unamortized net discount ) ) ​ ​ ​ ​ ​ ​ ​ ​ Less current obligations of long-term debt ) — Less current obligations under capital lease ) ) ​ ​ ​ ​ ​ ​ ​ ​ TOTAL LONG-TERM DEBT $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (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 June 11, 2015, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 3.59% First Mortgage Bonds due 2030. A delayed settlement occurred on August 20, 2015. Interest is payable semi-annually on the bonds on each February 20 and August 20, commencing February 20, 2016. The bonds are prepayable 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 prepayment date. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for general corporate purposes. The bonds have not been and will not be registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage. On October 15, 2014, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 4.27% First Mortgage Bonds due December 1, 2044. A delayed settlement occurred on December 1, 2014. Interest is payable semi-annually on the bonds on each December 1 and June 1, commencing June 1, 2015. The bonds may be redeemed at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for general corporate purposes. The bonds have not been, and will not be, registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage. Shelf Registration We have a $200 million shelf registration statement with the SEC that is effective for three years from December 13, 2013. See Note 4. EDE Mortgage Indenture Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $297 million of new first mortgage bonds. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. 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. The annual interest coverage requirement and retired bonds or 60% of net property additions test would permit the issuance of more than $297.0 million of first mortgage bonds; however, as discussed above, we are otherwise limited to the issuance of no more than $297.0 million of new first mortgage bonds. As of December 31, 2015, 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 Indenture of Mortgage and Deed of Trust of The Empire District Gas Company (EDG Mortgage) is limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of December 31, 2015, this test would allow us to issue approximately $19.5 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%. As of December 31, 2015, we are in compliance with all restrictive covenants of the EDG Mortgage. Our long-term debt obligations over the next five years are as follows (in thousands): Payments Due By Period Long-Term Debt Payout Schedule (Excluding Unamortized Discount) (in thousands) Total Regulated Entity Debt Obligations Capital Lease Obligations 2016 $ $ $ 2017 — 2018 2019 — 2020 Thereafter ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total long-term debt obligations $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Less current obligations and unamortized discount ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL LONG-TERM DEBT $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

SHORT-TERM BORROWINGS

SHORT-TERM BORROWINGS	12 Months Ended
	Dec. 31, 2015
SHORT-TERM BORROWINGS
SHORT-TERM BORROWINGS	6. SHORT-TERM BORROWINGS At December 31, 2015, total short-term borrowings consisted of $25.0 million in commercial paper and no borrowings under our line of credit. During 2015 and 2014 our short-term borrowings outstanding averaged (in millions) 2015 2014 Average borrowings outstanding $ $ Highest month end balance $ $ The weighted average interest rates and the weighted average interest rate of borrowings outstanding at December 31, 2015 and 2014 were:. 2015 2014 Weighted average interest rate % % Weighted average interest rate of borrowings outstanding % % We have in place a $200 million 5-year Credit Agreement which expires in October 2019. This agreement replaced the former $150 million Third Amended and Restated Unsecured Credit Agreement that had a January 2017 expiration date. This agreement may be used for working capital, commercial paper back-up and general corporate purposes. The credit facility includes a $20 million swingline loan sublimit, a $20 million sublimit for letters of credit issuance and, subject to bank approval, a $75 million accordion feature and two one-year extensions of the credit facility's maturity date. Interest on borrowings under the new facility accrues at a rate equal to, at our option, (i) the highest of (A) the agent prime rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, in each case, plus a margin or (ii) one month, two month, three month or six month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility is 1.025%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings, which is currently 0.175%. In addition, upon entering into the new credit facility, we paid upfront fees to the revolving credit banks of $0.3 million in the aggregate. The new credit facility requires our total indebtedness to be less than 65.0% of our total capitalization at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2015, we were in compliance with this covenant as our ratio of total indebtedness to total capitalization was 0.53 to 1.0. The new credit facility is also subject to cross-default if we default on more than $25 million in the aggregate on our other indebtedness. As of December 31, 2015, we were not in default under any of our debt obligations. The new credit agreement does not legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under the agreement at December 31, 2015; however, $25.0 million was used to back up our outstanding commercial paper.

RETIREMENT AND OTHER EMPLOYEE B

RETIREMENT AND OTHER EMPLOYEE BENEFITS	12 Months Ended
	Dec. 31, 2015
RETIREMENT AND OTHER EMPLOYEE BENEFITS
RETIREMENT AND OTHER EMPLOYEE BENEFITS	7. RETIREMENT AND OTHER EMPLOYEE BENEFITS We record retirement benefits in accordance with the ASC guidance on accounting for pension and other postretirement benefits, and have recorded the appropriate liabilities to reflect the unfunded status of our benefit plans, with offsetting entries to a regulatory asset, because we believe it is probable the unfunded amount of these plans will be afforded rate recovery. Additionally, the MPSC agreed that the effects of purchase accounting entries related to pension and other post-retirement benefits would be recoverable in future rate proceedings. These amounts, which are related to EDG, were recorded as regulatory assets and are being amortized. The tax effects of these entries are reflected as deferred tax assets and liabilities and regulatory liabilities. Annually we evaluate the discount rate, retirement age, compensation rate increases, expected return on plan assets, healthcare cost trend rate, and other actuarial assumptions related to pension benefit and post-retirement medical plan. We utilize an interest rate yield curve to determine an appropriate discount rate. The yield curve is constructed based on the yields on over 500 high-quality, non-callable corporate bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of the Empire pension plan and develop a single point discount rate matching the plan's payout structure. In evaluating these assumptions, many factors are considered, including, current market conditions, asset allocations, changes in demographics and the views of leading financial advisors and economists. In evaluating the expected retirement age assumption, we consider the retirement ages of past employees eligible for pension and medical benefits together with expectations of future retirement ages. It is reasonably possible that changes in these assumptions will occur in the near term and, due to the uncertainties inherent in setting assumptions, the effect of such changes could be material to the Company's consolidated financial statements. A roll forward technique is used to value the year ending pension obligations. The roll forward technique values the year-end obligation by rolling forward the beginning-of-year obligation using the demographic assumptions disclosed below. The economic assumptions are updated as of the end of the year. All of the benefit plans have been measured as of December 31, 2015, consistent with previous years. See Note 1. Pensions Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. Effective on January 1, 2014, the plan was amended to include a cash balance benefit formula. Employees hired on or after January 1, 2014 will accrue benefits based on a cash balance methodology. Employees hired prior to January 1, 2014 were given a one-time option to convert to the cash balance methodology, or remain with our traditional average annual basic earnings formula, by December 31, 2014. Both benefit formulas allow for a lump sum distribution of vested benefits. Lump sum distributions totaled approximately $15.3 million and $9.0 million during 2015 and 2014, respectively, and did not require settlement accounting according to ASC 715. Annual contributions to the plan are at least equal to the greater of either minimum funding requirements of ERISA or the accrued cost of the Plan, as required by the Missouri Public Service Commission. Our net pension liability decreased $2.4 million in 2015, which 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. The decrease in the liability is primarily due to an increase in discount rates. Our contribution is estimated to be approximately $13.6 million for 2016. 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 2017, the performance of our pension assets during 2016. 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. The liability for this plan increased $0.7 million in 2015. Expected benefit payments are as follows (in millions): Year Payments from Trust Payments from Company Funds 2016 $ $ 2017 2018 2019 2020 2021 – 2025 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 $10.0 million in 2015, which 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. The decrease in the liability is primarily due to a significant actuarial gain resulting from increases in discount rates, the adoption of a new mortality table and positive claims trends. 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 $4.9 million in 2016. Estimated benefit payments are as follows (in millions): Year Payments from Trust Expected Federal Subsidy Payments from Company Funds 2016 $ $ $ 2017 2018 2019 2020 2021 – 2025 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). Pension SERP OPEB Reconciliation of Projected Benefit Obligations: 2015 2014 2015 2014 2015 2014 Benefit obligation at beginning of year $ $ $ $ $ $ Service cost Interest cost Amendments — ) — ) — — Net actuarial (gain)/loss ) ) Plan participant's contribution — — — — Benefits and expenses paid ) ) ) ) ) ) Federal subsidy — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Benefit obligation at end of year $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Pension SERP OPEB Reconciliation of Fair Value of Plan Assets: 2015 2014 2015 2014 2015 2014 Fair value of plan assets at beginning of year $ $ $ — $ — $ $ Actual return on plan assets — gain/(loss) ) — — ) Employer contribution — — Benefits paid ) ) — — ) ) Plan participant's contribution — — — — Federal subsidy — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair value of plan assets at end of year $ $ $ — $ — $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Pension SERP OPEB Reconciliation of Funded Status: 2015 2014 2015 2014 2015 2014 Fair value of plan assets $ $ $ — $ — $ $ Projected benefit obligations ) ) ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Funded status $ ) $ ) $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The employee pension plan accumulated benefit obligation at December 31, 2015 and 2014 is presented in the following table (in thousands): Pension Benefits SERP 2015 2014 2015 2014 Accumulated benefit obligation $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amounts recognized in the balance sheet consist of (in thousands): Pension SERP OPEB 2015 2014 2015 2014 2015 2014 Accounts Payable and Accrued Liabilities $ — $ — $ $ $ $ Pension and other postretirement benefit obligation $ $ $ $ $ $ Net periodic benefit pension cost for 2015, 2014 and 2013, 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): Pension OPEB Net Periodic Pension Benefit Cost: 2015 2014 2013 2015 2014 2013 Service cost $ $ $ $ $ $ Interest cost Expected return on plan assets ) ) ) ) ) ) Amortization of prior service cost/(benefit) (1) ) ) ) ) Amortization of actuarial loss (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net periodic benefit cost $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ SERP Net Periodic Pension Benefit Cost: 2015 2014 2013 Service cost $ $ $ Interest cost Expected return on plan assets — — — Amortization of prior service cost/(benefit)t (1) ) ) ) Amortization of actuarial loss (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net periodic benefit cost $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet. The tables below present other changes in plan assets and benefit obligations recognized in the regulatory asset accounts for the year (in thousands). Amount Recognized Regulatory Assets Beginning Balance 12/31/14 Current Year Actuarial Loss Amortization of Actuarial Loss Current Year Prior Service Credit Amortization of Prior Service (Cost)/Credit Ending Balance 12/31/15 Pension $ ) — $ SERP $ ) — $ OPEB $ ) ) — $ Amount Recognized Regulatory Assets Beginning Balance 12/31/13 Current Year Actuarial Loss Amortization of Actuarial Loss Current Year Prior Service Credit Amortization of Prior Service (Cost)/Credit Ending Balance 12/31/14 Pension $ ) ) ) $ SERP $ ) ) $ OPEB $ ) — $ 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, 2015, and the subsequent twelve-month period (in thousands): Pension Benefits SERP OPEB 2015 Subsequent Period 2015 Subsequent Period 2015 Subsequent Period Net actuarial loss $ $ $ $ $ $ Prior service cost (benefit) ) ) ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 Benefits OPEB 2015 2014 2015 2014 Discount rate % % % % Rate of compensation increase % % % % Weighted-average assumptions used to determine the net benefit cost (income) as of January 1: Pension Benefits OPEB 2015 2014 2013 2015 2014 2013 Discount rate % % % % % % Expected return on plan assets % % % % % % Rate of compensation increase % % % % % % 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 2015 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 7.0%. Each trend rate decreases 0.50% through 2020 to an ultimate rate of 5.0% in 2020 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 $ $ ) Effect on post-retirement benefit obligation $ $ ) Fair value measurements of plan assets See Note 15 for a discussion of fair value measurements. The Company believes that it is appropriate for the pension fund to assume a moderate degree of investment risk with diversification of fund assets among different classes (or types) of investments, as appropriate, as a means of reducing risk. Although the pension fund can and will tolerate some variability in market value and rates of return in order to achieve a greater long-term rate of return, primary emphasis is placed on preserving the pension fund's principal. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company's Investment Committee. The following is a description of the valuation methodologies used for assets measured at fair value using significant other observable, or significant unobservable inputs. Short-term investments: Valued at cost, which approximates fair value. Common/Collective trusts: Valued at the fair value based on audited financials of the trusts. U.S. corporate and foreign issue debt: Valued at quoted market prices when available in an active market. If quoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows. Equity long/short hedge funds: Valued at the net asset value reported in the annual audited financial statements and updated monthly based on changes in the value of the underlying funds reported by the fund manager. Pension plan assets We utilize fair value in determining the market-related values for the different classes of our pension plan assets. The market-related value is determined based on smoothing actual asset returns in excess of (or less than) expected return on assets over a 5-year period. The Company's primary investment goals for pension fund assets are based around four basic elements: 1. Preserve capital, 2. Maintain a minimum level of return equal to the actuarial interest rate assumption, 3. Maintain a high degree of flexibility and a low degree of volatility, and 4. Maximize the rate of return while operating within the confines of prudence and safety. Asset Allocation We have adopted an investment strategy referred to as a de-risking glide path to increase the fixed income allocation as the plan's funded status improves. As the pension plan reaches set funded status milestones, the plan's assets will be rebalanced to shift more assets from equity to fixed income. Based on the plan's progress with this strategy, the target investment allocation for pension fund assets is approximately 72% equities and 28% fixed income securities. However, these allocations are permitted to vary within the following ranges: 60% – 80% for equities and 20% – 40% for fixed income securities. Money market funds are permitted within the fixed income category. Investment managers may generally hold up to 10% cash in their portfolios although this limit may be exceeded if market conditions warrant. The following fair value hierarchy table presents information about the pension fund assets measured at fair value as of December 31, 2015 and December 31, 2014 (in thousands): Fair Value Measurements as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Percentage of Plan Assets Short term investments $ — $ $ — $ % Equity securities Common collective trusts — domestic — — % Common collective trusts — international % Fixed income Common collective trust — — % Other types of investments Equity long/short hedge funds — — % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ $ $ % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements as of December 31, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Percentage of Plan Assets Short term investments $ — $ $ — $ % Equity securities Common collective trusts — domestic — — % Common collective trusts — international % Fixed income Common collective trust — — % Other types of investments Equity long/short hedge funds — — % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ $ $ % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — December 31, 2015 2014 Equity long/short hedge funds Equity long/short hedge funds Beginning Balance, January 1, $ $ Actual return on plan assets: Relating to assets still held at the reporting date ) Relating to assets sold during the period — Purchases — Sales — ) Settlements — — Transfers into and (out of) Level 3 — — ​ ​ ​ ​ ​ ​ ​ ​ Ending Balance, December 31, $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Permissible Investments Listed below are the investment vehicles specifically permitted: Permissible Investments Equity Oriented Fixed Income Oriented and Real Estate  Common Stocks  Preferred Stocks (minimum "A-rated" by Moody's or S&P)  American Depository Receipts  Convertible Preferred Stocks  Convertible Bonds  Covered Options  Hedged Equity Funds of Funds  Bonds (including US Government and Agencies)  Corporate Bonds (minimum quality rating of Baa by Moody's or BBB by S&P)  Comingled bond funds (25% max. allocation to high yield)  Foreign Government Bonds  GIC's, BIC's  Commercial Paper (rated A1 by S&P or P1 by Moody's)  Certificates of Deposit in institutions with FDIC/FSLIC protection  Money Market Funds/Bank STIF Funds  Real Estate — Publicly Traded The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts. Those investments prohibited by the Investment Committee without prior approval are: Prohibited Investments Requiring Pre-approval  Privately Placed Securities  Commodities Futures  Securities of Empire District (except in the hedged equity funds of funds or commingled funds)  Restricted Stock  Warrants  Short Sales  Index Options  Letter Stock OPEB plan assets The Company's primary investment goals for the component of the OPEB fund used to pay current benefits are liquidity and safety. The primary investment goals for the component of the OPEB fund used to accumulate funds to provide for payment of benefits after the retirement of plan participants are preservation of the fund with a reasonable rate of return. The target allocation for plan assets is 60% equities and 40% fixed income, although, at any given time, up to 10% of either category may be invested in cash equivalents. The 10% cash limitation may be exceeded if market conditions warrant. Allocations may also vary within the following ranges: 44% – 76% equities and 36% – 44% fixed income securities. The following fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2014 and December 31, 2013 (in thousands): Fair Value Measurements as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Percentage of Plan Assets Equity securities Common collective trusts $ — $ $ — $ % Fixed income Common collective trusts — — % Other types of investments Common collective trusts — — % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payable for securities purchased ) –0.2 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements as of December 31, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Percentage of Plan Assets Equity securities Common collective trusts $ — $ $ — $ % Fixed income Common collective trusts — — % Other types of investments Common collective trusts — — % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payable for securities purchased ) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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  Preferred Stocks  Cash-Equivalent Securities with a maturity of one-year or less, including: money market funds, US Government and Agency securities, certificates of deposit or banker's acceptances issued by domestic banks with FDIC protection and commercial paper rated A1 by S&P or P1 by Moody's  Government Bonds  Money Market Funds / Bank STIF Funds  Certificates of Deposit in institutions with FDIC protection  Corporate Bonds (minimum quality rating of A Baa by Moody's or BBB by S&P at time of issuance) The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts. Listed below are those investments prohibited by the Investment Committee: Prohibited Investments  Privately Placed Securities  Securities of Empire District  Derivatives  Instrumentalities in violation of the Prohibited Transactions Standards of ERISA  Margin Transactions  Options (other than "covered call options")  Lettered or Restricted Stock  Any other investment security which, in the opinion of the investment manager produces an imprudent risk to the fund 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 look-back feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of December 31, 2015 there were 764,645 shares available for issuance in this plan. 2015 2014 2013 Subscriptions outstanding at December 31, Maximum subscription price $ (1) $ $ Shares of stock issued Stock issuance price $ $ $ (1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2015 to May 31, 2016. Assumptions for valuation of these shares are shown in the table below. 2015 2014 2013 Weighted average fair value of grants $ $ $ Risk-free interest rate % % % Dividend yield % % % Expected volatility (1) % % % Expected life in months Grant date 6/1/2015 6/2/2014 6/1/2013 (1) One-year historic volatility 401(k) Plan and ESOP Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to 25% of their annual compensation up to an Internal Revenue Service specified limit. For employees participating in the cash balance formula of the pension plan, discussed above, we match 100% of their deferrals, not to exceed 6% of the employee's eligible compensation. The first 3% of the matching contribution is made in shares of our common stock with the remaining portion made by contributing cash. For employees remaining with the traditional average annual basic earnings formula of the pension plan, we match 50% of their deferrals by contributing shares of our common stock, with such matching contributions not to exceed 3% of the employee's eligible compensation. We record the compensation expense at the time the quarterly matching contributions are made to the plan. At December 31, 2015 there were 129,616 shares available to be issued. 2015 2014 2013 Shares contributed Deferred Compensation Effective January 2015, we established a non-qualified Deferred Compensation Plan for the purpose of allowing executive officers who elect to participate in the qualifying cash balance option of the Pension plan to obtain retirement savings that are not available to them under the 401(k) plan.

EQUITY COMPENSATION

EQUITY COMPENSATION	12 Months Ended
	Dec. 31, 2015
EQUITY COMPENSATION
EQUITY COMPENSATION	8. EQUITY COMPENSATION We have several stock-based awards and programs, which are described below. Performance-based restricted stock awards, time-vested restricted stock and stock options are valued as liability awards, in accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award. We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in thousands): 2015 2014 2013 Compensation expense $ $ $ Tax benefit recognized Stock Incentive Plans Our 2006 Stock Incentive Plan (the 2006 Incentive Plan), which expired on December 31, 2015, was replaced by the 2015 Stock Incentive Plan (the 2015 Incentive Plan). The 2015 Incentive Plan was adopted by shareholders at the annual meeting on May 1, 2014 and provides for grants of up to 500,000 shares of common stock through January 2025. At December 31, 2015 there were 496,766 shares available to be issued. The 2015 Stock Incentive Plan permits (and the 2006 Incentive Plan permitted) grants of stock options and restricted stock to qualified employees and permits Directors and, if approved by the Compensation Committee of the Board of Directors, qualified employees to receive common stock in lieu of cash. Certain executive officers and other senior managers applied to receive annual incentive awards related to 2013, 2014 and 2015 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 and 2015 Stock Incentive Plans. 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 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. In addition, if a change in control occurs during the vesting period, a pro-rata portion of the time-vested restricted stock awards will vest upon such change in control, and any portion of such awards that remains unvested immediately after the change in control will be forfeited. The fair value measurements for each grant year are noted in the following table: Fair Value of Grants Outstanding at December 31 2015 2014 Total unrecognized compensation cost (in millions) $0.4 $0.4 Recognition period 0.1 years to 2.1 years 1.1 years to 2.1 years Fair value $25.17 $26.82 A summary of time-vested restricted stock activity under the plan for 2015, 2014 and 2013 is presented in the table below: 2015 2014 2013 Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Number Of Shares Weighted Average Grant Date Fair Value Outstanding at January 1, $ $ $ Granted $ $ $ Distributed ) $ ) $ — — Forfeited ) $ ) $ — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Outstanding at December 31, $ $ $ 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 2013, 2014 and 2015 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. If employment terminates during the performance period because of death, retirement, or disability, the individual is entitled to a pro-rata portion of the performance-based restricted stock awards such individual would otherwise have earned. If employment is terminated during the performance period for reasons other than those listed above, the performance-based restricted stock awards will be forfeited on the date of the termination unless the Compensation Committee of the Board of Directors determines, in its sole discretion, that the individual is entitled to a pro-rata portion of such award. In addition, if a change in control occurs during the performance period, a pro-rata portion of the target performance-based restricted stock awards will vest and be distributed upon such change in control. At the end of the performance period, the number of shares earned, determined without regard to the special change in control vesting provisions will be determined and such amount, less the number of shares distributed upon the change in control, shall be distributed. In connection with the Agreement and Plan of Merger dated February 9, 2016, by and among the Company, Liberty Utilities (Central) Co. and Liberty Sub Corp. (the "Merger Agreement"), we amended outstanding performance-based restricted stock awards to provide that, effective upon and subject to the occurrence of the merger under the Merger Agreement, each performance-based restricted stock award outstanding immediately prior to the effective time of the merger will be converted into the right to receive a lump sum in cash equal to the merger consideration under the merger agreement, multiplied by the target number of shares under the award. (See Note 17 for further discussion of the Merger Agreement). The fair value of the outstanding restricted stock awards was estimated as of December 31, 2015, 2014 and 2013 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, 2015 2014 2013 Risk-free interest rate 0.65% to 1.06% 0.25% to 0.67% 0.13% to 0.38% Expected volatility of Empire stock 18.7% 14.5% 20.2% Expected volatility of peer group stock 14.5% to 34.4% 12.4% to 24.8% 12.3% to 27.5% Expected dividend yield on Empire stock 3.7% 3.5% 4.5% Expected forfeiture rates 3% 3% 3% Plan cycle 3 years 3 years 3 years Fair value percentage 115.0% to 182.0% 140.0% to 157.0% 0.0% to 108.0% Weighted average fair value per share $41.73 $43.80 $18.47 Non-vested performance-based restricted stock awards (based on target number) as of December 31, 2015, 2014 and 2013 and changes during the year ended December 31, 2015, 2014 and 2013 were as follows: 2015 2014 2013 Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Number Of Shares Weighted Average Grant Date Fair Value Outstanding at January 1, $ $ $ Target shares granted $ $ $ Shares issued in excess of target $ — — — — Shares awarded ) $ — — ) $ Forfeited shares ) $ — — — Target shares not awarded — — ) $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nonvested at December 31, $ $ $ At December 31, 2015 and 2014, unrecognized compensation expense related to estimated outstanding awards was $0.7 million and $1.1 million, respectively. Stock Options Beginning in 2011, we began issuing time-vested restricted stock in lieu of stock options and dividend equivalents. Prior to 2011 stock options were issued with an exercise price equal to the fair market value of the shares on the date of grant. They became exercisable after three years and expired ten years after the date granted. Dividend equivalent awards, under which dividend equivalents accumulated during the vesting period, were also issued to recipients of the stock options. Participants' options and dividend equivalents that were not vested were forfeited when participants left Empire, except for terminations of employment under certain specified circumstances. There were no stock options or dividend equivalents granted in 2015, 2014, or 2013, and all outstanding options were exercised prior to December 31, 2014. Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. There were no outstanding options at December 31, 2015 and 2014. The fair value of the outstanding options was estimated as of December 31, 2013, under a Black-Scholes methodology. The assumptions used in the valuations are shown below: Fair Value of Grants Outstanding at December 31, 2013 Risk-free interest rate 0.10% to 0.38% Dividend yield 4.5% Expected volatility 24.0% Expected life in months 6.5 to 24.5 Market value $22.69 Weighted average fair value per option $1.57 A summary of option activity under the plan during the years ended December 31, 2014 and 2013 is presented below: 2014 2013 Options Weighted Average Exercise Price Options Weighted Average Exercise Price Outstanding at January 1, $ $ Granted — — $ — Exercised $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Outstanding at December 31, — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exercisable, end of year — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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: 2013 Aggregate intrinsic value (in millions) Less than $0.1 Weighted-average remaining contractual life of outstanding options 2.1 years Range of exercise prices $21.92 to $23.81 Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan — Recognition period — 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, 2015, a total of 900,000 shares were authorized under this plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock. In connection with the Merger Agreement, we amended the Stock Unit Plan to provide that, effective upon and subject to the occurrence of the merger under the Merger Agreement, each stock unit outstanding immediately prior to the effective time of the merger will be converted into the right to receive in cash the merger consideration under the Merger Agreement, with interest at the prime rate from the effective time of the merger until the payment date under the plan. (See Note 17 for further discussion of the Merger Agreement). 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: 2015 2014 Shares accrued to directors' accounts Shares available for issuance Units accrued for service and dividends as well as units redeemed for common stock at December 31 are shown in the table below: 2015 2014 2013 Units accrued for service and dividends Units redeemed for common stock

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
INCOME TAXES.
INCOME TAXES	9. INCOME TAXES Income tax expense components for the years ended December 31 are as follows (in thousands): 2015 2014 2013 Current income taxes: Federal $ — $ ) $ State — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL — ) Deferred income taxes: Federal State ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL Investment tax credit amortization ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL INCOME TAX EXPENSE $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Deferred Income Taxes Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows (in thousands): December 31, Deferred Income Taxes 2015 2014 NET DEFERRED TAX LIABILITIES $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows (in thousands): December 31, Temporary Differences 2015 2014 Deferred tax assets: Plant related basis differences $ $ Net operating loss (NOL) Regulated liabilities related to income taxes Disallowed plant costs Gains on hedging transactions Pensions and other post-retirement benefits — Carry forward of income tax credit Other ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities: Depreciation, amortization and other plant related differences $ $ Regulated assets related to income Loss on reacquired debt Amortization of intangibles Pensions and other post-retirement benefits — Deferred construction accounting costs Other ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax liabilities ​ ​ ​ ​ ​ ​ ​ ​ NET DEFERRED TAX LIABILITIES $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 2015 2014 2015 Federal statutory income tax rate % % % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) Investment tax credit amortization ) ) ) Effect of ratemaking on property related differences ) ) ) Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ EFFECTIVE INCOME TAX RATE % % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We do not have any unrecognized tax benefits as of December 31, 2015. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months. The "Protecting Americans from Tax Hikes" Act (the "Act") was signed into law on December 18, 2015. The Act restored several expired business tax provisions, including bonus depreciation for 2015. Because of the reinstatement of bonus depreciation, we anticipate making no material income tax payments in 2016. We generated $74.1 million of tax NOLs during 2014, mainly due to bonus depreciation. We intend to carry forward these tax NOLs, which, if unused, will expire in 2034. We estimate that we will utilize approximately $38.0 million of the 2014 tax NOLs on our 2015 return when filed. As of December 31, 2015, we estimate there is $13.5 million of deferred tax assets remaining to be utilized related to the tax NOLs. A portion of the deferred tax assets related to the tax NOLs is recorded as a receivable on the balance sheet in anticipation of income tax payment refunds. In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2, which, if unused, will expire in 2030. We utilized $9.0 million of these credits on our 2013 tax return. Due to the passage of the Act, we estimate we will not be able to use the remaining credits on our 2015 tax return, but expect to use them to offset future income tax liabilities. The tax credits will have no significant income statement impact because they will flow to our customers as we amortize the tax credits over the life of the plant. On September 13, 2013, the IRS and the Treasury Department released final regulations under Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations applied to tax years beginning on or after January 1, 2014, and we filed a Form 3115 with the IRS to change our tax accounting method to comply with the regulations. As a result, we deducted approximately $29 million on our 2014 income tax return under IRS Code Section 481(a) as an adjustment required by the change in tax accounting method. Our 2014 income tax return included another tax accounting method change regarding the deductibility of the Voluntary Employee Benefit Association (VEBA) plan activity. As a result, we deducted approximately $14 million as an adjustment required by the change in tax method of accounting. These changes did not have a material impact on the effective tax rate.

COMMONLY OWNED FACILITIES

COMMONLY OWNED FACILITIES	12 Months Ended
	Dec. 31, 2015
COMMONLY OWNED FACILITIES
COMMONLY OWNED FACILITIES	10. COMMONLY OWNED FACILITIES Iatan We own a 12% undivided interest in the coal-fired Units No. 1 and No. 2 at the Iatan Generating Station located near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. We are entitled to 12% of each unit's available capacity and are obligated to pay for a like percentage of the operating costs of the units. KCP&L and KCP&L Greater Missouri Operations Co. own 70% and 18% respectively, of Unit 1, and 54% and 18%, respectively, of Unit 2. KCP&L operates the units for the joint owners. At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions): Iatan 2015 2014 Cost of ownership in plant in service $ $ Accumulated Depreciation $ $ Expenditures (1) $ $ (1) Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense. State Line Combined Cycle Unit We and Westar Generating, Inc, ("WGI"), a subsidiary of Westar Energy, Inc., share joint ownership of a nominal 500-megawatt combined cycle unit at the State Line Power Plant (the "State Line Combined Cycle Unit"). We are responsible for the operation and maintenance of the State Line Combined Cycle Unit, and are entitled to 60% of the available capacity and are responsible for approximately 60% of its costs. At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions): State Line Combined Cycle Unit 2015 2014 Cost of ownership in plant in service $ $ Accumulated Depreciation $ $ Expenditures (1) $ $ (1) Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense. Plum Point Energy Station We own a 7.52% undivided interest in the coal-fired Plum Point Energy Station located near Osceola, Arkansas. We are entitled to 7.52% of the station's capacity, and are obligated to pay for a like percentage of the station's operating costs. At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions): Plum Point Energy Station 2015 2014 Cost of ownership in plant in service $ $ Accumulated Depreciation $ $ Expenditures (1) $ $ (1) Recognized in operating, maintenance and fuel expenditures excluding depreciation expense. All of the dollar amounts listed above represent our ownership share of costs.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES	11. COMMITMENTS AND CONTINGENCIES We are a party to various claims and legal proceedings arising out of the normal course of our business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company's defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows. Coal, Natural Gas and Transportation Contracts The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of December 31, 2015 (in millions). Firm physical gas and transportation contracts Coal and coal transportation contracts January 1, 2016 through December 31, 2016 $ $ January 1, 2017 through December 31, 2018 January 1, 2019 through December 31, 2020 January 1, 2021 and beyond — We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be placed in storage. The firm physical gas and transportation commitments are detailed in the table above. We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of December 31, 2015 are detailed in the table above. Purchased Power We currently supplement our on-system (native load) generating capacity with purchases of capacity and energy from other entities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules. The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit's capacity. We also have a long-term agreement for the purchase of an additional 50 megawatts of capacity from Plum Point. Commitments under this agreement are approximately $277.6 million through August 31, 2039, the end date of the agreement. We had the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the MPSC on July 1, 2013. We did not exercise this option by the March 2015 notification deadline in the contract. We have a long-term purchased power agreement, which expires in 2028, 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 long-term contract, which expires in 2025, 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 We have in place a contract with a third party vendor to complete engineering, procurement, and construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion includes the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. The Air Emission Source Construction Permit necessary for this project was issued by Kansas Department of Health and Environment on July 11, 2013. This conversion is currently scheduled to be completed in early to mid-2016 at a cost estimated to range from $165 million to $175 million, excluding allowance for funds used during construction (AFUDC). Construction costs, consisting of pre-engineering, site preparation activities and contract costs incurred project to date through December 31, 2015 were $159.6 million, excluding AFUDC. In December 2014 we completed an environmental retrofit at our Asbury plant. The retrofit project included the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This new equipment enables us to comply with the Mercury and Air Toxics Standard (MATS). Final costs were approximately $112.1 million, excluding AFUDC. Leases We have purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these agreements are disclosed in the Purchased Power section of this note. We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility. The gross amount of assets recorded under capital leases total $5.3 million at December 31, 2015. Our lease obligations over the next five years are as follows (in thousands): Capital Leases Operating Leases 2016 $ $ 2017 2018 2019 2020 — Thereafter — ​ ​ ​ ​ ​ ​ ​ ​ Total minimum payments $ Less amount representing interest ​ ​ ​ ​ ​ ​ ​ ​ Present value of net minimum lease payments $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Expenses incurred related to operating leases were $0.8 million, $0.8 million and $0.8 million for 2015, 2014, and 2013, respectively, excluding payments for wind generated purchased power agreements. The accumulated amount of amortization for our capital leases was $1.9 million and $1.5 million at December 31, 2015 and 2014, 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. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect these costs to be material, although recoverable in rates. Compliance Plan In order to comply with current and forthcoming environmental regulations, we continue to implement our compliance plan and strategy (Compliance Plan), which largely follows our Integrated Resource Plan (IRP) filed with MPSC in mid-2013. The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), are the drivers behind our Compliance Plan and its implementation schedule. We anticipate compliance costs associated with the MATS, CAIR and CSAPR regulations to continue to be recoverable in our rates. The following list summarizes the most significant environmental regulations affecting our operations: Regulations Air Emissions — NOx and SO2 CAIR (Clean Air Interstate Rule) CSAPR (Cross State Air Pollution Rule) MATS (Mercury Air Toxic Standards) NAAQS (National Ambient Air Quality Standards) Greenhouse Gases (GHGs) — CO 2 Surface Impoundments Coal Ash Impoundments: Asbury Power Plant Riverton (capped and closed in 2014 as industrial (coal combustion waste) landfill) Water Discharges MATS: In June 2015, the U.S. Supreme Court remanded the MATS back to the D.C. Circuit Court, holding that the EPA must consider cost (including cost of compliance) before deciding whether a regulation is appropriate and necessary. The court noted that it will be up to the EPA to decide within the limits of reasonable interpretation how to account for cost. MATS remains in effect until the D.C. Circuit Court acts. Greenhouse Gases: On August 3, 2015, the EPA released the final rule for limiting carbon emissions from existing power plants. The "Clean Power Plan" (CPP) requires a 32% carbon emission reduction from 2005 baseline levels by 2030 and requires fossil fuel-fired power plants across the nation, including those in Empire's fleet, to meet state-specific goals to lower carbon levels. States will choose between two plan types to meet their goals: an emission standards plan which includes source-specific requirements impacting affected power plants or a state measures plan which includes a mixture of measures implemented by the state. By September 6, 2016, each state must either submit to the EPA its initial plan with a request for an extension or a final plan. If the state receives an extension, the final plan must be submitted by September 6, 2018. States will then implement plans to achieve the progressive CO2 emissions performance rates over the period of 2022 to 2029 with the final CO2 goal accountability by 2030. Empire continues to evaluate potential paths forward on the final rule released by the EPA. As of January 26, 2016, twenty-five states have initiated legal challenges to the CPP which by and large seek to invalidate the rule. The ultimate cost of compliance cannot be determined at this time because of the uncertainties regarding the final outcome of the GHG regulations, including the legal challenges thereto, and the compliance methods yet to be chosen by the jurisdictions in which we operate. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates. Surface Impoundments: On September 30, 2015, the EPA finalized a revision of the Clean Water Act (CWA) Steam Electric Effluent Limitation Guidelines (ELGs) for coal-fired power plants. The new rule sets technology-based ELGs based on the nature of the pollutants being discharged and the facilities involved. As published, beginning in November 2018, the EPA and states would incorporate the new standards into all wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs at each facility that will result from the new standards to be in effect no later than December 2023. Effective October 19, 2015, the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs) as a non-hazardous solid waste under subtitle D of the Resource Conservation and Recovery Act (RCRA). We expect compliance with both the CCR and ELG rule to result in the need to construct a new landfill and the conversion of existing bottom ash handling from a wet to a dry system at a potential cost of up to $15 million at our Asbury Power Plant. We expect resulting costs to be recoverable in our rates. Final closure of the existing ash impoundment, for which an asset retirement obligation of $5.4 million has been recorded, is anticipated after the new landfill is operational. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station. We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. A technical review of our Detailed Site Investigation (DSI) for the specific site has been completed and was approved by the Missouri Department of Natural Resources on June 29, 2015. Receipt of the final construction permit for the CCR waste landfill is expected in January 2017. 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 EPA final rule under the CWA Section 316(b) for existing cooling water intake structures became effective on October 14, 2014. An industry coalition has filed an appeal of the rule in the Fifth Circuit and additional court challenges are expected. We expect the regulations to have no future impact at Riverton as the new intake structure design and installed cooling tower, as part of the Unit 12 conversion, meets the regulatory requirement for aquatic life protections. 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. Iatan Unit 2 and Plum Point Unit 1 are covered by the regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally affected by the final rule. Renewable Energy On November 4, 2008 Missouri voters approved the Clean Energy Initiative (Proposition C) which currently requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC. Proposition C also requires that 2% of the energy from renewable energy sources must be solar; however, we believed that we were exempted by statute from the solar requirement. On January 20, 2013 the Earth Island Institute, d/b/a Renew Missouri, and others challenged our solar exemption by filing a complaint with the MPSC. The MPSC dismissed the complaint and Renew Missouri filed a notice of appeal seeking review by the Missouri Supreme Court. On February 10, 2015 the Missouri Supreme Court issued an opinion holding that the legislature had the authority to adopt the statute providing the exemption but reversed the MPSC's holding that the two laws could be harmonized. The statute providing the exemption (which was enacted in August 2008) was impliedly repealed by the adoption of Proposition C because it conflicted with the latter law. On May 6, 2015, the MPSC approved tariffs we filed on May 5, 2015 to establish solar rebate payment procedures and revise our net metering tariffs to accommodate the payment of solar rebates. As of December 31, 2015, we had processed 262 solar rebate applications resulting in solar rebate-related costs totaling approximately $3.5 million under the new tariff. We have recorded the $3.5 million as a regulatory asset (See Note 3 — Regulatory Matters). The law provides a number of methods that may be utilized to recover the associated expenses. We expect any costs to be recoverable in rates. Legislation was recently adopted that altered the Kansas renewable portfolio standard (RPS), ending all mandatory requirements in 2015. The mandate, which required 20% of our Kansas retail customer peak capacity requirements to be sourced from renewables by 2020, has been changed to a voluntary goal. We are currently in compliance as a result of purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC.

SEGMENT INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2015
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, 2015 Electric Gas Other Eliminations Total Statement of Income Information: Operating Revenues (1) $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Income from continuing operations $ $ $ $ — $ Capital Expenditures $ $ $ $ — $ (1) The Electric Segment includes SPP Integrated Marketplace net revenues of $15.0 million. 2014 Electric Gas Other Eliminations Total Statement of Income Information: Operating Revenues (1) $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Income from continuing operations $ $ $ $ — $ Capital Expenditures $ $ $ $ — $ (1) The Electric Segment includes SPP Integrated Marketplace net revenues of $41.9 million. 2013 Electric Gas Other Eliminations Total Statement of Income Information: Operating Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Income from continuing operations $ $ $ $ — $ Capital Expenditures $ $ $ $ — $ December 31, 2015 Electric Gas (1) Other Eliminations Total Balance Sheet Information: Total assets $ $ $ $ ) $ December 31, 2014 Electric Gas (1) Other Eliminations Total Balance Sheet Information: Total assets $ $ $ $ ) $ (1) Includes goodwill of $39,492 at December 31, 2015 and 2014.

SELECTED QUARTERLY INFORMATION

SELECTED QUARTERLY INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2015
SELECTED QUARTERLY INFORMATION (UNAUDITED)
SELECTED QUARTERLY INFORMATION (UNAUDITED)	13. SELECTED QUARTERLY INFORMATION (UNAUDITED) The following is a summary of quarterly results for 2015 and 2014 (dollars in thousands except per share amounts): Quarters Quarterly Results for 2015 First Second Third Fourth Operating revenues (1) $ $ $ $ Operating income $ $ $ $ Net Income $ $ $ $ Basic Earnings Per Share $ $ $ $ Diluted Earnings Per Share $ $ $ $ (1) Operating revenue for the first, second, third and fourth quarters of 2015 include SPP IM net revenues of $4.7 million, $3.4 million, $4.0 million, and $2.9 million, respectively. Quarters Quarterly Results for 2014 First Second Third Fourth Operating revenues (1) $ $ $ $ Operating income $ $ $ $ Net Income $ $ $ $ Basic and Diluted Earnings Per Share $ $ $ $ (1) Operating revenue for the first, second, third and fourth quarters of 2014 include SPP IM net revenues of $6.2 million, $16.5 million, $11.5 million, and $7.5 million, respectively. The sum of the net income and quarterly earnings per share of common stock may not equal the net income and earnings per share of common stock as computed on an annual basis due to rounding.

RISK MANAGEMENT AND DERIVATIVE

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS
RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS	14. RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain cost predictability. We began acquiring Transmission Congestion Rights (TCR) in 2013 in an effort to mitigate the cost of power we purchase from the SPP IM due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results. All derivative instruments are recognized at fair value on the balance sheet. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms. Risks and uncertainties affecting the determination of fair value include: market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instruments in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income and subject to our fuel adjustment mechanism. As of December 31, 2015 and 2014, 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 2015 2014 Balance Sheet Classification Fair Value Fair Value Natural gas contracts, gas segment Current assets $ $ — Non-current assets and deferred charges — Other — Natural gas contracts, electric segment Current assets — Non-current assets and deferred charges — Other — — Transmission congestion rights, electric segment Current assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total derivatives assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ LIABILITY DERIVATIVES Non-designated as hedging instruments due to regulatory accounting 2015 2014 Balance Sheet Classification Fair Value Fair Value Natural gas contracts, gas segment Current liabilities $ $ Non-current liabilities and deferred credits — Natural gas contracts, electric segment Current liabilities Non-current liabilities and deferred credits Transmission congestion rights, electric segment Current liabilities — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total derivatives liabilities $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Electric At December 31, 2015, approximately $4.2 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, 2015 and 2014, 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 of Gain/(Loss) on Derivative 2015 2014 Commodity contracts — electric segment Regulatory (assets)/liabilities $ ) $ ) Transmission congestion rights — electric segment Regulatory (assets)/liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total — Electric Segment $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 2015 2014 Commodity contracts Fuel and purchased power expense $ ) $ ) Transmission congestion rights — electric segment Fuel and purchased power expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total — Electric Segment $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to fair value accounting because they qualify for the normal purchase normal sale exemption. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchase normal sale exception contain a price adjustment feature and will account for these contracts accordingly. At December 31, 2015, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for 2016 and the next four years are hedged at the following average prices per Dekatherm (Dth): Year % Hedged Dth Hedged Physical Dth Hedged Financial Average Price 2016 % $ 2017 % $ 2018 % $ 2019 % — $ 2020 % — — — We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year's and 80% of any future year's expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered. Year End of Year Minimum % Hedged Current Up to 100% First 60% Second 40% Third 20% Fourth 10% At December 31, 2015, the following transmission congestion rights (TCR) have been obtained from TCR auctions to hedge congestion costs in the SPP Integrated Marketplace: Year Monthly MWH Hedged $ Value 2016 $ 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, 2015 we had 1.4 million Dths in storage on the three pipelines that serve our customers. This represents 70% 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, 2015 (Dth in thousands). Season Minimum % Hedged Dth Hedged Financial Dth Hedged Physical Dth in Storage Actual % Hedged Current % — % Second Up to 50 % — — % Third Up to 20 % — — % A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet. The following table sets forth "mark-to-market" pre-tax gains/ (losses) from derivatives not designated as hedging instruments for the gas segment for the years ended December 31 (in thousands): Non-Designated Hedging Instruments Due to Regulatory Accounting — Gas Segment Amount of Loss Recognized on Balance Sheet Balance Sheet Classification of Loss on Derivative 2015 2014 Commodity contracts Regulatory assets $ ) $ ) — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total — Gas Segment $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Contingent Features Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. We had no derivative instruments with the credit-risk-related contingent features in a net liability position on December 31, 2015 and have posted no collateral in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at the dates shown. There were no margin deposit liabilities at these dates. (in millions) December 31, 2015 December 31, 2014 Margin deposit assets $ $ Offsetting of derivative assets and liabilities We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Collateral requirements are calculated at the master trading and netting agreement level by the counterparty. As shown above, our asset and liability commodity contract derivatives are reported at gross on the balance sheet. ASC guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. For the years ended December 31, 2015 and December 31, 2014, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2015
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	15. FAIR VALUE MEASUREMENTS The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data. The guidance also requires that the fair value measurement of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements. Our TCR positions, which are acquired on the SPP Integrated Marketplace, are valued using the most recent monthly auction clearing prices. Our commodity contracts are valued using the market value approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of December 31: Fair Value Measurements at Reporting Date Using ($ in 000's) Description Assets/(Liabilities) at Fair Value Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) December 31, 2015 Derivative assets $ $ $ $ — Derivative liabilities $ ) $ ) $ — $ — December 31, 2014 Derivative assets $ $ $ $ — Derivative liabilities $ ) $ ) $ — $ — * 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, 2015 and 2014 was $859 million and $799 million, compared to a fair market value of approximately $815 million and $829 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, 2015 or that will be realizable in the future.

REGULATED OPERATING EXPENSE

REGULATED OPERATING EXPENSE	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Power operation expense (other than fuel) $ $ $ Electric transmission and distribution expense Natural gas transmission and distribution expense Customer accounts & assistance expense Employee pension expense (1) Employee healthcare plan (1) General office supplies and expense Administrative and general expense Bad debt expense Regulatory reversal of gain on sale of assets — Miscellaneous expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (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.

SUBSEQUENT EVENT - AGREEMENT AN

SUBSEQUENT EVENT - AGREEMENT AND PLAN OF MERGER	12 Months Ended
	Dec. 31, 2015
SUBSEQUENT EVENT - AGREEMENT AND PLAN OF MERGER
SUBSEQUENT EVENT - AGREEMENT AND PLAN OF MERGER	17. SUBSEQUENT EVENT — AGREEMENT AND PLAN OF MERGER On February 9, 2016, Empire entered into an Agreement and Plan of Merger (the Merger Agreement) with Liberty Utilities (Central) Co., a Delaware corporation (Liberty), and Liberty Sub Corp., a Kansas corporation (Merger Sub), providing for the merger of Merger Sub with and into Empire, with Empire surviving the Merger as a wholly-owned subsidiary of Liberty (the Merger). Pursuant to the Merger Agreement, at the effective time of the Merger, each issued and outstanding share of Empire common stock (other than any shares owned by Empire or Algonquin Power & Utilities Corp. (APUC)) or any of their respective subsidiaries or any shares for which appraisal rights have been perfected) will be cancelled and converted automatically into the right to receive $34.00 in cash, without interest. The closing of the Merger is subject to certain conditions, including, among others, approval of Empire shareholders, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period and receipt of all required regulatory approvals and consents, including from the Federal Energy Regulatory Commission, the Federal Communications Commission, the Arkansas Public Service Commission, the Kansas Corporation Commission, the Missouri Public Service Commission, the Oklahoma Corporation Commission and the Committee on Foreign Investment in the United States, which approvals and consents shall not, individually or in the aggregate, have or be reasonably likely to have a material adverse effect on the business, properties, financial condition or results of operations of Liberty Utilities Co. and its subsidiaries (including Empire and its subsidiaries), taken as a whole. If Empire shareholders do not approve the Merger, or the Merger is not consummated by February 9, 2017, the Merger Agreement may terminate, although it may be extended six months in order to obtain certain required regulatory approvals. The Merger Agreement also provides for certain other termination rights for both Empire and Liberty. If either party terminates the Merger Agreement because Empire's board of directors changes its recommendation, or, if within nine months after the termination of the Merger Agreement under certain circumstances, Empire shall have entered into a definitive agreement with respect to, or consummated, an alternative transaction, Empire must pay Liberty a termination fee of $53.0 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, failure to consummate the Merger after all closing conditions have been satisfied and a financing failure has occurred or a breach by Liberty of its regulatory cooperation covenants, Liberty must pay Empire a termination fee of $65.0 million. Simultaneously with the execution of the Merger Agreement, Liberty delivered to Empire a guarantee agreement (the Guarantee Agreement) executed by APUC, the parent of Liberty Utilities Co. The Guarantee Agreement provides for an unconditional and irrevocable guarantee by APUC of the full and prompt payment and performance, when due, of all obligations of Liberty and Merger Sub under the Merger Agreement. In connection with entering into the Merger Agreement, Empire has incurred approximately $0.2 million of transaction costs as of December 31, 2015. We expect that the total transaction costs will be approximately $15 to $17 million, with approximately 50% payable in 2016 (assuming a 2017 closing date), of which approximately $4.5 million will be incurred in the first quarter of 2016. The foregoing description of the Merger, the Merger Agreement and the Guarantee is not a complete description thereof and is qualified in its entirety by reference to the full text of the Merger Agreement and the Guarantee. For more information regarding the terms of the Merger, including copies of the Merger Agreement and the Guarantee, see Empire's Current Report on Form 8-K filed with the SEC on February 9, 2016.

SCHEDULE II - Valuation and Qua

SCHEDULE II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2015
SCHEDULE II - Valuation and Qualifying Accounts
SCHEDULE II - Valuation and Qualifying Accounts	SCHEDULE II Valuation and Qualifying Accounts Years ended December 31, 2015, 2014 and 2013: Additions Charged to Other Accounts Deductions From Reserve Balance At Beginning Of Period Charged To Income Description Amount Description Amount Balance At Close of Period Year ended December 31, 2015: Reserve deducted from assets: accumulated provision for uncollectible accounts. $ $ Recovery of amounts previously written off $ Accounts written off $ $ Year ended December 31, 2014: Reserve deducted from assets: accumulated provision for uncollectible accounts. $ $ Recovery of amounts previously written off $ Accounts written off $ $ Year ended December 31, 2013: Reserve deducted from assets: accumulated provision for uncollectible accounts. $ $ Recovery of amounts previously written off $ Accounts written off $ $

SUMMARY OF SIGNIFICANT ACCOUN25

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation	Basis of Presentation The consolidated financial statements include the accounts of EDE, EDG, and our other subsidiaries. The consolidated entity is referred to throughout as "we" or the "Company". All intercompany balances and transactions have been eliminated in consolidation. See Note 12 for additional information regarding our three segments. Certain immaterial reclassifications have been made to prior year information to conform to the current year presentation.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include unbilled utility revenues, collectability of accounts receivable, depreciable lives, asset impairment and goodwill impairment evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation, and tax provisions. Actual amounts could differ from those estimates.
Accounting for the Effects of Regulation	Accounting for the Effects of Regulation In accordance with the Accounting Standard Codification (ASC) guidance for regulated operations, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the APSC and the FERC). We record a regulatory asset for all or part of an incurred cost that would otherwise be charged to expense in accordance with the ASC guidance for regulated operations which says that an asset should be recorded if it is probable that future revenue in an amount at least equal to the capitalized cost will be allowable for costs for rate making purposes and the current available evidence indicates that future revenue will be provided to permit recovery of the cost. This guidance also indicates that a liability should be recorded when a regulator has provided current recovery for a cost that is expected to be incurred in the future. We follow this guidance for incurred costs or credits that are subject to future recovery from or refund to our customers in accordance with the orders of our regulators. Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory assets and liabilities are ratably amortized through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues. We generally include amortization of regulatory assets and liabilities in the depreciation and amortization line of our statement of cash flows. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC guidance for regulated operations with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of this guidance based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations. (See Note 3 for further discussion of regulatory assets and liabilities)
Revenue Recognition	Revenue Recognition For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer classes.
Municipal Franchise Taxes	Municipal Franchise Taxes Municipal franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other taxes in the Consolidated Statements of Income. Municipal franchise taxes of $11.4 million, $11.8 million and $11.2 million were recorded for each of the years ended December 31, 2015, 2014 and 2013, respectively.
Accounts Receivable	Accounts Receivable Accounts receivable are recorded at the tariffed rates for customer usage, including applicable taxes and fees and do not bear interest. We review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered.
Property, Plant & Equipment	Property, Plant & Equipment The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material, an allocation of general and administrative costs, and an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of and the costs of removal are charged to accumulated depreciation, unless the removed property constitutes an operating unit or system. In this case a gain or loss is recognized upon the disposal of the asset. Maintenance expenditures and the removal of minor property items are charged to income as incurred. A liability is created for any additions to electric or gas utility property that are paid for by advances from developers. For a period of five years we refund to the developer a pro rata amount of the original cost of the extension for each new customer added to the extension. Nonrefundable payments at the end of the five year period are applied as a reduction to the cost of the plant in service. The liability as of December 31, 2015 and 2014 was $2.1 million and $1.9 million, respectively.
Depreciation	Depreciation Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by regulatory authorities. These rates are applied to the various classes of utility assets on a composite basis. Provisions for depreciation for our other segment are computed at straight-line rates over the estimated useful life of the properties (See Note 2 for additional details regarding depreciation rates). As of December 31, 2015 and 2014, we had recorded accrued cost of removal of $85.4 million and $82.8 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, 2015 and 2014 was $8.8 million and $7.7 million, respectively. These amounts are net of our actual cost of removal expenditures.
Asset Retirement Obligation	Asset Retirement Obligation We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value. We have identified asset retirement obligations associated with the future removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We also have a solid waste land fill at the Plum Point Energy Station, and asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. As a result of the fuel use transition from coal to natural gas at the Riverton Power Plant, the closure of the Riverton ash landfill was completed, and the related asset retirement obligation was settled during 2014 (Note 11). During 2015 the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs). As a result of these new rules, an asset retirement obligation of $5.4 million has been recorded for the final closure of the existing ash impoundment at our Asbury Power Plant. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station. In addition, we have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB) contaminants associated with our transformers and substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures for the removal of similar past liabilities. The potential costs of these future expenditures are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. This liability will be accreted over the period up to the estimated settlement date. All of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 4.5% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. During 2014 the liability for asbestos at the Riverton Power Plant was re-evaluated. Changes in the cost estimates and timing resulted in cash flow revisions for these liabilities. The balances at the end of 2015 and 2014 are shown below. (000's) Liability Balance 12/31/14 Liabilities Recognized Liabilities Settled Accretion Cash Flow Revisions Liability Balance at 12/31/15 Asset Retirement Obligation $ $ $ ) $ $ — $ (000's) Liability Balance 12/31/13 Liabilities Recognized Liabilities Settled Accretion Cash Flow Revisions Liability Balance at 12/31/14 Asset Retirement Obligation $ $ — $ ) $ $ $ 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, 2015 and 2014, our regulatory assets relating to asset retirement obligations totaled $7.7 million and $5.1 million, respectively. Also as noted previously under property, plant and equipment, we reclassify the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset retirement obligation under this guidance, from accumulated depreciation to a regulatory liability. This balance sheet reclassification has no impact on results of operations.
Allowance for Funds Used During Construction	Allowance for Funds Used During Construction As provided in the FERC regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction (AFUDC) when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds applicable to construction programs are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials. AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation. In accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 5.5% for 2015, 6.6% for 2014, and 7.3% for 2013, compounded semiannually.
Asset Impairments (excluding goodwill)	Asset Impairments (excluding goodwill) We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on undiscounted forecasted cash flows to assess the recoverability of the assets and, if necessary, the fair value is determined to measure the impairment amount. None of our assets were impaired as of December 31, 2015 and 2014.
Goodwill	Goodwill As of December 31, 2015, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and income approaches is used to estimate the fair value of goodwill. We use the market approach which estimates fair value of the gas reporting unit by comparing certain financial metrics to comparable companies. Comparable companies whose securities are actively traded in the public market are judgmentally selected by management based on operational and economic similarities. We utilize EBITDA (earnings before interest, taxes, depreciation, and amortization) multiples of the comparable companies in relation to the EBITDA results of the gas reporting unit to determine an estimate of fair value. We also utilize a valuation technique under the income approach which estimates the discounted future cash flows of operations. Our procedures include developing a baseline test and performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering those assumptions which are subjective in nature and inherent to a discounted cash flows calculation. Other qualitative factors and comparisons to industry peers are also used to further support the assumptions and ultimately the overall evaluation. A key qualitative assumption considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for the gas reporting unit. Some of the key quantitative assumptions included in our tests involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. If negative changes occurred to one or more key assumptions, an impairment charge could result. With the exception of the capital spending rate, the key assumptions noted are significantly determined by market factors and significant changes in market factors that impact the gas reporting unit would somewhat be mitigated by our current and future regulatory rate design. Other risks and uncertainties affecting these assumptions include: changes in business, industry, laws, technology and economic conditions. Actual results for the gas reporting unit indicate a slight decline in gas customer count and demand. A continued decline in customer count or demand coupled with an increase in the discount rate would have adverse impacts on the valuation and could result in an impairment charge in the future. Our forecasts anticipate relatively flat customer counts over the next several years. We weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of October 2015 indicated the estimated fair market value of the gas reporting unit to be $18 – $22 million higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or decline in the terminal value calculation could lead to an impairment charge in the future.
Fuel and Purchased Power	Fuel and Purchased Power Electric Segment Fuel and purchased power costs are recorded at the time the fuel is used, or the power purchased. SPP Integrated Marketplace purchased power is also included in fuel and purchased power costs. The net effects of our SPP IM activity, including SPP IM net revenue and net purchased power costs, flow through our fuel recovery mechanisms in each state. In our Missouri jurisdiction, the MPSC establishes a base cost for the recovery of fuel and purchased power expenses used to supply energy for our fuel adjustment clause (FAC). Beginning with our 2015 rate order, certain transmission costs are also included in the base cost. The FAC permits the distribution to customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, nearly the entire off-system sales margin flows back to the customer. Rates related to the fuel adjustment clause are modified twice a year subject to the review and approval by the MPSC. In accordance with the ASC guidance for regulated operations, 95% of the difference between the actual costs of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered from or refunded to our customers when the fuel adjustment clause is modified. In our Kansas jurisdiction, the costs of fuel are recovered from customers through a fuel adjustment clause, based upon estimated fuel costs and purchased power. The adjustments are subject to audit and final determination by regulators. The difference between the costs of fuel used and the cost of fuel recovered from our Kansas customers is recorded as a regulatory asset or a regulatory liability if the actual costs are higher or lower than the costs billed to customers, in accordance with the ASC guidance for regulated operations. Similar fuel recovery mechanisms are in place for our Oklahoma, Arkansas and FERC jurisdictions. At December 31, 2015 and 2014, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net over-recovered position by $5.9 million and a net under-recovered position of $3.1 million, respectively, which are reflected in our regulatory assets and liabilities. We receive the renewable attributes associated with the power purchased through our purchased power agreements with Elk River Windfarm LLC and Cloud County Windfarm, LLC. These renewable attributes are converted into renewable energy credits (REC), which are considered inventory, and recorded at zero cost (See Note 11). Revenue from the sale of RECs reduces fuel and purchased power expense. We have a Stipulation and Agreement with the MPSC granting us authority to manage our emissions allowance inventory in accordance with our Plan for Purchasing and Selling Emissions Allowances (PPSEMA). The PPSEMA allows us to purchase allowances needed for compliance, exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell allowances outright for monetary value. For compliance year 2015 we did not exchange or sell any allowances, and for compliance year 2014 we purchased 69 NOx annual allowances for compliance. 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 the following emissions allowances in inventory at December 31, 2015 and 2014: Emission Allowances in Inventory 2015 2014 Acid Rain SO2 CSAPR SO2 — CSAPR NOx (annual) — CSAPR NOx (seasonal) — Gas Segment Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery allowed in rates. A Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and related carrying costs associated with the Company's use of natural gas financial instruments to hedge the purchase price of natural gas. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year. We calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC. Elements considered part of the PGA factor include cost of gas supply, storage costs, hedging contracts, revenue and refunds, prior period adjustments and transportation costs. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and carrying costs associated with the use of financial instruments) are reflected as a regulatory asset or liability. The balance is amortized as amounts are reflected in customer billings.
Derivatives	Derivatives We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel in our electric business or sold in our natural gas business, on the spot market and to manage certain interest rate exposure. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we purchase from the SPP Integrated Marketplace (see Note 14). Electric Segment Pursuant to the ASC guidance on accounting for derivative instruments and hedging activities, derivatives are required to be recognized on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability ("cash-flow" hedge); or (2) an instrument that is held for non-hedging purposes (a "non-hedging" instrument). We record the mark-to-market gains or losses on derivatives used to hedge our fuel and congestion costs as regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism. We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts, if they meet the definition of a derivative, are not subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions. If these transactions don't qualify for NPNS treatment, they would be marked to market for each reporting period through regulatory assets or liabilities. Gas Segment Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because we have a commission approved natural gas cost recovery mechanism (PGA), we record the mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/liability account. The regulatory asset/liability account tracks the difference between revenues billed to customers for natural gas costs and actual natural gas expense which is trued up at the end of August each year and included in the Actual Cost Adjustment (ACA) factor to be billed to customers during the next year. This is consistent with the ASC guidance on regulated operations, in that we will be recovering our costs after the annual true up period (subject to a prudency review by the MPSC). Cash flows from hedges for both electric and gas segments are classified within cash flows from operations.
Pension and Other Postretirement Benefits	Pension and Other Postretirement Benefits We recognize expense related to pension and other postretirement benefits (OPEB) as earned during the employee's period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the projected benefit obligation. Our pension and OPEB expense or benefit includes amortization of previously unrecognized net gains or losses. Additional income or expense may be recognized when our unrecognized gains or losses as of the most recent measurement date exceed 10% of our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits and OPEB benefits, unrecognized net gains or losses as of the measurement date are amortized into actuarial expense over ten years. Pensions We have rate orders with Missouri, Kansas and Oklahoma that allow us to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate orders, we prospectively calculate the value of plan assets using a market-related value method as allowed by the ASC guidance on pension benefits. As a result, we are allowed to record the Missouri, Kansas and Oklahoma portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively. The MPSC has allowed us to adopt this pension cost recovery methodology for EDG as well. Other Postretirement Benefits (OPEB) We have regulatory treatment for our OPEB costs similar to the treatment described above for pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into actuarial expense over ten years and the recognition of regulatory assets and liabilities as described above. Additional guidance in the ASC on employers' accounting for defined benefit pension and other postretirement plans requires an employer to recognize the over funded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The guidance also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. Pension and other postretirement employee benefits tracking mechanisms are utilized to allow for future rate recovery of these obligations. We record these as regulatory assets on the balance sheet rather than as reductions of equity through comprehensive income (See Note 7).
Unamortized Debt Discount, Premium and Expense	Unamortized Debt Discount, Premium and Expense Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices.
Liability Insurance	Liability Insurance We are primarily self-insured for workers' compensation claims, general liabilities, benefits paid under employee healthcare programs and long-term disability benefits. Accruals are primarily based on the estimated undiscounted cost of claims. We self-insure up to certain limits that vary by segment and type of risk. Periodically, we evaluate the level of insurance coverage over the self-insured limits and adjust insurance levels based on risk tolerance and premium expense. We carry excess liability insurance for workers' compensation and public liability claims for our electric segment. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. Our gas segment is covered by excess liability insurance for public liability claims, and workers' compensation claims are covered by a guaranteed cost policy (See Note 11).
Other Noncurrent Liabilities	Other Noncurrent Liabilities Other noncurrent liabilities are comprised of accruals and other accounting estimates not sufficiently large enough to merit individual disclosure. At December 31, 2015, the balance of other noncurrent liabilities is primarily comprised of accruals for self-insurance, customer advances for construction and asset retirement obligations.
Cash & Cash Equivalents	Cash & Cash Equivalents Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities and were $23.2 million and $28.3 million at December 31, 2015 and 2014, respectively.
Restricted Cash	Restricted Cash As part of our Plum Point ownership agreement, we are required to have funds available in an escrow account which guarantees payment of certain operating costs. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts restricted, which were $1.8 million at December 31, 2015 and 2014, may increase or decrease based on an annual review. We are required to post cash collateral with Southwest Power Pool (SPP) to participate in Transmission Congestion Rights (TCR) auctions. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $2.5 million at December 31, 2015 and 2014. Due to our Plum Point energy station interconnection with Midcontinent Independent System Operator (MISO), we participate in Financial Transmission Rights (FTR) auctions which require us to post cash collateral. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $0.5 million at December 31, 2015 and 2014.
Fuel, Materials and Supplies	Fuel, Materials and Supplies Fuel, materials and supplies consist primarily of coal, natural gas in storage and materials and supplies, which are reported at average cost. These balances are as follows (in thousands): 2015 2014 Electric fuel inventory $ $ Natural gas inventory Materials and supplies ​ ​ ​ ​ ​ ​ ​ ​ TOTAL $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Income Taxes	Income Taxes Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes; measured using statutory tax rates (See Note 9). Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. The longest remaining amortization period for investment tax credits is approximately 55 years.
Accounting for Uncertainty in Income Taxes	Accounting for Uncertainty in Income Taxes In 2006, the FASB issued guidance which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with the ASC guidance on accounting for income taxes. We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2010. At December 31, 2015 and 2014, our balance sheet did not include any unrecognized tax benefits. We do not expect any material changes to unrecognized tax benefits within the next twelve months. We recognize interest and penalties, if any, related to unrecognized tax benefits in other expenses.
Computations of Earnings Per Share	Computations of Earnings Per Share The ASC guidance on earnings per share requires dual presentation of basic and diluted earnings per share. Basic earnings per share does not include potentially dilutive securities and is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share assumes the issuance of common shares pursuant to the Company's stock-based compensation plans at the beginning of each respective period, or at the date of grant or award if later. Shares attributable to stock options are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. 2015 2014 2013 Weighted Average Number Of Shares Basic Dilutive Securities: Performance-based restricted stock awards Employee stock purchase plan Stock options — — Time-based restricted stock awards ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total dilutive securities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Diluted weighted average number of shares ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Antidilutive Shares Potentially dilutive shares are not expected to have a material impact unless significant appreciation of the Company's stock price occurs.
Stock-Based Compensation	Stock-Based Compensation We have several stock-based compensation plans, which are described in more detail in Note 8. In accordance with the ASC guidance on stock-based compensation, we recognize compensation expense over the requisite service period of all stock-based compensation awards based upon the fair-value of the award as of the date of issuance.
Recently Issued and Proposed Accounting Standards	Recently Issued and Proposed Accounting Standards Revenue from contracts with customers: In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In July 2015, the FASB approved a one year delay in the standard's effective date. The new standard is now effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard. Extraordinary and unusual items: In January 2015, the FASB issued revised guidance that eliminates from GAAP the concept of extraordinary items. Under the revised guidance, an entity will no longer be required to separately classify, present and disclose events or transactions that are determined to be both unusual in nature and infrequent in occurrence. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity. Presentation of debt issuance costs: In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. As of December 31, 2015, we expect that the implementation of this standard would reduce both assets and liabilities by approximately $8.7 million. The application of this standard is not expected to have a material impact on our results of operations or liquidity. Balance sheet classification of deferred taxes: In November 2015, the FASB issued revised guidance addressing the classification of deferred taxes. Under the revised guidance all deferred tax assets and liabilities will be classified as noncurrent in a classified statement of financial position. The revised guidance is effective for interim and annual periods beginning after December 15, 2016, however early adoption is permitted. As of December 31, 2015, we have retrospectively adopted this standard. The application of this guidance resulted in $19.2 million in current deferred tax assets being reclassified from prepaid expenses and other to deferred income taxes (noncurrent) on the December 31, 2014 Consolidated Balance Sheet. Recognition and measurement of financial assets and financial liabilities: In January 2016, the FASB issued revised guidance addressing the recognition, measurement, presentation and disclosure of financial instruments. Under the revised guidance all equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are to be measured at fair value with the changes in fair value recognized in net income. The amended guidance also addresses the impairment assessment of some equity investments, as well as disclosure requirements. The revised guidance is effective for interim and annual periods beginning after December 15, 2017. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

SUMMARY OF SIGNIFICANT ACCOUN26

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Schedule of gross operating revenues by segments	Our gross operating revenues in 2015 were derived as follows: Electric segment sales* % On-system revenues % SPP IM revenues Other revenues Gas segment sales Other segment sales * Sales from our electric segment include 0.3% from the sale of water.
Operating revenues
Schedule of asset retirement obligation	(000's) Liability Balance 12/31/14 Liabilities Recognized Liabilities Settled Accretion Cash Flow Revisions Liability Balance at 12/31/15 Asset Retirement Obligation $ $ $ ) $ $ — $ (000's) Liability Balance 12/31/13 Liabilities Recognized Liabilities Settled Accretion Cash Flow Revisions Liability Balance at 12/31/14 Asset Retirement Obligation $ $ — $ ) $ $ $
Schedule of inventory emission allowances	Emission Allowances in Inventory 2015 2014 Acid Rain SO2 CSAPR SO2 — CSAPR NOx (annual) — CSAPR NOx (seasonal) —
Schedule of fuel, materials and supplies	These balances are as follows (in thousands): 2015 2014 Electric fuel inventory $ $ Natural gas inventory Materials and supplies ​ ​ ​ ​ ​ ​ ​ ​ TOTAL $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of weighted average number of shares	2015 2014 2013 Weighted Average Number Of Shares Basic Dilutive Securities: Performance-based restricted stock awards Employee stock purchase plan Stock options — — Time-based restricted stock awards ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total dilutive securities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Diluted weighted average number of shares ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Antidilutive Shares
Electric
Operating revenues
Schedule of operating revenues by major customer classes	Our electric operations serve approximately 170,000 customers as of December 31, 2015, and the 2015 electric operating revenues were derived as follows: Customer Class % of revenue Residential % Commercial Industrial Wholesale on-system Wholesale off-system Miscellaneous sources, primarily public authorities Other electric revenues
Schedule of operating revenues, by jurisdiction	Our retail electric revenues for 2015 by jurisdiction were as follows: Jurisdiction % of revenue Missouri % Kansas Oklahoma Arkansas
Gas
Operating revenues
Schedule of operating revenues by major customer classes	Our gas operations serve approximately 43,200 customers as of December 31, 2015, and the 2015 gas operating revenues were derived as follows: Customer Class % of revenue Residential % Commercial Industrial Transportation Miscellaneous

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2015
PROPERTY, PLANT AND EQUIPMENT
Summary of property, plant and equipment	Our total property, plant and equipment are summarized below (in thousands). December 31, 2015 2014 Electric plant Production $ $ Transmission Distribution General (1) ​ ​ ​ ​ ​ ​ ​ ​ Electric plant Less accumulated depreciation and amortization (2) ​ ​ ​ ​ ​ ​ ​ ​ Electric plant net of depreciation and amortization Construction work in progress ​ ​ ​ ​ ​ ​ ​ ​ Net electric plant Water plant Less accumulated depreciation and amortization ​ ​ ​ ​ ​ ​ ​ ​ Water plant net of depreciation and amortization Construction work in progress ​ ​ ​ ​ ​ ​ ​ ​ Net water plant ​ ​ ​ ​ ​ ​ ​ ​ Net electric segment plant Gas plant Transmission Distribution General (3) ​ ​ ​ ​ ​ ​ ​ ​ Gas Plant Less accumulated depreciation and amortization ​ ​ ​ ​ ​ ​ ​ ​ Gas plant net of accumulated depreciation Construction work in progress ​ ​ ​ ​ ​ ​ ​ ​ Net gas plant Other Fiber Less accumulated depreciation and amortization ​ ​ ​ ​ ​ ​ ​ ​ Non-regulated net of depreciation and amortization Construction work in progress ​ ​ ​ ​ ​ ​ ​ ​ Net non-regulated property ​ ​ ​ ​ ​ ​ ​ ​ TOTAL NET PLANT AND PROPERTY $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Includes intangible property of $39.8 and $41.2 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2015 and 2014 was $15.6 and $15.7 million, respectively. (2) As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are not reflected here. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail. (3) Includes intangible property of $0.9 and $0.7 million as of December 31, 2015 and 2014, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2015 and 2014 was $0.6 million and $0.5 million, respectively.
Summary of total provision for depreciation and the depreciation rates for continuing operations	The table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended December 31 (in thousands): 2015 2014 2013 Provision for depreciation Regulated — Electric and Water (1) $ $ $ Regulated — Gas (1) Non-Regulated ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL Amortization ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) A portion of this amount is reclassified to a regulatory liability for the cost of removal. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail. 2015 2014 2013 Annual depreciation rates Electric and water % % % Gas % % % Non-Regulated % % % TOTAL COMPANY % % %
Summary of average depreciation rate for each class of assets	2015 2014 2013 Annual Weighted Average Depreciation Rate Electric fixed assets: Production plant % % % Transmission plant % % % Distribution plant % % % General plant % % % Water % % % Gas % % % Non-regulated % % %

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 Regulatory Assets: Current: Under recovered fuel costs $ $ Current portion of long-term regulatory assets ​ ​ ​ ​ ​ ​ ​ ​ Regulatory assets, current ​ ​ ​ ​ ​ ​ ​ ​ Long-term: Pension and other postretirement benefits (1) Income taxes Deferred construction accounting costs (2) Unamortized loss on reacquired debt Unsettled derivative losses — electric segment System reliability — vegetation management Storm costs (3) Asset retirement obligation Customer programs Missouri solar initiative — Current portion of long-term regulatory assets ) ) Other ​ ​ ​ ​ ​ ​ ​ ​ Regulatory assets, long-term ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Liabilities Current: Over recovered fuel costs $ $ Current portion of long-term regulatory liabilities ​ ​ ​ ​ ​ ​ ​ ​ Regulatory liabilities, current ​ ​ ​ ​ ​ ​ ​ ​ Long-term: Costs of removal (4) SWPA payment for Ozark Beach lost generation Income taxes Deferred construction accounting costs — fuel (5) Unamortized gain on interest rate derivative Pension and other postretirement benefits Over recovered fuel costs System reliability — vegetation management — Current portion of long-term regulatory liabilities ) ) Other — ​ ​ ​ ​ ​ ​ ​ ​ Regulatory liabilities, long-term ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Primarily consists of unfunded pension and OPEB liability. See Note 7. (2) Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants. (3) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $2.9 million at December 31, 2015. (4) As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are reflected here. See the depreciation discussion under Note 1 and Note 2 Property, Plant and Equipment for more detail. (5) Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.
Schedule of electric and water rate increases	The following table sets forth information regarding electric and water rate increases since January 1, 2013: Jurisdiction Date Requested Annual Increase Granted Percent Increase Granted Date Effective Missouri — Electric August 29, 2014 $ % July 26, 2015 Kansas — Electric December 5, 2014 $ % June 1, 2015 Arkansas — Electric February 23, 2015 $ % February 23, 2015 Kansas — Electric January 22, 2015 $ % February 23, 2015 Arkansas — Electric December 3, 2013 $ % September 26, 2014 Missouri — Electric July 6, 2012 $ % April 1, 2013
Schedule of new highway/byway cost allocation methodology	Transmission Project Voltage Regional Funding Percentage Zonal Funding Percentage 300 kV and Above % % 100kV to 299kV % % Below 100 kV % %

SHAREHOLDERS' EQUITY (Tables)

SHAREHOLDERS' EQUITY (Tables)	12 Months Ended
	Dec. 31, 2015
SHAREHOLDERS' EQUITY
Schedule of diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance	(in millions, except per share amounts) 2015 2014 2013 Diluted earnings per share $ $ $ Dividends paid per share $ $ $ Total dividends paid $ $ $ Retained earnings year-end balance $ $ $

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
LONG-TERM DEBT.
Schedule of long-term debt outstanding	At December 31, 2015 and 2014, the balance of long-term debt outstanding was as follows (in thousands): 2015 2014 First mortgage bonds (EDE): 7.20% Series due 2016 $ $ 6.375% Series due 2018 (1) 4.65% Series due 2020 (1) 3.58% Series due 2027 (1) 3.59% Series due 2030 (1) — 3.73% Series due 2033 (1) 5.875% Series due 2037 (1) 5.20% Series due 2040 (1) 4.32% Series due 2043 (1) 4.27% Series due 2044 (1) First mortgage bonds (EDG): 6.82% Series due 2036 (1) ​ ​ ​ ​ ​ ​ ​ ​ Senior Notes, 6.70% Series due 2033 (1) Senior Notes, 5.80% Series due 2035 (1) Capital lease obligations Less unamortized net discount ) ) ​ ​ ​ ​ ​ ​ ​ ​ Less current obligations of long-term debt ) — Less current obligations under capital lease ) ) ​ ​ ​ ​ ​ ​ ​ ​ TOTAL LONG-TERM DEBT $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (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 (Excluding Unamortized Discount) (in thousands) Total Regulated Entity Debt Obligations Capital Lease Obligations 2016 $ $ $ 2017 — 2018 2019 — 2020 Thereafter ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total long-term debt obligations $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Less current obligations and unamortized discount ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL LONG-TERM DEBT $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

SHORT-TERM BORROWINGS (Tables)

SHORT-TERM BORROWINGS (Tables)	12 Months Ended
	Dec. 31, 2015
SHORT-TERM BORROWINGS
Schedule of the entity's average short-term borrowings outstanding	At December 31, 2015, total short-term borrowings consisted of $25.0 million in commercial paper and no borrowings under our line of credit. During 2015 and 2014 our short-term borrowings outstanding averaged (in millions) 2015 2014 Average borrowings outstanding $ $ Highest month end balance $ $
Schedule of weighted average interest rates and the weighted average interest rate of borrowings outstanding	2015 2014 Weighted average interest rate % % Weighted average interest rate of borrowings outstanding % %

RETIREMENT AND OTHER EMPLOYEE32

RETIREMENT AND OTHER EMPLOYEE BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2015
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Schedule of the Company's benefit plans' projected benefit obligations	The following table set forth the Company's benefit plans' projected benefit obligations (in thousands). Pension SERP OPEB Reconciliation of Projected Benefit Obligations: 2015 2014 2015 2014 2015 2014 Benefit obligation at beginning of year $ $ $ $ $ $ Service cost Interest cost Amendments — ) — ) — — Net actuarial (gain)/loss ) ) Plan participant's contribution — — — — Benefits and expenses paid ) ) ) ) ) ) Federal subsidy — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Benefit obligation at end of year $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of fair value of the plans' assets	The following table set forth the fair value of the plans' assets (in thousands). Pension SERP OPEB Reconciliation of Fair Value of Plan Assets: 2015 2014 2015 2014 2015 2014 Fair value of plan assets at beginning of year $ $ $ — $ — $ $ Actual return on plan assets — gain/(loss) ) — — ) Employer contribution — — Benefits paid ) ) — — ) ) Plan participant's contribution — — — — Federal subsidy — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair value of plan assets at end of year $ $ $ — $ — $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of the funded status	The following table set forth the fair value of the funded status (in thousands). Pension SERP OPEB Reconciliation of Funded Status: 2015 2014 2015 2014 2015 2014 Fair value of plan assets $ $ $ — $ — $ $ Projected benefit obligations ) ) ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Funded status $ ) $ ) $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of employee pension plan accumulated benefit obligation	The employee pension plan accumulated benefit obligation at December 31, 2015 and 2014 is presented in the following table (in thousands): Pension Benefits SERP 2015 2014 2015 2014 Accumulated benefit obligation $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of amounts recognized in the balance sheet	Amounts recognized in the balance sheet consist of (in thousands): Pension SERP OPEB 2015 2014 2015 2014 2015 2014 Accounts Payable and Accrued Liabilities $ — $ — $ $ $ $ Pension and other postretirement benefit obligation $ $ $ $ $ $
Schedule of net periodic benefit pension cost	Net periodic benefit pension cost for 2015, 2014 and 2013, 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): Pension OPEB Net Periodic Pension Benefit Cost: 2015 2014 2013 2015 2014 2013 Service cost $ $ $ $ $ $ Interest cost Expected return on plan assets ) ) ) ) ) ) Amortization of prior service cost/(benefit) (1) ) ) ) ) Amortization of actuarial loss (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net periodic benefit cost $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ SERP Net Periodic Pension Benefit Cost: 2015 2014 2013 Service cost $ $ $ Interest cost Expected return on plan assets — — — Amortization of prior service cost/(benefit)t (1) ) ) ) Amortization of actuarial loss (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net periodic benefit cost $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.
Schedule of activity in the regulatory asset accounts	The tables below present other changes in plan assets and benefit obligations recognized in the regulatory asset accounts for the year (in thousands). Amount Recognized Regulatory Assets Beginning Balance 12/31/14 Current Year Actuarial Loss Amortization of Actuarial Loss Current Year Prior Service Credit Amortization of Prior Service (Cost)/Credit Ending Balance 12/31/15 Pension $ ) — $ SERP $ ) — $ OPEB $ ) ) — $ Amount Recognized Regulatory Assets Beginning Balance 12/31/13 Current Year Actuarial Loss Amortization of Actuarial Loss Current Year Prior Service Credit Amortization of Prior Service (Cost)/Credit Ending Balance 12/31/14 Pension $ ) ) ) $ SERP $ ) ) $ OPEB $ ) — $
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, 2015, and the subsequent twelve-month period (in thousands): Pension Benefits SERP OPEB 2015 Subsequent Period 2015 Subsequent Period 2015 Subsequent Period Net actuarial loss $ $ $ $ $ $ Prior service cost (benefit) ) ) ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of assumptions used to determine the benefit obligation	Weighted-average assumptions used to determine the benefit obligation as of December 31: Pension Benefits OPEB 2015 2014 2015 2014 Discount rate % % % % Rate of compensation increase % % % %
Schedule of assumptions used to determine the periodic costs	Weighted-average assumptions used to determine the net benefit cost (income) as of January 1: Pension Benefits OPEB 2015 2014 2013 2015 2014 2013 Discount rate % % % % % % Expected return on plan assets % % % % % % Rate of compensation increase % % % % % %
Schedule of employee stock purchase plan	2015 2014 2013 Subscriptions outstanding at December 31, Maximum subscription price $ (1) $ $ Shares of stock issued Stock issuance price $ $ $ (1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2015 to May 31, 2016.
Schedule of assumptions used in valuation of shares under employee stock purchase plan	2015 2014 2013 Weighted average fair value of grants $ $ $ Risk-free interest rate % % % Dividend yield % % % Expected volatility (1) % % % Expected life in months Grant date 6/1/2015 6/2/2014 6/1/2013 (1) One-year historic volatility
Schedule of shares contributed under 401(k) plan and ESOP	2015 2014 2013 Shares contributed
Pension Benefits
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Schedule of expected benefit payments	Expected benefit payments are as follows (in millions): Year Payments from Trust Payments from Company Funds 2016 $ $ 2017 2018 2019 2020 2021 – 2025
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, 2015 and December 31, 2014 (in thousands): Fair Value Measurements as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Percentage of Plan Assets Short term investments $ — $ $ — $ % Equity securities Common collective trusts — domestic — — % Common collective trusts — international % Fixed income Common collective trust — — % Other types of investments Equity long/short hedge funds — — % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ $ $ % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements as of December 31, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Percentage of Plan Assets Short term investments $ — $ $ — $ % Equity securities Common collective trusts — domestic — — % Common collective trusts — international % Fixed income Common collective trust — — % Other types of investments Equity long/short hedge funds — — % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ $ $ % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of fair value measurements using significant unobservable inputs (level 3)	Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — December 31, 2015 2014 Equity long/short hedge funds Equity long/short hedge funds Beginning Balance, January 1, $ $ Actual return on plan assets: Relating to assets still held at the reporting date ) Relating to assets sold during the period — Purchases — Sales — ) Settlements — — Transfers into and (out of) Level 3 — — ​ ​ ​ ​ ​ ​ ​ ​ Ending Balance, December 31, $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of permissible investments	Permissible Investments Equity Oriented Fixed Income Oriented and Real Estate  Common Stocks  Preferred Stocks (minimum "A-rated" by Moody's or S&P)  American Depository Receipts  Convertible Preferred Stocks  Convertible Bonds  Covered Options  Hedged Equity Funds of Funds  Bonds (including US Government and Agencies)  Corporate Bonds (minimum quality rating of Baa by Moody's or BBB by S&P)  Comingled bond funds (25% max. allocation to high yield)  Foreign Government Bonds  GIC's, BIC's  Commercial Paper (rated A1 by S&P or P1 by Moody's)  Certificates of Deposit in institutions with FDIC/FSLIC protection  Money Market Funds/Bank STIF Funds  Real Estate — Publicly Traded The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts. Those investments prohibited by the Investment Committee without prior approval are: Prohibited Investments Requiring Pre-approval  Privately Placed Securities  Commodities Futures  Securities of Empire District (except in the hedged equity funds of funds or commingled funds)  Restricted Stock  Warrants  Short Sales  Index Options  Letter Stock
OPEB
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Schedule of expected benefit payments	Estimated benefit payments are as follows (in millions): Year Payments from Trust Expected Federal Subsidy Payments from Company Funds 2016 $ $ $ 2017 2018 2019 2020 2021 – 2025
Schedule of effect of 1% change in assumed healthcare cost growth rates	The healthcare cost trend rate affects projected benefit obligations. A 1% change in assumed healthcare cost growth rates would have the following effects (in thousands): 1% Increase 1% Decrease Effect on total of service and interest cost $ $ ) Effect on post-retirement benefit obligation $ $ )
Schedule of fund assets measured at fair value	The following fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2014 and December 31, 2013 (in thousands): Fair Value Measurements as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Percentage of Plan Assets Equity securities Common collective trusts $ — $ $ — $ % Fixed income Common collective trusts — — % Other types of investments Common collective trusts — — % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payable for securities purchased ) –0.2 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements as of December 31, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Percentage of Plan Assets Equity securities Common collective trusts $ — $ $ — $ % Fixed income Common collective trusts — — % Other types of investments Common collective trusts — — % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payable for securities purchased ) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of permissible investments	Permissible Investments Equity Fixed Income  Common Stocks  Preferred Stocks  Cash-Equivalent Securities with a maturity of one-year or less, including: money market funds, US Government and Agency securities, certificates of deposit or banker's acceptances issued by domestic banks with FDIC protection and commercial paper rated A1 by S&P or P1 by Moody's  Government Bonds  Money Market Funds / Bank STIF Funds  Certificates of Deposit in institutions with FDIC protection  Corporate Bonds (minimum quality rating of A Baa by Moody's or BBB by S&P at time of issuance) The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts. Listed below are those investments prohibited by the Investment Committee: Prohibited Investments  Privately Placed Securities  Securities of Empire District  Derivatives  Instrumentalities in violation of the Prohibited Transactions Standards of ERISA  Margin Transactions  Options (other than "covered call options")  Lettered or Restricted Stock  Any other investment security which, in the opinion of the investment manager produces an imprudent risk to the fund

EQUITY COMPENSATION (Tables)

EQUITY COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2015
EQUITY COMPENSATION
Schedule of compensation expense and tax benefits for stock-based awards and programs	We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in thousands): 2015 2014 2013 Compensation expense $ $ $ Tax benefit recognized
Schedule of fair value measurements for each grant year	Fair Value of Grants Outstanding at December 31 2015 2014 Total unrecognized compensation cost (in millions) $0.4 $0.4 Recognition period 0.1 years to 2.1 years 1.1 years to 2.1 years Fair value $25.17 $26.82
Schedule of time vested restricted stock activity	2015 2014 2013 Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Number Of Shares Weighted Average Grant Date Fair Value Outstanding at January 1, $ $ $ Granted $ $ $ Distributed ) $ ) $ — — Forfeited ) $ ) $ — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Outstanding at December 31, $ $ $
Schedule of assumptions used in valuation of performance-based restricted stock awards	Fair Value of Grants Outstanding at December 31, 2015 2014 2013 Risk-free interest rate 0.65% to 1.06% 0.25% to 0.67% 0.13% to 0.38% Expected volatility of Empire stock 18.7% 14.5% 20.2% Expected volatility of peer group stock 14.5% to 34.4% 12.4% to 24.8% 12.3% to 27.5% Expected dividend yield on Empire stock 3.7% 3.5% 4.5% Expected forfeiture rates 3% 3% 3% Plan cycle 3 years 3 years 3 years Fair value percentage 115.0% to 182.0% 140.0% to 157.0% 0.0% to 108.0% Weighted average fair value per share $41.73 $43.80 $18.47
Schedule of non-vested performance-based restricted stock awards (based on target number) and changes during the reporting period	2015 2014 2013 Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Number Of Shares Weighted Average Grant Date Fair Value Outstanding at January 1, $ $ $ Target shares granted $ $ $ Shares issued in excess of target $ — — — — Shares awarded ) $ — — ) $ Forfeited shares ) $ — — — Target shares not awarded — — ) $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nonvested at December 31, $ $ $
Schedule of assumptions used in the valuations of stock options	Fair Value of Grants Outstanding at December 31, 2013 Risk-free interest rate 0.10% to 0.38% Dividend yield 4.5% Expected volatility 24.0% Expected life in months 6.5 to 24.5 Market value $22.69 Weighted average fair value per option $1.57
Schedule of stock options activity	2014 2013 Options Weighted Average Exercise Price Options Weighted Average Exercise Price Outstanding at January 1, $ $ Granted — — $ — Exercised $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Outstanding at December 31, — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exercisable, end of year — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of aggregate intrinsic values of stock options	2013 Aggregate intrinsic value (in millions) Less than $0.1 Weighted-average remaining contractual life of outstanding options 2.1 years Range of exercise prices $21.92 to $23.81 Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan — Recognition period —
Schedule of shares accrued to directors' accounts and shares available for issuance under Stock Unit Plan for directors	2015 2014 Shares accrued to directors' accounts Shares available for issuance
Schedule of units accrued and redeemed under Stock Unit Plan for directors	2015 2014 2013 Units accrued for service and dividends Units redeemed for common stock

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
INCOME TAXES.
Schedule of income tax expense components	Income tax expense components for the years ended December 31 are as follows (in thousands): 2015 2014 2013 Current income taxes: Federal $ — $ ) $ State — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL — ) Deferred income taxes: Federal State ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL Investment tax credit amortization ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL INCOME TAX EXPENSE $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
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 2015 2014 NET DEFERRED TAX LIABILITIES $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
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 2015 2014 Deferred tax assets: Plant related basis differences $ $ Net operating loss (NOL) Regulated liabilities related to income taxes Disallowed plant costs Gains on hedging transactions Pensions and other post-retirement benefits — Carry forward of income tax credit Other ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities: Depreciation, amortization and other plant related differences $ $ Regulated assets related to income Loss on reacquired debt Amortization of intangibles Pensions and other post-retirement benefits — Deferred construction accounting costs Other ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax liabilities ​ ​ ​ ​ ​ ​ ​ ​ NET DEFERRED TAX LIABILITIES $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
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 2015 2014 2015 Federal statutory income tax rate % % % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) Investment tax credit amortization ) ) ) Effect of ratemaking on property related differences ) ) ) Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ EFFECTIVE INCOME TAX RATE % % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

COMMONLY OWNED FACILITIES (Tabl

COMMONLY OWNED FACILITIES (Tables)	12 Months Ended
	Dec. 31, 2015
Iatan
COMMONLY OWNED FACILITIES
Schedule of property, plant and equipment	At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions): Iatan 2015 2014 Cost of ownership in plant in service $ $ Accumulated Depreciation $ $ Expenditures (1) $ $ (1) Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.
State Line Combined Cycle Unit
COMMONLY OWNED FACILITIES
Schedule of property, plant and equipment	At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions): State Line Combined Cycle Unit 2015 2014 Cost of ownership in plant in service $ $ Accumulated Depreciation $ $ Expenditures (1) $ $ (1) Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.
Plum point
COMMONLY OWNED FACILITIES
Schedule of property, plant and equipment	At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in the following chart (in millions): Plum Point Energy Station 2015 2014 Cost of ownership in plant in service $ $ Accumulated Depreciation $ $ Expenditures (1) $ $ (1) Recognized in operating, maintenance and fuel expenditures excluding depreciation expense.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2015
COMMITMENTS AND CONTINGENCIES
Schedule of physical gas, coal and transportation contracts	The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of December 31, 2015 (in millions). Firm physical gas and transportation contracts Coal and coal transportation contracts January 1, 2016 through December 31, 2016 $ $ January 1, 2017 through December 31, 2018 January 1, 2019 through December 31, 2020 January 1, 2021 and beyond —
Schedule of lease obligations over the next five years	Our lease obligations over the next five years are as follows (in thousands): Capital Leases Operating Leases 2016 $ $ 2017 2018 2019 2020 — Thereafter — ​ ​ ​ ​ ​ ​ ​ ​ Total minimum payments $ Less amount representing interest ​ ​ ​ ​ ​ ​ ​ ​ Present value of net minimum lease payments $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Summary of most significant environmental regulations affecting operations	Regulations Air Emissions — NOx and SO2 CAIR (Clean Air Interstate Rule) CSAPR (Cross State Air Pollution Rule) MATS (Mercury Air Toxic Standards) NAAQS (National Ambient Air Quality Standards) Greenhouse Gases (GHGs) — CO 2 Surface Impoundments Coal Ash Impoundments: Asbury Power Plant Riverton (capped and closed in 2014 as industrial (coal combustion waste) landfill) Water Discharges

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2015
SEGMENT INFORMATION
Schedule of statement of income information, balance sheet information and capital expenditures by business segments	For the year ended December 31, 2015 Electric Gas Other Eliminations Total Statement of Income Information: Operating Revenues (1) $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Income from continuing operations $ $ $ $ — $ Capital Expenditures $ $ $ $ — $ (1) The Electric Segment includes SPP Integrated Marketplace net revenues of $15.0 million. 2014 Electric Gas Other Eliminations Total Statement of Income Information: Operating Revenues (1) $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Income from continuing operations $ $ $ $ — $ Capital Expenditures $ $ $ $ — $ (1) The Electric Segment includes SPP Integrated Marketplace net revenues of $41.9 million. 2013 Electric Gas Other Eliminations Total Statement of Income Information: Operating Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Income from continuing operations $ $ $ $ — $ Capital Expenditures $ $ $ $ — $ December 31, 2015 Electric Gas (1) Other Eliminations Total Balance Sheet Information: Total assets $ $ $ $ ) $ December 31, 2014 Electric Gas (1) Other Eliminations Total Balance Sheet Information: Total assets $ $ $ $ ) $ (1) Includes goodwill of $39,492 at December 31, 2015 and 2014.

SELECTED QUARTERLY INFORMATIO38

SELECTED QUARTERLY INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2015
SELECTED QUARTERLY INFORMATION (UNAUDITED)
Summary of quarterly results	The following is a summary of quarterly results for 2015 and 2014 (dollars in thousands except per share amounts): Quarters Quarterly Results for 2015 First Second Third Fourth Operating revenues (1) $ $ $ $ Operating income $ $ $ $ Net Income $ $ $ $ Basic Earnings Per Share $ $ $ $ Diluted Earnings Per Share $ $ $ $ (1) Operating revenue for the first, second, third and fourth quarters of 2015 include SPP IM net revenues of $4.7 million, $3.4 million, $4.0 million, and $2.9 million, respectively. Quarters Quarterly Results for 2014 First Second Third Fourth Operating revenues (1) $ $ $ $ Operating income $ $ $ $ Net Income $ $ $ $ Basic and Diluted Earnings Per Share $ $ $ $ (1) Operating revenue for the first, second, third and fourth quarters of 2014 include SPP IM net revenues of $6.2 million, $16.5 million, $11.5 million, and $7.5 million, respectively.

RISK MANAGEMENT AND DERIVATIV39

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS
Schedule of fair value of derivative financial instruments, balance sheet classification	As of December 31, 2015 and 2014, 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 2015 2014 Balance Sheet Classification Fair Value Fair Value Natural gas contracts, gas segment Current assets $ $ — Non-current assets and deferred charges — Other — Natural gas contracts, electric segment Current assets — Non-current assets and deferred charges — Other — — Transmission congestion rights, electric segment Current assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total derivatives assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ LIABILITY DERIVATIVES Non-designated as hedging instruments due to regulatory accounting 2015 2014 Balance Sheet Classification Fair Value Fair Value Natural gas contracts, gas segment Current liabilities $ $ Non-current liabilities and deferred credits — Natural gas contracts, electric segment Current liabilities Non-current liabilities and deferred credits Transmission congestion rights, electric segment Current liabilities — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total derivatives liabilities $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
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 of Gain/(Loss) on Derivative 2015 2014 Commodity contracts — electric segment Regulatory (assets)/liabilities $ ) $ ) Transmission congestion rights — electric segment Regulatory (assets)/liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total — Electric Segment $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 2015 2014 Commodity contracts Fuel and purchased power expense $ ) $ ) Transmission congestion rights — electric segment Fuel and purchased power expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total — Electric Segment $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of volumes and percentage of anticipated volume of natural gas usage for entity's electric operations with procurement guidelines	Year % Hedged Dth Hedged Physical Dth Hedged Financial Average Price 2016 % $ 2017 % $ 2018 % $ 2019 % — $ 2020 % — — —
Schedule of minimum percentage hedged by year in the entity's procurement guidelines	Year End of Year Minimum % Hedged Current Up to 100% First 60% Second 40% Third 20% Fourth 10%
Schedule of transmission congestion rights (TCR)	Year Monthly MWH Hedged $ Value 2016 $
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, 2015 (Dth in thousands). Season Minimum % Hedged Dth Hedged Financial Dth Hedged Physical Dth in Storage Actual % Hedged Current % — % Second Up to 50 % — — % Third Up to 20 % — — %
Schedule of mark-to-market pre-tax gains/(losses) from non-designated derivative instruments - gas segment	The following table sets forth "mark-to-market" pre-tax gains/ (losses) from derivatives not designated as hedging instruments for the gas segment for the years ended December 31 (in thousands): Non-Designated Hedging Instruments Due to Regulatory Accounting — Gas Segment Amount of Loss Recognized on Balance Sheet Balance Sheet Classification of Loss on Derivative 2015 2014 Commodity contracts Regulatory assets $ ) $ ) — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total — Gas Segment $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of margin deposit assets	(in millions) December 31, 2015 December 31, 2014 Margin deposit assets $ $

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
FAIR VALUE MEASUREMENTS
Schedule of transmission congestion rights (TCR) and commodity contracts measured at fair value	Fair Value Measurements at Reporting Date Using ($ in 000's) Description Assets/(Liabilities) at Fair Value Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) December 31, 2015 Derivative assets $ $ $ $ — Derivative liabilities $ ) $ ) $ — $ — December 31, 2014 Derivative assets $ $ $ $ — Derivative liabilities $ ) $ ) $ — $ — * The only recurring measurements are derivative related.

REGULATED OPERATING EXPENSE (Ta

REGULATED OPERATING EXPENSE (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Power operation expense (other than fuel) $ $ $ Electric transmission and distribution expense Natural gas transmission and distribution expense Customer accounts & assistance expense Employee pension expense (1) Employee healthcare plan (1) General office supplies and expense Administrative and general expense Bad debt expense Regulatory reversal of gain on sale of assets — Miscellaneous expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (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 ACCOUN42

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2015segmentcustomeritem
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Number of business segments | segment	3
Number of towns to which water service is provided | item	3
Electric
Operating revenues
% of revenue (as a percent)	91.70%
Number of customers	170,000
Electric | On-system Member
Operating revenues
% of revenue (as a percent)	86.60%
Electric | SPP IM
Operating revenues
% of revenue (as a percent)	2.50%
Electric | Other revenues
Operating revenues
% of revenue (as a percent)	2.30%
Electric | Water
Operating revenues
% of revenue (as a percent)	0.30%
Electric | Missouri
Operating revenues
% of revenue (as a percent)	89.00%
Electric | Kansas
Operating revenues
% of revenue (as a percent)	4.80%
Electric | Arkansas
Operating revenues
% of revenue (as a percent)	3.40%
Electric | Oklahoma
Operating revenues
% of revenue (as a percent)	2.80%
Electric | Residential
Operating revenues
% of revenue (as a percent)	41.70%
Electric | Commercial
Operating revenues
% of revenue (as a percent)	31.10%
Electric | Industrial
Operating revenues
% of revenue (as a percent)	15.90%
Electric | Wholesale on-system
Operating revenues
% of revenue (as a percent)	3.30%
Electric | Wholesale off-system
Operating revenues
% of revenue (as a percent)	2.70%
Electric | Miscellaneous sources, primarily public authorities
Operating revenues
% of revenue (as a percent)	2.80%
Electric | Miscellaneous
Operating revenues
% of revenue (as a percent)	2.50%
Gas
Operating revenues
% of revenue (as a percent)	6.90%
Number of customers	43,200
Gas | Residential
Operating revenues
% of revenue (as a percent)	63.00%
Gas | Commercial
Operating revenues
% of revenue (as a percent)	25.60%
Gas | Industrial
Operating revenues
% of revenue (as a percent)	0.80%
Gas | Transportation
Operating revenues
% of revenue (as a percent)	8.90%
Gas | Miscellaneous
Operating revenues
% of revenue (as a percent)	1.70%
Other
Operating revenues
% of revenue (as a percent)	1.40%

SUMMARY OF SIGNIFICANT ACCOUN43

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Municipal Franchise Taxes
Municipal franchise taxes	$ 11,400	$ 11,800	$ 11,200
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	$ 2,100	1,900
Regulatory Liability [Abstract]
Regulatory liability	141,072	136,369
Electric | Costs of removal
Regulatory Liability [Abstract]
Regulatory liability	85,400	82,800
Gas | Costs of removal
Regulatory Liability [Abstract]
Regulatory liability	$ 8,800	$ 7,700

SUMMARY OF SIGNIFICANT ACCOUN44

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 3)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)item	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)	Oct. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Asset Retirement Obligation
Proportionate ownership interest (as a percent)						12.00%
Change in asset retirement obligation
Asset retirement obligation	$ 15,072,000	$ 4,847,000	$ 4,847,000	$ 4,190,000	$ 4,190,000	$ 15,072,000		$ 4,847,000
Opening balance of asset retirement obligation			4,847,000	4,190,000
Liabilities Recognized			9,812,000
Liabilities settled			(73,000)	(1,175,000)
Accretion			486,000	172,000
Cash Flow Revisions				1,660,000
Closing balance of asset retirement obligation	15,072,000	4,847,000	$ 15,072,000	$ 4,847,000	$ 4,190,000
Regulatory assets						216,760,000		220,469,000
Allowance for Funds Used During Construction
Aggregate rates (on a before-tax basis)			5.50%	6.60%	7.30%
Asset Impairments (excluding goodwill)
Assets impaired	0	$ 0
Goodwill
Number of assumptions whose negative charge will affect impairment | item			1
Number of approaches used to estimate the fair value | item			2
Fuel and Purchased Power
Inventory allowances						0
Pension and Other Postretirement Benefits
Percentage that unrecognized gains or losses must exceed postretirement benefit obligation or fair value of plan assets for recognition of additional income or expense			10.00%
Amortization period of unrecognized gains or losses into actuarial expense			10 years
Cash & Cash Equivalents
Checks and electronic fund transfers that have been issued but not cleared through bank						23,200,000		28,300,000
Restricted Cash
Amounts restricted for operating costs						1,800,000		1,800,000
Asbury Power Plant
Change in asset retirement obligation
Asset retirement obligation	5,400,000		$ 5,400,000			5,400,000
Closing balance of asset retirement obligation	5,400,000		5,400,000
Iatan Generating Station
Change in asset retirement obligation
Asset retirement obligation	4,400,000		4,400,000			4,400,000
Closing balance of asset retirement obligation	$ 4,400,000		$ 4,400,000
SPP
Restricted Cash
Amounts restricted for secured collateral						2,500,000		2,500,000
MISO
Restricted Cash
Amounts restricted for secured collateral						$ 500,000		500,000
Electric
Fuel and Purchased Power
Number of NOx annual allowances purchased for compliance | item				69
Electric | Missouri Public Service Commission (MPSC)
Fuel and Purchased Power
Percentage of changes in fuel and purchased power costs from the base cost permitted for distribution to customers under fuel adjustment clause			95.00%
Gas
Fuel and Purchased Power
Maximum number of rate changes allowed by PGA clause throughout the year | item			4
Low end of range
Asset Retirement Obligation
Credit adjusted risk-free rate (as a percent)						4.50%
Low end of range | Gas
Goodwill
Excess fair value of the reporting unit over carrying value							$ 18,000,000
High end of range
Asset Retirement Obligation
Credit adjusted risk-free rate (as a percent)						5.52%
High end of range | Gas
Goodwill
Excess fair value of the reporting unit over carrying value							$ 22,000,000
Asset retirement obligation.
Change in asset retirement obligation
Regulatory assets						$ 7,700,000		5,100,000
Under recovered fuel costs
Change in asset retirement obligation
Regulatory assets						5,900,000		3,100,000
Acid Rain SO2
Fuel and Purchased Power
Inventory allowances						11,443		$ 872
CSAPR SO2
Fuel and Purchased Power
Inventory allowances						5,861
CSAPR NOx (annual)
Fuel and Purchased Power
Inventory allowances						500
CSAPR Nox (seasonal)
Fuel and Purchased Power
Inventory allowances						$ 241

SUMMARY OF SIGNIFICANT ACCOUN45

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Detail 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fuel, Materials and Supplies
Total	$ 60,950	$ 57,799
Income taxes
Longest remaining amortization period for investment tax credits	55 years
Accounting for Uncertainty in Income Taxes
No material changes to unrecognized tax benefits in other expenses	12 months
Weighted Average Number Of Shares
Basic (in shares)	43,671,000	43,291,000	42,781,000
Dilutive Securities:
Performance-based restricted stock awards (in shares)	19,890	8,809	12,142
Employee stock purchase plan (in shares)	1,249	3,422	1,729
Stock options (in shares)			61
Time-based restricted stock awards (in shares)	25,523	10,666	7,907
Total dilutive securities (in shares)	46,662	22,897	21,839
Diluted weighted average number of shares	43,718,000	43,314,000	42,803,000
Antidilutive Shares	20,289	25,259	107,100
Electric fuel inventory
Fuel, Materials and Supplies
Total	$ 30,185	$ 26,454
Natural gas inventory
Fuel, Materials and Supplies
Total	3,868	5,040
Materials and supplies
Fuel, Materials and Supplies
Total	$ 26,897	$ 26,305

SUMMARY OF SIGNIFICANT ACCOUN46

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 5) - New Accounting Pronouncement, Early Adoption, Effect $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Accounting Standards Update 2015-03 Simplifying the Presentation of Debt Issuance Costs
Recently Issued and Proposed Accounting Standards
Change in financial position	$ 8.7
Accounting Standards Update 2015-11 Balance Sheet Classification of Deferred Taxes
Recently Issued and Proposed Accounting Standards
Change in financial position	$ 19.2

PROPERTY, PLANT AND EQUIPMENT47

PROPERTY, PLANT AND EQUIPMENT (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, plant and equipment
Less accumulated depreciation and amortization	$ 764,895	$ 743,407
Construction work in progress	183,689	112,097
Total plant and property, Net	2,020,386	1,910,272
Plant and property, Gross	83,402	79,364
Plant and property, Gross	44,263	41,394
Provision for depreciation	82,816	72,342	$ 68,893
Amortization	2,858	2,692	2,492
Total depreciation and amortization	$ 85,674	$ 75,034	$ 71,385
Annual depreciation rates (as a percent)	3.20%	3.00%	3.10%
Regulated
Property, plant and equipment
Total plant and property, Net	$ 1,929,423	$ 1,821,772
Non-Regulated
Property, plant and equipment
Provision for depreciation	$ 4,895	$ 1,891	$ 1,938
Annual depreciation rates (as a percent)	4.40%	4.70%	5.00%
Electric plant | Regulated
Property, plant and equipment
Plant and property, Gross	$ 2,460,818	$ 2,408,015
Less accumulated depreciation and amortization	721,883	704,596
Plant and property, net of depreciation and amortization	1,738,935	1,703,419
Construction work in progress	182,585	110,500
Total plant and property, Net	1,921,520	1,813,919
Electric plant | Intangible property, primarily capitalized software and investments in facility upgrades | Regulated
Property, plant and equipment
Plant and property, Gross	39,800	41,200
Less accumulated depreciation and amortization	15,600	15,700
Production | Regulated
Property, plant and equipment
Plant and property, Gross	$ 1,151,395	$ 1,159,140
Annual depreciation rates (as a percent)	2.80%	2.40%	2.40%
Transmission. | Regulated
Property, plant and equipment
Plant and property, Gross	$ 316,038	$ 288,542
Annual depreciation rates (as a percent)	2.40%	2.40%	2.40%
Distribution. | Regulated
Property, plant and equipment
Plant and property, Gross	$ 870,047	$ 840,761
Annual depreciation rates (as a percent)	3.50%	3.60%	3.60%
General | Regulated
Property, plant and equipment
Plant and property, Gross	$ 123,338	$ 119,572
Annual depreciation rates (as a percent)	5.90%	5.80%	5.80%
Gas plant | Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	$ 18,557	$ 16,405
Plant and property, net of depreciation and amortization	64,845	62,959
Construction work in progress	627	379
Total plant and property, Net	65,472	63,338
Plant and property, Gross	83,402	79,364
Provision for depreciation	$ 4,036	$ 3,851	$ 3,763
Annual depreciation rates (as a percent)	5.10%	5.20%	5.40%
Transmission | Regulated
Property, plant and equipment
Plant and property, Gross	$ 8,498	$ 8,269
Distribution | Regulated
Property, plant and equipment
Plant and property, Gross	66,588	63,319
General | Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	600	500
Plant and property, Gross	8,316	7,776
General | Intangible property, primarily capitalized software and investments in facility upgrades | Regulated
Property, plant and equipment
Plant and property, Gross	900	700
Water plant | Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	5,281	5,102
Plant and property, net of depreciation and amortization	7,828	7,707
Construction work in progress	75	146
Total plant and property, Net	7,903	7,853
Plant and property, Gross	$ 13,109	$ 12,809
Annual depreciation rates (as a percent)	2.80%	2.70%	2.80%
Other | Non-Regulated
Property, plant and equipment
Less accumulated depreciation and amortization	$ 19,174	$ 17,304
Plant and property, net of depreciation and amortization	25,089	24,090
Construction work in progress	402	1,072
Total plant and property, Net	25,491	25,162
Fiber | Non-Regulated
Property, plant and equipment
Plant and property, Gross	44,263	41,394
Electric and Water | Regulated
Property, plant and equipment
Provision for depreciation	$ 73,885	$ 66,600	$ 63,192
Annual depreciation rates (as a percent)	3.10%	3.00%	3.00%

REGULATORY MATTERS (Details)

REGULATORY MATTERS (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Aug. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets:
Regulatory assets, current		$ 7,052	$ 10,752
Regulatory assets, long-term		209,708	209,717
Total Regulatory Assets		216,760	220,469
Regulatory Liabilities:
Regulatory liabilities, current		8,615	7,898
Regulatory liabilities, long-term		132,457	128,471
Total Regulatory Liabilities		141,072	136,369
Missouri 2015 Rate Case | Iatan2
Regulatory Assets and Liabilities
Amortizable life tracking mechanism	3 years
Amortizable life tracking mechanism related to vegetation	5 years
Over recovered fuel costs
Regulatory Liabilities:
Regulatory liabilities, current		5,280	4,227
System reliability - vegetation management
Regulatory Liabilities:
Regulatory liabilities, long-term		1,320
Current portion of long-term regulatory liabilities
Regulatory Liabilities:
Regulatory liabilities, current		3,335	3,671
Other
Regulatory Liabilities:
Regulatory liabilities, long-term		56
Costs of removal
Regulatory Liabilities:
Regulatory liabilities, long-term		94,193	90,527
SWPA payment for Ozark Beach lost generation
Regulatory Liabilities:
Regulatory liabilities, long-term		14,213	16,744
Income taxes
Regulatory Liabilities:
Regulatory liabilities, long-term		11,244	11,451
Deferred construction accounting costs - fuel
Regulatory Liabilities:
Regulatory liabilities, long-term		7,690	7,849
Unamortized gain on interest rate derivative
Regulatory Liabilities:
Regulatory liabilities, long-term		$ 3,031	3,201
Unamortized gain on interest rate derivative | High end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		25 years
Unamortized gain on interest rate derivative | Low end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		4 years
Pension and other postretirement benefits
Regulatory Liabilities:
Regulatory liabilities, long-term		$ 1,745	2,369
Over recovered electric fuel and purchased power costs
Regulatory Liabilities:
Regulatory liabilities, long-term		2,300	1
Under recovered fuel costs
Regulatory Assets:
Regulatory assets, current		196	2,618
Total Regulatory Assets		5,900	3,100
Current portion of long-term regulatory assets
Regulatory Assets:
Regulatory assets, current		6,856	8,134
Pension and other postretirement benefits
Regulatory Assets:
Regulatory assets, long-term		$ 108,273	111,121
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		5 years
Portion of regulatory assets expected to be recoverable in future periods		$ 99,000
Income taxes
Regulatory Assets:
Regulatory assets, long-term		48,613	47,177
Deferred construction accounting costs
Regulatory Assets:
Regulatory assets, long-term		14,977	15,521
Unamortized loss on reacquired debt
Regulatory Assets:
Regulatory assets, long-term		$ 9,731	10,405
Unamortized loss on reacquired debt | High end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		25 years
Unamortized loss on reacquired debt | Low end of range
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		4 years
System reliability - vegetation management
Regulatory Assets:
Regulatory assets, long-term		$ 3,604	5,337
Storm costs
Regulatory Assets:
Regulatory assets, long-term		$ 3,531	4,183
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		5 years
Asset retirement obligation.
Regulatory Assets:
Regulatory assets, long-term		$ 7,722	5,145
Total Regulatory Assets		7,700	5,100
Customer programs
Regulatory Assets:
Regulatory assets, long-term		5,942	5,253
Missouri solar initiative
Regulatory Assets:
Regulatory assets, long-term		3,504
Other
Regulatory Assets:
Regulatory assets, long-term		2,892	4,672
Ice storm and tornado cost
Regulatory Assets:
Regulatory assets, long-term		$ 2,900
Asbury five-year maintenance
Regulatory Liabilities:
Regulatory Asset Noncurrent, Amortization Period		5 years
Electric | Costs of removal
Regulatory Liabilities:
Total Regulatory Liabilities		$ 85,400	82,800
Electric | Unsettled derivative losses- electric segment
Regulatory Assets:
Regulatory assets, long-term		7,775	9,037
Gas | Costs of removal
Regulatory Liabilities:
Total Regulatory Liabilities		$ 8,800	$ 7,700

REGULATORY MATTERS (Details 2)

REGULATORY MATTERS (Details 2)

Jan. 22, 2016USD ($)

Jul. 26, 2015USD ($)$ / MWh

Jun. 08, 2015

Jun. 01, 2015USD ($)

Jan. 22, 2015USD ($)

Dec. 05, 2014USD ($)

Oct. 29, 2013item

Jun. 13, 2012

Dec. 31, 2015

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Oct. 16, 2015USD ($)

Feb. 23, 2015USD ($)

Sep. 26, 2014USD ($)

Aug. 29, 2014USD ($)

May. 20, 2014USD ($)

Dec. 03, 2013USD ($)

Apr. 01, 2013USD ($)

RATE MATTERS

Plant Disallowance

$ 86,000

$ 2,409,000

Utilities Operating Expense Reverse Gain on Sale of Assets

$ 44,000

$ 1,236,000

Number of new Missouri demand-side management programs | item

4

Missouri Public Service Commission (MPSC) | Missouri 2015 Rate Case

RATE MATTERS

Net reduction in base fuel and purchased power | $ / MWh

1.60

Fuel Adjustment Charge (in percent)

34

Missouri Public Service Commission (MPSC) | Electric

RATE MATTERS

Approved amount of annual increase in base rate

$ 17,125,000

$ 27,500,000

Approved percentage of annual increase in base rate

3.90%

6.78%

Missouri Public Service Commission (MPSC) | Electric | Missouri 2015 Rate Case

RATE MATTERS

Requested amount of annual increase in base rate

$ 33,400,000

Requested percentage of annual increase in base rate

7.30%

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

RATE MATTERS

Requested amount of annual increase in electric base rate

$ 24,300,000

Percentage of annual base rate increase requested

5.50%

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

RATE MATTERS

Proposed recover costs

$ 860,000

Approved recover costs

$ 780,000

Kansas Corporation Commission (KCC) | Ad Valorem Tax Surcharge

RATE MATTERS

Annual increase related to Ad Valorem taxes

$ 270,000,000

Additional Annual Increase Related To AdValorem Taxes

$ 200,000

Kansas Corporation Commission (KCC) | Electric

RATE MATTERS

Approved amount of annual increase in base rate

$ 782,479

$ 273,455

Approved percentage of annual increase in base rate

4.71%

1.08%

Oklahoma Corporation Commission (OCC) | Electric | High end of range

RATE MATTERS

Customer rate reciprocity who serve less of total customers (in percent)

10

Arkansas Public Service Commission (APSC) | Electric

RATE MATTERS

Approved amount of annual increase in base rate

$ 457,000

$ 1,366,809

Approved percentage of annual increase in base rate

3.35%

11.34%

Arkansas Public Service Commission (APSC) | Electric | Missouri 2014 Rate Case

RATE MATTERS

Requested amount of annual increase in electric base rate

$ 1,375,000

Percentage of annual base rate increase requested

11.00%

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

RATE MATTERS

Requested amount of annual increase in electric base rate

$ 2,200,000

Percentage of annual base rate increase requested

18.00%

Federal Energy Regulatory Commission (FERC) | TFR rate case

RATE MATTERS

Percentage of ROE

10.00%

REGULATORY MATTERS (Details 3)

REGULATORY MATTERS (Details 3) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2012item	Dec. 31, 2015USD ($)	Dec. 31, 2010
RATE MATTERS
Deferred expenses related to rate cases		$ 0.4
SPP Regional Transmission Development
RATE MATTERS
Estimated increase in transmission expenses		$ 1.3
SPP Regional Transmission Development | Low end of range
RATE MATTERS
Transmission Project Voltage (in kV) | item	161
SPP Regional Transmission Development | Transmission projects between 100 kV and 299 kV | Electric
RATE MATTERS
Regional Funding Percentage			33.30%
Zonal Funding Percentage			66.70%
SPP Regional Transmission Development | Transmission projects 300 kV or above | Electric
RATE MATTERS
Regional Funding Percentage			100.00%
Zonal Funding Percentage			0.00%
SPP Regional Transmission Development | Transmission projects below 100 kV | Electric
RATE MATTERS
Regional Funding Percentage			0.00%
Zonal Funding Percentage			100.00%
SPP Day-Ahead Market | Low end of range
RATE MATTERS
Percentage of generation needed for next day throughout SPP territory that will be cleared through Integrated Marketplace		90.00%
SPP Day-Ahead Market | High end of range
RATE MATTERS
Percentage of generation needed for next day throughout SPP territory that will be cleared through Integrated Marketplace		95.00%

SHAREHOLDERS' EQUITY (Details)

SHAREHOLDERS' EQUITY (Details) - USD ($) $ in Millions	Aug. 20, 2015	Dec. 01, 2014	Dec. 13, 2013	Dec. 31, 2015
SHAREHOLDERS' EQUITY
Shelf registration statement, amount			$ 200	$ 200
Maximum amount of securities to be issued in the form of first mortgage bonds				150
Amount that would remain available after giving effect to issuance of first mortgage bonds				$ 30
Issuance of first mortgage bonds	$ 60	$ 60
Effective period to use proceeds under shelf to fund capital expenditures, refinancings of existing debt or general corporate needs			3 years
Employee Stock Purchase Plan
Equity compensation
Shares available for issuance				764,645
2015 Stock Incentive Plan
Equity compensation
Shares available for issuance				496,766
Number of shares of common stock provided for grant				500,000
401 (k) plan and ESOP
Equity compensation
Shares available to be issued				129,616

SHAREHOLDERS' EQUITY (Details 2

SHAREHOLDERS' EQUITY (Details 2)	12 Months Ended
	Dec. 31, 2015USD ($)$ / shares	Dec. 31, 2014USD ($)$ / shares	Dec. 31, 2013USD ($)$ / shares
Dividends
Total earnings per weighted average share of common stock - diluted (in dollars per share | $ / shares	$ 1.29	$ 1.55	$ 1.48
Dividends paid per share (in dollars per share) | $ / shares	$ 1.04	$ 1.025	$ 1.005
Total dividends paid	$ 45,430,000	$ 44,381,000	$ 43,006,000
Retained earnings year-end balance	101,443,000	$ 90,276,000	$ 67,600,000
First quarterly dividend paid excluded from EDE Mortgage covenant	98,000
Cumulative aggregate amount up to which the entity may declare or pay any dividends as per EDE Mortgage covenant	$ 10,750,000
Maximum period for payment of dividend after the related date of declaration or notice of dividend as per EDE Mortgage covenant	60 days
Ratio of total indebtedness to total capitalization	0.625

SHAREHOLDERS' EQUITY (Details 3

SHAREHOLDERS' EQUITY (Details 3) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Preferred stock issued (in shares)	0	0
Preferred stock outstanding (in shares)	0	0
Preferred stock
Preferred stock authorized (in shares)	2,500,000
Series A Participating Preference Stock
Preferred stock authorized (in shares)	500,000
Cumulative preferred stock
Preferred stock authorized (in shares)	5,000,000
Preferred stock, par value per share (in dollars per share)	$ 10

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) $ in Thousands	Jun. 11, 2015USD ($)	Oct. 15, 2014USD ($)	Dec. 13, 2013USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
LONG-TERM DEBT
Less unamortized net discount				$ (633)	$ (686)
Total long-term debt, current and non current				863,257	803,481
Total long-term debt, current and non current				863,890
Current obligations of long term debt				(25,000)
Current obligations under capital lease				(310)	(292)
Total long-term debt				837,947	803,189
Shelf registration statement, amount			$ 200,000	200,000
Effective period to use proceeds under shelf to fund capital expenditures, refinancings of existing debt or general corporate needs			3 years
First mortgage bonds
LONG-TERM DEBT
Total long-term debt, current and non current				$ 758,000	698,000
First mortgage bonds | EDE
LONG-TERM DEBT
Number of consecutive months within the fifteen months preceding issuance to determine net earnings to annual interest requirement ratio				12 months
Number of months preceding issuance to determine net earnings to annual interest requirement ratio				15 months
Net earnings to annual interest requirement ratio				2
Maximum principal amount outstanding at any one time				$ 1,000,000
New bonds to be issued as a percentage of net property additions				60.00%
First mortgage bonds | EDE | Low end of range
LONG-TERM DEBT
Debt permitted to be issued on compliance of amount of retired bonds and percentage of net property additions covenant				$ 297,000
First mortgage bonds | EDG
LONG-TERM DEBT
Maximum principal amount outstanding at any one time				$ 300,000
Interest rate assumed on debt permitted to be issued on compliance of interest coverage ratio covenant (as a percent)				5.50%
Debt permitted to be issued on compliance of amount of retired bonds and percentage of net property additions covenant				$ 19,500
Number of most recent fiscal quarters used in calculating the interest coverage ratio as per the terms of debt instrument covenants				12 months
Ratio of EBITDA to interest charges, minimum				2
First mortgage bonds | EDG | High end of range
LONG-TERM DEBT
New bonds to be issued as a percentage of net property additions				75.00%
7.20% Series due 2016 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 25,000	$ 25,000
Interest rate, stated percentage				7.20%	7.20%
5.875% Series due 2037 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 80,000	$ 80,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				5.875%
6.375% Series due 2018 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 90,000	$ 90,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%	100.00%
Interest rate, stated percentage				6.375%	6.375%
4.65% Series due 2020 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 100,000	$ 100,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				4.65%	4.65%
5.20% Series due 2040 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 50,000	$ 50,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				5.20%
3.58% Series Due 2027 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 88,000	$ 88,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				3.58%	3.58%
3.59% Series due 2030
LONG-TERM DEBT
Aggregate principal amount of debt entered into in private placement	$ 60,000
Interest rate, stated percentage	3.59%
3.59% Series due 2030 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 60,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				3.59%
3.73% Series due 2033 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 30,000	$ 30,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				3.73%
4.32% Series due 2043 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 120,000	120,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				4.32%
4.27% Series due 2044
LONG-TERM DEBT
Aggregate principal amount of debt entered into in private placement		$ 60,000
Interest rate, stated percentage				4.27%
4.27% Series due 2044 | EDE
LONG-TERM DEBT
Total long-term debt, current and non current				$ 60,000	60,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				4.27%
6.82% Series due 2036 | EDG
LONG-TERM DEBT
Total long-term debt, current and non current				$ 55,000	$ 55,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				6.82%	6.82%
Senior Notes, 6.70% Series due 2033
LONG-TERM DEBT
Total long-term debt, current and non current				$ 62,000	$ 62,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				6.70%	6.70%
Senior Notes, 5.80% Series due 2035
LONG-TERM DEBT
Total long-term debt, current and non current				$ 40,000	$ 40,000
Percentage of principal amount at which the entity may redeem all the notes				100.00%
Interest rate, stated percentage				5.80%	5.80%
Other.
LONG-TERM DEBT
Total long-term debt, current and non current				$ 3,890	$ 4,167
New first mortgage bonds | EDE | Low end of range
LONG-TERM DEBT
Debt permitted to be issued on compliance of amount of retired bonds and percentage of net property additions covenant				297,000
New first mortgage bonds | EDE | High end of range
LONG-TERM DEBT
Debt permitted to be issued based on the limit on the principal amount and current level of outstanding bonds				$ 297,000

LONG-TERM DEBT (Details 2)

LONG-TERM DEBT (Details 2) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long-Term Debt Payout Schedule
2,016	$ 25,310
2,017	329
2,018	90,351
2,019	375
2,020	100,396
Thereafter	647,129
Total long-term debt obligations	863,890
Less current obligations and unamortized discount	25,943
Total long-term debt	837,947	$ 803,189
Regulated Entity Debt Obligations
Long-Term Debt Payout Schedule
2,016	25,000
2,018	90,000
2,020	100,000
Thereafter	645,000
Total long-term debt obligations	860,000
Capital Lease Obligations
Long-Term Debt Payout Schedule
2,016	310
2,017	329
2,018	351
2,019	375
2,020	396
Thereafter	2,129
Total long-term debt obligations	$ 3,890

SHORT-TERM BORROWINGS (Details)

SHORT-TERM BORROWINGS (Details) $ in Thousands	Oct. 20, 2014USD ($)item	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Oct. 19, 2014USD ($)
Short-Term Borrowings
Short-term borrowings		$ 25,000	$ 44,000
Average borrowings outstanding		48,900	30,000
Highest month-end balances		$ 97,000	$ 77,000
Weighted average interest rate during period (as a percent)		0.54	0.38
Weighted average interest rate at year end (as a percent)		0.84%	0.44%
Debt issuance costs		$ 818	$ 651	$ 1,879
Commercial paper
Short-Term Borrowings
Short-term borrowings		25,000
Outstanding borrowings		0
Amount of credit facility used to back up outstanding commercial paper borrowings		25,000
Unsecured revolving credit facility
Short-Term Borrowings
Outstanding borrowings		$ 0
Unsecured revolving credit facility	$ 200,000				$ 150,000
Maturity term	5 years
Number of extensions | item	2
Extension period	1 year
Facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings (as a percent)		0.175%
Debt issuance costs		$ 300
Maximum percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement		65.00%
Percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement		53.00%
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.		$ 25,000
Unsecured revolving credit facility | Federal fund effective rate
Short-Term Borrowings
Margin over the base rate (as a percent)		0.50%
Unsecured revolving credit facility | One month LIBOR
Short-Term Borrowings
Description of interest rate basis		one month LIBOR
Margin over the base rate (as a percent)		1.00%
Unsecured revolving credit facility | One month, two month or three month LIBOR
Short-Term Borrowings
Description of interest rate basis		one month, two month, three month or six month LIBOR
Margin over the base rate (as a percent)		1.025%
Letters of credit
Short-Term Borrowings
Unsecured revolving credit facility	$ 20,000
Additional borrowing capacity		$ 75,000
Swingline loan
Short-Term Borrowings
Unsecured revolving credit facility	$ 20,000

RETIREMENT AND OTHER EMPLOYEE57

RETIREMENT AND OTHER EMPLOYEE BENEFITS (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Amounts recognized in the balance sheet
Accounts payable and accrued liabilities				$ 66,946	$ 83,420
Pension and other postretirement benefit obligations				82,144	93,863
Effect of 1% change in assumed healthcare cost growth rates
Number of non-callable corporate bonds | item	500
Low end of range
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Maturity of non-cancellable corporate bonds	0 years
High end of range
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Maturity of non-cancellable corporate bonds	30 years
Pension Benefits
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Lump sum distribution	$ 15,300	$ 9,000
Increase (decrease) in net liability	(2,400)
Estimated contribution in next fiscal year	13,600
Reconciliation of Projected Benefit Obligations:
Benefit obligation at beginning of year	251,879	225,131
Amendments		(7,753)
Net actuarial (gain)/loss	(708)	36,742
Benefits and expenses paid	(25,201)	(19,527)
Benefit obligation at end of year	243,690	251,879	$ 225,131
Reconciliation of Fair Value of Plan Assets:
Fair value of plan assets at beginning of year	192,674	186,547
Actual return on plan assets gain/(loss)	(1,978)	14,319
Employer contribution	21,350	11,335
Benefits paid	(25,201)	(19,527)
Fair value of plan assets at end of year	186,845	192,674	186,547
Reconciliation of Funded Status:
Fair value of plan assets	192,674	186,547	186,547	186,845	192,674
Projected benefit obligations	(251,879)	(225,131)	(225,131)	(243,690)	(251,879)
Funded status				(56,845)	(59,205)
Employee pension plan accumulated benefit obligation
Accumulated benefit obligation				221,481	227,928
Amounts recognized in the balance sheet
Pension and other postretirement benefit obligations				56,845	59,205
Net Periodic Pension Benefit Cost:
Service cost	7,442	6,467	7,454
Interest cost	10,278	10,819	10,063
Expected return on plan assets	(13,567)	(13,105)	(12,428)
Amortization of prior service cost	(630)	418	532
Amortization of net actuarial loss	10,033	6,611	10,445
Net periodic benefit cost	13,556	11,210	16,066
Activity in the regulatory asset accounts
Beginning Balance	77,456	56,709
Current Year Actuarial (Gain)/Loss	14,836	35,529
Amortization of Actuarial Loss	(10,033)	(6,611)
Current Year Prior Service Credit		(7,753)
Amortization of Prior Service (Cost)/Credit	630	(418)
Ending Balance	82,889	77,456	56,709
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				88,981
Prior service cost (benefit)				(6,092)
Total	77,456	$ 56,709	$ 56,709	$ 82,889	$ 77,456
Amounts expected to be recognized in the subsequent year
Net actuarial loss	8,426
Prior service cost (benefit)	(630)
Total	$ 7,796
Weighted-average assumptions used to determine the benefit obligation
Discount rate (as a percent)				4.40%	4.06%
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)	4.06%	4.90%	4.00%
Expected return on plan assets (as a percent)	7.75%	7.75%	7.75%
Rate of compensation increase (as a percent)	3.50%	3.50%	3.50%
Pension Benefits | Payments from Trust
Expected benefit payments
2,016				$ 22,500
2,017				22,800
2,018				21,500
2,019				20,000
2,020				20,900
2021 - 2025				97,400
Pension Benefits | Payments from Company Funds
Expected benefit payments
2,016				500
2,017				600
2,018				500
2,019				500
2,020				800
2021 - 2025				2,900
SERP
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Increase (decrease) in net liability	$ 700
Reconciliation of Projected Benefit Obligations:
Benefit obligation at beginning of year	9,155	$ 7,108
Amendments		(45)
Net actuarial (gain)/loss	557	1,890
Benefits and expenses paid	(366)	(338)
Benefit obligation at end of year	9,886	9,155	$ 7,108
Reconciliation of Funded Status:
Projected benefit obligations	(9,155)	(7,108)	(7,108)	(9,886)	$ (9,155)
Funded status				(9,886)	(9,155)
Employee pension plan accumulated benefit obligation
Accumulated benefit obligation				8,609	7,160
Amounts recognized in the balance sheet
Accounts payable and accrued liabilities				534	481
Pension and other postretirement benefit obligations				9,352	8,674
Net Periodic Pension Benefit Cost:
Service cost	158	153	135
Interest cost	382	387	315
Amortization of prior service cost	(42)	(8)	(8)
Amortization of net actuarial loss	597	504	567
Net periodic benefit cost	1,095	1,036	1,009
Activity in the regulatory asset accounts
Beginning Balance	5,537	4,188
Current Year Actuarial (Gain)/Loss	557	1,890
Amortization of Actuarial Loss	(597)	(504)
Current Year Prior Service Credit		(45)
Amortization of Prior Service (Cost)/Credit	42	8
Ending Balance	5,539	5,537	4,188
Amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost
Net actuarial loss				5,555
Prior service cost (benefit)				(16)
Total	5,537	4,188	4,188	5,539	5,537
Amounts expected to be recognized in the subsequent year
Net actuarial loss	555
Prior service cost (benefit)	(14)
Total	541
OPEB
RETIREMENT AND OTHER EMPLOYEE BENEFITS
Increase (decrease) in net liability	(10,000)
Estimated contribution in next fiscal year	$ 4,900
Expected benefit payments
Eligible age	55 years
Minimum service period for eligibility	5 years
Reconciliation of Projected Benefit Obligations:
Benefit obligation at beginning of year	$ 109,899	85,332
Net actuarial (gain)/loss	(14,358)	20,347
Plan participant's contribution	963	850
Benefits and expenses paid	(3,839)	(3,897)
Federal subsidy	419	306
Benefit obligation at end of year	101,467	109,899	85,332
Reconciliation of Fair Value of Plan Assets:
Fair value of plan assets at beginning of year	83,776	79,098
Actual return on plan assets gain/(loss)	(955)	5,030
Employer contribution	4,903	2,258
Benefits paid	(3,670)	(3,707)
Plan participant's contribution	912	804
Federal subsidy	403	293
Fair value of plan assets at end of year	85,369	83,776	79,098
Reconciliation of Funded Status:
Fair value of plan assets	83,776	79,098	79,098	85,369	83,776
Projected benefit obligations	(109,899)	(85,332)	(85,332)	(101,467)	(109,899)
Funded status				(16,098)	(26,123)
Amounts recognized in the balance sheet
Accounts payable and accrued liabilities				151	139
Pension and other postretirement benefit obligations				15,947	25,984
Net Periodic Pension Benefit Cost:
Service cost	3,713	2,601	2,941
Interest cost	4,670	4,360	3,827
Expected return on plan assets	(5,197)	(4,801)	(4,353)
Amortization of prior service cost	(1,011)	(1,011)	(1,011)
Amortization of net actuarial loss	2,747	967	2,261
Net periodic benefit cost	4,922	2,116	3,665
Activity in the regulatory asset accounts
Beginning Balance	20,446	285
Current Year Actuarial (Gain)/Loss	(8,208)	20,117
Amortization of Actuarial Loss	(2,747)	(967)
Amortization of Prior Service (Cost)/Credit	1,011	1,011
Ending Balance	10,502	20,446	285
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				12,075
Prior service cost (benefit)				(1,573)
Total	20,446	$ 285	$ 285	$ 10,502	$ 20,446
Amounts expected to be recognized in the subsequent year
Net actuarial loss	1,030
Prior service cost (benefit)	(1,011)
Total	$ 19
Weighted-average assumptions used to determine the benefit obligation
Discount rate (as a percent)				4.48%	4.15%
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)	4.15%	5.00%	4.11%
Expected return on plan assets (as a percent)	6.52%	6.52%	6.52%
Rate of compensation increase (as a percent)	3.50%	3.50%	3.50%
Cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation
Cost trend rate assumed (as a percent)	7.00%
Decrease in trend rate through 2019 (as a percent)	0.50%
Ultimate rate (as a percent)	5.00%
Effect of 1% change in assumed healthcare cost growth rates
Effect of 1% increase on total of service and interest cost	$ 2,051
Effect of 1% decrease on total of service and interest cost	(1,530)
Effect of 1% increase on post-retirement benefit obligation	17,473
Effect of 1% decrease on post-retirement benefit obligation	$ (13,794)
OPEB | Payments from Trust
Expected benefit payments
2,016				$ 2,800
2,017				3,200
2,018				3,500
2,019				3,800
2,020				4,100
2021 - 2025				25,000
OPEB | Expected Federal Subsidy
Estimated benefit payments
2,016				400
2,017				400
2,018				500
2,019				500
2,020				600
2021 - 2025				3,700
OPEB | Payments from Company Funds
Expected benefit payments
2,016				200
2,017				200
2,018				200
2,019				200
2,020				200
2021 - 2025				$ 800

RETIREMENT AND OTHER EMPLOYEE58

RETIREMENT AND OTHER EMPLOYEE BENEFITS (Details 2) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)$ / sharesshares	Dec. 31, 2015USD ($)item$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)$ / sharesshares
Actual return on plan assets:
Cash-Equivalent Securities with a maturity	1 year
Employee Stock Purchase Plan
Actual return on plan assets:
Common stock purchase price to eligible employees (as a percent)	90.00%
Percentage of Black-Scholes methodology used as a component to calculate value of lookback feature	90.00%
Percentage of maximum subscription price used as a component to calculate value of lookback feature	10.00%
Shares available for issuance | shares				764,645
Subscriptions outstanding (in shares) | shares				58,742	57,369	60,413
Maximum subscription price (in dollars per share) | $ / shares				$ 21.09	$ 21.43	$ 19.58
Shares of stock issued | shares	56,193	56,942	68,099
Stock issuance price (in dollars per share) | $ / shares				$ 21.01	$ 19.58	$ 17.95
Assumptions for valuation of shares
Fair value of grants (in dollars per share) | $ / shares	$ 3.58	$ 3.07	$ 2.78
Risk-free interest rate (as a percent)	0.26%	0.10%	0.14%
Dividend yield (as a percent)	4.40%	4.30%	4.60%
Expected volatility (as a percent)	21.00%	14.00%	14.00%
Expected life in months	12 months	12 months	12 months
Pension Benefits
Fair value measurements of plan assets
Period over which the market-related value is determined	5 years
Number of basic elements on which primary investment goals of the company for pension fund assets are based (in counts) | item				4
Target allocations for plan assets
Cash investment managers generally hold in their portfolios (as a percent)	10.00%
Fund assets measured at fair value
Fair value of plan assets	$ 192,674	$ 186,547	$ 186,547	$ 186,845	$ 192,674	$ 186,547
Percentage of Plan Assets				100.00%	100.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	192,674	186,547
Actual return on plan assets:
Fair value of plan assets at end of year	$ 186,845	192,674	186,547
Pension Benefits | Equity securities
Target allocations for plan assets
Target allocation (as a percent)	72.00%
Pension Benefits | Equity securities | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	80.00%
Pension Benefits | Equity securities | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	60.00%
Pension Benefits | Common collective trusts - domestic
Fund assets measured at fair value
Fair value of plan assets	$ 48,760	48,760		$ 46,182	$ 48,760
Percentage of Plan Assets				24.70%	25.30%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	48,760
Actual return on plan assets:
Fair value of plan assets at end of year	46,182	48,760
Pension Benefits | Common collective trusts - international
Fund assets measured at fair value
Fair value of plan assets	42,770	42,770		$ 41,928	$ 42,770
Percentage of Plan Assets				22.50%	22.20%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	42,770
Actual return on plan assets:
Fair value of plan assets at end of year	41,928	42,770
Pension Benefits | Short term investments
Fund assets measured at fair value
Fair value of plan assets	70	70		$ 71	$ 70
Percentage of Plan Assets				0.00%	0.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	70
Actual return on plan assets:
Fair value of plan assets at end of year	71	70
Pension Benefits | Equity long/short hedge funds
Fund assets measured at fair value
Fair value of plan assets	38,428	38,428		$ 37,970	$ 38,428
Percentage of Plan Assets				20.30%	20.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	38,428
Actual return on plan assets:
Fair value of plan assets at end of year	$ 37,970	38,428
Pension Benefits | Fixed income
Target allocations for plan assets
Target allocation (as a percent)	28.00%
Pension Benefits | Fixed income | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	40.00%
Pension Benefits | Fixed income | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	20.00%
Pension Benefits | Common collective trust fixed income
Fund assets measured at fair value
Fair value of plan assets	$ 62,646	62,646		$ 60,694	$ 62,646
Percentage of Plan Assets				32.50%	32.50%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	62,646
Actual return on plan assets:
Fair value of plan assets at end of year	$ 60,694	62,646
Pension Benefits | Comingled bond funds
Fund assets measured at fair value
Maximum high yield	25.00%
Pension Benefits | Significant Other Observable Inputs (Level 2)
Fund assets measured at fair value
Fair value of plan assets	$ 154,246	154,246		$ 148,875	$ 154,246
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	154,246
Actual return on plan assets:
Fair value of plan assets at end of year	148,875	154,246
Pension Benefits | Significant Other Observable Inputs (Level 2) | Common collective trusts - domestic
Fund assets measured at fair value
Fair value of plan assets	48,760	48,760		46,182	48,760
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	48,760
Actual return on plan assets:
Fair value of plan assets at end of year	46,182	48,760
Pension Benefits | Significant Other Observable Inputs (Level 2) | Common collective trusts - international
Fund assets measured at fair value
Fair value of plan assets	42,770	42,770		41,928	42,770
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	42,770
Actual return on plan assets:
Fair value of plan assets at end of year	41,928	42,770
Pension Benefits | Significant Other Observable Inputs (Level 2) | Short term investments
Fund assets measured at fair value
Fair value of plan assets	70	70		71	70
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	70
Actual return on plan assets:
Fair value of plan assets at end of year	71	70
Pension Benefits | Significant Other Observable Inputs (Level 2) | Common collective trust fixed income
Fund assets measured at fair value
Fair value of plan assets	62,646	62,646		60,694	62,646
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	62,646
Actual return on plan assets:
Fair value of plan assets at end of year	60,694	62,646
Pension Benefits | Significant Unobservable Inputs (Level 3)
Fund assets measured at fair value
Fair value of plan assets	38,428	38,428		37,970	38,428
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	38,428
Actual return on plan assets:
Fair value of plan assets at end of year	37,970	38,428
Pension Benefits | Significant Unobservable Inputs (Level 3) | Equity long/short hedge funds
Fund assets measured at fair value
Fair value of plan assets	38,428	36,729	36,729	37,970	38,428	36,729
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	38,428	36,729
Actual return on plan assets:
Relating to assets still held at the reporting date	(458)	1,382
Relating to assets sold during the period		1,491
Purchases		9,700
Sales		(10,874)
Fair value of plan assets at end of year	37,970	38,428	36,729
OPEB
Fund assets measured at fair value
Fair value of plan assets	83,776	79,098	79,098	$ 85,369	$ 83,776	$ 79,098
Percentage of Plan Assets				100.00%	100.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	83,776	79,098
Actual return on plan assets:
Fair value of plan assets at end of year	$ 85,369	83,776	$ 79,098
OPEB | Equity securities
Target allocations for plan assets
Target allocation (as a percent)	60.00%
OPEB | Equity securities | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	76.00%
OPEB | Equity securities | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	44.00%
OPEB | Common collective trust equity securities
Fund assets measured at fair value
Fair value of plan assets	$ 47,690	47,690		$ 48,553	$ 47,690
Percentage of Plan Assets				56.90%	56.90%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	47,690
Actual return on plan assets:
Fair value of plan assets at end of year	48,553	47,690
OPEB | Fund assets
Fund assets measured at fair value
Fair value of plan assets	83,851	83,851		$ 85,504	$ 83,851
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	83,851
Actual return on plan assets:
Fair value of plan assets at end of year	$ 85,504	83,851
OPEB | Cash and cash equivalents | High end of range
Target allocations for plan assets
Target allocation (as a percent)	10.00%
OPEB | Fixed income
Target allocations for plan assets
Target allocation (as a percent)	40.00%
OPEB | Fixed income | High end of range
Target allocations for plan assets
Target allocation, maximum (as a percent)	44.00%
OPEB | Fixed income | Low end of range
Target allocations for plan assets
Target allocation, minimum (as a percent)	36.00%
OPEB | Common collective trust fixed income
Fund assets measured at fair value
Fair value of plan assets	$ 33,708	33,708		$ 34,395	$ 33,708
Percentage of Plan Assets				40.30%	40.20%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	33,708
Actual return on plan assets:
Fair value of plan assets at end of year	34,395	33,708
OPEB | Common collective trusts
Fund assets measured at fair value
Fair value of plan assets	2,453	2,453		$ 2,556	$ 2,453
Percentage of Plan Assets				3.00%	2.90%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	2,453
Actual return on plan assets:
Fair value of plan assets at end of year	2,556	2,453
OPEB | Payable for securities purchased
Fund assets measured at fair value
Fair value of plan assets	(75)	(75)		$ (135)	$ (75)
Percentage of Plan Assets				(0.20%)	0.00%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	(75)
Actual return on plan assets:
Fair value of plan assets at end of year	(135)	(75)
OPEB | Significant Other Observable Inputs (Level 2) | Common collective trust equity securities
Fund assets measured at fair value
Fair value of plan assets	47,690	47,690		$ 48,553	$ 47,690
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	47,690
Actual return on plan assets:
Fair value of plan assets at end of year	48,553	47,690
OPEB | Significant Other Observable Inputs (Level 2) | Fund assets
Fund assets measured at fair value
Fair value of plan assets	83,851	83,851		85,504	83,851
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	83,851
Actual return on plan assets:
Fair value of plan assets at end of year	85,504	83,851
OPEB | Significant Other Observable Inputs (Level 2) | Common collective trust fixed income
Fund assets measured at fair value
Fair value of plan assets	33,708	33,708		34,395	33,708
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	33,708
Actual return on plan assets:
Fair value of plan assets at end of year	34,395	33,708
OPEB | Significant Other Observable Inputs (Level 2) | Common collective trusts
Fund assets measured at fair value
Fair value of plan assets	2,453	2,453		$ 2,556	$ 2,453
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Fair value of plan assets at beginning of year	2,453
Actual return on plan assets:
Fair value of plan assets at end of year	$ 2,556	$ 2,453
401 (k) plan and ESOP
Employee 401k and Stock Ownership Plan, ESOP Disclosures [Abstract]
Maximum percentage of annual compensation to be deferred by participating employees	25.00%
Shares available to be issued | shares				129,616
Shares contributed | shares	66,783	60,049	64,128
Cash balance formula
Employee 401k and Stock Ownership Plan, ESOP Disclosures [Abstract]
Percentage of each employee's deferrals to be matched	100.00%
Maximum matching contribution as a percentage of employee's eligible compensation	6.00%
Percentage of matching contribution made in shares	3.00%
Average annual basic earnings formula
Employee 401k and Stock Ownership Plan, ESOP Disclosures [Abstract]
Percentage of each employee's deferrals to be matched	50.00%
Maximum matching contribution as a percentage of employee's eligible compensation	3.00%

EQUITY COMPENSATION (Details)

EQUITY COMPENSATION (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
EQUITY COMPENSATION
Compensation Expense	$ 4,279	$ 3,688	$ 2,577
Tax Benefit Recognized	$ 1,576	1,359	$ 929
2015 Stock Incentive Plan
Fair value
Number of shares of common stock provided for grant	500,000
Shares available for issuance	496,766
Performance-Based Restricted Stock Awards
Assumptions used for estimating fair value of grants outstanding
Unrecognized compensation expense	$ 700	$ 1,100
Vesting period	3 years
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)	63,300	47,200	33,900
Target shares granted (in shares)	21,800	27,000	26,300
Shares issued in excess of target (in shares)	3,653
Shares awarded (in shares)	(13,653)		(4,460)
Forfeited shares (in shares)	(6,079)
Target shares not awarded (in shares)		(10,900)	(8,540)
Nonvested, balance at the end of the period (in shares)	69,021	63,300	47,200
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)	$ 21.74	$ 21.39	$ 20.25
Granted (in dollars per share)	$ 30.40
Target shares granted (in dollars per share)		22.40	21.36
Shares issued in excess of target (in dollars per share)	20.97
Shares awarded (in dollars per share)	$ 20.97		18.36
Forfeited shares ( in dollars per share)	24.10
Target shares not awarded (in dollars per share)		21.84	18.36
Nonvested, balance at the end of the period (in dollars per share)	$ 24.38	$ 21.74	$ 21.39
Assumptions for valuation of shares
Risk-free interest rate, low end of range (as a percent)	0.65%	0.25%	0.13%
Risk-free interest rate, high end of range (as a percent)	1.06%	0.67%	0.38%
Expected dividend yield (as a percent)	3.70%	3.50%	4.50%
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)	$ 41.70	$ 43.80	$ 18.47
Expected volatility (as a percent)	18.70%	14.50%	20.20%
Fair value
Threshold performance level set at percentile level of peer group (as a percent)	20.00%	20.00%	20.00%
Target performance level set at percentile level of peer group (as a percent)	50.00%	50.00%	50.00%
Maximum performance level set at percentile level of peer group (as a percent)	80.00%	80.00%	80.00%
Percentage of shares granted on reaching target performance level	100.00%
Percentage of shares granted on reaching threshold performance level	50.00%
Percentage of shares granted on reaching maximum performance level	200.00%
Performance-Based Restricted Stock Awards | Low end of range
Assumptions for valuation of shares
Expected volatility of peer group stock (as a percent)	14.50%	12.40%	12.30%
Fair value percentage	115.00%	140.00%	0.00%
Performance-Based Restricted Stock Awards | High end of range
Assumptions for valuation of shares
Expected volatility of peer group stock (as a percent)	34.40%	24.80%	27.50%
Fair value percentage	182.00%	157.00%	108.00%
Time-Vested Restricted Stock Awards
Assumptions used for estimating fair value of grants outstanding
Unrecognized compensation expense	$ 400	$ 400
Vesting period	3 years
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)	41,000	24,900	3,300
Granted (in shares)	19,000	22,600	21,600
Distributed (in shares)	(1,654)	(4,010)
Forfeited shares (in shares)	(2,746)	(2,490)
Nonvested, balance at the end of the period (in shares)	55,600	41,000	24,900
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)	$ 21.89	$ 21.42	$ 21.84
Granted (in dollars per share)	30.40	22.40	21.36
Distributed (in dollars per share)	21.92	21.77
Forfeited shares ( in dollars per share)	25.91	21.99
Nonvested, balance at the end of the period (in dollars per share)	24.60	21.89	$ 21.42
Fair value
Fair value (in dollars per share)	$ 25.17	$ 26.82
Time-Vested Restricted Stock Awards | Low end of range
Fair value
Recognition period	1 month 6 days	1 year 1 month 6 days
Time-Vested Restricted Stock Awards | High end of range
Fair value
Recognition period	2 years 1 month 6 days	2 years 1 month 6 days
Stock Options
Assumptions used for estimating fair value of grants outstanding
Vesting period	3 years
Stock options, expiration term	10 years
Stock options or divident equivalents granted	0	0	0
Outstanding options	0	0	112,500	163,300
Assumptions for valuation of shares
Risk-free interest rate, low end of range (as a percent)			0.10%
Risk-free interest rate, high end of range (as a percent)			0.38%
Expected dividend yield (as a percent)			4.50%
Expected volatility (as a percent)			24.00%
Market value (in dollars per share)			$ 22.69
Weighted average fair value per option (in dollars per share)			$ 1.57
Stock Options | Low end of range
Assumptions for valuation of shares
Expected life in months			6 months 15 days
Stock Options | High end of range
Assumptions for valuation of shares
Expected life in months			24 months 15 days

EQUITY COMPENSATION (Details 2)

EQUITY COMPENSATION (Details 2) - Stock Options - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock options
Outstanding, balance at the beginning of the period (in shares)	0	112,500	163,300
Exercised (in shares)		112,500	(50,800)
Outstanding, balance at the end of the period (in shares)	0	0	112,500
Exercisable (in shares)			112,500
Weighted Average Exercise Price
Outstanding, balance at the beginning of the period (in dollars per option)		$ 23.27	$ 22.13
Exercised (in dollars per share)		$ 24.58	21.78
Outstanding, balance at the end of the period (in dollars per option)			23.27
Exercisable (in dollars per share)			$ 23.27
Intrinsic value of unexercised options if closing price of stock is less than the exercise price (in dollars per share)	$ 0
Aggregate intrinsic value
Weighted-average remaining contractual life of outstanding options			2 years 1 month 6 days
Range of exercise prices, low end of range (in dollars per share)			$ 21.92
Range of exercise prices, high end of range (in dollars per share)			$ 23.81
Assumptions for valuation of shares
Dividend yield (as a percent)			4.50%
Expected volatility (as a percent)			24.00%
High end of range
Aggregate intrinsic value
Aggregate intrinsic values			$ 0.1
Assumptions for valuation of shares
Expected life in months			24 months 15 days

EQUITY COMPENSATION (Details 3)

EQUITY COMPENSATION (Details 3) - Stock Unit Plan for directors - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assumptions used for estimating fair value of grants outstanding
Number of shares authorized under the plan	900,000
Number of shares accrued in director's accounts	157,672	164,085
Shares available for issuance	677,980	714,978
Units accrued for service and dividends (in shares)	30,595	30,765	34,252
Units redeemed for common stock (in shares)	37,008	21,083	22,908

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2010
Current income taxes:
Federal		$ (2,350,000)	$ 6,726,000
State		(123,000)	2,495,000
TOTAL		(2,473,000)	9,221,000
Deferred income taxes:
Federal	$ 29,722,000	36,620,000	24,954,000
State	4,233,000	5,216,000	3,554,000
TOTAL	33,955,000	41,836,000	28,508,000
Investment tax credit amortization	(143,000)	(143,000)	(237,000)
TOTAL INCOME TAX EXPENSE	33,812,000	39,220,000	$ 37,492,000
Deferred tax assets and liabilities as reflected on consolidated balance sheet
NET DEFERRED TAX LIABILITIES	396,542,000	358,252,000
Deferred tax assets:
Plant related basis differences	27,347,000	25,349,000
Net operating loss	9,055,000	22,000,000
Disallowed plant costs	1,699,000	1,754,000
Gains on hedging transactions	1,195,000	1,260,000
Regulated liabilities related to income taxes	13,142,000	13,350,000
Pensions and other post-retirement benefits		1,175,000
Carry forward of income tax credit	8,675,000	6,367,000
Other	1,550,000	1,633,000
Total deferred tax assets	62,663,000	72,888,000
Deferred tax liabilities:
Depreciation, amortization and other plant related differences	382,897,000	363,337,000
Regulated assets related to income	38,615,000	37,180,000
Loss on reacquired debt	3,572,000	3,828,000
Amortization of intangibles	10,248,000	9,168,000
Pensions and other post-retirement benefits	7,112,000
Deferred construction accounting costs	5,711,000	6,082,000
Other	11,050,000	11,545,000
Total deferred tax liabilities	459,205,000	431,140,000
NET DEFERRED TAX LIABILITIES	$ 396,542,000	$ 358,252,000
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%)	(0.10%)	(0.20%)
Effect of ratemaking on property related differences (as a percent)	(1.40%)	(1.70%)	(1.10%)
Other (as a percent)	0.90%	0.60%	0.30%
Consolidated provision for income taxes	$ 33,812,000	$ 39,220,000	$ 37,492,000
Consolidated effective federal and state income tax rates (as a percent)	37.40%	36.90%	37.10%
Net operating loss carryfowards		$ 74,100,000
Net operating losses estimated to be utilized		38,000,000
Deferred tax assets estimated to be utilized	$ 13,500,000
Advanced coal investment tax credit				$ 17,700,000
Maximum tax credit utilized			$ 9,000,000
Adjustment due to change in tax accounting method om deduction and capitalization of tangible property		29,000,000
Adjustment due to change in tax accounting method on deductibility of VEBA plan activity		$ 14,000,000

COMMONLY OWNED FACILITIES (Deta

COMMONLY OWNED FACILITIES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)miMW	Dec. 31, 2014USD ($)
COMMONLY OWNED FACILITIES
Proportionate ownership interest (as a percent)	12.00%
Distance of Iatan Generating Facility from Kansas city (in miles) | mi	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	$ 380.2	$ 373.3
Accumulated Depreciation	105.3	99.1
Expenditures	$ 26.9	27.8
Iatan1 | KCP&L
COMMONLY OWNED FACILITIES
Ownership interest in the site (as a percent)	70.00%
Iatan1 | KCP&L Greater Missouri Operations Co.
COMMONLY OWNED FACILITIES
Ownership interest in the site (as a percent)	18.00%
Iatan2 | KCP&L
COMMONLY OWNED FACILITIES
Ownership interest in the site (as a percent)	54.00%
Iatan2 | KCP&L Greater Missouri Operations Co.
COMMONLY OWNED FACILITIES
Ownership interest in the site (as a percent)	18.00%
State Line Combined Cycle Unit
Amounts included in property, plant and equipment
Cost of ownership in plant in service	$ 163	161.5
Accumulated Depreciation	43.5	40
Expenditures	$ 40.7	47.1
Power capacity (in megawatts) | MW	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	$ 109.1	108.3
Accumulated Depreciation	11.9	9.4
Expenditures	$ 9.6	$ 8.1
Plum point | EDE
COMMONLY OWNED FACILITIES
Proportionate ownership interest (as a percent)	7.52%

COMMITMENTS AND CONTINGENCIES64

COMMITMENTS AND CONTINGENCIES (Detail) $ in Thousands	Dec. 15, 2008	Dec. 15, 2005	Dec. 31, 2015USD ($)itemMW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Commitments and Contingencies
Period of the average cost that is used as a basis for determining the maximum annual payments		20 years
Electric | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Construction costs year to date			$ 159,600
Cost related to pre-engineering, site preparation activities and contract cost year to date				$ 112,100
Electric | Low end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			165,000
Electric | High end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			175,000
Firm Physical gas and transportation contracts
Commitments and Contingencies
January 1, 2016 through December 31, 2016			26,700
January 1, 2017 through December 31, 2018			37,400
January 1, 2019 through December 31, 2020			28,800
January 1, 2021 and beyond			45,700
Coal and coal transportation contracts
Commitments and Contingencies
January 1, 2016 through December 31, 2016			18,000
January 1, 2017 through December 31, 2018			27,500
January 1, 2019 through December 31, 2020			$ 10,800
Purchased power | Plum Point Energy Station
Commitments and Contingencies
Energy capacity (in megawatts) | MW			670
Amount of energy capacity owned (in megawatts) | MW			50
Additional capacity under long-term contract agreement (in megawatts) | MW			50
Amount of long-term contract obligation			$ 277,600
Amount of energy capacity under option to purchase (in megawatts) | MW			50
Purchased power | Cloud County Windfarm
Commitments and Contingencies
Energy capacity (in megawatts) | MW			105
Period of the average cost that is used as a basis for determining the maximum annual payments	20 years
Purchased power | Cloud County Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 0
Purchased power | Cloud County Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 14,600
Purchased power | Elk River Windfarm
Commitments and Contingencies
Energy capacity (in megawatts) | MW			150
Purchased power | Elk River Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 0
Purchased power | Elk River Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			16,900
Leases
Commitments and Contingencies
Gross amount of assets recorded under capital leases			5,300
Capital leases, 2016			554
Capital leases, 2017			551
Capital leases, 2018			551
Capital leases, 2019			550
Capital leases, 2020			546
Capital leases, thereafter			2,460
Capital leases, total minimum payments			5,212
Capital leases, amount representing interest			1,322
Capital leases, present value of net minimum lease payments			3,890
Operating leases, 2016			734
Operating leases, 2017			689
Operating leases, 2018			648
Operating leases, 2019			484
Operating leases, total minimum payments			2,555
Expenses incurred related to operating leases			800	800	$ 800
Accumulated amount of amortization of capital leases			$ 1,900	$ 1,500
Leases | Electric
Commitments and Contingencies
Number of unit trains under short-term operating leases | item			2
Leases | Gas
Commitments and Contingencies
Number of office facilities under short-term operating leases | item			1
Leases | Plum Point Energy Station
Commitments and Contingencies
Number of railcars under capital leases | item			108

COMMITMENTS AND CONTINGENCIES65

COMMITMENTS AND CONTINGENCIES (Details 2) $ in Thousands	Jan. 26, 2016state	Feb. 10, 2015item	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Environmental Laws And Regulations
Number of states initiating legal challenges to invalidate rule | state	25
Asset retirement obligation			$ 15,072	$ 4,847	$ 4,190
Regulatory assets of Missouri solar initiative			209,708	$ 209,717
Asbury Power Plant
Environmental Laws And Regulations
Asset retirement obligation			5,400
Iatan Generating Station
Environmental Laws And Regulations
Asset retirement obligation			4,400
Surface Impoundments | Electric | High end of range
Environmental Laws And Regulations
Potential cost for construction of new landfill and conversion of existing ash handling from wet to dry system(s)			$ 15,000
Renewable Energy | Electric
Environmental Laws And Regulations
Minimum percentage of Missouri retail sales required to generate or purchase electricity in 2014			5.00%
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 laws harmonized | item		2
Number of solar rebate applications processed in Missouri solar initiative | item			262
Rebate Commitments in Missouri solar initiative			$ 3,500
Regulatory assets of Missouri solar initiative			$ 3,500
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2020			20.00%
Green House Gases
Environmental Laws And Regulations
Percentage of carbon emission reduction from 2005 baseline levels by 2030, required by the proposed Clean Power Plan			32.00%
Number of plan types for states to choose to meet their goals | item			2

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	$ 136,758	$ 169,714	$ 134,557	$ 164,544	$ 151,363	$ 171,512	$ 149,782	$ 179,673	$ 605,573	$ 652,330	$ 594,330
Depreciation and amortization									80,550	73,185	69,306
Federal and state income taxes									33,812	39,220	37,492
Operating income	19,757	35,783	16,047	24,713	19,300	31,709	19,502	29,488	96,301	99,999	99,663
Interest income									145	51	566
Interest expense									45,103	41,740	41,479
Income from AFUDC (debt and equity)									7,695	9,917	5,940
Income from continuing operations									56,597	67,103	63,445
Net income	9,905	25,285	6,770	14,637	11,112	23,892	11,194	20,905	56,597	67,103	63,445
Capital Expenditures									176,524	222,853	160,208
Total assets	2,455,303				2,371,056				2,455,303	2,371,056
Goodwill	39,492				39,492				39,492	39,492
SPP IM
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	2,900	$ 4,000	$ 3,400	$ 4,700	7,500	$ 11,500	$ 16,500	$ 6,200
Electric
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									555,085	592,491	536,413
Depreciation and amortization									74,732	67,534	63,659
Federal and state income taxes									31,123	35,737	34,478
Operating income									88,124	90,488	90,984
Interest income									133	37	537
Interest expense									41,307	37,911	37,683
Income from AFUDC (debt and equity)									7,681	9,833	5,910
Income from continuing operations									52,240	61,467	58,603
Capital Expenditures									169,111	212,866	153,401
Total assets	2,339,850				2,252,339				2,339,850	2,252,339
Electric | SPP IM
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									15,000	41,900
Gas
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									41,702	51,842	50,041
Depreciation and amortization									3,923	3,760	3,709
Federal and state income taxes									800	1,840	1,484
Operating income									5,153	6,775	6,194
Interest income									36	25	115
Interest expense									3,867	3,861	3,890
Income from AFUDC (debt and equity)									14	84	30
Income from continuing operations									1,287	2,965	2,355
Capital Expenditures									5,190	7,836	4,419
Total assets	127,871				130,856				127,871	130,856
Goodwill	39,492				39,492				39,492	39,492
Other
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									10,165	9,302	9,147
Depreciation and amortization									1,895	1,891	1,938
Federal and state income taxes									1,889	1,643	1,530
Operating income									3,024	2,736	2,485
Interest income									47	21	8
Income from continuing operations									3,070	2,671	2,487
Capital Expenditures									2,223	2,151	2,388
Total assets	38,300				34,655				38,300	34,655
Eliminations
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues									(1,379)	(1,305)	(1,271)
Interest income									(71)	(32)	(94)
Interest expense									(71)	(32)	$ (94)
Total assets	$ (50,718)				$ (46,794)				$ (50,718)	$ (46,794)

SELECTED QUARTERLY INFORMATIO67

SELECTED QUARTERLY INFORMATION (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues	$ 136,758	$ 169,714	$ 134,557	$ 164,544	$ 151,363	$ 171,512	$ 149,782	$ 179,673	$ 605,573	$ 652,330	$ 594,330
Operating income	19,757	35,783	16,047	24,713	19,300	31,709	19,502	29,488	96,301	99,999	99,663
Net income	$ 9,905	$ 25,285	$ 6,770	$ 14,637	$ 11,112	$ 23,892	$ 11,194	$ 20,905	$ 56,597	$ 67,103	$ 63,445
Basic Earnings Per Share	$ 0.23	$ 0.58	$ 0.16	$ 0.34
Diluted Earnings Per Share	$ 0.23	$ 0.58	$ 0.15	$ 0.34
Basic and Diluted Earnings Per Share					$ 0.26	$ 0.55	$ 0.26	$ 0.48
SPP IM
Operating revenues	$ 2,900	$ 4,000	$ 3,400	$ 4,700	$ 7,500	$ 11,500	$ 16,500	$ 6,200

RISK MANAGEMENT AND DERIVATIV68

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair value of derivative financial instruments
Current assets	$ 1,295	$ 3,901
Total derivatives assets	1,311	3,901
Current liabilities	4,472	6,469
Non-current liabilities and deferred credits	3,696	3,243
Total derivatives liabilities	8,168	9,712
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Gas
Fair value of derivative financial instruments
Current assets	2
Non-current other assets	16
Current liabilities	282	476
Non-current liabilities and deferred credits	66
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Electric
Fair value of derivative financial instruments
Current assets		1
Current liabilities	4,190	5,993
Non-current liabilities and deferred credits	3,630	3,243
Non-designated as hedging instruments due to regulatory accounting | Transmission congestion rights (TCR) | Electric
Fair value of derivative financial instruments
Current assets	$ 1,293	$ 3,900

RISK MANAGEMENT AND DERIVATIV69

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Electric
Gain / (Loss) on derivatives
Unrealized net losses applicable to financial instruments which will settle in next twelve months	$ 4,200
Period within which financial instruments will settle	12 months
Amount of Gain/(Loss) Recognized on Balance Sheet	$ (1,883)	$ 6,178
Amount of Gain / (Loss) Recognized in Income on Derivative	(647)	9,447
Mark-to-market pre-tax gains/(losses) from ineffective portions	0	0
Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(447)	(511)
Commodity contracts | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(6,853)	(6,780)
Amount of Gain / (Loss) Recognized in Income on Derivative	(8,115)	(1,659)
Commodity contracts | Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(447)	(511)
Transmission congestion rights (TCR) | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	4,970	12,958
Amount of Gain / (Loss) Recognized in Income on Derivative	$ 7,468	$ 11,106

RISK MANAGEMENT AND DERIVATIV70

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 3)	12 Months Ended
	Dec. 31, 2015USD ($)itemMWh$ / item
Transmission congestion rights (TCR) - 2015
Procurement guidelines
Monthly MWH Hedged | MWh	3,212
Monthly MWH Hedged, estimated fair value | $	$ 1,292,943
Electric | Natural Gas Usage - 2016
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	61.00%
Dth Hedged Physical	2,706,000
Dth Hedged Financial	5,940,000
Average Price (in dollars per dth) | $ / item	3.372
Electric | Natural Gas Usage - 2017
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	41.00%
Dth Hedged Physical	782,900
Dth Hedged Financial	5,210,000
Average Price (in dollars per dth) | $ / item	3.347
Electric | Natural Gas Usage - 2018
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Dth Hedged Physical	565,000
Dth Hedged Financial	2,460,000
Average Price (in dollars per dth) | $ / item	3.334
Electric | Natural Gas Forward 2019
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Dth Hedged Financial	1,460,000
Average Price (in dollars per dth) | $ / item	2.955
Electric | Natural Gas Forward 2020
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	0.00%
Electric | Current Year Procurement Guidelines
Procurement guidelines
Maximum percentage of volume to be hedged in any given month	100.00%
Maximum flexibility to hedge any future year's expected requirements (as a percent)	80.00%
Electric | First Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	60.00%
Electric | Second Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	40.00%
Electric | Third Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Electric | Fourth Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Electric | High end of range | Current Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	100.00%

RISK MANAGEMENT AND DERIVATIV71

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS (Details 4) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)
Contingent Features
Derivative instruments with the credit-risk-related contingent features that are in a liability position | $	$ 0
Collateral posted | $	0
Margin deposit liabilities | $	0
Margin deposit assets
Margin deposit assets | $	$ 11.2	$ 9.1
Gas
Price Risk Mitigation for Gas Segment
Target percentage of storage capacity utilization	95.00%
Volume of storage in pipelines that serve customers (in Dth)	1,400,000
Number of pipelines that serve customers (in units)	3
Storage capacity utilized (as a percent)	70.00%
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	2
Gas | Current Winter Season
Gas Usage Hedged By Winter Season
Minimum % Hedged	50.00%
Dth Hedged Financial	400,000,000
Dth in Storage	1,419,752,000
Actual % Hedged	93.00%
Gas | High end of range | Second Winter Season
Gas Usage Hedged By Winter Season
Minimum % Hedged	50.00%
Dth Hedged Financial	200,000,000
Actual % Hedged	6.00%
Gas | High end of range | Third Winter Season
Gas Usage Hedged By Winter Season
Minimum % Hedged	20.00%
Dth Hedged Financial	280,000,000
Actual % Hedged	9.00%

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - Recurring basis - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Measurements at Reporting Date
Derivative assets	$ 1,311	$ 3,901
Derivative liabilities	(8,168)	(9,712)
Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)
Fair Value Measurements at Reporting Date
Derivative assets	18	1
Derivative liabilities	(8,168)	(9,712)
Significant Other Observable Inputs (Level 2)
Fair Value Measurements at Reporting Date
Derivative assets	$ 1,293	$ 3,900

FAIR VALUE MEASUREMENTS (Deta73

FAIR VALUE MEASUREMENTS (Details 2) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Long-Term Debt
Carrying amount of total long-term debt exclusive of capital leases	$ 859	$ 799
Fair market value	$ 815	$ 829

REGULATED OPERATING EXPENSE (De

REGULATED OPERATING EXPENSE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REGULATED OPERATING EXPENSE
Electric transmission and distribution expense	$ 28,893	$ 27,919	$ 21,863
Natural gas transmission and distribution expense	2,699	2,362	2,498
Power operation expense (other than fuel)	18,263	16,089	15,643
Customer accounts and assistance expense	10,937	11,239	11,180
Employee pension expense	10,786	10,590	10,736
Employee healthcare expense	10,162	9,147	10,190
General office supplies and expense	14,438	15,024	12,850
Administrative and general expense	14,863	14,385	14,800
Allowance for uncollectible accounts	2,080	3,420	3,665
Regulatory reversal of gain on sale of assets		44	1,236
Miscellaneous expense	430	472	672
Total	$ 113,551	$ 110,691	$ 105,333

SUBSEQUENT EVENT - AGREEMENT 75

SUBSEQUENT EVENT - AGREEMENT AND PLAN OF MERGER (Details) - USD ($)	Feb. 09, 2016	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Subsequent event
Transaction costs				$ 200,000
Subsequent event
Subsequent event
Termination fee	$ 53,000,000
Subsequent event | Liberty Utilities (Central) Co
Subsequent event
Righ to receive in cash without interest	$ 34
Maximum period for extending regulatory approvals	6 months
Maximum period for exercising termination right	9 months
Forecast
Subsequent event
Transaction costs			$ 4,500,000
Percentage payable of transaction costs		50.00%
Forecast | High end of range
Subsequent event
Transaction costs		$ 17,000,000
Forecast | Low end of range
Subsequent event
Transaction costs		$ 15,000,000
Liberty Utilities (Central) Co | Subsequent event
Subsequent event
Termination fee	$ 65,000,000

SCHEDULE II - Valuation and Q76

SCHEDULE II - Valuation and Qualifying Accounts (Details) - Reserve deducted from assets: accumulated provision for uncollectible accounts. - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Valuation and Qualifying Accounts
Balance At Beginning Of Period	$ 1,020,637	$ 1,025,177	$ 1,387,673
Charged To Income	2,266,976	3,463,797	2,213,988
Charged to Other Accounts	2,079,751	2,128,325	2,013,959
Deductions From Reserve	4,744,648	5,596,662	4,590,443
Balance At Close of Period	$ 622,716	$ 1,020,637	$ 1,025,177