Beginning Balances (shares) at Dec. 31, 2017

$ 0.3250

^[1],[2]

16,344,442

Beginning Balances at Dec. 31, 2017

$ 486,294

^[2]

$ 7,955

^[2]

$ 253,470

$ 229,141

$ (4,272)

$ 3,395

$ (3,395)

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

New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification

26,854

(1,498)

Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect

907

(907)

(1,694)

Retirement savings plan and dividend reinvestment plan (shares)

(5,380)

Dividend reinvestment plan

(1)

$ 0

(1)

^[3],[4]

19,350

^[3],[4]

666

$ 9

657

Ending Balances (shares) at Mar. 31, 2018

178

(178)

^[2]

16,363,792

Ending Balances at Mar. 31, 2018

505,241

^[2]

$ 7,964

^[2]

254,126

250,024

(6,873)

3,573

(3,573)

Beginning Balances (shares) at Dec. 31, 2017

^[1],[2]

16,344,442

Beginning Balances at Dec. 31, 2017

486,294

^[2]

$ 7,955

^[2]

253,470

229,141

(4,272)

3,395

(3,395)

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

Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect

33,241

(907)

Ending Balances (shares) at Jun. 30, 2018

(539)

^[1],[2]

16,378,545

Ending Balances at Jun. 30, 2018

$ 507,986

^[2]

$ 7,971

^[2]

255,356

250,377

(5,718)

3,782

(3,782)

Beginning Balances (shares) at Mar. 31, 2018

$ 0.3700

^[2]

16,363,792

Beginning Balances at Mar. 31, 2018

$ 505,241

^[2]

$ 7,964

^[2]

254,126

250,024

(6,873)

3,573

(3,573)

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

6,387

1,155

Dividend reinvestment plan

(6,034)

(1)

^[3],[4]

14,753

^[3],[4]

1,238

$ 7

1,231

Ending Balances (shares) at Jun. 30, 2018

209

(209)

^[1],[2]

16,378,545

Ending Balances at Jun. 30, 2018

$ 507,986

^[2]

$ 7,971

^[2]

255,356

250,377

(5,718)

3,782

(3,782)

Preferred Stock, Shares Authorized

2,000,000

Preferred Stock, Par or Stated Value Per Share

$ 0.01

Beginning Balances (shares) at Dec. 31, 2018

$ 0.3700

^[1],[2]

16,378,545

Beginning Balances at Dec. 31, 2018

$ 518,439

^[2]

$ 7,971

^[2]

255,651

261,530

(6,713)

3,854

(3,854)

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

Prior Period Reclassification Adjustment

28,664

115

(115)

3,089

Stock Issued During Period, Shares, Dividend Reinvestment Plan

(6,198)

Stock Issued During Period, Value, Dividend Reinvestment Plan

(1)

$ 0

(1)

^[3],[4]

18,472

^[3],[4]

(334)

$ 9

(343)

Ending Balances (shares) at Mar. 31, 2019

522

(522)

^[2]

16,397,017

Ending Balances at Mar. 31, 2019

543,659

^[2]

$ 7,980

^[2]

255,307

284,111

(3,739)

4,376

(4,376)

Beginning Balances (shares) at Dec. 31, 2018

^[1],[2]

16,378,545

Beginning Balances at Dec. 31, 2018

518,439

^[2]

$ 7,971

^[2]

255,651

261,530

(6,713)

3,854

(3,854)

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

Prior Period Reclassification Adjustment

36,968

(115)

Ending Balances (shares) at Jun. 30, 2019

1,081

^[1],[2]

16,403,776

Ending Balances at Jun. 30, 2019

$ 544,384

^[2]

$ 7,984

^[2]

256,385

285,762

(5,747)

4,694

(4,694)

Beginning Balances (shares) at Mar. 31, 2019

$ 0.4050

^[2]

16,397,017

Beginning Balances at Mar. 31, 2019

$ 543,659

^[2]

$ 7,980

^[2]

255,307

284,111

(3,739)

4,376

(4,376)

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

8,304

(2,008)

Stock Issued During Period, Value, Dividend Reinvestment Plan

(6,653)

(1)

^[3],[4]

6,759

^[3],[4]

1,083

$ 4

1,079

Ending Balances (shares) at Jun. 30, 2019

318

(318)

^[1],[2]

16,403,776

Ending Balances at Jun. 30, 2019

$ 544,384

^[2]

$ 7,984

^[2]

$ 256,385

$ 285,762

$ (5,747)

$ 4,694

$ (4,694)

Preferred Stock, Shares Authorized

2,000,000

Preferred Stock, Par or Stated Value Per Share

$ 0.01

[1]	Includes 105,409 shares at June 30, 2019, 97,053 shares at December 31, 2018, 96,204 shares at June 30, 2018 and 90,961 shares at December 31, 2017, 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 have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the statements of stockholders’ equity.
[3]	The shares issued under the SICP are net of shares withheld for employee taxes. For the three months ended June 30, 2018, we withheld 6,482 shares for employee taxes. We did not withhold any shares for employee taxes for the three months ended June 30, 2019. For the six months ended June 30, 2019 and 2018, we withheld 7,635 and 16,918 shares, respectively, for employee taxes.
[4]	Includes amounts for shares issued for directors’ compensation.

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (Unaudited) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Dividend declared (in dollars per share)	$ 0.4050	$ 0.3700
Deferred compensation plan held Rabbi Trust (shares)	105,409	96,204	105,409	96,204	97,053	90,961
Preferred Stock, Shares Authorized	2,000,000		2,000,000		2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01		$ 0.01		$ 0.01
Shares issued under the performance incentive plan withheld for employee taxes (shares)	6,482		7,635	16,918

Summary of Accounting Policies

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Summary of Accounting Policies

Basis of Presentation

References in this document to the “Company,” “Chesapeake Utilities,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2018. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.

Where necessary to improve comparability, prior period amounts have been changed to conform to current period presentation.

Marlin Gas Transport and Ohl Fuel Oil Acquisitions

In December 2018, Marlin Gas Services acquired certain operating assets of Marlin Gas Transport. The acquisition allows us to offer solutions to supply interruption scenarios and other situations where pipeline supplies are unavailable or inadequate to meet customer requirements.

In December 2018, Sharp acquired certain propane operating assets and customers of R. F. Ohl Fuel Oil, Inc. ("Ohl"), which provides propane distribution service to approximately 2,500 residential and commercial customers in Pennsylvania.

We initially accounted for the purchases of the operating assets of Marlin Gas Transport and Ohl, which totaled approximately $18.4 million, as business combinations within our Unregulated Energy segment. Goodwill of $4.8 million, related to the Marlin Gas Transport acquisition, and $1.5 million, associated with the Ohl acquisition, were initially recorded at the close of these transactions. In the second quarter of 2019, we recorded a reduction to the purchase price for Ohl of $0.2 million upon completing our inspection of the assets purchased. The purchase price adjustment was recorded as a reduction in our property, plant and equipment balance. The amounts recorded in conjunction with these acquisitions are preliminary and subject to adjustment based on additional valuations performed during the measurement period. Due to the timing of these acquisitions, the revenue and operating income from these acquisitions in 2018 were immaterial. For the quarter and six months ended June 30, 2019, these acquisitions generated the following operating revenue and income:



	Three Months Ended June 30, 2019					Six Months Ended June 30, 2019
	Operating Revenue		Operating Income			Operating Revenue		Operating Income
(in thousands)
Marlin Gas Services	$	1,108	$	48		$	3,541	$	1,423
Ohl propane acquisition	$	174	$	(61	)	$	997	$	212

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a right of use model that requires a lessee to recognize a right of use asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; ASU No. 2018-11, Targeted Improvements; and ASU No. 2019-01, Codification Improvements. We adopted ASU 2016-02 and the related amendments on January 1, 2019, and used

the optional transition method for all existing leases. The optional transition method enabled us to adopt the new standard as of the beginning of the period of adoption and did not require restatement of prior period financial information. As a result, prior period financial information was not recast and continues to be reported under the accounting guidance effective during those periods.

At adoption, we elected the following practical expedients: (1) the ‘package of practical expedients,’ pursuant to which we did not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs, (2) the ‘use-of-hindsight’ practical expedient, which allowed us to use hindsight in assessing impairment of our existing land easements, (3) the creation of an accounting policy for short-term leases resulting in lease payments being recorded as an expense on a straight-line basis over the lease term, and (4) the aggregation, rather than separation, of the lease and non-lease components for all leases.

See Note 15, Leases, for additional information with respect to the impact of the adoption of the lease accounting guidance and the disclosures required by ASU 2016-02 and the related amendments.

Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. We adopted ASU 2018-07 on January 1, 2019. Implementation of this new standard did not have a material impact on our financial position or results of operations.

Recent Accounting Standards Yet to be Adopted

Financial Instruments - Credit Losses (ASC 326) - In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments, which changes how an entity accounts for credit losses for most financial assets and certain other instruments, and subsequent guidance which served to clarify or amend the original standard. ASU 2016-13 and the related amendments require entities to estimate lifetime expected credit losses for trade receivables and to provide additional disclosure related to credit losses. ASU 2016-13 will be effective for our annual and interim financial statements beginning in January 1, 2020 and is not expected to have a material impact on our financial position or results of operations.

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 implementation of this new standard will not have a material impact on our financial position or results of operations.

Fair Value Measurement (ASC 820) - In August 2018, the FASB issued ASU 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies and adds certain disclosure requirements on fair value measurements in ASC 820. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

Revenue Recognition (Notes)

6 Months Ended

Jun. 30, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

Revenue Recognition

We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation.

The following table displays our revenue by major source based on product and service type for the three months ended June 30, 2019 and 2018:



	Three months ended June 30, 2019												Three Months Ended June 30, 2018
(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total			Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	8,256		$	—		$	—		$	8,256		$	11,882		$	—		$	—		$	11,882
Florida natural gas division	7,015			—			—			7,015			6,317			—			—			6,317
FPU electric distribution	20,464			—			—			20,464			18,362			—			—			18,362
FPU natural gas distribution	18,663			—			—			18,663			18,281			—			—			18,281
Maryland natural gas division	3,186			—			—			3,186			4,001			—			—			4,001
Sandpiper natural gas/propane operations	3,482			—			—			3,482			4,367			—			—			4,367
Total energy distribution	61,066			—			—			61,066			63,210			—			—			63,210

Energy transmission
Aspire Energy	—			5,421			—			5,421			—			5,854			—			5,854
Eastern Shore	17,740			—			—			17,740			14,502			—			—			14,502
Peninsula Pipeline	3,565			—			—			3,565			2,968			—			—			2,968
Total energy transmission	21,305			5,421			—			26,726			17,470			5,854			—			23,324

Energy generation
Eight Flags	—			4,235			—			4,235			—			4,230			—			4,230

Propane operations
Propane delivery operations	—			17,018			—			17,018			—			20,206			—			20,206

Energy services
Marlin Gas Services	—			1,108			—			1,108			—			—			—			—
PESCO - Natural Gas Marketing	—			41,280			—			41,280			—			48,798			—			48,798
Total energy services	—			42,388			—			42,388			—			48,798			—			48,798

Other and eliminations
Eliminations	(8,968		)	(2,628		)	(9,536		)	(21,132		)	(10,176		)	(3,248		)	(10,379		)	(23,803		)
Other	—			470			132			602			—			505			194			699
Total other and eliminations	(8,968		)	(2,158		)	(9,404		)	(20,530		)	(10,176		)	(2,743		)	(10,185		)	(23,104		)

Total operating revenues⁽¹⁾	$	73,403		$	66,904		$	(9,404	)	$	130,903		$	70,504		$	76,345		$	(10,185	)	$	136,664

⁽¹⁾ Total operating revenues for the three months ended June 30, 2019, include other revenue (revenues from sources other than contracts with customers) of $(0.3) million and $0.1 million for our Regulated and Unregulated Energy segments, respectively, and $(0.4) million and $0.1 million for our Regulated and Unregulated Energy segments, respectively, for the three months ended June 30, 2018. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.

The following table displays our revenue by major source based on product and service type for the six months ended June 30, 2019 and 2018:



	Six months ended June 30, 2019												Six months ended June 30, 2018
(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total			Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	35,805		$	—		$	—		$	35,805		$	43,954		$	—		$	—		$	43,954
Florida natural gas division	14,915			—			—			14,915			12,180			—			—			12,180
FPU electric distribution	34,842			—			—			34,842			37,103			—			—			37,103
FPU natural gas distribution	42,449			—			—			42,449			41,494			—			—			41,494
Maryland natural gas division	13,233			—			—			13,233			14,673			—			—			14,673
Sandpiper natural gas/propane operations	10,564			—			—			10,564			13,331			—			—			13,331
Total energy distribution	151,808			—			—			151,808			162,735			—			—			162,735

Energy transmission
Aspire Energy	—			18,892			—			18,892			—			17,931			—			17,931
Eastern Shore	36,796			—			—			36,796			30,100			—			—			30,100
Peninsula Pipeline	7,131			—			—			7,131			5,065			—			—			5,065
Total energy transmission	43,927			18,892			—			62,819			35,165			17,931			—			53,096

Energy generation
Eight Flags	—			8,377			—			8,377			—			8,608			—			8,608

Propane operations
Propane delivery operations	—			63,143			—			63,143			—			72,311			—			72,311

Energy services
Marlin Gas Services	—			3,541			—			3,541			—			—			—			—
PESCO - Natural Gas Marketing	—			118,302			—			118,302						130,357			—			130,357
Total energy services	—			121,843			—			121,843			—			130,357			—			130,357

Other and eliminations
Eliminations	(18,714		)	(8,123		)	(23,773		)	(50,610		)	(18,003		)	(8,494		)	(25,976		)	(52,473		)
Other	—			875			264			1,139			—			999			387			1,386
Total other and eliminations	(18,714		)	(7,248		)	(23,509		)	(49,471		)	(18,003		)	(7,495		)	(25,589		)	(51,087		)

Total operating revenues⁽¹⁾	$	177,021		$	205,007		$	(23,509	)	$	358,519		$	179,897		$	221,712		$	(25,589	)	$	376,020

⁽¹⁾ Total operating revenues for the six months ended June 30, 2019, include other revenue (revenues from sources other than contracts with customers) of $(0.2) million and $0.2 million for our Regulated and Unregulated Energy segments, respectively, and $(0.9) million and $0.2 million for our Regulated and Unregulated Energy segments, respectively, for the six months ended June 30, 2018. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.

Contract balances

The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our condensed consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2018 and June 30, 2019 were as follows:



	Trade Receivables			Contract Assets (Current)		Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2018	$	83,214		—		$	2,614	$	480
Balance at 6/30/2019	47,254			18		3,051		316
Increase (decrease)	$	(35,960	)	$	18	$	437	$	(164	)

Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our current contract assets are included in other current assets in the condensed consolidated balance sheet. Our non-current contract assets are included in other assets in the condensed consolidated balance sheet and primarily relate to operations and maintenance costs incurred by Eight Flags that have not yet been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement.

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the condensed consolidated balance sheet and relate to non-refundable prepaid fixed fees for our Delmarva Peninsula propane delivery operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the three months ended June 30, 2019 and 2018, we recognized revenue of $0.2 million and $0.1 million, respectively. For the six months ended June 30, 2019 and 2018, we recognized revenue of $0.5 million and $0.3 million, respectively.

Remaining performance obligations

Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations, at June 30, 2019, are expected to be recognized as follows:



(in thousands)	2019		2020		2021		2022		2023		2024		2025 and thereafter
Eastern Shore and Peninsula Pipeline	$	19,210	$	36,835	$	33,519	$	26,575	$	21,148	$	18,969	$	193,651
Natural gas distribution operations	2,007		3,624		3,403		3,369		2,971		2,957		27,941
PESCO - Natural Gas Marketing	2,903		7,529		1,925		23		—		—		—
FPU electric distribution	149		297		297		109		—		—		—
Total revenue contracts with remaining performance obligations	$	24,269	$	48,285	$	39,144	$	30,076	$	24,119	$	21,926	$	221,592

Rates and Other Regulatory Activities

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

Public Utilities Disclosure [Text Block]

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.

Delaware

Effect of the TCJA on Customers: On January 31, 2019, the Delaware PSC approved the as-filed Delaware Division Delivery Service Rates reflecting the impact of the TCJA. The new rates went into effect March 1, 2019. The refunds, which were retroactive to February 2018, were completed prior to the mandated deadline of June 30, 2019. The order also provided for a line item billing credit that went into effect on April 1, 2019, for the return of the excess accumulated

deferred income taxes ("ADIT"). Additional information on the TCJA impact is included in the table at the end of this Note 4, Rates and Other Regulatory Activities.

Weather Normalization Adjustment: In January 2019, we filed with the Delaware PSC an application requesting approval to implement a weather normalization adjustment. The proposed weather normalization adjustment would have provided either a billing credit (during colder than normal weather) or surcharge (during warmer than normal weather) designed to produce natural gas bills for customers that reflect normal temperatures. The weather normalization adjustment would have ensured we did not over or under-collect Delaware PSC authorized levels of distribution revenues due to weather variability. The Delaware PSC issued an order on March 19, 2019 to open a docket. In July 2019, the Delaware Division withdrew the petition and is planning, as proposed by the Delaware PSC, to include a weather normalization adjustment in its next rate case.

Florida

Electric Limited Proceeding-Storm Recovery: In February 2018, FPU filed a petition with the Florida PSC, requesting recovery of incremental storm restoration costs related to several hurricanes and tropical storms, along with the replenishment of the storm reserve to its pre-storm level of $1.5 million. As a result of these hurricanes and tropical storms, FPU’s storm reserve was depleted and, at the time of this filing, had a deficit of $0.8 million. This matter went to hearing in December 2018 and was subsequently approved at the March 5, 2019 Agenda with the Final Order issued on March 25, 2019. FPU received approval to include a surcharge of $1.54 per 1,000-kilowatt hour on customer bills for two years beginning in April 2019, to recover storm-related costs and replenish the storm reserve.

Hurricane Michael: In October 2018, Hurricane Michael passed through FPU's electric distribution operation's service territory in Northwest Florida. The hurricane caused widespread and severe damage to FPU's infrastructure resulting in 100 percent of its customers in the Northwest Florida service territory losing electrical service. FPU, after exerting extraordinary hurricane restoration efforts, restored service to those customers who were able to accept it. FPU expended more than $65 million to restore service, which has been recorded as new plant and equipment, charged against FPU’s accumulated depreciation or charged against FPU’s storm reserve. In conjunction with the hurricane-related expenditures, we executed two 13-month unsecured term loans as temporary financing, each in the amount of $30 million. The interest cost associated with these loans is one-month LIBOR rate plus 75 points. One of the term loans was executed in December 2018; the other was executed in January 2019. While there is a short-term negative impact, the storm is not expected to have a significant impact on our financial results going forward, assuming recovery is granted through the regulatory process. We expect to file the necessary regulatory filings in the third quarter of 2019 to seek recovery of the restoration costs incurred, including eligible financing costs.

Effect of the TCJA on Customers: In February 2018, the Florida PSC opened dockets to consider the impacts associated with the TCJA. In May 2018, FPU’s natural gas divisions filed petitions and supporting testimony regarding the disposition of the related impacts of the TCJA. Hearings on this matter took place in November 2018, and the staff's recommendation was approved by the Florida PSC at the February 5, 2019 Agenda. Final orders were issued on February 25, 2019. Staff’s recommendations are summarized in the table at the end of this Note 4, Rates and Other Regulatory Activities.

Imbalance Petition: In February 2019, FPU filed a petition, with the Florida PSC, to modify the pool manager cash out tiers and respective cash out rates. With this petition, FPU further facilitates consistency across the Florida business units and eliminates the unintentional arbitrage opportunity created by the tariff. The petition does not have a financial impact for FPU, and it will benefit customers by lowering costs. This petition was approved by the Florida PSC at the April 2, 2019 Agenda.

Natural Gas Depreciation Study: In March 2019, FPU filed a petition, with the Florida PSC, for approval of its Consolidated Natural Gas depreciation rates. If approved, the new rates will decrease expense approximately $0.3 million annually and be effective retro-actively to January 2019. The petition is on the Florida PSC's September 2019 Agenda for approval.

Auburndale Project: In June 2019, Peninsula Pipeline filed with the Florida PSC for approval of its Transportation Service Agreement with the Florida Division of Chesapeake Utilities. Peninsula Pipeline will purchase existing pipeline owned by the Florida Division of Chesapeake Utilities and Calpine and construct pipeline in Polk County, Florida. Peninsula Pipeline will provide transportation service to the Florida Division of Chesapeake Utilities increasing both delivery capacity and downstream pressure as well as introducing a secondary source of natural gas for the Florida Division of Chesapeake Utilities' distribution system. The petition is on the Florida PSC's August 2019 Agenda for approval.

Palm Beach Expansion Project: In June 2019, Peninsula Pipeline filed with the Florida PSC for approval of its Transportation Service Agreement with FPU. Peninsula Pipeline will construct several new interconnection points and pipeline expansions in Palm Beach County, Florida, which will enable FPU to serve an industrial research park and several new residential developments. Peninsula Pipeline will provide transportation service to FPU, increasing reliability, system

pressure as well as introducing diversity in fuel source for natural gas to serve the increased demand in these areas. The petition is on the Florida PSC's August 2019 Agenda for approval.

Maryland Division and Sandpiper

There were no material regulatory matters during the quarter.

Eastern Shore

Del-Mar Energy Pathway Project: In September 2018, Eastern Shore filed a Certificate Application with the FERC, requesting authorization to construct and operate the Del-Mar Energy Pathway project, which will provide an additional 14,300 Dts/d of firm service to four customers. Facilities to be constructed include six miles of pipeline looping in Delaware; 13 miles of new mainline extension in Sussex County, Delaware and Somerset County, Maryland; and new pressure control and delivery stations in these counties. The benefits of this project include: (i) additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (ii) extension of Eastern Shore’s pipeline system, for the first time, into Somerset County, Maryland. During the fourth quarter of 2018, the FERC held a full project area scoping meeting in Sussex County, Delaware and issued a Notice of Schedule for Environmental Review. The Environmental Assessment for the Del-Mar Energy Pathway project was issued in April 2019; however, final FERC authorization is still pending. Eastern Shore anticipates that this project will be fully in-service by mid-2021, contingent upon the FERC issuing authorization for the project in the third quarter of 2019.

Summary TCJA Table

The following table summarizes the TCJA impact on our regulated businesses:



	Regulatory Liabilities related to ADIT
Operation and Regulatory Jurisdiction	Amount (in thousands)	Status	Status of Customer Rate impact related to lower federal corporate income tax rate
Eastern Shore (FERC)	$34,190	Will be addressed in Eastern Shore's next rate case filing.	Implemented one-time bill credit (totaling $0.9 million) in April 2018. Customer rates adjusted in April 2018.
Delaware Division (Delaware PSC)	$12,906	PSC approved amortization of ADIT in January 2019.	Implemented one-time bill credit (totaling $1.5 million) in April 2019. Customer rates adjusted in March 2019.
Maryland Division (Maryland PSC)	$4,143	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.4 million) in July 2018. Customer rates adjusted effective May 1, 2018.
Sandpiper Energy (Maryland PSC)	$3,790	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.6 million) in July 2018 - Customer rates adjusted effective May 1, 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,318	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.	Florida PSC's final order was issued in February 2019. Excluding GRIP, tax savings arising from the TCJA rate reduction will be retained by the Company. GRIP: Tax savings for 2018 will be refunded to customers in 2020 through the annual GRIP cost recovery mechanism. Future customer GRIP surcharges will be adjusted to reflect tax savings associated with TCJA.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,173	Same treatment on a net basis as Chesapeake Florida Gas Division (above).	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$298	Same treatment on a net basis as Chesapeake Florida Gas Division (above).	Tax rate reduction: The impact was immaterial for the divisions. GRIP (Applicable to Fort Meade division only): Same treatment as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,858	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.	TCJA benefit will flow back to its customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years.

Environmental Commitments and Contingencies

6 Months Ended

Jun. 30, 2019

Environmental Remediation Obligations [Abstract]

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. We have received approval for recovery of clean-up costs in rates for sites located in Salisbury, Maryland; Seaford, Delaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We are also in discussions with the Maryland Department of Environment ("MDE") regarding another former MGP site located in Cambridge, Maryland.

As of June 30, 2019 and December 31, 2018, we had approximately $8.5 million and $9.1 million, respectively, in environmental liabilities related to FPU’s MGP sites in Key West, Pensacola, Sanford and West Palm Beach. FPU has approval to recover, from insurance and through customer rates, up to $14.0 million of its environmental costs related to its MGP sites. As of June 30, 2019 and December 31, 2018, we had recovered approximately $11.7 million and $11.5 million, respectively, leaving approximately $2.3 million and $2.5 million, respectively, 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:



MGP Site (Jurisdiction)	Status	Estimated Cost to Clean up (Expect to Recover through Rates with Customers)
West Palm Beach (Florida)	Remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. We expect to implement similar remedial actions on other remaining portions, including the anticipated demolition of buildings on the site's west parcel in 2019.	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.
Sanford (Florida)	In March 2018, the United States Environmental Protection Agency ("EPA") approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be immaterial.
Winter Haven (Florida)	Remediation is ongoing.	Not expected to exceed $0.4 million, which includes costs of implementing institutional controls at the site.
Seaford (Delaware)	Conducted investigations of on-site and off-site impacts in the vicinity of the site, from 2014 through 2018, and submitted the findings to Delaware Department of Natural Resources and Environmental Control ("DNREC") in a March 2019 report. An interim action involving air-sparging/vapor extraction to mitigate on-site impact will be implemented, after the Work Plan submitted in June 2019 is approved by DNREC.	Between $0.2 million and $0.5 million.
Cambridge (Maryland)	Currently in discussions with the MDE.	Unable to estimate.

Other Commitments and Contingencies	6 Months Ended
Other Commitments and Contingencies	Jun. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Other Commitments and Contingencies	Other Commitments and Contingencies Natural Gas and Electric Our Delmarva Peninsula natural gas distribution operations have asset management agreements with PESCO to manage 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. In May 2019, FPU natural gas distribution operations and Eight Flags entered into separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. The agreements will commence on or about July 2020, and each has a 10-year term. Chesapeake Utilities' Florida Division has firm transportation service contracts with Florida Gas Transmission Company ("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. To date, Chesapeake Utilities has not been required to make a payment resulting from this contingency. FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with Florida Power & Light Company 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 FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric 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 two 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 June 30, 2019, 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 our electric customers. In July 2016, Eight Flags also started selling steam, pursuant to a separate 20-year contract, to the landowner 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. Corporate Guarantees 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 June 30, 2019 was approximately $68.1 million, with the guarantees expiring on various dates through December 31, 2020. 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 14, Long-Term Debt, for further details). As of June 30, 2019, we have issued letters of credit totaling approximately $7.0 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 April 5, 2020. There have been no draws on these letters of credit as of June 30, 2019. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that they will be renewed to the extent necessary in the future.

Segment Information

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

Segment Information

We use the management approach to identify operating segments. We organize our business around differences in regulatory environment 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 are entirely domestic and are comprised of two reportable segments:


•	Regulated Energy. Includes energy distribution and transmission services (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 energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, the new mobile compressed natural gas distribution and pipeline solutions subsidiary, and other energy services (natural gas marketing and related services). These operations are unregulated as to their rates and services. 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 are 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 financial information about our reportable segments:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	70,719		$	67,731		$	171,458		$	173,685
Unregulated Energy	60,184			68,933			187,061			202,335
Total operating revenues, unaffiliated customers	$	130,903		$	136,664		$	358,519		$	376,020
Intersegment Revenues ⁽¹⁾
Regulated Energy	$	2,684		$	2,773		$	5,563		$	6,212
Unregulated Energy	6,720			7,412			17,946			19,377
Other businesses	132			194			264			387
Total intersegment revenues	$	9,536		$	10,379		$	23,773		$	25,976
Operating Income
Regulated Energy	$	18,752		$	14,304		$	47,769		$	41,015
Unregulated Energy	(1,348		)	490			13,628			14,174
Other businesses and eliminations	32			(1,546		)	32			(1,535		)
Operating income	17,436			13,248			61,429			53,654
Other expense, net	(316		)	(262		)	(361		)	(194		)
Interest charges	5,655			3,881			11,365			7,545
Income before Income Taxes	11,465			9,105			49,703			45,915
Income taxes	3,161			2,718			12,735			12,674
Net Income	$	8,304		$	6,387		$	36,968		$	33,241

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



(in thousands)	June 30, 2019		December 31, 2018
Identifiable Assets
Regulated Energy segment	$	1,349,422	$	1,345,805
Unregulated Energy segment	284,888		306,045
Other businesses and eliminations	46,732		41,821
Total identifiable assets	$	1,681,042	$	1,693,671

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2019

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Stockholder's Equity

Accumulated Other Comprehensive Loss

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements and natural gas swaps and futures contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated other comprehensive loss. The following tables present the changes in the balance of accumulated other comprehensive (loss)/income as of June 30, 2019 and 2018. All amounts except the stranded tax reclassification are presented net of tax.



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2018	$	(5,928	)	$	(785	)	$	(6,713	)
Other comprehensive income before reclassifications	—			1,000			1,000
Amounts reclassified from accumulated other comprehensive income/(loss)	213			(132		)	81
Net current-period other comprehensive income	213			868			1,081
Prior-year reclassification	—			(115		)	(115		)
As of June 30, 2019	$	(5,715	)	$	(32	)	$	(5,747	)



(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	—			(1,440		)	(1,440		)
Amounts reclassified from accumulated other comprehensive income/(loss)	189			712			901
Net prior-period other comprehensive income/(loss)	189			(728		)	(539		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of June 30, 2018	$	(5,576	)	$	(142	)	$	(5,718	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and six months ended June 30, 2019 and 2018. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit ⁽¹⁾	$	19		$	19		$	39		$	39
Net loss⁽¹⁾	(163		)	(149		)	(328		)	(297		)
Total before income taxes	(144		)	(130		)	(289		)	(258		)
Income tax benefit	37			36			76			69
Net of tax	$	(107	)	$	(94	)	$	(213	)	$	(189	)
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements ⁽²⁾	$	252		$	(181	)	$	858		$	(645	)
Natural gas swaps ⁽²⁾	—			(31		)	11			(481		)
Natural gas futures ⁽²⁾	(125		)	(161		)	(698		)	137
Total before income taxes	127			(373		)	171			(989		)
Income tax benefit (expense)	(34		)	105			(39		)	277
Net of tax	93			(268		)	132			(712		)
Total reclassifications for the period	$	(14	)	$	(362	)	$	(81	)	$	(901	)

⁽¹⁾ These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.

⁽²⁾These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.

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

Employee Benefit Plans

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2019 and 2018 are set forth in the following tables:



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended June 30,	2019			2018			2019			2018			2019		2018		2019			2018			2019		2018
(in thousands)
Interest cost	$	104		$	98		$	615		$	592		$	21	$	21	$	9		$	9		$	12	$	13
Expected return on plan assets	(127		)	(138		)	(693		)	(774		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(19		)	(19		)	—		—
Amortization of net loss	101			88			129			108			26		25		12			15			—		—
Net periodic cost (benefit)	78			48			51			(74		)	47		46		2			5			12		13
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	78		$	48		$	242		$	117		$	47	$	46	$	2		$	5		$	14	$	15



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Six Months Ended June 30,	2019			2018			2019			2018			2019		2018		2019			2018			2019		2018
(in thousands)
Interest cost	$	209		$	195		$	1,230		$	1,184		$	42	$	42	$	19		$	19		$	24	$	26
Expected return on plan assets	(254		)	(276		)	(1,386		)	(1,549		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(39		)	(39		)	—		—
Amortization of net loss	203			176			258			217			52		50		24			30			—		—
Net periodic cost (benefit)	158			95			102			(148		)	94		92		4			10			24		26
Amortization of pre-merger regulatory asset	—			—			381			381			—		—		—			—			4		4
Total periodic cost	$	158		$	95		$	483		$	233		$	94	$	92	$	4		$	10		$	28	$	30

We expect to record pension and postretirement benefit costs of approximately $1.3 million for 2019. Included in these costs is approximately $0.6 million related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred, but were not recognized, as part of net periodic benefit costs prior to the FPU merger in 2009. This was deferred as a regulatory asset by FPU prior to the merger, to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was approximately $0.2 million and approximately $0.6 million at June 30, 2019 and December 31, 2018, respectively. Excluding the service cost component, the other components of the net periodic costs have been recorded or reclassified to other expense, net in the condensed consolidated statements of income.

Pursuant to a Florida PSC order, FPU continues to record, as a regulatory asset, a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss.

The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three and six months ended June 30, 2019 and 2018:



For the Three Months Ended June 30, 2019	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	101		129		26		12			—		268
Total recognized in net periodic benefit cost	101		129		26		(7		)	—		249
Recognized from accumulated other comprehensive loss ⁽¹⁾	101		24		26		(7		)	—		144
Recognized from regulatory asset	—		105		—		—			—		105
Total	$	101	$	129	$	26	$	(7	)	$	—	$	249



For the Three Months Ended June 30, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	88		108		25		15			—		236
Total recognized in net periodic benefit cost	88		108		25		(4		)	—		217
Recognized from accumulated other comprehensive loss ⁽¹⁾	88		21		25		(4		)	—		130
Recognized from regulatory asset	—		87		—		—			—		87
Total	$	88	$	108	$	25	$	(4	)	$	—	$	217



For the Six Months Ended June 30, 2019	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	—		—		—		(39		)	—		(39		)
Net loss	203		258		52		24			—		537
Total recognized in net periodic benefit cost	203		258		52		(15		)	—		498
Recognized from accumulated other comprehensive loss ⁽¹⁾	203		49		52		(15		)	—		289
Recognized from regulatory asset	—		209		—		—			—		209
Total	$	203	$	258	$	52	$	(15	)	$	—	$	498



For the Six Months Ended June 30, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(39	)	$	—	$	(39	)
Net loss	176		217		50		30			—		473
Total recognized in net periodic benefit cost	176		217		50		(9		)	—		434
Recognized from accumulated other comprehensive loss ⁽¹⁾	176		41		50		(9		)	—		258
Recognized from regulatory asset	—		176		—		—			—		176
Total	$	176	$	217	$	50	$	(9	)	$	—	$	434

⁽¹⁾See Note 8, Stockholder's Equity.

During the three and six months ended June 30, 2019, we contributed approximately $0.1 million to the Chesapeake Pension Plan and approximately $0.4 million and $0.6 million, respectively, to the FPU Pension Plan. We expect to contribute a total of approximately $0.2 million and approximately $1.2 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2019, which represents the minimum annual contribution payments required.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the six months ended June 30, 2019 were $0.1 million. There were immaterial cash benefits paid for the three months ended June 30, 2019. We expect to pay total cash benefits of approximately $0.4 million under the Chesapeake SERP in 2019. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the six months ended June 30, 2019, were immaterial and no cash benefits were paid for medical claims during the second quarter of 2019. We estimate that approximately $0.1 million will be paid for such benefits under the Chesapeake Postretirement Plan in 2019. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2019, were immaterial for each period. We estimate that approximately $0.1 million will be paid for such benefits under the FPU Medical Plan in 2019.

Share-Based Compensation

6 Months Ended

Jun. 30, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

Our non-employee directors and key employees are 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.

The table below presents the amounts included in net income related to share-based compensation expense for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
(in thousands)
Awards to non-employee directors	$	157		$	135		$	305		$	269
Awards to key employees	452			1,190			790			2,575
Total compensation expense	609			1,325			1,095			2,844
Less: tax benefit	(158		)	(363		)	(285		)	(779		)
Share-based compensation amounts included in net income	$	451		$	962		$	810		$	2,065

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a deferred expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2019, after the most recent election of directors, each of our continuing non-employee directors received an annual retainer of 751 shares of common stock under the SICP for service as a director through the 2020 Annual Meeting of Stockholders.



	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2018	—		$	—
Granted	6,759		$	93.14
Vested	(6,759	)	$	93.14
Outstanding—June 30, 2019	—		$	—

At June 30, 2019, there was approximately $0.5 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending April 30, 2020. See Note 1, Summary of Accounting Policies, for additional information regarding ASU 2018-07 and its impact on the accounting for non-employee share-based payments.

Our former President and Chief Executive Officer, Michael P. McMasters, retired as an executive officer on December 31, 2018 but continued as a member of the Board of Directors until the 2019 Annual Meeting of Stockholders. Mr. McMasters received a pro-rated grant of 276 shares of common stock under the SICP for service as a non-employee director from January 1, 2019 through May 8, 2019. These shares awarded to Mr. McMasters immediately vested upon issuance in January 2019, had a weighted average fair value of $75.70 per share, and were fully expensed as of April 30, 2019.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2019:



	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2018	131,741		$	67.24
Granted	45,016		$	91.19
Vested	(25,831	)	$	67.08
Expired	(15,086	)	$	69.28
Outstanding—June 30, 2019	135,840		$	74.05

In June 2018, the Company and a former executive officer entered into a separation agreement and release (the "Separation Agreement"). Pursuant to the Separation Agreement, three awards, representing a total of 14,107 shares of common stock

previously granted to the executive officer under the SICP, immediately vested at the time of separation; 2,569 shares were forfeited, and we recognized $1.1 million as share-based compensation expense.

In February 2019, our Board of Directors granted awards of 45,016 shares of common stock to key employees under the SICP. The shares granted are multi-year awards that will vest at the end of the three-year service period ending December 31, 2021. All of these stock awards are earned based upon the successful achievement of long-term financial results, which comprise market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

In March 2019, upon the election of certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that we awarded in February 2019 for the performance period ended December 31, 2018, remitted the cash to the appropriate taxing authorities, and paid the balance of such awarded shares to each such executive officer. We withheld 7,635 shares, based on the value of the shares on their award date, determined by the average of the high and low prices of our common stock. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $0.7 million.

At June 30, 2019, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $12.9 million. At June 30, 2019, there was approximately $3.8 million of unrecognized compensation cost related to these awards, which is expected to be recognized as expense from July 1, 2019 through December 31, 2021.

Stock Options

We did not have any stock options outstanding at June 30, 2019 or 2018, nor were any stock options issued during these periods.

Derivative Instruments

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Aspire Energy has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Both our propane distribution and natural gas marketing operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of June 30, 2019, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Volume of Derivative Activity

As of June 30, 2019, the volume of our open commodity derivative contracts were as follows:



Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
PESCO	Natural gas (Dts)	30.6	Cash flows hedges	October 2023
PESCO	Natural gas (Dts)	5.6	Not designated	October 2022
Sharp	Propane (gallons)	12.1	Cash flows hedges	June 2022

PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. We designated and accounted for them as cash flow hedges. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $0.5 million from accumulated other comprehensive loss to earnings during the next 12-month period ended June 30, 2020.

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased during the heating season. Under the futures and swap agreements, Sharp will receive the difference between: (i) the index prices (Mont Belvieu prices in August 2018 through March 2023), and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. We designated and accounted for propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in

other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $1.0 million from accumulated other comprehensive income (loss) to earnings during the next 12-month period ended June 30, 2020.

Balance Sheet Offsetting

PESCO has entered into master netting agreements with counterparties that enable it to net the counterparties' outstanding accounts receivable and payable, which are presented on a net basis in the condensed consolidated balance sheets. The following table summarizes the accounts receivable and payable on a gross and net basis at June 30, 2019 and December 31, 2018:



	At June 30, 2019
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	2,964	$	927	$	2,037
Accounts payable	$	10,418	$	927	$	9,491



	At December 31, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	12,368	$	3,834	$	8,534
Accounts payable	$	24,741	$	3,834	$	20,907

Broker Margin

Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily MTM relative to maintenance margin requirements. We maintain separate broker margin accounts for Sharp and PESCO. The balance related to the margin accounts are as follows:



(in thousands)	Balance Sheet Location	At June 30, 2019		At December 31, 2018
Sharp	Other Current Assets	$	1,841	$	2,170
PESCO	Other Current Assets	$	1,592	$	2,810

Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency.

The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2019 and December 31, 2018, are as follows:



	Derivative Assets
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2019		December 31, 2018
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative assets, at fair value	$	2,747	$	4,024
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	—		71
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	7,715		9,059
Propane swap agreements	Derivative assets, at fair value	109		11
Total asset derivatives		$	10,571	$	13,165



	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2019		December 31, 2018
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	3,144	$	4,562
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	6,663		8,705
Propane swap agreements	Derivative liabilities, at fair value	1,187		1,604
Total liability derivatives		$	10,994	$	14,871

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:



		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2019			2018			2019			2018
Derivatives not designated as hedging instruments
Natural gas futures contracts	Cost of sales	$	28		$	(128	)	$	6		$	(2,963	)
Propane swap agreements	Cost of sales	—			(4		)	—			(13		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	252			(181		)	858			(645		)
Propane swap agreements	Other comprehensive income (loss)	(494		)	106			515			(886		)
Natural gas futures contracts	Cost of sales	(125		)	(161		)	(698		)	137
Natural gas swap contracts	Cost of sales	—			(31		)	11			(481		)
Natural gas swap contracts	Other comprehensive income (loss)	(2,463		)	523			763			588
Natural gas futures contracts	Other comprehensive income (loss)	(8		)	861			(67		)	(871		)
Total		$	(2,810	)	$	985		$	1,388		$	(5,134	)

As of June 30, 2019, the following amounts were recorded in the condensed consolidated balance sheets related to fair value hedges:



(in thousands)	Carrying Amount of Hedged Item				Cumulative Adjustment Included in Carrying Amount of Hedged Item
Balance Sheet Location of Hedged Items	At June 30, 2019		At December 31, 2018		At June 30, 2019		At December 31, 2018
Inventory	$	—	$	212	$	—	$	—

Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

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:



Fair Value Hierarchy	Description of Fair Value Level	Fair Value Technique Utilized
Level 1	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities	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	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	Derivative assets and liabilities - The fair values of forward contracts are measured using market transactions in either the listed or over-the-counter 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 over-the-counter markets.
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)	Investments - guaranteed income fund - The fair values of these investments are recorded at the contract value, which approximates their fair value.

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 June 30, 2019 and December 31, 2018:



			Fair Value Measurements Using:
As of June 30, 2019	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	$	26	$	26	$	—	$	—
Investments—guaranteed income fund	791		—		—		791
Investments—mutual funds and other	8,004		8,004		—		—
Total investments	8,821		8,030		—		791
Derivative assets	10,571		—		10,571		—
Total assets	$	19,392	$	8,030	$	10,571	$	791
Liabilities:
Derivative liabilities	$	10,994	$	—	$	10,994	$	—



			Fair Value Measurements Using:
As of December 31, 2018	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	686		—		—		686
Investments—mutual funds and other	6,003		6,003		—		—
Total investments	6,711		6,025		—		686
Derivative assets	13,165		—		13,165		—
Total assets	$	19,876	$	6,025	$	13,165	$	686
Liabilities:
Derivative liabilities	$	14,871	$	—	$	14,871	$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2019 and 2018:



	Six Months Ended June 30,
	2019			2018
(in thousands)
Beginning Balance	$	686		$	648
Purchases and adjustments	110			54
Transfers	—			(24		)
Distribution	(12		)	(12		)
Investment income	7			5
Ending Balance	$	791		$	671

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

At June 30, 2019, 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 June 30, 2019, long-term debt which includes current maturities, had a carrying value of approximately $352.1 million, compared to the estimated fair value of $363.4 million. At December 31, 2018, long-term debt, which includes the current maturities but excluded finance lease obligations and debt issuance costs, had a carrying value of approximately $327.2 million, compared to a fair value of approximately $323.8 million. The fair value was calculated 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, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

- Definition

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.

+ References + Details

Long-Term Debt

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Long-Term Debt

Our outstanding long-term debt is shown below:



	June 30,			December 31,
(in thousands)	2019			2018
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,988		$	7,986
Uncollateralized senior notes:
5.50% note, due October 12, 2020	4,000			4,000
5.93% note, due October 31, 2023	13,500			15,000
5.68% note, due June 30, 2026	20,300			23,200
6.43% note, due May 2, 2028	6,300			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			70,000
3.48% note, due May 31, 2038	50,000			50,000
3.58% note, due November 30, 2038	50,000			50,000
Term Note due January 21, 2020	30,000			30,000
Term Note due February 28, 2020	30,000			—
Promissory notes	—			26
Finance lease obligation	—			1,310
Less: debt issuance costs	(564		)	(567		)
Total long-term debt	351,524			327,955
Less: current maturities	(75,600		)	(11,935		)
Total long-term debt, net of current maturities	$	275,924		$	316,020

⁽¹⁾ FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.

Term Notes

In December 2018, we issued a $30.0 million unsecured term note through PNC Bank N.A. with a maturity date of January 21, 2020. The interest rate at June 30, 2019 and December 31, 2018 was 3.13% and 3.23%, respectively, which equals one-month LIBOR rate plus 75 basis points. In January 2019, we issued a $30.0 million unsecured term note through Branch Banking and Trust Company, with a maturity date of February 28, 2020. The interest rate, at June 30, 2019, was 3.19%, which equals the one-month LIBOR rate plus 75 basis points. As of June 30, 2019, these term notes totaling $60.0 million are included in the current maturities of long-term debt.

Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL, whom are under no obligation to purchase any unsecured debt. We entered into the Prudential Shelf Agreement, totaling $150.0 million, in October 2015, and we issued $70.0 million of 3.25% unsecured debt in April 2017. The Prudential Shelf Agreement was then amended in September 2018 to increase the borrowing capacity back up to $150.0 million, and Prudential accepted our request to purchase unsecured debt of $100.0 million at an interest rate of 3.98% on or before August 20, 2019. We entered into the NYL Shelf Agreement, totaling $100.0 million, in March 2017, and we issued unsecured debt totaling $100.0 million during 2018. The NYL Shelf Agreement was amended in November 2018 to add incremental borrowing capacity of $50.0 million. As of June 30, 2019, we had not requested that MetLife purchase unsecured senior debt under the MetLife Shelf Agreement, which we entered into in March 2017. The following table summarizes the borrowing information under our Shelf Agreements at June 30, 2019:



	Total Borrowing Capacity		Less: Amount of Debt Issued			Less: Unfunded Commitments			Remaining Borrowing Capacity
(in thousands)
Shelf Agreement
Prudential Shelf Agreement	$	220,000	$	(70,000	)	$	(100,000	)	$	50,000
MetLife Shelf Agreement	150,000		—			—			150,000
NYL Shelf Agreement	150,000		(100,000		)	—			50,000
Total	$	520,000	$	(170,000	)	$	(100,000	)	$	250,000

The Shelf Agreements or Shelf Notes 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.

Leases Leases

6 Months Ended

Jun. 30, 2019

Lease Disclosure [Abstract]

Lessee, Operating Leases [Text Block]

We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases have been entered into to better enable us to conduct our business operations in the regions in which we operate. Office space is leased to provide adequate workspace for all our employees in several locations throughout the Mid-Atlantic, Mid-West and in Florida. We lease land at various locations throughout our service territories to enable us to inject natural gas into underground storage and distribution systems, for bulk storage capacity, for our propane operations and for storage of equipment used in repairs and maintenance of our infrastructure. We lease natural gas compressors to ensure timely and reliable transportation of natural gas to our customers. Additionally, we lease a pipeline to deliver natural gas to an industrial customer in Polk County, Florida. We lease warehouses to store equipment and materials used in repairs and maintenance for our businesses.

Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would have resulted in immaterial additional annual lease costs.

Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25 years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our condensed consolidated balance sheet at June 30, 2019, pertaining to the right of use assets and lease liabilities, are measured based on our current expectations of exercising our available renewal options.

Our existing leases are not subject to any restrictions or covenants which preclude our ability to pay dividends, obtain financing or enter into additional leases.

We utilize our incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. Our incremental borrowing rate represents the rate that we would have to pay to borrow funds on a collateralized basis over a similar term and in a similar economic environment.

Leases with an initial term of 12 months or less are not recorded on our balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term.

We have elected not to separate non-lease components from all classes of our existing leases. Non-lease components have been accounted for as part of the single lease component to which they are related.

As of June 30, 2019, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our condensed consolidated statements of income:



		Three Months Ended				Six Months Ended
		June 30,				June 30,
( in thousands)	Classification	2019		2018		2019		2018
Operating lease cost ⁽¹⁾	Operations expense	$	654	$	698	$	1,288	$	1,805
Finance lease cost:
Amortization of lease assets	Depreciation and amortization	249		361		650		719
Interest on lease liabilities	Interest expense	1		14		5		31
Net lease cost		$	904	$	1,073	$	1,943	$	2,555

⁽¹⁾ Includes short-term leases and variable lease costs, which are immaterial

The following table presents the balance and classifications of our right of use assets and lease liabilities included in our condensed consolidated balance sheet at June 30, 2019:



(in thousands)	Balance sheet classification	Amount
Assets
Operating lease assets	Operating lease right-of-use assets	$	12,404
Total lease assets		$	12,404
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,704
Noncurrent
Operating lease liabilities	Operating lease - liabilities	10,710
Total lease liabilities		$	12,414

The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating and financing leases at June 30, 2019:



	At June 30, 2019
Weighted-average remaining lease term (in years)
Operating leases	9.13
Weighted-average discount rate
Operating leases	3.8	%

The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our condensed consolidated statements of cash flows as of June 30, 2019 and June 30, 2018:



	Six Months Ended
	June 30,
(in thousands)	2019		2018
Operating cash flows from operating leases	$	1,100	$	1,715
Operating cash flows from finance leases	$	5	$	31
Financing cash flows from finance leases	$	650	$	719

The following table presents the future undiscounted maturities of our operating and financing leases at June 30, 2019 and for each of the next five years and thereafter:



(in thousands)	Operating Leases ⁽¹⁾		Finance Leases		Total
Remainder of 2019	$	1,089	$	—	$	1,089
2020	2,091		—		2,091
2021	1,852		—		1,852
2022	1,691		—		1,691
2023	1,695		—		1,695
2024	1,451		—		1,451
Thereafter	4,916		—		4,916
Total lease payments	$	14,785	$	—	$	14,785
Less: Interest	2,371		—		2,371
Present value of lease liabilities	$	12,414	$	—	12,414

⁽¹⁾ Operating lease payments include $3.9 million related to options to extend lease terms that are reasonably certain of being exercised.

The following table presents future minimum lease payments for our operating leases at December 31, 2018 under ASC 840 and is being presented for comparative purposes:



Year(s)	2019	2020	2021	2022	2023	Thereafter	Total
(in thousands)
Expected payments	$2,349	$1,998	$1,761	$1,689	$1,642	$5,398	$14,837

Summary of Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Basis of Presentation

Where necessary to improve comparability, prior period amounts have been changed to conform to current period presentation.

Business Acquisition [Line Items]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

Marlin Gas Transport and Ohl Fuel Oil Acquisitions



	Three Months Ended June 30, 2019					Six Months Ended June 30, 2019
	Operating Revenue		Operating Income			Operating Revenue		Operating Income
(in thousands)
Marlin Gas Services	$	1,108	$	48		$	3,541	$	1,423
Ohl propane acquisition	$	174	$	(61	)	$	997	$	212

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

See Note 15, Leases, for additional information with respect to the impact of the adoption of the lease accounting guidance and the disclosures required by ASU 2016-02 and the related amendments.

Recent Accounting Standards Yet to be Adopted

Revenue Recognition (Tables)

6 Months Ended

Jun. 30, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

The following table displays our revenue by major source based on product and service type for the three months ended June 30, 2019 and 2018:



	Three months ended June 30, 2019												Three Months Ended June 30, 2018
(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total			Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	8,256		$	—		$	—		$	8,256		$	11,882		$	—		$	—		$	11,882
Florida natural gas division	7,015			—			—			7,015			6,317			—			—			6,317
FPU electric distribution	20,464			—			—			20,464			18,362			—			—			18,362
FPU natural gas distribution	18,663			—			—			18,663			18,281			—			—			18,281
Maryland natural gas division	3,186			—			—			3,186			4,001			—			—			4,001
Sandpiper natural gas/propane operations	3,482			—			—			3,482			4,367			—			—			4,367
Total energy distribution	61,066			—			—			61,066			63,210			—			—			63,210

Energy transmission
Aspire Energy	—			5,421			—			5,421			—			5,854			—			5,854
Eastern Shore	17,740			—			—			17,740			14,502			—			—			14,502
Peninsula Pipeline	3,565			—			—			3,565			2,968			—			—			2,968
Total energy transmission	21,305			5,421			—			26,726			17,470			5,854			—			23,324

Energy generation
Eight Flags	—			4,235			—			4,235			—			4,230			—			4,230

Propane operations
Propane delivery operations	—			17,018			—			17,018			—			20,206			—			20,206

Energy services
Marlin Gas Services	—			1,108			—			1,108			—			—			—			—
PESCO - Natural Gas Marketing	—			41,280			—			41,280			—			48,798			—			48,798
Total energy services	—			42,388			—			42,388			—			48,798			—			48,798

Other and eliminations
Eliminations	(8,968		)	(2,628		)	(9,536		)	(21,132		)	(10,176		)	(3,248		)	(10,379		)	(23,803		)
Other	—			470			132			602			—			505			194			699
Total other and eliminations	(8,968		)	(2,158		)	(9,404		)	(20,530		)	(10,176		)	(2,743		)	(10,185		)	(23,104		)

Total operating revenues⁽¹⁾	$	73,403		$	66,904		$	(9,404	)	$	130,903		$	70,504		$	76,345		$	(10,185	)	$	136,664

The following table displays our revenue by major source based on product and service type for the six months ended June 30, 2019 and 2018:



	Six months ended June 30, 2019												Six months ended June 30, 2018
(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total			Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	35,805		$	—		$	—		$	35,805		$	43,954		$	—		$	—		$	43,954
Florida natural gas division	14,915			—			—			14,915			12,180			—			—			12,180
FPU electric distribution	34,842			—			—			34,842			37,103			—			—			37,103
FPU natural gas distribution	42,449			—			—			42,449			41,494			—			—			41,494
Maryland natural gas division	13,233			—			—			13,233			14,673			—			—			14,673
Sandpiper natural gas/propane operations	10,564			—			—			10,564			13,331			—			—			13,331
Total energy distribution	151,808			—			—			151,808			162,735			—			—			162,735

Energy transmission
Aspire Energy	—			18,892			—			18,892			—			17,931			—			17,931
Eastern Shore	36,796			—			—			36,796			30,100			—			—			30,100
Peninsula Pipeline	7,131			—			—			7,131			5,065			—			—			5,065
Total energy transmission	43,927			18,892			—			62,819			35,165			17,931			—			53,096

Energy generation
Eight Flags	—			8,377			—			8,377			—			8,608			—			8,608

Propane operations
Propane delivery operations	—			63,143			—			63,143			—			72,311			—			72,311

Energy services
Marlin Gas Services	—			3,541			—			3,541			—			—			—			—
PESCO - Natural Gas Marketing	—			118,302			—			118,302						130,357			—			130,357
Total energy services	—			121,843			—			121,843			—			130,357			—			130,357

Other and eliminations
Eliminations	(18,714		)	(8,123		)	(23,773		)	(50,610		)	(18,003		)	(8,494		)	(25,976		)	(52,473		)
Other	—			875			264			1,139			—			999			387			1,386
Total other and eliminations	(18,714		)	(7,248		)	(23,509		)	(49,471		)	(18,003		)	(7,495		)	(25,589		)	(51,087		)

Total operating revenues⁽¹⁾	$	177,021		$	205,007		$	(23,509	)	$	358,519		$	179,897		$	221,712		$	(25,589	)	$	376,020

Contract with Customer, Asset and Liability [Table Text Block]

The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2018 and June 30, 2019 were as follows:



	Trade Receivables			Contract Assets (Current)		Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2018	$	83,214		—		$	2,614	$	480
Balance at 6/30/2019	47,254			18		3,051		316
Increase (decrease)	$	(35,960	)	$	18	$	437	$	(164	)

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

Revenue for these businesses for the remaining performance obligations, at June 30, 2019, are expected to be recognized as follows:



(in thousands)	2019		2020		2021		2022		2023		2024		2025 and thereafter
Eastern Shore and Peninsula Pipeline	$	19,210	$	36,835	$	33,519	$	26,575	$	21,148	$	18,969	$	193,651
Natural gas distribution operations	2,007		3,624		3,403		3,369		2,971		2,957		27,941
PESCO - Natural Gas Marketing	2,903		7,529		1,925		23		—		—		—
FPU electric distribution	149		297		297		109		—		—		—
Total revenue contracts with remaining performance obligations	$	24,269	$	48,285	$	39,144	$	30,076	$	24,119	$	21,926	$	221,592

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

6 Months Ended

Jun. 30, 2019

Rates and Regulatory Activities [Abstract]

Summary of Effects of Federal Tax Reform on Regulated Businesses [Table Text Block]

The following table summarizes the TCJA impact on our regulated businesses:



	Regulatory Liabilities related to ADIT
Operation and Regulatory Jurisdiction	Amount (in thousands)	Status	Status of Customer Rate impact related to lower federal corporate income tax rate
Eastern Shore (FERC)	$34,190	Will be addressed in Eastern Shore's next rate case filing.	Implemented one-time bill credit (totaling $0.9 million) in April 2018. Customer rates adjusted in April 2018.
Delaware Division (Delaware PSC)	$12,906	PSC approved amortization of ADIT in January 2019.	Implemented one-time bill credit (totaling $1.5 million) in April 2019. Customer rates adjusted in March 2019.
Maryland Division (Maryland PSC)	$4,143	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.4 million) in July 2018. Customer rates adjusted effective May 1, 2018.
Sandpiper Energy (Maryland PSC)	$3,790	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.6 million) in July 2018 - Customer rates adjusted effective May 1, 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,318	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.	Florida PSC's final order was issued in February 2019. Excluding GRIP, tax savings arising from the TCJA rate reduction will be retained by the Company. GRIP: Tax savings for 2018 will be refunded to customers in 2020 through the annual GRIP cost recovery mechanism. Future customer GRIP surcharges will be adjusted to reflect tax savings associated with TCJA.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,173	Same treatment on a net basis as Chesapeake Florida Gas Division (above).	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$298	Same treatment on a net basis as Chesapeake Florida Gas Division (above).	Tax rate reduction: The impact was immaterial for the divisions. GRIP (Applicable to Fort Meade division only): Same treatment as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,858	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.	TCJA benefit will flow back to its customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years.

Segment Information (Tables)

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

Schedule of Segment Reporting Information by Segment

The following table presents financial information about our reportable segments:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	70,719		$	67,731		$	171,458		$	173,685
Unregulated Energy	60,184			68,933			187,061			202,335
Total operating revenues, unaffiliated customers	$	130,903		$	136,664		$	358,519		$	376,020
Intersegment Revenues ⁽¹⁾
Regulated Energy	$	2,684		$	2,773		$	5,563		$	6,212
Unregulated Energy	6,720			7,412			17,946			19,377
Other businesses	132			194			264			387
Total intersegment revenues	$	9,536		$	10,379		$	23,773		$	25,976
Operating Income
Regulated Energy	$	18,752		$	14,304		$	47,769		$	41,015
Unregulated Energy	(1,348		)	490			13,628			14,174
Other businesses and eliminations	32			(1,546		)	32			(1,535		)
Operating income	17,436			13,248			61,429			53,654
Other expense, net	(316		)	(262		)	(361		)	(194		)
Interest charges	5,655			3,881			11,365			7,545
Income before Income Taxes	11,465			9,105			49,703			45,915
Income taxes	3,161			2,718			12,735			12,674
Net Income	$	8,304		$	6,387		$	36,968		$	33,241

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



(in thousands)	June 30, 2019		December 31, 2018
Identifiable Assets
Regulated Energy segment	$	1,349,422	$	1,345,805
Unregulated Energy segment	284,888		306,045
Other businesses and eliminations	46,732		41,821
Total identifiable assets	$	1,681,042	$	1,693,671

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) (Tables)

6 Months Ended

Jun. 30, 2019

Equity [Abstract]

Changes in Accumulated Other Comprehensive Loss



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2018	$	(5,928	)	$	(785	)	$	(6,713	)
Other comprehensive income before reclassifications	—			1,000			1,000
Amounts reclassified from accumulated other comprehensive income/(loss)	213			(132		)	81
Net current-period other comprehensive income	213			868			1,081
Prior-year reclassification	—			(115		)	(115		)
As of June 30, 2019	$	(5,715	)	$	(32	)	$	(5,747	)



(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	—			(1,440		)	(1,440		)
Amounts reclassified from accumulated other comprehensive income/(loss)	189			712			901
Net prior-period other comprehensive income/(loss)	189			(728		)	(539		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of June 30, 2018	$	(5,576	)	$	(142	)	$	(5,718	)

Reclassifications out of Accumulated Other Comprehensive Income (Loss)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit ⁽¹⁾	$	19		$	19		$	39		$	39
Net loss⁽¹⁾	(163		)	(149		)	(328		)	(297		)
Total before income taxes	(144		)	(130		)	(289		)	(258		)
Income tax benefit	37			36			76			69
Net of tax	$	(107	)	$	(94	)	$	(213	)	$	(189	)
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements ⁽²⁾	$	252		$	(181	)	$	858		$	(645	)
Natural gas swaps ⁽²⁾	—			(31		)	11			(481		)
Natural gas futures ⁽²⁾	(125		)	(161		)	(698		)	137
Total before income taxes	127			(373		)	171			(989		)
Income tax benefit (expense)	(34		)	105			(39		)	277
Net of tax	93			(268		)	132			(712		)
Total reclassifications for the period	$	(14	)	$	(362	)	$	(81	)	$	(901	)

⁽¹⁾ These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.

⁽²⁾These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.

Employee Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2019 and 2018 are set forth in the following tables:



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended June 30,	2019			2018			2019			2018			2019		2018		2019			2018			2019		2018
(in thousands)
Interest cost	$	104		$	98		$	615		$	592		$	21	$	21	$	9		$	9		$	12	$	13
Expected return on plan assets	(127		)	(138		)	(693		)	(774		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(19		)	(19		)	—		—
Amortization of net loss	101			88			129			108			26		25		12			15			—		—
Net periodic cost (benefit)	78			48			51			(74		)	47		46		2			5			12		13
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	78		$	48		$	242		$	117		$	47	$	46	$	2		$	5		$	14	$	15



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Six Months Ended June 30,	2019			2018			2019			2018			2019		2018		2019			2018			2019		2018
(in thousands)
Interest cost	$	209		$	195		$	1,230		$	1,184		$	42	$	42	$	19		$	19		$	24	$	26
Expected return on plan assets	(254		)	(276		)	(1,386		)	(1,549		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(39		)	(39		)	—		—
Amortization of net loss	203			176			258			217			52		50		24			30			—		—
Net periodic cost (benefit)	158			95			102			(148		)	94		92		4			10			24		26
Amortization of pre-merger regulatory asset	—			—			381			381			—		—		—			—			4		4
Total periodic cost	$	158		$	95		$	483		$	233		$	94	$	92	$	4		$	10		$	28	$	30

Amounts Included in Regulatory asset and AOCI [Table Text Block]



For the Three Months Ended June 30, 2019	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	101		129		26		12			—		268
Total recognized in net periodic benefit cost	101		129		26		(7		)	—		249
Recognized from accumulated other comprehensive loss ⁽¹⁾	101		24		26		(7		)	—		144
Recognized from regulatory asset	—		105		—		—			—		105
Total	$	101	$	129	$	26	$	(7	)	$	—	$	249



For the Three Months Ended June 30, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	88		108		25		15			—		236
Total recognized in net periodic benefit cost	88		108		25		(4		)	—		217
Recognized from accumulated other comprehensive loss ⁽¹⁾	88		21		25		(4		)	—		130
Recognized from regulatory asset	—		87		—		—			—		87
Total	$	88	$	108	$	25	$	(4	)	$	—	$	217



For the Six Months Ended June 30, 2019	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	—		—		—		(39		)	—		(39		)
Net loss	203		258		52		24			—		537
Total recognized in net periodic benefit cost	203		258		52		(15		)	—		498
Recognized from accumulated other comprehensive loss ⁽¹⁾	203		49		52		(15		)	—		289
Recognized from regulatory asset	—		209		—		—			—		209
Total	$	203	$	258	$	52	$	(15	)	$	—	$	498



For the Six Months Ended June 30, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(39	)	$	—	$	(39	)
Net loss	176		217		50		30			—		473
Total recognized in net periodic benefit cost	176		217		50		(9		)	—		434
Recognized from accumulated other comprehensive loss ⁽¹⁾	176		41		50		(9		)	—		258
Recognized from regulatory asset	—		176		—		—			—		176
Total	$	176	$	217	$	50	$	(9	)	$	—	$	434

⁽¹⁾See Note 8, Stockholder's Equity

Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2019

Shares awarded to non-employee directors [Line Items]

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan

The table below presents the amounts included in net income related to share-based compensation expense for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
(in thousands)
Awards to non-employee directors	$	157		$	135		$	305		$	269
Awards to key employees	452			1,190			790			2,575
Total compensation expense	609			1,325			1,095			2,844
Less: tax benefit	(158		)	(363		)	(285		)	(779		)
Share-based compensation amounts included in net income	$	451		$	962		$	810		$	2,065

Awards to non-employee directors [Member]

Shares awarded to non-employee directors [Line Items]

Schedule of Share-based Compensation, Activity



	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2018	—		$	—
Granted	6,759		$	93.14
Vested	(6,759	)	$	93.14
Outstanding—June 30, 2019	—		$	—

Award to key employees [Member]

Shares awarded to non-employee directors [Line Items]

Schedule of Share-based Compensation, Activity

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2019:



	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2018	131,741		$	67.24
Granted	45,016		$	91.19
Vested	(25,831	)	$	67.08
Expired	(15,086	)	$	69.28
Outstanding—June 30, 2019	135,840		$	74.05

Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments [Table Text Block]

As of June 30, 2019, the volume of our open commodity derivative contracts were as follows:



Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
PESCO	Natural gas (Dts)	30.6	Cash flows hedges	October 2023
PESCO	Natural gas (Dts)	5.6	Not designated	October 2022
Sharp	Propane (gallons)	12.1	Cash flows hedges	June 2022

Offsetting Assets and Liabilities [Table Text Block]

The following table summarizes the accounts receivable and payable on a gross and net basis at June 30, 2019 and December 31, 2018:



	At June 30, 2019
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	2,964	$	927	$	2,037
Accounts payable	$	10,418	$	927	$	9,491



	At December 31, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	12,368	$	3,834	$	8,534
Accounts payable	$	24,741	$	3,834	$	20,907

Schedule of Due to (from) Broker-Dealers and Clearing Organizations [Table Text Block]

We maintain separate broker margin accounts for Sharp and PESCO. The balance related to the margin accounts are as follows:



(in thousands)	Balance Sheet Location	At June 30, 2019		At December 31, 2018
Sharp	Other Current Assets	$	1,841	$	2,170
PESCO	Other Current Assets	$	1,592	$	2,810

Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet

The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2019 and December 31, 2018, are as follows:



	Derivative Assets
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2019		December 31, 2018
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative assets, at fair value	$	2,747	$	4,024
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	—		71
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	7,715		9,059
Propane swap agreements	Derivative assets, at fair value	109		11
Total asset derivatives		$	10,571	$	13,165



	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2019		December 31, 2018
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	3,144	$	4,562
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	6,663		8,705
Propane swap agreements	Derivative liabilities, at fair value	1,187		1,604
Total liability derivatives		$	10,994	$	14,871

Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:



		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2019			2018			2019			2018
Derivatives not designated as hedging instruments
Natural gas futures contracts	Cost of sales	$	28		$	(128	)	$	6		$	(2,963	)
Propane swap agreements	Cost of sales	—			(4		)	—			(13		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	252			(181		)	858			(645		)
Propane swap agreements	Other comprehensive income (loss)	(494		)	106			515			(886		)
Natural gas futures contracts	Cost of sales	(125		)	(161		)	(698		)	137
Natural gas swap contracts	Cost of sales	—			(31		)	11			(481		)
Natural gas swap contracts	Other comprehensive income (loss)	(2,463		)	523			763			588
Natural gas futures contracts	Other comprehensive income (loss)	(8		)	861			(67		)	(871		)
Total		$	(2,810	)	$	985		$	1,388		$	(5,134	)

Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

As of June 30, 2019, the following amounts were recorded in the condensed consolidated balance sheets related to fair value hedges:



(in thousands)	Carrying Amount of Hedged Item				Cumulative Adjustment Included in Carrying Amount of Hedged Item
Balance Sheet Location of Hedged Items	At June 30, 2019		At December 31, 2018		At June 30, 2019		At December 31, 2018
Inventory	$	—	$	212	$	—	$	—

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=109980867&loc=SL5624163-113959

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=109980867&loc=SL5580258-113959

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=109980867&loc=d3e41620-113959

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=109980867&loc=SL5579245-113959

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=109980867&loc=d3e41638-113959

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=109980867&loc=d3e41678-113959

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=109980867&loc=d3e41641-113959

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=109980867&loc=SL5624171-113959

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=109980867&loc=SL5579240-113959

+ Details

Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Financial Assets and Liabilities Measured at Fair Value on Recurring Basis



			Fair Value Measurements Using:
As of June 30, 2019	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	$	26	$	26	$	—	$	—
Investments—guaranteed income fund	791		—		—		791
Investments—mutual funds and other	8,004		8,004		—		—
Total investments	8,821		8,030		—		791
Derivative assets	10,571		—		10,571		—
Total assets	$	19,392	$	8,030	$	10,571	$	791
Liabilities:
Derivative liabilities	$	10,994	$	—	$	10,994	$	—



			Fair Value Measurements Using:
As of December 31, 2018	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	686		—		—		686
Investments—mutual funds and other	6,003		6,003		—		—
Total investments	6,711		6,025		—		686
Derivative assets	13,165		—		13,165		—
Total assets	$	19,876	$	6,025	$	13,165	$	686
Liabilities:
Derivative liabilities	$	14,871	$	—	$	14,871	$	—

Summary of Changes in Fair Value of Investments

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2019 and 2018:



	Six Months Ended June 30,
	2019			2018
(in thousands)
Beginning Balance	$	686		$	648
Purchases and adjustments	110			54
Transfers	—			(24		)
Distribution	(12		)	(12		)
Investment income	7			5
Ending Balance	$	791		$	671

Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2019

Schedule of Line of Credit Facilities [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

The following table summarizes the borrowing information under our Shelf Agreements at June 30, 2019:



	Total Borrowing Capacity		Less: Amount of Debt Issued			Less: Unfunded Commitments			Remaining Borrowing Capacity
(in thousands)
Shelf Agreement
Prudential Shelf Agreement	$	220,000	$	(70,000	)	$	(100,000	)	$	50,000
MetLife Shelf Agreement	150,000		—			—			150,000
NYL Shelf Agreement	150,000		(100,000		)	—			50,000
Total	$	520,000	$	(170,000	)	$	(100,000	)	$	250,000

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:



	June 30,			December 31,
(in thousands)	2019			2018
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,988		$	7,986
Uncollateralized senior notes:
5.50% note, due October 12, 2020	4,000			4,000
5.93% note, due October 31, 2023	13,500			15,000
5.68% note, due June 30, 2026	20,300			23,200
6.43% note, due May 2, 2028	6,300			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			70,000
3.48% note, due May 31, 2038	50,000			50,000
3.58% note, due November 30, 2038	50,000			50,000
Term Note due January 21, 2020	30,000			30,000
Term Note due February 28, 2020	30,000			—
Promissory notes	—			26
Finance lease obligation	—			1,310
Less: debt issuance costs	(564		)	(567		)
Total long-term debt	351,524			327,955
Less: current maturities	(75,600		)	(11,935		)
Total long-term debt, net of current maturities	$	275,924		$	316,020

⁽¹⁾ FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.

Leases Leases (Tables)

6 Months Ended

Jun. 30, 2019

Lease Disclosure [Abstract]

Lease, Cost [Table Text Block]

The following table presents information related to our total lease cost included in our condensed consolidated statements of income:



		Three Months Ended				Six Months Ended
		June 30,				June 30,
( in thousands)	Classification	2019		2018		2019		2018
Operating lease cost ⁽¹⁾	Operations expense	$	654	$	698	$	1,288	$	1,805
Finance lease cost:
Amortization of lease assets	Depreciation and amortization	249		361		650		719
Interest on lease liabilities	Interest expense	1		14		5		31
Net lease cost		$	904	$	1,073	$	1,943	$	2,555

⁽¹⁾ Includes short-term leases and variable lease costs, which are immaterial

Schedule of Leases Reported on Consolidated Statement of Financial Position [Table Text Block]

The following table presents the balance and classifications of our right of use assets and lease liabilities included in our condensed consolidated balance sheet at June 30, 2019:



(in thousands)	Balance sheet classification	Amount
Assets
Operating lease assets	Operating lease right-of-use assets	$	12,404
Total lease assets		$	12,404
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,704
Noncurrent
Operating lease liabilities	Operating lease - liabilities	10,710
Total lease liabilities		$	12,414

Leases, Weighted Average Remaining Lease Term [Table Text Block]

The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating and financing leases at June 30, 2019:



	At June 30, 2019
Weighted-average remaining lease term (in years)
Operating leases	9.13
Weighted-average discount rate
Operating leases	3.8	%

Lease, Cash Flow [Table Text Block]



	Six Months Ended
	June 30,
(in thousands)	2019		2018
Operating cash flows from operating leases	$	1,100	$	1,715
Operating cash flows from finance leases	$	5	$	31
Financing cash flows from finance leases	$	650	$	719

Schedule of Maturities of Leases [Table Text Block]

The following table presents the future undiscounted maturities of our operating and financing leases at June 30, 2019 and for each of the next five years and thereafter:



(in thousands)	Operating Leases ⁽¹⁾		Finance Leases		Total
Remainder of 2019	$	1,089	$	—	$	1,089
2020	2,091		—		2,091
2021	1,852		—		1,852
2022	1,691		—		1,691
2023	1,695		—		1,695
2024	1,451		—		1,451
Thereafter	4,916		—		4,916
Total lease payments	$	14,785	$	—	$	14,785
Less: Interest	2,371		—		2,371
Present value of lease liabilities	$	12,414	$	—	12,414

⁽¹⁾ Operating lease payments include $3.9 million related to options to extend lease terms that are reasonably certain of being exercised.

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

The following table presents future minimum lease payments for our operating leases at December 31, 2018 under ASC 840 and is being presented for comparative purposes:



Year(s)	2019	2020	2021	2022	2023	Thereafter	Total
(in thousands)
Expected payments	$2,349	$1,998	$1,761	$1,689	$1,642	$5,398	$14,837

Summary of Accounting Policies Acquisitions Additional information (Details) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
Revenues	$ 130,903	$ 136,664	$ 358,519	$ 376,020
Operating Income (Loss)	17,436	13,248	61,429	53,654
Marlin and Ohl [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred					$ 18,400
Marlin [Member]
Business Acquisition [Line Items]
Revenues	1,108		3,541
Operating Income (Loss)	48		1,423
Ohl [Member]
Business Acquisition [Line Items]
Revenues	174		997
Operating Income (Loss)	(61)		212
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments	200		200
Unregulated Energy [Member]
Business Acquisition [Line Items]
Operating Income (Loss)	$ (1,348)	$ 490	$ 13,628	$ 14,174
Unregulated Energy [Member] \| Marlin [Member]
Business Acquisition [Line Items]
Goodwill, Acquired During Period					4,800
Unregulated Energy [Member] \| Ohl [Member]
Business Acquisition [Line Items]
Goodwill, Acquired During Period					$ 1,500
Number of customers acquired through acquisition					2,500

Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Calculation of Basic Earnings Per Share:
Net Income	$ 8,304	$ 28,664	$ 6,387	$ 26,854	$ 36,968	$ 33,241
Weighted shares outstanding (shares)	16,401,028		16,369,641		16,393,022	16,360,540
Basic Earnings Per Share (in dollars per share)	$ 0.51		$ 0.39		$ 2.26	$ 2.03
Reconciliation of Numerator:
Net Income	$ 8,304	$ 28,664	$ 6,387	$ 26,854	$ 36,968	$ 33,241
Reconciliation of Denominator:
Weighted shares outstanding - Basic (shares)	16,401,028		16,369,641		16,393,022	16,360,540
Effect of dilutive securities:
Share-based compensation (shares)	44,715		47,441		46,311	49,521
Adjusted denominator-Diluted (shares)	16,445,743		16,417,082		16,439,333	16,410,061
Diluted Earnings Per Share (in dollars per share)	$ 0.50		$ 0.39		$ 2.25	$ 2.03

Revenue Recognition Disegragation of Revenue (Details) - USD ($)

3 Months Ended

6 Months Ended

Jun. 30, 2019

Jun. 30, 2018

Jun. 30, 2019

Jun. 30, 2018

Revenue from Contract with Customer, Excluding Assessed Tax

Revenues

$ 130,903,000

$ 136,664,000

$ 358,519,000

$ 376,020,000

130,903,000

^[1]

136,664,000

^[1]

358,519,000

^[2]

376,020,000

^[2]

Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

73,403,000

^[1]

70,504,000

^[1]

177,021,000

^[2]

179,897,000

^[2]

Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

66,904,000

^[1]

76,345,000

^[1]

205,007,000

^[2]

221,712,000

^[2]

Other Segments And Intersegments Eliminations [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

(9,404,000)

(10,185,000)

(23,509,000)

(25,589,000)

Other [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

(9,404,000)

^[1]

(10,185,000)

^[1]

(23,509,000)

^[2]

(25,589,000)

^[2]

Consolidation, Eliminations [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

(20,530,000)

(23,104,000)

(49,471,000)

(51,087,000)

Eliminations [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

(8,968,000)

(10,176,000)

(18,714,000)

(18,003,000)

Other [Member] | Regulated Energy [Member]

Other [Member] | Unregulated Energy [Member]

Revenues

(300,000)

(400,000)

(200,000)

(900,000)

Revenue from Contract with Customer, Excluding Assessed Tax

Revenues

100,000

200,000

(2,158,000)

(2,743,000)

(7,248,000)

(7,495,000)

Energy Distribution [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

61,066,000

63,210,000

151,808,000

162,735,000

Energy Distribution [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

61,066,000

63,210,000

151,808,000

162,735,000

Energy Distribution [Member] | Delaware natural gas division [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

8,256,000

11,882,000

35,805,000

43,954,000

Energy Distribution [Member] | Delaware natural gas division [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

8,256,000

11,882,000

35,805,000

43,954,000

Energy Distribution [Member] | Central Florida Gas Division [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

7,015,000

6,317,000

14,915,000

12,180,000

Energy Distribution [Member] | Central Florida Gas Division [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

7,015,000

6,317,000

14,915,000

12,180,000

Energy Distribution [Member] | FPU Electric Distribution [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

20,464,000

18,362,000

34,842,000

37,103,000

Energy Distribution [Member] | FPU Electric Distribution [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

20,464,000

18,362,000

34,842,000

37,103,000

Energy Distribution [Member] | Florida Public Utilities Company [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

18,663,000

18,281,000

42,449,000

41,494,000

Energy Distribution [Member] | Florida Public Utilities Company [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

18,663,000

18,281,000

42,449,000

41,494,000

Energy Distribution [Member] | Maryland Natural Gas [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

3,186,000

4,001,000

13,233,000

14,673,000

Energy Distribution [Member] | Maryland Natural Gas [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

3,186,000

4,001,000

13,233,000

14,673,000

Energy Distribution [Member] | Sandpiper [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

3,482,000

4,367,000

10,564,000

13,331,000

Energy Distribution [Member] | Sandpiper [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

3,482,000

4,367,000

10,564,000

13,331,000

Energy Transmission [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

26,726,000

23,324,000

62,819,000

53,096,000

Energy Transmission [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

21,305,000

17,470,000

43,927,000

35,165,000

Energy Transmission [Member] | Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

5,421,000

5,854,000

18,892,000

17,931,000

Energy Transmission [Member] | Aspire [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

5,421,000

5,854,000

18,892,000

17,931,000

Energy Transmission [Member] | Aspire [Member] | Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

5,421,000

5,854,000

18,892,000

17,931,000

Energy Transmission [Member] | Eastern Shore Gas Company [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

17,740,000

14,502,000

36,796,000

30,100,000

Energy Transmission [Member] | Eastern Shore Gas Company [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

17,740,000

14,502,000

36,796,000

30,100,000

Energy Transmission [Member] | Peninsula Pipeline [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

3,565,000

2,968,000

7,131,000

5,065,000

Energy Transmission [Member] | Peninsula Pipeline [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

3,565,000

2,968,000

7,131,000

5,065,000

Energy Generation [Member] | Eight Flags [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

4,235,000

4,230,000

8,377,000

8,608,000

Energy Generation [Member] | Eight Flags [Member] | Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

4,235,000

4,230,000

8,377,000

8,608,000

Propane Delivery [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

17,018,000

20,206,000

63,143,000

72,311,000

Propane Delivery [Member] | Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

17,018,000

20,206,000

63,143,000

72,311,000

Energy Services [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

42,388,000

48,798,000

121,843,000

130,357,000

Energy Services [Member] | Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

42,388,000

48,798,000

121,843,000

130,357,000

Energy Services [Member] | Marlin Gas Services [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

1,108,000

3,541,000

Energy Services [Member] | Marlin Gas Services [Member] | Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

1,108,000

3,541,000

Energy Services [Member] | PESCO [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

41,280,000

48,798,000

118,302,000

130,357,000

Energy Services [Member] | PESCO [Member] | Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

41,280,000

48,798,000

118,302,000

130,357,000

Eliminations [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

(21,132,000)

(23,803,000)

(50,610,000)

(52,473,000)

Eliminations [Member] | Regulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

(8,968,000)

(10,176,000)

(18,714,000)

(18,003,000)

Eliminations [Member] | Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

(2,628,000)

(3,248,000)

(8,123,000)

(8,494,000)

Eliminations [Member] | Eliminations [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

(9,536,000)

(10,379,000)

(23,773,000)

(25,976,000)

Other [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

602,000

699,000

1,139,000

1,386,000

Other [Member] | Unregulated Energy [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

470,000

505,000

875,000

999,000

Other [Member] | Other [Member]

Revenue from Contract with Customer, Excluding Assessed Tax

$ 132,000

$ 194,000

$ 264,000

$ 387,000

[1]

[2]

Revenue Recognition Contract Balances with Customers (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 47,254		$ 47,254		$ 83,214
Contract with Customer, Asset, Net, Current	18		18
Contract with Customer, Asset, Net, Noncurrent	3,051		3,051		2,614
Contract with Customer, Liability, Current	316		316		$ 480
Increase (Decrease) in Receivables			(35,960)
Increase (Decrease) in Other Current Assets			18
Increase (Decrease) in Other Noncurrent Assets			437
Increase (Decrease) in Other Current Liabilities			(164)
Contract with Customer, Liability, Revenue Recognized	$ 200	$ 100	$ 500	$ 300

Rates and Other Regulatory Activities - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2019 USD ($) kWh customer Dekatherm mi
Rates and Other Regulatory Activities [Line Items]
Depreciation Expense Decrease from Depreciation Study Rate Change	$ 300,000
Electric Limited Proceedings [Member]
Rates and Other Regulatory Activities [Line Items]
Dollar Amount of Term Notes to Finance Hurricane Michael Costs	$ 30,000,000
Extent of Customers Losing Service	100.00%
Basis Plus LIBOR for Term Notes to Finance Hurricane Michael Costs	75
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 1.54
Asset Recovery Damaged Property Costs, Noncurrent	1,500,000
Deferred Storm and Property Reserve Deficiency, Noncurrent	$ 800,000
Public Utilities Approved Rate Increase (Decrease), Units \| kWh	1,000
Number of Years to Recover Storm Related Costs	2 years
Number of Months for Term Notes to Finance Hurricane Michael	13 months
Amounts Spent to Restore Service	$ 65,000,000
Number of Term Notes to Finance Hurricane Michael	2
Del-Mar Pathway Project [Member] \| Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Mainline Pipeline Miles \| mi	13
Additional Firm Natural Gas Transportation Deliverability \| Dekatherm	14,300
number of customers \| customer	4
Number of Pipeline Miles \| mi	6
Fort Meade and Indiantown Divisions [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	$ 298,000
Delaware natural gas division [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	1,500,000
Regulatory Liabilities	12,906,000
Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	900,000
Regulatory Liabilities	34,190,000
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	19,173,000
Central Florida Gas Division [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	8,318,000
Maryland Division [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	400,000
Regulatory Liabilities	4,143,000
Sandpiper [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	600,000
Regulatory Liabilities	3,790,000
FPU electric division [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	$ 5,858,000

Environmental Commitments and Contingencies - Additional Information (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2019 USD ($) site	Dec. 31, 2018 USD ($)
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites \| site	7
Environmental liabilities	$ 6,994,000	$ 7,638,000
West Palm Beach Florida [Member] \| Minimum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	4,500,000
West Palm Beach Florida [Member] \| Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	15,400,000
Winter Haven Florida [Member] \| Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	400,000
Seaford [Member] \| Minimum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	200,000
Seaford [Member] \| Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	500,000
FPU [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	8,500,000	9,100,000
Approval of recovery of environmental costs	14,000,000.0
Environmental costs recovered	11,700,000	11,500,000
FPU [Member] \| Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets for future recovery of environmental costs	$ 2,300,000	$ 2,500,000

Other Commitments and Contingencies - Additional Information (Detail) $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2019	Jun. 30, 2019 USD ($)
Other Commitments [Line Items]
Debt Service Coverage Ratio		1.25
Debt Service Coverage Ratio Measurement Period		12
Maximum Days To Make Default Good		5 days
Ratio based on average number of prior quarters		6
Ratios based on average of the prior quarters	1 year 6 months
Funds from operations interest coverage ratio minimum times		2
Total debt to capital maximum		0.65
Number Of Years For Power Purchase Agreement		20 years
Contract Duration		20 years
Aggregate guaranteed amount		$ 68.1
Draws on letters of credit		$ 7.0
Florida Natural Gas Distribution and Eight Flags [Member]
Other Commitments [Line Items]
Number of Years for Asset Management Agreement		10 years
Delmarva [Member]
Other Commitments [Line Items]
Number of Years for Asset Management Agreement		3 years

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

3 Months Ended

6 Months Ended

Jun. 30, 2019

USD ($)

Mar. 31, 2019

USD ($)

Jun. 30, 2018

USD ($)

Mar. 31, 2018

USD ($)

Jun. 30, 2019

USD ($)

Jun. 30, 2018

USD ($)

Dec. 31, 2018

USD ($)

Segment Reporting Information [Line Items]

Number of Reportable Segments

$ 130,903

$ 136,664

$ 358,519

$ 376,020

Income Before Income Taxes

17,436

13,248

61,429

53,654

Other expense, net

(316)

(262)

(361)

(194)

Interest

5,655

3,881

11,365

7,545

11,465

9,105

49,703

45,915

Income taxes

3,161

2,718

12,735

12,674

8,304

$ 28,664

6,387

$ 26,854

36,968

33,241

Regulated Energy [Member]

1,681,042

$ 1,693,671

18,752

14,304

47,769

41,015

Unregulated Energy [Member]

1,349,422

1,345,805

(1,348)

490

13,628

14,174

284,888

306,045

Other [Member]

Other and eliminations [Member]

46,732

$ 41,821

Operating Revenues, Unaffiliated Customers [Member]

(1,546)

(1,535)

Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]

130,903

136,664

358,519

376,020

Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]

70,719

67,731

171,458

173,685

Intersegment Revenues [Member]

60,184

68,933

187,061

202,335

Intersegment Revenues [Member] | Regulated Energy [Member]

^[1]

9,536

10,379

23,773

25,976

Intersegment Revenues [Member] | Unregulated Energy [Member]

^[1]

2,684

2,773

5,563

6,212

Intersegment Revenues [Member] | Other [Member]

^[1]

6,720

7,412

17,946

19,377

Amortization of pension and postretirement items:

^[1]

$ 132

$ 194

$ 264

$ 387

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

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	$ (6,713)	$ (4,272)	$ (6,713)	$ (4,272)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			1,000	(1,440)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			81	901
Net current-period other comprehensive income (loss)			1,081	(539)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect		0
Ending balance			(5,747)	(5,718)
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	(5,928)	(4,743)	(5,928)	(4,743)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			213	189
Net current-period other comprehensive income (loss)			213	189
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect				(1,022)
Ending balance			(5,715)	(5,576)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	(785)	471	(785)	471
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			1,000	(1,440)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			(132)	712
Net current-period other comprehensive income (loss)			868	(728)
Prior Period Reclassification Adjustment			(115)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect				115
Ending balance			(32)	(142)
AOCI Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Prior Period Reclassification Adjustment	$ (115)		$ (115)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect		$ (907)		$ (907)

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($)
$ in Thousands

3 Months Ended

6 Months Ended

Jun. 30, 2019

Jun. 30, 2018

Jun. 30, 2019

Jun. 30, 2018

Tax benefit

$ (3,161)

$ (2,718)

$ (12,735)

$ (12,674)

Reclassification out of Accumulated Other Comprehensive Income [Member]

Amortization of pension and postretirement items:

Net of tax

(14)

(362)

(81)

(901)

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

Amortization of pension and postretirement items:

Prior service cost

^[1]

Net loss

^[1]

(163)

(149)

(328)

(297)

Total before tax

(144)

(130)

(289)

(258)

Tax benefit

Net of tax

(107)

(94)

(213)

(189)

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

Amortization of pension and postretirement items:

Total before tax

127

(373)

171

(989)

Tax benefit

(34)

105

(39)

277

Net of tax

(268)

132

(712)

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

Amortization of pension and postretirement items:

Other Comprehensive Income Loss Adjustments AOCI Swap Agreements

^[2]

252

(181)

858

(645)

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

Amortization of pension and postretirement items:

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

^[2]

(31)

(481)

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

Amortization of pension and postretirement items:

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

^[2]

$ (125)

$ (161)

$ (698)

$ 137

[1]	These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.
[2]	These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.

Employee Benefit Plans (Detail) - USD ($)
$ in Thousands

3 Months Ended

6 Months Ended

Jun. 30, 2019

Jun. 30, 2018

Jun. 30, 2019

Jun. 30, 2018

Dec. 31, 2018

Defined Benefit Plan, Plan Assets, Contributions by Employer

$ 100

Expected Amortization Of Pre Merger Regulatory Asset

600

Amortization of prior service cost

$ (19)

(39)

$ (39)

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

268

236

537

473

Defined Benefit Plan Amounts Recognized Gain (Loss)

249

217

498

434

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax

^[1]

144

130

289

258

Defined Benefit Plan Amounts Recognized From Regulatory Asset

105

209

176

Chesapeake Pension Plan [Member]

Defined Benefit Plan, Plan Assets, Contributions by Employer

100

Expected return on plan assets

104

209

195

(127)

(138)

(254)

(276)

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

101

203

176

^[1]

158

Defined Benefit Plan Amounts Recognized Gain (Loss)

158

101

203

176

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax

^[1]

101

203

176

Florida Public Utilities Company Pension Plan [Member]

Defined Benefit Plan, Plan Assets, Contributions by Employer

400

600

Expected Amortization Of Pre Merger Regulatory Asset

200

$ 600

Expected return on plan assets

615

592

1,230

1,184

(693)

(774)

(1,386)

(1,549)

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

129

108

258

217

Amortization of pre-merger regulatory asset

^[1]

(74)

102

(148)

191

381

Defined Benefit Plan Amounts Recognized Gain (Loss)

242

117

483

233

129

108

258

217

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax

^[1]

Defined Benefit Plan Amounts Recognized From Regulatory Asset

105

209

176

Chesapeake Pension SERP [Member]

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

^[1]

Defined Benefit Plan Amounts Recognized Gain (Loss)

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax

^[1]

Chesapeake Postretirement Plan [Member]

Amortization of prior service cost

(19)

(39)

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

^[1]

Defined Benefit Plan Amounts Recognized Gain (Loss)

(7)

(4)

(15)

(9)

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax

^[1]

(7)

(4)

(15)

(9)

Florida Public Utilities Company Medical Plan [Member]

Amortization of pre-merger regulatory asset

^[1]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

$ 14

$ 15

$ 28

$ 30

[1]	See Note 8, Stockholder's Equity.

Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Expected pension and postretirement benefit costs		$ 1,300
Expected amortization of pre merger regulatory asset		600
Contribution to pension plan		100
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Unamortized balance of regulatory asset	$ 200	200	$ 600
Contribution to pension plan	400	600
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	1,200	1,200
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan		100
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	200	200
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	400	400
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	100	100
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	$ 100	$ 100

Employee Benefit Plans - Amounts Included in Regulatory Asset and Accumulated Other Comprehensive Income/Loss Recognized as Net Periodic Benefit Cost (Detail) - USD ($)
$ in Thousands

3 Months Ended

6 Months Ended

Jun. 30, 2019

Jun. 30, 2018

Jun. 30, 2019

Jun. 30, 2018

Prior service cost (credit)

$ (19)

$ (39)

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

268

236

537

473

Recognized from accumulated other comprehensive loss

^[1]

144

130

289

258

Recognized from regulatory asset

105

209

176

Chesapeake Pension Plan [Member]

249

217

498

434

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

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

101

203

176

Recognized from accumulated other comprehensive loss

^[1]

101

203

176

Florida Public Utilities Company Pension Plan [Member]

101

203

176

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

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

129

108

258

217

Recognized from accumulated other comprehensive loss

^[1]

Recognized from regulatory asset

105

209

176

Chesapeake Pension SERP [Member]

129

108

258

217

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

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

Recognized from accumulated other comprehensive loss

^[1]

Chesapeake Postretirement Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Prior service cost (credit)

(19)

(39)

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

Recognized from accumulated other comprehensive loss

^[1]

(7)

(4)

(15)

(9)

$ (7)

$ (4)

$ (15)

$ (9)

[1]	See Note 8, Stockholder's Equity.

Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
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, Grants in Period			751
Total compensation expense	$ 609	$ 1,325	$ 1,095	$ 2,844
Less: tax benefit	(158)	(363)	(285)	(779)
Share-Based Compensation amounts included in net income	451	962	$ 810	2,065
Awards to non-employee directors [Member]
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, Grants in Period			6,759
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			6,759
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value			$ 93.14
Total compensation expense	$ 157	135	$ 305	269
Award to key employees [Member]
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, Nonvested, Number	135,840		135,840		131,741
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			45,016
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			25,831
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period			15,086
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 74.05		$ 74.05		$ 67.24
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value			91.19
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value			67.08
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expirations Weighted Average Grant Date Fair Value			$ 69.28
Total compensation expense	$ 452	$ 1,190	$ 790	$ 2,575

Share-Based Compensation - Summary of Stock Activity under the SICP (Detail)	6 Months Ended
	Jun. 30, 2019 $ / shares shares
Number of Shares
Granted awards (shares)	751
Awards to non-employee directors [Member]
Number of Shares
Granted awards (shares)	6,759
Vested (shares)	(6,759)
Weighted Average Fair Value
Granted (in dollars per share) \| $ / shares	$ 93.14

Share-Based Compensation - Additional Information (Detail) $ / shares in Units, $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019 USD ($) shares	Jun. 30, 2019 USD ($) $ / shares shares	Jun. 30, 2018 USD ($) yr shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares)		751
Shares Paid for Tax Withholding for Share Based Compensation	6,482	7,635	16,918
Payments Related to Tax Withholding for Share-based Compensation \| $		$ 692	$ 1,210
Unrecognized compensation cost \| $	$ 3,800	$ 3,800
Awards to non-employee directors [Member]
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, Grants in Period, Weighted Average Grant Date Fair Value \| $ / shares		$ 93.14
Amortization of expense equally over a service period		1 year
Granted awards (shares)		6,759
Unrecognized compensation expense related to the awards to non-employee directors \| $	500	$ 500
Awards to non-employee director [Member]
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, Grants in Period, Weighted Average Grant Date Fair Value \| $ / shares		$ 75.70
Granted awards (shares)		276
Award to key employees [Member]
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 Expired In Period		15,086
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value \| $ / shares		$ 91.19
Granted awards (shares)		45,016
Vesting period		3 years
Payments Related to Tax Withholding for Share-based Compensation \| $		$ 700
Intrinsic value of the SICP awards \| $	$ 12,900	$ 12,900
Accelerated Vested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares Paid for Tax Withholding for Share Based Compensation		7,635
Accelerated Vested Shares [Member] \| Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Multi year Awards \| yr			3
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number			14,107
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period			2,569
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost \| $			$ 1,100

Derivative Instruments Volume of Derivative Activity (Details) $ in Thousands, gal in Millions, Mcf in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) gal Mcf
PESCO [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months \| $	$ (500)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimate of Time to Transfer	12 months
PESCO [Member] \| Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| Mcf	30.6
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months \| $	$ (1,000)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimate of Time to Transfer	12 months
Sharp Energy Inc [Member] \| Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal	12.1
Not Designated as Hedging Instrument [Member] \| PESCO [Member] \| Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| Mcf	5.6

Derivative Instruments - Additional Information (Detail) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	$ 927	$ 3,834
Accounts Payable Subject To Master Netting Arrangement	927	3,834
Energy Marketing Contracts Assets, Current	10,571	13,165
Energy Marketing Contract Liabilities, Current	(10,994)	(14,871)
Derivative, Amount of Hedged Item	0	212
Hedging Liability [Member] \| Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	(6,663)	(8,705)
Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets [Member] \| Put Option [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	0	71
Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets [Member] \| Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	7,715	9,059
Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets [Member] \| Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	109	11
Designated as Hedging Instrument [Member] \| Mark-to-market energy liabilities [Member] \| Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	(1,187)	(1,604)
Not Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets [Member] \| Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	2,747	4,024
Not Designated as Hedging Instrument [Member] \| Mark-to-market energy liabilities [Member] \| Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	(3,144)	(4,562)
Sharp Energy Inc [Member]
Derivative [Line Items]
Other Receivables from Broker-Dealers and Clearing Organizations	1,841	2,170
PESCO [Member]
Derivative [Line Items]
Other Receivables from Broker-Dealers and Clearing Organizations	1,592	2,810
Gross [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	2,964	12,368
Accounts Payable Subject To Master Netting Arrangement	10,418	24,741
Net [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	2,037	8,534
Accounts Payable Subject To Master Netting Arrangement	$ 9,491	$ 20,907

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 10,571	$ 13,165
Energy Marketing Contract Liabilities, Current	10,994	14,871
Mark To Market Energy Assets [Member] \| Natural Gas Futures [Member] \| Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	2,747	4,024
Mark To Market Energy Assets [Member] \| Natural Gas Futures [Member] \| Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	7,715	9,059
Mark To Market Energy Assets [Member] \| Put Option [Member] \| Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	0	71
Mark To Market Energy Assets [Member] \| Propane Swap Agreement [Member] \| Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	109	11
Mark-to-market energy liabilities [Member] \| Natural Gas Futures [Member] \| Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	3,144	4,562
Mark-to-market energy liabilities [Member] \| Propane Swap Agreement [Member] \| Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	1,187	1,604
Hedging Liability [Member] \| Natural Gas Futures [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 6,663	$ 8,705

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ (2,810,000)	$ 985,000	$ 1,388,000	$ (5,134,000)
Cost of Sales [Member] \| Derivatives not designated as hedging instruments [Member] \| Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	28,000	(128,000)	6,000	(2,963,000)
Cost of Sales [Member] \| Derivatives not designated as hedging instruments [Member] \| Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	(4,000)	0	(13,000)
Cost of Sales [Member] \| Derivatives designated as hedging instrument [Member] \| Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(125,000)	(161,000)	(698,000)	137,000
Cost of Sales [Member] \| Derivatives designated as hedging instrument [Member] \| Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	(31,000)	11,000	(481,000)
Cost of Sales [Member] \| Derivatives designated as hedging instrument [Member] \| Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	252,000	(181,000)	858,000	(645,000)
Other Comprehensive Income (Loss) [Member] \| Derivatives designated as hedging instrument [Member] \| Natural Gas Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	(2,463,000)	523,000	763,000	588,000
Other Comprehensive Income (Loss) [Member] \| Derivatives designated as hedging instrument [Member] \| Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	(494,000)	106,000	515,000	(886,000)
Other Comprehensive Income (Loss) [Member] \| Derivatives designated as hedging instrument [Member] \| Natural Gas Futures [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	$ (8,000)	$ 861,000	$ (67,000)	$ (871,000)

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Assets:
Investments	$ 8,821	$ 6,711
Energy Marketing Contracts Assets, Current	10,571	13,165
Liabilities:
Energy Marketing Contract Liabilities, Current	10,994	14,871
Equity Securities [Member]
Assets:
Investments	26	22
Quoted Prices in Active Markets (Level 1) [Member]
Assets:
Assets, Fair Value Disclosure	8,030	6,025
Quoted Prices in Active Markets (Level 1) [Member] \| Equity Securities [Member]
Assets:
Investments	26	22
Quoted Prices in Active Markets (Level 1) [Member] \| Investments - Mutual funds and other [Member]
Assets:
Investments	8,004	6,003
Quoted Prices in Active Markets (Level 1) [Member] \| Total Investments [Member]
Assets:
Investments	8,030	6,025
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Assets, Fair Value Disclosure	10,571	13,165
Liabilities:
Energy Marketing Contract Liabilities, Current	10,994
Significant Other Observable Inputs (Level 2) [Member] \| Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	10,571
Significant Unobservable Inputs (Level 3) [Member]
Assets:
Assets, Fair Value Disclosure	791	686
Significant Unobservable Inputs (Level 3) [Member] \| Investments in guaranteed income fund [Member]
Assets:
Investments	791	686
Significant Unobservable Inputs (Level 3) [Member] \| Total Investments [Member]
Assets:
Investments	791	686
Recurring [Member]
Assets:
Assets, Fair Value Disclosure	19,392	19,876
Liabilities:
Energy Marketing Contract Liabilities, Current	10,994	14,871
Recurring [Member] \| Equity Securities [Member]
Assets:
Investments	26	22
Recurring [Member] \| Investments in guaranteed income fund [Member]
Assets:
Investments	791	686
Recurring [Member] \| Investments - Mutual funds and other [Member]
Assets:
Investments	8,004	6,003
Recurring [Member] \| Total Investments [Member]
Assets:
Investments	8,821	6,711
Recurring [Member] \| Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	$ 10,571	$ 13,165

Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	$ 12	$ 12
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	686	648
Purchases and adjustments	110	54
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	0	24
Investment Income	7	5
Ending Balance	$ 791	$ 671

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($)
$ in Thousands

Jun. 30, 2019

Dec. 31, 2018

$ (352,100)

$ (327,200)

Less: debt issuance costs

250,000

Finance lease obligation

1,310

Total Long-term debt

351,524

327,955

Less: current maturities

(75,600)

(11,935)

564

567

Total long-term debt, net of current maturities

275,924

316,020

Aggregated Unfunded Commitments [Member]

Prudential Unfunded Commitments [Member]

(100,000)

(100,000)

New York Life [Member]

9.08% bond, due June 1, 2022 [Member]

(100,000)

5.50% note, due October 12, 2020 [Member]

^[1]

(7,988)

(7,986)

5.93% note, due October 31, 2023 [Member]

(4,000)

5.68% note, due June 30, 2026 [Member]

(13,500)

(15,000)

6.43% note, due May 2, 2028 [Member]

(20,300)

(23,200)

3.73% note, due December 16, 2028 [Member]

(6,300)

(7,000)

3.88% note, due May 15, 2029 [Member]

(20,000)

3.25% note, due April 30, 2032 [Member]

(50,000)

3.48% note, due May 31, 2038 [Member]

(70,000)

Uncollateralized Senior Note Due November Two Thousand Thirty Eight [Member]

(50,000)

Term Note Due January Two Thousand Twenty [Member]

(50,000)

Term Note Due February Two Thousand Twenty [Member]

(30,000)

(30,000)

Promissory note [Member]

Aggregate Shelf Agreements [Member]

$ (26)

Aggregate Shelf Agreements [Member] | Maximum [Member]

(170,000)

520,000

Prudential [Member]

(70,000)

Prudential [Member] | Maximum [Member]

50,000

220,000

MetLife [Member]

MetLife [Member] | Maximum [Member]

150,000

150,000

New York Life [Member]

100,000

New York Life [Member] | Maximum [Member]

50,000