Adjustments to reconcile net income to net operating cash:

$ 58,124

$ 44,675

$ 41,140

Depreciation and amortization

36,599

32,159

29,972

Depreciation and accretion included in operations expenses

8,122

7,334

6,978

Deferred income taxes, net

^[1]

11,085

31,257

20,520

Realized (gain) loss on sale of assets/investments

3,179

695

(340)

Unrealized (gain) loss on investments/commodity contracts

(1,001)

(385)

Employee benefits and compensation

1,577

1,887

1,235

Accounts receivable and accrued revenue

2,490

2,367

1,937

Other, net

(750)

(79)

Changes in assets and liabilities:

(19,506)

(27,013)

17,097

Propane inventory, storage gas and other inventory

(9,036)

(2,531)

1,527

Regulatory assets/liabilities, net

(2,855)

(7,523)

3,883

Prepaid expenses and other current assets

(7,001)

(1,387)

(759)

Accounts payable and other accrued liabilities

15,596

19,599

(11,324)

Income taxes receivable (payable)

8,110

2,466

(4,967)

Customer deposits and refunds

5,513

2,065

1,976

Accrued compensation

2,488

358

(331)

Other assets and liabilities, net

(2,645)

(1,803)

(3,972)

Net cash provided by operating activities

110,089

104,141

104,715

Investing Activities

Property, plant and equipment expenditures

(175,329)

(169,861)

(143,599)

Proceeds from sale of assets

708

174

164

Acquisitions, net of cash acquired

(11,945)

(20,930)

Environmental expenditures

(329)

(350)

(174)

Net cash used in investing activities

(186,895)

(170,037)

(164,539)

Financing Activities

Common stock dividends

(19,928)

(17,482)

(15,924)

Issuance of stock for Dividend Reinvestment Plan

811

813

Proceeds from issuance of common stock, net of expenses

(10)

^[2]

57,360

^[2]

(692)

(770)

(592)

Change in cash overdrafts due to outstanding checks

1,738

3,920

2,450

Net borrowing under line of credit agreements

39,338

32,526

82,178

Proceeds from issuance of long-term debt

69,807

Repayment of long-term debt and capital lease obligation

(12,100)

(9,146)

(10,820)

Net cash provided by financing activities

78,242

67,219

58,105

Net Increase (Decrease) in Cash and Cash Equivalents

1,436

1,323

(1,719)

Cash and Cash Equivalents — Beginning of Period

4,178

2,855

4,574

Cash and Cash Equivalents — End of Period

$ 5,614

$ 4,178

$ 2,855

[1]	(1)Includes $873,000, $2.1 million and $2.1 million of deferred state income taxes for the years 2017, 2016 and 2015, respectively.
[2]	On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million.

Consolidated Balance Sheets - USD ($)
$ in Thousands

Dec. 31, 2017

Dec. 31, 2016

Property, Plant and Equipment

Regulated Energy

$ 1,073,736

$ 957,681

Unregulated Energy

210,682

196,800

Other businesses and eliminations

27,699

21,114

Total property, plant and equipment

1,312,117

1,175,595

Less: Accumulated depreciation and amortization

(270,599)

(245,207)

Plus: Construction work in progress

84,509

56,276

Net property, plant and equipment

1,126,027

986,664

Current Assets

Cash and cash equivalents

5,614

4,178

Accounts receivable (less allowance for uncollectible accounts of $936 and $909, respectively)

77,223

62,803

Accrued revenue

22,279

16,986

Propane inventory, at average cost

8,324

6,457

Other inventory, at average cost

12,022

4,576

Regulatory assets

10,930

7,694

Storage gas prepayments

5,250

5,484

Income taxes receivable

14,778

22,888

Prepaid expenses

13,621

6,792

Derivative assets, at fair value

1,286

823

Other current assets

7,260

2,470

Total current assets

178,587

141,151

Deferred Charges and Other Assets

Goodwill

22,104

15,070

Other intangible assets, net

4,686

1,843

Investments, at fair value

6,756

4,902

Regulatory assets

75,575

76,803

Receivables and other deferred charges

3,699

2,786

Total deferred charges and other assets

112,820

101,404

Total Assets

1,417,434

1,229,219

Stockholders’ equity

Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding

Common stock, par value $0.4867 per share (authorized 50,000,000 shares)

7,955

7,935

Additional paid-in capital

253,470

250,967

Retained earnings

229,141

192,062

Deferred compensation obligation

(4,272)

(4,878)

3,395

2,416

Treasury stock

(3,395)

(2,416)

Total stockholders’ equity

^[1]

486,294

446,086

Long-term debt, net of current maturities

197,395

136,954

Total capitalization

683,689

583,040

Current Liabilities

Current portion of long-term debt

9,421

12,099

Short-term borrowing

250,969

209,871

Accounts payable

74,688

56,935

Customer deposits and refunds

34,751

29,238

Accrued interest

1,742

1,312

Dividends payable

5,312

4,973

Accrued compensation

13,112

10,496

Regulatory liabilities

6,485

1,291

Derivative liabilities, at fair value

6,247

773

Other accrued liabilities

10,273

7,063

Total current liabilities

413,000

334,051

Deferred Credits and Other Liabilities

Deferred income taxes

135,850

222,894

Regulatory liabilities

140,978

43,064

Environmental liabilities

8,263

8,592

Other pension and benefit costs

29,699

32,828

Deferred investment tax credits and other liabilities

5,955

4,750

Total deferred credits and other liabilities

320,745

312,128

Commitments and Contingencies

Total Capitalization and Liabilities

$ 1,417,434

$ 1,229,219

[1]	Includes 90,961, 76,745 and 70,631 shares at December 31, 2017, 2016 and 2015, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 936	$ 909
Common stock, par value	$ 0.4867	$ 0.4867
Common stock, shares authorized	50,000,000	50,000,000
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01

Consolidated Statements of Stockholders' Equity - USD ($)
$ in Thousands

Total

Common Stock [Member]

Additional Paid-In Capital [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Loss [Member]

Deferred Compensation [Member]

Treasury Stock [Member]

Beginning Balances at Dec. 31, 2014

$ 300,322

^[1]

$ 7,100

$ 156,581

$ 142,317

$ (5,676)

$ 1,258

$ (1,258)

Beginning Balances, shares at Dec. 31, 2014

^[1],[2]

14,588,711

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Proceeds from issuance of common stock, net of expenses

41,140

Other comprehensive loss

(164)

Dividends

(17,222)

Stock Issued During Period, Value, Acquisitions

592,970

30,165

$ 289

29,876

Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan

2,235

$ 21

2,214

Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan

43,275

Share-based compensation, shares

^[3],[4]

1,662

$ 22

1,640

^[3],[4]

45,703

Treasury stock activities

^[1]

625

(625)

Ending Balances at Dec. 31, 2015

358,138

^[1]

$ 7,432

190,311

166,235

(5,840)

1,883

(1,883)

Ending Balances, shares at Dec. 31, 2015

^[1],[2]

15,270,659

Increase (Decrease) in Stockholders' Equity [Roll Forward]

(5,840)

Proceeds from issuance of common stock, net of expenses

44,675

Other comprehensive loss

962

Dividends

(18,848)

^[5]

$ 57,360

$ 467

56,893

Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan

960,488

^[5]

$ 2,242

$ 17

2,225

Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan

36,253

Share-based compensation, shares

^[3],[4]

1,557

$ 19

1,538

^[3],[4]

36,099

Treasury stock activities

533

^[1]

(533)

^[1]

Ending Balances at Dec. 31, 2016

446,086

^[1]

$ 7,935

250,967

192,062

(4,878)

2,416

(2,416)

Ending Balances, shares at Dec. 31, 2016

^[1],[2]

16,303,499

Retained earnings

192,062

Increase (Decrease) in Stockholders' Equity [Roll Forward]

(4,878)

Stock Issued During Period, Shares, Dividend Reinvestment Plan

58,124

Other comprehensive loss

606

Dividends

(21,045)

10,771

Stock Issued During Period, Value, Dividend Reinvestment Plan

735

$ 5

730

Proceeds from issuance of common stock, net of expenses

(10)

^[5]

$ 0

(10)

^[5]

Share-based compensation, shares

^[3],[4]

1,798

$ 15

1,783

^[3],[4]

30,172

Treasury stock activities

^[1]

979

(979)

Ending Balances at Dec. 31, 2017

486,294

^[1]

$ 7,955

$ 253,470

$ 3,395

$ (3,395)

Ending Balances, shares at Dec. 31, 2017

^[1],[2]

16,344,442

Retained earnings

229,141

$ 229,141

Increase (Decrease) in Stockholders' Equity [Roll Forward]

$ (4,272)

[1]	Includes 90,961, 76,745 and 70,631 shares at December 31, 2017, 2016 and 2015, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan
[2]	2,000,000 shares of preferred stock at $0.01 par value per share have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the Statements of Stockholders’ Equity.
[3]	Includes amounts for shares issued for directors’ compensation.
[4]	The shares issued under the SICP are net of shares withheld for employee taxes. For 2017, 2016 and 2015, we withheld 10,269, 12,031 and 12,620 shares, respectively, for taxes.
[5]	On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million.

Consolidated Statements of Stockholders' Equity Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Stockholders' Equity [Abstract]
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Shares Held In Trust For Deferred Compensation Plan	90,961	76,745	70,631
Dividends Declared	$ 1.2800	$ 1.2025	$ 1.1325
Shares Issued Under Performance Incentive Plan Withheld For Employee Taxes	10,269	12,031	12,620

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 2017
Text Block [Abstract]
Organization and Basis of Presentation	ORGANIZATION AND BASIS OF PRESENTATION Chesapeake Utilities, incorporated in 1947 in Delaware, is a diversified energy company engaged in regulated and unregulated energy businesses. Our regulated energy businesses consist of: (a) regulated natural gas distribution operations in central and southern Delaware, Maryland’s eastern shore and Florida; (b) regulated natural gas transmission operations on the Delmarva Peninsula, in Pennsylvania and in Florida; and (c) regulated electric distribution operations serving customers in northeast and northwest Florida. Our unregulated energy businesses primarily include: (a) propane distribution operations in Delaware, Maryland, the eastern shore of Virginia, southeastern Pennsylvania and Florida; (b) our natural gas marketing operation providing natural gas supplies directly to commercial and industrial customers in Florida, Delaware, Maryland, Ohio and other states; (c) our natural gas supply, gathering and processing operation in central and eastern Ohio; and (d) our CHP plant in Florida that generates electricity and steam. Our consolidated financial statements include the accounts of Chesapeake Utilities and its wholly-owned subsidiaries. We do not have any ownership interest in investments accounted for using the equity method or any interest in a variable interest entity. All intercompany accounts and transactions have been eliminated in consolidation. We have assessed and, if applicable, reported on subsequent events through the date of issuance of these consolidated financial statements. We reclassified certain amounts in the consolidated statement of cash flows for the years ended December 31, 2016 and 2015 to conform to the current year’s presentation.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates. As additional information becomes available, or actual amounts are determined, recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Property, Plant and Equipment

Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, AFUDC, and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged to expense as incurred, and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. Upon retirement or disposition of property owned by the unregulated businesses, the gain or loss, net of salvage value, is charged to income. A summary of property, plant and equipment by classification as of December 31, 2017 and 2016 is provided in the following table:



	As of December 31,
(in thousands)	2017			2016
Property, plant and equipment
Regulated Energy
Natural gas distribution – Delmarva Peninsula	$	234,654		$	220,083
Natural gas distribution – Florida	354,495			331,281
Natural gas transmission – Delmarva	357,264			285,746
Natural gas transmission – Florida	27,096			27,018
Electric distribution – Florida	100,227			93,553
Unregulated Energy
Propane distribution – Delmarva Peninsula	79,139			73,686
Propane distribution – Florida	29,038			26,359
Other unregulated natural gas services – Ohio	66,037			61,383
CHP - Florida	35,239			35,237
Other unregulated energy	1,229			135
Other	27,699			21,114
Total property, plant and equipment	1,312,117			1,175,595
Less: Accumulated depreciation and amortization	(270,599		)	(245,207		)
Plus: Construction work in progress	84,509			56,276
Net property, plant and equipment	$	1,126,027		$	986,664

Contributions or Advances in Aid of Construction

Customer contributions or advances in aid of construction reduce property, plant and equipment, unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. The amounts that are determined to be non-refundable reduce property, plant and equipment at the time of such determination. During the years ended December 31, 2017, 2016 and 2015, there were $2.1 million, $1.0 million and $1.7 million, respectively, of non-refundable contributions or advances that reduced property, plant and equipment.

Allowance for Funds Used During Construction

Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in the applicable rate base for rate making purposes when the completed projects are placed in service. During the years ended December 31, 2017, 2016 and 2015, AFUDC, which was reflected as a reduction of interest charges, was not material.

Assets Used in Leases

Property, plant and equipment for the Florida natural gas transmission operation included $1.4 million of assets, at December 31, 2017 and 2016, consisting primarily of mains, measuring equipment and regulation station equipment used by Peninsula Pipeline to provide natural gas transmission service pursuant to a contract with a third party. This contract is accounted for as an operating lease due to the exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and generates $264,000 in annual revenue for a 20-year term. Accumulated depreciation for these assets totaled $652,000 and $580,000 at December 31, 2017 and 2016, respectively.

Capital Lease Asset

Property, plant and equipment for our Delmarva Peninsula natural gas distribution operation included a capital lease asset of $2.0 million and $3.4 million, net of accumulated amortization, at December 31, 2017 and 2016, respectively, related to Sandpiper's capacity, supply and operating agreement. The original fair value of this asset was $7.1 million. See Note 20, Other Commitments and Contingencies, for additional information. At December 31, 2017 and 2016, accumulated amortization for this capital lease asset was $5.1 million and $3.7 million, respectively. For the years ended December 31, 2017, 2016 and 2015, we recorded $1.4 million, $1.4 million and $1.3 million, respectively, in amortization of this capital lease asset, which was included in our fuel cost recovery mechanisms.

Jointly-owned Pipeline

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2017 and 2016, which consists of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, jointly owned by Peninsula Pipeline and Peoples Gas. The amount included in property, plant and equipment represents Peninsula Pipeline’s 45-percent ownership of this pipeline. Each party was responsible for financing its portion of the jointly-owned pipeline. This 16-mile pipeline was placed in service in December 2012. Accumulated depreciation for this pipeline totaled $1.3 million and $1.0 million, at December 31, 2017 and 2016, respectively.

Asset Impairment Evaluations

We periodically evaluate whether events or circumstances have occurred, which indicate that other long-lived assets may not be fully recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the asset, compared to the carrying value of the asset. When such events or circumstances are present, we record an impairment loss equal to the excess of the asset's carrying value over its fair value, if any.

In May 2015, we entered into a settlement agreement with a vendor related to the implementation of a customer billing system. Pursuant to the agreement, we received $1.5 million in cash, which is reflected as "Gain from a settlement" in the accompanying consolidated statements of income. In May 2016, we received an additional $650,000 in cash; however, retention of this amount is contingent upon engaging this vendor to provide agreed-upon services through May 2020.

Depreciation and Accretion Included in Operations Expenses

We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the respective regulatory bodies. The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2017, 2016 and 2015:



	2017	2016	2015
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.4%
Natural gas distribution – Florida	2.9%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.8%	2.7%	2.7%
Natural gas transmission – Florida	3.5%	3.9%	4.0%
Electric distribution – Florida	3.4%	3.5%	3.5%

For our unregulated operations, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets:



Asset Description	Useful Life
Propane distribution mains	10-37 years
Propane bulk plants and tanks	10-40 years
Propane equipment	5-33 years
Meters and meter installations	5-33 years
Measuring and regulating station equipment	5-37 years
Natural gas pipelines	45 years
Natural gas right of ways	Perpetual
CHP plant	30 years
Natural gas processing equipment	20-25 years
Office furniture and equipment	3-10 years
Transportation equipment	4-20 years
Structures and improvements	5-45 years
Other	Various

We report certain depreciation and accretion in operations expense, rather than as a depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expense consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2017, 2016 and 2015, we reported $8.1 million, $7.3 million and $7.0 million, respectively, of depreciation and accretion in operations expenses.

Regulated Operations

We account for our regulated operations in accordance with ASC Topic 980, Regulated Operations, which includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company, for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future, as regulatory liabilities. If we were required to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in the statement of income at that time, which could have a material impact on our financial position, results of operations and cash flows.

We monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that the provisions of ASC Topic 980, Regulated Operations, continue to apply to our regulated operations and that the recovery of our regulatory assets is probable.

Revenue Recognition

Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC in each state in which they operate. Eastern Shore’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to negotiated rates.

For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters and natural gas marketing customers, whose billing cycles do not coincide with our accounting periods.

Our Ohio natural gas supply operation recognizes revenues based on actual volumes of natural gas shipped using contractual rates, which are based upon index prices that are published monthly.

Our natural gas marketing operation recognizes revenue based on the volume of natural gas delivered to its customers.

The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in our consolidated statements of income. For propane bulk delivery customers without meters, we record revenue in the period the products are delivered and/or services are rendered.

Eight Flags records revenues based on the amount of electricity and steam generated and sold to its customers.

All of our natural gas and electric distribution operations, except for two utilities that do not sell natural gas to end-use customers as a result of deregulation, have fuel cost recovery mechanisms. These mechanisms provide a method of adjusting the billing rates to reflect changes in the cost of purchased fuel. The difference between the current cost of fuel purchased and the cost of fuel recovered in billed rates is deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year. Chesapeake Utilities' Florida Division and FPU's Indiantown division provide unbundled delivery service to their customers, whereby the customers are permitted to purchase their gas requirements directly from competitive natural gas marketers.

We charge flexible rates to our natural gas distribution industrial interruptible customers to compete with prices of alternative fuels which these customers are able to use. Neither we nor our interruptible customers are contractually obligated to deliver or receive natural gas on a firm service basis.

We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis.

Cost of Sales

Cost of sales includes the direct costs attributable to the products sold or services provided to our customers. These costs include primarily the variable cost of natural gas, electricity and propane commodities, pipeline capacity costs needed to transport and store natural gas, transmission costs for electricity, gathering and processing gas costs, transportation costs to transport propane purchases to our storage facilities, and steam and electricity generation costs. Depreciation expense is not included in our cost of sales.

Operations and Maintenance Expenses

Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of cost of removal for future retirements of utility assets and other administrative expenses.

Cash and Cash Equivalents

Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates fair value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable consist primarily of amounts due for distribution sales of natural gas, electricity and propane and transportation services to customers. An allowance for doubtful accounts is recorded against amounts due to reduce the receivables balance to the amount we reasonably expect to collect based upon our collections experiences and our assessment of customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, the level of natural gas, electricity and propane prices and general economic conditions. Accounts are written off when they are deemed to be uncollectible.

Inventories

We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to their net realizable value. There was no lower-of-cost-or-net realizable value adjustment during 2017, 2016 or 2015.

Goodwill and Other Intangible Assets

Goodwill is not amortized but is tested for impairment at least annually. Goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its implied fair value. The testing of goodwill for 2017, 2016 and 2015 indicated no goodwill impairment.

Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

Other Deferred Charges

Other deferred charges primarily include issuance costs associated with short-term borrowings. These charges are amortized over the life of the related short-term debt borrowings.

Asset Removal Cost

As authorized by the appropriate PSC, we accrue future asset removal costs associated with utility property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities or assets. When we retire depreciable utility plant and equipment, we charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities or assets. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes. Accordingly, these differences are deferred as regulatory liabilities or assets. In the rate setting process, the regulatory liability or asset is excluded from the rate base upon which those utilities have the opportunity to earn their allowed rates of return. The costs associated with our asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

Pension and Other Postretirement Plans

Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates, including the fair value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. We review annually the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates, expected returns on plan assets and the mortality assumption are the factors that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.

The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When estimating our discount rates, we consider high quality corporate bond rates, such as the Prudential curve index and the Citigroup yield curve, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options.

The expected long-term rates of return on assets are utilized in calculating the expected returns on the plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets of each of our plans by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on assets.

We estimate the health care cost trend rates used in determining our postretirement net expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date.

The mortality assumption used for our pension and postretirement plans is based on the actuarial table that is most reflective of the expected mortality of the plan participants and reviewed periodically.

Actual changes in the fair value of plan assets and the differences between the actual and expected return on plan assets could have a material effect on the amount of pension and postretirement benefit costs that we ultimately recognize. A 0.25 percent decrease in the discount rate could increase our annual pension and postretirement costs by approximately $7,000, and a 0.25 percent increase could decrease our annual pension and postretirement costs by approximately $9,000. A 0.25 percent change in the rate of return could change our annual pension cost by approximately $143,000 and would not have an impact on the postretirement and supplemental executive retirement plans because these plans are not funded.

Income Taxes, Investment Tax Credit Adjustments and Tax-Related Contingency

Deferred tax assets and liabilities are recorded for the income tax effect of temporary differences between the financial statement basis and tax basis of assets and liabilities and are measured using the enacted income tax rates in effect in the years in which the differences are expected to reverse. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such income tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.

We account for uncertainty in income taxes in our consolidated financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the consolidated financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income.

We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and estimable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss assuming the proper inquiries are made by tax authorities.

Financial Instruments

Prior to its wind down in the second quarter of 2017, Xeron engaged in trading activities using forward and futures contracts, which were accounted for using the MTM method of accounting. Under MTM accounting, our trading contracts were recorded at fair value as derivative assets and liabilities. The changes in fair value of the contracts were recognized as gains or losses in revenues in the consolidated statements of income in the period of change.

Our natural gas, electric and propane distribution operations and natural gas marketing operations enter into agreements with suppliers to purchase natural gas, electricity, and propane for resale to our respective customers. Purchases under these contracts, as well as distribution and marketing operations sales agreements with counterparties or customers, either do not meet the definition of a derivative, or qualify for “normal purchases and sales” treatment under ASC Topic 815 Derivatives and Hedging, and are accounted for on an accrual basis.

Our propane distribution operations enter into derivative transactions, such as swaps, put options and call options in order to mitigate the impact of wholesale price fluctuations on inventory valuation and future purchase commitments.

Our natural gas marketing operation enters into natural gas futures and swap contracts to mitigate any price risk associated with the purchase and/or sale of natural gas to specific customers.

These transactions may be designated as fair value hedges or cash flow hedges, if they meet all of the accounting requirements pursuant to ASC Topic 815, Derivatives and Hedging, and we elect to designate the instruments as hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap, future, or put option, is recorded at fair value, with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of the hedged item. If designated as a cash flow hedge, the value of the hedging instrument, such as a swap, call option or natural gas futures contract, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument being recorded in comprehensive income. The ineffective portion of the gain or loss of a hedge is recorded in earnings. If the instrument is not designated as a fair value or cash flow hedge, or it does not meet the accounting requirements of a hedge under ASC Topic 815, Derivatives and Hedging, it is recorded at fair value with all gains or losses being recorded directly in earnings. In 2018, we will be adopting ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, the updated hedge accounting standard, which we expect will reduce the MTM volatility in PESCO’s results due to better alignment of risk management activities and financial reporting, risk component hedging and certain other simplifications of hedge accounting guidance.

FASB Statements

Recently Adopted Accounting Standards

Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. We adopted ASU 2015-11 on January 1, 2017, on a prospective basis. Adoption of this standard did not have a material impact on our financial position or results of operations.

Recent Accounting Standards Yet to be Adopted

Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. In March 2016, FASB issued ASU 2016-08, Principal versus Agent Considerations (Reporting Revenue Gross versus Net), to clarify the implementation guidance on principal versus agent considerations. For public entities, this standard is effective for interim and annual financial statements issued beginning January 1, 2018.

We have completed our evaluation of our revenue sources and the impact on our financial position, results of operations and cash flows. In tandem, we have developed and documented accounting policies and position papers, which are intended to meet the requirements of this new revenue recognition standard. We have also completed our plan to update our internal controls. Since the third quarter of 2017, we have provided additional training to our employees and have implemented system and process changes that are associated with the adoption of the standard. We will adopt the updated accounting guidance in the first quarter of 2018, using the modified retrospective transition method, which will result in a cumulative adjustment that will decrease retained earnings and receivables and other deferred charges by $1.5 million, related to one long-term firm transmission contract with an industrial customer for which the timing and recognition of revenue will be shifted to later years. Based on our assessment, we believe that the implementation of this new standard will not have a material impact on the amount and timing of revenue recognition, other than the one long-term contract for which we will delay the recognition of approximately $407,000 in revenue from 2018 to future years.

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted.

The FASB allows companies to elect several practical expedients, in order to simplify the transition to the new standard. The following three expedients must all be elected together:


•	An entity need not reassess whether any expired or existing contracts are or contain leases.


•	An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases).

•An entity need not reassess initial direct costs for any existing leases.

Other practical expedients that can be elected individually are:


•	An entity may elect to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets.


•	An entity may elect to apply the provisions of the new lease guidance at the effective date, without adjusting the comparative periods presented.

We expect to use the practical expedients to assist in implementation of this standard. We have assessed all of our leases and have concluded that we may have some operating leases that qualify for the short-term lease exception. Upon adoption, we will record the right-of-use assets and the lease liabilities related to our operating leases with a lease term in excess of one year. We do not believe that this will have a material impact on our financial position, results of operations or cash flows.

In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which provides a practical expedient to not evaluate, under Topic 842, existing or expired land easements that were not previously accounted for as leases. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easements and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption.

Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. ASU 2016-15 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. We believe that the implementation of this new standard will not have a material impact on our consolidated statement of cash flows.

Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.

Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update allows for capitalization of the service cost component when applicable. ASU 2017-07 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. The presentation of the service cost and other components in this update are to be applied retrospectively, and the capitalization of the service cost is to be applied prospectively on or after the effective date. Aside from changes in presentation, we believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.

Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) changes as a result of a change in the terms or conditions of the award. The guidance is effective for our annual financial statements beginning January 1, 2018, although early adoption is permitted. The amendments included in this standard are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.

Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Among other changes to hedge designation, ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We are evaluating the effect of this standard on our future financial position and results of operations. In 2018, we will be adopting the updated hedge accounting standard, which we expect will reduce the MTM volatility in PESCO’s results due to better alignment of risk management activities and financial reporting, risk component hedging and certain other simplifications of hedge accounting guidance.

Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. ASU 2018-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We are evaluating the effect of this standard on our future financial position and results of operations.

Acquisitions

12 Months Ended

Dec. 31, 2017

Acquisitions

ACQUISITIONS

Acquisitions in 2017

ARM, Chipola and Central Gas Asset Acquisitions

In August 2017, PESCO acquired certain natural gas marketing assets of ARM. We have accounted for the purchase of these assets as a business combination and recorded goodwill of $6.8 million, which is included in Unregulated Energy segment. The acquired assets complement PESCO’s current asset portfolio and expand our regional footprint and retail demand in a market where we have existing pipeline capacity and wholesale liquidity. In connection with the acquisition, we recorded a contingent liability of $2.5 million, which represents the expected future payment of additional consideration to ARM based on the achievement of certain performance targets. The payment, which is expected to be paid in 2019, is contingent upon the achievement of certain gross margin targets during the 2018 calendar year. The recorded liability is based upon our most recent gross margin projections for the acquired assets and is subject to change based on actual performance or changes in our gross margin projections.

In August 2017, Flo-gas acquired certain operating assets of Chipola, which provides propane distribution service to approximately 800 residential and commercial customers in Bay, Calhoun, Gadsden, Jackson, Liberty, and Washington Counties, Florida.

In December 2017, Flo-gas acquired certain operating assets of Central Gas, which provides propane distribution service to approximately 325 residential and commercial customers in Glades, Highlands, Martin, Okeechobee, and St. Lucie Counties, Florida.

The revenue and net income from these acquisitions that were included in our consolidated statement of income for the year ended December 31, 2017, were not material. The amounts recorded in conjunction with these acquisitions are preliminary and subject to adjustment based on additional valuations performed during the measurement period.

Acquisition in 2015

Gatherco Merger

On April 1, 2015, we completed the merger with Gatherco, in which Gatherco merged with and into Aspire Energy, our then newly formed, wholly-owned subsidiary.

At closing, we issued 592,970 shares of our common stock, valued at $30.2 million based on the closing price of our common stock as reported on the NYSE on April 1, 2015. In addition, we paid $27.5 million in cash and assumed $1.7 million of existing outstanding debt, which we paid off on the same date. We also acquired $6.8 million of cash on hand at closing.



(in thousands)	Net Purchase Price
Chesapeake Utilities common stock issued	$	30,164
Cash	27,494
Acquired debt	1,696
Aggregate amount paid in the acquisition	59,354
Less: cash acquired	(6,806		)
Net amount paid in the acquisition	$	52,548

The merger agreement provided for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities during the five-year period following the closing. As of December 31, 2017, there have been no related gathering opportunities developed; therefore, no contingent liability has been recorded. We are unable to estimate the range of future undiscounted contingent liability outcomes at this time. However, a liability for additional contingent cash consideration may be recorded prior to April 2020 as additional information becomes available.

We incurred $1.3 million in transaction costs associated with this merger, of which $514,000 and $786,000 were expensed during the years ended December 31, 2015 and 2014, respectively. Transaction costs were included in operations expense in the consolidated statements of income. The revenues and net income from this acquisition for the years ended December 31, 2017, 2016 and 2015, included in our consolidated statements of income, were $33.3 million and $8.9 million, respectively, for 2017, $26.6 million and $2.1 million, respectively, for 2016 and $16.7 million and $312,000, respectively, for 2015.

The purchase price allocation of the Gatherco acquisition is as follows:



(in thousands)	Purchase Price Allocation
Purchase price	$	57,658

Property plant and equipment	53,203
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226

Long-term debt	1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$	10,119

The goodwill reflects the value paid primarily for opportunities for growth in a new and strategic geographic area. All of the goodwill from this acquisition was recorded in the Unregulated Energy segment and is not deductible for income tax purposes.

Segment Information

12 Months Ended

Dec. 31, 2017

Segment Information

SEGMENT INFORMATION

We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance.

Our operations comprise two reportable segments:


•	Regulated Energy. Includes natural gas distribution, natural gas transmission and electric distribution operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

•

Unregulated Energy. Includes propane distribution as well as natural gas marketing, gathering, processing, transportation and supply. These operations are unregulated as to their rates and services. Effective June 2016, this segment includes electricity and steam generation through Eight Flags' CHP plant. Through March 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary that began winding down operations at the end of the first quarter of 2017. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services.

The remainder of our operations is presented as “Other businesses and eliminations”, which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.

The following table presents information about our reportable segments.



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	316,971		$	302,402		$	300,674
Unregulated Energy	300,612			196,458			158,570
Total operating revenues, unaffiliated customers	$	617,583		$	498,860		$	459,244
Intersegment Revenues ⁽¹⁾
Regulated Energy	$	9,339		$	3,287		$	1,228
Unregulated Energy	23,983			7,321			3,537
Other businesses	774			880			880
Total intersegment revenues	$	34,096		$	11,488		$	5,645
Operating Income
Regulated Energy	$	73,160		$	69,851		$	60,985
Unregulated Energy	12,477			13,844			16,355
Other businesses and eliminations	206			401			418
Operating Income	85,843			84,096			77,758
Other (expense) income	(765		)	(441		)	293
Interest charges	12,645			10,639			10,006
Income Before Income taxes	72,433			73,016			68,045
Income taxes	14,309			28,341			26,905
Net Income	$	58,124		$	44,675		$	41,140
Depreciation and Amortization
Regulated Energy	$	28,554		$	25,677		$	24,195
Unregulated Energy	7,954			6,386			5,679
Other businesses and eliminations	91			96			98
Total depreciation and amortization	$	36,599		$	32,159		$	29,972
Capital Expenditures
Regulated Energy	$	159,011		$	139,994		$	98,372
Unregulated Energy	26,190			23,984			90,895
Other businesses	5,902			5,398			5,994
Total capital expenditures	$	191,103		$	169,376		$	195,261


⁽¹⁾	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.



	As of December 31,
	2017		2016
Identifiable Assets
Regulated Energy	$	1,121,673	$	986,752
Unregulated Energy	261,541		226,368
Other businesses	34,220		16,099
Total identifiable assets	$	1,417,434	$	1,229,219

Our operations are entirely domestic.

Supplemental Cash Flow Disclosures

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Disclosures

SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2017, 2016 and 2015 were as follows:



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Cash paid for interest	$	12,420		$	10,315		$	9,497
Cash paid for income taxes, net of refunds	$	(4,114	)	$	(5,308	)	$	11,076

Non-cash investing and financing activities during the years ended December 31, 2017, 2016, and 2015 were as follows:



	For the Year Ended December 31,
	2017		2016		2015
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	15,457	$	9,791	$	10,268
Common stock issued for the Retirement Savings Plan	$	—	$	777	$	690
Common stock issued under the SICP	$	1,127	$	1,027	$	1,594
Capital lease obligation	$	2,070	$	3,471	$	4,824
Common stock issued in acquisition	$	—	$	—	$	30,164

Derivative Instruments

12 Months Ended

Dec. 31, 2017

Derivative Instruments

The effects of gains and losses from derivative instruments are as follows:



	Amount of Gain (Loss) on Derivatives:
	Location of Gain (Loss) on Derivatives	For the Year Ended December 31,
(in thousands)	Location of Gain (Loss) on Derivatives	2017			2016			2015
Derivatives not designated as hedging instruments
Realized gain (loss) on forward contracts and options ⁽¹⁾	Revenue	$	112		$	(546	)	$	426
Unrealized (loss) on forward contracts ⁽¹⁾	Revenue	—			—			(126		)
Natural gas futures contracts	Cost of sales	(3,633		)	(541		)	—
Propane swap agreements	Cost of sales	8			7			18
Natural gas swap contracts	Cost of sales	1			—			—
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	(9		)	49			528
Put/Call option ⁽²⁾	Propane inventory	—			—			43
Natural gas futures contracts	Natural gas inventory	—			(233		)	—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	1,607			(364		)	(120		)
Propane swap agreements	Other comprehensive income (loss)	487			1,016			(323		)
Call options	Cost of sales	—			—			(81		)
Natural gas futures contracts	Cost of sales	(456		)	345			—
Natural gas swap contracts	Cost of sales	(822		)	—			—
Natural gas futures contracts	Other comprehensive income (loss)	(1,476		)	222			109
Natural gas swap contracts	Other comprehensive income (loss)	986			—			—
Total		$	(3,195	)	$	(45	)	$	474


(1)	All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our consolidated statements of income.

(2)

As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this call option effectively changed the value of propane inventory on the consolidated balance sheets.

Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2017

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The three levels of the fair value hierarchy are the following:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and

Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).

Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2017 and 2016, respectively:



			Fair Value Measurements Using:
As of December 31, 2017	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	648		—		—		648
Investments—mutual funds and other	6,086		6,086		—		—
Total investments	6,756		6,108		—		648
Derivative assets	1,286		—		1,286		—
Total assets	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	6,247	$	—	$	6,247	$	—



			Fair Value Measurements Using:
As of December 31, 2016	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	561		—		—		561
Investments—mutual funds and other	4,320		4,320		—		—
Total investments	4,902		4,341		—		561
Derivative assets	823		—		823		—
Total assets	$	5,725	$	4,341	$	823	$	561
Liabilities:
Derivative liabilities	$	773	$	—	$	773	$	—

The following valuation techniques were used to measure fair value assets on a recurring basis as of December 31, 2017 and 2016:

Level 1 Fair Value Measurements:

Investments - equity securities — The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.

Investments - mutual funds and other — The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.

Level 2 Fair Value Measurements:

Derivative assets and liabilities — The fair values of forward contracts are measured using market transactions in either the listed or OTC markets. The fair value of the propane put/call options, swap agreements and natural gas futures contracts are measured using market transactions for similar assets and liabilities in either the listed or OTC markets.

Level 3 Fair Value Measurements:

Investments - guaranteed income fund — The fair values of these investments are recorded at the contract value, which approximates their fair value.

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2017 and 2016:



	For the Year Ended December 31,
	2017			2016
(in thousands)
Beginning Balance	$	561		$	279
Purchases and adjustments	79			123
Transfers/disbursements	(53		)	151
Investment income	61			8
Ending Balance	$	648		$	561

Investment income from the Level 3 investments is reflected in other (expense) income in the consolidated statements of income.

At December 31, 2017 and 2016, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement).

At December 31, 2017, long-term debt, which includes the current maturities but excludes a capital lease obligation, had a carrying value of $205.2 million, compared to a fair value of $215.4 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, adjusted for duration, optionality and risk profile. At December 31, 2016, long-term debt, which includes the current maturities but excludes a capital lease obligation, had a carrying value of $145.9 million compared to the estimated fair value of $161.5 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

See Note 16, Employee Benefit Plans, for fair value measurement information related to our pension plan assets.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Investments

12 Months Ended

Dec. 31, 2017

Investments [Abstract]

Investments

INVESTMENTS

The investment balances at December 31, 2017 and 2016, consisted of the following:



	As of December 31,
(in thousands)	2017		2016
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	6,734	$	4,881
Investments in equity securities	22		21
Total	$	6,756	$	4,902

We classify these investments as trading securities and report them at their fair value. For the years ended December 31, 2017, 2016 and 2015, we recorded net unrealized gains of $1.0 million, $379,000 and $7,000, respectively, in other income (expense) in the consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

Goodwill and Other Intangible Assets

12 Months Ended

Dec. 31, 2017

Goodwill and Other Intangible Assets

GOODWILL AND OTHER INTANGIBLE ASSETS

The carrying value of goodwill as of December 31, 2017 and 2016 was as follows:



	As of December 31,
(in thousands)	2017		2016
Regulated Energy	$	3,353	$	3,353
Unregulated Energy	18,751		11,717
Total	$	22,104	$	15,070

As of December 31, 2017, goodwill in our Regulated Energy segment is comprised of approximately $2.5 million from the FPU merger in October 2009, $170,000 from the purchase of operating assets from IGC in August 2010 and $714,000 from the purchase of Fort Meade in December 2013. As of December 31, 2017, goodwill in our Unregulated Energy segment is comprised of $10.1 million from the acquisition of Gatherco in April 2015, $6.8 million from the acquisition of certain operating assets from ARM in August 2017, and $1.9 million from the acquisition of the operating assets of several propane distribution companies. The annual impairment testing for 2017 and 2016 indicated no impairment of goodwill.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2017 and 2016 are as follows:



	As of December 31,
	2017				2016
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	7,393	$	2,880	$	4,012	$	2,379
Non-Compete agreements	270		175		270		146
Other	270		192		270		184
Total	$	7,933	$	3,247	$	4,552	$	2,709

The customer lists acquired in the purchases of the operating assets of several companies are being amortized over seven to 12 years. The non-compete agreements acquired in the purchase of the operating assets of several companies are being amortized over a six-year or seven-year period. The other intangible assets consist of acquisition costs from our propane distribution acquisitions in the late 1980s and 1990s and are being amortized over 40 years.

For the years ended December 31, 2017, 2016 and 2015, amortization expense of intangible assets was $537,000, $380,000, and $367,000, respectively. Amortization expense of intangible assets is expected to be $790,000 for each of the years 2018, 2019 and 2020, $725,000 for 2021 and $471,000 for 2022.

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. Our returns for tax years after 2013 are subject to examination.

We had no net operating loss for federal income tax purposes as of December 31, 2017. As of December 31, 2016, we had a net operating loss for federal income tax purposes of $14.0 million, which we carried back two years. For state income tax purposes, we had net operating losses in various states of $34.2 million and $19.6 million as of December 31, 2017 and 2016, respectively, almost all of which will expire in 2036. We have recorded deferred tax assets of $1.6 million and $893,000 related to state net operating loss carry-forwards at December 31, 2017 and 2016, respectively, but we have not recorded a valuation allowance to reduce the future benefit of the tax net operating losses because we believe they will be fully utilized.

Federal Tax Reform

On December 22, 2017, President Trump signed into law the TCJA. Substantially all of the provisions of the TCJA are effective for taxable years beginning on or after January 1, 2018. The provisions significantly impacting us include the reduction of the corporate federal income tax rate from 35 percent to 21 percent and several technical provisions, including, among others, limiting the utilization of net operating losses arising after December 31, 2017 to 80 percent of taxable income with an indefinite carryforward. Our federal income tax expense for periods beginning on January 1, 2018 will be based on the new federal corporate income tax rate. The specific TCJA provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, and continuation of certain rate normalization requirements for accelerated depreciation benefits.

Additionally, enactment of the TCJA resulted in changes to the Internal Revenue Code, which materially impacted our 2017 financial statements. ASC 740, Income Taxes, requires recognition of the effects of changes in tax laws in the period in which the law is enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. We have completed and have made a reasonable estimate of the measurement and accounting of certain effects of the TCJA, which have been reflected in the December 31, 2017 consolidated financial statements, the period in which the TCJA was enacted. At the date of enactment, we re-measured deferred income taxes based upon the new corporate tax rate. For our regulated businesses, the change in deferred income taxes of $98.5 million was recorded as an offset to a regulatory liability, some portion of which may ultimately be subject to refund to customers. We are at various stages of discussion with our regulatory jurisdictions. For our unregulated businesses, the change in deferred income taxes of $14.3 million was recorded as an adjustment to our deferred income taxes and increased our net income.

The following tables provide: (a) the components of income tax expense in 2017, 2016, and 2015; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2017, 2016, and 2015; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2017 and 2016.



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Current Income Tax Expense
Federal	$	2,803		$	(4,898	)	$	4,875
State	492			2,053			1,533
Other	(71		)	(71		)	(23		)
Total current income tax expense	3,224			(2,916		)	6,385
Deferred Income Tax Expense ⁽¹⁾
Property, plant and equipment	8,314			31,062			21,205
Deferred gas costs	2,002			1,163			(1,539		)
Pensions and other employee benefits	180			237			(84		)
FPU merger-related premium cost and deferred gain	(1,148		)	(572		)	(556		)
Net operating loss carryforwards	193			(9		)	2,078
Other	1,544			(624		)	(584		)
Total deferred income tax expense	11,085			31,257			20,520
Total Income Tax Expense	$	14,309		$	28,341		$	26,905

⁽¹⁾Includes $873,000, $2.1 million and $2.1 million of deferred state income taxes for the years 2017, 2016 and 2015, respectively.



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Reconciliation of Effective Income Tax Rates
Federal income tax expense ⁽¹⁾	$	25,351		$	22,759		$	23,865
State income taxes, net of federal benefit	1,894			3,422			3,062
ESOP dividend deduction	(257		)	(264		)	(263		)
Revaluation of deferred tax assets and liabilities	(14,299		)	—			—
Other	1,620			2,424			241
Total Income Tax Expense	$	14,309		$	28,341		$	26,905
Effective Income Tax Rate ⁽²⁾	19.75		%	38.81		%	39.54		%


⁽¹⁾	Federal income taxes were calculated at 35 percent for each year represented.


⁽²⁾	Effective tax rate for 2017 includes the impact of the revaluation of deferred tax assets and liabilities for our unregulated businesses due to implementation of the TCJA.



	As of December 31,
	2017		2016
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	133,581	$	218,074
Acquisition adjustment	9,323		14,840
Loss on reacquired debt	153		442
Deferred gas costs	2,574		1,846
Other	5,422		6,375
Total deferred income tax liabilities	151,053		241,577
Deferred income tax assets:
Pension and other employee benefits	4,698		6,230
Environmental costs	1,744		2,592
Net operating loss carryforwards	1,625		952
Investment tax credit carryforwards	—		2,643
Self insurance	164		189
Storm reserve liability	717		1,131
Other	6,255		4,946
Total deferred income tax assets	15,203		18,683
Deferred Income Taxes Per Consolidated Balance Sheets	$	135,850	$	222,894

Long-Term Debt

12 Months Ended

Dec. 31, 2017

Long-Term Debt

LONG-TERM DEBT

Our outstanding long-term debt is shown below:



	As of December 31,
(in thousands)	2017			2016
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	7,982		$	7,978
Uncollateralized Senior Notes:
6.64% note, due October 31, 2017	—			2,727
5.50% note, due October 12, 2020	6,000			8,000
5.93% note, due October 31, 2023	18,000			21,000
5.68% note, due June 30, 2026	26,100			29,000
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000
3.88% note, due May 15, 2029	50,000			50,000
3.25% note, due April 30, 2032	70,000			—
Promissory notes	97			168
Capital lease obligation	2,070			3,471
Less: debt issuance costs	(433		)	(291		)
Total long-term debt	206,816			149,053
Less: current maturities	(9,421		)	(12,099		)
Total long-term debt, net of current maturities	$	197,395		$	136,954

Annual maturities and principal repayments of long-term debt, excluding the capital lease obligation, are as follows: $8.0 million for 2018; $10.6 million for 2019; $15.6 million for 2020; $13.6 million for 2021; $25.1 million for 2022 and $132.3 million thereafter. See Note 14, Lease Obligations, for future payments related to the capital lease obligation.

Shelf Agreements

In October 2015, we entered into the Prudential Shelf Agreement, under which we may request that Prudential purchase, through October 8, 2018, up to $150.0 million of Prudential Shelf Notes. The Prudential Shelf Notes have a fixed interest rate and a maturity date not to exceed twenty years from the date of issuance. Prudential is under no obligation to purchase any of the Prudential Shelf Notes. The interest rate and terms of payment of any series of the Prudential Shelf Notes will be determined at the time of purchase.

In May 2016, Prudential agreed to purchase $70.0 million of 3.25 percent Prudential Shelf Notes, which were issued on April 21, 2017. The proceeds received from this issuance of Prudential Shelf Notes were used to reduce short-term borrowings under the Revolver. The balance under the Revolver had accumulated over time as capital expenditures were temporarily financed. As of December 31, 2017, $80 million remains available for issuance under the Prudential Shelf Agreement.

In March 2017, we entered into the MetLife Shelf Agreement and the NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million and $100.0 million, respectively, of our unsecured senior debt. The unsecured senior debt would have a fixed interest rate and a maturity date not to exceed twenty years from the date of issuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. The interest rate and terms of payment of any series of unsecured senior debt will be determined at the time of purchase.

In November 2017, NYL agreed to purchase $50.0 million of 3.48% Series A notes and $50.0 million of 3.58% Series B notes. The Series A notes and Series B notes will be issued on or before May 21, 2018 and November 20, 2018, respectively. The proceeds received from the issuances of these shelf notes will be used to reduce short-term borrowings under the Revolver and/or lines of credit and/or to fund capital expenditures. The NYL Shelf Agreement has been fully utilized.

As of December 31, 2017, we had not requested that MetLife purchase unsecured senior debt under the MetLife Shelf Agreement.

The Prudential Shelf Agreement, the MetLife Shelf Agreement, and the NYL Shelf Agreement set forth certain business covenants to which we are subject when any Note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

Secured First Mortgage Bonds

We guaranteed FPU’s first mortgage bonds, which are secured by a lien covering all of FPU’s property. FPU’s first mortgage bonds contain a restriction that limits the payment of dividends by FPU. It provides that FPU cannot make dividends or other restricted payments in excess of the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. As of December 31, 2017, FPU’s cumulative net income base was $142.6 million, offset by restricted payments of $37.6 million, leaving $104.9 million of cumulative net income for FPU free of restrictions pursuant to this covenant.

The dividend restrictions in FPU’s first mortgage bonds resulted in approximately $43.0 million of the net assets of our consolidated subsidiaries being restricted at December 31, 2017. This represents approximately 9 percent of our consolidated net assets. Other than the dividend restrictions in FPU’s first mortgage bonds, there are no legal, contractual or regulatory restrictions on the net assets of our subsidiaries.

Uncollateralized Senior Notes

All of our uncollateralized Senior Notes require periodic principal and interest payments as specified in each note. They also contain various restrictions. The most stringent restrictions state that we must maintain equity of at least 40 percent of total capitalization, and the fixed charge coverage ratio must be at least 1.2 times. The most recent Senior Notes issued in December 2013 also contain a restriction that we must maintain an aggregate net book value in our regulated business assets of at least 50 percent of our consolidated total assets. Failure to comply with those covenants could result in accelerated due dates and/or termination of the Senior Note agreements.

Certain uncollateralized Senior Notes contain a “restricted payments” covenant as defined in the respective note agreements. The most restrictive covenants of this type are included within the 5.93 percent Senior Note, due October 31, 2023. The covenant provides that we cannot pay or declare any dividends or make any other restricted payments in excess of the sum of $10.0 million, plus our consolidated net income accrued on and after January 1, 2003. As of December 31, 2017, the cumulative consolidated net income base was $387.7 million, offset by restricted payments of $178.0 million), leaving $209.7 million of cumulative net income free of restrictions.

As of December 31, 2017, we are in compliance with all of our debt covenants.

Short-Term Borrowing

12 Months Ended

Dec. 31, 2017

Accumulated Other Comprehensive Income (Loss)

Short-Term Borrowing

SHORT-TERM BORROWINGS

At December 31, 2017 and 2016, we had $251.0 million and $209.9 million, respectively, of short-term borrowings outstanding at the weighted average interest rates of 2.42 percent and 1.43 percent, respectively. In October 2015, we entered into a Credit Agreement with the Lenders for a $150.0 million Revolver through October 2020 subject to the terms and conditions as specified. In November 2017, we entered into a new $40.0 million short-term credit facility with a new lender. As a result, we now have an aggregate of $370.0 million in credit lines comprised of five unsecured bank credit facilities with four financial institutions, with $220.0 million in total available credit, and a Revolver with five participating Lenders totaling $150.0 million. We incurred commitment fees of $131,000, $145,000 and $106,000 in 2017, 2016 and 2015, respectively. The following table summarizes our short-term borrowing facilities information at December 31, 2017 and 2016.



					Outstanding borrowings at
(in thousands)	Total Facility		Interest Rate	Expiration Date	December 31, 2017		December 31, 2016		Available at December 31, 2017
Bank Credit Facility
Committed revolving credit facility A	$	55,000	LIBOR plus 1.00 percent ⁽¹⁾	October 28, 2018	$	55,000	$	45,000	$	—
Committed revolving credit facility B	30,000		LIBOR plus 1.00 percent ⁽¹⁾	October 31, 2018	20,500		21,311		9,500
Short-term revolving credit note C	50,000		LIBOR plus 0.80 percent ⁽²⁾	October 31, 2018	50,000		50,000		—
Committed revolving credit facility D	45,000		LIBOR plus 0.85 percent ⁽³⁾	October 31, 2018	40,171		35,000		4,829
Committed revolving credit facility E	40,000		LIBOR plus 0.85 percent ⁽³⁾	October 31, 2018	—		—		40,000
Committed revolving credit facility F⁽⁵⁾	150,000		LIBOR plus 1.00 percent ⁽¹⁾	October 08, 2020	75,000		50,000		75,000
Total short term credit facilities	$	370,000			$	240,671	$	201,311	$	129,329
Book overdrafts⁽⁴⁾					10,298		8,560
Total short-term borrowing					$	250,969	$	209,871

⁽¹⁾ This facility bears interest at LIBOR for the applicable period plus up to 1.00 percent, based on Total Indebtedness as a percentage of Total Capitalization.

⁽²⁾ At our discretion, the borrowings under this facility can bear interest at the lender's base rate plus 0.80 percent.

⁽³⁾At our discretion, the borrowing under this facility can bear interest at the lender's base rate plus 0.85 percent.

⁽⁴⁾ If presented, these book overdrafts would be funded through the bank revolving credit facilities.

⁽⁵⁾This committed revolving credit facility includes a restriction that our short-term borrowings, excluding any borrowings under the committed revolving

credit facility, shall not exceed $200.0 million.

These bank credit facilities are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. We are authorized by our Board of Directors to borrow up to $275.0 million of short-term debt, as required, from these short-term lines of credit. As of February 27, 2018 the Board increased this limit from $275.0 million to $350.0 million.

The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our revolving credit facilities to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. We are in compliance with all of our debt covenants.

Lease Obligations	12 Months Ended
Lease Obligations	Dec. 31, 2017
Text Block [Abstract]
Lease Obligations	LEASE OBLIGATIONS We have entered into several operating lease arrangements for office space, equipment and pipeline facilities. Rent expense related to these leases for 2017, 2016 and 2015 was $3.6 million, $2.5 million, and $1.7 million, respectively. As of December 31, 2017, future minimum payments under our current lease agreements for the years 2018 through 2022 are $2.7 million, $1.7 million, $1.0 million, $815,000, and $654,000, respectively and approximately $3.7 million thereafter, with an aggregate total of approximately $10.6 million. For each of the years ended December 31, 2017, 2016, and 2015, we paid $1.5 million, for a capital lease arrangement related to Sandpiper's capacity, supply and operating agreement. Future minimum payments under this lease arrangement are $1.5 million for 2018 and $625,000 in 2019, with an aggregate total of $2.1 million.

Stockholders' Equity

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

STOCKHOLDERS' EQUITY

Preferred Stock

We have 2,000,000 authorized and unissued shares of $0.01 par value preferred stock as of December 31, 2017 and 2016. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and without the necessity of further action or authorization by stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional or other special rights and qualifications as the Board of Directors may, in its discretion, determine.

Common Stock Public Offering

In September 2016, we completed a public offering of 960,488 shares of our common stock at a public offering price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million, which were added to our general funds and used primarily to repay a portion of our short-term debt under unsecured lines of credit.

Shareholders' Rights

Effective February 27, 2018, we entered into the Amendment to the Rights Agreement to accelerate the expiration of the Rights (as defined below) from 5:00 P.M., New York City time, on August 20, 2019, to 5:00 P.M., New York City time, on February 27, 2018 and, which has the effect of terminating the Rights Agreement on that date. At the time of the termination of the Rights Agreement, all of the Rights distributed to holders of our common stock pursuant to the Rights Agreement will expire by their respective terms. Accordingly, the Rights Agreement is of no further force and effect.

Prior to termination of the Rights Agreement, each outstanding share of our common stock held of record on September 3, 1999, as adjusted for our stock split in September 2014, and additional shares of common stock issued since that time, was accompanied by one preferred stock purchase right (each, a "Right," and, collectively, the "Rights"). Each Right initially entitled the holder to purchase one fiftieth of a share of our Series A Participating Cumulative Preferred Stock, par value $0.01 per share, at a price of $70 per unit, subject to anti-dilution adjustments. Upon a person or entity becoming an Acquiring Person, each Right (other than the Rights held by the Acquiring Person) would have become exercisable to purchase a number of shares of our common stock having a market value equal to two times the exercise price of the Right.

Accumulated Other Comprehensive (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures and swap contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive income (loss).

The following tables present the changes in the balance of accumulated other comprehensive loss for the years ended December 31, 2017 and 2016. All amounts in the following tables are presented net of tax.



	Defined Benefit Pension and Postretirement Plan Items			Commodity Contract Cash Flow Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive income before reclassifications	281			159			440
Amounts reclassified from accumulated other comprehensive income/(loss)	336			(170		)	166
Net current-period other comprehensive income/(loss)	617			(11		)	606
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)



	Defined Benefit Pension and Postretirement Plan Items			Commodity Contracts Cash Flow Hedges			Total
(in thousands)
As of December 31, 2015	$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive income/(loss) before reclassifications	(254		)	762			508
Amounts reclassified from accumulated other comprehensive income/(loss)	474			(20		)	454
Net current-period other comprehensive income	220			742			962
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2017, 2016 and 2015. Deferred gains and losses of our commodity contracts cash flow hedges are recognized in earnings upon settlement.



	For the Year Ended December 31,
(in thousands)	2017			2016			2015
Amortization of defined benefit pension and postretirement plan items:
Prior service cost ⁽¹⁾	$	77		$	77		$	68
Net gain ⁽¹⁾	(636		)	(871		)	(650		)
Total before income taxes	(559		)	(794		)	(582		)
Income tax benefit	223			320			233
Net of tax	$	(336	)	$	(474	)	$	(349	)

Gains and losses on commodity contracts cash flow hedges
Propane swap agreements ⁽²⁾	$	1,607		$	(322	)	$	(120	)
Natural gas swaps ⁽²⁾	(822		)	—			(55		)
Natural gas futures ⁽²⁾	(456		)	345			(31		)
Total before income taxes	329			23			(206		)
Income tax impact	(159		)	(3		)	83
Net of tax	$	170		$	20		$	(123	)

Total reclassifications for the period	$	(166	)	$	(454	)	$	(472	)


⁽¹⁾	These amounts are included in the computation of net periodic benefits. See Note 16, Employee Benefit Plans, for additional details.


⁽²⁾	These amounts are included in the effects of gains and losses from derivative instruments. See Note 7, Derivative Instruments, for additional details.

Amortization of defined benefit pension and postretirement plan items is included in operations expense, and gains and losses on propane swap agreements, call options and natural gas futures contracts are included in cost of sales in the accompanying consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2017

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

We measure the assets and obligations of the defined benefit pension plans and other postretirement benefits plans to determine the plans’ funded status as of the end of the year as an asset or a liability on our consolidated balance sheets. We record as a component of other comprehensive income/loss or a regulatory asset the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs.

Defined Benefit Pension Plans

We sponsor three defined benefit pension plans: the Chesapeake Pension Plan, the FPU Pension Plan and the Chesapeake SERP.

The Chesapeake Pension Plan was closed to new participants, effective January 1, 1999, and was frozen with respect to additional years of service and additional compensation, effective January 1, 2005. Benefits under the Chesapeake Pension Plan were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan. Active participants on the date the Chesapeake Pension Plan was frozen were credited with two additional years of service. The unfunded liability for the Chesapeake Pension Plan of approximately $2.1 million and $2.7 million at December 31, 2017 and 2016, is included in the other pension and benefit costs liability in our consolidated balance sheets.

The FPU Pension Plan covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. Prior to the FPU merger, the FPU Pension Plan was frozen with respect to additional years of service and additional compensation, effective December 31, 2009. The unfunded liability for the FPU Pension Plan of approximately $16.3 million and $20.6 million at December 31, 2017 and 2016, respectively, is included in the other pension and benefit costs liability in our consolidated balance sheets.

The Chesapeake SERP was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the Chesapeake SERP were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan. Active participants on the date the Chesapeake SERP was frozen were credited with two additional years of service. The unfunded liability for the Chesapeake SERP of approximately $2.4 million, at both December 31, 2017 and 2016, is included in the other pension and benefit costs liability in our consolidated balance sheets.

The following schedule sets forth the funded status at December 31, 2017 and 2016 and the net periodic cost for the years ended December 31, 2017, 2016 and 2015 for the Chesapeake and FPU Pension Plans:



	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2017			2016			2017			2016
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	11,355		$	11,501		$	63,832		$	64,435
Interest cost	402			421			2,482			2,525
Actuarial loss (gain)	454			330			1,199			(216		)
Effect of settlement	—			(433		)	—			—
Benefits paid	(768		)	(464		)	(2,849		)	(2,912		)
Benefit obligation — end of year	11,443			11,355			64,664			63,832
Change in plan assets:
Fair value of plan assets — beginning of year	8,668			8,752			43,272			42,207
Actual return on plan assets	1,144			424			6,025			2,343
Employer contributions	306			389			1,948			1,634
Benefits paid	(768		)	(464		)	(2,849		)	(2,912		)
Effect of settlement	—			(433		)	—			—
Fair value of plan assets — end of year	9,350			8,668			48,396			43,272
Reconciliation:
Funded status	(2,093		)	(2,687		)	(16,268		)	(20,560		)
Accrued pension cost	$	(2,093	)	$	(2,687	)	$	(16,268	)	$	(20,560	)
Assumptions:
Discount rate	3.50		%	3.75		%	3.75		%	4.00		%
Expected return on plan assets	6.00		%	6.00		%	6.50		%	6.50		%



	Chesapeake Pension Plan									FPU Pension Plan
For the Years Ended December 31,	2017			2016			2015			2017			2016			2015
(in thousands)
Components of net periodic pension cost:
Interest cost	$	402		$	421		$	407		$	2,482		$	2,525		$	2,504
Expected return on assets	(495		)	(501		)	(530		)	(2,779		)	(2,702		)	(3,107		)
Amortization of actuarial loss	399			459			392			513			519			456
Settlement expense	—			161			—			—			—			—
Net periodic pension cost	306			540			269			216			342			(147		)
Amortization of pre-merger regulatory asset	—			—			—			761			761			761
Total periodic cost	$	306		$	540		$	269		$	977		$	1,103		$	614
Assumptions:
Discount rate	3.75		%	3.75		%	3.50		%	4.00		%	4.00		%	3.75		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	6.50		%	6.50		%	7.00		%

Included in the net periodic costs for the FPU Pension Plan is continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU's regulated operations for the changes in funded status that occurred, but were not recognized as part of net periodic cost, prior to the merger with Chesapeake Utilities in October 2009. This was previously deferred as a regulatory asset to be recovered through rates pursuant to an order by the Florida PSC. The unamortized balance of this regulatory asset was $1.3 million and $2.1 million at December 31, 2017 and 2016, respectively.

The following sets forth the funded status at December 31, 2017 and 2016 and the net periodic cost for the years ended December 31, 2017, 2016 and 2015 for the Chesapeake SERP:



At December 31,	2017			2016
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	2,428		$	2,510
Interest cost	89			91
Actuarial loss (gain)	63			(21		)
Benefits paid	(152		)	(152		)
Benefit obligation — end of year	2,428			2,428
Change in plan assets:
Fair value of plan assets — beginning of year	—			—
Employer contributions	152			152
Benefits paid	(152		)	(152		)
Fair value of plan assets — end of year	—			—
Reconciliation:
Funded status	(2,428		)	(2,428		)
Accrued pension cost	$	(2,428	)	$	(2,428	)
Assumptions:
Discount rate	3.50		%	3.75		%



For the Years Ended December 31,	2017			2016			2015
(in thousands)
Components of net periodic pension cost:
Interest cost	$	89		$	91		$	91
Amortization of prior service cost	—			—			9
Amortization of actuarial loss	87			87			99
Net periodic pension cost	$	176		$	178		$	199
Assumptions:
Discount rate	3.75		%	3.75		%	3.50		%

Our funding policy provides that payments to the trustee of each qualified plan shall be equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2017, 2016 and 2015:



	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2017		2016		2015		2017		2016		2015
Asset Category
Equity securities	52.70	%	52.93	%	48.01	%	55.17	%	53.18	%	48.56	%
Debt securities	37.79	%	37.64	%	39.62	%	36.56	%	37.74	%	41.74	%
Other	9.51	%	9.43	%	12.37	%	8.27	%	9.08	%	9.70	%
Total	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%

The investment policy of both the Chesapeake and FPU Pension Plans is designed to provide the capital assets necessary to meet the financial obligations of the plans. The investment goals and objectives are to achieve investment returns that, together with contributions, will provide funds adequate to pay promised benefits to present and future beneficiaries of the plans, earn a long-term investment return in excess of the growth of the plans’ retirement liabilities, minimize pension expense and cumulative contributions resulting from liability measurement and asset performance, and maintain a diversified portfolio to reduce the risk of large losses.

The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the plans’ goals and objectives:



Asset Allocation Strategy
Asset Class	Minimum Allocation Percentage		Maximum Allocation Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	14	%	32	%
Foreign Equities (Developed and Emerging Markets)	13	%	25	%
Fixed Income (Inflation Bond and Taxable Fixed)	26	%	40	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	6	%	14	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%	19	%
Cash	0	%	5	%

Due to periodic contributions and different asset classes producing varying returns, the actual asset values may temporarily move outside of the intended ranges. The investments are monitored on a quarterly basis, at a minimum, for asset allocation and performance.

At December 31, 2017 and 2016, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:



	Fair Value Measurement Hierarchy

	At December 31, 2017								At December 31, 2016
Asset Category	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(in thousands)
Mutual Funds - Equity securities
U.S. Large Cap ⁽¹⁾	$	4,245	$	—	$	—	$	4,245	$	4,031	$	—	$	—	$	4,031
U.S. Mid Cap ⁽¹⁾	1,775		—		—		1,775		1,677		—		—		1,677
U.S. Small Cap ⁽¹⁾	918		—		—		918		845		—		—		845
International ⁽²⁾	11,916		—		—		11,916		9,574		—		—		9,574
Alternative Strategies ⁽³⁾	5,528		—		—		5,528		5,238		—		—		5,238
	24,382		—		—		24,382		21,365		—		—		21,365
Mutual Funds - Debt securities
Fixed income ⁽⁴⁾	18,454		—		—		18,454		16,958		—		—		16,958
High Yield ⁽⁴⁾	2,772		—		—		2,772		2,636		—		—		2,636
	21,226		—		—		21,226		19,594		—		—		19,594
Mutual Funds - Other
Commodities ⁽⁵⁾	2,154		—		—		2,154		2,134		—		—		2,134
Real Estate ⁽⁶⁾	2,300		—		—		2,300		2,116		—		—		2,116
Guaranteed deposit ⁽⁷⁾	—		—		436		436		—		—		498		498
	4,454		—		436		4,890		4,250		—		498		4,748
Total Pension Plan Assets in fair value hierarchy	$	50,062	$	—	$	436	50,498		$	45,209	$	—	$	498	45,707
Investments measured at net asset value ⁽⁸⁾							7,248								6,233
Total Pension Plan Assets							$	57,746							$	51,940


⁽¹⁾	Includes funds that invest primarily in United States common stocks.


⁽²⁾	Includes funds that invest primarily in foreign equities and emerging markets equities.


⁽³⁾	Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.


⁽⁴⁾	Includes funds that invest in investment grade and fixed income securities.


⁽⁵⁾	Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.


⁽⁶⁾	Includes funds that invest primarily in real estate.


⁽⁷⁾	Includes investment in a group annuity product issued by an insurance company.


⁽⁸⁾	Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy. These amounts are presented to reconcile to total pension plan assets.

At December 31, 2017 and 2016, all of the investments were classified under the same fair value measurement hierarchy (Level 1 through Level 3) described under Note 8, Fair Value of Financial Instruments. The Level 3 investments were recorded at fair value based on the contract value of annuity products underlying guaranteed deposit accounts, which was calculated using discounted cash flow models. The contract value of these products represented deposits made to the contract, plus earnings at guaranteed crediting rates, less withdrawals and fees.

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2017 and 2016:



	For the Year Ended December 31,
	2017			2016
(in thousands)
Balance, beginning of year	$	498		$	1,286
Purchases	2,271			2,023
Transfers in	1,743			1,435
Disbursements	(4,101		)	(4,268		)
Investment income	25			22
Balance, end of year	$	436		$	498

Other Postretirement Benefits Plans

We sponsor two defined benefit plans: the Chesapeake Postretirement Plan and the FPU Medical Plan. The following table sets forth the funded status at December 31, 2017 and 2016 and the net periodic cost for the years ended December 31, 2017, 2016, and 2015:



	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2017			2016			2017			2016
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,132		$	1,153		$	1,349		$	1,444
Interest cost	41			43			50			55
Plan participants contributions	118			90			48			64
Actuarial loss (gain)	72			20			(48		)	(41		)
Benefits paid	(235		)	(174		)	(112		)	(173		)
Benefit obligation — end of year	1,128			1,132			1,287			1,349
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions⁽¹⁾	117			84			64			109
Plan participants contributions	118			90			48			64
Benefits paid	(235		)	(174		)	(112		)	(173		)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,128		)	(1,132		)	(1,287		)	(1,349		)
Accrued postretirement cost	$	(1,128	)	$	(1,132	)	$	(1,287	)	$	(1,349	)
Assumptions:
Discount rate	3.50		%	3.75		%	3.75		%	4.00		%


⁽¹⁾	The Chesapeake Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

Net periodic postretirement benefit costs for 2017, 2016, and 2015 include the following components:



	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2017			2016			2015			2017			2016			2015
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	41		$	43		$	42		$	50		$	55		$	57
Amortization of:
Actuarial loss	53			64			72			—			—			—
Prior service cost	(77		)	(77		)	(77		)	—			—			—
Net periodic cost	17			30			37			50			55			57
Amortization of pre-merger regulatory asset	—			—			—			8			8			8
Net periodic cost	$	17		$	30		$	37		$	58		$	63		$	65
Assumptions
Discount rate	3.75		%	3.75		%	3.50		%	4.00		%	4.00		%	3.75		%

Similar to the FPU Pension Plan, continued amortization of the FPU Medical Plan regulatory asset related to the unrecognized cost prior to the merger with Chesapeake Utilities was included in the net periodic cost. The unamortized balance of this regulatory asset was $22,000 and $30,000 at December 31, 2017 and 2016, respectively.

The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive loss or as a regulatory asset as of December 31, 2017:



(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
Prior service cost (credit)	$	—	$	—	$	—	$	(601	)	$	—	$	(601	)
Net loss	3,629		17,483		733		767			10		22,622
Total	$	3,629	$	17,483	$	733	$	166		$	10	$	22,021

Accumulated other comprehensive loss pre-tax⁽¹⁾	$	3,629	$	3,322	$	733	$	166		$	2	$	7,852
Post-merger regulatory asset	—		14,161		—		—			8		14,169
Subtotal	3,629		17,483		733		166			10		22,021
Pre-merger regulatory asset	—		1,304		—		—			22		1,326
Total unrecognized cost	$	3,629	$	18,787	$	733	$	166		$	32	$	23,347


⁽¹⁾	The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2017 is net of income tax benefits of $3.1 million.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations, which is included in the above table as a post-merger regulatory asset. FPU also continues to maintain and amortize a portion of the unrecognized pension and postretirement benefit costs prior to the merger with Chesapeake Utilities related to its regulated operations, which is shown as a pre-merger regulatory asset.

The amounts in accumulated other comprehensive loss and recorded as a regulatory asset for our pension and postretirement benefits plans that are expected to be recognized as a component of net periodic benefit cost in 2018 are set forth in the following table:



(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
Prior service cost (credit)	$	—	$	—	$	—	$	(77	)	$	—	$	(77	)
Net loss	$	351	$	434	$	101	$	58		$	—	$	944
Amortization of pre-merger regulatory asset	$	—	$	761	$	—	$	—		$	8	$	769

Assumptions

The assumptions used for the discount rate to calculate the benefit obligations of all the plans were based on the interest rates of high-quality bonds in 2017, reflecting the expected lives of the plans. In determining the average expected return on plan assets for each applicable plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since Chesapeake Utilities' plans and FPU’s plans have different expected plan lives, particularly in light of the lump-sum-payment option provided in the Chesapeake Pension Plan, different assumptions regarding discount rate and expected return on plan assets were selected for Chesapeake Utilities' and FPU’s plans. Since both pension plans are frozen with respect to additional years of service and compensation, the rate of assumed compensation increases is not applicable.

The health care inflation rate for 2017 used to calculate the benefit obligation is 5.0 percent for medical and 6.0 percent for prescription drugs for the Chesapeake Postretirement Plan; and 5.0 percent for both medical and prescription drugs for the FPU Medical Plan. A one-percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated postretirement benefit obligation by approximately $277,000 as of December 31, 2017, and would increase the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2017 by approximately $11,000. A one-percentage point decrease in the health care inflation rate from the assumed rate would decrease the accumulated postretirement benefit obligation by approximately $215,000 as of December 31, 2017, and would decrease the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2017 by approximately $8,000.

Estimated Future Benefit Payments

In 2018, we expect to contribute $359,000 and $1.5 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, and $151,000 to the Chesapeake SERP. We also expect to contribute $97,000 and $88,000 to the Chesapeake Postretirement Plan and FPU Medical Plan, respectively, in 2017. The schedule below shows the estimated future benefit payments for each of the plans previously described:



	Chesapeake Pension Plan⁽¹⁾		FPU Pension Plan⁽¹⁾		Chesapeake SERP⁽²⁾		Chesapeake Postretirement Plan⁽²⁾		FPU Medical Plan⁽²⁾
(in thousands)
2018	$	687	$	3,078	$	151	$	97	$	88
2019	$	490	$	3,207	$	150	$	96	$	94
2020	$	675	$	3,304	$	149	$	85	$	87
2021	$	779	$	3,362	$	385	$	82	$	91
2022	$	592	$	3,536	$	146	$	81	$	93
Years 2023 through 2027	$	5,278	$	18,608	$	738	$	290	$	404


⁽¹⁾	The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.


⁽²⁾	Benefit payments are expected to be paid out of our general funds.

Retirement Savings Plan

For the years ended December 31, 2017, 2016 and 2015, we sponsored a 401(k) Retirement Savings Plan. This plan is offered to all eligible employees who have completed three months of service. We match 100 percent of eligible participants’ pre-tax contributions to the Retirement Savings Plan up to a maximum of six percent of eligible compensation. The employer matching contribution is made in cash and is invested based on a participant’s investment directions. In addition, we may make a discretionary supplemental contribution to participants in the plan, without regard to whether or not they make pre-tax contributions. Any supplemental employer contribution is generally made in our common stock. With respect to the employer match and supplemental employer contribution, employees are 100 percent vested after two years of service or upon reaching 55 years of age while still employed by us. New employees who do not make an election to contribute and do not opt out of the Retirement Savings Plan will be automatically enrolled at a deferral rate of three percent, and the automatic deferral rate will increase by one percent per year up to a maximum of six percent. In 2018, the maximum automatic deferral rate will be increased to ten percent. All contributions and matched funds can be invested among the mutual funds available for investment.

Employer contributions to our Retirement Savings Plan totaled $5.0 million, $4.5 million, and $4.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, there were 831,183 shares of our common stock reserved to fund future contributions to the Retirement Savings Plan.

Non-Qualified Deferred Compensation Plan

Members of our Board of Directors, and executive officers designated by the Compensation Committee, are eligible to participate in the Non-Qualified Deferred Compensation Plan. Directors can elect to defer any portion of their cash or stock compensation and executive officers can defer up to 80 percent of their base compensation, cash bonuses or any amount of their stock bonuses (net of required withholdings). Executive officers may receive a matching contribution on their cash compensation deferrals up to six percent of their compensation, provided it does not duplicate a match they receive in the Retirement Savings Plan. Stock bonuses are not eligible for matching contributions. Participants are able to elect the payment of benefits to begin on a specified future date or upon separation from service. Additionally, participants can elect to receive payments upon the earlier of a fixed date or separation from service or they can elect to receive payment upon the later of a fixed date or separation from service. The payments can be made in one lump sum or annual installments for up to 15 years.

All obligations arising under the Non-Qualified Deferred Compensation Plan are payable from our general assets, although we have established a Rabbi Trust to informally fund the plan. Deferrals of cash compensation may be invested by the participants in various mutual funds (the same options that are available in the Retirement Savings Plan). The participants are credited with gains or losses on those investments. Deferred stock compensation may not be diversified. The participants are credited with dividends on our common stock in the same amount that is received by all other stockholders. Such dividends are reinvested into our common stock. Assets held in the Rabbi Trust had a fair value of $6.7 million and $4.9 million at December 31, 2017 and 2016, respectively. (See Note 9, Investments, for further details). The assets of the Rabbi Trust are at all times subject to the claims of our general creditors.

Deferrals of executive base compensation and cash bonuses and directors’ cash retainers are paid in cash. All deferrals of executive performance shares, which represent deferred stock units, and directors’ stock retainers are paid in shares of our common stock, except that cash is paid in lieu of fractional shares. The value of our stock held in the Rabbi Trust is classified within the stockholders’ equity section of the consolidated balance sheets and has been accounted for in a manner similar to treasury stock. The amounts recorded under the Non-Qualified Deferred Compensation Plan totaled $3.4 million and $2.4 million at December 31, 2017 and 2016, respectively.

Share-Based Compensation Plans

12 Months Ended

Dec. 31, 2017

Share-Based Compensation Plans

SHARE-BASED COMPENSATION PLANS

Our non-employee directors and key employees have been granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period. We have 509,202 shares of common stock reserved for issuance under the SICP.

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2017, 2016 and 2015:



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Awards to non-employee directors	$	540		$	580		$	640
Awards to key employees	1,950			1,787			1,297
Total compensation expense	2,490			2,367			1,937
Less: tax benefit	(1,003		)	(952		)	(780		)
Share-based compensation amounts included in net income	$	1,487		$	1,415		$	1,157

Stock Options

We did not have any stock options outstanding at December 31, 2017 or 2016, nor were any stock options issued during the years 2015 through 2017.

Non-employee Directors

Shares granted to non-employee directors are issued in advance of these directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2017, each of our non-employee directors received an annual retainer of 835 shares of common stock under the SICP for board service through the 2018 Annual Meeting of Stockholders. A summary of stock activity for our non-employee directors for the years ended December 31, 2017 and 2016 is presented below:



	Number of Shares		Weighted Average Grant Date Fair Value
Outstanding — December 31, 2015	—		$	—
Granted	8,577		$	62.90
Vested	(8,577	)	$	62.90
Outstanding — December 31, 2016	—		$	—
Granted	7,515		$	71.80
Vested	(7,515	)	$	71.80
Outstanding — December 31, 2017	—		$	—

The weighted average grant date fair value of shares granted to our non-employee directors during 2017, 2016 and 2015 was $71.80, $62.90 and $45.54 per share, respectively. The intrinsic values of the shares granted to our non-employee directors are equal to the fair value of these awards on the date of grant. At December 31, 2017, there was $179,000 of unrecognized compensation expense related to these awards. This expense will be fully recognized by April 2018, which approximates the expected remaining service period of those directors.

Key Employees

Our Compensation Committee is authorized to grant our key employees the right to receive awards of shares of our common stock, contingent upon the achievement of established performance goals. These awards are subject to certain post-vesting transfer restrictions.

We currently have outstanding several multi-year performance plans, which are based upon the successful achievement of long-term goals, growth and financial results which comprise both market-based and performance-based conditions or targets. The fair value of each share of stock, tied to a performance-based condition or target, is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each share of market-based award granted.

The table below presents the summary of the stock activity for awards to key employees:



	Number of Shares		Weighted Average Fair Value
Outstanding — December 31, 2015	110,398		$	38.34
Granted	46,571		$	67.90
Vested	(39,553	)	$	31.79
Expired	(2,325	)	$	42.25
Outstanding — December 31, 2016	115,091		$	51.85
Granted	52,355		$	63.42
Vested	(32,926	)	$	38.88
Expired	(1,878	)	$	39.97
Outstanding — December 31, 2017	132,642		$	53.00

In 2017, 2016 and 2015, we withheld shares with a value at least equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes, and remitted the cash to the appropriate taxing authorities with the executives electing to receive the net shares. The total number of shares withheld of 10,269, 12,031 and 12,620 for 2017, 2016 and 2015, respectively, were based on the closing price of the shares on their award date. Total payments for the employees’ tax obligations to the taxing authorities were approximately $692,000, $770,000 and $592,000, in 2017, 2016 and 2015, respectively. The tax benefits associated with these obligations for 2017, 2016 and 2015 are $349,000, $285,000, and $297,000, respectively. The tax benefit for 2015 was recorded in additional paid-in capital in the consolidated statements of stockholders' equity. The tax benefit for 2017 and 2016 was included in the statements of income due to the adoption of new accounting guidance.

The weighted average grant-date fair value of shares granted to key employees during 2017, 2016 and 2015 was $63.42, $67.90 and $47.65 per share, respectively. The intrinsic value of these awards was $10.4 million, $7.7 million and $6.3 million in 2017, 2016 and 2015, respectively. At December 31, 2017, there was $2.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2018 through 2019.

Rates and Other Regulatory Activities

12 Months Ended

Dec. 31, 2017

Rates and Other Regulatory Activities

RATES AND OTHER REGULATORY ACTIVITIES

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake Utilities' Florida Division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities.

Delaware

Rate Case Filing: In December 2015, our Delaware Division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. The Delaware Division, Delaware PSC Staff, the Division of the Public Advocate and other intervenors met and reached a settlement agreement in November 2016. The terms of the settlement agreement included an annual increase of approximately $2.3 million in base rates. The order became final in December 2016, and the new rates became effective January 1, 2017. Amounts collected through interim rates in excess of the respective portion of the $2.3 million increase through December 31, 2016 were accrued as of that date. In January 2017, we filed our proposed refund plan with the Delaware PSC and subsequently issued refunds to customers in March 2017.

Effect of the TCJA on rate payers: As result of the enactment of the TCJA, the Delaware PSC issued an order requiring all rate-regulated utilities to file estimates of their determination of the impact of the TCJA on their cost of service for the most recent test year available (including new rate schedules). The order also requires utilities to propose procedures for changing rates to reflect those impacts on or before March 31, 2018. Our Delaware Division is assessing the impact of the TCJA and will file the requisite reports with the Delaware PSC. If, after reviewing the required filing, the Delaware PSC determines to reduce our rates, it will open a new docket and establish a procedural schedule for conducting an evidentiary hearing regarding the impacts of the TCJA on our operations and existing rates. We believe that the ultimate resolution of this matter will not have a material impact on our financial position or results of operations.

In addition, the Division of the Public Advocate filed a Motion to direct regulated public utilities to accrue regulatory liabilities, starting February 1, 2018, to reflect the Delaware jurisdictional revenue requirement impacts of the changes in the federal corporate income tax rate effected by the TCJA. On February 1, 2018, the PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities reflecting the jurisdictional revenue requirement impacts of the changes in the federal corporate income tax laws.

Maryland Division and Sandpiper

Effect of the TCJA on rate payers: The Maryland PSC issued an order requiring all Maryland public utilities whose rates are explicitly grossed-up for income taxes to track the impacts of the TCJA beginning January 1, 2018. The order required utilities to: (a) apply regulatory accounting treatment, which includes the use of regulatory assets and liabilities for all impacts of the TCJA; (b) file, on or before February 15, 2018, an explanation of the expected effects of the TCJA on their expenses and revenues; and (c) explain when and how they expect to pass on to their customers the net results of those effects. Our Maryland division and Sandpiper prepared filings that included preliminary estimates of the annual impact of the change in the statutory federal income tax rate from 35 percent to 21 percent and also requested that the Maryland PSC grant us additional time to finalize our calculations. We will be recommending appropriate treatment and/or amortization periods for the regulatory liabilities created from the deferred tax revaluation.

Florida

Cost Recovery for the Electric Interconnect Project: In September 2015, FPU’s electric division filed to recover the cost of the proposed FPL interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project would enable FPU's electric division to negotiate a new power purchase agreement to mitigate fuel costs for its Northeast division. FPU's proposal was approved by the Florida PSC at its Agenda Conference held in December 2015. In January 2016, however, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. The Florida Supreme Court reversed the Florida PSC decision in March 2017, after consideration of the parties' legal briefs and oral arguments. As a result, FPU excluded the recovery of these costs from its 2018 Fuel and Purchased Power Cost Recovery Clause and included the costs for recovery in the limited proceeding filing described below.

Surcharge Associated with Modernization of Electric Distribution System Project: In February 2017, FPU’s electric division filed a petition with the Florida PSC requesting a temporary surcharge mechanism to recover costs and generate an appropriate return on investment associated with an essential reliability and modernization project for its electric distribution system. FPU requested approval to invest approximately $59.8 million, over a five-year period, associated with the modernization project. In February 2017, the Office of Public Counsel intervened in this petition. The Florida PSC requested that FPU file a limited proceeding to include these investments in base rates instead of seeking approval of a temporary surcharge. In April 2017, FPU voluntarily withdrew its petition and subsequently filed the limited proceeding described in the next paragraph.

Electric Limited Proceeding: In July 2017, FPU’s electric division filed a petition with the Florida PSC, requesting approval to include $15.2 million of certain capital project expenditures in its rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safety of the electric system while enhancing the capability of FPU’s grid. Included in the $15.2 million is the interconnection project with FPL, which enables FPU to mitigate fuel costs for its electric customers. In December 2017, the Florida PSC approved this petition with an effective date of January 1, 2018. The settlement agreement prescribes the methodology for adjusting the new rates based on the lower federal income tax rate and the process and methodology regarding the refund of deferred income taxes, reclassified as a regulatory liability, as a result of the TCJA.

Northwest Florida Expansion Project: Peninsula Pipeline and our Florida Division are constructing a pipeline in Escambia County, Florida, that will interconnect with FGT's pipeline. The project consists of 33 miles of 12-inch transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and eight miles of 8-inch lateral distribution line that will be operated by Chesapeake Utilities' Florida Division. We have entered into agreements to serve two large customers and are marketing to other customers located close to the facilities.

New Smyrna Beach, Florida Project: In 2017, Peninsula Pipeline constructed a pipeline in Volusia County, Florida, that interconnects with FGT's pipeline. The project, which was placed into service in the fourth quarter of 2017, consists of 14 miles of transmission line from the FGT interconnect operated by Peninsula Pipeline and serves FPU's natural gas distribution system.

(Palm Beach County) Belvedere, Florida Project

Peninsula Pipeline is constructing a pipeline in Palm Beach County, Florida that will interconnect with FGT's pipeline. The project consists of approximately two miles of transmission pipe that will bring gas directly to FPU’s distribution system in West Palm Beach. This interconnection, which will be operated by Peninsula Pipeline, will bring gas directly to FPU’s distribution system in the vicinity of Belvedere Road and Sonsbury Way in West Palm Beach, Florida. This expansion is expected to be placed into service by the end of the third quarter of 2018.

Effect of the TCJA on rate payers: The Office of Public Counsel filed a petition requesting the Florida PSC to establish a general docket to investigate and adjust rates for all investor-owned utilities related to the passage of the TCJA. The Florida PSC issued a Memorandum with a recommendation that, if utilities do not agree to a January 1, 2018 effective date, then the effective date should be February 6, 2018. On January 30, 2018, the Florida PSC scheduled informal meetings between its staff and interested persons to discuss the impact of TCJA. Meetings to discuss the impact of the TCJA for natural gas utilities, electric utilities and water and wastewater utilities have been scheduled individually in mid-February 2018. In the case of our FPU electric division, an order was issued in December regarding the limited proceeding, which prescribes the applicability, timing and treatment of the implications of tax reform. We believe that the ultimate resolution of this matter will not have a material impact on our financial position or results of operations.

Eastern Shore

White Oak Mainline Expansion Project: In July 2016, Eastern Shore received FERC authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an electric power generator in Kent County, Delaware. Eastern Shore constructed approximately 5.4 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and increased compression capability at Eastern Shore’s existing Delaware City compressor station in New Castle County, Delaware. At the end of March 2017, the entire project was placed into service. The total cost to complete the project was approximately $42.0 million.

System Reliability Project: In September 2016, the FERC approved Eastern Shore's application to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware, and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposed to reinforce critical points on its pipeline system. Previously, in July 2016, the FERC granted Eastern Shore’s pre-determination of rolled-in rate treatment absent any significant change in circumstances. As of June 2017, the entire project was placed into service. The total cost to complete the project was approximately $38.0 million. We began to recover the project's costs in August 2017, coinciding with the proposed effectiveness of new rates, subject to refund, pending final resolution of the base rate case described below.

2017 Expansion Project: In May 2016, FERC approved Eastern Shore's request to initiate the pre-filing review process for its 2017 Expansion Project. The 2017 Expansion Project's facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. Eastern Shore entered into precedent agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.

In December 2016, Eastern Shore submitted an application for a CP authorizing construction of the expansion facilities, which the FERC issued in October 2017. The estimated cost of the 2017 Expansion Project is approximately $117.0 million. In December 2017, the TETLP interconnect was placed into service, as requested. The remaining segments of the Expansion Project are expected to be placed into service in various phases over the second through fourth quarters of 2018.

2017 Rate Case Filing: In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million, resulting in an overall requested revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent. In March 2017, the FERC issued an order suspending the tariff rates for the usual five-month period.

On August 1, 2017, Eastern Shore implemented new rates, subject to refund based upon the outcome of the rate proceeding. Eastern Shore recorded incremental revenue of approximately $3.7 million for the year ended December 31, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until the rate case settlement is approved by the FERC and customers receive refunds according to the terms of the settlement agreement. Eastern Shore filed an uncontested settlement agreement and a motion to place interim settlement rates into effect on January 1, 2018. In December 2017, FERC issued an order approving the implementation of interim settlement rates. Not considering the effects of the TCJA, base rates will increase, on an annual basis, by approximately $9.8 million. On February 28, 2018, FERC approved the settlement agreement by a letter order. The order will be deemed final upon the expiration of the right to rehearing on March 30, 2018. Eastern Shore will recover the costs of its 2016 System Reliability Project (placed into service in 2017), along the cost of investments and expenses associated with various expansion, reliability and safety initiatives.

Effect of the TCJA on rate payers: As set forth in the settlement agreement filed with the FERC in the rate case, Eastern Shore agreed to make a filing to reflect the change in the federal corporate income tax rate. Any excess accumulated deferred income tax balances would flow back to customers over the period determined in the next rate case, absent any transition rule included in the TCJA or other statutes or rules that would govern the flow-back period. We believe that the ultimate resolution of this matter will not have a material impact on our financial position or results of operations.

At December 31, 2017 and 2016, our regulated utility operations had recorded the following regulatory assets and liabilities included in our consolidated balance sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.



	As of December 31,
	2017		2016
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery ⁽¹⁾	$	9,869	$	5,703
Under-recovered GRIP revenue ⁽²⁾	164		1,469
Deferred postretirement benefits ⁽³⁾	15,498		18,379
Deferred conversion and development costs ⁽¹⁾	11,735		8,051
Environmental regulatory assets and expenditures ⁽⁴⁾	3,222		3,694
Acquisition adjustment ⁽⁵⁾	39,992		41,864
Loss on reacquired debt ⁽⁶⁾	1,031		1,145
Other	4,994		4,192
Total Regulatory Assets	$	86,505	$	84,497


Regulatory Liabilities
Self-insurance ⁽⁷⁾	$	1,013	$	987
Over-recovered purchased fuel and conservation cost recovery ⁽¹⁾	2,048		808
Under-recovered GRIP revenue ⁽²⁾	2,245		—
Storm reserve ⁽⁷⁾	669		2,310
Accrued asset removal cost ⁽⁸⁾	40,948		39,826
Deferred income taxes due to rate change ⁽⁹⁾	98,492		—
Other	2,048		424
Total Regulatory Liabilities	$	147,463	$	44,355


⁽¹⁾	We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

⁽²⁾

The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution, Fort Meade and Chesapeake Utilities’ Florida Division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.


⁽³⁾	The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. See Note 16, Employee Benefit Plans, for additional information.


⁽⁴⁾	All of our environmental expenditures incurred to date and our current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 19, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

⁽⁵⁾

We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. Included in these amounts are $1.3 million of the premium paid by FPU, $34.2 million of the premium paid by us in 2009, including the gross up of the amount for income tax, because it is not tax deductible, and $746,000 of the premium paid by FPU in 2010.


⁽⁶⁾	Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.


⁽⁷⁾	We have self-insurance and storm reserves in our Florida regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.


⁽⁸⁾	See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.


⁽⁹⁾	We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes, for additional information.

Environmental Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Environmental Commitments and Contingencies

ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate at current and former operating sites the effect on the environment of the disposal or release of specified substances.

MGP Sites

We have participated in the investigation, assessment or remediation of, and have exposures at, seven former MGP sites. Those sites are located in Salisbury, Maryland, Seaford, Delaware and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.

As of December 31, 2017, we had approximately $9.6 million in environmental liabilities, related to FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to its MGP sites. Approximately $11.0 million has been recovered as of December 31, 2017, leaving approximately $3.0 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates. The following is a summary of our remediation status and estimated costs to implement clean-up of our key MGP sites:



Jurisdiction	MGP Site	Status	Cost to Clean up	Recovery through Rates
Florida	West Palm Beach	Remedial actions approved by FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.	Yes
Florida	Sanford	In January 2007, FPU and the Sanford group signed a Third Participation Agreement. FPU's share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000, which has been paid to an escrow account. The EPA issued a preliminary close-out report in December 2014. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are estimated to be approximately $24,000.	Yes
Florida	Winter Haven	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.	Yes
Delaware	Seaford	Proposed plan for implementation approved by DNREC in July 2017.	$273,000 to $465,000.	Yes
Maryland	Cambridge	Currently in discussions with MDE.	Unable to estimate.	N/A

Other Commitments and Contingencies	12 Months Ended
Other Commitments and Contingencies	Dec. 31, 2017
Text Block [Abstract]
Other Commitments and Contingencies	OTHER COMMITMENTS AND CONTINGENCIES Natural Gas, Electric and Propane Supply We have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. In 2017, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with PESCO to manage a portion of their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, 2020. Previously, the Delaware PSC approved PESCO to serve as an asset manager with respect to our Delaware Division. In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six -year term ending in May 2019. Sandpiper's current annual commitment is estimated at approximately 2.7 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices. Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term ending in May 2019. Sharp's current annual commitment is estimated at approximately 2.7 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement. Chesapeake Utilities' Florida Division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to FGT and Gulfstream should any party that acquired the capacity through release fail to pay the capacity charge. FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with FPL requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If this ratio is not met by FPU, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of December 31, 2017, FPU was in compliance with all of the requirements of its fuel supply contracts. Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to its retail electric customers. In July 2016, Eight Flags also started selling steam, pursuant to a separate 20-year contract, to Rayonier, the land owner on which the CHP plant is located. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline. The total purchase obligations for natural gas, electric and propane supplies are approximately $152.9 million for 2018, $122.8 million for 2019-2020, $44.6 million for 2021-2022 and $149.6 million thereafter. Corporate Guarantees The Board of Directors has authorized the Company to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit was $95.0 million. We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at December 31, 2017 was $72.0 million, with the guarantees expiring on various dates through December 2018. Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 12, Long-Term Debt, for further details). As of December 31, 2017, we have issued letters of credit totaling approximately $5.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the payment of natural gas purchases for PESCO, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through December 2018. There have been no draws on these letters of credit as of December 31, 2017. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

Quarterly Financial Data

12 Months Ended

Dec. 31, 2017

Quarterly Financial Data (Unaudited)

QUARTERLY FINANCIAL DATA (UNAUDITED)

In our opinion, the quarterly financial information shown below includes all adjustments necessary for a fair presentation of the operations for such periods. Due to the seasonal nature of our business, there are substantial variations in operations reported on a quarterly basis.



	For the Quarters Ended
	March 31		June 30		September 30		December 31
(in thousands except per share amounts)
2017 ⁽¹⁾
Operating Revenues	$	185,160	$	125,084	$	126,936	$	180,403
Operating Income	$	34,676	$	13,666	$	14,239	$	23,263
Net Income	$	19,144	$	6,046	$	6,833	$	26,101
Earnings per share:
Basic	$	1.17	$	0.37	$	0.42	$	1.60
Diluted	$	1.17	$	0.37	$	0.42	$	1.59

2016 ⁽¹⁾
Operating Revenues	$	146,296	$	102,342	$	108,348	$	141,874
Operating Income	$	36,380	$	15,742	$	10,156	$	21,819
Net Income	$	20,367	$	8,029	$	4,416	$	11,863
Earnings per share:
Basic	$	1.33	$	0.52	$	0.29	$	0.73
Diluted	$	1.33	$	0.52	$	0.29	$	0.73


⁽¹⁾	The sum of the four quarters does not equal the total year due to rounding.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment

Use of Estimates



	As of December 31,
(in thousands)	2017			2016
Property, plant and equipment
Regulated Energy
Natural gas distribution – Delmarva Peninsula	$	234,654		$	220,083
Natural gas distribution – Florida	354,495			331,281
Natural gas transmission – Delmarva	357,264			285,746
Natural gas transmission – Florida	27,096			27,018
Electric distribution – Florida	100,227			93,553
Unregulated Energy
Propane distribution – Delmarva Peninsula	79,139			73,686
Propane distribution – Florida	29,038			26,359
Other unregulated natural gas services – Ohio	66,037			61,383
CHP - Florida	35,239			35,237
Other unregulated energy	1,229			135
Other	27,699			21,114
Total property, plant and equipment	1,312,117			1,175,595
Less: Accumulated depreciation and amortization	(270,599		)	(245,207		)
Plus: Construction work in progress	84,509			56,276
Net property, plant and equipment	$	1,126,027		$	986,664

Contributions or Advances in Aid of Construction

Allowance for Funds Used During Construction

Assets Used in Leases

Capital Lease Asset

Jointly-owned Pipeline

Asset Impairment Evaluations

Depreciation and Accretion Included in Operations Expenses



	2017	2016	2015
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.4%
Natural gas distribution – Florida	2.9%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.8%	2.7%	2.7%
Natural gas transmission – Florida	3.5%	3.9%	4.0%
Electric distribution – Florida	3.4%	3.5%	3.5%

For our unregulated operations, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets:



Asset Description	Useful Life
Propane distribution mains	10-37 years
Propane bulk plants and tanks	10-40 years
Propane equipment	5-33 years
Meters and meter installations	5-33 years
Measuring and regulating station equipment	5-37 years
Natural gas pipelines	45 years
Natural gas right of ways	Perpetual
CHP plant	30 years
Natural gas processing equipment	20-25 years
Office furniture and equipment	3-10 years
Transportation equipment	4-20 years
Structures and improvements	5-45 years
Other	Various

Regulated Operations

Operating Revenues

Our Ohio natural gas supply operation recognizes revenues based on actual volumes of natural gas shipped using contractual rates, which are based upon index prices that are published monthly.

Our natural gas marketing operation recognizes revenue based on the volume of natural gas delivered to its customers.

Eight Flags records revenues based on the amount of electricity and steam generated and sold to its customers.

We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis.

Cost of Sales

Operations and Maintenance Expenses

Cash and Cash Equivalents

Accounts Receivable and Allowance for Doubtful Accounts

Inventories

Goodwill and Other Intangible Assets

Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

Other Deferred Charges

Other deferred charges primarily include issuance costs associated with short-term borrowings. These charges are amortized over the life of the related short-term debt borrowings.

Pension and Other Postretirement Plans

Income Taxes and Investment Tax Credit Adjustments

Income Taxes, Investment Tax Credit Adjustments and Tax-Related Contingency

Financial Instruments

Our natural gas marketing operation enters into natural gas futures and swap contracts to mitigate any price risk associated with the purchase and/or sale of natural gas to specific customers.

Recently Adopted Accounting Standards

FASB Statements

Recently Adopted Accounting Standards

Recent Accounting Standards Yet to be Adopted

The FASB allows companies to elect several practical expedients, in order to simplify the transition to the new standard. The following three expedients must all be elected together:


•	An entity need not reassess whether any expired or existing contracts are or contain leases.


•	An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases).

•An entity need not reassess initial direct costs for any existing leases.

Other practical expedients that can be elected individually are:


•	An entity may elect to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets.


•	An entity may elect to apply the provisions of the new lease guidance at the effective date, without adjusting the comparative periods presented.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Summary of Property, Plant and Equipment by Classification

A summary of property, plant and equipment by classification as of December 31, 2017 and 2016 is provided in the following table:



	As of December 31,
(in thousands)	2017			2016
Property, plant and equipment
Regulated Energy
Natural gas distribution – Delmarva Peninsula	$	234,654		$	220,083
Natural gas distribution – Florida	354,495			331,281
Natural gas transmission – Delmarva	357,264			285,746
Natural gas transmission – Florida	27,096			27,018
Electric distribution – Florida	100,227			93,553
Unregulated Energy
Propane distribution – Delmarva Peninsula	79,139			73,686
Propane distribution – Florida	29,038			26,359
Other unregulated natural gas services – Ohio	66,037			61,383
CHP - Florida	35,239			35,237
Other unregulated energy	1,229			135
Other	27,699			21,114
Total property, plant and equipment	1,312,117			1,175,595
Less: Accumulated depreciation and amortization	(270,599		)	(245,207		)
Plus: Construction work in progress	84,509			56,276
Net property, plant and equipment	$	1,126,027		$	986,664

Average Depreciation Rates



	2017	2016	2015
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.4%
Natural gas distribution – Florida	2.9%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.8%	2.7%	2.7%
Natural gas transmission – Florida	3.5%	3.9%	4.0%
Electric distribution – Florida	3.4%	3.5%	3.5%

Estimated Useful Lives of Assets

For our unregulated operations, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets:



Asset Description	Useful Life
Propane distribution mains	10-37 years
Propane bulk plants and tanks	10-40 years
Propane equipment	5-33 years
Meters and meter installations	5-33 years
Measuring and regulating station equipment	5-37 years
Natural gas pipelines	45 years
Natural gas right of ways	Perpetual
CHP plant	30 years
Natural gas processing equipment	20-25 years
Office furniture and equipment	3-10 years
Transportation equipment	4-20 years
Structures and improvements	5-45 years
Other	Various

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2017

Calculations of Basic and Diluted Earnings Per Share

The following table presents the calculation of the Company’s basic and diluted earnings per share for the years ended December 31:



	For the Year Ended December 31,
	2017		2016		2015
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	58,124	$	44,675	$	41,140
Weighted average shares outstanding	16,336,789		15,570,539		15,094,423
Basic Earnings Per Share	$	3.56	$	2.87	$	2.73

Calculation of Diluted Earnings Per Share:
Net Income	$	58,124	$	44,675	$	41,140
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,336,789		15,570,539		15,094,423
Effect of dilutive securities — Share-based compensation	46,563		42,552		48,950
Adjusted denominator — Diluted	16,383,352		15,613,091		15,143,373
Diluted Earnings Per Share	$	3.55	$	2.86	$	2.72

Acquisitions Acquisition (Tables)

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Mergers, Acquisitions and Dispositions Disclosures [Text Block]



(in thousands)	Net Purchase Price
Chesapeake Utilities common stock issued	$	30,164
Cash	27,494
Acquired debt	1,696
Aggregate amount paid in the acquisition	59,354
Less: cash acquired	(6,806		)
Net amount paid in the acquisition	$	52,548

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The purchase price allocation of the Gatherco acquisition is as follows:



(in thousands)	Purchase Price Allocation
Purchase price	$	57,658

Property plant and equipment	53,203
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226

Long-term debt	1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$	10,119

Segment Information Segment Information (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The following table presents information about our reportable segments.



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	316,971		$	302,402		$	300,674
Unregulated Energy	300,612			196,458			158,570
Total operating revenues, unaffiliated customers	$	617,583		$	498,860		$	459,244
Intersegment Revenues ⁽¹⁾
Regulated Energy	$	9,339		$	3,287		$	1,228
Unregulated Energy	23,983			7,321			3,537
Other businesses	774			880			880
Total intersegment revenues	$	34,096		$	11,488		$	5,645
Operating Income
Regulated Energy	$	73,160		$	69,851		$	60,985
Unregulated Energy	12,477			13,844			16,355
Other businesses and eliminations	206			401			418
Operating Income	85,843			84,096			77,758
Other (expense) income	(765		)	(441		)	293
Interest charges	12,645			10,639			10,006
Income Before Income taxes	72,433			73,016			68,045
Income taxes	14,309			28,341			26,905
Net Income	$	58,124		$	44,675		$	41,140
Depreciation and Amortization
Regulated Energy	$	28,554		$	25,677		$	24,195
Unregulated Energy	7,954			6,386			5,679
Other businesses and eliminations	91			96			98
Total depreciation and amortization	$	36,599		$	32,159		$	29,972
Capital Expenditures
Regulated Energy	$	159,011		$	139,994		$	98,372
Unregulated Energy	26,190			23,984			90,895
Other businesses	5,902			5,398			5,994
Total capital expenditures	$	191,103		$	169,376		$	195,261


⁽¹⁾	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.



	As of December 31,
	2017		2016
Identifiable Assets
Regulated Energy	$	1,121,673	$	986,752
Unregulated Energy	261,541		226,368
Other businesses	34,220		16,099
Total identifiable assets	$	1,417,434	$	1,229,219

Supplemental Cash Flow Disclosures (Tables)

12 Months Ended

Dec. 31, 2017

Cash Paid for Interest and Income Taxes

Cash paid for interest and income taxes during the years ended December 31, 2017, 2016 and 2015 were as follows:



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Cash paid for interest	$	12,420		$	10,315		$	9,497
Cash paid for income taxes, net of refunds	$	(4,114	)	$	(5,308	)	$	11,076

Non-Cash Investing and Financing Activities

Non-cash investing and financing activities during the years ended December 31, 2017, 2016, and 2015 were as follows:



	For the Year Ended December 31,
	2017		2016		2015
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	15,457	$	9,791	$	10,268
Common stock issued for the Retirement Savings Plan	$	—	$	777	$	690
Common stock issued under the SICP	$	1,127	$	1,027	$	1,594
Capital lease obligation	$	2,070	$	3,471	$	4,824
Common stock issued in acquisition	$	—	$	—	$	30,164

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Hedge Ineffectiveness [Table Text Block]

The impact of our natural gas futures commodity contracts previously designated as fair value hedges and the related hedged item on our consolidated income statement for the year ended December 31, 2016, is presented below:



	Year Ended
(in thousands)	December 31, 2016 ⁽¹⁾
Commodity contracts	$	(233	)
Fair value adjustment for natural gas inventory designated as the hedged item	681
Total increase in purchased gas cost	$	448

The increase in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(83	)
Timing ineffectiveness	531
Total ineffectiveness	$	448


⁽¹⁾	There were no natural gas futures commodity contracts designated as fair value hedges in 2017.

Offsetting Assets and Liabilities [Table Text Block]

The following table summarizes the accounts receivable and payables on a gross and net basis at December 31, 2017 and 2016:



	At December 31, 2017
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	8,283	$	2,391	$	5,892
Accounts payable	$	16,643	$	2,391	$	14,252



	At December 31, 2016
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	2,764	$	1,431	$	1,333
Accounts payable	$	5,335	$	1,431	$	3,904

Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets

Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2017 and 2016, are as follows:



	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	December 31, 2017		December 31, 2016
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	13	$	8
Put options	Derivative assets, at fair value	—		9
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	92		113
Propane swap agreements	Derivative assets, at fair value	1,181		693
Total asset derivatives		$	1,286	$	823



	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	December 31, 2017		December 31, 2016
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	5,776	$	773
Derivatives designated as cash flow hedges
Natural gas swap contracts	Derivative liabilities, at fair value	469		—
Propane swap agreements	Derivative liabilities, at fair value	2		—
Total liability derivatives		$	6,247	$	773

Derivative Instruments and Hedging Activities Disclosure [Text Block]

The effects of gains and losses from derivative instruments are as follows:



	Amount of Gain (Loss) on Derivatives:
	Location of Gain (Loss) on Derivatives	For the Year Ended December 31,
(in thousands)	Location of Gain (Loss) on Derivatives	2017			2016			2015
Derivatives not designated as hedging instruments
Realized gain (loss) on forward contracts and options ⁽¹⁾	Revenue	$	112		$	(546	)	$	426
Unrealized (loss) on forward contracts ⁽¹⁾	Revenue	—			—			(126		)
Natural gas futures contracts	Cost of sales	(3,633		)	(541		)	—
Propane swap agreements	Cost of sales	8			7			18
Natural gas swap contracts	Cost of sales	1			—			—
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	(9		)	49			528
Put/Call option ⁽²⁾	Propane inventory	—			—			43
Natural gas futures contracts	Natural gas inventory	—			(233		)	—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	1,607			(364		)	(120		)
Propane swap agreements	Other comprehensive income (loss)	487			1,016			(323		)
Call options	Cost of sales	—			—			(81		)
Natural gas futures contracts	Cost of sales	(456		)	345			—
Natural gas swap contracts	Cost of sales	(822		)	—			—
Natural gas futures contracts	Other comprehensive income (loss)	(1,476		)	222			109
Natural gas swap contracts	Other comprehensive income (loss)	986			—			—
Total		$	(3,195	)	$	(45	)	$	474


(1)	All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our consolidated statements of income.

(2)

Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Financial Assets and Liabilities Measured at Fair Value on Recurring Basis



			Fair Value Measurements Using:
As of December 31, 2017	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	648		—		—		648
Investments—mutual funds and other	6,086		6,086		—		—
Total investments	6,756		6,108		—		648
Derivative assets	1,286		—		1,286		—
Total assets	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	6,247	$	—	$	6,247	$	—



			Fair Value Measurements Using:
As of December 31, 2016	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	561		—		—		561
Investments—mutual funds and other	4,320		4,320		—		—
Total investments	4,902		4,341		—		561
Derivative assets	823		—		823		—
Total assets	$	5,725	$	4,341	$	823	$	561
Liabilities:
Derivative liabilities	$	773	$	—	$	773	$	—

Schedule of Changes in Fair Value of Plan Assets

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2017 and 2016:



	For the Year Ended December 31,
	2017			2016
(in thousands)
Beginning Balance	$	561		$	279
Purchases and adjustments	79			123
Transfers/disbursements	(53		)	151
Investment income	61			8
Ending Balance	$	648		$	561

Tabular disclosure of financial instruments measured at fair value, including those classified in shareholders' equity measured on a recurring or nonrecurring basis. Disclosures include, but are not limited to, fair value measurements recorded and the reasons for the measurements, level within the fair value hierarchy in which the fair value measurements are categorized and transfers between levels 1 and 2. Nonrecurring fair value measurements are those that are required or permitted in the statement of financial position in particular circumstances.

Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of Carrying Value of Goodwill

The carrying value of goodwill as of December 31, 2017 and 2016 was as follows:



	As of December 31,
(in thousands)	2017		2016
Regulated Energy	$	3,353	$	3,353
Unregulated Energy	18,751		11,717
Total	$	22,104	$	15,070

Schedule of Carrying Value and Accumulated Amortization of Intangible Assets

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2017 and 2016 are as follows:



	As of December 31,
	2017				2016
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	7,393	$	2,880	$	4,012	$	2,379
Non-Compete agreements	270		175		270		146
Other	270		192		270		184
Total	$	7,933	$	3,247	$	4,552	$	2,709

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Current Income Tax Expense
Federal	$	2,803		$	(4,898	)	$	4,875
State	492			2,053			1,533
Other	(71		)	(71		)	(23		)
Total current income tax expense	3,224			(2,916		)	6,385
Deferred Income Tax Expense ⁽¹⁾
Property, plant and equipment	8,314			31,062			21,205
Deferred gas costs	2,002			1,163			(1,539		)
Pensions and other employee benefits	180			237			(84		)
FPU merger-related premium cost and deferred gain	(1,148		)	(572		)	(556		)
Net operating loss carryforwards	193			(9		)	2,078
Other	1,544			(624		)	(584		)
Total deferred income tax expense	11,085			31,257			20,520
Total Income Tax Expense	$	14,309		$	28,341		$	26,905

⁽¹⁾Includes $873,000, $2.1 million and $2.1 million of deferred state income taxes for the years 2017, 2016 and 2015, respectively.

Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Reconciliation of Effective Income Tax Rates
Federal income tax expense ⁽¹⁾	$	25,351		$	22,759		$	23,865
State income taxes, net of federal benefit	1,894			3,422			3,062
ESOP dividend deduction	(257		)	(264		)	(263		)
Revaluation of deferred tax assets and liabilities	(14,299		)	—			—
Other	1,620			2,424			241
Total Income Tax Expense	$	14,309		$	28,341		$	26,905
Effective Income Tax Rate ⁽²⁾	19.75		%	38.81		%	39.54		%


⁽¹⁾	Federal income taxes were calculated at 35 percent for each year represented.


⁽²⁾	Effective tax rate for 2017 includes the impact of the revaluation of deferred tax assets and liabilities for our unregulated businesses due to implementation of the TCJA.

Schedule of Accumulated Deferred Income Tax Assets and Liabilities



	As of December 31,
	2017		2016
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	133,581	$	218,074
Acquisition adjustment	9,323		14,840
Loss on reacquired debt	153		442
Deferred gas costs	2,574		1,846
Other	5,422		6,375
Total deferred income tax liabilities	151,053		241,577
Deferred income tax assets:
Pension and other employee benefits	4,698		6,230
Environmental costs	1,744		2,592
Net operating loss carryforwards	1,625		952
Investment tax credit carryforwards	—		2,643
Self insurance	164		189
Storm reserve liability	717		1,131
Other	6,255		4,946
Total deferred income tax assets	15,203		18,683
Deferred Income Taxes Per Consolidated Balance Sheets	$	135,850	$	222,894

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:



	As of December 31,
(in thousands)	2017			2016
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	7,982		$	7,978
Uncollateralized Senior Notes:
6.64% note, due October 31, 2017	—			2,727
5.50% note, due October 12, 2020	6,000			8,000
5.93% note, due October 31, 2023	18,000			21,000
5.68% note, due June 30, 2026	26,100			29,000
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000
3.88% note, due May 15, 2029	50,000			50,000
3.25% note, due April 30, 2032	70,000			—
Promissory notes	97			168
Capital lease obligation	2,070			3,471
Less: debt issuance costs	(433		)	(291		)
Total long-term debt	206,816			149,053
Less: current maturities	(9,421		)	(12,099		)
Total long-term debt, net of current maturities	$	197,395		$	136,954

Short-Term Borrowing Short-Term Borrowing (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Schedule of Short-term Debt



					Outstanding borrowings at
(in thousands)	Total Facility		Interest Rate	Expiration Date	December 31, 2017		December 31, 2016		Available at December 31, 2017
Bank Credit Facility
Committed revolving credit facility A	$	55,000	LIBOR plus 1.00 percent ⁽¹⁾	October 28, 2018	$	55,000	$	45,000	$	—
Committed revolving credit facility B	30,000		LIBOR plus 1.00 percent ⁽¹⁾	October 31, 2018	20,500		21,311		9,500
Short-term revolving credit note C	50,000		LIBOR plus 0.80 percent ⁽²⁾	October 31, 2018	50,000		50,000		—
Committed revolving credit facility D	45,000		LIBOR plus 0.85 percent ⁽³⁾	October 31, 2018	40,171		35,000		4,829
Committed revolving credit facility E	40,000		LIBOR plus 0.85 percent ⁽³⁾	October 31, 2018	—		—		40,000
Committed revolving credit facility F⁽⁵⁾	150,000		LIBOR plus 1.00 percent ⁽¹⁾	October 08, 2020	75,000		50,000		75,000
Total short term credit facilities	$	370,000			$	240,671	$	201,311	$	129,329
Book overdrafts⁽⁴⁾					10,298		8,560
Total short-term borrowing					$	250,969	$	209,871

⁽¹⁾ This facility bears interest at LIBOR for the applicable period plus up to 1.00 percent, based on Total Indebtedness as a percentage of Total Capitalization.

⁽²⁾ At our discretion, the borrowings under this facility can bear interest at the lender's base rate plus 0.80 percent.

⁽³⁾At our discretion, the borrowing under this facility can bear interest at the lender's base rate plus 0.85 percent.

⁽⁴⁾ If presented, these book overdrafts would be funded through the bank revolving credit facilities.

⁽⁵⁾This committed revolving credit facility includes a restriction that our short-term borrowings, excluding any borrowings under the committed revolving

credit facility, shall not exceed $200.0 million.

Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)



	Defined Benefit Pension and Postretirement Plan Items			Commodity Contract Cash Flow Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive income before reclassifications	281			159			440
Amounts reclassified from accumulated other comprehensive income/(loss)	336			(170		)	166
Net current-period other comprehensive income/(loss)	617			(11		)	606
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)



	Defined Benefit Pension and Postretirement Plan Items			Commodity Contracts Cash Flow Hedges			Total
(in thousands)
As of December 31, 2015	$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive income/(loss) before reclassifications	(254		)	762			508
Amounts reclassified from accumulated other comprehensive income/(loss)	474			(20		)	454
Net current-period other comprehensive income	220			742			962
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)

Reclassification out of Accumulated Other Comprehensive Income



	For the Year Ended December 31,
(in thousands)	2017			2016			2015
Amortization of defined benefit pension and postretirement plan items:
Prior service cost ⁽¹⁾	$	77		$	77		$	68
Net gain ⁽¹⁾	(636		)	(871		)	(650		)
Total before income taxes	(559		)	(794		)	(582		)
Income tax benefit	223			320			233
Net of tax	$	(336	)	$	(474	)	$	(349	)

Gains and losses on commodity contracts cash flow hedges
Propane swap agreements ⁽²⁾	$	1,607		$	(322	)	$	(120	)
Natural gas swaps ⁽²⁾	(822		)	—			(55		)
Natural gas futures ⁽²⁾	(456		)	345			(31		)
Total before income taxes	329			23			(206		)
Income tax impact	(159		)	(3		)	83
Net of tax	$	170		$	20		$	(123	)

Total reclassifications for the period	$	(166	)	$	(454	)	$	(472	)


⁽¹⁾	These amounts are included in the computation of net periodic benefits. See Note 16, Employee Benefit Plans, for additional details.


⁽²⁾	These amounts are included in the effects of gains and losses from derivative instruments. See Note 7, Derivative Instruments, for additional details.

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of Assets by Investment Type

The following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2017, 2016 and 2015:



	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2017		2016		2015		2017		2016		2015
Asset Category
Equity securities	52.70	%	52.93	%	48.01	%	55.17	%	53.18	%	48.56	%
Debt securities	37.79	%	37.64	%	39.62	%	36.56	%	37.74	%	41.74	%
Other	9.51	%	9.43	%	12.37	%	8.27	%	9.08	%	9.70	%
Total	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%

Schedule of Asset Allocation Strategy

The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the plans’ goals and objectives:



Asset Allocation Strategy
Asset Class	Minimum Allocation Percentage		Maximum Allocation Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	14	%	32	%
Foreign Equities (Developed and Emerging Markets)	13	%	25	%
Fixed Income (Inflation Bond and Taxable Fixed)	26	%	40	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	6	%	14	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%	19	%
Cash	0	%	5	%

Summary of Pension Plan Assets

At December 31, 2017 and 2016, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:



	Fair Value Measurement Hierarchy

	At December 31, 2017								At December 31, 2016
Asset Category	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(in thousands)
Mutual Funds - Equity securities
U.S. Large Cap ⁽¹⁾	$	4,245	$	—	$	—	$	4,245	$	4,031	$	—	$	—	$	4,031
U.S. Mid Cap ⁽¹⁾	1,775		—		—		1,775		1,677		—		—		1,677
U.S. Small Cap ⁽¹⁾	918		—		—		918		845		—		—		845
International ⁽²⁾	11,916		—		—		11,916		9,574		—		—		9,574
Alternative Strategies ⁽³⁾	5,528		—		—		5,528		5,238		—		—		5,238
	24,382		—		—		24,382		21,365		—		—		21,365
Mutual Funds - Debt securities
Fixed income ⁽⁴⁾	18,454		—		—		18,454		16,958		—		—		16,958
High Yield ⁽⁴⁾	2,772		—		—		2,772		2,636		—		—		2,636
	21,226		—		—		21,226		19,594		—		—		19,594
Mutual Funds - Other
Commodities ⁽⁵⁾	2,154		—		—		2,154		2,134		—		—		2,134
Real Estate ⁽⁶⁾	2,300		—		—		2,300		2,116		—		—		2,116
Guaranteed deposit ⁽⁷⁾	—		—		436		436		—		—		498		498
	4,454		—		436		4,890		4,250		—		498		4,748
Total Pension Plan Assets in fair value hierarchy	$	50,062	$	—	$	436	50,498		$	45,209	$	—	$	498	45,707
Investments measured at net asset value ⁽⁸⁾							7,248								6,233
Total Pension Plan Assets							$	57,746							$	51,940

Schedule of Level Three Defined Benefit Plan Assets Roll Forward

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2017 and 2016:



	For the Year Ended December 31,
	2017			2016
(in thousands)
Balance, beginning of year	$	498		$	1,286
Purchases	2,271			2,023
Transfers in	1,743			1,435
Disbursements	(4,101		)	(4,268		)
Investment income	25			22
Balance, end of year	$	436		$	498

Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets

The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive loss or as a regulatory asset as of December 31, 2017:



(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
Prior service cost (credit)	$	—	$	—	$	—	$	(601	)	$	—	$	(601	)
Net loss	3,629		17,483		733		767			10		22,622
Total	$	3,629	$	17,483	$	733	$	166		$	10	$	22,021

Accumulated other comprehensive loss pre-tax⁽¹⁾	$	3,629	$	3,322	$	733	$	166		$	2	$	7,852
Post-merger regulatory asset	—		14,161		—		—			8		14,169
Subtotal	3,629		17,483		733		166			10		22,021
Pre-merger regulatory asset	—		1,304		—		—			22		1,326
Total unrecognized cost	$	3,629	$	18,787	$	733	$	166		$	32	$	23,347


⁽¹⁾	The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2017 is net of income tax benefits of $3.1 million.

Amounts in Accumulated Other Comprehensive Income/Loss and Regulatory Asset



(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
Prior service cost (credit)	$	—	$	—	$	—	$	(77	)	$	—	$	(77	)
Net loss	$	351	$	434	$	101	$	58		$	—	$	944
Amortization of pre-merger regulatory asset	$	—	$	761	$	—	$	—		$	8	$	769

Schedule of Estimated Future Benefit Payments

The schedule below shows the estimated future benefit payments for each of the plans previously described:



	Chesapeake Pension Plan⁽¹⁾		FPU Pension Plan⁽¹⁾		Chesapeake SERP⁽²⁾		Chesapeake Postretirement Plan⁽²⁾		FPU Medical Plan⁽²⁾
(in thousands)
2018	$	687	$	3,078	$	151	$	97	$	88
2019	$	490	$	3,207	$	150	$	96	$	94
2020	$	675	$	3,304	$	149	$	85	$	87
2021	$	779	$	3,362	$	385	$	82	$	91
2022	$	592	$	3,536	$	146	$	81	$	93
Years 2023 through 2027	$	5,278	$	18,608	$	738	$	290	$	404


⁽¹⁾	The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.


⁽²⁾	Benefit payments are expected to be paid out of our general funds.

Pension benefit

Component of Net Periodic Pension Cost (Benefit)



	Chesapeake Pension Plan									FPU Pension Plan
For the Years Ended December 31,	2017			2016			2015			2017			2016			2015
(in thousands)
Components of net periodic pension cost:
Interest cost	$	402		$	421		$	407		$	2,482		$	2,525		$	2,504
Expected return on assets	(495		)	(501		)	(530		)	(2,779		)	(2,702		)	(3,107		)
Amortization of actuarial loss	399			459			392			513			519			456
Settlement expense	—			161			—			—			—			—
Net periodic pension cost	306			540			269			216			342			(147		)
Amortization of pre-merger regulatory asset	—			—			—			761			761			761
Total periodic cost	$	306		$	540		$	269		$	977		$	1,103		$	614
Assumptions:
Discount rate	3.75		%	3.75		%	3.50		%	4.00		%	4.00		%	3.75		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	6.50		%	6.50		%	7.00		%

Schedule of Funded Status of Benefit Obligation and Plan Assets



	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2017			2016			2017			2016
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	11,355		$	11,501		$	63,832		$	64,435
Interest cost	402			421			2,482			2,525
Actuarial loss (gain)	454			330			1,199			(216		)
Effect of settlement	—			(433		)	—			—
Benefits paid	(768		)	(464		)	(2,849		)	(2,912		)
Benefit obligation — end of year	11,443			11,355			64,664			63,832
Change in plan assets:
Fair value of plan assets — beginning of year	8,668			8,752			43,272			42,207
Actual return on plan assets	1,144			424			6,025			2,343
Employer contributions	306			389			1,948			1,634
Benefits paid	(768		)	(464		)	(2,849		)	(2,912		)
Effect of settlement	—			(433		)	—			—
Fair value of plan assets — end of year	9,350			8,668			48,396			43,272
Reconciliation:
Funded status	(2,093		)	(2,687		)	(16,268		)	(20,560		)
Accrued pension cost	$	(2,093	)	$	(2,687	)	$	(16,268	)	$	(20,560	)
Assumptions:
Discount rate	3.50		%	3.75		%	3.75		%	4.00		%
Expected return on plan assets	6.00		%	6.00		%	6.50		%	6.50		%

Other Postretirement Benefit Plans

Component of Net Periodic Pension Cost (Benefit)

Net periodic postretirement benefit costs for 2017, 2016, and 2015 include the following components:



	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2017			2016			2015			2017			2016			2015
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	41		$	43		$	42		$	50		$	55		$	57
Amortization of:
Actuarial loss	53			64			72			—			—			—
Prior service cost	(77		)	(77		)	(77		)	—			—			—
Net periodic cost	17			30			37			50			55			57
Amortization of pre-merger regulatory asset	—			—			—			8			8			8
Net periodic cost	$	17		$	30		$	37		$	58		$	63		$	65
Assumptions
Discount rate	3.75		%	3.75		%	3.50		%	4.00		%	4.00		%	3.75		%

Schedule of Funded Status of Benefit Obligation and Plan Assets

The following table sets forth the funded status at December 31, 2017 and 2016 and the net periodic cost for the years ended December 31, 2017, 2016, and 2015:



	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2017			2016			2017			2016
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,132		$	1,153		$	1,349		$	1,444
Interest cost	41			43			50			55
Plan participants contributions	118			90			48			64
Actuarial loss (gain)	72			20			(48		)	(41		)
Benefits paid	(235		)	(174		)	(112		)	(173		)
Benefit obligation — end of year	1,128			1,132			1,287			1,349
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions⁽¹⁾	117			84			64			109
Plan participants contributions	118			90			48			64
Benefits paid	(235		)	(174		)	(112		)	(173		)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,128		)	(1,132		)	(1,287		)	(1,349		)
Accrued postretirement cost	$	(1,128	)	$	(1,132	)	$	(1,287	)	$	(1,349	)
Assumptions:
Discount rate	3.50		%	3.75		%	3.75		%	4.00		%


⁽¹⁾	The Chesapeake Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

Rabbi trust (associated with Supplemental Executive Retirement Savings Plan)

Component of Net Periodic Pension Cost (Benefit)



For the Years Ended December 31,	2017			2016			2015
(in thousands)
Components of net periodic pension cost:
Interest cost	$	89		$	91		$	91
Amortization of prior service cost	—			—			9
Amortization of actuarial loss	87			87			99
Net periodic pension cost	$	176		$	178		$	199
Assumptions:
Discount rate	3.75		%	3.75		%	3.50		%

Schedule of Funded Status of Benefit Obligation and Plan Assets

The following sets forth the funded status at December 31, 2017 and 2016 and the net periodic cost for the years ended December 31, 2017, 2016 and 2015 for the Chesapeake SERP:



At December 31,	2017			2016
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	2,428		$	2,510
Interest cost	89			91
Actuarial loss (gain)	63			(21		)
Benefits paid	(152		)	(152		)
Benefit obligation — end of year	2,428			2,428
Change in plan assets:
Fair value of plan assets — beginning of year	—			—
Employer contributions	152			152
Benefits paid	(152		)	(152		)
Fair value of plan assets — end of year	—			—
Reconciliation:
Funded status	(2,428		)	(2,428		)
Accrued pension cost	$	(2,428	)	$	(2,428	)
Assumptions:
Discount rate	3.50		%	3.75		%

Share-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2017

Share-Based Compensation Amounts Included in Net Income

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2017, 2016 and 2015:



	For the Year Ended December 31,
	2017			2016			2015
(in thousands)
Awards to non-employee directors	$	540		$	580		$	640
Awards to key employees	1,950			1,787			1,297
Total compensation expense	2,490			2,367			1,937
Less: tax benefit	(1,003		)	(952		)	(780		)
Share-based compensation amounts included in net income	$	1,487		$	1,415		$	1,157

SICP Awards to Non-employee directors

Summary of Stock Activity Non-employee directors

A summary of stock activity for our non-employee directors for the years ended December 31, 2017 and 2016 is presented below:



	Number of Shares		Weighted Average Grant Date Fair Value
Outstanding — December 31, 2015	—		$	—
Granted	8,577		$	62.90
Vested	(8,577	)	$	62.90
Outstanding — December 31, 2016	—		$	—
Granted	7,515		$	71.80
Vested	(7,515	)	$	71.80
Outstanding — December 31, 2017	—		$	—

SICP Awards to Key Employees

Summary of Stock Activity Non-employee directors

The table below presents the summary of the stock activity for awards to key employees:



	Number of Shares		Weighted Average Fair Value
Outstanding — December 31, 2015	110,398		$	38.34
Granted	46,571		$	67.90
Vested	(39,553	)	$	31.79
Expired	(2,325	)	$	42.25
Outstanding — December 31, 2016	115,091		$	51.85
Granted	52,355		$	63.42
Vested	(32,926	)	$	38.88
Expired	(1,878	)	$	39.97
Outstanding — December 31, 2017	132,642		$	53.00

Rates and Other Regulatory Activities Regulatory assets and liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Regulated Operations [Abstract]

Schedule of Regulatory Assets [Table Text Block]



	As of December 31,
	2017		2016
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery ⁽¹⁾	$	9,869	$	5,703
Under-recovered GRIP revenue ⁽²⁾	164		1,469
Deferred postretirement benefits ⁽³⁾	15,498		18,379
Deferred conversion and development costs ⁽¹⁾	11,735		8,051
Environmental regulatory assets and expenditures ⁽⁴⁾	3,222		3,694
Acquisition adjustment ⁽⁵⁾	39,992		41,864
Loss on reacquired debt ⁽⁶⁾	1,031		1,145
Other	4,994		4,192
Total Regulatory Assets	$	86,505	$	84,497


Regulatory Liabilities
Self-insurance ⁽⁷⁾	$	1,013	$	987
Over-recovered purchased fuel and conservation cost recovery ⁽¹⁾	2,048		808
Under-recovered GRIP revenue ⁽²⁾	2,245		—
Storm reserve ⁽⁷⁾	669		2,310
Accrued asset removal cost ⁽⁸⁾	40,948		39,826
Deferred income taxes due to rate change ⁽⁹⁾	98,492		—
Other	2,048		424
Total Regulatory Liabilities	$	147,463	$	44,355


⁽¹⁾	We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

⁽²⁾


⁽³⁾	The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. See Note 16, Employee Benefit Plans, for additional information.


⁽⁴⁾	All of our environmental expenditures incurred to date and our current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 19, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

⁽⁵⁾


⁽⁶⁾	Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.


⁽⁷⁾	We have self-insurance and storm reserves in our Florida regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.


⁽⁸⁾	See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

Environmental Commitments and Contingencies Environmental Remediation Status (Tables)

12 Months Ended

Dec. 31, 2017

Environmental Remediation Obligations [Abstract]

Schedule of Environmental Loss Contingencies by Site [Table Text Block]

The following is a summary of our remediation status and estimated costs to implement clean-up of our key MGP sites:



Jurisdiction	MGP Site	Status	Cost to Clean up	Recovery through Rates
Florida	West Palm Beach	Remedial actions approved by FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.	Yes
Florida	Sanford	In January 2007, FPU and the Sanford group signed a Third Participation Agreement. FPU's share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000, which has been paid to an escrow account. The EPA issued a preliminary close-out report in December 2014. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are estimated to be approximately $24,000.	Yes
Florida	Winter Haven	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.	Yes
Delaware	Seaford	Proposed plan for implementation approved by DNREC in July 2017.	$273,000 to $465,000.	Yes
Maryland	Cambridge	Currently in discussions with MDE.	Unable to estimate.	N/A

Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of Quarterly Financial Information

Due to the seasonal nature of our business, there are substantial variations in operations reported on a quarterly basis.



	For the Quarters Ended
	March 31		June 30		September 30		December 31
(in thousands except per share amounts)
2017 ⁽¹⁾
Operating Revenues	$	185,160	$	125,084	$	126,936	$	180,403
Operating Income	$	34,676	$	13,666	$	14,239	$	23,263
Net Income	$	19,144	$	6,046	$	6,833	$	26,101
Earnings per share:
Basic	$	1.17	$	0.37	$	0.42	$	1.60
Diluted	$	1.17	$	0.37	$	0.42	$	1.59

2016 ⁽¹⁾
Operating Revenues	$	146,296	$	102,342	$	108,348	$	141,874
Operating Income	$	36,380	$	15,742	$	10,156	$	21,819
Net Income	$	20,367	$	8,029	$	4,416	$	11,863
Earnings per share:
Basic	$	1.33	$	0.52	$	0.29	$	0.73
Diluted	$	1.33	$	0.52	$	0.29	$	0.73


⁽¹⁾	The sum of the four quarters does not equal the total year due to rounding.

Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment by Classification (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, plant and equipment
Total property, plant and equipment	$ 1,312,117	$ 1,175,595
Less: Accumulated depreciation and amortization	(270,599)	(245,207)
Plus: Construction work in progress	84,509	56,276
Net property, plant and equipment	1,126,027	986,664
OHIO
Property, plant and equipment
Total property, plant and equipment	66,037	61,383
Natural gas distribution \| Delmarva
Property, plant and equipment
Total property, plant and equipment	234,654	220,083
Natural gas distribution \| Florida
Property, plant and equipment
Total property, plant and equipment	354,495	331,281
Natural gas transmission \| Delmarva
Property, plant and equipment
Total property, plant and equipment	357,264	285,746
Natural gas transmission \| Florida
Property, plant and equipment
Total property, plant and equipment	27,096	27,018
Electric distribution \| Florida
Property, plant and equipment
Total property, plant and equipment	100,227	93,553
Propane distribution \| Delmarva
Property, plant and equipment
Total property, plant and equipment	79,139	73,686
Propane distribution \| Florida
Property, plant and equipment
Total property, plant and equipment	29,038	26,359
CHP \| Florida
Property, plant and equipment
Total property, plant and equipment	35,239	35,237
Other unregulated energy
Property, plant and equipment
Total property, plant and equipment	1,229	135
Other
Property, plant and equipment
Total property, plant and equipment	$ 27,699	$ 21,114

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017 USD ($) mi	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	May 31, 2016 USD ($)	May 01, 2013 USD ($)
Summary Of Accounting Policies [Line Items]
Number of Utilities that do not have cost recovery mechanism	2
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 1,500,000
Number of contracts affecting new revenue recognition principle adoption	1
Delay of Revenue Recognition Due To Implementation of New Standard	$ 407,000
Maturity Period To Be Considered Cash Equivalents	3
Contributions or Advances in Aid of Construction	$ 2,100,000	$ 1,000,000	$ 1,700,000
Property, plant and equipment in service assets under operating lease contract	1,400,000
Annual revenue from operating lease	$ 264,000
Operating lease term	20 years
Accumulated depreciation, plant in service assets under operating lease	$ 652,000	580,000
Capital Leased Assets, Net	2,000,000	3,400,000
Capital Leased Assets, Noncurrent, Fair Value Disclosure					$ 7,100,000
Ground Leases, Accumulated Amortization	5,100,000	3,700,000
Amortization of Leased Asset	1,400,000	1,400,000	1,300,000
Net property, plant and equipment	1,126,027,000	986,664,000
Accumulated depreciation	270,599,000	245,207,000
Depreciation and accretion reported in operations expenses	$ 8,100,000	7,300,000	7,000,000
Deferred revenue refund payment, period	1 year
Gain from a settlement	$ (130,000)	(130,000)	$ (1,500,000)
Gain Contingency, Unrecorded Amount				$ 650,000
Natural Gas Operations
Summary Of Accounting Policies [Line Items]
Net property, plant and equipment	$ 6,670,000
Length of pipeline \| mi	16
Ownership interest	45.00%
Accumulated depreciation	$ 1,251,000	$ 1,029,000
Pension And Other Postretirement Benefits [Member]
Summary Of Accounting Policies [Line Items]
Percentage of change in discount rate	0.25%
Percentage of change in rate of return	0.25%
Estimated increase in annual pension and postretirement costs	$ 7,000
Estimated decrease in annual pension and postretirement costs	(9,000)
Estimated change in annual post retirement and supplemental executive retirement plans	$ 143,000

Summary of Significant Accounting Policies - Average Depreciation Rates (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Natural gas distribution \| Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.50%	2.50%	2.40%
Natural gas distribution \| Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.90%	2.90%	2.90%
Natural gas transmission \| Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.80%	2.70%	2.70%
Natural gas transmission \| Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	3.50%	3.90%	4.00%
Electric distribution \| Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	3.40%	3.50%	3.50%

Summary of Significant Accounting Policies - Estimated Useful Lives of Assets (Detail)	12 Months Ended
	Dec. 31, 2017
Minimum \| Propane Distribution Mains [Member]
Useful Life of Assets	10 years
Minimum \| Propane Bulk Plants And Tanks [Member]
Useful Life of Assets	10 years
Minimum \| Liquefied Petroleum Gas Equipment [Member]
Useful Life of Assets	5 years
Minimum \| Meters And Meter Installations [Member]
Useful Life of Assets	5 years
Minimum \| Measuring And Regulating Station Equipment [Member]
Useful Life of Assets	5 years
Minimum \| Natural gas processing equipment [Member]
Useful Life of Assets	20 years
Minimum \| Office Furniture And Equipment [Member]
Useful Life of Assets	3 years
Minimum \| Transportation Equipment [Member]
Useful Life of Assets	4 years
Minimum \| Structures And Improvements [Member]
Useful Life of Assets	5 years
Maximum \| Propane Distribution Mains [Member]
Useful Life of Assets	37 years
Maximum \| Propane Bulk Plants And Tanks [Member]
Useful Life of Assets	40 years
Maximum \| Liquefied Petroleum Gas Equipment [Member]
Useful Life of Assets	33 years
Maximum \| Meters And Meter Installations [Member]
Useful Life of Assets	33 years
Maximum \| Measuring And Regulating Station Equipment [Member]
Useful Life of Assets	37 years
Maximum \| Natural gas pipelines [Member]
Useful Life of Assets	45 years
Maximum \| Natural gas processing equipment [Member]
Useful Life of Assets	25 years
Maximum \| Office Furniture And Equipment [Member]
Useful Life of Assets	10 years
Maximum \| Transportation Equipment [Member]
Useful Life of Assets	20 years
Maximum \| Structures And Improvements [Member]
Useful Life of Assets	45 years

Earnings Per Share - Calculations of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Calculation of Basic Earnings Per Share:
Net Income	$ 26,101	$ 6,833	$ 6,046	$ 19,144	$ 11,863	$ 4,416	$ 8,029	$ 20,367	$ 58,124	$ 44,675	$ 41,140
Weighted shares outstanding - Basic (in shares)									16,336,789	15,570,539	15,094,423
Basic Earnings Per Share (in usd per share)	$ 1.60	$ 0.42	$ 0.37	$ 1.17	$ 0.73	$ 0.29	$ 0.52	$ 1.33	$ 3.56	$ 2.87	$ 2.73
Calculation of Diluted Earnings Per Share:
Net Income	$ 26,101	$ 6,833	$ 6,046	$ 19,144	$ 11,863	$ 4,416	$ 8,029	$ 20,367	$ 58,124	$ 44,675	$ 41,140
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)									16,336,789	15,570,539	15,094,423
Share-based Compensation									46,563	42,552	48,950
Adjusted denominator — Diluted									16,383,352	15,613,091	15,143,373
Diluted Earnings Per Share (in usd per share)	$ 1.59	$ 0.42	$ 0.37	$ 1.17	$ 0.73	$ 0.29	$ 0.52	$ 1.33	$ 3.55	$ 2.86	$ 2.72

Acquisitions - Additional Information (Detail)		3 Months Ended								12 Months Ended
Acquisitions - Additional Information (Detail)	Apr. 01, 2015 USD ($) shares	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares	592,970
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned		$ 0				$ 0				$ 0	$ 0	$ 30,164,000
Cash paid for acquisition										11,945,000	0	20,930,000
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed												514,000	$ 786,000
Revenues		180,403,000	$ 126,936,000	$ 125,084,000	$ 185,160,000	141,874,000	$ 108,348,000	$ 102,342,000	$ 146,296,000	617,583,000	498,860,000	459,244,000
Net Income		26,101,000	$ 6,833,000	$ 6,046,000	$ 19,144,000	$ 11,863,000	$ 4,416,000	$ 8,029,000	$ 20,367,000	58,124,000	44,675,000	41,140,000
ARM Energy [Member]
Business Combination, Liabilities Arising from Contingencies, Amount Recognized		$ 2,500,000.0								$ 2,500,000.0
Chipola [Member]
Number of customers acquired through acquisition										800
Central Gas [Member]
Number of customers acquired through acquisition										325
Gatherco [Member]
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned	$ 30,200,000											30,164,000
Cash paid for acquisition	27,500,000											27,494,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt	1,696,000											1,696,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	$ 6,800,000											6,806,000
Business Combination Contingent Cash Consideration Payable												15,000,000
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed												1,300,000
Revenues										$ 33,300,000	26,600,000	16,700,000
Net Income										$ 8,913,000	$ 2,100,000	$ 312,000

Acquisitions Purchase Consideration (Details) - USD ($) $ in Thousands			12 Months Ended
	Aug. 31, 2017	Apr. 01, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		592,970
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned			$ 0	$ 0	$ 30,164
Payments to Acquire Businesses, Gross			$ 11,945	$ 0	20,930
Gatherco [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned		$ 30,200			30,164
Payments to Acquire Businesses, Gross		27,500			27,494
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt		1,696			1,696
Business Combination, Consideration Transferred					57,658
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents		$ (6,800)			$ (6,806)
Unregulated Energy
Business Acquisition [Line Items]
Goodwill, Acquired During Period	$ 1,900
Unregulated Energy \| ARM [Member]
Business Acquisition [Line Items]
Goodwill, Acquired During Period	$ 6,800

Acquisitions Purchase Price Allocation (Details) - USD ($) $ in Thousands		12 Months Ended
	Apr. 01, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned		$ 0	$ 0	$ 30,164
Goodwill		22,104	15,070
Payments to Acquire Businesses, Gross		$ 11,945	$ 0	20,930
Gatherco [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned	$ 30,200			30,164
Business Combination, Consideration Transferred				57,658
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				53,203
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	(6,800)			(6,806)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables				3,629
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Current Assets Income Taxes Receivable				3,163
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets				425
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets				67,226
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt	1,696			1,696
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent				13,409
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable				3,837
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other				745
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities				19,687
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net				47,539
Goodwill				10,119
Payments to Acquire Businesses, Gross	$ 27,500			27,494
Net [Member] \| Gatherco [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred				52,548
Gross [Member] \| Gatherco [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred				$ 59,354

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 180,403

$ 126,936

$ 125,084

$ 185,160

$ 141,874

$ 108,348

$ 102,342

$ 146,296

$ 617,583

$ 498,860

$ 459,244

180,403

126,936

125,084

185,160

141,874

108,348

102,342

146,296

617,583

498,860

459,244

Income Before Income taxes

23,263

14,239

13,666

34,676

21,819

10,156

15,742

36,380

85,843

84,096

77,758

Other income

(765)

(441)

293

Interest charges

12,645

10,639

10,006

72,433

73,016

68,045

Income taxes

14,309

28,341

26,905

26,101

$ 6,833

$ 6,046

$ 19,144

11,863

$ 4,416

$ 8,029

$ 20,367

58,124

44,675

41,140

36,599

32,159

29,972

191,103

169,376

195,261

1,417,434

1,229,219

1,417,434

1,229,219

Regulated Energy

73,160

69,851

60,985

28,554

25,677

24,195

159,011

139,994

98,372

1,121,673

986,752

1,121,673

986,752

Unregulated Energy

12,477

13,844

16,355

7,954

6,386

5,679

26,190

23,984

90,895

261,541

226,368

261,541

226,368

206

401

418

5,902

5,398

5,994

$ 34,220

$ 16,099

34,220

16,099

Other and eliminations

Operating Segments

617,583

498,860

459,244

Operating Segments | Regulated Energy

617,583

498,860

459,244

316,971

302,402

300,674

Operating Segments | Unregulated Energy

316,971

302,402

300,674

300,612

196,458

158,570

Intersegment Eliminations

300,612

196,458

158,570

^[1]

34,096

11,488

5,645

Intersegment Eliminations | Regulated Energy

^[1]

34,096

11,488

5,645

^[1]

9,339

3,287

1,228

Intersegment Eliminations | Unregulated Energy

^[1]

9,339

3,287

1,228

^[1]

23,983

7,321

3,537

Intersegment Eliminations | Other

^[1]

23,983

7,321

3,537

^[1]

774

880

Fair value adjustment for natural gas inventory designated as the hedged item

^[1]

$ 774

$ 880

[1]	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

Supplemental Cash Flow Disclosures - Cash Paid for Interest and Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Supplemental Cash Flow Disclosures Cash Paid For Interest And Income Taxes [Abstract]
Cash paid for interest	$ 12,420	$ 10,320	$ 9,500
Cash paid for income taxes	$ (4,114)	$ (5,308)	$ 11,076

Supplemental Cash Flow Disclosures - Non-Cash Investing and Financing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Supplemental Cash Flow Disclosures Noncash Investing And Financing Activities [Abstract]
Capital property and equipment acquired on account, but not paid as of December 31	$ 15,457	$ 9,791	$ 10,268
Retirement Savings Plan	0	777	690
Performance Incentive Plan	1,127	1,027	1,594
Capital Lease Obligation	2,070	3,471	4,824
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned	$ 0	$ 0	$ 30,164

Derivative Instruments - Additional Information (Detail) gal in Thousands, Mcf in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) $ / gal gal Mcf	Dec. 31, 2016 USD ($) $ / gal gal	Dec. 31, 2015 USD ($) $ / gal gal
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| Mcf	2,900
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 520
Energy Marketing Contract Liabilities, Current	6,247	$ 773
Accounts Payable Subject To Master Netting Arrangement	2,391	1,431
Derivative assets, at fair value	1,286	823
Unrealized Gain (Loss) on Derivatives	(3,195)	(45)	$ 474
Put Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal			2,500
Payment to purchase call options			$ 143
Cash Received On Derivative Settlement			$ 239
Propane Swap Agreement
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal			2,500
Cash Paid On Derivative Settlement			$ 484
Hedging Liability [Member] \| Natural Gas Swaps [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	(469)
Not Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets \| Propane Swap Agreement
Derivative [Line Items]
Derivative assets, at fair value	13	8
Not Designated as Hedging Instrument [Member] \| Mark-to-market energy liabilities \| Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	5,776	773
Derivatives designated as fair value hedges \| Mark To Market Energy Assets \| Natural Gas Futures [Member]
Derivative [Line Items]
Derivative assets, at fair value	92	113
Derivatives designated as fair value hedges \| Mark To Market Energy Assets \| Put Option
Derivative [Line Items]
Derivative assets, at fair value	0	9
Derivatives designated as fair value hedges \| Mark To Market Energy Assets \| Propane Swap Agreement
Derivative [Line Items]
Derivative assets, at fair value	1,181	693
Derivatives designated as fair value hedges \| Mark-to-market energy liabilities \| Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 469	$ 0
Put Option Strike Price 1 [Member] \| Put Option
Derivative [Line Items]
Strike price of put option \| $ / gal		0.4950
Put Option Strike Price 2 [Member] \| Put Option
Derivative [Line Items]
Strike price of put option \| $ / gal			0.4888
Put Option Strike Price 3 [Member] \| Put Option
Derivative [Line Items]
Strike price of put option \| $ / gal			0.4500
Put Option Strike Price 4 [Member] \| Put Option
Derivative [Line Items]
Strike price of put option \| $ / gal			0.4200
Strike Price 1 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements \| $ / gal			0.5200
Strike Price 2 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements \| $ / gal			0.5950
Sharp Energy Inc [Member] \| Put Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal		630
Strike price of put option \| $ / gal		0.5650
Payment to purchase call options		$ 33
PESCO [Member] \| Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| Mcf	17,200
2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal	4,900
2017 [Member] \| Natural Gas Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| Mcf	591
2017 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal	7,700
Derivative, Cash Received on Hedge	$ 440
Volume settled on hedges \| gal	1,470
2017 [Member] \| Derivatives designated as fair value hedges \| Mark-to-market energy liabilities \| Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 2	$ 0
2017 [Member] \| Strike Price 1 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements \| $ / gal	0.59
2016 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal	0
Derivative, Cash Received on Hedge	$ (663)
2016 [Member] \| Strike Price 1 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements \| $ / gal		0.5225
2016 [Member] \| Strike Price 2 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements \| $ / gal		0.5650
Other Comprehensive Income (Loss) \| Derivatives designated as fair value hedges \| Natural Gas Futures [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(1,476)	$ 222	$ 109
Other Comprehensive Income (Loss) \| Derivatives designated as fair value hedges \| Natural Gas Swaps [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	986	0	0
Other Comprehensive Income (Loss) \| Derivatives designated as fair value hedges \| Propane Swap Agreement
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	487	1,016	(323)
Cost of Sales [Member] \| Not Designated as Hedging Instrument [Member] \| Future [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(3,633)	(541)	0
Cost of Sales [Member] \| Not Designated as Hedging Instrument [Member] \| Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	8	7	18
Cost of Sales [Member] \| Derivatives designated as fair value hedges \| Natural Gas Swaps [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives		0	0
Cost of Sales [Member] \| Derivatives designated as fair value hedges \| Future [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives		345	0
Cost of Sales [Member] \| Derivatives designated as fair value hedges \| Call options
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0	(81)
Cost of Sales [Member] \| Derivatives designated as fair value hedges \| Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1,607	(364)	(120)
Inventories [Member] \| Not Designated as Hedging Instrument [Member] \| Natural Gas Swaps [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 1	$ 0	$ 0

Derivative Instruments Fair Value Hedges (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2016

USD ($)

^[1]

Fair Value Hedges [Abstract]

Commodity contracts

$ (233)

681

Total increase in purchased gas cost

448

Basis ineffectiveness

(83)

Timing ineffectiveness

531

Total ineffectiveness

$ 448

[1]	(1) There were no natural gas futures commodity contracts designated as fair value hedges in 2017.

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 1,286	$ 823
Energy Marketing Contract Liabilities, Current	6,247	773
Not Designated as Hedging Instrument [Member] \| Mark-to-market energy liabilities \| Natural Gas Futures [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	5,776	773
Not Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets \| Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	13	8
Designated as Hedging Instrument [Member] \| Mark-to-market energy liabilities \| Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	469	0
Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets \| Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	1,181	693
Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets \| Put Option
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	0	9
Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets \| Natural Gas Futures [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	92	113
2017 [Member] \| Designated as Hedging Instrument [Member] \| Mark-to-market energy liabilities \| Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 2	$ 0

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Derivative Instruments, Gain (Loss) [Line Items]

$ 6,247

$ 773

Revenue | Derivatives not designated as hedging instruments | Forward Contracts

(3,195)

(45)

$ 474

Derivative Instruments, Gain (Loss) [Line Items]

^[1]

112

(546)

426

Cost of Sales | Derivatives not designated as hedging instruments | Propane Swap Agreement

^[1]

(126)

Derivative Instruments, Gain (Loss) [Line Items]

Cost of Sales | Derivatives not designated as hedging instruments | Future [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Cost of Sales | Derivatives designated as fair value hedges | Put Or Call Option [Member]

(3,633)

(541)

Derivative Instruments, Gain (Loss) [Line Items]

Cost of Sales | Derivatives designated as fair value hedges | Call options

(9)

528

Derivative Instruments, Gain (Loss) [Line Items]

Cost of Sales | Derivatives designated as fair value hedges | Propane Swap Agreement

(81)

Derivative Instruments, Gain (Loss) [Line Items]

Cost of Sales | Derivatives designated as fair value hedges | Future [Member]

1,607

(364)

(120)

Derivative Instruments, Gain (Loss) [Line Items]

Propane Inventory | Derivatives designated as fair value hedges | Put Or Call Option [Member]

345

Derivative Instruments, Gain (Loss) [Line Items]

Propane Inventory | Derivatives designated as fair value hedges | Future [Member]

^[2]

Derivative Instruments, Gain (Loss) [Line Items]

Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Futures [Member]

(233)

Derivative Instruments, Gain (Loss) [Line Items]

Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Propane Swap Agreement

(1,476)

222

109

Derivative Instruments, Gain (Loss) [Line Items]

Mark To Market Energy Liabilities [Member] | Derivatives not designated as hedging instruments | Natural Gas Futures [Member]

487

1,016

$ (323)

Derivative Instruments, Gain (Loss) [Line Items]

Mark To Market Energy Liabilities [Member] | Derivatives designated as fair value hedges | Propane Swap Agreement

5,776

773

Derivative Instruments, Gain (Loss) [Line Items]

2017 [Member] | Mark To Market Energy Liabilities [Member] | Derivatives designated as fair value hedges | Propane Swap Agreement

469

Derivative Instruments, Gain (Loss) [Line Items]

$ 2

$ 0

[1]

All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our consolidated statements of income.

[2]

Derivative Instruments Accounts Receivable and Payable on a Gross and Net Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Offsetting Liabilities [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	$ 2,391	$ 1,431
Accounts Payable Subject To Master Netting Arrangement	2,391	1,431
Net [Member]
Offsetting Liabilities [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	5,892	1,333
Accounts Payable Subject To Master Netting Arrangement	14,252	3,904
Gross [Member]
Offsetting Liabilities [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	8,283	2,764
Accounts Payable Subject To Master Netting Arrangement	$ 16,643	$ 5,335

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract]
Long-term debt including current maturities	$ 205.2	$ 145.9
Fair value of long-term debt	$ 215.4	$ 161.5

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets:
Investments	$ 6,756	$ 4,902
Fair Value, Inputs, Level 1 [Member]
Assets:
Assets, Fair Value Disclosure	6,108	4,341
Fair Value, Inputs, Level 1 [Member] \| Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0	0
Significant Other Observable Inputs (Level 2)
Assets:
Assets, Fair Value Disclosure	1,286	823
Significant Other Observable Inputs (Level 2) \| Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	6,247	773
Significant Unobservable Inputs (Level 3)
Assets:
Assets, Fair Value Disclosure	648	561
Significant Unobservable Inputs (Level 3) \| Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0	0
Equity Securities [Member] \| Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	22	21
Equity Securities [Member] \| Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Equity Securities [Member] \| Significant Unobservable Inputs (Level 3)
Assets:
Investments	0	0
Guaranteed Income Fund [Member] \| Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	0	0
Guaranteed Income Fund [Member] \| Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Guaranteed Income Fund [Member] \| Significant Unobservable Inputs (Level 3)
Assets:
Investments	648	561
Investments - other \| Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	6,086	4,320
Investments - other \| Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Investments - other \| Significant Unobservable Inputs (Level 3)
Assets:
Investments	0	0
Investments [Member] \| Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	6,108	4,341
Investments [Member] \| Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Investments [Member] \| Significant Unobservable Inputs (Level 3)
Assets:
Investments	648	561
Mark-to-market energy assets, including put option \| Fair Value, Inputs, Level 1 [Member]
Assets:
Mark-to-market energy assets, including put option	0	0
Mark-to-market energy assets, including put option \| Significant Other Observable Inputs (Level 2)
Assets:
Mark-to-market energy assets, including put option	1,286	823
Mark-to-market energy assets, including put option \| Significant Unobservable Inputs (Level 3)
Assets:
Mark-to-market energy assets, including put option	0	0
Fair Value
Assets:
Assets, Fair Value Disclosure	8,042	5,725
Fair Value \| Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	6,247	773
Fair Value \| Equity Securities [Member]
Assets:
Investments	22	21
Fair Value \| Guaranteed Income Fund [Member]
Assets:
Investments	648	561
Fair Value \| Investments - other
Assets:
Investments	6,086	4,320
Fair Value \| Investments [Member]
Assets:
Investments	6,756	4,902
Fair Value \| Mark-to-market energy assets, including put option
Assets:
Mark-to-market energy assets, including put option	$ 1,286	$ 823

Fair Value of Financial Instruments Fair Value of Financial Instruments - Summary of Changes in Fair Value of Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 561	$ 279
Purchases and adjustments	79	123
Transfers/disbursements	53	(151)
Investment income	61	8
Ending Balance	$ 648	$ 561

Investments - Schedule of Investment (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Investment [Line Items]
Investments, at fair value	$ 6,756	$ 4,902
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investment [Line Items]
Investments, at fair value	6,734	4,881
Fair Value, Inputs, Level 1 [Member] \| Investments in equity securities
Investment [Line Items]
Investments, at fair value	$ 22	$ 21

Fair value portion of investment securities, including, but not limited to, marketable securities, derivative financial instruments, and investments accounted for under the equity method.

Goodwill and Other Intangible Assets - Additional Information (Detail) - USD ($) $ in Thousands		12 Months Ended
	Aug. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 02, 2013	Aug. 30, 2010	Oct. 31, 2009
Goodwill [Line Items]
Goodwill		$ 22,104	$ 15,070
Amortization of intangible assets		537	380	$ 367
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		790
Amortization of intangible assets, 2021		725
Amortization of intangible assets, 2022		471
Regulated Energy
Goodwill [Line Items]
Goodwill		3,353	3,353
Unregulated Energy
Goodwill [Line Items]
Goodwill		18,751	$ 11,717
Goodwill, Acquired During Period	$ 1,900
FPU \| Regulated Energy
Goodwill [Line Items]
Goodwill							$ 2,500
Indiantown Gas Company \| Regulated Energy
Goodwill [Line Items]
Goodwill						$ 170
Fort Meade
Goodwill [Line Items]
Goodwill					$ 714
Gatherco
Goodwill [Line Items]
Goodwill				$ 10,119
Gatherco \| Unregulated Energy
Goodwill [Line Items]
Goodwill		$ 10,100
ARM [Member] \| Unregulated Energy
Goodwill [Line Items]
Goodwill, Acquired During Period	$ 6,800
Anderson Gas
Goodwill [Line Items]
Amortized period of acquired intangible assets		6 years
Virginia LP Gas, Inc.
Goodwill [Line Items]
Amortized period of acquired intangible assets		7 years
Virginia LP Gas, Inc. \| Maximum
Goodwill [Line Items]
Amortized period of acquired intangible assets		40 years
Customer list \| Minimum
Goodwill [Line Items]
Amortized period of acquired intangible assets		7 years
Customer list \| Maximum
Goodwill [Line Items]
Amortized period of acquired intangible assets		12 years

Goodwill and Other Intangible Assets - Schedule of Carrying Value of Goodwill (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill	$ 22,104	$ 15,070
Regulated Energy
Goodwill [Line Items]
Goodwill	3,353	3,353
Unregulated Energy
Goodwill [Line Items]
Goodwill	$ 18,751	$ 11,717

Goodwill and Other Intangible Assets - Schedule of Carrying Value and Accumulated Amortization of Intangible Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 7,933	$ 4,552
Accumulated Amortization	3,247	2,709
Customer list
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	7,393	4,012
Accumulated Amortization	2,880	2,379
Non-Compete Agreements
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	270	270
Accumulated Amortization	175	146
Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	270	270
Accumulated Amortization	$ 192	$ 184

Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
Percentage of Net Operating Losses Limited upon Tax Reform Enactment		80.00%
Deferred tax asset related to state net operating loss carry-forwards		$ 1,586,000	$ 893,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%
Federal
Operating Loss Carryforwards [Line Items]
Federal net operating losses for income tax			$ 14,000,000
State
Operating Loss Carryforwards [Line Items]
Federal net operating losses for income tax		$ 34,200,000	$ 19,600,000
Federal tax reform [Member]
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Current Income Tax Expense

Federal

$ 2,803

$ (4,898)

$ 4,875

State

492

2,053

1,533

Total current income tax expense

(71)

(23)

3,224

(2,916)

6,385

Property, plant and equipment

^[1]

11,085

31,257

20,520

Total Income Tax Expense

14,309

28,341

26,905

8,314

31,062

21,205

Deferred gas costs

Pensions and other employee benefits

2,002

1,163

(1,539)

180

237

(84)

Net operating loss carryforwards

(1,148)

(572)

(556)

193

(9)

2,078

Reconciliation of Effective Income Tax Rates Continuing Operations

$ 1,544

$ (624)

$ (584)

[1]	(1)Includes $873,000, $2.1 million and $2.1 million of deferred state income taxes for the years 2017, 2016 and 2015, respectively.

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Federal income tax expense (1)

^[1]

$ 25,351

$ 22,759

$ 23,865

State income taxes, net of federal benefit

1,894

3,422

3,062

ESOP dividend deduction

(257)

(264)

(263)

Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount

(14,299)

Effective Income Tax Rate (2)

1,620

2,424

241

Total Income Tax Expense

$ 14,309

$ 28,341

$ 26,905

^[2]

19.75%

38.81%

39.54%

[1]	Federal income taxes were calculated at 35 percent for each year represented.
[2]	Effective tax rate for 2017 includes the impact of the revaluation of deferred tax assets and liabilities for our unregulated businesses due to implementation of the TCJA

Income Taxes - Schedule of Accumulated Deferred Income Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2015	Dec. 31, 2016
Disclosure Income Taxes Schedule Of Accumulated Deferred Income Tax Assets And Liabilities [Abstract]
Deferred State and Local Income Tax Expense (Benefit)	$ 900	$ 2,100
Deferred income tax liabilities:
Property, plant and equipment	133,581		$ 218,074
Acquisition adjustment	9,323		14,840
Loss on reacquired debt	153		442
Deferred gas costs	2,574		1,846
Other	5,422		6,375
Total deferred income tax liabilities	151,053		241,577
Deferred income tax assets:
Pension and other employee benefits	4,698		6,230
Environmental costs	1,744		2,592
Net operating loss carryforwards	1,625		952
Investment tax credit carryforwards	0		2,643
Self insurance	164		189
Storm reserve liability	717		1,131
Other	6,255		4,946
Total deferred income tax assets	15,203		18,683
Deferred Income Tax Liabilities, Net	$ 135,850		$ 222,894

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Income Taxes Summary Of Reconciliation Of Statutory Federal Tax And Effective Income Tax Rates [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%	35.00%

Income Taxes Federal Tax Reform (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Federal Tax Reform
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%
Percentage of Net Operating Losses Limited upon Tax Reform Enactment		80.00%
Reevaluation of Deferred Income Taxes due to tax reform		$ 98,500
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ (14,299)	$ 0	$ 0
Federal tax reform [Member]
Federal Tax Reform
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands		12 Months Ended
	Oct. 08, 2015	Dec. 31, 2017	Nov. 30, 2017	Mar. 31, 2017	May 31, 2016
Debt Instrument [Line Items]
Long-term debt maturities repayment of principal in next twelve months		$ 8,000
Long-term debt maturities repayment of principal in year two		10,600
Long-term debt maturities repayment of principal in year three		15,600
Long-term debt maturities repayment of principal in year four		13,600
Long-term debt maturities repayment of principal in year five		25,100
Long-term debt maturities repayment of principal in year five thereafter		132,300
Debt Instrument, Unused Borrowing Capacity, Amount		$ 80,000
Percentage of equity of total capitalization		40.00%
Fixed charge coverage ratio		1.2
Required net book value of regulated business assets, minimum percentage of consolidated total assets		50.00%
Maximum limit on payment of dividends		10.0
Cumulative consolidated net income base		$ 387,700
Cumulative net income with restrictions		178,000
Cumulative net income free of restrictions		209,700
Restricted net assets of consolidated subsidiaries		$ 43,000
Percentage of restricted net assets		9.00%
Uncollateralized Senior Note Due On Two Thousand Twenty Six [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage		5.68%
First Mortgage Bond Due On Two Thousand Twenty Two [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage		9.08%
Cumulative consolidated net income base		$ 142,600
Cumulative net income with restrictions		37,600
Cumulative net income free of restrictions		$ 104,900
Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage		6.43%
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage		3.73%
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage		3.88%
Uncollateralized Senior Note One Due On Two Thousand Seventeen [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage		6.64%
Uncollateralized Senior Note Due On Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage		5.50%
Uncollateralized Senior Note Due On Two Thousand Twenty Three [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage		5.93%
Notes Payable, Other Payables \| Shelf Notes
Debt Instrument [Line Items]
Face amount	$ 150,000				$ 70,000
Long-term debt, interest percentage					3.25%
Term	20 years
Florida Public Utilities Company [Member]
Debt Instrument [Line Items]
Cumulative net income with restrictions		$ 2,500
MetLife [Member] \| Notes Payable, Other Payables \| Shelf Notes
Debt Instrument [Line Items]
Face amount				$ 150,000
New York Life [Member] \| Notes Payable, Other Payables \| Shelf Notes
Debt Instrument [Line Items]
Face amount				$ 100,000
Series A [Member]
Debt Instrument [Line Items]
Face amount			$ 50,000
Long-term debt, interest percentage			3.48%
Series B [Member]
Debt Instrument [Line Items]
Face amount			$ 50,000
Long-term debt, interest percentage			3.58%

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt	$ 205,200	$ 145,900
Capital lease obligation	2,070	3,471
Less: debt issuance costs	(433)	(291)
Long-term Debt and Capital Lease Obligations	206,816	149,053
Less: current maturities	(9,421)	(12,099)
Total long-term debt, net of current maturities	197,395	136,954
9.08% bond, due June 1, 2022
Debt Instrument [Line Items]
Long-term Debt	7,982	7,978
6.64% note, due October 31, 2017
Debt Instrument [Line Items]
Long-term Debt	0	2,727
5.50% note, due October 12, 2020
Debt Instrument [Line Items]
Long-term Debt	6,000	8,000
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term Debt	18,000	21,000
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term Debt	26,100	29,000
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term Debt	7,000	7,000
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term Debt	20,000	20,000
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term Debt	50,000	50,000
3.25% note, due April 30, 2032 [Member]
Debt Instrument [Line Items]
Long-term Debt	70,000	0
Promissory note
Debt Instrument [Line Items]
Long-term Debt	$ 97	$ 168

Long-Term Debt - Outstanding Long-Term Debt (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2017
9.08% bond, due June 1, 2022
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Debt Instrument, Maturity Date	Jun. 01, 2022
6.64% note, due October 31, 2017
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.64%
Debt Instrument, Maturity Date	Oct. 31, 2017
5.50% note, due October 12, 2020
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.50%
Debt Instrument, Maturity Date	Oct. 12, 2020
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.93%
Debt Instrument, Maturity Date	Oct. 31, 2023
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.68%
Debt Instrument, Maturity Date	Jun. 30, 2026
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Debt Instrument, Maturity Date	May 02, 2028
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%
Debt Instrument, Maturity Date	Dec. 16, 2028
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
Debt Instrument, Maturity Date	May 15, 2029
Uncollateralized Senior Note Due on Two Thousand Thirty Two [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.25%
Debt Instrument, Maturity Date	Apr. 30, 2032

Short-Term Borrowing - Additional Information (Detail)	12 Months Ended
Short-Term Borrowing - Additional Information (Detail)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Nov. 30, 2017 USD ($)	Oct. 08, 2015 USD ($)
Short-term Debt [Line Items]
Short-term borrowings	$ 250,969,000	$ 209,871,000
Line of Credit Facility, Aggregate Borrowing Capacity	$ 370,000,000
Number Of Unsecured Bank Credit Facilities	5
Number Of Financial Institutions With Bank Credit Facilities	4
Line Of Available Credit Facility Borrowing Capacity	$ 220,000,000
ParticipatingLendersInTheRevolver	5
Short-term Debt, Weighted Average Interest Rate, at Point in Time	2.4246%	1.4269%
Line of Credit Facility, Commitment Fee Amount	$ 131,000	$ 145,000	$ 106,000
Ratio of Indebtedness to Net Capital	0.65
Uncommitted Line Of Credit Facility One [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 40,000,000	$ 150,000,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Aggregate Borrowing Capacity	$ 275,000,000
Committed Line of Credit Facility Two [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR rate, plus 1.00 percent
Line of Credit Facility, Aggregate Borrowing Capacity	$ 30,000,000
Short-term Revolving Line of Credit Facility [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	Lender's base rate plus 80 basis points
Line of Credit Facility, Aggregate Borrowing Capacity	$ 50,000,000
Committed Line of Credit Facility Three [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	Lender's base rate, plus 0.85 percent
Line of Credit Facility, Aggregate Borrowing Capacity	$ 45,000,000
Maximum \| Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Aggregate Borrowing Capacity	$ 350,000,000

Short-Term Borrowing Short-Term Borrowing - Schedule of Short-Term Debt (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Line of Credit Facility, Maximum Borrowing Capacity

$ 370,000

Line of Credit Facility, Remaining Borrowing Capacity

240,671

$ 201,311

129,329

Bank Overdrafts

^[1]

10,298

8,560

Short-term borrowing

250,969

209,871

Committed Line of Credit Facility One [Member]

Line of Credit Facility, Maximum Borrowing Capacity

$ 55,000

Oct. 28, 2018

Line of Credit Facility, Remaining Borrowing Capacity

$ 55,000

45,000

$ 0

Debt Instrument, Description of Variable Rate Basis

LIBOR rate, plus 1.00 percent

Short-term Revolving Line of Credit Facility [Member]

Line of Credit Facility, Maximum Borrowing Capacity

$ 50,000

Oct. 31, 2018

Debt Instrument, Description of Variable Rate Basis

$ 50,000

50,000

Lender's base rate plus 80 basis points

Committed Line of Credit Facility Three [Member]

Line of Credit Facility, Maximum Borrowing Capacity

$ 45,000

Oct. 31, 2018

Line of Credit Facility, Remaining Borrowing Capacity

$ 40,171

35,000

$ 4,829

Debt Instrument, Description of Variable Rate Basis

Lender's base rate, plus 0.85 percent

Committed Line of Credit Facility Five [Member]

Line of Credit Facility, Maximum Borrowing Capacity

$ 40,000

Line of Credit Facility, Remaining Borrowing Capacity

Oct. 31, 2018

$ 40,000

Debt Instrument, Description of Variable Rate Basis

Lender's base rate, plus 0.85 percent

Committed Line of Credit Facility Four [Member]

Line of Credit Facility, Maximum Borrowing Capacity

^[2]

$ 150,000

Oct. 08, 2020

Line of Credit Facility, Remaining Borrowing Capacity

^[2]

$ 75,000

50,000

^[2]

$ 75,000

Debt Instrument, Description of Variable Rate Basis

LIBOR rate, plus 1.00 percent

Committed Line of Credit Facility Two [Member]

Line of Credit Facility, Maximum Borrowing Capacity

$ 30,000

Oct. 31, 2018

Line of Credit Facility, Remaining Borrowing Capacity

$ 20,500

$ 21,311

$ 9,500

Debt Instrument, Description of Variable Rate Basis

LIBOR rate, plus 1.00 percent

[1]	If presented, these book overdrafts would be funded through the bank revolving credit facilities.
[2]	This committed revolving credit facility includes a restriction that our short-term borrowings, excluding any borrowings under the committed revolving credit facility, shall not exceed $200.0 million.

Lease Obligations - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsequent Event [Line Items]
Rent expense related to operating leases	$ 3,600,000	$ 2,500,000	$ 1,700,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	2,700,000
Operating Leases, Future Minimum Payments, Due in Two Years	1,700,000
Operating Leases, Future Minimum Payments, Due in Three Years	1,000,000
Operating Leases, Future Minimum Payments, Due in Four Years	815,000
Operating Leases, Future Minimum Payments, Due in Five Years	654,000
Future minimum payments under current lease agreements, thereafter	3,700,000
Future minimum payments under current lease agreements, total	10,600,000
Payments to Acquire Capital Leases	1,500,000
Capital Leases, Future Minimum Payments Due, Next Twelve Months	1,500,000
Capital Leases, Future Minimum Payments Due in Five Years	625,000
Capital Leases, Future Minimum Payments Due	$ 2,100,000

Stockholders' Equity Additional Details (Details) - USD ($)

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Stockholders' Equity Attributable to Parent [Abstract]

Preferred Stock, Shares Authorized

2,000,000

Preferred Stock, Par or Stated Value Per Share

$ 0.01

Stock Issued During Period, Value, Other

960,488

$ 62.26

Proceeds from issuance of common stock, net of expenses

$ (10,000)

^[1]

$ 57,360,000

^[1]

$ 0

[1]	On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million.

Stockholders' Equity Accumulated Other comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ (4,878)	$ (5,840)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	440	508
Amounts reclassified from accumulated other comprehensive income/(loss)	166	454
Net current-period other comprehensive income/(loss)	606	962
Accumulated other comprehensive loss at end of period	(4,272)	(4,878)
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(5,360)	(5,580)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	281	(254)
Amounts reclassified from accumulated other comprehensive income/(loss)	336	474
Net current-period other comprehensive income/(loss)	617	220
Accumulated other comprehensive loss at end of period	(4,743)	(5,360)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	482	(260)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	159	762
Amounts reclassified from accumulated other comprehensive income/(loss)	(170)	(20)
Net current-period other comprehensive income/(loss)	(11)	742
Accumulated other comprehensive loss at end of period	$ 471	$ 482

Stockholders' Equity Accumulated Other Comprehensive Income (loss) - Reclassifications of Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Amortization of defined benefit pension and postretirement plan items:

Income tax benefit

$ (14,309)

$ (28,341)

$ (26,905)

Reclassification out of Accumulated Other Comprehensive Income [Member]

Amortization of defined benefit pension and postretirement plan items:

Net of tax

(166)

(454)

(472)

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

Amortization of defined benefit pension and postretirement plan items:

Prior service cost

^[1]

Net gain

^[1]

(636)

(871)

(650)

Total before income taxes

(559)

(794)

(582)

Income tax benefit

223

320

233

Net of tax

(336)

(474)

(349)

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]

Amortization of defined benefit pension and postretirement plan items:

Total before income taxes

329

(206)

Income tax benefit

(159)

(3)

Net of tax

170

(123)

Propane Swap Agreement [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]

Amortization of defined benefit pension and postretirement plan items:

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax

^[2]

1,607

(322)

(120)

Natural Gas Futures [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]

Amortization of defined benefit pension and postretirement plan items:

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax

^[2]

(456)

345

(31)

Natural Gas Swaps [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]

Amortization of defined benefit pension and postretirement plan items:

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax

^[2]

$ (822)

$ 0

$ (55)

[1]	These amounts are included in the computation of net periodic benefits. See Note 16, Employee Benefit Plans, for additional details.
[2]	These amounts are included in the effects of gains and losses from derivative instruments. See Note 7, Derivative Instruments, for additional details.

Stockholders' Equity Shareholder Rates and Preferred Stock (Details)	12 Months Ended
	Dec. 31, 2016 USD ($) $ / shares	Dec. 31, 2017 $ / shares $ / unit
Shareholder Rates and Preferred Stock [Abstract]
Stock Issued During Period, Value, Other \| $	$ 62.26
Preferred Stock, Par or Stated Value Per Share \| $ / shares	$ 0.01	$ 0.01
Preferred Stock, Price Per Unit \| $ / unit		70

Employee Benefit Plans - Additional Information (Detail)
$ in Thousands

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2017

plan

Defined Benefit Plan, Number of Plans

Income tax benefits

$ 3,100

1,326

Expected Amortization Of Pre Merger Regulatory Asset

23,347

$ 0

One-percentage point increase in health care inflation rate, accumulated postretirement benefit obligation

277

One-percentage point increase in health care inflation rate, service cost and interest cost components

One-percentage point decrease in health care inflation rate, accumulated postretirement benefit obligation

215

One-percentage point decrease in health care inflation rate, service cost and interest cost components

$ 8

Required period of service for eligibility

3 months

Percentage of eligible participants contribution to the plan

100.00%

Maximum percentage of eligible compensation

6.00%

Employer matching contribution vested, percentage

100.00%

Deferred Compensation Arrangement with Individual, Requisite Service Period

2 years

Employee contribution age

55 years

Deferral rate

80.00%

Deferred Compensation Employer Matching Contribution Rate

6.00%

Number Of Years to Collect Benefits

20 years

Deferral rate increase, minimum

1.00%

Employer contributions to pension plan

$ 5,000

$ 4,500

$ 4,100

Shares reserved to fund future contributions | shares

831,183

Investments, Fair Value Disclosure

4,902

6,756

Deferred compensation obligation

2,416

3,395

Minimum

Maximum percentage of eligible compensation

3.00%

Maximum

Number Of Years to Collect Benefits

15 years

3,629

Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year

(2,687)

(2,093)

359

^[1]

687

Defined Benefit Plan, Amortization of Transition Asset (Obligation)

1,300

2,100

1,304

18,787

Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year

(20,560)

(16,268)

1,500

^[1]

3,078

733

Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year

(2,428)

151

^[2]

151

Medical

Health care inflation rate

5.00%

166

Expected Amortization Of Pre Merger Regulatory Asset

(1,132)

(1,128)

$ 0

Health care inflation rate

6.00%

Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year

^[2]

Health care inflation rate

(1,349)

(1,287)

5.00%

Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year

Rabbi Trust Associated With Deferred Compensation Plan [Member]

^[2]

Investments, Fair Value Disclosure

$ 4,881

$ 6,734

Subsequent Event

Maximum percentage of eligible compensation

10.00%

[1]	The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.
[2]	Benefit payments are expected to be paid out of our general funds.

Employee Benefit Plans - Schedule of Funded Status of Benefit Obligation and Plan Assets (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 89

$ 91

51,940

57,746

51,940

11,355

11,501

402

421

407

454

330

Effect of settlement

(433)

(768)

(464)

11,443

11,355

11,501

Actual return on plan assets

8,668

8,752

1,144

424

306

389

(768)

(464)

Effect of settlement

(433)

9,350

8,668

$ 8,752

(2,093)

(2,687)

$ (2,093)

$ (2,687)

3.50%

3.75%

6.00%

$ 63,832

$ 64,435

2,482

2,525

$ 2,504

1,199

(216)

(2,849)

(2,912)

64,664

63,832

64,435

Actual return on plan assets

43,272

42,207

6,025

2,343

1,948

1,634

(2,849)

(2,912)

48,396

43,272

$ 42,207

(16,268)

(20,560)

$ (16,268)

$ (20,560)

3.75%

4.00%

6.50%

7.00%

$ 2,428

$ 2,510

(21)

(152)

2,428

$ 2,510

152

(152)

(2,428)

$ (2,428)

3.50%

3.75%

$ 1,132

$ 1,153

118

(235)

(174)

1,128

1,132

1,153

^[1]

117

118

(235)

(174)

(1,128)

(1,132)

$ (1,128)

$ (1,132)

3.50%

3.75%

$ 1,349

$ 1,444

(48)

(41)

(112)

(173)

1,287

1,349

1,444

^[1]

109

(112)

(173)

$ 0

(1,287)

(1,349)

$ (1,287)

$ (1,349)

3.75%

4.00%

[1]	The Chesapeake Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

Employee Benefit Plans - Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

$ (601)

22,622

22,021

7,852

14,169

22,021

1,326

23,347

3,629

3,629

^[1]

3,629

3,629

3,629

17,483

17,483

^[1]

3,322

14,161

17,483

1,304

18,787

733

733

^[1]

733

733

733

(601)

767

166

^[1]

166

166

166

^[1]

$ 30

$ 32

[1]	The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2017 is net of income tax benefits of $3.1 million.

Employee Benefit Plans - Schedule of Assets by Investment Type (Detail)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Chesapeake Pension Plan
Asset Category
Percentage of assets by investment type	100.00%	100.00%	100.00%
Chesapeake Pension Plan \| Investments in equity securities
Asset Category
Percentage of assets by investment type	52.70%	52.93%	48.01%
Chesapeake Pension Plan \| Debt securities
Asset Category
Percentage of assets by investment type	37.79%	37.64%	39.62%
Chesapeake Pension Plan \| Other
Asset Category
Percentage of assets by investment type	9.51%	9.43%	12.37%
FPU Pension Plan
Asset Category
Percentage of assets by investment type	100.00%	100.00%	100.00%
FPU Pension Plan \| Investments in equity securities
Asset Category
Percentage of assets by investment type	55.17%	53.18%	48.56%
FPU Pension Plan \| Debt securities
Asset Category
Percentage of assets by investment type	36.56%	37.74%	41.74%
FPU Pension Plan \| Other
Asset Category
Percentage of assets by investment type	8.27%	9.08%	9.70%

Employee Benefit Plans - Schedule of Asset Allocation Strategy (Detail)	Dec. 31, 2017
Minimum \| Domestic Equities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	14.00%
Minimum \| Foreign Equities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	13.00%
Minimum \| Fixed Income
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	26.00%
Minimum \| Alternative Strategies
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	6.00%
Minimum \| Diversifying Assets
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	7.00%
Minimum \| Cash
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%
Maximum \| Domestic Equities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	32.00%
Maximum \| Foreign Equities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	25.00%
Maximum \| Fixed Income
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	40.00%
Maximum \| Alternative Strategies
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	14.00%
Maximum \| Diversifying Assets
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	19.00%
Maximum \| Cash
Schedule of Trading Securities and Other Trading Assets [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	5.00%

Employee Benefit Plans - Component of Net Periodic Pension Cost (Benefit) (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Amortization of prior service cost

$ 89

$ 91

Expected Amortization Of Pre Merger Regulatory Asset

769

$ 176

$ 178

$ 199

3.75%

3.50%

$ 57,746

$ 51,940

Amortization of prior service cost

$ 42

(77)

Expected Amortization Of Pre Merger Regulatory Asset

$ 17

$ 30

$ 37

Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant

3.75%

3.50%

$ 118

$ 90

Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)

Defined Benefit Plan, Benefit Obligation, Benefits Paid

(235)

(174)

Defined Benefit Plan, Plan Assets, Contributions by Employer

$ 0

^[1]

117

Defined Benefit Plan, Plan Assets, Contributions by Plan Participant

118

(235)

(174)

Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits

(1,128)

(1,132)

$ 1,128

$ 1,132

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

3.50%

3.75%

Amortization of prior service cost

$ 50

$ 55

$ 58

$ 63

$ 65

Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant

4.00%

3.75%

$ 48

$ 64

Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)

(48)

(41)

Defined Benefit Plan, Benefit Obligation, Benefits Paid

(112)

(173)

Defined Benefit Plan, Plan Assets, Contributions by Employer

$ 0

^[1]

109

Defined Benefit Plan, Plan Assets, Contributions by Plan Participant

(112)

(173)

Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits

(1,287)

(1,349)

$ 1,287

$ 1,349

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

3.75%

4.00%

$ 89

$ 91

Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)

(21)

Defined Benefit Plan, Benefit Obligation, Benefits Paid

(152)

Defined Benefit Plan, Plan Assets, Contributions by Employer

152

(152)

Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits

(2,428)

$ 2,428

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

3.50%

3.75%

Expected return on assets

$ 402

$ 421

407

(495)

(501)

(530)

Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement

399

459

392

161

306

540

269

$ 306

$ 540

$ 269

3.75%

3.50%

Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)

6.00%

$ 454

$ 330

Defined Benefit Plan, Benefit Obligation, Benefits Paid

(768)

(464)

Defined Benefit Plan, Plan Assets, Contributions by Employer

9,350

8,668

$ 8,752

306

389

(768)

(464)

Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits

(2,093)

(2,687)

$ 2,093

$ 2,687

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

3.50%

3.75%

Expected return on assets

$ 2,482

$ 2,525

2,504

(2,779)

(2,702)

(3,107)

513

519

456

216

342

(147)

761

$ 977

$ 1,103

$ 614

4.00%

3.75%

Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)

6.50%

7.00%

$ 1,199

$ (216)

Defined Benefit Plan, Benefit Obligation, Benefits Paid

(2,849)

(2,912)

Defined Benefit Plan, Plan Assets, Contributions by Employer

48,396

43,272

$ 42,207

1,948

1,634

(2,849)

(2,912)

Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits

(16,268)

(20,560)

$ 16,268

$ 20,560

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

3.75%

4.00%

[1]	The Chesapeake Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

Employee Benefit Plans - Amounts in Accumulated Other Comprehensive Income/Loss and Regulatory Asset (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	$ (77)
Net loss	944
Amortization of pre-merger regulatory asset	769
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	351
Amortization of pre-merger regulatory asset	0	$ 0	$ 0
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	434
Amortization of pre-merger regulatory asset	761	761	761
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	101
Amortization of pre-merger regulatory asset	0
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	(77)
Net loss	58
Amortization of pre-merger regulatory asset	0
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	0
Amortization of pre-merger regulatory asset	$ 8	$ 8	$ 8

Employee Benefit Plans - Schedule of Estimated Future Benefit Payments (Detail)
$ in Thousands

Dec. 31, 2017

USD ($)

Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]

2017

$ 687

^[1]

2018

490

^[1]

2019

675

^[1]

2020

779

^[1]

2021

592

^[1]

5,278

^[1]

Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]

2017

3,078

^[1]

2018

3,207

^[1]

2019

3,304

^[1]

2020

3,362

^[1]

2021

3,536

^[1]

18,608

^[1]

Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]

2017

151

^[2]

2018

150

^[2]

2019

149

^[2]

2020

385

^[2]

2021

146

^[2]

738

^[2]

Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]

^[2]

^[2]

^[2]

^[2]

^[2]

290

^[2]

Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]

^[2]

^[2]

^[2]

^[2]

^[2]

Rates and Other Regulatory Activities [Line Items]

$ 404

^[2]

[1]	The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.
[2]	Benefit payments are expected to be paid out of our general funds.

Employee Benefit Plans Employee benefit plans phantoms (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Funded status	$ (2,093)	$ (2,687)

Share-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense related to the awards to Non employee directors	$ 2,278
Shares reserved for issuance	831,183
Number of Shares, Granted	835
Payments of employees' tax obligations to taxing authorities	$ 692	$ 770	$ 592
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 71.80	$ 62.90
Amortization of expense equally over a service period	1 year
Unrecognized compensation expense related to the awards to Non employee directors	$ 179
Number of Shares, Granted	7,515	8,577
Weighted average grant-date fair value of awards granted		$ 62.90	$ 45.54
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 38.88	$ 31.79
Number of Shares, Granted	52,355	46,571
Number of shares withheld	10,269	12,031	12,620
Payments of employees' tax obligations to taxing authorities	$ 692	$ 770	$ 592
Weighted average grant-date fair value of awards granted	$ 63.42	$ 67.90	$ 47.65
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	$ 10,400	$ 7,700	$ 6,300
Additional Paid-In Capital [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustments to Additional Paid in Capital, Income Tax Benefit from Share-based Compensation	$ (349)	$ 285	$ 297
Stock and Incentive Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	509,202

Share-Based Compensation Plans - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 2,490	$ 2,367	$ 1,937
Less: tax benefit	(1,003)	(952)	(780)
Share-Based Compensation amounts included in net income	1,487	1,415	1,157
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	2,278
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	540	580	640
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	179
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	10,400	7,700	6,300
Total compensation expense	$ 1,950	$ 1,787	$ 1,297

Share-Based Compensation Plans - Summary of Stock Activity Non-employee directors (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	835
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance	0	0
Number of Shares, Granted	7,515	8,577
Number of Shares, Vested	(7,515)	(8,577)
Number of Shares, Outstanding Ending Balance	0	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value, Outstanding Beginning Balance	$ 0.00	$ 0.00
Weighted Average Grant Date Fair Value, Granted		62.90	$ 45.54
Weighted Average Grant Date Fair Value, Vested	71.80	62.90
Weighted Average Grant Date Fair Value, Outstanding Ending Balance	$ 0.00	$ 0.00	$ 0.00

Share-Based Compensation Plans - Summary of Stock Activity under SICP - Key employees (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	835
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance	115,091	110,398
Number of Shares, Granted	52,355	46,571
Number of Shares, Vested	(32,926)	(39,553)
Number of Shares, Expired	1,878	(2,325)
Number of Shares, Outstanding Ending Balance	132,642	115,091	110,398
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value, Outstanding Beginning Balance	$ 51.85	$ 38.34
Weighted Average Grant Date Fair Value, Granted	63.42	67.90	$ 47.65
Weighted Average Grant Date Fair Value, Vested	38.88	31.79
Weighted Average Grant Date Fair Value, Expired	39.97	42.25
Weighted Average Grant Date Fair Value, Outstanding Ending Balance	$ 53.00	$ 51.85	$ 38.34

Rates and Other Regulatory Activities - Additional Information (Detail) $ in Thousands		1 Months Ended	3 Months Ended								6 Months Ended	12 Months Ended
	Feb. 02, 2017 USD ($)	Jan. 31, 2017 USD ($)	Dec. 31, 2017 USD ($) mi	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($) mi	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Jun. 30, 2017 USD ($) mi	Dec. 31, 2017 USD ($) dekatherm / d unit mi in	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Rates and Other Regulatory Activities [Line Items]
Restricted Payment			$ 178,000									$ 178,000
Regulatory Assets			86,505				$ 84,497					86,505	$ 84,497
Revenues			180,403	$ 126,936	$ 125,084	$ 185,160	$ 141,874	$ 108,348	$ 102,342	$ 146,296		617,583	$ 498,860	$ 459,244
Electric distribution
Rates and Other Regulatory Activities [Line Items]
Amount of Regulatory Costs Not yet Approved			$ 15,200									15,200
DELAWARE
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount												$ 2,250
Florida Public Utilities Company [Member] \| New Smyrna Beach [Member]
Rates and Other Regulatory Activities [Line Items]
Length of Natural Gas Pipeline \| mi												14.0
Florida Public Utilities Company [Member] \| Northwest Florida Expansion [Member]
Rates and Other Regulatory Activities [Line Items]
Lateral Diameter Of Pipeline To Be Installed \| in												8
Diameter of pipe to be installed in the future \| mi			12.0									12.0
Florida
Rates and Other Regulatory Activities [Line Items]
Estimated capital costs of project	$ 59,800
Number Of Years In Project	5 years
Florida \| New Smyrna Beach [Member]
Rates and Other Regulatory Activities [Line Items]
number of customers												2
Florida \| Belvedere Project [Member]
Rates and Other Regulatory Activities [Line Items]
Length of Natural Gas Pipeline \| mi												2.0
Eastern Shore Gas Company
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount												$ 9,800
Cost of Services		$ 60,000
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 18,900
Public Utilities, Requested Return on Equity, Percentage		13.75%
Number of Months Rates Suspended		5 months
Increase in Revenue Recognized Due to Motion Rate in Effect			$ 3,700									3,700
Eastern Shore Gas Company \| White Oak Lateral Mainline Expansion [Member]
Rates and Other Regulatory Activities [Line Items]
Estimated capital costs of project												$ 42,000
Lateral Diameter Of Pipeline To Be Installed \| in												16
Volume The Expansion Project Is Expected to Provide \| dekatherm / d												45,000
Miles Of Natural Gas Pipeline \| mi					5.4						5.4
Eastern Shore Gas Company \| System Reliability Project [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Pipeline Miles \| mi			10.1									10.1
Estimated capital costs of project											$ 38,000
Lateral Diameter Of Pipeline To Be Installed \| in												16
Eastern Shore Gas Company \| 2017 Expansion Project [Member]
Rates and Other Regulatory Activities [Line Items]
firm natural gas transportation deliverability \| dekatherm / d												61,162
Additional Firm Natural Gas Transportation Deliverability \| dekatherm / d												52,500
Number of Pipeline Miles \| mi			23									23
Estimated capital costs of project												$ 117,000
Miles Of Natural Gas Pipeline \| mi			17									17
Pressure Control Stations											2
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Restricted Payment			$ 2,500									$ 2,500
Business Acquisition Premium Paid			$ 34,200									$ 34,200
Subscribers [Member] \| Eastern Shore Gas Company \| 2017 Expansion Project [Member]
Rates and Other Regulatory Activities [Line Items]
number of customers												7
Number of affiliates \| unit												3
12 inches [Member] \| Florida Public Utilities Company [Member] \| Northwest Florida Expansion [Member]
Rates and Other Regulatory Activities [Line Items]
Length of Natural Gas Pipeline \| mi												33.0
8 inches [Member] \| Florida Public Utilities Company [Member] \| Northwest Florida Expansion [Member]
Rates and Other Regulatory Activities [Line Items]
Length of Natural Gas Pipeline \| mi												8.0

Rates and Other Regulatory Activities Regulatory Assets and Liabilities (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

$ 86,505

$ 84,497

Deferred Federal Income Tax Expense (Benefit)

147,463

44,355

^[1]

98,492

Self Insured Liabilities [Member]

Rates and Other Regulatory Activities [Line Items]

Overrecovered Gas And Fuel Costs [Member]

^[2]

1,013

987

Rates and Other Regulatory Activities [Line Items]

Rates and Other Regulatory Activities [Line Items]

^[3]

2,048

808

Storm Reserve [Member]

Accrued asset removal cost

^[2]

669

2,310

Rates and Other Regulatory Activities [Line Items]

Other Regulatory Liability [Member]

^[4]

40,948

39,826

Rates and Other Regulatory Activities [Line Items]

Underrecovered Gas And Fuel Costs [Member]

2,048

424

Rates and Other Regulatory Activities [Line Items]

Under-recovered GRIP Revenue [Member]

^[3]

9,869

5,703

Rates and Other Regulatory Activities [Line Items]

^[5]

164

1,469

Deferred Post Retirement Benefits [Member]

^[5]

2,245

Rates and Other Regulatory Activities [Line Items]

Deferred Conversion And Development Costs [Member]

^[6]

15,498

18,379

Rates and Other Regulatory Activities [Line Items]

Environmental Regulatory Assets And Expenditures [Member]

^[3]

11,735

8,051

Rates and Other Regulatory Activities [Line Items]

Acquisition Adjustment [Member]

^[7]

3,222

3,694

Rates and Other Regulatory Activities [Line Items]

Loss on Reacquired Debt [Member]

^[8]

39,992

41,864

Rates and Other Regulatory Activities [Line Items]

Other Regulatory Asset [Member]

^[9]

1,031

1,145

Rates and Other Regulatory Activities [Line Items]

Florida Public Utilities Company [Member]

4,994

$ 4,192

Rates and Other Regulatory Activities [Line Items]

Business Acquisition Premium Paid

34,200

Indiantown Gas Company

Rates and Other Regulatory Activities [Line Items]

Business Acquisition Premium Paid

746