Empire District Electric (EDE) 10-Q 7 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 31, 2016
Document and Entity Information
Entity Registrant Name	EMPIRE DISTRICT ELECTRIC CO
Entity Central Index Key	32,689
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		44,094,312
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Operating revenues:
Electric	$ 169,070	$ 162,412	$ 435,256	$ 431,335	$ 559,005	$ 565,471
Gas	4,559	5,084	25,313	31,181	35,835	46,437
Other	1,725	2,218	5,421	6,299	7,907	8,271
Total operating revenues	175,354	169,714	465,990	468,815	602,747	620,179
Operating revenue deductions:
Fuel and purchased power	45,795	45,795	121,140	133,926	157,074	182,494
Cost of natural gas sold and transported	861	1,301	9,900	14,765	14,636	22,860
Regulated operating expenses	27,224	28,437	82,554	84,656	111,449	112,094
Other operating expenses	740	879	2,555	2,474	3,392	3,217
Maintenance and repairs	10,456	11,454	33,387	37,303	44,605	50,424
Merger related expenses	252		8,691		8,691
Depreciation and amortization	23,852	20,090	65,073	60,237	85,386	78,774
Provision for income taxes	17,115	15,850	31,582	28,789	37,593	35,500
Other taxes	10,045	10,125	29,474	30,121	38,531	38,971
Total operating revenue deductions	136,340	133,931	384,356	392,271	501,357	524,334
Operating income	39,014	35,783	81,634	76,544	101,390	95,845
Other income and (deductions):
Allowance for equity funds used during construction	234	1,257	3,000	3,469	4,382	5,317
Interest income	26	2	80	142	83	145
Benefit for other income taxes	145	586	298	713	572	687
Other - non-operating expense, net	(449)	(1,751)	(1,219)	(2,675)	(1,972)	(3,019)
Total other income	(44)	94	2,159	1,649	3,065	3,130
Interest charges:
Long-term debt	11,298	11,001	33,895	32,504	45,193	42,824
Short-term debt	25	80	113	247	130	298
Allowance for borrowed funds used during construction	(140)	(743)	(1,809)	(2,030)	(2,623)	(2,984)
Other	282	254	855	780	1,111	1,033
Total interest charges	11,465	10,592	33,054	31,501	43,811	41,171
Net income	$ 27,505	$ 25,285	$ 50,739	$ 46,692	$ 60,644	$ 57,804
Weighted average number of common shares outstanding - basic (in shares)	44,049	43,728	43,962	43,629	43,920	43,583
Weighted average number of common shares outstanding - diluted (in shares)	44,106	43,819	44,007	43,721	43,956	43,677
Total earnings per weighted average share of common stock - basic and diluted (in dollars per share)	$ 0.62	$ 0.58	$ 1.15	$ 1.07
Total earnings per weighted average share of common stock - basic (in dollars per share)					$ 1.38	$ 1.33
Total earnings per weighted average share of common stock - diluted (in dollars per share					1.38	1.32
Dividends declared per share of common stock (in dollars per share)	$ 0.26	$ 0.26	$ 0.78	$ 0.78	$ 1.04	$ 1.04

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Plant and property, at original cost:
Electric	$ 2,695,201	$ 2,473,927
Gas	86,438	83,402
Other	45,001	44,263
Construction work in progress	31,840	183,689
Total plant and property, Gross	2,858,480	2,785,281
Accumulated depreciation and amortization	809,510	764,895
Total plant and property, Net	2,048,970	2,020,386
Current assets:
Cash and cash equivalents	7,931	1,753
Restricted cash	4,728	4,726
Accounts receivable - trade, net of allowance $726 and $623, respectively	51,873	40,162
Accrued unbilled revenues	17,952	20,653
Accounts receivable - other	14,835	28,320
Fuel, materials and supplies	57,515	60,950
Prepaid expenses and other	11,346	8,835
Unrealized gain in fair value of derivative contracts	4,527	1,295
Regulatory assets	7,127	7,052
Total current assets	177,834	173,746
Noncurrent assets and deferred charges:
Regulatory assets	207,154	209,708
Goodwill	39,492	39,492
Unrealized gain in fair value of derivative contracts	7	16
Other	3,100	3,297
Total noncurrent assets and deferred charges	249,753	252,513
Total Assets	2,476,557	2,446,645
Capitalization and liabilities
Common stock, $1 par value, 44,080,737 and 43,820,726 shares issued and outstanding, respectively	44,081	43,821
Capital in excess of par value	664,523	657,466
Retained earnings	117,869	101,443
Total common stockholders' equity	826,473	802,730
Long-term debt (net of current portion):
Obligations under capital lease	3,335	3,580
First mortgage bonds and secured debt	725,313	724,838
Unsecured debt	100,978	100,935
Total long-term debt	829,626	829,353
Total long-term debt and common stockholders' equity	1,656,099	1,632,083
Current liabilities:
Accounts payable and accrued liabilities	44,487	66,946
Current maturities of long-term debt	25,312	25,246
Short-term debt		25,000
Regulatory liabilities	17,724	8,615
Customer deposits	15,156	14,623
Interest accrued	15,213	7,348
Unrealized loss in fair value of derivative contracts	2,118	4,472
Taxes accrued	19,294	2,832
Other current liabilities	246	323
Total current liabilities	139,550	155,405
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	131,778	132,457
Deferred income taxes	428,066	396,542
Unamortized investment tax credits	18,374	18,487
Pension and other postretirement benefit obligations	74,095	82,144
Unrealized loss in fair value of derivative contracts	1,520	3,696
Other	27,075	25,831
Total noncurrent liabilities	680,908	659,157
Total Capitalization and Liabilities	$ 2,476,557	$ 2,446,645

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Consolidated Balance Sheets
Accounts receivable - trade, allowance (in dollars)	$ 726	$ 623
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares issued	44,080,737	43,820,726
Common stock, shares outstanding	44,080,737	43,820,726

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating activities:
Net income	$ 50,739	$ 46,692
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	63,593	67,099
Pension and other postretirement benefit costs, net of contributions	(2,105)	(12,038)
Deferred income taxes and unamortized investment tax credit, net	31,284	28,237
Allowance for equity funds used during construction	(3,000)	(3,469)
Stock compensation expense	4,116	1,507
Non-cash (gain)/loss on derivatives	3,368	4,892
Other	99	(45)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	862	14,496
Fuel, materials and supplies	3,435	(2,495)
Prepaid expenses, other current assets and deferred charges	(13,533)	(5,813)
Accounts payable and accrued liabilities	(19,167)	(24,621)
Asset retirement obligations	(188)	(27)
Interest, taxes accrued and customer deposits	24,860	25,457
Other liabilities and other deferred credits	11,200	5,818
Net cash provided by operating activities	155,563	145,690
Investing activities:
Capital expenditures - regulated	(94,330)	(145,886)
Capital expenditures and other investments - non-regulated	(682)	(1,828)
Restricted cash	(1)
Net cash used in investing activities	(95,013)	(147,714)
Financing activities:
Proceeds from first mortgage bonds, net		60,000
Long-term debt issuance costs		(519)
Proceeds from issuance of common stock, net of issuance costs	5,173	4,307
Net short-term debt borrowings/(repayments)	(25,000)	(27,750)
Dividends	(34,313)	(34,042)
Other	(232)	(217)
Net cash provided by (used in) financing activities	(54,372)	1,779
Net increase (decrease) in cash and cash equivalents	6,178	(245)
Cash and cash equivalents at beginning of period	1,753	2,105
Cash and cash equivalents at end of period	$ 7,931	$ 1,860

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2016
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	Note 1 - Summary of Significant Accounting Policies We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary which provides natural gas distribution to customers in 48 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business. The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2015. 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 Central), 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 Central (the Merger). See Note 13 for further information.

Recently Issued and Proposed Ac

Recently Issued and Proposed Accounting Standards	9 Months Ended
	Sep. 30, 2016
Recently Issued and Proposed Accounting Standards
Recently Issued and Proposed Accounting Standards	Note 2 - Recently Issued and Proposed Accounting Standards 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. The application of this standard resulted in $8.7 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the December 31, 2015 Consolidated Balance Sheet for comparative purposes and $8.1 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the September 30, 2016 Consolidated Balance Sheet. Revenue from contracts with customers: In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard. Leases: In February 2016, the FASB issued new guidance on accounting for leases. Under the new guidance a lessee will be required to recognize the assets and liabilities arising from leases on the balance sheet. The new guidance also addresses the income statement treatment for leases. Under the new guidance leases will be classified as either operating or financing based on criteria that are similar to the old guidance. Lease expense will be recognized on a straight line basis for operating leases while expense for capital leases will be similar to the finance pattern utilized today. The new guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We are evaluating the impact of the adoption of this standard. Stock Compensation: In March 2016 the FASB issued revised guidance on stock compensation. The updated guidance is intended to simplify some aspects of the accounting for stock compensation such as the income tax impact, classification of awards as either equity or liabilities, and cash flow classification. This guidance will be effective for periods beginning after December 15, 2016. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity. 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. Classification of Certain Cash Receipts and Cash Payments: In August 2016 the FASB issued revised guidance addressing the classification of eight specific cash receipts and cash payments in the statement of cash flows. The revised guidance is intended to reduce diversity in practice in how these items were being classified. The new 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. See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2015 for further information regarding recently issued and proposed accounting standards.

Regulatory Matters

Regulatory Matters	9 Months Ended
	Sep. 30, 2016
Regulatory Matters
Regulatory Matters	Note 3— Regulatory Matters The following table sets forth the components of our regulatory assets and liabilities on our consolidated balance sheet (in thousands). Regulatory Assets and Liabilities September 30, 2016 December 31, 2015 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 Asset retirement obligation Customer programs Missouri solar initiative(3) Current portion of long-term regulatory assets ) ) Unrecovered fuel costs — Other Regulatory assets, long-term Total Regulatory Assets $ $ September 30, 2016 December 31, 2015 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 other postretirement benefits (OPEB) liability. See Note 8. (2) Reflects deferrals resulting from our 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants. (3) Resulting from the Missouri Clean Energy Initiative and consists of approximately 841 solar rebate applications processed and internal costs as of September 30, 2016, (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $10.9 million. (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 in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 for more detail. (5) Resulting from our regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.

Risk Management and Derivative

Risk Management and Derivative Financial Instruments	9 Months Ended
	Sep. 30, 2016
Risk Management and Derivative Financial Instruments
Risk Management and Derivative Financial Instruments	Note 4— Risk Management and Derivative Financial Instruments We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain cost predictability. We began acquiring Transmission Congestion Rights (TCR) in 2013 in an attempt to mitigate the cost of power we purchase from the Southwest Power Pool (SPP) Integrated Marketplace (IM) due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results. All derivative instruments are recognized at fair value on the balance sheet. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the Accounting Standards Codification (ASC) guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms. Risks and uncertainties affecting the determination of fair value include: market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instruments in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income and subject to our fuel adjustment mechanism. As of September 30, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands): September 30, December 31, ASSET DERIVATIVES 2016 2015 Hedging instruments 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 $ $ September 30, December 31, LIABILITY DERIVATIVES 2016 2015 Hedging instruments 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 Total derivatives liabilities $ $ Electric Segment At September 30, 2016, approximately $1.1 million of unrealized net losses are applicable to natural gas financial instruments which will settle within the next twelve months. The following tables set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended September 30, (in thousands): Non-Designated Hedging Balance Sheet Amount of Gain / (Loss) Recognized on Balance Sheet Regulatory Accounting Gain / (Loss) on Three Months Ended Nine Months Ended Twelve Months Ended Electric Segment Derivative 2016 2015 2016 2015 2016 2015 Commodity contracts Regulatory (assets)/liabilities $ ) $ ) $ $ ) $ ) $ ) Transmission congestion rights Regulatory (assets)/liabilities Total Electric Segment $ ) $ ) $ $ $ $ ) Non-Designated Hedging Statement of Amount of Gain / (Loss) Recognized in Income Regulatory Accounting Gain / (Loss) on Three Months Ended Nine Months Ended Twelve Months Ended Electric Segment Derivative 2016 2015 2016 2015 2016 2015 Commodity contracts Fuel and purchased power expense $ ) $ ) $ ) $ ) $ ) $ ) Transmission congestion rights 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 exemption contain a price adjustment feature and will account for these contracts accordingly. As of September 30, 2016, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2016 and for the next four years are shown below at the following average prices per Dekatherm (Dth). 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. Dth Hedged Procurement Year % Hedged Physical Financial Average Price Guidelines Remainder 2016 % — $ Up to 100% 2017 % $ 60% 2018 % $ 40% 2019 % — $ 20% 2020 % — — $ — 10% At September 30, 2016, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP IM (dollars in thousands): Year Monthly MWH Hedged Estimated Fair Value 2016-17 $ Gas Segment We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of September 30, 2016, we had 1.8 million Dths in storage on the three pipelines that serve our customers. This represents 86% 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 and illustrates our hedged position as of September 30, 2016 (Dth in thousands). Season Target % Hedged Dth Hedged - Dth Hedged - Dth in Actual % Nov. 2016 – Mar. 2017 50% — % Nov. 2017 – Mar. 2018 Up to 50% — — % Nov. 2018 – Mar. 2019 Up to 20% — — % A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations. Therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet. The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended September 30, (in thousands). Non-Designated Hedging Balance Sheet Amount of Gain/(Loss) Recognized on Balance Sheet Instruments Due to Regulatory Gain / (Loss) on Three Months Ended Nine Months Ended Twelve Months Ended Accounting - Gas Segment Derivative 2016 2015 2016 2015 2016 2015 Commodity contracts Regulatory (assets)/liabilities $ ) $ ) $ $ ) $ ) $ ) 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 September 30, 2016 and have posted no collateral with counterparties in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our contracts held with our NYMEX 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) September 30, 2016 December 31, 2015 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 periods ended September 30, 2016 and December 31, 2015, 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	9 Months Ended
	Sep. 30, 2016
Fair Value Measurements
Fair Value Measurements	Note 5— Fair Value Measurements The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data. The guidance also requires that the fair value measurements of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements. Our TCR positions, which are acquired on the SPP IM, 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 September 30, 2016 and December 31, 2015. Fair Value Measurements at Reporting Date Using ($ in 000’s) Assets/(Liabilities) Quoted Prices in Active Significant Other Significant September 30, 2016 Derivative assets $ $ $ $ — Derivative liabilities $ ) $ ) $ — $ — December 31, 2015 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 both September 30, 2016 and December 31, 2015 was $851 million. The fair market value at September 30, 2016 was approximately $910 million as compared to approximately $815 million at December 31, 2015. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of September 30, 2016 or that will be realizable in the future.

Financing

Financing	9 Months Ended
	Sep. 30, 2016
Financing
Financing	Note 6— Financing We have an unsecured revolving credit facility of $200 million in place through October 20, 2019. 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. The 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 September 30, 2016, we were in compliance with this covenant as our ratio of total indebtedness was 51% of our total capitalization. This 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 September 30, 2016, we were not in default under any of such other indebtedness. The credit agreement does not legally restrict the use of our cash in the normal course of operations. As of September 30, 2016, there were no outstanding borrowings under either the credit agreement or our commercial paper program which the credit agreement backs. On October 20, 2016, the revolving credit facility was amended such that the pending Merger would not trigger the credit agreement’s change of control provision. The revolving credit facility will remain in place after the Merger closing.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies
Commitments and Contingencies	Note 7— Commitments and Contingencies Legal Proceedings We are a party to various claims and legal proceedings arising out of the normal course of our business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In 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. Proceedings in connection with the pending merger with Liberty Central On March 24, 2016, a purported shareholder of Empire filed a complaint styled as a class action lawsuit in the District Court for the 3rd Judicial District, in Shawnee County, Kansas. The shareholder filed an amended complaint on April 15, 2016. The complaint alleges that Empire’s Board of Directors breached its fiduciary duties in agreeing to the Merger Agreement by, among other things, conducting an inadequate sales process and failing to obtain adequate consideration, having an interest in completing the Merger, and failing to make adequate disclosures in the proxy statement. The complaint seeks various relief, including an injunction against the Merger. The complaint also alleges that Empire, APUC, Liberty Central and Merger Sub aided and abetted such alleged breaches. On June 7, 2016, following arm’s length negotiations, Empire and other defendants entered into a Memorandum of Understanding (MOU) providing for the settlement, subject to court approval, of all claims asserted in the complaint against all defendants. In connection with the MOU, Empire agreed to make additional disclosures related to the Merger in the proxy statement (which were made on June 8, 2016). Empire and the other defendants that entered into the MOU did so solely to avoid the costs, risks and uncertainties inherent in litigation and without admitting any liability or wrongdoing, and vigorously denied, and continue to vigorously deny, that they committed any violation of law or engaged in any wrongful acts alleged in the complaint. The parties to the MOU have agreed to attempt in good faith to finalize and execute a stipulation of settlement and to present the stipulation of settlement to the Court for final approval. The stipulation of settlement will be subject to customary conditions and will provide for, among other things, certification of the alleged class as a non-opt-out class action and an award of plaintiff’s reasonable attorneys’ fees and expenses. The stipulation of settlement will also provide for the release of any and all claims arising out of or relating to the Merger. The settlement is subject to final Court approval following notice to the class members and the parties anticipate this will take place after the closing of the Merger. There can be no assurance that the settling parties will ultimately enter into a stipulation of settlement or that the Court will approve the settlement. In such event, or if the Merger is not consummated for any reason, the proposed settlement will be null and void and of no force and effect. The outcome of the lawsuit cannot be predicted with any certainty. A preliminary injunction could delay or jeopardize the completion of the Merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the Merger. All of the defendants believe that the claims asserted against them in the lawsuit are without merit. Coal, Natural Gas and Transportation Contracts The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of September 30, 2016 (in millions). Firm physical gas and Coal and coal October 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. The firm physical gas and transportation commitments are detailed in the table above. We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of September 30, 2016, are detailed in the table above. Our existing railroad agreement was modified and became effective on October 1, 2016. Our contractual obligations, as reflected in the table above, were reduced as a result of the amendment. The amended terms continue to allow us to operate the Asbury plant up to full load capacity. Purchased Power We have three purchased power agreements. 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 $270.1 million through August 31, 2039, the end date of the agreement. We have a long-term purchased power agreement, which expires in 2028, with Cloud County Windfarm, LLC, majority owned by EDP Renewables North America LLC, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost. We also have a long-term purchased power agreement, which expires in 2020, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost. We do not own any portion of these windfarms. Payments for these agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations. New Construction In April 2016 we completed the conversion of Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion included the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. Construction costs through September 30, 2016 were $167.8 million for the project to date, excluding AFUDC. Final costs are estimated to range from $167.8 million to $175 million, excluding AFUDC. This amount was included in our five-year capital expenditure plan. See “Environmental Matters” below for more information. 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 September 30, 2016. 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 implemented our compliance plan and strategy (2013 Compliance Plan), which largely followed our Integrated Resource Plan (IRP) filed with the Missouri Public Service Commission (MPSC) in mid-2013. On April 1, 2016, we filed our updated IRP, reflecting the completion of our 2013 Compliance Plan. The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), were the drivers behind our 2013 Compliance Plan and its implementation schedule. Compliance costs we have incurred associated with the MATS, CAIR and CSAPR regulations are being recovered in our rates and we anticipate any future costs 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 ACID RAIN 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 Water Discharges MATS : As noted above, the completion of our Compliance Plan puts us in compliance with 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. The EPA’s determination claimed that considering cost does not alter the agency’s conclusion that it is appropriate and necessary to regulate coal and oil-fired electric utility steam generating units (EGUs) under the regulation. MATS has remained in place, and a final supplemental finding issued on April 14, 2016 completes the EPA’s response to the Supreme Court’s decision. The final Technical Corrections Rule was signed March 17, 2016. 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. On February 9, 2016, the Supreme Court ordered a stay on the CPP. Twenty-seven states and numerous industry groups have challenged the CPP’s legality in the D.C. Circuit. The stay will remain in effect until the court resolves the legal challenges to the CPP. Presentation of oral arguments from defenders and challengers of the climate rule were heard before a ten-judge panel on September 27, 2016. The D.C. court is expected to decide the case by late February 2017. If, however, the case is appealed to the Supreme Court, the matter is likely to continue into 2018. Other than the cancellation of the initial submittal deadline in September 2016, the EPA has not made any definitive statements regarding whether CPP timelines may change under the stay. The EPA continues to work on the CPP and released a proposed rule for the Clean Energy Incentive Program (CEIP) design guidelines on June 16, 2016. 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 will begin to 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 affected 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). Compliance with both the CCR and ELG rules at our Asbury plant is expected to require the closure of the existing ash impoundment, construction of a new utility waste landfill and conversion of the existing bottom ash handling from a wet to a dry system. 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. On February 1, 2016, a construction permit application was submitted to the Missouri Department of Natural Resources’ Solid Waste Management Program (SWMP) for a new utility waste landfill adjacent to the Asbury plant. The MDNR has issued a draft construction permit, and approval of the final permit for the utility waste landfill is expected by February 2017. At this time, we anticipate CCR/ELG compliance costs to be approximately $15-$30 million. This estimate is based on our current capital budget, information gathered to date in relation to the multiple CCR Rule reports, and the current execution plan. As we move forward through the ELG and CCR rules’ timelines of compliance, these plans may change. Currently, the landfill construction and bottom ash conversion are anticipated to be complete by early 2019. The CCR impoundment will be closed within five years after inactivity. We expect compliance costs to be recoverable in our rates. 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 The Missouri Clean Energy Initiative (Proposition C) 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 2014-2017, at least 10% in 2018-2020 and 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 previously mentioned 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. 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. We expect solar rebates to be sufficient to allow compliance with the current 2% requirement. As of September 30, 2016, we had processed 841 solar rebate applications resulting in solar rebate-related costs totaling approximately $10.9 million under the new tariff. We have recorded the $10.9 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 adopted that altered the Kansas renewable portfolio standard (RPS), ending all mandatory requirements in 2015. The former 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 meeting the voluntary goal as a result of purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC.

Retirement and Other Employee B

Retirement and Other Employee Benefits	9 Months Ended
	Sep. 30, 2016
Retirement and Other Employee Benefits
Retirement and Other Employee Benefits	Note 8 — Retirement and Other Employee Benefits Net periodic benefit cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components and is shown for our noncontributory defined benefit pension plan, our supplemental retirement program (SERP) and other postretirement benefits (OPEB) (in thousands): Three months ended September 30, Pension Benefits SERP OPEB 2016 2015 2016 2015 2016 2015 Service cost $ $ $ $ $ $ Interest cost Expected return on plan assets ) ) — — ) ) Amortization of prior service cost (1) ) ) ) ) ) ) Amortization of net actuarial loss (1) Net periodic benefit cost $ $ $ $ $ $ Nine months ended September 30, Pension Benefits SERP OPEB 2016 2015 2016 2015 2016 2015 Service cost $ $ $ $ $ $ Interest cost Expected return on plan assets ) ) — — ) ) Amortization of prior service cost (1) ) ) ) ) ) ) Amortization of net actuarial loss (1) Net periodic benefit cost $ $ $ $ $ $ Twelve months ended September 30, Pension Benefits SERP OPEB 2016 2015 2016 2015 2016 2015 Service cost $ $ $ $ $ $ Interest cost Expected return on plan assets ) ) — — ) ) Amortization of prior service cost (1) ) ) ) ) ) ) Amortization of net 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. 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 June 1, 2014 will not receive a subsidy for healthcare benefits received upon retirement. In accordance with our regulatory agreements, our pension funding policy is to make contributions that are at least equal to the greater of either the minimum funding requirements of ERISA or the accrued cost of the plan. We have made contributions totaling $12.5 million through the nine months ended September 30, 2016. No additional contributions are expected for the remainder of the year. Our OPEB funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. We expect to be required to fund approximately $2.6 million during 2016, of which we have made contributions of approximately $1.8 million as of September 30, 2016. The actual minimum funding requirements for both pension and OPEB will be determined based on the results of the actuarial valuations. Employee Stock Purchase Plan Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of September 30, 2016, there were 707,735 shares available for issuance in this plan. 2016 2015 Subscriptions outstanding at September 30 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, 2016 to May 31, 2017. Assumptions for valuation of these shares are shown in the table below. 2016 2015 Fair value of grants at June 30 $ $ Risk-free interest rate % % Expected dividend yield % % Expected volatility % % Expected life in months Grant Date 6/1/16 6/1/15 Pursuant to the Merger Agreement, the right of any employee to continue participation in the ESPP and any purchase period under the ESPP then in effect shall terminate immediately prior to the effective time of the Merger. Payment of all remaining, unused amounts credited to each participant’s account, together with interest as provided in the ESPP, shall be made to the applicable participant as promptly as practicable following the effective time.

Equity Compensation

Equity Compensation	9 Months Ended
	Sep. 30, 2016
Equity Compensation
Equity Compensation	Note 9 — Equity Compensation Our time-vested restricted stock awards and performance-based restricted stock awards are valued as liability awards, in accordance with fair value guidelines. We allow qualified individuals to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award. Grants were made in the first quarter of 2016 (the effect of which is included in the table below). We had unrecognized compensation expense of $1.8 million as of September 30, 2016 which will be recognized over the remaining requisite service period. We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended September 30 (in thousands): Three Months Ended Nine Months Ended Twelve Months Ended 2016 2015 2016 2015 2016 2015 Compensation Expense $ $ $ $ $ $ Tax Benefit Recognized Time-Vested Restricted Stock Awards Our time-vested restricted stock awards vest after a three-year period. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminates during the vesting period because of death, retirement, or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned, which is distributed 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. Consummation of the Merger will constitute a change of control. A summary of time-vested restricted stock activity under the plan for 2015 and 2016 is presented in the table below: 2016 2015 Weighted Weighted Number of Average Grant Number of Average Grant shares Date Fair Value shares Date Fair Value Outstanding at January 1, $ $ Granted Distributed ) ) Forfeited shares ) Outstanding at September 30 $ $ Performance-Based Restricted Stock Awards Performance-based restricted stock awards consisting of the right to receive a number of shares of common stock at the end of the restricted period (assuming performance criteria are met) are granted to qualified individuals. We estimate the fair value of outstanding restricted stock awards using a Monte Carlo option valuation model. 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 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 13 for further discussion of the Merger Agreement). Non-vested performance-based restricted stock awards (based on target number) as of September 30, 2016 and 2015 and changes during the nine months ended September 30, 2016 and 2015 were as follows: 2016 2015 Weighted Weighted Number of Average Grant Number of Average Grant shares Date Fair Value shares Date Fair Value Outstanding at January 1, $ $ Target shares granted $ $ Shares issued in excess of target $ $ Shares awarded ) $ ) $ Forfeited shares — — ) $ Target shares not awarded — $ — — $ — Granted, nonvested at September 30, $ $

Regulated Operating Expense

Regulated Operating Expense	9 Months Ended
	Sep. 30, 2016
Regulated Operating Expense
Regulated Operating Expense	Note 10- Regulated Operating Expenses The following table sets forth the major components comprising “regulated operating expenses” under “Operating Revenue Deductions” on our consolidated statements of income for all periods presented ended September 30 (in thousands): Three Three Nine Nine Twelve Twelve 2016 2015 2016 2015 2016 2015 Electric transmission and distribution expense $ $ $ $ $ $ Natural gas transmission and distribution expense Power operation expense (other than fuel) Customer accounts and assistance expense Employee pension expense (1) Employee healthcare expense (1) General office supplies and expense Administrative and general expense Allowance for uncollectible accounts Miscellaneous expense Total $ $ $ $ $ $ (1) Does not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to and amortized from a regulatory asset and/or a regulatory liability for Missouri, Kansas and Oklahoma jurisdictions.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2016
Segment Information
Segment Information	Note 11— Segment Information The tables below present statement of income information, balance sheet information and capital expenditures of our business segments. Merger related expenses are reflected below in the electric segment operating income. For the three months ended September 30, 2016 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes ) — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income ) — Capital Expenditures $ $ $ — $ For the three months ended September 30, 2015 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes ) — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income ) — Capital Expenditures $ $ $ $ For the nine months ended September 30, 2016 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income — Capital Expenditures $ $ $ $ For the nine months ended September 30, 2015 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income — Capital Expenditures $ $ $ $ For the twelve months ended September 30, 2016 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income — Capital Expenditures $ $ $ $ For the twelve months ended September 30, 2015 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net Income — Capital Expenditures $ $ $ $ As of September 30, 2016 ($-000’s) Electric Gas(1) Other Eliminations Total Balance Sheet Information Total assets $ $ $ $ ) $ (1) Includes goodwill of $39,492. As of December 31, 2015 ($-000’s) Electric Gas(1) Other Eliminations Total Balance Sheet Information Total assets $ $ $ $ ) $ (1) Includes goodwill of $39,492.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Taxes
Income Taxes	Note 12— Income Taxes The following table shows our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended September 30: Three Months Ended Nine Months Ended Twelve Months Ended 2016 2015 2016 2015 2016 2015 Consolidated provision for income taxes $ $ $ $ $ $ Consolidated effective federal and state income tax rates % % % % % % The effective income tax rate for the three, nine and twelve month periods ended September 30, 2016 is higher than comparable periods in 2015 primarily due to lower equity AFUDC income in 2016 compared to 2015. We do not have any unrecognized tax benefits as of September 30, 2016. 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 utilized $43.8 million of the 2014 tax NOLs on our 2015 return. We also anticipate incurring a $17.0 million NOL in 2016 mostly due to bonus depreciation we expect to utilize on our recently completed Riverton Combined Cycle Plant project. As of September 30, 2016, we estimate there are $12.4 million of tax-affected deferred tax assets remaining to be utilized related to the tax NOLs. 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 2016 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.

Mergers and Acquisitions

Mergers and Acquisitions	9 Months Ended
	Sep. 30, 2016
Mergers and Acquisitions
Mergers and Acquisitions	Note 13 — Mergers and Acquisitions Pending Merger with Liberty Utilities (Central) Co. and Liberty Sub Corp. 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 Central), 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 Central (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 (HSR Act) waiting period and receipt of all required regulatory approvals and consents, including from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission FCC), the Arkansas Public Service Commission (APSC), the Kansas Corporation Commission (KCC), the Missouri Public Service Commission (MPSC), the Oklahoma Corporation Commission (OCC) and the Committee on Foreign Investment in the United States (CFIUS), 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. As discussed below, all approvals have been received except for approval from the KCC. If 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 Central. 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 Central 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 Central of its regulatory cooperation covenants, Liberty Central must pay Empire a termination fee of $65.0 million. Simultaneously with the execution of the Merger Agreement, Liberty Central 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 Central and Merger Sub under the Merger Agreement. On March 16, 2016, we filed joint applications in all four states in which we have electric operations (Missouri, Oklahoma, Kansas and Arkansas) and with the FERC requesting approval of the Merger. On May 6, 2016, we received an order from the FERC authorizing the Merger. We received an order on May 12, 2016 from the OCC approving the Merger. On June 16, 2016, Empire’s shareholders voted to approve the merger. On June 29, 2016, we and Algonquin filed a joint notice with CFIUS and we and Algonquin each filed notification with the Federal Trade Commission and U.S. Department of Justice under the HSR Act. The 30-day waiting period under the HSR Act expired on July 29, 2016 without receiving a request for additional information. On June 29, 2016, we filed a joint motion with the APSC to approve a Stipulation and Settlement Agreement in the matter of the joint application for approval of the Merger filed March 16, 2016. We received an order on September 29, 2016 from the APSC approving the Merger. On August 4, 2016, we filed a non-unanimous stipulation and agreement with the staff of the MPSC. On September 7, 2016, we received an order from the MPSC approving the Merger, effective October 7, 2016. On October 6, 2016, we announced a filing with the KCC of a Unanimous Settlement Agreement with respect to the joint application for approval of the Merger filed March 16, 2016. The Unanimous Settlement Agreement is subject to approval by the KCC. As a condition of the Unanimous Settlement Agreement that was reached with the KCC staff, our pending Kansas rate case is to be withdrawn and current base rates are to remain in effect through January 1, 2019. A decision from Kansas regulators is due no later than January 10, 2017, with an expected transaction close early in 2017. In connection with each of the regulatory agreements noted above, Liberty Utilities Co. has agreed to certain commitments regarding ongoing service to Empire customers, employment of Empire personnel, cost sharing mechanisms, and compliance with existing regulatory stipulations in the normal course of business. In connection with entering into the Merger Agreement, Empire has incurred approximately $8.7 million of transaction costs as of September 30, 2016. 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).

Recently Issued and Proposed 19

Recently Issued and Proposed Accounting Standards (Policies)	9 Months Ended
	Sep. 30, 2016
Recently Issued and Proposed Accounting Standards
Recently Issued and Proposed Accounting Standards	Recently Issued and Proposed Accounting Standards 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. The application of this standard resulted in $8.7 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the December 31, 2015 Consolidated Balance Sheet for comparative purposes and $8.1 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the September 30, 2016 Consolidated Balance Sheet. Revenue from contracts with customers: In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard. Leases: In February 2016, the FASB issued new guidance on accounting for leases. Under the new guidance a lessee will be required to recognize the assets and liabilities arising from leases on the balance sheet. The new guidance also addresses the income statement treatment for leases. Under the new guidance leases will be classified as either operating or financing based on criteria that are similar to the old guidance. Lease expense will be recognized on a straight line basis for operating leases while expense for capital leases will be similar to the finance pattern utilized today. The new guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We are evaluating the impact of the adoption of this standard. Stock Compensation: In March 2016 the FASB issued revised guidance on stock compensation. The updated guidance is intended to simplify some aspects of the accounting for stock compensation such as the income tax impact, classification of awards as either equity or liabilities, and cash flow classification. This guidance will be effective for periods beginning after December 15, 2016. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity. 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. Classification of Certain Cash Receipts and Cash Payments: In August 2016 the FASB issued revised guidance addressing the classification of eight specific cash receipts and cash payments in the statement of cash flows. The revised guidance is intended to reduce diversity in practice in how these items were being classified. The new 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. See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2015 for further information regarding recently issued and proposed accounting standards.

Regulatory Matters (Tables)

Regulatory Matters (Tables)	9 Months Ended
	Sep. 30, 2016
Regulatory Matters
Components of regulatory assets and liabilities	The following table sets forth the components of our regulatory assets and liabilities on our consolidated balance sheet (in thousands). Regulatory Assets and Liabilities September 30, 2016 December 31, 2015 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 Asset retirement obligation Customer programs Missouri solar initiative(3) Current portion of long-term regulatory assets ) ) Unrecovered fuel costs — Other Regulatory assets, long-term Total Regulatory Assets $ $ September 30, 2016 December 31, 2015 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 other postretirement benefits (OPEB) liability. See Note 8. (2) Reflects deferrals resulting from our 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants. (3) Resulting from the Missouri Clean Energy Initiative and consists of approximately 841 solar rebate applications processed and internal costs as of September 30, 2016, (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $10.9 million. (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 in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 for more detail. (5) Resulting from our regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.

Risk Management and Derivativ21

Risk Management and Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2016
Risk Management and Derivative Financial Instruments
Schedule of fair value of derivative financial instruments, balance sheet classification	As of September 30, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands): September 30, December 31, ASSET DERIVATIVES 2016 2015 Hedging instruments 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 $ $ September 30, December 31, LIABILITY DERIVATIVES 2016 2015 Hedging instruments 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 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 periods ended September 30, (in thousands): Non-Designated Hedging Balance Sheet Amount of Gain / (Loss) Recognized on Balance Sheet Regulatory Accounting Gain / (Loss) on Three Months Ended Nine Months Ended Twelve Months Ended Electric Segment Derivative 2016 2015 2016 2015 2016 2015 Commodity contracts Regulatory (assets)/liabilities $ ) $ ) $ $ ) $ ) $ ) Transmission congestion rights Regulatory (assets)/liabilities Total Electric Segment $ ) $ ) $ $ $ $ ) Non-Designated Hedging Statement of Amount of Gain / (Loss) Recognized in Income Regulatory Accounting Gain / (Loss) on Three Months Ended Nine Months Ended Twelve Months Ended Electric Segment Derivative 2016 2015 2016 2015 2016 2015 Commodity contracts Fuel and purchased power expense $ ) $ ) $ ) $ ) $ ) $ ) Transmission congestion rights 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	Dth Hedged Procurement Year % Hedged Physical Financial Average Price Guidelines Remainder 2016 % — $ Up to 100% 2017 % $ 60% 2018 % $ 40% 2019 % — $ 20% 2020 % — — $ — 10%
Schedule of transmission congestion rights (TCR)	At September 30, 2016, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP IM (dollars in thousands): Year Monthly MWH Hedged Estimated Fair Value 2016-17 $
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 and illustrates our hedged position as of September 30, 2016 (Dth in thousands). Season Target % Hedged Dth Hedged - Dth Hedged - Dth in Actual % Nov. 2016 – Mar. 2017 50% — % Nov. 2017 – Mar. 2018 Up to 50% — — % Nov. 2018 – Mar. 2019 Up to 20% — — %
Schedule of mark-to-market pre-tax gains/(losses) from non-designated derivative instruments - gas segment	The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended September 30, (in thousands). Non-Designated Hedging Balance Sheet Amount of Gain/(Loss) Recognized on Balance Sheet Instruments Due to Regulatory Gain / (Loss) on Three Months Ended Nine Months Ended Twelve Months Ended Accounting - Gas Segment Derivative 2016 2015 2016 2015 2016 2015 Commodity contracts Regulatory (assets)/liabilities $ ) $ ) $ $ ) $ ) $ ) Total - Gas Segment $ ) $ ) $ $ ) $ ) $ )
Schedule of margin deposit assets	(in millions) September 30, 2016 December 31, 2015 Margin deposit assets $ $

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2016
Fair Value Measurements
Schedule of transmission congestion rights (TCR) and commodity contracts measured at fair value	Fair Value Measurements at Reporting Date Using ($ in 000’s) Assets/(Liabilities) Quoted Prices in Active Significant Other Significant September 30, 2016 Derivative assets $ $ $ $ — Derivative liabilities $ ) $ ) $ — $ — December 31, 2015 Derivative assets $ $ $ $ — Derivative liabilities $ ) $ ) $ — $ — *The only recurring measurements are derivative related.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2016
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 September 30, 2016 (in millions). Firm physical gas and Coal and coal October 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 —
Summary of most significant environmental regulations affecting operations	Regulations Air Emissions - NOx and SO2 ACID RAIN 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 Water Discharges

Retirement and Other Employee24

Retirement and Other Employee Benefits (Tables)	9 Months Ended
	Sep. 30, 2016
Retirement and Other Employee Benefits
Schedule of net periodic benefit pension cost	Net periodic benefit cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components and is shown for our noncontributory defined benefit pension plan, our supplemental retirement program (SERP) and other postretirement benefits (OPEB) (in thousands): Three months ended September 30, Pension Benefits SERP OPEB 2016 2015 2016 2015 2016 2015 Service cost $ $ $ $ $ $ Interest cost Expected return on plan assets ) ) — — ) ) Amortization of prior service cost (1) ) ) ) ) ) ) Amortization of net actuarial loss (1) Net periodic benefit cost $ $ $ $ $ $ Nine months ended September 30, Pension Benefits SERP OPEB 2016 2015 2016 2015 2016 2015 Service cost $ $ $ $ $ $ Interest cost Expected return on plan assets ) ) — — ) ) Amortization of prior service cost (1) ) ) ) ) ) ) Amortization of net actuarial loss (1) Net periodic benefit cost $ $ $ $ $ $ Twelve months ended September 30, Pension Benefits SERP OPEB 2016 2015 2016 2015 2016 2015 Service cost $ $ $ $ $ $ Interest cost Expected return on plan assets ) ) — — ) ) Amortization of prior service cost (1) ) ) ) ) ) ) Amortization of net 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 employee stock purchase plan	2016 2015 Subscriptions outstanding at September 30 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, 2016 to May 31, 2017.
Schedule of assumptions used in valuation of shares under employee stock purchase plan	2016 2015 Fair value of grants at June 30 $ $ Risk-free interest rate % % Expected dividend yield % % Expected volatility % % Expected life in months Grant Date 6/1/16 6/1/15

Equity Compensation (Tables)

Equity Compensation (Tables)	9 Months Ended
	Sep. 30, 2016
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 periods ended September 30 (in thousands): Three Months Ended Nine Months Ended Twelve Months Ended 2016 2015 2016 2015 2016 2015 Compensation Expense $ $ $ $ $ $ Tax Benefit Recognized
Schedule of time vested restricted stock activity	2016 2015 Weighted Weighted Number of Average Grant Number of Average Grant shares Date Fair Value shares Date Fair Value Outstanding at January 1, $ $ Granted Distributed ) ) Forfeited shares ) Outstanding at September 30 $ $
Schedule of non-vested performance-based restricted stock awards (based on target number) and changes during the reporting period	2016 2015 Weighted Weighted Number of Average Grant Number of Average Grant shares Date Fair Value shares Date Fair Value Outstanding at January 1, $ $ Target shares granted $ $ Shares issued in excess of target $ $ Shares awarded ) $ ) $ Forfeited shares — — ) $ Target shares not awarded — $ — — $ — Granted, nonvested at September 30, $ $

Regulated Operating Expense (Ta

Regulated Operating Expense (Tables)	9 Months Ended
	Sep. 30, 2016
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 all periods presented ended September 30 (in thousands): Three Three Nine Nine Twelve Twelve 2016 2015 2016 2015 2016 2015 Electric transmission and distribution expense $ $ $ $ $ $ Natural gas transmission and distribution expense Power operation expense (other than fuel) Customer accounts and assistance expense Employee pension expense (1) Employee healthcare expense (1) General office supplies and expense Administrative and general expense Allowance for uncollectible accounts Miscellaneous expense Total $ $ $ $ $ $ (1) Does not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to and amortized from a regulatory asset and/or a regulatory liability for Missouri, Kansas and Oklahoma jurisdictions.

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2016
Segment Information
Schedule of statement of income information, balance sheet information and capital expenditures by business segments	For the three months ended September 30, 2016 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes ) — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income ) — Capital Expenditures $ $ $ — $ For the three months ended September 30, 2015 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes ) — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income ) — Capital Expenditures $ $ $ $ For the nine months ended September 30, 2016 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income — Capital Expenditures $ $ $ $ For the nine months ended September 30, 2015 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income — Capital Expenditures $ $ $ $ For the twelve months ended September 30, 2016 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net income — Capital Expenditures $ $ $ $ For the twelve months ended September 30, 2015 ($-000’s) Electric Gas Other Eliminations Total Statement of Income Information Revenues $ $ $ $ ) $ Depreciation and amortization — Federal and state income taxes — Operating income — Interest income ) Interest expense — ) Income from AFUDC (debt and equity) — — Net Income — Capital Expenditures $ $ $ $ As of September 30, 2016 ($-000’s) Electric Gas(1) Other Eliminations Total Balance Sheet Information Total assets $ $ $ $ ) $ (1) Includes goodwill of $39,492. As of December 31, 2015 ($-000’s) Electric Gas(1) Other Eliminations Total Balance Sheet Information Total assets $ $ $ $ ) $ (1) Includes goodwill of $39,492.

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2016
Income Taxes
Schedule of provision for income taxes and consolidated effective federal and state income tax rates	The following table shows our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended September 30: Three Months Ended Nine Months Ended Twelve Months Ended 2016 2015 2016 2015 2016 2015 Consolidated provision for income taxes $ $ $ $ $ $ Consolidated effective federal and state income tax rates % % % % % %

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Details)	9 Months Ended
	Sep. 30, 2016segmentitem
Accounting Policies
Number of business segments | segment	3
Number of towns to which water service is provided	3
Number of communities provided natural gas distribution	48

Recently Issued and Proposed 30

Recently Issued and Proposed Accounting Standards (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Scenario, Adjustment | Accounting Standards Update 2015-03 Simplifying the Presentation of Debt Issuance Costs
Recently Issued and Proposed Accounting Standards
Change in financial position	$ 8.1	$ 8.7

Regulatory Matters (Details)

Regulatory Matters (Details) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016USD ($)item	Dec. 31, 2015USD ($)item
Regulatory Assets:
Regulatory assets, current	$ 7,127	$ 7,052
Regulatory assets, long-term	207,154	209,708
Total Regulatory Assets	214,281	216,760
Regulatory Liabilities:
Regulatory liabilities, current	17,724	8,615
Regulatory liabilities, long-term	131,778	132,457
Total Regulatory Liabilities	149,502	141,072
Over recovered fuel costs
Regulatory Liabilities:
Regulatory liabilities, current	14,416	5,280
Regulatory liabilities, long-term	2,065	2,300
System reliability - vegetation management
Regulatory Liabilities:
Regulatory liabilities, long-term		1,320
Current portion of long-term regulatory liabilities
Regulatory Liabilities:
Regulatory liabilities, current	3,308	3,335
Other
Regulatory Liabilities:
Regulatory liabilities, long-term		56
Costs of removal
Regulatory Liabilities:
Regulatory liabilities, long-term	98,265	94,193
SWPA payment for Ozark Beach lost generation
Regulatory Liabilities:
Regulatory liabilities, long-term	12,300	14,213
Income taxes
Regulatory Liabilities:
Regulatory liabilities, long-term	11,083	11,244
Deferred construction accounting costs - fuel
Regulatory Liabilities:
Regulatory liabilities, long-term	7,574	7,690
Unamortized gain on interest rate derivative
Regulatory Liabilities:
Regulatory liabilities, long-term	2,904	3,031
Pension and other postretirement benefits
Regulatory Liabilities:
Regulatory liabilities, long-term	895	1,745
Under recovered fuel costs
Regulatory Assets:
Regulatory assets, current	7	196
Current portion of long-term regulatory assets
Regulatory Assets:
Regulatory assets, current	7,120	6,856
Pension and other postretirement benefits
Regulatory Assets:
Regulatory assets, long-term	101,307	108,273
Income taxes
Regulatory Assets:
Regulatory assets, long-term	48,581	48,613
Deferred construction accounting costs
Regulatory Assets:
Regulatory assets, long-term	14,712	14,977
Unamortized loss on reacquired debt
Regulatory Assets:
Regulatory assets, long-term	9,226	9,731
System reliability - vegetation management
Regulatory Assets:
Regulatory assets, long-term	2,164	3,604
Storm costs
Regulatory Assets:
Regulatory assets, long-term	3,118	3,531
Asset retirement obligation.
Regulatory Assets:
Regulatory assets, long-term	10,493	7,722
Customer programs
Regulatory Assets:
Regulatory assets, long-term	6,677	5,942
Missouri solar initiative
Regulatory Assets:
Regulatory assets, long-term	$ 10,897	$ 3,504
Number of solar rebate applications processed | item	841	262
Unrecovered fuel costs
Regulatory Assets:
Regulatory assets, long-term	$ 1,089
Other
Regulatory Assets:
Regulatory assets, long-term	2,687	$ 2,892
Electric | Unsettled derivative losses- electric segment
Regulatory Assets:
Regulatory assets, long-term	$ 3,323	$ 7,775

Risk Management and Derivativ32

Risk Management and Derivative Financial Instruments - Fair Value (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair value of derivative financial instruments
Current assets	$ 4,527	$ 1,295
Non-current assets and deferred charges - other	7	16
Total derivatives assets	4,534	1,311
Current liabilities	2,118	4,472
Non-current liabilities and deferred credits	1,520	3,696
Total derivatives liabilities	3,638	8,168
Hedging instruments | Commodity contracts | Gas
Fair value of derivative financial instruments
Current assets	121	2
Non-current assets and deferred charges - other	7	16
Current liabilities		282
Non-current liabilities and deferred credits		66
Hedging instruments | Commodity contracts | Electric
Fair value of derivative financial instruments
Current assets	1,039
Current liabilities	2,118	4,190
Non-current liabilities and deferred credits	1,520	3,630
Hedging instruments | Transmission congestion rights (TCR) | Electric
Fair value of derivative financial instruments
Current assets	$ 3,367	$ 1,293

Risk Management and Derivativ33

Risk Management and Derivative Financial Instruments - Gain Loss on Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Electric
Gain / (Loss) on derivatives
Unrealized net gains applicable to financial instruments which will settle in next twelve months	$ 1,100		$ 1,100		$ 1,100
Period within which financial instruments will settle			12 months
Amount of Gain/(Loss) Recognized on Balance Sheet	(1,280)	$ (1,565)	$ 7,644	$ 841	4,918	$ (3,830)
Amount of Gain / (Loss) Recognized in Income on Derivative	(763)	(2,971)	37	65	(675)	1,548
Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(65)	(236)	107	(50)	(289)	(647)
Commodity contracts | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(1,678)	(1,690)	1,705	(3,909)	(1,240)	(10,152)
Amount of Gain / (Loss) Recognized in Income on Derivative	(2,231)	(4,104)	(3,774)	(6,381)	(5,508)	(7,105)
Commodity contracts | Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(65)	(236)	107	(50)	(289)	(647)
Transmission congestion rights (TCR) | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	398	125	5,939	4,750	6,158	6,322
Amount of Gain / (Loss) Recognized in Income on Derivative	$ 1,468	$ 1,133	$ 3,811	$ 6,446	$ 4,833	$ 8,653

Risk Management and Derivativ34

Risk Management and Derivative Financial Instruments - Derivatives Hedging Strategy (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016USD ($)itemMWh$ / item
Transmission congestion rights (TCR) - 2015
Procurement guidelines
Monthly MWH Hedged | MWh	8,464
Monthly MWH Hedged, estimated fair value | $	$ 3,367
Electric | Natural Gas Usage - Remainder 2016
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	33.00%
Dth Hedged Financial	1,160,000
Average Price (in dollars per dth) | $ / item	3.122
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	2.995
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 Derivativ35

Risk Management and Derivative Financial Instruments - Other (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)item	Dec. 31, 2015USD ($)
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 | $	$ 4.2	$ 11.2
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)	1,800,000
Number of pipelines that serve customers (in units)	3
Storage capacity utilized (as a percent)	86.00%
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	2
Gas | Nov. 2016 - Mar. 2017
Gas Usage Hedged By Winter Season
Target % Hedged	50.00%
Dth Hedged Financial	200
Dth in Storage	1,751
Actual % Hedged	65.00%
Gas | High end of range | Nov. 2017 - Mar. 2018
Gas Usage Hedged By Winter Season
Target % Hedged	50.00%
Dth Hedged Financial	280
Actual % Hedged	9.00%
Gas | High end of range | Nov. 2018 - Mar. 2019
Gas Usage Hedged By Winter Season
Target % Hedged	20.00%
Dth Hedged Financial	0
Actual % Hedged	0.00%

Fair Value Measurements - Hiera

Fair Value Measurements - Hierarchy (Details) - Recurring basis - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair Value Measurements at Reporting Date
Derivative assets	$ 4,534	$ 1,311
Derivative liabilities	(3,638)	(8,168)
Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)
Fair Value Measurements at Reporting Date
Derivative assets	1,167	18
Derivative liabilities	(3,638)	(8,168)
Significant Other Observable Inputs (Level 2)
Fair Value Measurements at Reporting Date
Derivative assets	$ 3,367	$ 1,293

Fair Value Measurements - Long

Fair Value Measurements - Long Term Debt (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Long-Term Debt
Carrying amount of total long-term debt exclusive of capital leases	$ 851	$ 851
Fair market value	$ 910	$ 815

Financing (Details)

Financing (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)item
Schedule of debt instruments
Outstanding borrowings	$ 0
Unsecured revolving credit facility
Schedule of debt instruments
Unsecured revolving credit facility	200
Additional borrowing capacity	$ 75
Number of extensions | item	2
Extension period	1 year
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	51.00%
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.	$ 25
Swingline loan
Schedule of debt instruments
Unsecured revolving credit facility	20
Letters of credit
Schedule of debt instruments
Unsecured revolving credit facility	$ 20

Commitments and Contingencies -

Commitments and Contingencies - Other (Detail) $ in Millions	Dec. 15, 2008	Dec. 15, 2005	Sep. 30, 2016USD ($)OfficeitemMW
Electric | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Cost related to pre-engineering, site preparation activities and contract cost project to date			$ 167.8
Term of Capital Expenditure Plan			5 years
Electric | Low end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			$ 167.8
Electric | High end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			175
Firm Physical gas and transportation contracts
Commitments and Contingencies
October 1, 2016 through December 31, 2016			4.2
January 1, 2017 through December 31, 2018			37.4
January 1, 2019 through December 31, 2020			28.8
January 1, 2021 and beyond			45.7
Coal and coal transportation contracts
Commitments and Contingencies
October 1, 2016 through December 31, 2016			1.6
January 1, 2017 through December 31, 2018			14.5
January 1, 2019 through December 31, 2020			$ 2.2
Purchased power
Commitments and Contingencies
Number of purchased power agreement | item			3
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			$ 270.1
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			$ 14.6
Purchased power | Elk River Windfarm
Commitments and Contingencies
Energy capacity (in megawatts) | MW			150
Period of the average cost that is used as a basis for determining the maximum annual payments		20 years
Purchased power | Elk River Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 0
Purchased power | Elk River Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			16.9
Leases
Commitments and Contingencies
Gross amount of assets recorded under capital leases			$ 5.3
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 | Office			1
Leases | Plum Point Energy Station
Commitments and Contingencies
Number of railcars under capital leases | item			108

Commitments and Contingencies40

Commitments and Contingencies - Regulations (Details) $ in Thousands	Jan. 09, 2016state	Sep. 30, 2016USD ($)item	Dec. 31, 2015USD ($)
Environmental Laws And Regulations
Regulatory assets of Missouri solar initiative		$ 207,154	$ 209,708
Surface Impoundments | Asbury Power Plant | Electric
Environmental Laws And Regulations
Asset retirement obligation		$ 5,400
CRR impound will be closed after inactivity		5 years
Surface Impoundments | Asbury Power Plant | Electric | High end of range
Environmental Laws And Regulations
Compliance costs		$ 30,000
Surface Impoundments | Asbury Power Plant | Electric | Low end of range
Environmental Laws And Regulations
Compliance costs		15,000
Surface Impoundments | Iatan | Electric
Environmental Laws And Regulations
Asset retirement obligation		$ 4,400
Renewable Energy | Electric
Environmental Laws And Regulations
Minimum percentage of Missouri retail sales required to generate or purchase electricity in 2014-2017		5.00%
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2018-2020		10.00%
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 solar rebate applications processed in Missouri solar initiative | item		841
Rebate Commitments in Missouri solar initiative		$ 10,900
Regulatory assets of Missouri solar initiative		$ 10,900
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
Clean Power Plan
Environmental Laws And Regulations
Number of states initiating legal challenges to invalidate rule | state	27

Retirement and Other Employee41

Retirement and Other Employee Benefits (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits
Net Periodic Pension Benefit Cost:
Service cost	$ 1,752	$ 1,816	$ 5,650	$ 5,581		$ 7,511	$ 7,198
Interest cost	2,669	2,702	7,936	7,708		10,505	10,413
Expected return on plan assets	(3,387)	(3,396)	(10,318)	(10,175)		(13,709)	(13,452)
Amortization of prior service cost	(157)	(157)	(472)	(472)		(630)	(368)
Amortization of net actuarial loss	2,313	2,835	6,526	7,525		9,034	9,178
Net periodic benefit cost	3,190	3,800	9,322	10,167		12,711	12,969
Employer contribution			12,500
SERP
Net Periodic Pension Benefit Cost:
Service cost	41	33	132	119		171	157
Interest cost	110	102	325	286		421	383
Amortization of prior service cost	(4)	(10)	(11)	(32)		(21)	(34)
Amortization of net actuarial loss	149	168	427	448		576	574
Net periodic benefit cost	296	293	873	821		1,147	1,080
OPEB
Net Periodic Pension Benefit Cost:
Service cost	826	945	2,453	2,785		3,382	3,435
Interest cost	1,188	1,175	3,501	3,502		4,668	4,592
Expected return on plan assets	(1,375)	(1,272)	(4,124)	(3,897)		(5,423)	(5,097)
Amortization of prior service cost	(253)	(253)	(758)	(758)		(1,011)	(1,011)
Amortization of net actuarial loss	326	699	841	2,061		1,528	2,303
Net periodic benefit cost	$ 712	$ 1,294	1,913	$ 3,693		$ 3,144	$ 4,222
Pension contributions					$ 2,600
Employer contribution			$ 1,800
Healthcare benefits
Net Periodic Pension Benefit Cost:
Eligible age			55 years
Minimum service period for eligibility			5 years

Retirement and Other Employee42

Retirement and Other Employee Benefits - Employee Stock Purchase Plan (Details) - Employee Stock Purchase Plan - $ / shares	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
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	707,735
Subscriptions outstanding (in shares)	25,118	59,463
Maximum subscription price (in dollars per share)	$ 30.29	$ 21.43
Shares of stock issued	56,908	56,193
Stock issuance price (in dollars per share)	$ 21.09	$ 21.01
Assumptions for valuation of shares
Fair value of grants (in dollars per share)	$ 6.11	$ 3.58
Risk-free interest rate (as a percent)	0.70%	0.26%
Expected dividend yield (as a percent)	3.10%	4.40%
Expected volatility (as a percent)	27.00%	21.00%
Expected life in months	12 months	12 months

Equity Compensation - Share Bas

Equity Compensation - Share Based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Other Equity Compensation
Unrecognized compensation expense	$ 1,800		$ 1,800		$ 1,800
Compensation Expense	1,302	$ 598	4,211	$ 1,659	6,832		$ 2,976
Tax Benefit Recognized	$ 485	$ 213	$ 1,565	$ 592	$ 2,549		$ 1,081
Time-Vested Restricted Stock Awards
Assumptions used for estimating fair value of grants outstanding
Vesting period			3 years
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)			55,600	41,000	55,600	41,000
Granted (in shares)			18,400	19,000
Distributed (in shares)			(18,500)	(1,654)
Forfeited shares (in shares)			0	(2,746)
Nonvested, balance at the end of the period (in shares)	55,500	55,600	55,500	55,600	55,500	55,600	55,600
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)			$ 24.60	$ 21.89	$ 24.60	$ 21.89
Granted (in dollars per share)			29.53	30.40
Distributed (in dollars per share)			21.36	21.92
Forfeited shares ( in dollars per share)						25.91
Nonvested, balance at the end of the period (in dollars per share)	$ 27.31	$ 24.60	$ 27.31	$ 24.60	$ 27.31	$ 24.60	$ 24.60
Performance-Based Restricted Stock Awards
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)			69,021	63,300	69,021	63,300
Target shares granted (in shares)			22,400	21,800
Shares issued in excess of target (in shares)			18,403	3,653
Shares awarded (in shares)			(43,036)	(13,653)
Forfeited shares (in shares)				(6,079)
Nonvested, balance at the end of the period (in shares)	66,788	69,021	66,788	69,021	66,788	69,021	69,021
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)			$ 24.38	$ 21.74	$ 24.38	$ 21.74
Target shares granted (in dollars per share)			$ 29.53	$ 30.40
Shares issued in excess of target (in dollars per share)			21.36	30.55
Shares awarded (in dollars per share)			$ 21.36	$ 30.55
Forfeited shares ( in dollars per share)				24.10
Nonvested, balance at the end of the period (in dollars per share)	$ 27.22	$ 24.38	$ 27.22	$ 24.38	$ 27.22	$ 24.38	$ 24.38

Regulated Operating Expenses (D

Regulated Operating Expenses (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Regulated Operating Expense
Electric transmission and distribution expense	$ 5,340	$ 7,325	$ 18,802	$ 21,839	$ 25,856	$ 28,619
Natural gas transmission and distribution expense	610	592	1,933	1,997	2,635	2,558
Power operation expense (other than fuel)	4,466	4,258	12,505	13,813	16,955	17,708
Customer accounts and assistance expense	2,712	2,649	8,252	8,142	11,047	10,889
Employee pension expense	3,574	2,769	8,843	8,170	11,459	10,797
Employee healthcare expense	2,691	3,022	7,373	7,640	9,895	9,970
General office supplies and expense	4,157	3,352	12,434	9,032	17,840	13,591
Administrative and general expense	2,935	3,650	10,594	11,647	13,810	15,061
Allowance for uncollectible accounts	651	705	1,530	2,050	1,560	2,453
Miscellaneous expense	88	115	288	326	392	448
Total	$ 27,224	$ 28,437	$ 82,554	$ 84,656	$ 111,449	$ 112,094

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	$ 175,354	$ 169,714	$ 465,990	$ 468,815	$ 602,747	$ 620,179
Depreciation and amortization	23,852	20,090	65,073	60,237	85,386	78,774
Federal and state income taxes	16,970	15,264	31,284	28,076	37,021	34,813
Operating income	39,014	35,783	81,634	76,544	101,390	95,845
Interest income	26	2	80	142	83	145
Interest expense	11,605	11,335	34,863	33,531	46,434	44,155
Income from AFUDC (debt and equity)	374	2,000	4,809	5,499	7,005	8,301
Net income	27,505	25,285	50,739	46,692	60,644	57,804
Capital Expenditures	25,080	42,346	90,312	143,480	123,357	207,276
Total assets	2,476,557		2,476,557		2,476,557		$ 2,446,645
Goodwill	39,492		39,492		39,492		39,492
Operating segments | Electric
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	169,070	162,412	435,256	431,335	559,005	565,471
Depreciation and amortization	22,365	18,651	60,599	55,930	79,402	72,971
Federal and state income taxes	17,065	15,137	30,293	26,296	35,121	31,894
Operating income	38,250	34,622	77,195	70,791	94,527	87,188
Interest income	25	1	69	128	74	131
Interest expense	10,668	10,384	32,054	30,686	42,675	40,352
Income from AFUDC (debt and equity)	369	1,997	4,798	5,493	6,987	8,290
Net income	27,691	25,086	49,139	43,809	57,569	53,005
Capital Expenditures	23,715	39,867	86,366	137,977	117,500	199,189
Total assets	2,362,639		2,362,639		2,362,639		2,331,705
Operating segments | Gas
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	4,559	5,084	25,313	31,181	35,835	46,437
Depreciation and amortization	1,009	984	3,010	2,932	4,001	3,902
Federal and state income taxes	(420)	(340)	57	454	403	1,230
Operating income	249	413	2,977	3,629	4,501	5,859
Interest income	5	6	30	34	32	36
Interest expense	967	968	2,903	2,898	3,872	3,865
Income from AFUDC (debt and equity)	5	3	11	6	18	11
Net income	(714)	(560)	81	728	641	1,981
Capital Expenditures	1,261	2,009	3,264	3,679	4,775	5,431
Total assets	124,544		124,544		124,544		127,359
Goodwill	39,492		39,492		39,492		39,492
Operating segments | Other
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	2,070	2,563	6,455	7,334	9,286	9,650
Depreciation and amortization	478	455	1,464	1,375	1,983	1,901
Federal and state income taxes	325	467	934	1,326	1,497	1,689
Operating income	515	748	1,462	2,124	2,362	2,798
Interest income	26	12	75	33	90	40
Net income	528	759	1,519	2,155	2,434	2,818
Capital Expenditures	104	470	682	1,824	1,082	2,656
Total assets	39,470		39,470		39,470		38,299
Eliminations
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	(345)	(345)	(1,034)	(1,035)	(1,379)	(1,379)
Interest income	(30)	(17)	(94)	(53)	(113)	(62)
Interest expense	(30)	$ (17)	(94)	$ (53)	(113)	$ (62)
Total assets	$ (50,096)		$ (50,096)		$ (50,096)		$ (50,718)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2010
Income Taxes
Consolidated provision for income taxes	$ 16,970	$ 15,264	$ 31,284	$ 28,076	$ 37,021	$ 34,813
Consolidated effective federal and state income tax rates (as a percent)	38.20%	37.60%	38.10%	37.60%	37.90%	37.60%
Net operating loss	$ 17,000		$ 17,000		$ 17,000		$ 74,100
Deferred tax assets							43,800
Deferred tax assets estimated to be utilized	$ 12,400		$ 12,400		$ 12,400
Advanced coal investment tax credit								$ 17,700
Maximum tax credit utilized							$ 9,000

Mergers and Acquisitions (Detai

Mergers and Acquisitions (Details)	Jun. 29, 2016	Mar. 16, 2016item	Feb. 09, 2016USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)
Mergers and Acquisitions
Maximum period for extending regulatory approvals			6 months
Maximum period for exercising termination right			9 months
Termination fee			$ 53,000,000
Number of States to which Entity Provides Electric Service | item		4
Transaction costs				$ 252,000	$ 8,691,000		$ 8,691,000
Waiting period	30 days
Liberty Utilities (Central) Co
Mergers and Acquisitions
Right to receive in cash without interest			34
Termination fee			$ 65,000,000
Forecast
Mergers and Acquisitions
Percentage payable of transaction costs						50.00%
Forecast | High end of range
Mergers and Acquisitions
Transaction costs						$ 17,000,000
Forecast | Low end of range
Mergers and Acquisitions
Transaction costs						$ 15,000,000