Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2017 | Oct. 31, 2017 | |
Document Document And Entity Information [Abstract] | ||
Entity Registrant Name | CHESAPEAKE UTILITIES CORP | |
Trading Symbol | CPK | |
Entity Central Index Key | 19,745 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 16,344,442 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Operating Revenues | ||||
Regulated Energy | $ 69,703 | $ 70,019 | $ 238,353 | $ 226,630 |
Unregulated Energy and other | 57,233 | 38,329 | 198,827 | 130,356 |
Total Operating Revenues | 126,936 | 108,348 | 437,180 | 356,986 |
Operating Expenses | ||||
Regulated Energy cost of sales | 22,794 | 24,644 | 87,206 | 81,184 |
Unregulated Energy and other cost of sales | 44,066 | 28,183 | 145,325 | 85,142 |
Operations | 29,667 | 30,126 | 92,990 | 85,370 |
Maintenance | 2,737 | 3,542 | 9,370 | 8,925 |
Gain From A Settlement | 0 | 0 | (130) | (130) |
Depreciation and amortization | 9,362 | 8,209 | 27,267 | 23,493 |
Other taxes | 4,071 | 3,488 | 12,572 | 10,725 |
Total Operating Expenses | 112,697 | 98,192 | 374,600 | 294,709 |
Operating Income | 14,239 | 10,156 | 62,580 | 62,277 |
Other income (expense), net | 239 | (28) | (643) | (68) |
Interest charges | 3,321 | 2,722 | 9,133 | 7,996 |
Income Before Income Taxes | 11,157 | 7,406 | 52,804 | 54,213 |
Income taxes | 4,324 | 2,990 | 20,781 | 21,401 |
Net Income | $ 6,833 | $ 4,416 | $ 32,023 | $ 32,812 |
Weighted Average Common Shares Outstanding: | ||||
Basic (shares) | 16,344,442 | 15,372,413 | 16,334,210 | 15,324,932 |
Diluted (shares) | 16,389,635 | 15,412,783 | 16,378,633 | 15,365,955 |
Earnings Per Share of Common Stock: | ||||
Basic (in dollars per share) | $ 0.42 | $ 0.29 | $ 1.96 | $ 2.14 |
Diluted (in dollars per share) | 0.42 | 0.29 | 1.96 | 2.14 |
Cash Dividends Declared Per Share of Common Stock (in dollars per share) | $ 0.325 | $ 0.305 | $ 0.955 | $ 0.8975 |
Condensed Consolidated Stateme3
Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Statement of Comprehensive Income [Abstract] | ||||
Net Income | $ 6,833 | $ 4,416 | $ 32,023 | $ 32,812 |
Other Comprehensive (Loss) Income, net of tax: | ||||
Amortization of prior service cost, net of tax of $(8), $(8), $(23) and $(23), respectively | (11) | (12) | (35) | (37) |
Net gain, net of tax of $69, $66, $212 and $200, respectively | 102 | 100 | 297 | 300 |
Cash Flow Hedges, net of tax: | ||||
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of $(15), $38, $(376) and $360, respectively | (104) | 51 | (643) | 548 |
Total Other Comprehensive (Loss) Income | (13) | 139 | (381) | 811 |
Comprehensive Income | $ 6,820 | $ 4,555 | $ 31,642 | $ 33,623 |
Condensed Consolidated Stateme4
Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Statement of Comprehensive Income [Abstract] | ||||
Amortization of prior service cost, tax | $ (8) | $ (8) | $ (23) | $ (23) |
Net gain, tax | 69 | 66 | 212 | 200 |
Unrealized (loss)/gain on commodity contract cash flow hedges, tax | $ (15) | $ 38 | $ (376) | $ 360 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment | |||
Regulated Energy | $ 1,050,332 | $ 957,681 | |
Unregulated Energy | 207,331 | 196,800 | |
Other businesses and eliminations | 26,061 | 21,114 | |
Total property, plant and equipment | 1,283,724 | 1,175,595 | |
Less: Accumulated depreciation and amortization | (267,138) | (245,207) | |
Plus: Construction work in progress | 69,053 | 56,276 | |
Net property, plant and equipment | 1,085,639 | 986,664 | |
Current Assets | |||
Cash and cash equivalents | 3,386 | 4,178 | |
Accounts receivable (less allowance for uncollectible accounts of $912 and $909, respectively) | 52,775 | 62,803 | |
Accrued revenue | 14,307 | 16,986 | |
Propane inventory, at average cost | 5,226 | 6,457 | |
Other inventory, at average cost | 12,711 | 4,576 | |
Regulatory assets | 9,761 | 7,694 | |
Storage gas prepayments | 6,876 | 5,484 | |
Income taxes receivable | 26,741 | 22,888 | |
Prepaid expenses | 10,899 | 6,792 | |
Derivative assets, at fair value | 1,526 | 823 | |
Other current assets | 4,797 | 2,470 | |
Total current assets | 149,005 | 141,151 | |
Deferred Charges and Other Assets | |||
Goodwill | 21,944 | 15,070 | |
Other intangible assets, net | 4,608 | 1,843 | |
Investments, at fair value | 6,380 | 4,902 | |
Regulatory assets | 75,793 | 76,803 | |
Receivables and other deferred charges | 3,381 | 2,786 | |
Total deferred charges and other assets | 112,106 | 101,404 | |
Total Assets | 1,346,750 | 1,229,219 | |
Stockholders’ equity | |||
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding | 0 | 0 | |
Common stock, par value $0.4867 per share (authorized 25,000,000 shares) | 7,955 | 7,935 | |
Additional paid-in capital | 252,722 | 250,967 | |
Retained earnings | 208,402 | 192,062 | |
Accumulated other comprehensive loss | (5,259) | (4,878) | |
Deferred compensation obligation | 3,366 | 2,416 | |
Treasury stock | (3,366) | (2,416) | |
Total stockholders’ equity | [1] | 463,820 | 446,086 |
Long-term debt, net of current maturities | 201,248 | 136,954 | |
Total capitalization | 665,068 | 583,040 | |
Current Liabilities | |||
Current portion of long-term debt | 12,136 | 12,099 | |
Short-term borrowing | 203,098 | 209,871 | |
Accounts payable | 53,284 | 56,935 | |
Customer deposits and refunds | 32,493 | 29,238 | |
Accrued interest | 3,361 | 1,312 | |
Dividends payable | 5,312 | 4,973 | |
Accrued compensation | 8,544 | 10,496 | |
Regulatory liabilities | 5,338 | 1,291 | |
Derivative liabilities, at fair value | 1,732 | 773 | |
Other accrued liabilities | 13,972 | 7,063 | |
Total current liabilities | 339,270 | 334,051 | |
Deferred Credits and Other Liabilities | |||
Deferred income taxes | 252,273 | 222,894 | |
Regulatory liabilities | 42,915 | 43,064 | |
Environmental liabilities | 8,382 | 8,592 | |
Other pension and benefit costs | 32,059 | 32,828 | |
Deferred investment tax credits and other liabilities | 6,783 | 4,750 | |
Total deferred credits and other liabilities | 342,412 | 312,128 | |
Environmental and other commitments and contingencies (Note 4 and 5) | |||
Total Capitalization and Liabilities | $ 1,346,750 | $ 1,229,219 | |
[1] | Includes 90,588 and 76,745 shares at September 30, 2017 and December 31, 2016, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan |
Condensed Consolidated Balance6
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Allowance for uncollectible accounts | $ 912 | $ 909 |
Common stock, par value (in dollars per share) | $ 0.4867 | $ 0.4867 |
Common stock, shares authorized (shares) | 25,000,000 | 25,000,000 |
Preferred Stock, Shares Authorized | 2,000,000 | 2,000,000 |
Preferred Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 |
Preferred Stock, Shares Issued | 0 | 0 |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | |||
Operating Activities | ||||
Net Income | $ 32,023 | $ 32,812 | ||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||
Depreciation and amortization | 27,267 | 23,493 | ||
Depreciation and accretion included in other costs | 5,989 | 5,357 | ||
Deferred income taxes | 29,520 | 12,004 | ||
Realized gain on commodity contracts/sale of assets/investments | (2,817) | (405) | ||
Unrealized gain on investments/commodity contracts | (695) | (243) | ||
Employee benefits and compensation | 1,212 | 1,217 | ||
Share-based compensation | 1,608 | 1,887 | ||
Other, net | (39) | 42 | ||
Changes in assets and liabilities: | ||||
Accounts receivable and accrued revenue | 12,912 | (3,835) | ||
Propane inventory, storage gas and other inventory | (8,256) | (2,179) | ||
Regulatory assets/liabilities, net | 927 | (3,326) | ||
Prepaid expenses and other current assets | (2,860) | 485 | ||
Accounts payable and other accrued liabilities | 4,515 | 7,187 | ||
Income taxes (payable) receivable | (3,810) | 14,897 | ||
Customer deposits and refunds | 3,255 | (314) | ||
Accrued compensation | (2,030) | (2,293) | ||
Other assets and liabilities, net | (349) | (1,053) | ||
Net cash provided by operating activities | 98,372 | 85,733 | ||
Investing Activities | ||||
Property, plant and equipment expenditures | (130,137) | (109,589) | ||
Proceeds from sales of assets | 601 | 119 | ||
Payments to Acquire Businesses, Gross | (11,707) | |||
Environmental expenditures | (210) | (260) | ||
Net cash used in investing activities | (141,453) | (109,730) | ||
Financing Activities | ||||
Common stock dividends | (14,780) | (12,964) | ||
Issuance of stock for Dividend Reinvestment Plan | 254 | 600 | ||
Stock issuance | (10) | [1] | 57,306 | |
Tax Withholding payments related to net settled stock compensation | (692) | (770) | ||
Change in cash overdrafts due to outstanding checks | (3,013) | 2,466 | ||
Net repayment under line of credit agreements | (3,760) | (21,379) | ||
Proceeds from issuance of long-term debt | 69,800 | 0 | ||
Repayment of long-term debt and capital lease obligation | (5,510) | (2,581) | ||
Net cash provided by financing activities | 42,289 | 22,678 | ||
Net Decrease in Cash and Cash Equivalents | (792) | (1,319) | ||
Cash and Cash Equivalents—Beginning of Period | 4,178 | 2,855 | ||
Cash and Cash Equivalents—End of Period | 3,386 | $ 1,536 | ||
Additional Paid-in Capital [Member] | ||||
Financing Activities | ||||
Stock issuance | [1] | $ (10) | ||
[1] | On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million. |
Condensed Consolidated Stateme8
Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-In Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Loss [Member] | Deferred Compensation [Member] | Treasury Stock [Member] | |||
Proceeds from issuance of common stocks | [1] | $ 57,360 | ||||||||
Beginning Balances (shares) at Dec. 31, 2015 | [2] | 15,270,659 | ||||||||
Beginning Balances at Dec. 31, 2015 | 358,138 | [2] | $ 7,432 | $ 190,311 | $ 166,235 | $ (5,840) | $ 1,883 | $ (1,883) | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net Income | 44,675 | 44,675 | ||||||||
Other comprehensive income (loss) | 962 | 962 | ||||||||
Dividend declared | (18,848) | (18,848) | ||||||||
Retirement savings plan and dividend reinvestment plan (shares) | 36,253 | |||||||||
Retirement savings plan and dividend reinvestment plan | $ 2,242 | $ 17 | 2,225 | |||||||
Stock issuance, shares | 960,488 | 960,488 | [1] | |||||||
Stock issuance | [1] | $ 57,360 | $ 467 | 56,893 | ||||||
Share-based compensation (shares) | [3],[4] | 36,099 | ||||||||
Share-based compensation and tax benefit | [3],[4] | 1,557 | $ 19 | 1,538 | ||||||
Treasury stock activities | 0 | 533 | (533) | |||||||
Ending Balances (shares) at Dec. 31, 2016 | [2],[5] | 16,303,499 | ||||||||
Ending Balances at Dec. 31, 2016 | $ 446,086 | [5] | $ 7,935 | 250,967 | 192,062 | (4,878) | 2,416 | (2,416) | ||
Preferred Stock, Shares Authorized | 2,000,000 | |||||||||
Preferred Stock, Par or Stated Value Per Share | $ 0.01 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net Income | $ 32,023 | 32,023 | ||||||||
Other comprehensive income (loss) | (381) | (381) | ||||||||
Dividend declared | (15,683) | (15,683) | ||||||||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 10,771 | |||||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 736 | $ 5 | 731 | |||||||
Stock issuance, shares | 960,488 | |||||||||
Stock issuance | [1] | $ (10) | (10) | |||||||
Share-based compensation (shares) | [3],[4] | 30,172 | ||||||||
Share-based compensation and tax benefit | [3],[4] | 1,049 | $ 15 | 1,034 | ||||||
Treasury stock activities | 0 | 950 | (950) | |||||||
Ending Balances (shares) at Sep. 30, 2017 | [2],[5] | 16,344,442 | ||||||||
Ending Balances at Sep. 30, 2017 | $ 463,820 | [5] | $ 7,955 | $ 252,722 | $ 208,402 | $ (5,259) | $ 3,366 | $ (3,366) | ||
Preferred Stock, Shares Authorized | 2,000,000 | |||||||||
Preferred Stock, Par or Stated Value Per Share | $ 0.01 | |||||||||
[1] | On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million. | |||||||||
[2] | 2,000,000 shares of preferred stock at $0.01 par value have been authorized. None has been issued or is outstanding; accordingly, no information has been included in the statements of stockholders’ equity. | |||||||||
[3] | Includes amounts for shares issued for Directors’ compensation. | |||||||||
[4] | The shares issued under the SICP are net of shares withheld for employee taxes. For the nine months ended September 30, 2017, and for the year ended December 31, 2016, we withheld 10,269 and 12,031 shares, respectively, for taxes. | |||||||||
[5] | Includes 90,588 and 76,745 shares at September 30, 2017 and December 31, 2016, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan |
Condensed Consolidated Stateme9
Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (Unaudited) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2017 | Dec. 31, 2016 | ||
Statement of Stockholders' Equity [Abstract] | ||||
Dividend declared (in dollars per share) | $ 0.325 | $ 0.955 | $ 1.2025 | |
Deferred compensation plan held Rabbi Trust (shares) | 90,588 | 90,588 | 76,745 | |
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 | |
Stock Issued During Period, Shares, New Issues | 960,488 | 960,488 | ||
Stock Issued During Period, Value, Other | $ 62.26 | $ 62.26 | ||
Proceeds from Issuance of Common Stock | [1] | $ (10,000) | $ 57,360,000 | |
Shares issued under the performance incentive plan withheld for employee taxes (shares) | 10,269 | 12,031 | ||
[1] | On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million. |
Summary of Accounting Policies
Summary of Accounting Policies | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Summary of Accounting Policies | 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, 2016 . 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. We reclassified certain amounts in the condensed consolidated statement of cash flows for the nine months ended September 30, 2016 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements. Acquisitions In August 2017, PESCO acquired certain natural gas marketing assets of ARM. We have accounted for the purchase of these assets as a business combination. The acquired assets complement PESCO’s current asset portfolio and will expand our regional footprint and retail demand in a market where we have existing pipeline capacity and wholesale liquidity. In connection with the acquisition, we recorded a contingent liability of $2.5 million , which represents the expected payment of contingent consideration to ARM. The payment, which is expected to be paid in 2019, is contingent upon the achievement of certain gross margin targets during the 2018 calendar year. The recorded liability is based upon our most recent gross margin projections for the acquired business and is subject to change based on actual performance or changes in our gross margin projections. In August 2017, Flo-gas acquired certain operating assets of Chipola, which provides propane distribution service to approximately 800 residential and commercial customers in Jackson, Calhoun, Gadsden, Liberty, Bay and Washington Counties, Florida. The revenue and net income from these acquisitions that we included in our condensed consolidated statements of income for the three and nine months ended September 30, 2017, were not material. The amounts recorded in conjunction with our acquisitions are preliminary and subject to adjustment based on additional valuations performed during the measurement period. FASB Statements and Other Authoritative Pronouncements Recently Adopted Accounting Standards Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. We adopted ASU 2015-11 on January 1, 2017, on a prospective basis. Adoption of this standard did not have a material impact on our financial position or results of operations. Recent Accounting Standards Yet to be Adopted Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. In March 2016, FASB issued ASU 2016-08, Principal versus Agent Considerations (Reporting Revenue Gross versus Net) , to clarify the implementation guidance on principal versus agent considerations. For public entities, this standard is effective for interim and annual financial statements issued beginning January 1, 2018. We have completed our evaluation of our revenue sources and will continue assessing the impact on our financial position, results of operations and cash flows during the fourth quarter of 2017. In tandem, we have developed and documented accounting policies and position papers, which are intended to meet the requirements of this new revenue recognition standard. We have also completed our plan to update our internal controls. In the third quarter of 2017, we began providing additional training to our employees and implementing system and process changes that are associated with the adoption of the standard. We plan to utilize the modified retrospective transition method upon adoption of this standard. Based on our current assessment, we believe that the implementation of this new standard will not have a material impact on the amount and timing of revenue recognition except for one long-term contract for which we will delay the recognition of revenue of approximately $407,000 in 2018. Since we have not yet finalized our assessment, we will continue to monitor and subsequently disclose future identified material impacts, if any, in our annual report on Form 10-K for the year ended December 31, 2017. In addition, the AICPA Power and Utilities Industry Task Force is addressing issues specific to our industry, including CIAC, and has concluded that CIAC is outside of the scope of this standard; accordingly, our Regulated Energy segment accounting for CIAC will not change as a result of ASC 606. Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We have assessed all of our leases and have concluded that a majority of our operating leases would continue to fall within the category of operating leases; however, we may have some leases that qualify for the short-term lease exception. We will record the right to use of assets and the lease liability related to the operating leases, but we do not believe that this will have a material impact on our financial position, results of operations and cash flows. During the fourth quarter of 2017, we intend to quantify the overall impact that may result from early adoption of the standard and implementation of the overall process. This guidance will be applied using the modified retrospective transition method for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments , which clarifies how certain transactions are classified in the statement of cash flows. ASU 2016-15 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. We believe that the implementation of this new standard will not have a material impact on our statement of cash flows. Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment , which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations. Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update allows for capitalization of the service cost component when applicable. ASU 2017-07 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. The presentation of the service cost and other components in this update are to be applied retrospectively, and the capitalization of the service cost is to be applied prospectively on or after the effective date. Aside from changes in presentation, we believe that the implementation of this new standard will not have a material impact on our financial position or results of operations. Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) changes as a result of a change in the terms or conditions of the award. The guidance is effective for our annual financial statements beginning January 1, 2018, although early adoption is permitted. The amendments included in this standard are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations. Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities , to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Among other changes to hedge designation, ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument included in the assessment of hedge effectiveness be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We are evaluating the effect of this standard on our future financial position and results of operations. |
Calculation of Earnings Per Sha
Calculation of Earnings Per Share | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Calculation of Earnings Per Share | Calculation of Earnings Per Share Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 6,833 $ 4,416 $ 32,023 $ 32,812 Weighted average shares outstanding 16,344,442 15,372,413 16,334,210 15,324,932 Basic Earnings Per Share $ 0.42 $ 0.29 $ 1.96 $ 2.14 Calculation of Diluted Earnings Per Share: Reconciliation of Numerator: Net Income $ 6,833 $ 4,416 $ 32,023 $ 32,812 Reconciliation of Denominator: Weighted shares outstanding—Basic 16,344,442 15,372,413 16,334,210 15,324,932 Effect of dilutive securities—Share-based compensation 45,193 40,370 44,423 41,023 Adjusted denominator—Diluted 16,389,635 15,412,783 16,378,633 15,365,955 Diluted Earnings Per Share $ 0.42 $ 0.29 $ 1.96 $ 2.14 |
Rates and Other Regulatory Acti
Rates and Other Regulatory Activities | 9 Months Ended |
Sep. 30, 2017 | |
Regulated Operations [Abstract] | |
Rates and Other Regulatory Activities | Rates and Other Regulatory Activities Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake Utilities' Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation, as separate entities, by the Florida PSC. Delaware Rate Case Filing: In December 2015, our Delaware Division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. The Delaware Division, Delaware PSC Staff, the Division of the Public Advocate and other intervenors met and reached a settlement agreement in November 2016. The terms of the settlement agreement included an annual increase of $2.3 million in base rates. The order became final in December 2016, and the new rates became effective January 1, 2017. Amounts collected through interim rates in excess of the respective portion of the $2.3 million increase through December 31, 2016 were accrued as of that date. In January 2017, we filed our proposed refund plan with the Delaware PSC and subsequently issued refunds to customers in March 2017. Maryland There were no material rates and other regulatory activities for our Maryland division during the period. Sandpiper There were no material rates and other regulatory activities for Sandpiper during the period. Florida Cost Recovery for the Electric Interconnect Project: In September 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project would enable FPU's electric division to negotiate a new power purchase agreement to mitigate fuel costs for its Northeast division. FPU's proposal was approved by the Florida PSC at its Agenda Conference held in December 2015. In January 2016, however, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. The Florida Supreme Court reversed the Florida PSC decision in March 2017, after consideration of the parties' legal briefs and oral arguments. As a result, FPU excluded the recovery of these costs from its 2018 Fuel and Purchased Power Cost Recovery Clause and included the costs for recovery in the limited proceeding filing described below. Surcharge Associated with Modernization of Electric Distribution System Project: In February 2017, FPU’s electric division filed a petition with the Florida PSC requesting a temporary surcharge mechanism to recover costs and generate an appropriate return on investment associated with an essential reliability and modernization project for its electric distribution system. We requested approval to invest approximately $59.8 million , over a five -year period, associated with the modernization project. In February 2017, the Office of Public Counsel intervened in this petition. The Florida PSC requested that FPU file a limited proceeding to include these investments in base rates instead of seeking approval of a temporary surcharge. In April 2017, FPU voluntarily withdrew its petition and subsequently filed the limited proceeding described in the next paragraph. Electric Limited Proceeding: In July 2017, FPU’s electric division filed a petition with the Florida PSC, requesting approval to include $15.2 million of certain capital project expenditures in its rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safety of the electric system while enhancing the capability of FPU’s grid. Included in the $15.2 million is the interconnection project with Florida Power & Light Company, which enables FPU to mitigate fuel costs for its electric customers. This petition is scheduled for the Florida PSC's December 2017 Agenda. Northwest Florida Expansion Project : Peninsula Pipeline and FPU's natural gas division are constructing a pipeline in Escambia County, Florida that will interconnect with FGT's pipeline. The project consists of 33 miles of 12 -inch transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and 8 miles of 8 -inch lateral distribution lines that will be operated by Chesapeake Utilities' Florida natural gas division. We have entered into agreements to serve two large customers and are marketing to other customers close to the facilities. New Smyrna Beach, Florida Project: Peninsula Pipeline is constructing a pipeline in Volusia County, Florida that will interconnect with FGT's pipeline. The project consists of 14 miles of transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and will serve FPU natural gas distribution customers. Eastern Shore White Oak Mainline Expansion Project: In July 2016, Eastern Shore received FERC authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an electric power generator in Kent County, Delaware ("White Oak Mainline Project"). Eastern Shore constructed approximately 5.4 miles of 16 -inch diameter pipeline looping in Chester County, Pennsylvania and increased compression capability at Eastern Shore’s existing Delaware City compressor station in New Castle County, Delaware. At the end of March 2017, the entire project was placed into service. The total cost to complete the project was approximately $42.0 million . System Reliability Project: In September 2016, the FERC approved Eastern Shore's application to construct, own and operate approximately 10.1 miles of 16 -inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware, and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposed to reinforce critical points on its pipeline system. Previously, in July 2016, the FERC granted Eastern Shore’s pre-determination of rolled-in rate treatment absent any significant change in circumstances. As of June 2017, the entire project was placed into service. The total cost to complete the project was approximately $38.0 million. We began to recover the project's costs in August 2017, coinciding with the proposed effectiveness of new rates, subject to refund, pending final resolution of the base rate case described below. 2017 Expansion Project: In May 2016, Eastern Shore submitted a request to the FERC to initiate the pre-filing review procedures for Eastern Shore's 2017 expansion project (the “2017 Expansion Project”). The 2017 Expansion Project's facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. In May 2016, the FERC approved Eastern Shore’s request to commence the pre-filing review process. Eastern Shore entered into Precedent Agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities. In December 2016, Eastern Shore submitted an application for a CP seeking authorization to construct the expansion facilities. Six of Eastern Shore's existing customers timely intervened to become parties. In February and March 2017, Eastern Shore submitted responses to the FERC staff's data requests. In October 2017, FERC issued a CP authorizing Eastern Shore to construct and operate the proposed 2017 Expansion Project. The estimated cost of the 2017 Expansion Project is approximately $115.0 million Eastern Shore is preparing its implementation plan, which will be filed with the FERC, addressing the actions Eastern Shore will undertake to meet the Environmental Conditions set forth in the FERC's order. Eastern Shore anticipates placing certain facilities into service by the end of the year and completing the entire project in 2018. 2017 Rate Case Filing: In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million resulting in an overall requested revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent. The filing includes incremental rates for the White Oak Lateral Project and White Oak Mainline Expansion Project, which benefits a single customer. Eastern Shore also proposed to revise its depreciation rates and negative salvage rate based on the results of independent, third-party depreciation and negative salvage value studies. In March 2017, the FERC issued an order suspending the tariff rates for the usual five -month period. On August 1, 2017, Eastern Shore implemented new rates, subject to refund based upon the outcome of the rate proceeding. Eastern Shore recorded incremental revenue of approximately $1.0 million for the three and nine months ended September 30, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until the rate case is resolved. Settlement discussions continue among the other parties to the case. |
Environmental Commitments and C
Environmental Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2017 | |
Environmental Remediation Obligations [Abstract] | |
Environmental Commitments and Contingencies | Environmental Commitments and Contingencies We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate, at current and former operating sites, the effect on the environment of the disposal or release of specified substances. MGP Sites We have participated in the investigation, assessment or remediation of, and have exposures at, seven former MGP sites. Those sites are located in Salisbury, Maryland, Seaford, Delaware and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland. As of September 30, 2017 , we had approximately $9.7 million in environmental liabilities, related to FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to its MGP sites. Approximately $10.9 million has been recovered as of September 30, 2017 , leaving approximately $3.1 million in regulatory assets for future recovery of environmental costs from FPU’s customers. Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates. The following is a summary of our remediation status and estimated costs to implement clean-up of our MGP sites: Jurisdiction MGP Site Status Cost to Clean up Recovery through Rates Florida West Palm Beach Remedial actions approved by FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions. Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties Yes Florida Sanford In January 2007, FPU and the Sanford group signed a Third Participation Agreement. FPU's share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000, which has been paid to an escrow account. The EPA issued a preliminary close-out report in December 2014. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. FPU's remaining remediation expenses, including attorneys' fees and costs, are estimated to be approximately $24,000 Yes Florida Winter Haven Remediation is ongoing. Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site Yes Delaware Seaford Proposed plan for implementation approved by DNREC in July 2017. $273,000 to $465,000 Yes Maryland Cambridge Currently in discussions with MDE Unable to estimate N/A |
Other Commitments and Contingen
Other Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Other Commitments and Contingencies | Other Commitments and Contingencies Natural Gas, Electric and Propane Supply We have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. In 2017, our Delmarva natural gas distribution operations entered into asset management agreements with PESCO to manage a portion of their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each has a three -year term, expiring on March 31, 2020. Previously, the Delaware PSC approved PESCO to serve as an asset manager. In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six -year term ending in May 2019. Sandpiper's current annual commitment is estimated at approximately 2.8 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices. Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six -year term ending in May 2019. Sharp's current annual commitment is estimated at approximately 2.8 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement. Chesapeake Utilities' Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to FGT and Gulfstream should any party that acquired the capacity through release fail to pay the capacity charge. FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times and (b) a fixed charge coverage ratio greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times) and (b) total debt to total capital (maximum of 65 percent ). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of September 30, 2017 , FPU was in compliance with all of the requirements of its fuel supply contracts. Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20 -year power purchase agreement for distribution to its retail electric customers. In July 2016, Eight Flags also started selling steam an industrial customer that owns the property on which the CHP plant is located pursuant to a separate 20 -year contract. 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 propane and 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 September 30, 2017 was approximately $71.9 million , with the guarantees expiring on various dates through September 2018 . Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 13 , Long-Term Debt , for further details). Letters of Credit As of September 30, 2017 , we have issued letters of credit totaling approximately $5.8 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, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through June 2018 . There have been no draws on these letters of credit as of September 30, 2017 . We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future. Other We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows. |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations are comprised of two reportable segments: • Regulated Energy . The Regulated Energy segment includes natural gas distribution, natural gas transmission and electric distribution operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore. • Unregulated Energy. The Unregulated Energy segment includes propane distribution as well as natural gas marketing, gathering, processing, transportation and supply. These operations are unregulated as to their rates and services. Effective June 2016, this segment includes electricity and steam generation through Eight Flags' CHP plant. Through March 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary that began winding down operations at the end of the first quarter of 2017. Other operations are presented as “Other businesses and eliminations,” which consist of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations. Our operations are entirely domestic. The following table presents financial information about our reportable segments: Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy segment $ 67,257 $ 68,899 $ 232,519 $ 224,382 Unregulated Energy segment and other businesses 59,679 39,449 204,661 132,604 Total operating revenues, unaffiliated customers $ 126,936 $ 108,348 $ 437,180 $ 356,986 Intersegment Revenues (1) Regulated Energy segment $ 2,446 $ 1,120 $ 5,834 $ 2,248 Unregulated Energy segment 5,009 2,593 15,801 3,759 Other businesses 194 240 581 705 Total intersegment revenues $ 7,649 $ 3,953 $ 22,216 $ 6,712 Operating Income Regulated Energy segment $ 15,168 $ 13,115 $ 51,915 $ 52,660 Unregulated Energy segment (989 ) (3,080 ) 10,504 9,267 Other businesses and eliminations 60 121 161 350 Total operating income 14,239 10,156 62,580 62,277 Other income (expense), net 239 (28 ) (643 ) (68 ) Interest charges 3,321 2,722 9,133 7,996 Income before Income Taxes 11,157 7,406 52,804 54,213 Income taxes 4,324 2,990 20,781 21,401 Net Income $ 6,833 $ 4,416 $ 32,023 $ 32,812 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) September 30, 2017 December 31, 2016 Identifiable Assets Regulated Energy segment $ 1,084,961 $ 986,752 Unregulated Energy segment 233,785 226,368 Other businesses and eliminations 28,004 16,099 Total identifiable assets $ 1,346,750 $ 1,229,219 |
Stockholder's Equity - Accumula
Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) | 9 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Stockholder's Equity Preferred Stock We had 2,000,000 authorized and unissued shares of preferred stock, $0.01 par value per share, as of September 30, 2017 and December 31, 2016. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and without the necessity of further action or authorization by stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional or other special rights and qualifications as the Board of Directors may, in its discretion, determine. Common Stock Public Offering In September 2016, we completed a public offering of 960,488 shares of our common stock at a public offering price per share of $62.26 . The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million , which were added to our general funds and used primarily to repay a portion of our short-term debt under unsecured lines of credit. Stockholders' Rights Pursuant to authority granted under Delaware law and our Certificate of Incorporation, our Board of Directors previously declared a dividend of one preferred stock purchase right (each, a "Right," and, collectively, the "Rights") for each outstanding share of our common stock held of record on September 3, 1999, as adjusted for our stock split in September of 2014, and for additional shares of common stock issued since that time. The description and terms of the Rights are set forth in the Rights Plan. Unless exercised, the Rights trade with our common stock and are evidenced by the common stock certificate. In general, each Right will become exercisable and trade independently from our common stock upon a person or entity acquiring a beneficial ownership of 15 percent or more of our outstanding common stock. Each Right, if it becomes exercisable, initially entitles the holder to purchase one fiftieth of a share of our Series A Participating Cumulative Preferred Stock, par value $0.01 per share, at a price of $70 per unit, subject to anti-dilution adjustments. Upon a person or entity becoming an "acquiring person," each Right (other than the Rights held by the acquiring person) will become exercisable to purchase a number of shares of our common stock having a market value equal to two times the exercise price of the Right. The Rights expire on August 20, 2019, unless they are redeemed earlier by us at the redemption price of $0.01 per Right. We may redeem the Rights at any time before they become exercisable and thereafter only in limited circumstances. Accumulated Other Comprehensive Loss Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures 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 for the nine months ended September 30, 2017 and 2016 . All amounts are presented net of tax. Defined Benefit Commodity Pension and Contracts Postretirement Cash Flow Plan Items Hedges Total (in thousands) As of December 31, 2016 $ (5,360 ) $ 482 $ (4,878 ) Other comprehensive income/(loss) before reclassifications (9 ) 322 313 Amounts reclassified from accumulated other comprehensive income/(loss) 271 (965 ) (694 ) Net current-period other comprehensive income/(loss) 262 (643 ) (381 ) As of September 30, 2017 $ (5,098 ) $ (161 ) $ (5,259 ) Defined Benefit Commodity Pension and Contracts Postretirement Cash Flow Plan Items Hedges Total (in thousands) As of December 31, 2015 $ (5,580 ) $ (260 ) $ (5,840 ) Other comprehensive income before reclassifications — 641 641 Amounts reclassified from accumulated other comprehensive income/(loss) 263 (93 ) 170 Net prior-period other comprehensive income 263 548 811 As of September 30, 2016 $ (5,317 ) $ 288 $ (5,029 ) The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2017 and 2016 . Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement. Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in thousands) Amortization of defined benefit pension and postretirement plan items: Prior service credit (1) $ 19 $ 20 $ 58 $ 60 Net loss (1) (171 ) (166 ) (509 ) (500 ) Total before income taxes (152 ) (146 ) (451 ) (440 ) Income tax benefit 61 58 180 177 Net of tax $ (91 ) $ (88 ) $ (271 ) $ (263 ) Gains and losses on commodity contracts cash flow hedges Propane swap agreements (2) $ 198 $ — $ 663 $ (322 ) Natural gas swaps (2) 1 — 1 — Natural gas futures (2) (852 ) 105 929 464 Total before income taxes (653 ) 105 1,593 142 Income tax benefit (expense) 248 (41 ) (628 ) (49 ) Net of tax (405 ) 64 965 93 Total reclassifications for the period $ (496 ) $ (24 ) $ 694 $ (170 ) (1) These amounts are included in the computation of net periodic costs (benefits). See Note 8 , Employee Benefit Plans , for additional details. (2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 11, Derivative Instruments , for additional details. Amortization of defined benefit pension and postretirement plan items is included in operations expense, and gains and losses on propane swap agreements and call options are included in cost of sales, in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax income (expense) in the accompanying condensed consolidated statements of income. |
Employee Benefit Plans
Employee Benefit Plans | 9 Months Ended |
Sep. 30, 2017 | |
Retirement Benefits [Abstract] | |
Employee Benefit Plans | Employee Benefit Plans Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, 2017 and 2016 are set forth in the following tables: Chesapeake FPU Chesapeake SERP Chesapeake FPU For the Three Months Ended September 30, 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 (in thousands) Interest cost $ 103 $ 105 $ 623 $ 635 $ 22 $ 23 $ 11 $ 11 $ 13 $ 14 Expected return on plan assets (127 ) (131 ) (699 ) (625 ) — — — — — — Amortization of prior service credit — — — — — — (19 ) (20 ) — — Amortization of net loss 107 103 131 133 22 22 17 16 — — Net periodic cost (benefit) 83 77 55 143 44 45 9 7 13 14 Amortization of pre-merger regulatory asset — — 191 191 — — — — 2 2 Total periodic cost $ 83 $ 77 $ 246 $ 334 $ 44 $ 45 $ 9 $ 7 $ 15 $ 16 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Nine Months Ended September 30, 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 (in thousands) Interest cost $ 309 $ 315 $ 1,870 $ 1,894 $ 66 $ 68 $ 31 $ 32 $ 38 $ 41 Expected return on plan assets (381 ) (392 ) (2,098 ) (2,027 ) — — — — — — Amortization of prior service credit — — — — — — (58 ) (60 ) — — Amortization of net loss 319 309 392 389 65 66 50 51 — — Net periodic cost (benefit) 247 232 164 256 131 134 23 23 38 41 Amortization of pre-merger regulatory asset — — 571 571 — — — — 6 6 Total periodic cost $ 247 $ 232 $ 735 $ 827 $ 131 $ 134 $ 23 $ 23 $ 44 $ 47 We expect to record pension and postretirement benefit costs of approximately $1.6 million for 2017. Included in these costs is approximately $769,000 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 $1.5 million and approximately $2.1 million at September 30, 2017 and December 31, 2016 , respectively. 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 nine months ended September 30, 2017 and 2016 : For the Three Months Ended September 30, 2017 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (19 ) $ — $ (19 ) Net loss 107 131 22 17 — 277 Total recognized in net periodic benefit cost 107 131 22 (2 ) — 258 Recognized from accumulated other comprehensive loss (1) 107 25 22 (2 ) — 152 Recognized from regulatory asset — 106 — — — 106 Total $ 107 $ 131 $ 22 $ (2 ) $ — $ 258 For the Three Months Ended September 30, 2016 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (20 ) $ — $ (20 ) Net loss 103 133 22 16 — 274 Total recognized in net periodic benefit cost 103 133 22 (4 ) — 254 Recognized from accumulated other comprehensive loss (1) 103 25 22 (4 ) — 146 Recognized from regulatory asset — 108 — — — 108 Total $ 103 $ 133 $ 22 $ (4 ) $ — $ 254 For the Nine Months Ended September 30, 2017 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (58 ) $ — $ (58 ) Net loss 319 392 65 50 — 826 Total recognized in net periodic benefit cost 319 392 65 (8 ) — 768 Recognized from accumulated other comprehensive loss (1) 319 75 65 (8 ) — 451 Recognized from regulatory asset — 317 — — — 317 Total $ 319 $ 392 $ 65 $ (8 ) $ — $ 768 For the Nine Months Ended September 30, 2016 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (60 ) $ — $ (60 ) Net loss 309 389 66 51 — 815 Total recognized in net periodic benefit cost 309 389 66 (9 ) — 755 Recognized from accumulated other comprehensive loss (1) 309 74 66 (9 ) — 440 Recognized from regulatory asset — 315 — — — 315 Total $ 309 $ 389 $ 66 $ (9 ) $ — $ 755 (1) See Note 7 , Stockholder's Equity . During the three and nine months ended September 30, 2017 , we contributed approximately $67,000 and $234,000 , respectively, to the Chesapeake Pension Plan and approximately $110,000 and $1.6 million , respectively, to the FPU Pension Plan. We expect to contribute a total of approximately $746,000 and approximately $3.0 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2017 , 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 three and nine months ended September 30, 2017 , were approximately $38,000 and $114,000 , respectively. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake SERP in 2017 . Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and nine months ended September 30, 2017 , were approximately $30,000 and $94,000 , respectively. We estimate that approximately $83,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2017 . Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, 2017 , were approximately $13,000 and $48,000 , respectively. We estimate that approximately $129,000 will be paid for such benefits under the FPU Medical Plan in 2017 . |
Investments
Investments | 9 Months Ended |
Sep. 30, 2017 | |
Investments, Debt and Equity Securities [Abstract] | |
Investments | Investments The investment balances at September 30, 2017 and December 31, 2016 , consisted of the following: (in thousands) September 30, December 31, Rabbi trust (associated with the Deferred Compensation Plan) $ 6,358 $ 4,881 Investments in equity securities 22 21 Total $ 6,380 4,902 We classify these investments as trading securities and report them at their fair value. For the three months ended September 30, 2017 and 2016 , we recorded a net unrealized gain of approximately $ 261,000 and $193,000 , respectively, in other income (expense), net in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 2017 and 2016 , we recorded an unrealized gain of approximately $694,000 and $246,000 , respectively, in other income (expense), net in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets and is adjusted each month for the gains and losses incurred by the investments in the Rabbi Trust. |
Share-Based Compensation
Share-Based Compensation | 9 Months Ended |
Sep. 30, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-Based Compensation | 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 nine months ended September 30, 2017 and 2016 : Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in thousands) Awards to non-employee directors $ 134 $ 135 $ 406 $ 445 Awards to key employees 662 488 1,202 1,442 Total compensation expense 796 623 1,608 1,887 Less: tax benefit (320 ) (251 ) (647 ) (760 ) Share-based compensation amounts included in net income $ 476 $ 372 $ 961 $ 1,127 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 grant date. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2017, each of our non-employee directors received an annual retainer of 835 shares of common stock under the SICP for service as a director through the 2018 Annual Meeting of Stockholders. A summary of the stock activity for our non-employee directors during the nine months ended September 30, 2017 is presented below: Number of Shares Weighted Average Fair Value Outstanding— December 31, 2016 — $ — Granted 7,515 $ 71.80 Vested (7,515 ) $ 71.80 Outstanding— September 30, 2017 — $ — At September 30, 2017 , there was approximately $314,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2018. Key Employees The table below presents the summary of the stock activity for awards to key employees for the nine months ended September 30, 2017 : Number of Shares Weighted Average Fair Value Outstanding— December 31, 2016 115,091 $ 51.85 Granted 52,355 $ 63.42 Vested (32,926 ) $ 38.88 Expired (1,878 ) $ 39.97 Outstanding— September 30, 2017 132,642 $ 52.42 In February and May 2017, our Board of Directors granted awards of 52,355 shares of common stock to key employees under the SICP. The shares granted in February and May 2017 are multi-year awards that will vest at the end of the three -year service period ending December 31, 2019. All of these stock awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both market-based and performance-based conditions or targets. The fair value of each 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. At the election of certain of our executives, in March 2017, for shares that were awarded for the performance period ending December 31, 2016, we withheld shares with a value at least equivalent to each such executive’s minimum statutory obligation for applicable income and other employment taxes, remitted the cash to the appropriate taxing authorities, and paid the balance of such shares to each such executive. We withheld 10,269 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 $692,000 . At September 30, 2017 , the aggregate intrinsic value of the SICP awards granted to key employees was approximately $10.4 million . At September 30, 2017 , there was approximately $2.7 million of unrecognized compensation cost related to these awards, which is expected to be recognized from 2017 through 2019. Stock Options We did not have any stock options outstanding at September 30, 2017 or 2016 , nor were any stock options issued during these periods. |
Derivative Instruments
Derivative Instruments | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Derivative Instruments We use derivative and non-derivative contracts to engage in trading activities and 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. 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 September 30, 2017 , our natural gas and electric distribution operations did not have any outstanding derivative contracts. Hedging Activities in 2017 In 2017, Sharp entered into several swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 11.1 million gallons expected to be purchased from October 2017 through September 2018 . Under the swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in October 2017 through September 2018) and the swap prices of $0.5900 and $0.6750 per gallon, to the extent the index prices exceed the swap prices. If the index prices are lower than the swap price, Sharp will pay the difference. We accounted for these swap agreements as cash flow hedges, and there is no ineffective portion of these hedges. At September 30, 2017 , the swap agreements had a fair value asset of approximately $1.5 million . The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss). PESCO enters into natural gas futures contracts associated with the purchase and sale of natural gas to other specific customers. These contracts have a two -year term, and we accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At September 30, 2017 , PESCO had a total of 4.0 million Dts hedged under natural gas futures contracts, with a liability fair value of approximately $1.3 million accounted for as a cash flow hedge. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss). In August 2017, PESCO entered into natural gas swap agreements associated with ARM's financial contracts to mitigate the risk of fluctuations in wholesale natural gas prices associated with 12.0 million Dts PESCO expects to purchase through January 2020. We accounted for these swap agreements as cash flow hedges, with a liability fair value of approximately $412,000 . The change in fair value of the natural gas swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss). The impact of PESCO's financial instruments that were not designated as hedges in our condensed consolidated financial statements for the nine months ended September 30, 2017 was $13,000 , which was recorded as an increase in gas costs and is associated with 1.4 million Dts of natural gas. This presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Hedging Activities in 2016 In 2016, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 4.8 million gallons expected to be purchased through September 2017. Under the swap agreements, Sharp would receive the difference between the index prices (Mont Belvieu prices in October 2016 through September 2017) and the swap prices of $0.5225 and $0.5650 per gallon, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap price, Sharp would pay the difference. Sharp received a total of approximately $193,000 , which represented the difference between the index prices and swap prices during the months of October 2016 through September 2017. We had accounted for these swap agreements as cash flow hedges. In December 2016, Sharp paid a total of $33,000 to purchase a put option to protect against a decline in propane prices and related potential inventory losses associated with 630,000 gallons for its propane price cap program in the 2016-2017 heating season. The put option expired without being exercised because the propane prices did not fall below the strike price of $0.5650 per gallon in December 2016, January 2017, or February 2017. We accounted for the put option as a fair value hedge, and there was no ineffective portion of this hedge. In January 2016, PESCO entered into a supplier agreement with Columbia Gas to provide natural gas supply for one of its local distribution customer pools. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the supplier agreement, which terminated on March 31, 2017. In conjunction with the supplier agreement, PESCO entered into natural gas futures contracts during the second quarter of 2016 in order to protect its natural gas inventory against market price fluctuations. We had previously accounted for these contracts as fair value hedges, with any ineffective portion being reported directly in earnings and offset by any associated gain (loss) on the inventory value being hedged. During the third quarter of 2016, we discontinued hedge accounting as the hedges were no longer highly effective. As of September 30, 2017 , these contracts have all expired and are no longer reported on the balance sheet. Commodity Contracts for Trading Activities Shortly after the first quarter of 2017, Xeron wound down its operations. Xeron was previously engaged in trading activities using forward and futures contracts for propane and crude oil. These contracts were considered derivatives and were accounted for using the mark-to-market method of accounting. As of September 30, 2017 , Xeron had no outstanding contracts that were accounted for as derivatives. 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 September 30, 2017 and December 31, 2016 , are as follows: Fair Value As Of (in thousands) Balance Sheet Location September 30, 2017 December 31, 2016 Derivatives not designated as hedging instruments Propane swap agreements Derivative assets, at fair value $ 15 $ 8 Put options Derivative assets, at fair value — 9 Natural gas swap contracts Derivative assets, at fair value 1 — Derivatives designated as cash flow hedges Natural gas futures contracts Derivative assets, at fair value — 113 Propane swap agreements Derivative assets, at fair value 1,510 693 Total asset derivatives $ 1,526 $ 823 Liability Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2017 December 31, 2016 Derivatives not designated as hedging instruments Natural gas futures contracts Derivative liabilities, at fair value $ 13 $773 Derivatives designated as cash flow hedges Natural gas swap contracts Derivative liabilities, at fair value 412 — Natural gas futures contracts Derivative liabilities, at fair value 1,307 — Total liability derivatives $ 1,732 $ 773 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 September 30, For the Nine Months Ended September 30, (in thousands) (Loss) on Derivatives 2017 2016 2017 2016 Derivatives not designated as hedging instruments Realized gain on forward contracts and options (1) Revenue $ — $ (231 ) $ 112 $ 44 Unrealized gain (loss) on forward contracts (1) Revenue — (2 ) — — Natural gas futures contracts Cost of sales 286 205 907 205 Propane swap agreements Cost of sales 15 — 11 — Natural gas swap contracts Cost of sales 1 — 1 — Derivatives designated as fair value hedges Put /Call option (2) Cost of sales — — (9 ) 73 Natural gas futures contracts Natural gas inventory — — — (233 ) Derivatives designated as cash flow hedges Propane swap agreements Cost of sales 198 — 663 (364 ) Propane swap agreements Other comprehensive income 1,590 213 814 559 Natural gas futures contracts Cost of sales (852 ) 105 929 464 Natural gas futures contracts Other comprehensive income (loss) (1,296 ) (123 ) (1,420 ) 349 Natural gas swap agreements Cost of sales 1 — 1 — Natural gas swap agreements Other comprehensive loss (413 ) — (413 ) — Total $ (470 ) $ 167 $ 1,596 $ 1,097 (1) All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income. (2) As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory on the condensed consolidated balance sheets. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | Fair Value of Financial Instruments GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following: Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities; Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity). Financial Assets and Liabilities Measured at Fair Value The following table summarizes 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 September 30, 2017 and December 31, 2016 : Fair Value Measurements Using: As of September 30, 2017 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 22 $ 22 $ — $ — Investments—guaranteed income fund 642 — — 642 Investments—mutual funds and other 5,716 5,716 — — Total investments 6,380 5,738 — 642 Derivative assets 1,526 — 1,526 — Total assets $ 7,906 $ 5,738 $ 1,526 $ 642 Liabilities: Derivative liabilities $ 1,732 $ — $ 1,732 $ — Fair Value Measurements Using: As of December 31, 2016 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 21 $ 21 $ — $ — Investments—guaranteed income fund 561 — — 561 Investments—mutual funds and other 4,320 4,320 — — Total investments 4,902 4,341 — 561 Derivative assets 823 — 823 — Total assets $ 5,725 $ 4,341 $ 823 $ 561 Liabilities: Derivative liabilities $ 773 $ — $ 773 $ — The following valuation techniques were used to measure the fair value of assets and liabilities in the tables above: Level 1 Fair Value Measurements: Investments - equity securities — The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities. Investments - mutual funds and other — The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares. Level 2 Fair Value Measurements: Derivative assets and liabilities — The fair values of forward contracts are measured using market transactions in either the listed or OTC markets. The fair value of the propane put/call options, swap agreements and natural gas futures contracts are measured using market transactions for similar assets and liabilities in either the listed or OTC markets. Level 3 Fair Value Measurements: Investments - guaranteed income fund — The fair values of these investments are recorded at the contract value, which approximates their fair value. The following table sets forth the summary of the changes in the fair value of Level 3 investments for the nine months ended September 30, 2017 and 2016 : Nine Months Ended 2017 2016 (in thousands) Beginning Balance $ 561 $ 279 Purchases and adjustments 76 120 Transfers — 88 Distribution (2 ) (8 ) Investment income 7 6 Ending Balance $ 642 $ 485 Investment income from the Level 3 investments is reflected in other expense, (net) in the accompanying condensed consolidated statements of income. At September 30, 2017 , 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 September 30, 2017 , long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately $211.4 million . This compares to a fair value of approximately $224.2 million , using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2016 , long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately $145.9 million , compared to the estimated fair value of approximately $161.5 million . The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement. |
Long-Term Debt
Long-Term Debt | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Our outstanding long-term debt is shown below: September 30, December 31, (in thousands) 2017 2016 FPU secured first mortgage bonds (1) : 9.08% bond, due June 1, 2022 $ 7,981 $ 7,978 Uncollateralized senior notes: 6.64% note, due October 31, 2017 2,727 2,727 5.50% note, due October 12, 2020 8,000 8,000 5.93% note, due October 31, 2023 19,500 21,000 5.68% note, due June 30, 2026 26,100 29,000 6.43% note, due May 2, 2028 7,000 7,000 3.73% note, due December 16, 2028 20,000 20,000 3.88% note, due May 15, 2029 50,000 50,000 3.25% note, due April 30, 2032 70,000 — Promissory notes 97 168 Capital lease obligation 2,425 3,471 Less: debt issuance costs (446 ) (291 ) Total long-term debt 213,384 149,053 Less: current maturities (12,136 ) (12,099 ) Total long-term debt, net of current maturities $ 201,248 $ 136,954 (1) FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities. Shelf Agreements In October 2015, we entered into the Prudential Shelf Agreement, under which we may request that Prudential purchase, through October 8, 2018, up to $150.0 million of Prudential Shelf Notes. The Prudential Shelf Notes have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Prudential Shelf Notes. The interest rate and terms of payment of any series of the Prudential Shelf Notes will be determined at the time of purchase. In May 2016, Prudential confirmed and accepted our request that Prudential purchase $70.0 million of 3.25 percent Prudential Shelf Notes, which were issued on April 21, 2017. The proceeds received from this issuance of Prudential Shelf Notes were used to reduce short-term borrowings under the Revolver. The balance under the Revolver had accumulated over time as capital expenditures were temporarily financed. The Prudential Shelf Agreement sets forth certain business covenants to which we are subject when any Prudential Shelf 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. In March 2017, we entered into the MetLife Shelf Agreement and the NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million and $100.0 million , respectively, of our unsecured senior debt. The unsecured senior debt would have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. The interest rate and terms of payment of any series of unsecured senior debt will be determined at the time of purchase. As of September 30, 2017 , no unsecured senior debt has been issued under the MetLife and NYL Shelf Agreements. |
Summary of Accounting Policies
Summary of Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | 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, 2016 . 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. We reclassified certain amounts in the condensed consolidated statement of cash flows for the nine months ended September 30, 2016 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements. |
FASB Statements and Other Authoritative Pronouncements | FASB Statements and Other Authoritative Pronouncements Recently Adopted Accounting Standards Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. We adopted ASU 2015-11 on January 1, 2017, on a prospective basis. Adoption of this standard did not have a material impact on our financial position or results of operations. Recent Accounting Standards Yet to be Adopted Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. In March 2016, FASB issued ASU 2016-08, Principal versus Agent Considerations (Reporting Revenue Gross versus Net) , to clarify the implementation guidance on principal versus agent considerations. For public entities, this standard is effective for interim and annual financial statements issued beginning January 1, 2018. We have completed our evaluation of our revenue sources and will continue assessing the impact on our financial position, results of operations and cash flows during the fourth quarter of 2017. In tandem, we have developed and documented accounting policies and position papers, which are intended to meet the requirements of this new revenue recognition standard. We have also completed our plan to update our internal controls. In the third quarter of 2017, we began providing additional training to our employees and implementing system and process changes that are associated with the adoption of the standard. We plan to utilize the modified retrospective transition method upon adoption of this standard. Based on our current assessment, we believe that the implementation of this new standard will not have a material impact on the amount and timing of revenue recognition except for one long-term contract for which we will delay the recognition of revenue of approximately $407,000 in 2018. Since we have not yet finalized our assessment, we will continue to monitor and subsequently disclose future identified material impacts, if any, in our annual report on Form 10-K for the year ended December 31, 2017. In addition, the AICPA Power and Utilities Industry Task Force is addressing issues specific to our industry, including CIAC, and has concluded that CIAC is outside of the scope of this standard; accordingly, our Regulated Energy segment accounting for CIAC will not change as a result of ASC 606. Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We have assessed all of our leases and have concluded that a majority of our operating leases would continue to fall within the category of operating leases; however, we may have some leases that qualify for the short-term lease exception. We will record the right to use of assets and the lease liability related to the operating leases, but we do not believe that this will have a material impact on our financial position, results of operations and cash flows. During the fourth quarter of 2017, we intend to quantify the overall impact that may result from early adoption of the standard and implementation of the overall process. This guidance will be applied using the modified retrospective transition method for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments , which clarifies how certain transactions are classified in the statement of cash flows. ASU 2016-15 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. We believe that the implementation of this new standard will not have a material impact on our statement of cash flows. Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment , which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations. Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update allows for capitalization of the service cost component when applicable. ASU 2017-07 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. The presentation of the service cost and other components in this update are to be applied retrospectively, and the capitalization of the service cost is to be applied prospectively on or after the effective date. Aside from changes in presentation, we believe that the implementation of this new standard will not have a material impact on our financial position or results of operations. Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) changes as a result of a change in the terms or conditions of the award. The guidance is effective for our annual financial statements beginning January 1, 2018, although early adoption is permitted. The amendments included in this standard are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations. Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities , to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Among other changes to hedge designation, ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument included in the assessment of hedge effectiveness be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We are evaluating the effect of this standard on our future financial position and results of operations. |
Calculation of Earnings Per S24
Calculation of Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Calculation of Basic and Diluted Earnings Per Share | Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 6,833 $ 4,416 $ 32,023 $ 32,812 Weighted average shares outstanding 16,344,442 15,372,413 16,334,210 15,324,932 Basic Earnings Per Share $ 0.42 $ 0.29 $ 1.96 $ 2.14 Calculation of Diluted Earnings Per Share: Reconciliation of Numerator: Net Income $ 6,833 $ 4,416 $ 32,023 $ 32,812 Reconciliation of Denominator: Weighted shares outstanding—Basic 16,344,442 15,372,413 16,334,210 15,324,932 Effect of dilutive securities—Share-based compensation 45,193 40,370 44,423 41,023 Adjusted denominator—Diluted 16,389,635 15,412,783 16,378,633 15,365,955 Diluted Earnings Per Share $ 0.42 $ 0.29 $ 1.96 $ 2.14 |
Environmental Commitments and25
Environmental Commitments and Contingencies Summary of Environmental Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Environmental Commitments and Contingencies [Abstract] | |
Environmental Remedies [Table Text Block] | Jurisdiction MGP Site Status Cost to Clean up Recovery through Rates Florida West Palm Beach Remedial actions approved by FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions. Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties Yes Florida Sanford In January 2007, FPU and the Sanford group signed a Third Participation Agreement. FPU's share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000, which has been paid to an escrow account. The EPA issued a preliminary close-out report in December 2014. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. FPU's remaining remediation expenses, including attorneys' fees and costs, are estimated to be approximately $24,000 Yes Florida Winter Haven Remediation is ongoing. Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site Yes Delaware Seaford Proposed plan for implementation approved by DNREC in July 2017. $273,000 to $465,000 Yes Maryland Cambridge Currently in discussions with MDE Unable to estimate N/A |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information by Segment | The following table presents financial information about our reportable segments: Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy segment $ 67,257 $ 68,899 $ 232,519 $ 224,382 Unregulated Energy segment and other businesses 59,679 39,449 204,661 132,604 Total operating revenues, unaffiliated customers $ 126,936 $ 108,348 $ 437,180 $ 356,986 Intersegment Revenues (1) Regulated Energy segment $ 2,446 $ 1,120 $ 5,834 $ 2,248 Unregulated Energy segment 5,009 2,593 15,801 3,759 Other businesses 194 240 581 705 Total intersegment revenues $ 7,649 $ 3,953 $ 22,216 $ 6,712 Operating Income Regulated Energy segment $ 15,168 $ 13,115 $ 51,915 $ 52,660 Unregulated Energy segment (989 ) (3,080 ) 10,504 9,267 Other businesses and eliminations 60 121 161 350 Total operating income 14,239 10,156 62,580 62,277 Other income (expense), net 239 (28 ) (643 ) (68 ) Interest charges 3,321 2,722 9,133 7,996 Income before Income Taxes 11,157 7,406 52,804 54,213 Income taxes 4,324 2,990 20,781 21,401 Net Income $ 6,833 $ 4,416 $ 32,023 $ 32,812 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) September 30, 2017 December 31, 2016 Identifiable Assets Regulated Energy segment $ 1,084,961 $ 986,752 Unregulated Energy segment 233,785 226,368 Other businesses and eliminations 28,004 16,099 Total identifiable assets $ 1,346,750 $ 1,229,219 |
Stockholder's Equity - Accumul
Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
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, 2016 $ (5,360 ) $ 482 $ (4,878 ) Other comprehensive income/(loss) before reclassifications (9 ) 322 313 Amounts reclassified from accumulated other comprehensive income/(loss) 271 (965 ) (694 ) Net current-period other comprehensive income/(loss) 262 (643 ) (381 ) As of September 30, 2017 $ (5,098 ) $ (161 ) $ (5,259 ) Defined Benefit Commodity Pension and Contracts Postretirement Cash Flow Plan Items Hedges Total (in thousands) As of December 31, 2015 $ (5,580 ) $ (260 ) $ (5,840 ) Other comprehensive income before reclassifications — 641 641 Amounts reclassified from accumulated other comprehensive income/(loss) 263 (93 ) 170 Net prior-period other comprehensive income 263 548 811 As of September 30, 2016 $ (5,317 ) $ 288 $ (5,029 ) |
Reclassifications out of Accumulated Other Comprehensive Income (Loss) | The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2017 and 2016 . Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement. Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in thousands) Amortization of defined benefit pension and postretirement plan items: Prior service credit (1) $ 19 $ 20 $ 58 $ 60 Net loss (1) (171 ) (166 ) (509 ) (500 ) Total before income taxes (152 ) (146 ) (451 ) (440 ) Income tax benefit 61 58 180 177 Net of tax $ (91 ) $ (88 ) $ (271 ) $ (263 ) Gains and losses on commodity contracts cash flow hedges Propane swap agreements (2) $ 198 $ — $ 663 $ (322 ) Natural gas swaps (2) 1 — 1 — Natural gas futures (2) (852 ) 105 929 464 Total before income taxes (653 ) 105 1,593 142 Income tax benefit (expense) 248 (41 ) (628 ) (49 ) Net of tax (405 ) 64 965 93 Total reclassifications for the period $ (496 ) $ (24 ) $ 694 $ (170 ) |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
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 nine months ended September 30, 2017 and 2016 are set forth in the following tables: Chesapeake FPU Chesapeake SERP Chesapeake FPU For the Three Months Ended September 30, 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 (in thousands) Interest cost $ 103 $ 105 $ 623 $ 635 $ 22 $ 23 $ 11 $ 11 $ 13 $ 14 Expected return on plan assets (127 ) (131 ) (699 ) (625 ) — — — — — — Amortization of prior service credit — — — — — — (19 ) (20 ) — — Amortization of net loss 107 103 131 133 22 22 17 16 — — Net periodic cost (benefit) 83 77 55 143 44 45 9 7 13 14 Amortization of pre-merger regulatory asset — — 191 191 — — — — 2 2 Total periodic cost $ 83 $ 77 $ 246 $ 334 $ 44 $ 45 $ 9 $ 7 $ 15 $ 16 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Nine Months Ended September 30, 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 (in thousands) Interest cost $ 309 $ 315 $ 1,870 $ 1,894 $ 66 $ 68 $ 31 $ 32 $ 38 $ 41 Expected return on plan assets (381 ) (392 ) (2,098 ) (2,027 ) — — — — — — Amortization of prior service credit — — — — — — (58 ) (60 ) — — Amortization of net loss 319 309 392 389 65 66 50 51 — — Net periodic cost (benefit) 247 232 164 256 131 134 23 23 38 41 Amortization of pre-merger regulatory asset — — 571 571 — — — — 6 6 Total periodic cost $ 247 $ 232 $ 735 $ 827 $ 131 $ 134 $ 23 $ 23 $ 44 $ 47 |
Amounts Included in Regulatory asset and AOCI [Table Text Block] | 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 nine months ended September 30, 2017 and 2016 : For the Three Months Ended September 30, 2017 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (19 ) $ — $ (19 ) Net loss 107 131 22 17 — 277 Total recognized in net periodic benefit cost 107 131 22 (2 ) — 258 Recognized from accumulated other comprehensive loss (1) 107 25 22 (2 ) — 152 Recognized from regulatory asset — 106 — — — 106 Total $ 107 $ 131 $ 22 $ (2 ) $ — $ 258 For the Three Months Ended September 30, 2016 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (20 ) $ — $ (20 ) Net loss 103 133 22 16 — 274 Total recognized in net periodic benefit cost 103 133 22 (4 ) — 254 Recognized from accumulated other comprehensive loss (1) 103 25 22 (4 ) — 146 Recognized from regulatory asset — 108 — — — 108 Total $ 103 $ 133 $ 22 $ (4 ) $ — $ 254 For the Nine Months Ended September 30, 2017 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (58 ) $ — $ (58 ) Net loss 319 392 65 50 — 826 Total recognized in net periodic benefit cost 319 392 65 (8 ) — 768 Recognized from accumulated other comprehensive loss (1) 319 75 65 (8 ) — 451 Recognized from regulatory asset — 317 — — — 317 Total $ 319 $ 392 $ 65 $ (8 ) $ — $ 768 For the Nine Months Ended September 30, 2016 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (60 ) $ — $ (60 ) Net loss 309 389 66 51 — 815 Total recognized in net periodic benefit cost 309 389 66 (9 ) — 755 Recognized from accumulated other comprehensive loss (1) 309 74 66 (9 ) — 440 Recognized from regulatory asset — 315 — — — 315 Total $ 309 $ 389 $ 66 $ (9 ) $ — $ 755 |
Investments (Tables)
Investments (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Investments, Debt and Equity Securities [Abstract] | |
Investments schedule [Table Text Block] | The investment balances at September 30, 2017 and December 31, 2016 , consisted of the following: (in thousands) September 30, December 31, Rabbi trust (associated with the Deferred Compensation Plan) $ 6,358 $ 4,881 Investments in equity securities 22 21 Total $ 6,380 4,902 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
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 nine months ended September 30, 2017 and 2016 : Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in thousands) Awards to non-employee directors $ 134 $ 135 $ 406 $ 445 Awards to key employees 662 488 1,202 1,442 Total compensation expense 796 623 1,608 1,887 Less: tax benefit (320 ) (251 ) (647 ) (760 ) Share-based compensation amounts included in net income $ 476 $ 372 $ 961 $ 1,127 |
Schedule of Share-based Compensation, Nonemployee Director Stock Award Plan, Activity [Table Text Block] | A summary of the stock activity for our non-employee directors during the nine months ended September 30, 2017 is presented below: Number of Shares Weighted Average Fair Value Outstanding— December 31, 2016 — $ — Granted 7,515 $ 71.80 Vested (7,515 ) $ 71.80 Outstanding— September 30, 2017 — $ — |
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 nine months ended September 30, 2017 : Number of Shares Weighted Average Fair Value Outstanding— December 31, 2016 115,091 $ 51.85 Granted 52,355 $ 63.42 Vested (32,926 ) $ 38.88 Expired (1,878 ) $ 39.97 Outstanding— September 30, 2017 132,642 $ 52.42 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
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 September 30, 2017 and December 31, 2016 , are as follows: Fair Value As Of (in thousands) Balance Sheet Location September 30, 2017 December 31, 2016 Derivatives not designated as hedging instruments Propane swap agreements Derivative assets, at fair value $ 15 $ 8 Put options Derivative assets, at fair value — 9 Natural gas swap contracts Derivative assets, at fair value 1 — Derivatives designated as cash flow hedges Natural gas futures contracts Derivative assets, at fair value — 113 Propane swap agreements Derivative assets, at fair value 1,510 693 Total asset derivatives $ 1,526 $ 823 Liability Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2017 December 31, 2016 Derivatives not designated as hedging instruments Natural gas futures contracts Derivative liabilities, at fair value $ 13 $773 Derivatives designated as cash flow hedges Natural gas swap contracts Derivative liabilities, at fair value 412 — Natural gas futures contracts Derivative liabilities, at fair value 1,307 — Total liability derivatives $ 1,732 $ 773 |
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 September 30, For the Nine Months Ended September 30, (in thousands) (Loss) on Derivatives 2017 2016 2017 2016 Derivatives not designated as hedging instruments Realized gain on forward contracts and options (1) Revenue $ — $ (231 ) $ 112 $ 44 Unrealized gain (loss) on forward contracts (1) Revenue — (2 ) — — Natural gas futures contracts Cost of sales 286 205 907 205 Propane swap agreements Cost of sales 15 — 11 — Natural gas swap contracts Cost of sales 1 — 1 — Derivatives designated as fair value hedges Put /Call option (2) Cost of sales — — (9 ) 73 Natural gas futures contracts Natural gas inventory — — — (233 ) Derivatives designated as cash flow hedges Propane swap agreements Cost of sales 198 — 663 (364 ) Propane swap agreements Other comprehensive income 1,590 213 814 559 Natural gas futures contracts Cost of sales (852 ) 105 929 464 Natural gas futures contracts Other comprehensive income (loss) (1,296 ) (123 ) (1,420 ) 349 Natural gas swap agreements Cost of sales 1 — 1 — Natural gas swap agreements Other comprehensive loss (413 ) — (413 ) — Total $ (470 ) $ 167 $ 1,596 $ 1,097 (1) All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income. (2) As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory on the condensed consolidated balance sheets. |
Fair Value of Financial Instr32
Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Financial Assets and Liabilities Measured at Fair Value on Recurring Basis | The following table summarizes 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 September 30, 2017 and December 31, 2016 : Fair Value Measurements Using: As of September 30, 2017 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 22 $ 22 $ — $ — Investments—guaranteed income fund 642 — — 642 Investments—mutual funds and other 5,716 5,716 — — Total investments 6,380 5,738 — 642 Derivative assets 1,526 — 1,526 — Total assets $ 7,906 $ 5,738 $ 1,526 $ 642 Liabilities: Derivative liabilities $ 1,732 $ — $ 1,732 $ — Fair Value Measurements Using: As of December 31, 2016 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 21 $ 21 $ — $ — Investments—guaranteed income fund 561 — — 561 Investments—mutual funds and other 4,320 4,320 — — Total investments 4,902 4,341 — 561 Derivative assets 823 — 823 — Total assets $ 5,725 $ 4,341 $ 823 $ 561 Liabilities: Derivative liabilities $ 773 $ — $ 773 $ — |
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 nine months ended September 30, 2017 and 2016 : Nine Months Ended 2017 2016 (in thousands) Beginning Balance $ 561 $ 279 Purchases and adjustments 76 120 Transfers — 88 Distribution (2 ) (8 ) Investment income 7 6 Ending Balance $ 642 $ 485 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Outstanding Long-Term Debt | Our outstanding long-term debt is shown below: September 30, December 31, (in thousands) 2017 2016 FPU secured first mortgage bonds (1) : 9.08% bond, due June 1, 2022 $ 7,981 $ 7,978 Uncollateralized senior notes: 6.64% note, due October 31, 2017 2,727 2,727 5.50% note, due October 12, 2020 8,000 8,000 5.93% note, due October 31, 2023 19,500 21,000 5.68% note, due June 30, 2026 26,100 29,000 6.43% note, due May 2, 2028 7,000 7,000 3.73% note, due December 16, 2028 20,000 20,000 3.88% note, due May 15, 2029 50,000 50,000 3.25% note, due April 30, 2032 70,000 — Promissory notes 97 168 Capital lease obligation 2,425 3,471 Less: debt issuance costs (446 ) (291 ) Total long-term debt 213,384 149,053 Less: current maturities (12,136 ) (12,099 ) Total long-term debt, net of current maturities $ 201,248 $ 136,954 (1) FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities. |
Summary of Accounting policie34
Summary of Accounting policies - Additional Information (Details) | 9 Months Ended |
Sep. 30, 2017USD ($) | |
Subsequent Event [Line Items] | |
Delay of Revenue Recognition Due To Implementation of New Standard | $ 407,000 |
Summary of Accounting Policie35
Summary of Accounting Policies Acquisitions Additional information (Details) | 9 Months Ended |
Sep. 30, 2017USD ($) | |
Business Acquisition [Line Items] | |
Number of customers acquired through acquisition | 800 |
ARM Energy [Member] | |
Business Acquisition [Line Items] | |
Business Combination, Liabilities Arising from Contingencies, Amount Recognized | $ 2,500,000 |
Calculation of Earnings Per S36
Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Calculation of Basic Earnings Per Share: | |||||
Net Income | $ 6,833 | $ 4,416 | $ 32,023 | $ 32,812 | $ 44,675 |
Weighted shares outstanding (shares) | 16,344,442 | 15,372,413 | 16,334,210 | 15,324,932 | |
Basic Earnings Per Share (in dollars per share) | $ 0.42 | $ 0.29 | $ 1.96 | $ 2.14 | |
Reconciliation of Numerator: | |||||
Net Income | $ 6,833 | $ 4,416 | $ 32,023 | $ 32,812 | $ 44,675 |
Reconciliation of Denominator: | |||||
Weighted shares outstanding - Basic (shares) | 16,344,442 | 15,372,413 | 16,334,210 | 15,324,932 | |
Effect of dilutive securities: | |||||
Share-based compensation (shares) | 45,193 | 40,370 | 44,423 | 41,023 | |
Adjusted denominator-Diluted (shares) | 16,389,635 | 15,412,783 | 16,378,633 | 15,365,955 | |
Diluted Earnings Per Share (in dollars per share) | $ 0.42 | $ 0.29 | $ 1.96 | $ 2.14 |
Rates and Other Regulatory Ac37
Rates and Other Regulatory Activities - Additional Information (Detail) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended |
Sep. 30, 2017USD ($)dekatherm / dinmi | Sep. 30, 2017USD ($)dekatherm / dunitcustomerinmi | Dec. 31, 2016USD ($) | |
DELAWARE | |||
Rates and Other Regulatory Activities [Line Items] | |||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 2,250 | ||
Electric Distribution [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Estimated Capital Cost | $ 59,800 | ||
Number of Years in Project | 5 years | ||
Amount of Regulatory Costs Not yet Approved | $ 15,200 | $ 15,200 | |
Eastern Shore [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Cost of Services | 60,000 | ||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 18,900 | ||
Public Utilities, Requested Return on Equity, Percentage | 13.75% | ||
Number of Months Rates Suspended | 5 months | ||
Increase in Revenue Recognized Due to Motion Rate in Effect | $ 1,000 | $ 1,000 | |
Northwest Florida Expansion [Member] | Florida Public Utilities Company [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Lateral diamater of pipeline to be installed | in | 8 | ||
Diameter of pipe to be installed in the future | in | 12 | 12 | |
New Smyrna Beach [Member] | Florida Public Utilities Company [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Length of Natural Gas Pipeline | mi | 14 | ||
White Oak Lateral Mainline Expansion [Member] | Eastern Shore [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Estimated Capital Cost | $ 42,000 | ||
Volume The Expansion Project Is Expected to Provide | dekatherm / d | 45,000 | ||
Lateral diamater of pipeline to be installed | in | 16 | ||
Revised Miles Of Natural Gas Pipeline | mi | 5.4 | 5.4 | |
System Reliability Project [Member] | Eastern Shore [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Estimated Capital Cost | $ 38,000 | ||
Number of pipeline miles requested | mi | 10.1 | 10.1 | |
Lateral diamater of pipeline to be installed | in | 16 | ||
2017 Expansion Project [Member] | Eastern Shore [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Estimated Capital Cost | $ 115,000 | ||
Number of pipeline miles requested | mi | 23 | 23 | |
Revised Miles Of Natural Gas Pipeline | mi | 17 | 17 | |
Pressure Control Stations | 2 | ||
Firm natural gas transportation deliverability | dekatherm / d | 61,162 | ||
Additional Firm Natural Gas Transportation Deliverability | dekatherm / d | 52,500 | ||
Subscribers [Member] | 2017 Expansion Project [Member] | Eastern Shore [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Number of customers | 7 | ||
Number of affiliates | unit | 3 | ||
Number of Customers intervened | customer | 6 | ||
12 inches [Member] | Northwest Florida Expansion [Member] | Florida Public Utilities Company [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Length of Natural Gas Pipeline | mi | 33 | ||
8 inches [Member] | Northwest Florida Expansion [Member] | Florida Public Utilities Company [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Length of Natural Gas Pipeline | mi | 8 |
Environmental Commitments and38
Environmental Commitments and Contingencies - Additional Information (Detail) | 9 Months Ended | |
Sep. 30, 2017USD ($)site | Dec. 31, 2016USD ($) | |
Environmental Commitments And Contingencies [Line Items] | ||
Company's exposure in number of former Manufactured Gas Plant Sites | site | 7 | |
Environmental liabilities | $ 8,382,000 | $ 8,592,000 |
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 | |
Sanford Florida [Member] | ||
Environmental Commitments And Contingencies [Line Items] | ||
Estimated costs of remediation range, minimum | 13,000,000 | |
Environmental remediation expense | $ 24,000 | |
Number of Years to ensure remedy | 5 | |
Winter Haven Florida [Member] | Maximum [Member] | ||
Environmental Commitments And Contingencies [Line Items] | ||
Environmental remediation expense | $ 425,000 | |
Seaford [Member] | Minimum [Member] | ||
Environmental Commitments And Contingencies [Line Items] | ||
Estimated costs of remediation range, minimum | 273,000 | |
Seaford [Member] | Maximum [Member] | ||
Environmental Commitments And Contingencies [Line Items] | ||
Estimated costs of remediation range, minimum | 465,000 | |
FPU [Member] | ||
Environmental Commitments And Contingencies [Line Items] | ||
Environmental liabilities | 9,700,000 | |
Approval of recovery of environmental costs | 14,000,000 | |
Environmental costs recovered | 10,900,000 | |
FPU [Member] | Sanford Florida [Member] | ||
Environmental Commitments And Contingencies [Line Items] | ||
Estimated costs of remediation range, minimum | $ 650,000 | |
Environmental remediation expense percent | 5.00% | |
FPU [Member] | Manufactured Gas Plant [Member] | ||
Environmental Commitments And Contingencies [Line Items] | ||
Regulatory Assets for future recovery of environmental costs | $ 3,100,000 |
Other Commitments and Conting39
Other Commitments and Contingencies - Additional Information (Detail) gal in Millions, $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2017USD ($)gal | Sep. 30, 2017USD ($)gal | |
Commitments and Contingencies Disclosure [Abstract] | ||
Number of Years for Asset Management Agreement | 3 years | |
Number of years to purchase propane under contract | 6 years | |
Estimated current annual commitment | gal | 2.8 | 2.8 |
Number of Propane Price Indices | 2 | |
Total liabilities to tangible net worth minimum times | 3.75 | 3.75 |
Fixed charge coverage ratio minimum times | 1.5 | 1.5 |
Time to cure ratio | 30 days | |
Ratios based on average of the prior quarters | 1 year 6 months | |
Funds from operations interest coverage ratio minimum times | 2 | 2 |
Total debt to capital maximum | 0.65 | 0.65 |
Number Of Years For Power Purchase Agreement | 20 years | |
Contract Duration | 20 years | |
Aggregate guaranteed amount | $ 71.9 | $ 71.9 |
Draws on letters of credit | $ 5.8 |
Segment Information - Schedule
Segment Information - Schedule of Segment Reporting Information by Segment (Detail) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) | ||
Segment Reporting Information [Line Items] | ||||||
Number of Reportable Segments | 2 | |||||
Operating Revenues, Unaffiliated Customers | ||||||
Total operating revenues, unaffiliated customers | $ 126,936 | $ 108,348 | $ 437,180 | $ 356,986 | ||
Intersegment Revenues | ||||||
Total operating revenues, unaffiliated customers | 126,936 | 108,348 | 437,180 | 356,986 | ||
Operating Income | ||||||
Total operating income | 14,239 | 10,156 | 62,580 | 62,277 | ||
Other expense, net | 239 | (28) | (643) | (68) | ||
Interest | 3,321 | 2,722 | 9,133 | 7,996 | ||
Income Before Income Taxes | 11,157 | 7,406 | 52,804 | 54,213 | ||
Income taxes | 4,324 | 2,990 | 20,781 | 21,401 | ||
Net Income | 6,833 | 4,416 | 32,023 | 32,812 | $ 44,675 | |
Identifiable Assets | ||||||
Total identifiable assets | 1,346,750 | 1,346,750 | 1,229,219 | |||
Regulated Energy [Member] | ||||||
Operating Income | ||||||
Total operating income | 15,168 | 13,115 | 51,915 | 52,660 | ||
Identifiable Assets | ||||||
Total identifiable assets | 1,084,961 | 1,084,961 | 986,752 | |||
Unregulated Energy [Member] | ||||||
Operating Income | ||||||
Total operating income | (989) | (3,080) | 10,504 | 9,267 | ||
Identifiable Assets | ||||||
Total identifiable assets | 233,785 | 233,785 | 226,368 | |||
Other [Member] | ||||||
Identifiable Assets | ||||||
Total identifiable assets | 28,004 | 28,004 | $ 16,099 | |||
Other and eliminations [Member] | ||||||
Operating Income | ||||||
Total operating income | 60 | 121 | 161 | 350 | ||
Operating Revenues, Unaffiliated Customers [Member] | ||||||
Operating Revenues, Unaffiliated Customers | ||||||
Total operating revenues, unaffiliated customers | 126,936 | 108,348 | 437,180 | 356,986 | ||
Intersegment Revenues | ||||||
Total operating revenues, unaffiliated customers | 126,936 | 108,348 | 437,180 | 356,986 | ||
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member] | ||||||
Operating Revenues, Unaffiliated Customers | ||||||
Total operating revenues, unaffiliated customers | 67,257 | 68,899 | 232,519 | 224,382 | ||
Intersegment Revenues | ||||||
Total operating revenues, unaffiliated customers | 67,257 | 68,899 | 232,519 | 224,382 | ||
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member] | ||||||
Operating Revenues, Unaffiliated Customers | ||||||
Total operating revenues, unaffiliated customers | 59,679 | 39,449 | 204,661 | 132,604 | ||
Intersegment Revenues | ||||||
Total operating revenues, unaffiliated customers | 59,679 | 39,449 | 204,661 | 132,604 | ||
Intersegment Revenues [Member] | ||||||
Operating Revenues, Unaffiliated Customers | ||||||
Total operating revenues, unaffiliated customers | [1] | 7,649 | 3,953 | 22,216 | 6,712 | |
Intersegment Revenues | ||||||
Total operating revenues, unaffiliated customers | [1] | 7,649 | 3,953 | 22,216 | 6,712 | |
Intersegment Revenues [Member] | Regulated Energy [Member] | ||||||
Operating Revenues, Unaffiliated Customers | ||||||
Total operating revenues, unaffiliated customers | [1] | 2,446 | 1,120 | 5,834 | 2,248 | |
Intersegment Revenues | ||||||
Total operating revenues, unaffiliated customers | [1] | 2,446 | 1,120 | 5,834 | 2,248 | |
Intersegment Revenues [Member] | Unregulated Energy [Member] | ||||||
Operating Revenues, Unaffiliated Customers | ||||||
Total operating revenues, unaffiliated customers | [1] | 5,009 | 2,593 | 15,801 | 3,759 | |
Intersegment Revenues | ||||||
Total operating revenues, unaffiliated customers | [1] | 5,009 | 2,593 | 15,801 | 3,759 | |
Intersegment Revenues [Member] | Other [Member] | ||||||
Operating Revenues, Unaffiliated Customers | ||||||
Total operating revenues, unaffiliated customers | [1] | 194 | 240 | 581 | 705 | |
Intersegment Revenues | ||||||
Total operating revenues, unaffiliated customers | [1] | $ 194 | $ 240 | $ 581 | $ 705 | |
[1] | All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. |
Stockholder's Equity - Accumu41
Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | ||
Beginning balance | $ (4,878) | $ (5,840) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 313 | 641 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (694) | 170 |
Net current-period other comprehensive income (loss) | (381) | 811 |
Ending balance | (5,259) | (5,029) |
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member] | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | ||
Beginning balance | (5,360) | (5,580) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (9) | |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 271 | 263 |
Net current-period other comprehensive income (loss) | 262 | 263 |
Ending balance | (5,098) | (5,317) |
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member] | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | ||
Beginning balance | 482 | (260) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 322 | 641 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (965) | (93) |
Net current-period other comprehensive income (loss) | (643) | 548 |
Ending balance | $ (161) | $ 288 |
Stockholder's Equity - Accum42
Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | ||
Amortization of pension and postretirement items: | |||||
Tax benefit | $ (4,324) | $ (2,990) | $ (20,781) | $ (21,401) | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | |||||
Amortization of pension and postretirement items: | |||||
Net of tax | (496) | (24) | 694 | (170) | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | |||||
Amortization of pension and postretirement items: | |||||
Prior service cost | [1] | 19 | 20 | 58 | 60 |
Net loss | [1] | (171) | (166) | (509) | (500) |
Total before tax | (152) | (146) | (451) | (440) | |
Tax benefit | 61 | 58 | 180 | 177 | |
Net of tax | (91) | (88) | (271) | (263) | |
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 | (653) | 105 | 1,593 | 142 | |
Tax benefit | 248 | (41) | (628) | (49) | |
Net of tax | (405) | 64 | 965 | 93 | |
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] | 198 | 663 | (322) | |
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] | 1 | |||
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] | $ (852) | $ 105 | $ 929 | $ 464 |
[1] | These amounts are included in the computation of net periodic costs (benefits). See Note 8, Employee Benefit Plans, for additional details. | ||||
[2] | (2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 11, Derivative Instruments, for additional details. |
Stockholder's Equity Stockholde
Stockholder's Equity Stockholder's Equity Additional Information (Details) | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2017USD ($)$ / shares$ / right$ / unitshares | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($)$ / sharesshares | ||||
Equity [Abstract] | ||||||
Preferred Stock, Shares Authorized | shares | 2,000,000 | 2,000,000 | ||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 0.01 | $ 0.01 | ||||
Stock Issued During Period, Shares, New Issues | shares | 960,488 | 960,488 | ||||
Stock Issued During Period, Value, Other | $ 62.26 | $ 62.26 | ||||
Proceeds from issuance of common stocks | [1] | 57,360,000 | ||||
Proceeds from Issuance of Common Stock | $ (10,000) | [1] | $ 57,306,000 | $ 57,360,000 | [1] | |
Common Stock ownership percentage | 15.00% | |||||
Preferred stock price per unit | $ / unit | 70 | |||||
redemption price per right | $ / right | 0.01 | |||||
[1] | On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million. |
Employee Benefit Plans (Detail)
Employee Benefit Plans (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Amortization of prior service cost | $ (19) | $ (20) | $ (58) | $ (60) |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | (277) | (274) | (826) | (815) |
Chesapeake Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 103 | 105 | 309 | 315 |
Expected return on plan assets | (127) | (131) | (381) | (392) |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | (107) | (103) | (319) | (309) |
Net periodic cost (benefit) | 83 | 77 | 247 | 232 |
Total periodic cost | 83 | 77 | 247 | 232 |
Florida Public Utilities Company Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 623 | 635 | 1,870 | 1,894 |
Expected return on plan assets | (699) | (625) | (2,098) | (2,027) |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | (131) | (133) | (392) | (389) |
Net periodic cost (benefit) | 55 | 143 | 164 | 256 |
Amortization of pre-merger regulatory asset | 191 | 191 | 571 | 571 |
Total periodic cost | 246 | 334 | 735 | 827 |
Chesapeake Pension SERP [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 22 | 23 | 66 | 68 |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | (22) | (22) | (65) | (66) |
Net periodic cost (benefit) | 44 | 45 | 131 | 134 |
Total periodic cost | 44 | 45 | 131 | 134 |
Chesapeake Postretirement Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 11 | 11 | 31 | 32 |
Amortization of prior service cost | (19) | (20) | (58) | (60) |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | (17) | (16) | (50) | (51) |
Net periodic cost (benefit) | 9 | 7 | 23 | 23 |
Total periodic cost | 9 | 7 | 23 | 23 |
Florida Public Utilities Company Medical Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 13 | 14 | 38 | 41 |
Net periodic cost (benefit) | 13 | 14 | 38 | 41 |
Amortization of pre-merger regulatory asset | 2 | 2 | 6 | 6 |
Total periodic cost | $ 15 | $ 16 | $ 44 | $ 47 |
Employee Benefit Plans - Additi
Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected pension and postretirement benefit costs | $ 1,600 | |||
Expected amortization of pre merger regulatory asset | 769 | |||
Florida Public Utilities Company Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Unamortized balance of regulatory asset | $ 1,500 | 1,500 | $ 2,100 | |
Contribution to pension plan | 110 | 1,639 | ||
Chesapeake Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Contribution to pension plan | 67 | 234 | ||
Chesapeake Pension SERP [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Contribution to pension plan | 38 | 114 | ||
Chesapeake Postretirement Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Contribution to pension plan | 30 | 94 | ||
Florida Public Utilities Company Medical Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Contribution to pension plan | $ 13 | $ 48 | ||
Scenario, Forecast [Member] | Florida Public Utilities Company Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year | $ 3,000 | |||
Scenario, Forecast [Member] | Chesapeake Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year | 746 | |||
Scenario, Forecast [Member] | Chesapeake Pension SERP [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year | 151 | |||
Scenario, Forecast [Member] | Chesapeake Postretirement Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year | 83 | |||
Scenario, Forecast [Member] | Florida Public Utilities Company Medical Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year | $ 129 |
Employee Benefit Plans - Amount
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 | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Prior service cost (credit) | $ (19) | $ (20) | $ (58) | $ (60) | |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | 277 | 274 | 826 | 815 | |
Recognized from accumulated other comprehensive loss | [1] | 152 | 146 | 451 | 440 |
Recognized from regulatory asset | 106 | 108 | 317 | 315 | |
Total recognized in net periodic benefit cost | 258 | 254 | 768 | 755 | |
Chesapeake Pension Plan [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | 107 | 103 | 319 | 309 | |
Recognized from accumulated other comprehensive loss | [1] | 107 | 103 | 319 | 309 |
Total recognized in net periodic benefit cost | 107 | 103 | 319 | 309 | |
Florida Public Utilities Company Pension Plan [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | 131 | 133 | 392 | 389 | |
Recognized from accumulated other comprehensive loss | [1] | 25 | 25 | 75 | 74 |
Recognized from regulatory asset | 106 | 108 | 317 | 315 | |
Total recognized in net periodic benefit cost | 131 | 133 | 392 | 389 | |
Chesapeake Pension SERP [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | 22 | 22 | 65 | 66 | |
Recognized from accumulated other comprehensive loss | [1] | 22 | 22 | 65 | 66 |
Total recognized in net periodic benefit cost | 22 | 22 | 65 | 66 | |
Chesapeake Postretirement Plan [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Prior service cost (credit) | (19) | (20) | (58) | (60) | |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | 17 | 16 | 50 | 51 | |
Recognized from accumulated other comprehensive loss | [1] | (2) | (4) | (8) | (9) |
Total recognized in net periodic benefit cost | $ (2) | $ (4) | $ (8) | $ (9) | |
[1] | See Note 7, Stockholder's Equity. |
Investments - Schedule of Inves
Investments - Schedule of Investments (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Investments schedule [Line Items] | ||
Investments, at fair value | $ 6,380 | $ 4,902 |
Rabbi Trust Associated With Deferred Compensation Plan [Member] | ||
Investments schedule [Line Items] | ||
Investments, at fair value | 6,358 | 4,881 |
Equity Securities [Member] | ||
Investments schedule [Line Items] | ||
Investments, at fair value | $ 22 | $ 21 |
Investments - Additional Inform
Investments - Additional Information (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Investments, Debt and Equity Securities [Abstract] | ||||
Unrealized gain (loss), net of other expenses | $ 261,000 | $ 193,000 | $ 694,000 | $ 246,000 |
Share-Based Compensation - Shar
Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Total compensation expense | $ 796 | $ 623 | $ 1,608 | $ 1,887 | |
Less: tax benefit | (320) | (251) | (647) | (760) | |
Share-Based Compensation amounts included in net income | 476 | 372 | $ 961 | 1,127 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 835 | ||||
Awards to non-employee directors [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Total compensation expense | $ 134 | 135 | $ 406 | 445 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 0 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | 7,515 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ 71.80 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | 7,515 | ||||
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 | 132,642 | 132,642 | 115,091 | ||
Total compensation expense | $ 662 | $ 488 | $ 1,202 | $ 1,442 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 52.42 | $ 52.42 | $ 51.85 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 52,355 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ 38.88 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | 32,926 |
Share-Based Compensation - Summ
Share-Based Compensation - Summary of Stock Activity under the SICP (Detail) | 9 Months Ended |
Sep. 30, 2017$ / sharesshares | |
Number of Shares | |
Granted awards (shares) | 835 |
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, Non-Option Equity Instruments, Granted | 7,515 |
Number of Shares | |
Vested (shares) | (7,515) |
Weighted Average Fair Value | |
Outstanding - December 31, 2016 (in dollars per share) | $ / shares | $ 0 |
Vested (in dollars per share) | $ / shares | $ 71.80 |
Award to key employees [Member] | |
Number of Shares | |
Outstanding - December 31, 2016 (shares) | 115,091 |
Granted awards (shares) | 52,355 |
Vested (shares) | (32,926) |
Expired (shares) | (1,878) |
Outstanding - September 30, 2017 (shares) | 132,642 |
Weighted Average Fair Value | |
Outstanding - December 31, 2016 (in dollars per share) | $ / shares | $ 51.85 |
Granted (in dollars per share) | $ / shares | 63.42 |
Vested (in dollars per share) | $ / shares | 38.88 |
Expired (in dollars per share) | $ / shares | 39.97 |
Outstanding - September 30, 2017 (in dollars per share) | $ / shares | $ 52.42 |
Share-Based Compensation - Addi
Share-Based Compensation - Additional Information (Detail) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted awards (shares) | 835 | ||
Shares Paid for Tax Withholding for Share Based Compensation | 10,269 | 12,031 | |
Payments Related to Tax Withholding for Share-based Compensation | $ 692 | $ 770 | |
Unrecognized compensation cost | $ 2,700 | ||
Awards to non-employee directors [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Amortization of expense equally over a service period | 1 year | ||
Unrecognized compensation expense related to the awards to non-employee directors | $ 314 | ||
Award to key employees [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted awards (shares) | 52,355 | ||
Vesting period | 3 years | ||
Intrinsic value of the SICP awards | $ 10,400 |
Derivative Instruments - Additi
Derivative Instruments - Additional Information (Detail) gal in Thousands, $ in Thousands, Mcf in Millions | 9 Months Ended | 12 Months Ended |
Sep. 30, 2017USD ($)$ / galgalMcf | Dec. 31, 2016USD ($)$ / galgal | |
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | Mcf | 1.4 | |
Energy Marketing Contracts Assets, Current | $ 1,526 | $ 823 |
Energy Marketing Contract Liabilities, Current | (1,732) | (773) |
Hedging Liability [Member] | Natural Gas Futures [Member] | ||
Derivative [Line Items] | ||
Energy Marketing Contract Liabilities, Current | (1,307) | |
Hedging Liability [Member] | Natural Gas Swaps [Member] | ||
Derivative [Line Items] | ||
Energy Marketing Contract Liabilities, Current | (412) | |
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Energy Marketing Contracts Assets, Current | 1,510 | |
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Natural Gas Swaps [Member] | ||
Derivative [Line Items] | ||
Energy Marketing Contracts Assets, Current | 1 | |
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Energy Marketing Contracts Assets, Current | 15 | 8 |
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Energy Marketing Contracts Assets, Current | 9 | |
Not Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities [Member] | Natural Gas Futures [Member] | ||
Derivative [Line Items] | ||
Energy Marketing Contract Liabilities, Current | $ (13) | $ (773) |
PESCO [Member] | Natural Gas Futures [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | Mcf | 4 | |
Derivative, Term of Contract | 2 years | |
Energy Marketing Contract Liabilities, Current | $ (1,300) | |
Sharp Energy Inc [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | gal | 630 | |
Payments for Derivative Instrument, Financing Activities | $ 33 | |
Derivative, Price Risk Option Strike Price | $ / gal | 0.5650 | |
2017 [Member] | Natural Gas Swaps [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | Mcf | 12 | |
2017 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | gal | 11,100 | |
2017 [Member] | Strike Price 4 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal | 0.59 | |
2017 [Member] | Strike Price 2 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal | 0.675 | |
2017 [Member] | Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Energy Marketing Contracts Assets, Current | $ 1,500 | |
2016 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | gal | 4,800 | |
Gain (Loss) on Hedging Activity | $ 193 | |
2016 [Member] | Strike Price 4 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal | 0.5225 | |
2016 [Member] | Strike Price 2 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal | 0.5650 |
Derivative Instruments - Fair V
Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contracts Assets, Current | $ 1,526 | $ 823 |
Energy Marketing Contract Liabilities, Current | 1,732 | 773 |
Mark To Market Energy Assets [Member] | Put Option [Member] | Derivatives not designated as hedging instruments [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contracts Assets, Current | 9 | |
Mark To Market Energy Assets [Member] | Natural Gas Swaps [Member] | Derivatives not designated as hedging instruments [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contracts Assets, Current | 1 | |
Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member] | Derivatives not designated as hedging instruments [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contracts Assets, Current | 15 | 8 |
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 | 1,510 | |
Hedging Asset [Member] | Natural Gas Futures [Member] | Derivatives designated as hedging instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contracts Assets, Current | 113 | |
Hedging Asset [Member] | Propane Swap Agreement [Member] | Derivatives designated as hedging instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contracts Assets, Current | 693 | |
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 | 13 | $ 773 |
Hedging Liability [Member] | Natural Gas Swaps [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contract Liabilities, Current | 412 | |
Hedging Liability [Member] | Natural Gas Futures [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contract Liabilities, Current | $ 1,307 |
Derivative Instruments - Effect
Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | ||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | $ (470,000) | $ 167,000 | $ 1,596,000 | $ 1,097,000 | |
Derivatives not designated as hedging instruments [Member] | Natural Gas Swaps [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | 1,000 | 1,000 | |||
Inventory [Member] | Derivatives designated as hedging instrument [Member] | Future [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | (233,000) | ||||
Inventories [Member] | Derivatives not designated as hedging instruments [Member] | Natural Gas Swaps [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | 1,000 | 1,000 | |||
Revenue [Member] | Derivatives not designated as hedging instruments [Member] | Forward Contracts [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | [1] | (231,000) | 112,000 | 44,000 | |
Unrealized Gain (Loss) on derivatives | [1] | (2,000) | |||
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 | 286,000 | 205,000 | 907,000 | 205,000 | |
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 | 15,000 | 11,000 | |||
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Future [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | (852,000) | 105,000 | 929,000 | 464,000 | |
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 | 198,000 | 663,000 | (364,000) | ||
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Put/Call Option [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | [2] | (9,000) | 73,000 | ||
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 | (413,000) | (413,000) | |||
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 | 1,590,000 | 213,000 | 814,000 | 559,000 | |
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 | $ (1,296,000) | $ (123,000) | $ (1,420,000) | $ 349,000 | |
[1] | (1) All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income. | ||||
[2] | As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory on the condensed consolidated balance sheets. |
Fair Value of Financial Instr55
Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Assets: | ||
Investments | $ 6,380 | $ 4,902 |
Liabilities: | ||
Energy Marketing Contract Liabilities, Current | 1,732 | 773 |
Equity Securities [Member] | ||
Assets: | ||
Investments | 22 | 21 |
Quoted Prices in Active Markets (Level 1) [Member] | ||
Assets: | ||
Assets, Fair Value Disclosure | 5,738 | 4,341 |
Quoted Prices in Active Markets (Level 1) [Member] | Equity Securities [Member] | ||
Assets: | ||
Investments | 22 | 21 |
Quoted Prices in Active Markets (Level 1) [Member] | Investments - other [Member] | ||
Assets: | ||
Investments | 5,716 | 4,320 |
Quoted Prices in Active Markets (Level 1) [Member] | Total Investments [Member] | ||
Assets: | ||
Investments | 5,738 | 4,341 |
Significant Other Observable Inputs (Level 2) [Member] | ||
Assets: | ||
Assets, Fair Value Disclosure | 1,526 | 823 |
Liabilities: | ||
Energy Marketing Contract Liabilities, Current | 1,732 | 773 |
Significant Other Observable Inputs (Level 2) [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member] | ||
Assets: | ||
Derivative assets | 1,526 | 823 |
Significant Unobservable Inputs (Level 3) [Member] | ||
Assets: | ||
Assets, Fair Value Disclosure | 642 | 561 |
Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member] | ||
Assets: | ||
Investments | 642 | 561 |
Significant Unobservable Inputs (Level 3) [Member] | Total Investments [Member] | ||
Assets: | ||
Investments | 642 | 561 |
Recurring [Member] | ||
Assets: | ||
Assets, Fair Value Disclosure | 7,906 | 5,725 |
Liabilities: | ||
Energy Marketing Contract Liabilities, Current | 1,732 | 773 |
Recurring [Member] | Equity Securities [Member] | ||
Assets: | ||
Investments | 22 | 21 |
Recurring [Member] | Investments in guaranteed income fund [Member] | ||
Assets: | ||
Investments | 642 | 561 |
Recurring [Member] | Investments - other [Member] | ||
Assets: | ||
Investments | 5,716 | 4,320 |
Recurring [Member] | Total Investments [Member] | ||
Assets: | ||
Investments | 6,380 | 4,902 |
Recurring [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member] | ||
Assets: | ||
Derivative assets | $ 1,526 | $ 823 |
Fair Value of Financial Instr56
Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Beginning Balance | $ 561 | $ 279 |
Purchases and adjustments | 76 | 120 |
Transfers | (88) | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales | (2) | (8) |
Investment Income | 7 | 6 |
Ending Balance | $ 642 | $ 485 |
Fair Value of Financial Instr57
Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Fair Value Disclosures [Abstract] | ||
Long-term debt including current maturities | $ 211.4 | $ 145.9 |
Fair value of long-term debt | $ 224.2 | $ 161.5 |
Long-Term Debt - Outstanding Lo
Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | |||
Total long-term debt | $ 211,400 | $ 145,900 | |
Capital lease obligation | 2,425 | 3,471 | |
Total Long-term debt | 213,384 | 149,053 | |
Less: current maturities | (12,136) | (12,099) | |
Less: debt issuance costs | (446) | (291) | |
Total long-term debt, net of current maturities | 201,248 | 136,954 | |
9.08% bond, due June 1, 2022 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | [1] | 7,981 | 7,978 |
6.64% note, due October 31, 2017 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 2,727 | 2,727 | |
5.50% note, due October 12, 2020 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 8,000 | 8,000 | |
5.93% note, due October 31, 2023 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 19,500 | 21,000 | |
5.68% note, due June 30, 2026 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 26,100 | 29,000 | |
Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 7,000 | 7,000 | |
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 20,000 | 20,000 | |
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 50,000 | 50,000 | |
3.25% note, due April 30, 2032 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 70,000 | ||
Promissory note [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | $ 97 | $ 168 | |
[1] | FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities. |
Long-Term Debt - Outstanding 59
Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail) | 9 Months Ended |
Sep. 30, 2017 | |
9.08% bond, due June 1, 2022 [Member] | |
Debt Instrument [Line Items] | |
Long-term debt, interest percentage | 9.08% |
Debt instrument, maturity date | Jun. 1, 2022 |
6.64% note, due October 31, 2017 [Member] | |
Debt Instrument [Line Items] | |
Long-term debt, interest percentage | 6.64% |
Debt instrument, maturity date | Oct. 31, 2017 |
5.50% note, due October 12, 2020 [Member] | |
Debt Instrument [Line Items] | |
Long-term debt, interest percentage | 5.50% |
Debt instrument, maturity date | Oct. 12, 2020 |
5.93% note, due October 31, 2023 [Member] | |
Debt Instrument [Line Items] | |
Long-term debt, interest percentage | 5.93% |
Debt instrument, maturity date | Oct. 31, 2023 |
5.68% note, due June 30, 2026 [Member] | |
Debt Instrument [Line Items] | |
Long-term debt, interest percentage | 5.68% |
Debt instrument, maturity date | Jun. 30, 2026 |
Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member] | |
Debt Instrument [Line Items] | |
Long-term debt, interest percentage | 6.43% |
Debt instrument, maturity date | May 2, 2028 |
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member] | |
Debt Instrument [Line Items] | |
Long-term debt, interest percentage | 3.73% |
Debt instrument, maturity date | Dec. 16, 2028 |
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member] | |
Debt Instrument [Line Items] | |
Long-term debt, interest percentage | 3.88% |
Debt instrument, maturity date | May 15, 2029 |
Uncollateralized Senior Note Due on Two Thousand Thirty Two [Member] | |
Debt Instrument [Line Items] | |
Long-term debt, interest percentage | 3.25% |
Debt instrument, maturity date | Apr. 30, 2032 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) - Notes Payable, Other Payables [Member] - Shelf Notes [Member] - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2017 | May 13, 2016 | |
Prudential [Member] | ||
Debt Instrument [Line Items] | ||
Senior notes | $ 150 | $ 70 |
Maturity date term | 20 years | |
Debt Instrument, Interest Rate, Stated Percentage | 3.25% | |
MetLife [Member] | ||
Debt Instrument [Line Items] | ||
Senior notes | $ 150 | |
Maturity date term | 20 years | |
New York Life [Member] | ||
Debt Instrument [Line Items] | ||
Senior notes | $ 100 | |
Maturity date term | 20 years |