Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Oct. 31, 2015 | |
Entity Information [Line Items] | ||
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 | Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 15,268,158 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Income - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Operating Revenues | ||||
Regulated energy | $ 63,796 | $ 59,356 | $ 235,438 | $ 223,168 |
Unregulated energy | 28,117 | 32,263 | 119,238 | 155,286 |
Total Operating Revenues | 91,913 | 91,619 | 354,676 | 378,454 |
Operating Expenses | ||||
Regulated energy cost of sales | 23,161 | 23,040 | 101,414 | 102,020 |
Unregulated energy and other cost of sales | 17,959 | 22,935 | 73,465 | 112,702 |
Operations | 26,388 | 25,365 | 79,522 | 76,604 |
Maintenance | 2,603 | 2,562 | 8,033 | 7,168 |
Gain from a settlement | 0 | 0 | (1,500) | 0 |
Depreciation and amortization | 7,636 | 6,774 | 22,155 | 20,146 |
Other taxes | 3,257 | 3,151 | 10,000 | 9,942 |
Total Operating Expenses | 81,004 | 83,827 | 293,089 | 328,582 |
Operating Income | 10,909 | 7,792 | 61,587 | 49,872 |
Other income, net of other expenses | 36 | (32) | (3) | 380 |
Interest charges | 2,492 | 2,495 | 7,425 | 6,954 |
Income Before Income Taxes | 8,453 | 5,265 | 54,159 | 43,298 |
Income taxes | 3,334 | 2,085 | 21,638 | 17,303 |
Net Income | $ 5,119 | $ 3,180 | $ 32,521 | $ 25,995 |
Weighted Average Common Shares Outstanding: | ||||
Basic (in shares) | 15,258,819 | 14,574,678 | 15,035,569 | 14,539,841 |
Diluted (in shares) | 15,306,843 | 14,616,665 | 15,083,641 | 14,588,130 |
Earnings Per Share of Common Stock: | ||||
Basic (in usd per share) | $ 0.34 | $ 0.22 | $ 2.16 | $ 1.79 |
Diluted (in usd per share) | 0.33 | 0.22 | 2.16 | 1.78 |
Cash Dividends Declared Per Share of Common Stock (in usd per share) | $ 0.2875 | $ 0.27 | $ 0.845 | $ 0.7967 |
Condensed Consolidated Stateme3
Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Net Income | $ 5,119 | $ 3,180 | $ 32,521 | $ 25,995 |
Employee Benefits, net of tax: | ||||
Amortization of prior service cost, net of tax of $(7), $(5), $(20) and $(18), respectively | (10) | (9) | (30) | (26) |
Net gain, net of tax of $62, $26, $187 and $80, respectively | 93 | 39 | 278 | 118 |
Commodity Contract Cash Flow Hedges [Abstract] | ||||
Unrealized loss on commodity contract cash flow hedges, net of tax of $(51), $(18), $(29) and $(19), respectively | (75) | (27) | (43) | (28) |
Total other comprehensive income | 8 | 3 | 205 | 64 |
Comprehensive Income | $ 5,127 | $ 3,183 | $ 32,726 | $ 26,059 |
Condensed Consolidated Stateme4
Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Tax expense recognized on the amortization of prior service cost | $ (7) | $ (5) | $ (20) | $ (18) |
Tax expense recognized on the net gain (loss) | 62 | 26 | 187 | 80 |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | $ (51) | $ (18) | $ (29) | $ (19) |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment | ||
Regulated energy | $ 813,145 | $ 766,855 |
Unregulated energy | 141,393 | 84,773 |
Other | 19,190 | 18,497 |
Total property, plant and equipment | 973,728 | 870,125 |
Less: Accumulated depreciation and amortization | (210,979) | (193,369) |
Plus: Construction work in progress | 56,441 | 13,006 |
Net property, plant and equipment | 819,190 | 689,762 |
Current Assets | ||
Cash and cash equivalents | 3,781 | 4,574 |
Accounts receivable (less allowance for uncollectible accounts of $1,088 and $1,120, respectively) | 39,861 | 53,300 |
Accrued revenue | 8,797 | 13,617 |
Propane inventory, at average cost | 4,211 | 7,250 |
Other inventory, at average cost | 4,143 | 3,699 |
Regulatory assets | 7,653 | 8,967 |
Storage gas prepayments | 3,839 | 4,258 |
Income taxes receivable | 6,935 | 18,806 |
Deferred income taxes | 338 | 0 |
Prepaid expenses | 7,507 | 6,652 |
Mark-to-market energy assets | 286 | 1,055 |
Other current assets | 339 | 195 |
Total current assets | 87,690 | 122,373 |
Deferred Charges and Other Assets | ||
Goodwill | 16,048 | 4,952 |
Other intangible assets, net | 2,317 | 2,404 |
Investments, at fair value | 3,412 | 3,678 |
Regulatory assets | 77,332 | 78,136 |
Receivables and other deferred charges | 2,453 | 3,164 |
Total deferred charges and other assets | 101,562 | 92,334 |
Total Assets | 1,008,442 | 904,469 |
Stockholders' equity | ||
Common stock, par value $0.4867 per share (authorized 25,000,000 shares) | 7,429 | 7,100 |
Additional paid-in capital | 189,321 | 156,581 |
Retained earnings | 162,036 | 142,317 |
Accumulated other comprehensive loss | (5,471) | (5,676) |
Deferred compensation obligation | 1,863 | 1,258 |
Treasury stock | (1,863) | (1,258) |
Total stockholders' equity | 353,315 | 300,322 |
Long-term debt, net of current maturities | 155,909 | 158,486 |
Total capitalization | 509,224 | 458,808 |
Current Liabilities | ||
Current portion of long-term debt | 9,139 | 9,109 |
Short-term borrowing | 127,093 | 88,231 |
Accounts payable | 41,129 | 44,610 |
Customer deposits and refunds | 24,020 | 25,197 |
Accrued interest | 3,242 | 1,352 |
Dividends payable | 4,388 | 3,939 |
Deferred Tax Liabilities, Net, Current | 0 | 832 |
Accrued compensation | 8,909 | 10,076 |
Regulatory liabilities | 9,346 | 3,268 |
Mark-to-market energy liabilities | 154 | 1,018 |
Other accrued liabilities | 9,443 | 6,603 |
Total current liabilities | 236,863 | 194,235 |
Deferred Credits and Other Liabilities | ||
Deferred income taxes | 174,247 | 160,232 |
Regulatory liabilities | 43,356 | 43,419 |
Environmental liabilities | 9,003 | 8,923 |
Other pension and benefit costs | 32,619 | 35,027 |
Deferred investment credits and Other liabilities | 3,130 | 3,825 |
Total deferred credits and other liabilities | $ 262,355 | $ 251,426 |
Other commitments and contingencies (Note 6) | ||
Total Capitalization and Liabilities | $ 1,008,442 | $ 904,469 |
Condensed Consolidated Balance6
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Allowance for uncollectible accounts | $ 1,088 | $ 1,120 |
Common stock, par value (in usd per share) | $ 0.4867 | $ 0.4867 |
Common stock, shares authorized | 25,000,000 | 25,000,000 |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Operating Activities | ||
Net Income | $ 32,521 | $ 25,995 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 22,155 | 20,146 |
Depreciation and accretion included in other costs | 5,280 | 5,152 |
Deferred income taxes, net | (1,155) | (156) |
Realized gain on commodity contracts/sales of assets/investments | (411) | (436) |
Unrealized loss on investments/commodity contracts | 60 | (44) |
Employee benefits | 901 | 476 |
Share-based compensation | 1,445 | 1,519 |
Other, net | 13 | 2 |
Changes in assets and liabilities: | ||
Accounts receivable and accrued revenue | 21,898 | 38,304 |
Propane inventory, storage gas and other inventory | 3,166 | 4,137 |
Increase (Decrease) in Regulatory Assets and Liabilities | 6,467 | (8,865) |
Prepaid expenses and other current assets | (159) | (804) |
Accounts payable and other accrued liabilities | (5,145) | (18,704) |
Income taxes receivable | 14,883 | 510 |
Customer deposits and refunds | (1,177) | (1,169) |
Accrued compensation | (1,406) | (1,242) |
Other assets and liabilities, net | (652) | 198 |
Net cash provided by operating activities | 98,684 | 65,019 |
Investing Activities | ||
Property, plant and equipment expenditures | (102,051) | (69,111) |
Proceeds from sales of assets | 109 | 505 |
Acquisitions, net of cash acquired | (20,930) | 0 |
Environmental expenditures | (113) | (134) |
Net cash used in investing activities | (122,985) | (68,740) |
Financing Activities | ||
Common stock dividends | (11,725) | (10,879) |
Purchase of stock for Dividend Reinvestment Plan | 633 | 300 |
Change in cash overdrafts due to outstanding checks | 2,964 | (503) |
Net borrowing (repayment) under line of credit agreements | 35,898 | (33,994) |
Proceeds from Issuance of Long-term Debt | 0 | 49,975 |
Repayment of long-term debt | (4,262) | (2,249) |
Net cash provided by financing activities | 23,508 | 2,650 |
Net Decrease in Cash and Cash Equivalents | (793) | (1,071) |
Cash and Cash Equivalents-Beginning of Period | 4,574 | 3,356 |
Cash and Cash Equivalents-End of Period | $ 3,781 | $ 2,285 |
Condensed Consolidated Stateme8
Condensed Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-In Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Loss [Member] | Deferred Compensation [Member] | Treasury Stock [Member] | |
Beginning Balances, shares at Dec. 31, 2013 | [1] | 14,457,345 | ||||||
Beginning Balances at Dec. 31, 2013 | $ 278,773 | $ 4,691 | $ 152,341 | $ 124,274 | $ (2,533) | $ 1,124 | $ (1,124) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net Income | 36,092 | 36,092 | ||||||
Other comprehensive loss | (3,143) | (3,143) | ||||||
Common Stock Dividends, Shares | 0 | |||||||
Dividends | (15,675) | (15,675) | ||||||
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan | 43,367 | |||||||
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan | 1,860 | $ 16 | 1,844 | |||||
Conversion of debentures, shares | [1] | 47,313 | ||||||
Stock Issued During Period, Value, Conversion of Convertible Securities | 535 | $ 15 | 520 | |||||
Share-based compensation, shares | [1],[2],[3] | 40,686 | ||||||
Share-based compensation and tax benefit | [2],[3] | 1,889 | $ 13 | 1,876 | ||||
Stock Split in Form of Stock Dividend Adjustment to Retained Earnings | (9) | $ 2,365 | (2,374) | |||||
Treasury stock activities | 0 | 134 | (134) | |||||
Ending Balances, shares at Dec. 31, 2014 | [1] | 14,588,711 | ||||||
Ending Balances at Dec. 31, 2014 | 300,322 | $ 7,100 | 156,581 | 142,317 | (5,676) | 1,258 | (1,258) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net Income | 32,521 | 32,521 | ||||||
Other comprehensive loss | 205 | 205 | ||||||
Common Stock Dividends, Shares | 0 | |||||||
Dividends | (12,802) | (12,802) | ||||||
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan | 36,289 | |||||||
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan | $ 18 | 1,849 | ||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | 1,867 | |||||||
Stock Issued During Period, Shares, Acquisitions | 592,970 | |||||||
Stock Issued During Period, Value, Acquisitions | 30,165 | $ 289 | 29,876 | |||||
Share-based compensation, shares | [1],[2],[3] | 45,703 | ||||||
Share-based compensation and tax benefit | [2],[3] | 1,037 | $ 22 | 1,015 | ||||
Treasury stock activities | 0 | 605 | (605) | |||||
Ending Balances, shares at Sep. 30, 2015 | [1] | 15,263,673 | ||||||
Ending Balances at Sep. 30, 2015 | $ 353,315 | $ 7,429 | $ 189,321 | $ 162,036 | $ (5,471) | $ 1,863 | $ (1,863) | |
[1] | Includes 70,253 and 57,382 shares at September 30, 2015 and December 31, 2014, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan. | |||||||
[2] | Includes amounts for shares issued for Directors’ compensation. | |||||||
[3] | The shares issued under the SICP are net of shares withheld for employee taxes. For the nine months ended September 30, 2015, and for the year ended December 31, 2014, we withheld 12,620 and 12,687 shares, respectively, for taxes. |
Condensed Consolidated Stateme9
Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares | 3 Months Ended | 9 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Sep. 30, 2015 | Dec. 31, 2014 | |
Deferred compensation plan held Rabbi Trust (in shares) | 70,253 | 70,253 | 57,382 |
Shares issued under the performance incentive plan withheld for employee taxes (in shares) | 12,620 | 12,687 | |
Cash Dividends Declared Per Share of Common Stock (in usd per share) | $ 0.2875 | $ 0.845 | $ 1.0667 |
Summary of Accounting Policies
Summary of Accounting Policies | 9 Months Ended |
Sep. 30, 2015 | |
Accounting Policies [Abstract] | |
Summary of Accounting Policies | Summary of Accounting Policies Basis of Presentation References in this document to the “Company,” “Chesapeake,” “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, 2014 . 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. Reclassifications As a result of the sale of our advanced information services subsidiary in October 2014, we changed our operating segments (see Note 7, Segment Information ). We reclassified certain amounts in the condensed consolidated statements of income for the three and nine months ended September 30, 2014 and condensed consolidated statements of cash flows for the nine months ended September 30, 2014 to conform to the current year's presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements. Gain Contingency Effective May 29, 2015, we entered into a settlement agreement with a vendor related to the implementation of a customer billing system. Pursuant to the agreement, we received $1.5 million in cash, which is reflected as "Gain from a settlement" in the accompanying condensed consolidated statements of income. Previously, at December 31, 2014, we recorded a $6.5 million pretax, non-cash impairment loss related to the same billing system implementation. We may also receive $750,000 in additional cash and discounts on future services; however, the receipt or retention of additional cash and future discounts is contingent upon engaging this vendor to provide agreed-upon services over the next five years. Subsequent Events On October 8, 2015, we entered into the Shelf Agreement with Prudential. See Note 14, Long-Term Debt for further details. On the same date, we also entered into the Credit Agreement with the Lenders for a $150.0 million Revolver for a term of five years . On October 19, 2015, we borrowed $25.0 million under the Revolver. See Note 15, Short-Term Borrowing for further details. FASB Statements and Other Authoritative Pronouncements 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. On July 9, 2015, the FASB affirmed its proposal to defer the implementation of this standard by one year. For public entities, this standard is effective for 2018 interim and annual financial statements. We are assessing the impact this standard may have on our financial position and results of operations. Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs . This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. As of September 30, 2015, we had $312,000 of unamortized debt issuance costs included in the accompanying condensed consolidated balance sheets. Upon adoption of ASU 2015-03, this will be presented as a deduction from long-term debt, net of current maturities. Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements . This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements which were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. This standard is not expected to have a material impact on our financial position and results of operation. Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The new guidance requires that the cumulative impact of a measurement period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 will be effective for our interim and annual financial statements issued beginning January 1, 2016 and is to be adopted on a prospective basis. Early adoption is permitted for financial statements that have not been previously issued. We are assessing the impact this standard may have on our financial position and results of operation. |
Calculation of Earnings Per Sha
Calculation of Earnings Per Share | 9 Months Ended |
Sep. 30, 2015 | |
Earnings Per Share [Abstract] | |
Calculation of Earnings Per Share | Calculation of Earnings Per Share Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 5,119 $ 3,180 $ 32,521 $ 25,995 Weighted average shares outstanding 15,258,819 14,574,678 15,035,569 14,539,841 Basic Earnings Per Share $ 0.34 $ 0.22 $ 2.16 $ 1.79 Calculation of Diluted Earnings Per Share: Reconciliation of Numerator: Net Income $ 5,119 $ 3,180 $ 32,521 $ 25,995 Reconciliation of Denominator: Weighted shares outstanding—Basic 15,258,819 14,574,678 15,035,569 14,539,841 Effect of dilutive securities: Share-based compensation 48,024 41,987 48,072 48,289 Adjusted denominator—Diluted 15,306,843 14,616,665 15,083,641 14,588,130 Diluted Earnings Per Share $ 0.33 $ 0.22 $ 2.16 $ 1.78 |
Acquisitions
Acquisitions | 9 Months Ended |
Sep. 30, 2015 | |
Business Combinations [Abstract] | |
Acquisitions | Acquisitions Gatherco Acquisition On April 1, 2015, we completed the merger with Gatherco, in which Gatherco merged with and into Aspire Energy of Ohio, a newly formed, wholly-owned subsidiary of Chesapeake. As a result, Aspire Energy of Ohio provides natural gas midstream services, including natural gas gathering services and natural gas liquid processing services to over 300 producers, through 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio. Aspire Energy of Ohio also supplies natural gas to Columbia Gas of Ohio, regional marketers of natural gas, and over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity, which Aspire Energy of Ohio manages under an operating agreement. At closing, we issued 592,970 shares of our common stock, valued at $30.2 million based on the closing price of our common stock as reported on the NYSE on April 1, 2015. In addition, we paid $27.5 million in cash and assumed $1.7 million of existing outstanding debt, which we paid off on the same date. We also acquired $6.8 million of cash on hand at closing. (in thousands) Chesapeake common stock $ 30,164 Cash 27,494 Acquired debt 1,696 Aggregate amount paid in the acquisition 59,354 Less: cash acquired (6,806 ) Net amount paid in the acquisition $ 52,548 The merger agreement provides for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities over the next five years. We incurred $1.3 million in transaction costs associated with this merger, $514,000 of which was expensed in the nine months ended September 30, 2015. Transactions costs are included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net income from this acquisition for the three months ended September 30, 2015, included in our condensed consolidated statement of income, were $5.7 million and $55,000 , respectively. The revenue and net loss from this acquisition for the nine months ended September 30, 2015, included in our condensed consolidated statement of income, were $11.0 million and $133,000 , respectively. The financial results of Aspire Energy of Ohio are projected to have a minimal impact on our earnings per share in 2015, since the merger was completed after the first quarter. The first quarter includes key winter months, which have historically produced a significant portion of Gatherco's annual earnings. This acquisition is expected to be accretive to our earnings in the first full year of operations, which will include the first quarter of 2016 . The preliminary purchase price allocation of the Gatherco acquisition is as follows: (in thousands) Purchase price $ 57,658 Property plant and equipment 52,578 Cash 6,806 Accounts receivable 3,629 Income taxes receivable 3,012 Other assets 247 Total assets acquired 66,272 Long-term debt 1,696 Deferred income taxes 13,863 Accounts payable 3,837 Other current liabilities 314 Total liabilities assumed 19,710 Net identifiable assets acquired 46,562 Goodwill $ 11,096 The excess of the purchase price over the estimated fair values of the assets acquired and the liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid primarily for opportunities for growth in a new, strategic geographic area. All of the goodwill from this acquisition was recorded in the Unregulated Energy segment and is not expected to be deductible for income tax purposes. The initial accounting for the Gatherco acquisition is not complete because the valuation necessary to assess the fair values of property, plant and equipment and the related impact on deferred income tax amounts is considered preliminary as we continue to evaluate these assets. The valuation of additional contingent cash consideration and potential environmental remediation costs may be adjusted as additional information becomes available. Although the purchase price allocation can be modified up to one year from the date of the acquisition, we intend to finalize the allocation as soon as practicable. Other acquisitions On May 7, 2015, we purchased certain propane distribution assets used to serve 253 customers in Citrus County, Florida for approximately $242,000 . In connection with this acquisition, we recorded $186,000 in intangible assets related to a non-compete agreement and the customer list to be amortized over six and 10 years, respectively. The remaining purchase price was allocated to property, plant and equipment and accounts receivable. The revenue and net income from this acquisition that were included in our condensed consolidated statements of income for the three and nine months ended September 30, 2015 were not material. |
Rates and Other Regulatory Acti
Rates and Other Regulatory Activities | 9 Months Ended |
Sep. 30, 2015 | |
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’s Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities. Delaware There were no significant rates and other regulatory activities in Delaware during the first nine months of 2015. Maryland Ocean City SIR Filing: On July 2, 2015, Sandpiper filed an application with the Maryland PSC, to establish an SIR to further fund system expansion within the city limits of Ocean City, Maryland. The proposed SIR, which would only be charged to customers located within city limits, was supported by Ocean City's local government. On August 5, 2015, the Maryland PSC approved the application. Florida On January 16, 2015, Chesapeake's Florida natural gas distribution division filed a petition with the Florida PSC for approval of a contract with its affiliate, Peninsula Pipeline, for additional natural gas transportation services in the vicinity of Haines City, located in Polk County, Florida. This petition was approved by the Florida PSC at its Agenda Conference on May 5, 2015. On July 1, 2015, FPU's electric division filed an electric depreciation study with the Florida PSC. Depending upon the Florida PSC’s decision in this proceeding, depreciation expense may change for FPU’s electric division as a result of a change in depreciation rates effective January 1, 2015. This action is scheduled for review by the Florida PSC at its Agenda Conference to be held in December 2015. On September 1, 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through the annual Fuel and Purchased Power Cost Recovery Clause filing. The project will enable FPU's electric division to negotiate a new power purchase agreement that will mitigate fuel costs for its Northeast Division. The hearing on this Docket was held on November 4, 2015. Ruling by the Florida PSC on the docket is expected at the Agenda Conference to be held in December 2015. Eastern Shore White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an industrial customer in Kent County, Delaware. Eastern Shore proposes to construct approximately 7.2 miles of 16 -inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additional compression at Eastern Shore’s existing Delaware City Compressor Station in New Castle County, Delaware. The estimated cost of the project is $29.8 million. On January 22, 2015, the FERC issued a Notice of Intent to Prepare an Environmental Assessment for this project. In February, April and May 2015, Eastern Shore filed environmental data in response to comments regarding evaluation of alternate routes for a segment of the pipeline route in the vicinity of the Kemblesville Historic District. On June 2, 2015, a field meeting was conducted to review the proposed route and alternate routes. In response to comments received from the National Park Service and other stakeholders, FERC Staff requested that Eastern Shore conduct an additional investigation in relation to Eastern Shore's existing right-of-way. On July 9, 2015, FERC issued a 30-day public scoping notice in advance of issuing an Environmental Assessment in order to solicit comments from the public regarding construction of the Kemblesville loop. On August 18, 2015, Eastern Shore submitted supplemental information to the FERC regarding the results of its investigation of the Kemblesville loop. System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization 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 proposes to reinforce critical points on its pipeline system. The total project will benefit all of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days in 2014 and 2015. The estimated cost of the project is $32.1 million. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project, and an order granting the requested authorization by December 2015. On June 8, 2015, the FERC filed a notice of the application, and the comment period ended on June 29, 2015. Eastern Shore anticipates FERC approval of this project in the fourth quarter of 2015 and estimates that construction will start in the first quarter of 2016. TETLP Capacity Expansion Project: On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities which will enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/day, for a total capacity of 160,000 Dts/d. Eastern Shore expects the project to be approved by the end of the year. |
Environmental Commitments and C
Environmental Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2015 | |
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. 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, 2015 , we had approximately $10.0 million in environmental liabilities, representing our estimate of the future costs associated with all of 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 all of its MGP sites, approximately $10.0 million of which has been recovered as of September 30, 2015 , leaving approximately $4.0 million in regulatory assets for future recovery of environmental costs from FPU’s customers. In addition to the FPU MGP sites, we had $389,000 in environmental liabilities at September 30, 2015 related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of September 30, 2015 , we had approximately $116,000 in regulatory and other assets for future recovery through Chesapeake’s rates. During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake’s MGP site in Seaford, Delaware, representing our estimate of future costs associated with this site, and recorded a regulatory asset for the same amount for probable future recovery through Chesapeake’s rates, although we have not yet sought Delaware PSC approval for recovery. As of September 30, 2015 , we had approximately $239,000 in environmental liabilities and $273,000 in regulatory and other assets related to this site. Environmental liabilities for all of 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. West Palm Beach, Florida We are evaluating remedial options to respond to environmental impacts to soil and groundwater at, and in the immediate vicinity of, a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is implementing a remedial plan approved by the FDEP for the east parcel of the West Palm Beach site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. We anticipate that similar remedial actions will ultimately be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately $4.5 million to $15.4 million , including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties. Sanford, Florida FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP at this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. 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 . As of September 30, 2015 , FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements. In December 2014, the EPA issued a preliminary close-out report, documenting the completion of all physical remediation construction activities at the Sanford site. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. The total cost of the final remedy is estimated to be over $20.0 million , which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement. As of September 30, 2015 , FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000 . However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site, as provided in the Third Participation Agreement, or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of September 30, 2015 . Key West, Florida FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two additional monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October 4, 2012. FDEP responded on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site. In October 2012, FDEP issued a RAP approval order, which requires a limited semi-annual monitoring program. The most recent groundwater-monitoring event was conducted on September 14, 2015. Natural Attenuation Default criteria were met at all locations sampled. The next semi-annual sampling event is scheduled for March 2016. Although the duration of the FDEP-required limited NAM cannot be determined with certainty, we anticipate that total costs to complete the remedial action will not exceed $50,000 . The annual cost to conduct the limited NAM program is not expected to exceed $8,000 . Pensacola, Florida FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that it would approve a conditional No Further Action determination for the site with the requirement for institutional and engineering controls. On June 16, 2014, FDEP issued a draft memorandum of understanding between FDOT and FDEP to implement site closure with approved institutional and engineering controls for the site. We anticipate that FPU’s share of remaining legal and cleanup costs will not exceed $5,000 . Winter Haven, Florida The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Groundwater monitoring results have shown a continuing reduction in contaminant concentrations from the sparging system, which has been in operation since 2002. On September 12, 2014, FDEP issued a letter approving shutdown of the sparging operations on the northern portion of the site, contingent upon continued semi-annual monitoring. Groundwater monitoring results on the southern portion of this site indicate that natural attenuation default criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation was reported in the semi-annual RAP implementation status report submitted on January 8, 2015. Although specific remedial actions have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $443,000 , which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. We continue to believe that the entire amount will be recoverable from customers through rates. FDEP previously indicated that we could also be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, and our recent meeting with FDEP, we believe that corrective measures for lake sediments are not warranted and will not be required by FDEP; therefore, we have not recorded a liability for sediment remediation. Salisbury, Maryland We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized groundwater contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. We anticipate that the remaining costs of the one remaining monitoring well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission the one remaining monitoring well. Seaford, Delaware In a letter dated December 5, 2013, the DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. We submitted an application to the DNREC on April 2, 2015, which was approved on September 17, 2015, to enter this site into the voluntary cleanup program. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000 . Other We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location. |
Other Commitments and Contingen
Other Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Other Commitments and Contingencies | Other Commitments and Contingencies Natural Gas, Electric and Propane Supply Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. Our Delaware and Maryland natural gas distribution divisions have a contract through March 31, 2017, with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity. In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six -year term. Approximately three years, four months remain under this contract. Sandpiper's current annual commitment is estimated at approximately 6.5 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. Sharp's current annual commitment is estimated at approximately 6.5 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’s 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 is contingently liable to FGT and Gulfstream should any party that acquired the capacity through release fail to pay the capacity charge. In May 2015, PESCO renewed contracts to purchase natural gas from various suppliers. The total monthly purchase commitment ranges from 9,982 to 13,423 Dts/d from June 2015 to May 2016. These contracts expire in May 2016. 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 FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. 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 either of these ratios, 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, 2015 , FPU was in compliance with all of the requirements of its fuel supply contracts. Corporate Guarantees The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $50.0 million . We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which is for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases, respectively, in the event that Xeron or PESCO defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at September 30, 2015 was $36.1 million , with the guarantees expiring on various dates through September 22, 2016 . Chesapeake also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14 , Long-Term Debt , for further details). In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million , which expires on September 12, 2016 , related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $1.2 million which expires on October 31, 2016 , as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company, we renewed and decreased the letter of credit for $24,000 to our former primary insurance company, which will expire on June 1, 2016 . We have also issued a letter of credit of $1.0 million which expires on March 31, 2016 , related to PESCO's transactions at the Natural Gas Exchange, Inc. We provided a letter of credit for $2.3 million to TETLP related to the firm transportation service agreement with our Delaware and Maryland divisions. There have been no draws on these letters of credit as of September 30, 2015 . 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. Tax-related Contingencies We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of September 30, 2015 , we maintained a liability of $100,000 related to unrecognized income tax benefits and $404,000 related to contingencies for taxes other than income. As of December 31, 2014 , we maintained a liability of $100,000 related to unrecognized income tax benefits and $724,000 related to contingencies for taxes other than income. 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, 2015 | |
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 comprise 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 and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Effective April 1, 2015, this segment includes Aspire Energy of Ohio, whose services include natural gas gathering and processing (See Note 3, Acquisitions , regarding the acquisition of Gatherco). Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services. We had previously identified "Other" as a separate reportable segment, which consisted primarily of our advanced information services subsidiary. As a result of the sale of that subsidiary on October 1, 2014, "Other" is no longer a separate reportable segment. The following table presents financial information about our reportable segments: Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy segment $ 63,526 $ 59,086 $ 234,608 $ 222,308 Unregulated Energy segment 28,387 27,041 120,068 141,215 Other businesses — 5,492 — 14,931 Total operating revenues, unaffiliated customers $ 91,913 $ 91,619 $ 354,676 $ 378,454 Intersegment Revenues (1) Regulated Energy segment $ 270 $ 270 $ 830 $ 860 Unregulated Energy segment 1,222 30 3,095 150 Other businesses 220 258 660 760 Total intersegment revenues $ 1,712 $ 558 $ 4,585 $ 1,770 Operating Income (Loss) Regulated Energy segment $ 11,828 $ 9,202 $ 47,616 $ 41,004 Unregulated Energy segment (1,022 ) (1,972 ) 13,666 8,843 Other businesses and eliminations 103 562 305 25 Total operating income 10,909 7,792 61,587 49,872 Other income (loss), net of other expenses 36 (32 ) (3 ) 380 Interest 2,492 2,495 7,425 6,954 Income before Income Taxes 8,453 5,265 54,159 43,298 Income taxes 3,334 2,085 21,638 17,303 Net Income $ 5,119 $ 3,180 $ 32,521 $ 25,995 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) September 30, 2015 December 31, 2014 Identifiable Assets Regulated Energy segment $ 824,330 $ 796,021 Unregulated Energy segment 156,838 84,732 Other businesses and eliminations 27,274 23,716 Total identifiable assets $ 1,008,442 $ 904,469 Our operations are entirely domestic. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 9 Months Ended |
Sep. 30, 2015 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Loss Defined benefit pension and postretirement plan items and unrealized gains (losses) of our propane swap agreements and call options, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive loss. The following tables present the changes in the balance of accumulated other comprehensive loss for the nine months ended September 30, 2015 and 2014 . 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, 2014 $ (5,643 ) $ (33 ) $ (5,676 ) Other comprehensive loss before reclassifications — (76 ) (76 ) Amounts reclassified from accumulated other comprehensive loss 248 33 281 Net current-period other comprehensive income 248 (43 ) 205 As of September 30, 2015 $ (5,395 ) $ (76 ) $ (5,471 ) Defined Benefit Commodity Pension and Contracts Postretirement Cash Flow Plan Items Hedges Total (in thousands) As of December 31, 2013 $ (2,533 ) $ — $ (2,533 ) Other comprehensive loss before reclassifications — (28 ) (28 ) Amounts reclassified from accumulated other comprehensive loss 92 — 92 Net current-period other comprehensive income (loss) 92 (28 ) 64 As of September 30, 2014 $ (2,441 ) $ (28 ) $ (2,469 ) The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2015 and 2014 . 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, 2015 2014 2015 2014 (in thousands) Amortization of defined benefit pension and postretirement plan items: Prior service cost (1) $ 17 $ 14 $ 50 $ 44 Net gain (1) (155 ) (65 ) (465 ) (198 ) Total before income taxes (138 ) (51 ) (415 ) (154 ) Income tax benefit 55 21 167 62 Net of tax $ (83 ) $ (30 ) $ (248 ) $ (92 ) Gains and losses on commodity contracts cash flow hedges Propane swap agreements (2) $ — $ — $ — $ — Call options (2) — — (55 ) — Total before income taxes — — (55 ) — Income tax benefit — — 22 — Net of tax — — (33 ) — Total reclassifications for the period $ (83 ) $ (30 ) $ (281 ) $ (92 ) (1) These amounts are included in the computation of net periodic costs (benefits). See Note 9 , Employee Benefit Plans , for additional details. (2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments , for additional details. Amortization of defined benefit pension and postretirement plan items is included in 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 expense in the accompanying condensed consolidated statements of income. |
Employee Benefit Plans
Employee Benefit Plans | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [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, 2015 and 2014 are set forth in the following tables: Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Three Months Ended September 30, 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 (in thousands) Interest cost $ 102 $ 107 $ 626 $ 647 $ 23 $ 23 $ 11 $ 13 $ 15 $ 17 Expected return on plan assets (135 ) (133 ) (777 ) (773 ) — — — — — — Amortization of prior service cost — — — — 2 5 (19 ) (19 ) — — Amortization of net loss 91 37 114 — 25 12 17 16 2 — Net periodic cost (benefit) 58 11 (37 ) (126 ) 50 40 9 10 17 17 Amortization of pre-merger regulatory asset — — 191 191 — — — — 2 2 Total periodic cost $ 58 $ 11 $ 154 $ 65 $ 50 $ 40 $ 9 $ 10 $ 19 $ 19 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Nine Months Ended September 30, 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 (in thousands) Interest cost $ 306 $ 320 $ 1,877 $ 1,941 $ 68 $ 69 $ 33 $ 39 $ 45 $ 50 Expected return on plan assets (405 ) (398 ) (2,330 ) (2,318 ) — — — — — — Amortization of prior service cost — — — — 8 14 (58 ) (58 ) — — Amortization of net loss 272 112 341 — 74 36 53 50 5 — Net periodic cost (benefit) 173 34 (112 ) (377 ) 150 119 28 31 50 50 Amortization of pre-merger regulatory asset — — 571 571 — — — — 6 6 Total periodic cost $ 173 $ 34 $ 459 $ 194 $ 150 $ 119 $ 28 $ 31 $ 56 $ 56 We expect to record pension and postretirement benefit costs of approximately $1.2 million for 2015. Included in these costs is $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 $3.1 million and $3.6 million at September 30, 2015 and December 31, 2014 , respectively. The amortization included in pension expense is also being added to a net periodic loss of $381,000 , which will increase our total expected benefit costs to $1.2 million . Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs 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’s operations is recorded to accumulated other comprehensive loss. The following table presents 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, 2015 and 2014 : For the Three Months Ended September 30, 2015 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service cost (credit) $ — $ — $ 2 $ (19 ) $ — $ (17 ) Net loss 91 114 25 17 2 249 Total recognized in net periodic benefit cost $ 91 $ 114 $ 27 $ (2 ) $ 2 $ 232 Recognized from accumulated other comprehensive loss (1) $ 91 $ 22 $ 27 $ (2 ) $ — $ 138 Recognized from regulatory asset — 92 — — 2 94 Total $ 91 $ 114 $ 27 $ (2 ) $ 2 $ 232 For the Nine Months Ended September 30, 2015 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service cost (credit) $ — $ — $ 8 $ (58 ) $ — $ (50 ) Net loss 272 341 74 53 5 745 Total recognized in net periodic benefit cost $ 272 $ 341 $ 82 $ (5 ) $ 5 $ 695 Recognized from accumulated other comprehensive loss (1) $ 272 $ 65 $ 82 $ (5 ) $ 1 $ 415 Recognized from regulatory asset — 276 — — 4 280 Total $ 272 $ 341 $ 82 $ (5 ) $ 5 $ 695 For the Three Months Ended September 30, 2014 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service cost (credit) $ — $ — $ 5 $ (19 ) $ — $ (14 ) Net loss 37 — 12 16 — 65 Total recognized in net periodic benefit cost $ 37 $ — $ 17 $ (3 ) $ — $ 51 Recognized from accumulated other comprehensive loss (1) $ 37 $ — $ 17 $ (3 ) $ — $ 51 Recognized from regulatory asset — — — — — — Total $ 37 $ — $ 17 $ (3 ) $ — $ 51 For the Nine Months Ended September 30, 2014 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service cost (credit) $ — $ — $ 14 $ (58 ) $ — $ (44 ) Net loss 112 — 36 50 — 198 Total recognized in net periodic benefit cost $ 112 $ — $ 50 $ (8 ) $ — $ 154 Recognized from accumulated other comprehensive loss (1) $ 112 $ — $ 50 $ (8 ) $ — $ 154 Recognized from regulatory asset — — — — — — Total $ 112 $ — $ 50 $ (8 ) $ — $ 154 (1) See Note 8 , Accumulated Other Comprehensive Loss . During the three and nine months ended September 30, 2015 , we contributed $127,000 and $346,000 , respectively, to the Chesapeake Pension Plan and $402,000 and $1.1 million , respectively, to the FPU Pension Plan. We expect to contribute a total of $475,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2015, which represent 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, 2015 , were $38,000 and $109,000 , respectively. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2015. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and nine months ended September 30, 2015 , were $14,000 and $42,000 , respectively. We estimate that approximately $79,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2015. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, 2015 , were $47,000 and $163,000 , respectively. We estimate that approximately $207,000 will be paid for such benefits under the FPU Medical Plan in 2015. |
Investments
Investments | 9 Months Ended |
Sep. 30, 2015 | |
Investments, Debt and Equity Securities [Abstract] | |
Investments | Investments The investment balances at September 30, 2015 and December 31, 2014 , consisted of the following: (in thousands) September 30, December 31, Rabbi trust (associated with the Deferred Compensation Plan) $ 3,394 $ 3,678 Investments in equity securities 18 — Total $ 3,412 $ 3,678 We classify these investments as trading securities and report them at their fair value. For the three months ended September 30, 2015 and 2014 , we recorded a net unrealized gain of $238,000 and $41,000 , respectively, in other income in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 2015 and 2014 , we recorded a net unrealized loss of $131,000 and a net unrealized gain of $111,000 , respectively, in other income 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 Rabbi Trust. |
Share-Based Compensation
Share-Based Compensation | 9 Months Ended |
Sep. 30, 2015 | |
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 the 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 grant date 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, 2015 and 2014 : Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands) Awards to non-employee directors $ 165 $ 137 $ 475 $ 394 Awards to key employees 334 317 970 1,125 Total compensation expense 499 454 1,445 1,519 Less: tax benefit (201 ) (183 ) (582 ) (612 ) Share-based compensation amounts included in net income $ 298 $ 271 $ 863 $ 907 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 2015, each of our non-employee directors received an annual retainer of 1,207 shares of common stock under the SICP for Board service through the 2016 Annual Meeting of Stockholders. A summary of the stock activity for our non-employee directors during the nine months ended September 30, 2015 is presented below: Number of Shares Weighted Average Fair Value Outstanding— December 31, 2014 — $ — Granted 14,484 $ 45.54 Vested (14,484 ) $ 45.54 Outstanding— September 30, 2015 — $ — At September 30, 2015 , there was $385,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2016. Key Employees The table below presents the summary of the stock activity for awards to key employees for the nine months ended September 30, 2015 : Number of Shares Weighted Average Fair Value Outstanding— December 31, 2014 123,038 $ 32.60 Granted 33,719 $ 48.21 Vested (43,839 ) $ 28.01 Expired (2,520 ) $ 28.83 Outstanding— September 30, 2015 110,398 $ 38.34 In January and March 2015, our Board of Directors granted awards of 33,719 shares of common stock to key employees under the SICP. The shares granted in January and March 2015 are multi-year awards that will vest at the end of the three -year service period ending December 31, 2017. 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 September 30, 2015 , the aggregate intrinsic value of the SICP awards granted to key employees was $5.9 million . At September 30, 2015 , there was $1.7 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2015 through 2017. |
Derivative Instruments
Derivative Instruments | 9 Months Ended |
Sep. 30, 2015 | |
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 their customers. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory or cash flow hedges of its future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of September 30, 2015 , our natural gas and electric distribution operations did not have any outstanding derivative contracts. Hedging Activities in 2015 In March, May and June 2015, Sharp paid a total of $143,000 to purchase put options to protect against a decline in propane prices and related potential inventory losses associated with 2.5 million gallons for the propane price cap program in the upcoming heating season. The put options are exercised if propane prices fall below the strike prices of $0.4950 , $0.4888 and $0.4500 per gallon in December 2015 through February 2016 and $0.4200 per gallon in January through March 2016. If exercised, we will receive the difference between the market price and the strike price during those months. We accounted for the put options as fair value hedges, and there is no ineffective portion of these hedges. As of September 30, 2015 , the put options had a fair value of $64,000 . The change in fair value of the put options effectively reduced our propane inventory balance. In March, May and June 2015, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 2.5 million gallons expected to be purchased for the upcoming heating season. Under these swap agreements, Sharp receives the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices of $0.5950 , $0.5888 , $0.5500 and $0.5200 per gallon for each swap agreement, to the extent the index prices exceed the swap prices. If the index prices are lower than the swap prices, Sharp will pay the difference. These swap agreements essentially fix the price of the 2.5 million gallons that we expect to purchase for the upcoming heating season. We accounted for the swap agreements as cash flow hedges, and there is no ineffective portion of these hedges. At September 30, 2015 , the swap agreements had a liability fair value of $128,000 . The change in the fair value of the swap agreements is recorded as unrealized gain/loss in other comprehensive income (loss). Hedging Activities in 2014 In August and October 2014, Sharp entered into call options to protect against an increase in propane prices associated with 1.3 million gallons purchased at market-based prices to supply the demands of our propane price cap program customers. The retail price that we charged to those customers during the heating season was capped at a pre-determined level. We would have exercised the call options if the propane prices had risen above the strike price of $1.0875 per gallon in December 2014 through February of 2015, and $1.0650 per gallon in January through March 2015. In that event, we would have received the difference between the market price and the strike price during those months. We paid $98,000 to purchase the call options, which expired without exercise as the market prices were below the strike prices. We accounted for the call options as cash flow hedges. In May 2014, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 630,000 gallons purchased in December 2014 through February 2015. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2014 through February 2015) and the swap prices of $1.1350 , $1.0975 and $1.0475 per gallon for each swap agreement, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap prices, Sharp would pay the difference. These swap agreements essentially fixed the price of the 630,000 gallons purchased during this period. We had initially accounted for them as cash flow hedges as the swap agreements met all the requirements. We paid $1.1 million , representing the difference between the market prices and strike prices during those months for the swap agreements. At December 31, 2014, we elected to discontinue hedge accounting on the swap agreements and reclassified $735,000 of unrealized loss from other comprehensive loss to propane cost of sales. Subsequently, we accounted for them as derivative instruments on a mark-to-market basis with the change in the fair value reflected in current period earnings. In May 2014, Sharp entered into put options to protect against declines in propane prices and related potential inventory losses associated with 630,000 gallons for the propane price cap program in December 2014 through February 2015. We exercised the put options because the propane prices fell below the strike prices of $1.0350 , $0.9975 , and $0.9475 per gallon, for each option agreement in December 2014 through February 2015, respectively. We paid $128,000 to purchase the put options and received $868,000 , representing the difference between the market prices and strike prices during those months. We accounted for them as fair value hedges. Commodity Contracts for Trading Activities Xeron engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statements of income for the period of change. As of September 30, 2015 , we had the following outstanding trading contracts, which we accounted for as derivatives: Quantity in Estimated Market Weighted Average At September 30, 2015 Gallons Prices Contract Prices Forward Contracts Sale 2,940,000 $0.4750 - $0.5288 $ 0.5210 Purchase 2,940,000 $0.4350 - $0.5025 $ 0.4545 Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the fourth quarter of 2015. Xeron has entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At September 30, 2015 , Xeron had no accounts receivable or accounts payable balances to offset with these two counterparties. At December 31, 2014, Xeron had a right to offset $1.6 million and $1.2 million of accounts receivable and accounts payable, respectively, with these two counterparties. 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, 2015 and December 31, 2014 , are as follows: Asset Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2015 December 31, 2014 Derivatives not designated as hedging instruments Forward contracts Mark-to-market energy assets $ 222 $ 407 Derivatives designated as fair value hedges Put options Mark-to-market energy assets 64 622 Derivatives designated as cash flow hedges Call options Mark-to-market energy assets — 26 Total asset derivatives $ 286 $ 1,055 Liability Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2015 December 31, 2014 Derivatives not designated as hedging instruments Forward contracts Mark-to-market energy liabilities $ 26 $ 283 Propane swap agreements Mark-to-market energy liabilities — 735 Derivatives designated as cash flow hedges Propane swap agreements Mark-to-market energy liabilities 128 — Total liability derivatives $ 154 $ 1,018 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 2015 2014 2015 2014 Derivatives not designated as hedging instruments Realized gain on forward contracts (1) Revenue $ 187 $ 54 $ 393 $ 1,384 Unrealized gain (loss) on forward contracts (1) Revenue (7 ) (5 ) 71 (67 ) Call option Cost of sales — — — 137 Propane swap agreements Cost of sales — — 18 — Derivatives designated as fair value hedges Put options Cost of sales — (43 ) 506 (92 ) Put options (2) Propane Inventory (46 ) — (79 ) — Derivatives designated as cash flow hedges Propane swap agreements Other Comprehensive Loss (126 ) (45 ) (128 ) (46 ) Call options Cost of sales — — (81 ) — Total $ 8 $ (39 ) $ 700 $ 1,316 (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 put 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. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 9 Months Ended |
Sep. 30, 2015 | |
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, 2015 and December 31, 2014 : Fair Value Measurements Using: As of September 30, 2015 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 $ 18 $ 18 $ — $ — Investments—guaranteed income fund $ 276 $ — $ — $ 276 Investments—other $ 3,118 $ 3,118 $ — $ — Mark-to-market energy assets, incl. put options and swap agreements $ 286 $ — $ 286 $ — Liabilities: Mark-to-market energy liabilities incl. swap agreements $ 154 $ — $ 154 $ — Fair Value Measurements Using: As of December 31, 2014 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—guaranteed income fund $ 287 $ — $ — $ 287 Investments—other $ 3,391 $ 3,391 $ — $ — Mark-to-market energy assets, incl. put/call options $ 1,055 $ — $ 1,055 $ — Liabilities: Mark-to-market energy liabilities, incl. swap agreements $ 1,018 $ — $ 1,018 $ — The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of September 30, 2015 and December 31, 2014 : 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- 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: Mark-to-market energy assets and liabilities— These forward contracts are valued using market transactions in either the listed or OTC markets. Propane put/call options and swap agreements— The fair value of the propane put/call options and swap agreements are determined 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, 2015 and 2014 : Nine Months Ended 2015 2014 (in thousands) Beginning Balance $ 287 $ 458 Purchases and adjustments (11 ) (89 ) Transfers (3 ) (58 ) Investment income 3 4 Ending Balance $ 276 $ 315 Investment income from the Level 3 investments is reflected in other income (loss) in the accompanying condensed consolidated statements of income. At September 30, 2015 , 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, 2015 , long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $159.9 million . This compares to a fair value of $175.8 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, 2014 , long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of $161.5 million , compared to the estimated fair value of $180.7 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, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Our outstanding long-term debt is shown below: September 30, December 31, (in thousands) 2015 2014 FPU secured first mortgage bonds (1) : 9.08% bond, due June 1, 2022 $ 7,973 $ 7,969 Uncollateralized senior notes: 6.64% note, due October 31, 2017 8,182 8,182 5.50% note, due October 12, 2020 12,000 12,000 5.93% note, due October 31, 2023 25,500 27,000 5.68% note, due June 30, 2026 29,000 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 Promissory notes 238 314 Capital lease obligation 5,155 6,130 Total long-term debt 165,048 167,595 Less: current maturities (9,139 ) (9,109 ) Total long-term debt, net of current maturities $ 155,909 $ 158,486 (1) FPU secured first mortgage bonds are guaranteed by Chesapeake. Shelf Agreement On October 8, 2015, we entered into a Shelf Agreement with Prudential. Under the terms of the Shelf Agreement, we may request that Prudential purchase, over the next three years , up to $150.0 million of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed twenty years from the date of issuance. Prudential is under no obligation to purchase any of the Shelf Notes. The interest rate and terms of payment of any series of Shelf Notes will be determined at the time of purchase. We currently anticipate the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowing and/or repayment of outstanding indebtedness and financing capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase and each request for purchase with respect to a series of Shelf Notes will specify the exact use of the proceeds. The Shelf Agreement sets forth certain business covenants to which we are subject when any Shelf Note is outstanding, including covenants that limit or restrict us and our subsidiaries from incurring indebtedness and incurring liens and encumbrances on any of our property. |
Short-term Borrowing (Notes)
Short-term Borrowing (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Short-term Borrowing [Abstract] | |
Short-term Debt [Text Block] | Short-Term Borrowing On October 8, 2015, we entered into a Credit Agreement with the Lenders for a $150.0 million Revolver for a term of five years subject to the terms and conditions of the Credit Agreement. Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements and capital expenditures. Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.25 percent or less. Interest will be payable quarterly and the Revolver is subject to a commitment fee on the unused portion of the facility. We may extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders to increase the Revolver to $200.0 million , with any increase at the sole discretion of each Lender. On October 19, 2015, we borrowed $25.0 million under the Revolver. |
Summary of Accounting Policies
Summary of Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Subsequent Event [Line Items] | |
Subsequent Events [Text Block] | Subsequent Events On October 8, 2015, we entered into the Shelf Agreement with Prudential. See Note 14, Long-Term Debt for further details. On the same date, we also entered into the Credit Agreement with the Lenders for a $150.0 million Revolver for a term of five years . On October 19, 2015, we borrowed $25.0 million under the Revolver. See Note 15, Short-Term Borrowing for further details. |
Basis of Presentation | Basis of Presentation References in this document to the “Company,” “Chesapeake,” “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, 2014 . 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. Reclassifications As a result of the sale of our advanced information services subsidiary in October 2014, we changed our operating segments (see Note 7, Segment Information ). We reclassified certain amounts in the condensed consolidated statements of income for the three and nine months ended September 30, 2014 and condensed consolidated statements of cash flows for the nine months ended September 30, 2014 to conform to the current year's presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements. Gain Contingency Effective May 29, 2015, we entered into a settlement agreement with a vendor related to the implementation of a customer billing system. Pursuant to the agreement, we received $1.5 million in cash, which is reflected as "Gain from a settlement" in the accompanying condensed consolidated statements of income. Previously, at December 31, 2014, we recorded a $6.5 million pretax, non-cash impairment loss related to the same billing system implementation. We may also receive $750,000 in additional cash and discounts on future services; however, the receipt or retention of additional cash and future discounts is contingent upon engaging this vendor to provide agreed-upon services over the next five years. |
Recent Accounting Standards Yet to be Adopted | FASB Statements and Other Authoritative Pronouncements 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. On July 9, 2015, the FASB affirmed its proposal to defer the implementation of this standard by one year. For public entities, this standard is effective for 2018 interim and annual financial statements. We are assessing the impact this standard may have on our financial position and results of operations. Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs . This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. As of September 30, 2015, we had $312,000 of unamortized debt issuance costs included in the accompanying condensed consolidated balance sheets. Upon adoption of ASU 2015-03, this will be presented as a deduction from long-term debt, net of current maturities. Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements . This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements which were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. This standard is not expected to have a material impact on our financial position and results of operation. Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The new guidance requires that the cumulative impact of a measurement period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 will be effective for our interim and annual financial statements issued beginning January 1, 2016 and is to be adopted on a prospective basis. Early adoption is permitted for financial statements that have not been previously issued. We are assessing the impact this standard may have on our financial position and results of operation. |
Calculation of Earnings Per S26
Calculation of Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Earnings Per Share [Abstract] | |
Calculation of Basic and Diluted Earnings Per Share | Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 5,119 $ 3,180 $ 32,521 $ 25,995 Weighted average shares outstanding 15,258,819 14,574,678 15,035,569 14,539,841 Basic Earnings Per Share $ 0.34 $ 0.22 $ 2.16 $ 1.79 Calculation of Diluted Earnings Per Share: Reconciliation of Numerator: Net Income $ 5,119 $ 3,180 $ 32,521 $ 25,995 Reconciliation of Denominator: Weighted shares outstanding—Basic 15,258,819 14,574,678 15,035,569 14,539,841 Effect of dilutive securities: Share-based compensation 48,024 41,987 48,072 48,289 Adjusted denominator—Diluted 15,306,843 14,616,665 15,083,641 14,588,130 Diluted Earnings Per Share $ 0.33 $ 0.22 $ 2.16 $ 1.78 |
Acquisitions Acquisitions (Tabl
Acquisitions Acquisitions (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Business Combinations [Abstract] | |
Merger Consideration paid [Table Text Block] | (in thousands) Chesapeake common stock $ 30,164 Cash 27,494 Acquired debt 1,696 Aggregate amount paid in the acquisition 59,354 Less: cash acquired (6,806 ) Net amount paid in the acquisition $ 52,548 |
Purchase price allocation [Table Text Block] | (in thousands) Purchase price $ 57,658 Property plant and equipment 52,578 Cash 6,806 Accounts receivable 3,629 Income taxes receivable 3,012 Other assets 247 Total assets acquired 66,272 Long-term debt 1,696 Deferred income taxes 13,863 Accounts payable 3,837 Other current liabilities 314 Total liabilities assumed 19,710 Net identifiable assets acquired 46,562 Goodwill $ 11,096 |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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, 2015 2014 2015 2014 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy segment $ 63,526 $ 59,086 $ 234,608 $ 222,308 Unregulated Energy segment 28,387 27,041 120,068 141,215 Other businesses — 5,492 — 14,931 Total operating revenues, unaffiliated customers $ 91,913 $ 91,619 $ 354,676 $ 378,454 Intersegment Revenues (1) Regulated Energy segment $ 270 $ 270 $ 830 $ 860 Unregulated Energy segment 1,222 30 3,095 150 Other businesses 220 258 660 760 Total intersegment revenues $ 1,712 $ 558 $ 4,585 $ 1,770 Operating Income (Loss) Regulated Energy segment $ 11,828 $ 9,202 $ 47,616 $ 41,004 Unregulated Energy segment (1,022 ) (1,972 ) 13,666 8,843 Other businesses and eliminations 103 562 305 25 Total operating income 10,909 7,792 61,587 49,872 Other income (loss), net of other expenses 36 (32 ) (3 ) 380 Interest 2,492 2,495 7,425 6,954 Income before Income Taxes 8,453 5,265 54,159 43,298 Income taxes 3,334 2,085 21,638 17,303 Net Income $ 5,119 $ 3,180 $ 32,521 $ 25,995 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) September 30, 2015 December 31, 2014 Identifiable Assets Regulated Energy segment $ 824,330 $ 796,021 Unregulated Energy segment 156,838 84,732 Other businesses and eliminations 27,274 23,716 Total identifiable assets $ 1,008,442 $ 904,469 |
Accumulated Other Comprehensi29
Accumulated Other Comprehensive Income (Loss) (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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, 2014 $ (5,643 ) $ (33 ) $ (5,676 ) Other comprehensive loss before reclassifications — (76 ) (76 ) Amounts reclassified from accumulated other comprehensive loss 248 33 281 Net current-period other comprehensive income 248 (43 ) 205 As of September 30, 2015 $ (5,395 ) $ (76 ) $ (5,471 ) Defined Benefit Commodity Pension and Contracts Postretirement Cash Flow Plan Items Hedges Total (in thousands) As of December 31, 2013 $ (2,533 ) $ — $ (2,533 ) Other comprehensive loss before reclassifications — (28 ) (28 ) Amounts reclassified from accumulated other comprehensive loss 92 — 92 Net current-period other comprehensive income (loss) 92 (28 ) 64 As of September 30, 2014 $ (2,441 ) $ (28 ) $ (2,469 ) |
Reclassifications out of Accumulated Other Comprehensive Income (Loss) | Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands) Amortization of defined benefit pension and postretirement plan items: Prior service cost (1) $ 17 $ 14 $ 50 $ 44 Net gain (1) (155 ) (65 ) (465 ) (198 ) Total before income taxes (138 ) (51 ) (415 ) (154 ) Income tax benefit 55 21 167 62 Net of tax $ (83 ) $ (30 ) $ (248 ) $ (92 ) Gains and losses on commodity contracts cash flow hedges Propane swap agreements (2) $ — $ — $ — $ — Call options (2) — — (55 ) — Total before income taxes — — (55 ) — Income tax benefit — — 22 — Net of tax — — (33 ) — Total reclassifications for the period $ (83 ) $ (30 ) $ (281 ) $ (92 ) |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Employee Benefit Plans | For the Three Months Ended September 30, 2015 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service cost (credit) $ — $ — $ 2 $ (19 ) $ — $ (17 ) Net loss 91 114 25 17 2 249 Total recognized in net periodic benefit cost $ 91 $ 114 $ 27 $ (2 ) $ 2 $ 232 Recognized from accumulated other comprehensive loss (1) $ 91 $ 22 $ 27 $ (2 ) $ — $ 138 Recognized from regulatory asset — 92 — — 2 94 Total $ 91 $ 114 $ 27 $ (2 ) $ 2 $ 232 For the Nine Months Ended September 30, 2015 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service cost (credit) $ — $ — $ 8 $ (58 ) $ — $ (50 ) Net loss 272 341 74 53 5 745 Total recognized in net periodic benefit cost $ 272 $ 341 $ 82 $ (5 ) $ 5 $ 695 Recognized from accumulated other comprehensive loss (1) $ 272 $ 65 $ 82 $ (5 ) $ 1 $ 415 Recognized from regulatory asset — 276 — — 4 280 Total $ 272 $ 341 $ 82 $ (5 ) $ 5 $ 695 For the Three Months Ended September 30, 2014 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service cost (credit) $ — $ — $ 5 $ (19 ) $ — $ (14 ) Net loss 37 — 12 16 — 65 Total recognized in net periodic benefit cost $ 37 $ — $ 17 $ (3 ) $ — $ 51 Recognized from accumulated other comprehensive loss (1) $ 37 $ — $ 17 $ (3 ) $ — $ 51 Recognized from regulatory asset — — — — — — Total $ 37 $ — $ 17 $ (3 ) $ — $ 51 For the Nine Months Ended September 30, 2014 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service cost (credit) $ — $ — $ 14 $ (58 ) $ — $ (44 ) Net loss 112 — 36 50 — 198 Total recognized in net periodic benefit cost $ 112 $ — $ 50 $ (8 ) $ — $ 154 Recognized from accumulated other comprehensive loss (1) $ 112 $ — $ 50 $ (8 ) $ — $ 154 Recognized from regulatory asset — — — — — — Total $ 112 $ — $ 50 $ (8 ) $ — $ 154 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Three Months Ended September 30, 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 (in thousands) Interest cost $ 102 $ 107 $ 626 $ 647 $ 23 $ 23 $ 11 $ 13 $ 15 $ 17 Expected return on plan assets (135 ) (133 ) (777 ) (773 ) — — — — — — Amortization of prior service cost — — — — 2 5 (19 ) (19 ) — — Amortization of net loss 91 37 114 — 25 12 17 16 2 — Net periodic cost (benefit) 58 11 (37 ) (126 ) 50 40 9 10 17 17 Amortization of pre-merger regulatory asset — — 191 191 — — — — 2 2 Total periodic cost $ 58 $ 11 $ 154 $ 65 $ 50 $ 40 $ 9 $ 10 $ 19 $ 19 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Nine Months Ended September 30, 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 (in thousands) Interest cost $ 306 $ 320 $ 1,877 $ 1,941 $ 68 $ 69 $ 33 $ 39 $ 45 $ 50 Expected return on plan assets (405 ) (398 ) (2,330 ) (2,318 ) — — — — — — Amortization of prior service cost — — — — 8 14 (58 ) (58 ) — — Amortization of net loss 272 112 341 — 74 36 53 50 5 — Net periodic cost (benefit) 173 34 (112 ) (377 ) 150 119 28 31 50 50 Amortization of pre-merger regulatory asset — — 571 571 — — — — 6 6 Total periodic cost $ 173 $ 34 $ 459 $ 194 $ 150 $ 119 $ 28 $ 31 $ 56 $ 56 |
Investments Investments (Tables
Investments Investments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Investments, Debt and Equity Securities [Abstract] | |
Investments schedule [Table Text Block] | (in thousands) September 30, December 31, Rabbi trust (associated with the Deferred Compensation Plan) $ 3,394 $ 3,678 Investments in equity securities 18 — Total $ 3,412 $ 3,678 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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 [Table Text Block] | 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, 2015 and 2014 : Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands) Awards to non-employee directors $ 165 $ 137 $ 475 $ 394 Awards to key employees 334 317 970 1,125 Total compensation expense 499 454 1,445 1,519 Less: tax benefit (201 ) (183 ) (582 ) (612 ) Share-based compensation amounts included in net income $ 298 $ 271 $ 863 $ 907 |
Awards to non-employee directors [Member] | |
Shares awarded to non-employee directors [Line Items] | |
Schedule of Share-based Compensation, Activity [Table Text Block] | A summary of the stock activity for our non-employee directors during the nine months ended September 30, 2015 is presented below: Number of Shares Weighted Average Fair Value Outstanding— December 31, 2014 — $ — Granted 14,484 $ 45.54 Vested (14,484 ) $ 45.54 Outstanding— September 30, 2015 — $ — |
Award to key employees [Member] | |
Shares awarded to non-employee directors [Line Items] | |
Schedule of Share-based Compensation, Activity [Table Text Block] | The table below presents the summary of the stock activity for awards to key employees for the nine months ended September 30, 2015 : Number of Shares Weighted Average Fair Value Outstanding— December 31, 2014 123,038 $ 32.60 Granted 33,719 $ 48.21 Vested (43,839 ) $ 28.01 Expired (2,520 ) $ 28.83 Outstanding— September 30, 2015 110,398 $ 38.34 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Outstanding Trading Contracts | Quantity in Estimated Market Weighted Average At September 30, 2015 Gallons Prices Contract Prices Forward Contracts Sale 2,940,000 $0.4750 - $0.5288 $ 0.5210 Purchase 2,940,000 $0.4350 - $0.5025 $ 0.4545 Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the fourth quarter of 2015. |
Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet | air values of the derivative contracts recorded in the condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 , are as follows: Asset Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2015 December 31, 2014 Derivatives not designated as hedging instruments Forward contracts Mark-to-market energy assets $ 222 $ 407 Derivatives designated as fair value hedges Put options Mark-to-market energy assets 64 622 Derivatives designated as cash flow hedges Call options Mark-to-market energy assets — 26 Total asset derivatives $ 286 $ 1,055 Liability Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2015 December 31, 2014 Derivatives not designated as hedging instruments Forward contracts Mark-to-market energy liabilities $ 26 $ 283 Propane swap agreements Mark-to-market energy liabilities — 735 Derivatives designated as cash flow hedges Propane swap agreements Mark-to-market energy liabilities 128 — Total liability derivatives $ 154 $ 1,018 |
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 2015 2014 2015 2014 Derivatives not designated as hedging instruments Realized gain on forward contracts (1) Revenue $ 187 $ 54 $ 393 $ 1,384 Unrealized gain (loss) on forward contracts (1) Revenue (7 ) (5 ) 71 (67 ) Call option Cost of sales — — — 137 Propane swap agreements Cost of sales — — 18 — Derivatives designated as fair value hedges Put options Cost of sales — (43 ) 506 (92 ) Put options (2) Propane Inventory (46 ) — (79 ) — Derivatives designated as cash flow hedges Propane swap agreements Other Comprehensive Loss (126 ) (45 ) (128 ) (46 ) Call options Cost of sales — — (81 ) — Total $ 8 $ (39 ) $ 700 $ 1,316 |
Fair Value of Financial Instr34
Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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, 2015 and December 31, 2014 : Fair Value Measurements Using: As of September 30, 2015 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 $ 18 $ 18 $ — $ — Investments—guaranteed income fund $ 276 $ — $ — $ 276 Investments—other $ 3,118 $ 3,118 $ — $ — Mark-to-market energy assets, incl. put options and swap agreements $ 286 $ — $ 286 $ — Liabilities: Mark-to-market energy liabilities incl. swap agreements $ 154 $ — $ 154 $ — Fair Value Measurements Using: As of December 31, 2014 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—guaranteed income fund $ 287 $ — $ — $ 287 Investments—other $ 3,391 $ 3,391 $ — $ — Mark-to-market energy assets, incl. put/call options $ 1,055 $ — $ 1,055 $ — Liabilities: Mark-to-market energy liabilities, incl. swap agreements $ 1,018 $ — $ 1,018 $ — |
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, 2015 and 2014 : Nine Months Ended 2015 2014 (in thousands) Beginning Balance $ 287 $ 458 Purchases and adjustments (11 ) (89 ) Transfers (3 ) (58 ) Investment income 3 4 Ending Balance $ 276 $ 315 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Debt Disclosure [Abstract] | |
Outstanding Long-Term Debt | Our outstanding long-term debt is shown below: September 30, December 31, (in thousands) 2015 2014 FPU secured first mortgage bonds (1) : 9.08% bond, due June 1, 2022 $ 7,973 $ 7,969 Uncollateralized senior notes: 6.64% note, due October 31, 2017 8,182 8,182 5.50% note, due October 12, 2020 12,000 12,000 5.93% note, due October 31, 2023 25,500 27,000 5.68% note, due June 30, 2026 29,000 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 Promissory notes 238 314 Capital lease obligation 5,155 6,130 Total long-term debt 165,048 167,595 Less: current maturities (9,139 ) (9,109 ) Total long-term debt, net of current maturities $ 155,909 $ 158,486 (1) FPU secured first mortgage bonds are guaranteed by Chesapeake. |
Summary of Accounting Policie36
Summary of Accounting Policies Summary of Accounting policies (Details) - USD ($) | Oct. 19, 2015 | Oct. 08, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 |
Subsequent Event [Line Items] | |||||||
Gain From A Settlement | $ 0 | $ 0 | $ 1,500,000 | $ 0 | |||
Asset Impairment Charges | $ 6,500,000 | ||||||
Gain Contingency, Unrecorded Amount | 750,000 | $ 750,000 | |||||
Period Additional Cash And Discounts On Future Services Is Based On | 5 years | ||||||
Debt Instrument, Unamortized Discount | $ 312,000 | $ 312,000 | |||||
Revolving Credit Facility [Member] | Subsequent Event [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Line of Credit Facility, Current Borrowing Capacity | $ 150,000,000 | ||||||
Line of Credit Facility, Expiration Period | 5 years | ||||||
Line of Credit Facility, Maximum Amount Outstanding During Period | $ 25,000,000 |
Calculation of Earnings Per S37
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, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Calculation of Basic Earnings Per Share: | |||||
Net Income | $ 5,119 | $ 3,180 | $ 32,521 | $ 25,995 | $ 36,092 |
Weighted shares outstanding - Basic (in shares) | 15,258,819 | 14,574,678 | 15,035,569 | 14,539,841 | |
Basic Earnings Per Share (in usd per share) | $ 0.34 | $ 0.22 | $ 2.16 | $ 1.79 | |
Reconciliation of Numerator: | |||||
Net Income | $ 5,119 | $ 3,180 | $ 32,521 | $ 25,995 | $ 36,092 |
Reconciliation of Denominator: | |||||
Weighted shares outstanding - Basic (in shares) | 15,258,819 | 14,574,678 | 15,035,569 | 14,539,841 | |
Effect of dilutive securities: | |||||
Share-based Compensation (in shares) | 48,024 | 41,987 | 48,072 | 48,289 | |
Adjusted denominator-Diluted (in shares) | 15,306,843 | 14,616,665 | 15,083,641 | 14,588,130 | |
Diluted Earnings Per Share (in usd per share) | $ 0.33 | $ 0.22 | $ 2.16 | $ 1.78 |
Acquisitions - Additional Infor
Acquisitions - Additional Information (Detail) $ in Thousands | May. 07, 2015USD ($) | Apr. 01, 2015USD ($)mi | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)shares | Sep. 30, 2014USD ($) | Dec. 31, 2014USD ($) |
Business Acquisition [Line Items] | |||||||
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed | $ (514) | ||||||
Revenues | $ 91,913 | $ 91,619 | 354,676 | $ 378,454 | |||
Net Income (Loss) Attributable to Parent | 5,119 | $ 3,180 | $ 32,521 | $ 25,995 | $ 36,092 | ||
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life | 10 years | ||||||
Gatherco [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Number Of Gathering Stations | 16 | ||||||
Number of Pipeline Miles | mi | 2,000 | ||||||
Number of Producers Served | 300 | ||||||
Number of Customers Served | 6,000 | ||||||
Business Combination, Consideration Transferred | $ 57,658 | ||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 592,970 | ||||||
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned | $ 30,200 | 30,164 | $ 30,164 | ||||
Payments to Acquire Businesses, Gross | 27,500 | 27,494 | |||||
Long-term debt | 1,696 | 1,696 | 1,696 | ||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents | $ 6,800 | 6,806 | 6,806 | ||||
Business Combination Contingent Cash Consideration Payable | 15,000 | $ 15,000 | |||||
Period Additional Contingent Cash Consideration Will Be Based On | 5 years | ||||||
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed | $ (1,300) | ||||||
Revenues | 5,700 | 11,000 | |||||
Net Income (Loss) Attributable to Parent | $ 55 | $ (133) | |||||
Propane Distribution [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Number of Customers Served | 253 | ||||||
Business Combination, Consideration Transferred | $ 242 | ||||||
Finite-lived Intangible Assets Acquired | $ 186 | ||||||
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life | 6 years |
Acquisitions Purchase Considera
Acquisitions Purchase Considerations (Details) - Gatherco [Member] - USD ($) $ in Thousands | Apr. 01, 2015 | Sep. 30, 2015 |
Business Acquisition [Line Items] | ||
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned | $ 30,200 | $ 30,164 |
Payments to Acquire Businesses, Gross | 27,500 | 27,494 |
Long-term debt | 1,696 | 1,696 |
Business Combination, Consideration Transferred | 57,658 | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents | $ (6,800) | (6,806) |
Gross [Member] | ||
Business Acquisition [Line Items] | ||
Business Combination, Consideration Transferred | 59,354 | |
Net [Member] | ||
Business Acquisition [Line Items] | ||
Business Combination, Consideration Transferred | $ 52,548 |
Acquisitions Gatherco purchase
Acquisitions Gatherco purchase price allocation (Details) - USD ($) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2015 | Apr. 01, 2015 | Dec. 31, 2014 | |
Business Acquisition [Line Items] | |||
Goodwill | $ 16,048 | $ 4,952 | |
Gatherco [Member] | |||
Business Acquisition [Line Items] | |||
Purchase price | 57,658 | ||
Property plant and equipment | 52,578 | ||
Cash | 6,806 | $ 6,800 | |
Accounts receivable | 3,629 | ||
Income taxes receivable | 3,012 | ||
Other assets | 247 | ||
Total assets acquired | 66,272 | ||
Long-term debt | 1,696 | $ 1,696 | |
Deferred income taxes | 13,863 | ||
Accounts payable | 3,837 | ||
Other current liabilities | 314 | ||
Total liabilities assumed | 19,710 | ||
Net identifiable assets acquired | 46,562 | ||
Goodwill | $ 11,096 |
Rates and Other Regulatory Ac41
Rates and Other Regulatory Activities - Additional Information (Detail) - Eastern Shore [Member] $ in Millions | Oct. 13, 2015dekatherm / d | Sep. 30, 2015USD ($)dekatherm / dinmi | Dec. 31, 2014USD ($) |
White Oak Lateral Mainline Expansion [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Volume The Expansion Project Is Expected to Provide | 45,000 | ||
Number of Pipeline Miles | mi | 7.2 | ||
Lateral diamater of pipeline to be installed | in | 16 | ||
Horsepower Of Additional Compression | 3,550 | ||
Estimated capital cost | $ | $ 29.8 | ||
System Reliability Project [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Number of Pipeline Miles | mi | 10.1 | ||
Lateral diamater of pipeline to be installed | in | 16 | ||
Estimated capital cost | $ | $ 32.1 | ||
TETLP Expansion Project [Member] | |||
Rates and Other Regulatory Activities [Line Items] | |||
Volume The Expansion Project Is Expected to Provide | 53,000 | ||
Total Capacity After Pipeline Improvements | 160,000 |
Environmental Commitments and42
Environmental Commitments and Contingencies - Additional Information (Detail) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2015USD ($)site | Sep. 30, 2014USD ($) | Dec. 31, 2014USD ($) | |
Environmental Commitments And Contingencies [Line Items] | |||
Company's exposure in number of former Manufactured Gas Plant Sites | site | 7 | ||
Environmental liabilities | $ 9,003 | $ 8,923 | |
Amount paid for funding requirements | 113 | $ 134 | |
Seaford [Member] | |||
Environmental Commitments And Contingencies [Line Items] | |||
Environmental liabilities | 273 | ||
Accrual for Environmental Loss Contingencies | 239 | ||
Regulatory Assets | 273 | ||
Estimated costs of remediation range, minimum | 273 | ||
Estimated costs of remediation range, maximum | 465 | ||
Winter Haven Florida [Member] | |||
Environmental Commitments And Contingencies [Line Items] | |||
Environmental remediation expense | 443 | ||
Additional remediation costs | 100 | ||
West Palm Beach Florida [Member] | |||
Environmental Commitments And Contingencies [Line Items] | |||
Estimated costs of remediation range, minimum | 4,500 | ||
Estimated costs of remediation range, maximum | 15,400 | ||
Sanford Florida [Member] | |||
Environmental Commitments And Contingencies [Line Items] | |||
Estimated costs of remediation range, maximum | 13,000 | ||
Cost of remedy for settlements of claims | 20,000 | ||
Environmental remediation expense | 24 | ||
FPU [Member] | |||
Environmental Commitments And Contingencies [Line Items] | |||
Environmental liabilities | 10,000 | ||
Approval of recovery of environmental costs | 14,000 | ||
Environmental costs recovered | 10,000 | ||
FPU [Member] | Sanford Florida [Member] | |||
Environmental Commitments And Contingencies [Line Items] | |||
Estimated costs of remediation range, maximum | $ 650 | ||
Environmental remediation expense percent | 5.00% | ||
Amount paid for funding requirements | $ 650 | ||
FPU [Member] | Manufactured Gas Plant [Member] | |||
Environmental Commitments And Contingencies [Line Items] | |||
Regulatory Assets | 4,000 | ||
Chesapeake [Member] | |||
Environmental Commitments And Contingencies [Line Items] | |||
Environmental liabilities | 389 | ||
Regulatory Assets | $ 116 |
Environmental Commitments and43
Environmental Commitments and Contingencies - Additional Information 1 (Detail) | 9 Months Ended |
Sep. 30, 2015USD ($) | |
Key West Florida [Member] | |
Environmental Commitments And Contingencies [Line Items] | |
Period of regulatory inactivity | 17 years |
Costs to resolve liability | $ 50,000 |
Key West Florida [Member] | Maximum [Member] | |
Environmental Commitments And Contingencies [Line Items] | |
Costs to resolve liability | 8,000 |
Pensacola Florida [Member] | |
Environmental Commitments And Contingencies [Line Items] | |
Costs to resolve liability | 5,000 |
Winter Haven Florida [Member] | |
Environmental Commitments And Contingencies [Line Items] | |
Environmental remediation expense | 443,000 |
Additional remediation costs | 100,000 |
Salisbury Maryland [Member] | |
Environmental Commitments And Contingencies [Line Items] | |
Monitoring well remaining maximum cost | $ 5,000 |
Other Commitments and Conting44
Other Commitments and Contingencies - Additional Information (Detail) $ in Thousands, gal in Millions | 9 Months Ended | 12 Months Ended |
Sep. 30, 2015USD ($)dekatherm / dgal | Dec. 31, 2014USD ($)dekatherm / d | |
Other Contingencies And Commitments [Line Items] | ||
Number of years to purchase propane under contract | 6 years | |
Number Of Years Remaining To Purchase Propane Under Contract | 3 years 4 months | |
Annual Estimate Of Volume Of Propane To Be Purchased | gal | 6.5 | |
Total liabilities to tangible net worth minimum times | 3.75 | |
Fixed charge coverage ratio minimum times | 1.5 | |
Time to cure ratio | 30 days | |
Funds from operations interest coverage ratio minimum times | 2 | |
Total debt to capital maximum | 0.65 | |
Document Period End Date | Sep. 30, 2015 | |
Maximum authorized liability under such guarantees and letters of credit | $ 50,000 | |
Aggregate guaranteed amount | 36,100 | |
Liability for Uncertain Tax Positions, Noncurrent | 100 | $ 100 |
Unrecognized Tax Benefits | $ 404 | $ 724 |
Purchase Commitment Minimum Volume | dekatherm / d | 9,982 | |
Purchase Commitment Maximum Volume | dekatherm / d | 13,423 | |
September 12, 2016 [Member] | ||
Other Contingencies And Commitments [Line Items] | ||
Draws on letters of credit | $ 1,000 | |
October 31,, 2016 [Member] | ||
Other Contingencies And Commitments [Line Items] | ||
Draws on letters of credit | 1,200 | |
June 1, 2016 [Member] | ||
Other Contingencies And Commitments [Line Items] | ||
Draws on letters of credit | 24 | |
March 31, 2016 [Member] | ||
Other Contingencies And Commitments [Line Items] | ||
Draws on letters of credit | 1,000 | |
TETLP [Member] | ||
Other Contingencies And Commitments [Line Items] | ||
Draws on letters of credit | $ 2,300 |
Segment Information - Schedule
Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | ||||
Operating Revenues, Unaffiliated Customers | ||||||||
Total operating revenues, unaffiliated customers | $ 91,913 | $ 91,619 | $ 354,676 | $ 378,454 | ||||
Intersegment Revenues | ||||||||
Total operating revenues, unaffiliated customers | 91,913 | 91,619 | 354,676 | 378,454 | ||||
Operating Income | ||||||||
Total operating income | 10,909 | 7,792 | 61,587 | 49,872 | ||||
Other income, net of other expenses | 36 | (32) | (3) | 380 | ||||
Interest | 2,492 | 2,495 | 7,425 | 6,954 | ||||
Income Before Income Taxes | 8,453 | 5,265 | 54,159 | 43,298 | ||||
Income taxes | 3,334 | 2,085 | 21,638 | 17,303 | ||||
Net Income | 5,119 | 3,180 | 32,521 | 25,995 | $ 36,092 | |||
Identifiable Assets | ||||||||
Total identifiable assets | 1,008,442 | 1,008,442 | 904,469 | |||||
Regulated Energy [Member] | ||||||||
Operating Income | ||||||||
Total operating income | 11,828 | 9,202 | 47,616 | 41,004 | ||||
Identifiable Assets | ||||||||
Total identifiable assets | 824,330 | 824,330 | 796,021 | |||||
Unregulated Energy [Member] | ||||||||
Operating Income | ||||||||
Total operating income | (1,022) | (1,972) | 13,666 | 8,843 | ||||
Identifiable Assets | ||||||||
Total identifiable assets | 156,838 | 156,838 | 84,732 | |||||
Other [Member] | ||||||||
Identifiable Assets | ||||||||
Total identifiable assets | 27,274 | 27,274 | $ 23,716 | |||||
Other and eliminations [Member] | ||||||||
Operating Income | ||||||||
Total operating income | 103 | 562 | 305 | 25 | ||||
Operating Revenues, Unaffiliated Customers [Member] | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Total operating revenues, unaffiliated customers | 91,913 | 91,619 | 354,676 | 378,454 | ||||
Intersegment Revenues | ||||||||
Total operating revenues, unaffiliated customers | 91,913 | 91,619 | 354,676 | 378,454 | ||||
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member] | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Total operating revenues, unaffiliated customers | 63,526 | 59,086 | 234,608 | 222,308 | ||||
Intersegment Revenues | ||||||||
Total operating revenues, unaffiliated customers | 63,526 | 59,086 | 234,608 | 222,308 | ||||
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member] | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Total operating revenues, unaffiliated customers | 28,387 | 27,041 | 120,068 | 141,215 | ||||
Intersegment Revenues | ||||||||
Total operating revenues, unaffiliated customers | 28,387 | 27,041 | 120,068 | 141,215 | ||||
Operating Revenues, Unaffiliated Customers [Member] | Other [Member] | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Total operating revenues, unaffiliated customers | 0 | 5,492 | 0 | 14,931 | ||||
Intersegment Revenues | ||||||||
Total operating revenues, unaffiliated customers | 0 | 5,492 | 0 | 14,931 | ||||
Intersegment Revenues [Member] | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Total operating revenues, unaffiliated customers | 1,712 | [1] | 558 | [1] | 4,585 | 1,770 | ||
Intersegment Revenues | ||||||||
Total operating revenues, unaffiliated customers | 1,712 | [1] | 558 | [1] | 4,585 | 1,770 | ||
Intersegment Revenues [Member] | Regulated Energy [Member] | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Total operating revenues, unaffiliated customers | [1] | 270 | 270 | 830 | 860 | |||
Intersegment Revenues | ||||||||
Total operating revenues, unaffiliated customers | [1] | 270 | 270 | 830 | 860 | |||
Intersegment Revenues [Member] | Unregulated Energy [Member] | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Total operating revenues, unaffiliated customers | [1] | 1,222 | 30 | 3,095 | 150 | |||
Intersegment Revenues | ||||||||
Total operating revenues, unaffiliated customers | [1] | 1,222 | 30 | 3,095 | 150 | |||
Intersegment Revenues [Member] | Other [Member] | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Total operating revenues, unaffiliated customers | [1] | 220 | 258 | 660 | 760 | |||
Intersegment Revenues | ||||||||
Total operating revenues, unaffiliated customers | [1] | $ 220 | $ 258 | $ 660 | $ 760 | |||
[1] | (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. |
Accumulated Other Comprehensi46
Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | ||
Beginning balance | $ (5,676) | $ (2,533) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (76) | (28) |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 281 | 92 |
Net current-period other comprehensive income (loss) | 205 | 64 |
Ending balance | (5,471) | (2,469) |
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member] | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | ||
Beginning balance | (5,643) | (2,533) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 0 | 0 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 248 | 92 |
Net current-period other comprehensive income (loss) | 248 | 92 |
Ending balance | (5,395) | (2,441) |
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member] | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | ||
Beginning balance | (33) | 0 |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (76) | (28) |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 33 | 0 |
Net current-period other comprehensive income (loss) | (43) | (28) |
Ending balance | $ (76) | $ (28) |
Accumulated Other Comprehensi47
Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Amortization of pension and postretirement items: | |||||
Tax benefit | $ (3,334) | $ (2,085) | $ (21,638) | $ (17,303) | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | |||||
Amortization of pension and postretirement items: | |||||
Net of tax | (83) | (30) | (281) | (92) | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | |||||
Amortization of pension and postretirement items: | |||||
Prior service cost | [1] | 17 | 14 | 50 | 44 |
Net loss | [1] | 155 | 65 | 465 | 198 |
Total before tax | (138) | (51) | (415) | (154) | |
Tax benefit | 55 | 21 | 167 | 62 | |
Net of tax | (83) | (30) | (248) | (92) | |
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 | 0 | 0 | (55) | 0 | |
Tax benefit | 0 | 0 | 22 | 0 | |
Net of tax | 0 | 0 | (33) | 0 | |
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements | [2] | 0 | 0 | 0 | 0 |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax | [2] | $ 0 | $ 0 | $ (55) | $ 0 |
[1] | These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details. | ||||
[2] | (2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details. |
Employee Benefit Plans - Employ
Employee Benefit Plans - Employee Benefit Plans (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Document Period End Date | Sep. 30, 2015 | |||
Amortization of prior service cost | $ (17) | $ (14) | $ (50) | $ (44) |
Amortization of net loss | 249 | 65 | 745 | 198 |
Florida Public Utilities Company Medical Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 15 | 17 | 45 | 50 |
Expected return on plan assets | 0 | 0 | 0 | 0 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Amortization of net loss | 2 | 0 | 5 | 0 |
Net periodic cost (benefit) | 17 | 17 | 50 | 50 |
Amortization of pre-merger regulatory asset | 2 | 2 | 6 | 6 |
Total periodic cost | 19 | 19 | 56 | 56 |
Chesapeake Postretirement Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 11 | 13 | 33 | 39 |
Expected return on plan assets | 0 | 0 | 0 | 0 |
Amortization of prior service cost | (19) | (19) | (58) | (58) |
Amortization of net loss | 17 | 16 | 53 | 50 |
Net periodic cost (benefit) | 9 | 10 | 28 | 31 |
Amortization of pre-merger regulatory asset | 0 | 0 | 0 | 0 |
Total periodic cost | 9 | 10 | 28 | 31 |
Chesapeake Pension SERP [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 23 | 23 | 68 | 69 |
Expected return on plan assets | 0 | 0 | 0 | 0 |
Amortization of prior service cost | 2 | 5 | 8 | 14 |
Amortization of net loss | 25 | 12 | 74 | 36 |
Net periodic cost (benefit) | 50 | 40 | 150 | 119 |
Amortization of pre-merger regulatory asset | 0 | 0 | 0 | 0 |
Total periodic cost | 50 | 40 | 150 | 119 |
Florida Public Utilities Company Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 626 | 647 | 1,877 | 1,941 |
Expected return on plan assets | (777) | (773) | (2,330) | (2,318) |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Amortization of net loss | 114 | 0 | 341 | 0 |
Net periodic cost (benefit) | (37) | (126) | (112) | (377) |
Amortization of pre-merger regulatory asset | 191 | 191 | 571 | 571 |
Total periodic cost | 154 | 65 | 459 | 194 |
Chesapeake Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Interest cost | 102 | 107 | 306 | 320 |
Expected return on plan assets | (135) | (133) | (405) | (398) |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Amortization of net loss | 91 | 37 | 272 | 112 |
Net periodic cost (benefit) | 58 | 11 | 173 | 34 |
Amortization of pre-merger regulatory asset | 0 | 0 | 0 | 0 |
Total periodic cost | $ 58 | $ 11 | $ 173 | $ 34 |
Employee Benefit Plans - Additi
Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Defined Benefit Plan Disclosure [Line Items] | |||||
Document Period End Date | Sep. 30, 2015 | ||||
Expected pension and postretirement benefit costs | $ 1,200 | ||||
Expected amortization of pre merger regulatory asset | 769 | ||||
Florida Public Utilities Company Medical Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 17 | $ 17 | 50 | $ 50 | |
Contribution to pension plan | 47 | 163 | |||
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year | 207 | ||||
Chesapeake Postretirement Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Net Periodic Benefit Cost | 9 | 10 | 28 | 31 | |
Contribution to pension plan | 14 | 42 | |||
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year | 79 | ||||
Chesapeake Pension SERP [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Net Periodic Benefit Cost | 50 | 40 | 150 | 119 | |
Contribution to pension plan | 38 | 109 | |||
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year | 151 | ||||
Consolidated [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Net Periodic Benefit Cost | (381) | ||||
Chesapeake Pension Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Net Periodic Benefit Cost | 58 | 11 | 173 | 34 | |
Contribution to pension plan | 127 | 346 | |||
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year | 475 | ||||
Florida Public Utilities Company Pension Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Unamortized balance of regulatory asset | 3,100 | 3,100 | $ 3,600 | ||
Defined Benefit Plan, Net Periodic Benefit Cost | (37) | $ (126) | (112) | $ (377) | |
Contribution to pension plan | $ 402 | 1,100 | |||
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year | $ 1,600 |
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, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Prior service cost (credit) | $ (17) | $ (14) | $ (50) | $ (44) | |
Net loss | 249 | 65 | 745 | 198 | |
Recognized from accumulated other comprehensive loss | [1] | 138 | 51 | 415 | 154 |
Recognized from regulatory asset | 94 | 0 | 280 | 0 | |
Total recognized in net periodic benefit cost | 232 | 51 | 695 | 154 | |
Chesapeake Pension Plan [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Prior service cost (credit) | 0 | 0 | 0 | 0 | |
Net loss | 91 | 37 | 272 | 112 | |
Recognized from accumulated other comprehensive loss | [1] | 91 | 37 | 272 | 112 |
Recognized from regulatory asset | 0 | 0 | 0 | 0 | |
Total recognized in net periodic benefit cost | 91 | 37 | 272 | 112 | |
Florida Public Utilities Company Pension Plan [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Prior service cost (credit) | 0 | 0 | 0 | 0 | |
Net loss | 114 | 0 | 341 | 0 | |
Recognized from accumulated other comprehensive loss | [1] | 22 | 0 | 65 | 0 |
Recognized from regulatory asset | 92 | 0 | 276 | 0 | |
Total recognized in net periodic benefit cost | 114 | 0 | 341 | 0 | |
Chesapeake Pension SERP [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Prior service cost (credit) | 2 | 5 | 8 | 14 | |
Net loss | 25 | 12 | 74 | 36 | |
Recognized from accumulated other comprehensive loss | [1] | 27 | 17 | 82 | 50 |
Recognized from regulatory asset | 0 | 0 | 0 | 0 | |
Total recognized in net periodic benefit cost | 27 | 17 | 82 | 50 | |
Chesapeake Postretirement Plan [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Prior service cost (credit) | (19) | (19) | (58) | (58) | |
Net loss | 17 | 16 | 53 | 50 | |
Recognized from accumulated other comprehensive loss | [1] | (2) | (3) | (5) | (8) |
Recognized from regulatory asset | 0 | 0 | 0 | 0 | |
Total recognized in net periodic benefit cost | (2) | (3) | (5) | (8) | |
Florida Public Utilities Company Medical Plan [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||||
Prior service cost (credit) | 0 | 0 | 0 | 0 | |
Net loss | 2 | 0 | 5 | 0 | |
Recognized from accumulated other comprehensive loss | [1] | 0 | 0 | 1 | 0 |
Recognized from regulatory asset | 2 | 0 | 4 | 0 | |
Total recognized in net periodic benefit cost | $ 2 | $ 0 | $ 5 | $ 0 | |
[1] | (1) See Note 8, Accumulated Other Comprehensive Loss. |
Investments - Additional Inform
Investments - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Investments, Debt and Equity Securities [Abstract] | ||||
Unrealized gain, net of other expenses | $ (238) | $ 41 | $ (131) | $ 111 |
Investments Schedule of Investm
Investments Schedule of Investments (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Investments schedule [Line Items] | ||
Investments, at fair value | $ 3,412 | $ 3,678 |
Rabbi Trust Associated With Deferred Compensation Plan [Member] | ||
Investments schedule [Line Items] | ||
Investments, at fair value | 3,394 | 3,678 |
Equity Securities [Member] | ||
Investments schedule [Line Items] | ||
Investments, at fair value | $ 18 | $ 0 |
Share-Based Compensation - Shar
Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | $ 499 | $ 454 | $ 1,445 | $ 1,519 |
Less: tax benefit | (201) | (183) | (582) | (612) |
Share-Based Compensation amounts included in net income | 298 | 271 | 863 | 907 |
Awards to non-employee directors [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | 165 | 137 | 475 | 394 |
Award to key employees [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | $ 334 | $ 317 | $ 970 | $ 1,125 |
Share-Based Compensation - Summ
Share-Based Compensation - Summary of Stock Activity under the SICP (Detail) | 9 Months Ended |
Sep. 30, 2015$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Number of Shares, Granted | 1,207 |
Award to key employees [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Number of Shares, Outstanding - December 31, 2014 | 123,038 |
Number of Shares, Granted | 33,719 |
Number of Shares, Vested | (43,839) |
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period | (2,520) |
Number of Shares, Outstanding - September 30, 2015 | 110,398 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |
Weighted Average Fair Value, Outstanding - December 31, 2014 | $ / shares | $ 32.60 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | 48.21 |
Weighted Average Fair Value, Vested | $ / shares | 28.01 |
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expirations Weighted Average Grant Date Fair Value | $ / shares | 28.83 |
Weighted Average Fair Value, Outstanding - September 30, 2015 | $ / shares | $ 38.34 |
Awards to non-employee directors [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Number of Shares, Outstanding - December 31, 2014 | 0 |
Number of Shares, Granted | 14,484 |
Number of Shares, Vested | (14,484) |
Number of Shares, Outstanding - September 30, 2015 | 0 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |
Weighted Average Fair Value, Outstanding - December 31, 2014 | $ / shares | $ 0 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | 45.54 |
Weighted Average Fair Value, Vested | $ / shares | 45.54 |
Weighted Average Fair Value, Outstanding - September 30, 2015 | $ / shares | $ 0 |
Share-Based Compensation - Addi
Share-Based Compensation - Additional Information (Detail) $ in Thousands | 9 Months Ended |
Sep. 30, 2015USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Granted awards, shares | shares | 1,207 |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized | $ 1,700 |
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 | $ 385 |
Granted awards, shares | shares | 14,484 |
Award to key employees [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Granted awards, shares | shares | 33,719 |
Vesting period | 3 years |
Intrinsic value of the SICP awards | $ 5,900 |
Derivative Instruments Outstand
Derivative Instruments Outstanding Trading Contracts (Details) - Forward Contracts [Member] gal in Thousands | Sep. 30, 2015$ / galgal |
Sales [Member] | |
Derivative [Line Items] | |
Quantity In Gallons | gal | 2,940 |
Weighted Average Contract Prices | 0.5210 |
Sales [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Estimated Market Prices | 0.3475 |
Sales [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Estimated Market Prices | 0.5288 |
Purchase [Member] | |
Derivative [Line Items] | |
Quantity In Gallons | gal | 2,940 |
Weighted Average Contract Prices | 0.4545 |
Purchase [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Estimated Market Prices | 0.3550 |
Purchase [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Estimated Market Prices | 0.5025 |
Derivative Instruments - Additi
Derivative Instruments - Additional Information (Detail) gal in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2015USD ($)Counterparty$ / galgal | Dec. 31, 2014USD ($)Counterparty$ / galgal | |
Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | gal | 2,500 | 630 |
Cash Paid On Derivative Settlement | $ | $ 1,100,000 | |
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements | $ | $ 735,000 | |
Call options [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | gal | 1,300 | |
Payments for Derivative Instrument, Financing Activities | $ | $ 98,000 | |
Put Option [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | gal | 2,500 | 630 |
Payments for Derivative Instrument, Financing Activities | $ | $ 143,000 | $ 128,000 |
Cash Received On Derivative Settlement | $ | $ 868,000 | |
Forward Contracts [Member] | ||
Derivative [Line Items] | ||
Number Of Counterparties With Master Repurchase Agreements | Counterparty | 2 | 2 |
Accounts Receivable Subject To Master Netting Arrangement | $ | $ 1,600,000 | |
Accounts Payable Subject To Master Netting Arrangement | $ | $ 1,200,000 | |
Mark To Market Energy Liabilities [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Cash Flow Hedge Derivative Instrument Liabilities at Fair Value | $ | $ 128,000 | |
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | $ | $ 64,000 | |
Strike Price 1 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Strike Price Per Gallon For The Propane Swap Agreements | 0.595 | 1.1350 |
Strike Price 2 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Strike Price Per Gallon For The Propane Swap Agreements | 0.5888 | 1.0975 |
Strike Price 3 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Strike Price Per Gallon For The Propane Swap Agreements | 0.5500 | 1.0475 |
Strike Price 4 [Member] | Propane Swap Agreement [Member] | ||
Derivative [Line Items] | ||
Strike Price Per Gallon For The Propane Swap Agreements | 0.5200 | |
Put Option Strike Price 1 [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Derivative, Price Risk Option Strike Price | 0.4950 | 1.0350 |
Put Option Strike Price 2 [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Derivative, Price Risk Option Strike Price | 0.4888 | 0.9975 |
Put Option Strike Price 3 [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Derivative, Price Risk Option Strike Price | 0.4500 | 0.9475 |
Put Option Strike Price 4 [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Derivative, Price Risk Option Strike Price | 0.4200 | |
Strike Price 1 [Member] | Call options [Member] | ||
Derivative [Line Items] | ||
Derivative, Price Risk Option Strike Price | 1.0875 | |
Strike Price 2 [Member] | Call options [Member] | ||
Derivative [Line Items] | ||
Derivative, Price Risk Option Strike Price | 1.0650 |
Derivative Instruments - Fair V
Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contract Liabilities, Current | $ 154 | $ 1,018 |
Energy Marketing Contracts Assets, Current | 286 | 1,055 |
Mark To Market Energy Assets [Member] | Forward Contracts [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contracts Assets, Current | 222 | 407 |
Mark To Market Energy Assets [Member] | Call options [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contracts Assets, Current | 0 | 26 |
Mark To Market Energy Assets [Member] | Put Option [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contracts Assets, Current | 64 | 622 |
Mark-to-market energy liabilities [Member] | Forward Contracts [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contract Liabilities, Current | 26 | 283 |
Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Energy Marketing Contract Liabilities, Current | $ 128 | $ 735 |
Derivative Instruments - Effect
Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | $ 8 | $ (39) | $ 700 | $ 1,316 | |
Revenue [Member] | Derivatives not designated as hedging instruments [Member] | Forward Contracts [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) on derivatives | [1] | (7) | (5) | 71 | (67) |
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Call Option [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 | 137 | |
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Propane Swap Agreement [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 18 | 0 | |
Cost of Sales [Member] | Derivatives designated as fair value hedges [Member] | Call Option [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | (81) | 0 | |
Cost of Sales [Member] | Derivatives designated as fair value hedges [Member] | Put/Call Option [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | 0 | (43) | 506 | (92) | |
Inventories [Member] | Derivatives designated as fair value hedges [Member] | Put/Call Option [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) on derivatives | [2] | (46) | 0 | (79) | 0 |
Other Comprehensive Income (Loss) [Member] | Derivatives designated as fair value hedges [Member] | Propane Swap Agreement [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) on derivatives | (126) | (45) | (128) | (46) | |
Options [Member] | Revenue [Member] | Forward Contracts [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | $ 187 | $ 54 | $ 393 | $ 1,384 | |
[1] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjg5ZTNhNTliOTlkZjQyYjQ4NmEyNzdiOWUxYWY3ODIxfFRleHRTZWxlY3Rpb246NzM2QzNDRTZFNjMyNUU0MUFEQURCMzVDQkM1RTNGNEYM} | ||||
[2] | As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this put 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. |
Fair Value of Financial Instr60
Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Assets: | |||
Investments | $ 3,412 | $ 3,678 | |
Equity Securities [Member] | |||
Assets: | |||
Investments | 18 | 0 | |
Quoted Prices in Active Markets (Level 1) [Member] | Mark-to-market energy liabilities [Member] | |||
Liabilities: | |||
Mark-to-market energy liabilities | 0 | 0 | |
Quoted Prices in Active Markets (Level 1) [Member] | Investments in guaranteed income fund [Member] | |||
Assets: | |||
Investments | 0 | 0 | |
Quoted Prices in Active Markets (Level 1) [Member] | Equity Securities [Member] | |||
Assets: | |||
Investments | 18 | ||
Quoted Prices in Active Markets (Level 1) [Member] | Investments - other [Member] | |||
Assets: | |||
Investments | 3,118 | 3,391 | |
Quoted Prices in Active Markets (Level 1) [Member] | Mark To Market Energy Assets Including Put Option [Member] | |||
Assets: | |||
Mark-to-market energy assets | 0 | 0 | |
Significant Other Observable Inputs (Level 2) [Member] | Mark-to-market energy liabilities [Member] | |||
Liabilities: | |||
Mark-to-market energy liabilities | 154 | 1,018 | |
Significant Other Observable Inputs (Level 2) [Member] | Investments in guaranteed income fund [Member] | |||
Assets: | |||
Investments | 0 | 0 | |
Significant Other Observable Inputs (Level 2) [Member] | Equity Securities [Member] | |||
Assets: | |||
Investments | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Investments - other [Member] | |||
Assets: | |||
Investments | 0 | 0 | |
Significant Other Observable Inputs (Level 2) [Member] | Mark To Market Energy Assets Including Put Option [Member] | |||
Assets: | |||
Mark-to-market energy assets | 286 | 1,055 | |
Significant Unobservable Inputs (Level 3) [Member] | Mark-to-market energy liabilities [Member] | |||
Assets: | |||
Mark-to-market energy assets | 0 | 0 | $ 0 |
Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member] | |||
Assets: | |||
Investments | 276 | 287 | |
Significant Unobservable Inputs (Level 3) [Member] | Equity Securities [Member] | |||
Assets: | |||
Investments | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Investments - other [Member] | |||
Assets: | |||
Investments | 0 | 0 | |
Recurring [Member] | Mark-to-market energy liabilities [Member] | |||
Liabilities: | |||
Mark-to-market energy liabilities | 154 | 1,018 | |
Recurring [Member] | Investments in guaranteed income fund [Member] | |||
Assets: | |||
Investments | 276 | 287 | |
Recurring [Member] | Equity Securities [Member] | |||
Assets: | |||
Investments | 18 | ||
Recurring [Member] | Investments - other [Member] | |||
Assets: | |||
Investments | 3,118 | 3,391 | |
Recurring [Member] | Mark To Market Energy Assets Including Put Option [Member] | |||
Assets: | |||
Mark-to-market energy assets | $ 286 | $ 1,055 |
Fair Value of Financial Instr61
Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Beginning Balance | $ 287 | $ 458 |
Purchases and adjustments | (11) | (89) |
Transfers | (3) | (58) |
Investment Income | 3 | 4 |
Ending Balance | $ 276 | $ 315 |
Fair Value of Financial Instr62
Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Fair Value Disclosures [Abstract] | ||
Long-term debt including current maturities | $ 159.9 | $ 161.5 |
Fair value of long-term debt | $ 175.8 | $ 180.7 |
Long-Term Debt - Outstanding Lo
Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||
Total long-term debt | $ 159,900 | $ 161,500 | |
Capital Lease Obligations | 5,155 | 6,130 | |
Total Long-term debt | 165,048 | 167,595 | |
Less: current maturities | (9,139) | (9,109) | |
Total long-term debt, net of current maturities | 155,909 | 158,486 | |
9.08% bond, due June 1, 2022 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | [1] | 7,973 | 7,969 |
6.64% note, due October 31, 2017 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 8,182 | 8,182 | |
5.50% note, due October 12, 2020 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 12,000 | 12,000 | |
5.93% note, due October 31, 2023 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 25,500 | 27,000 | |
5.68% note, due June 30, 2026 [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | 29,000 | 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 | |
Promissory note [Member] | |||
Debt Instrument [Line Items] | |||
Total long-term debt | $ 238 | $ 314 | |
[1] | FPU secured first mortgage bonds are guaranteed by Chesapeake. |
Long-Term Debt - Outstanding 64
Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail) | 9 Months Ended |
Sep. 30, 2015 | |
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 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands | Oct. 08, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||||
Total long-term debt | $ 159,900 | $ 161,500 | ||
Repayments of Long-term Debt | $ 4,262 | $ 2,249 | ||
Notes Payable, Other Payables [Member] | Subsequent Event [Member] | Shelf Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Period To Purchase Unsecured Senior Notes | 3 years | |||
Maturity Date For Unsecured Senior Notes | 20 years | |||
Scenario, Forecast [Member] | Notes Payable, Other Payables [Member] | Subsequent Event [Member] | Shelf Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 150,000 |
Short-term Borrowing Short-Term
Short-term Borrowing Short-Term Borrowing (Details) - Revolving Credit Facility [Member] - Subsequent Event [Member] - USD ($) | Oct. 19, 2015 | Oct. 08, 2015 | Dec. 31, 2015 |
Short-term Debt [Line Items] | |||
Line of Credit Facility, Current Borrowing Capacity | $ 150,000,000 | ||
Line of Credit Facility, Maximum Amount Outstanding During Period | $ 25,000,000 | ||
Number Of Years Of Extension of Credit Facility Expiration Date | 2 years | ||
Line of Credit Facility, Expiration Period | 5 years | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 200,000,000 | ||
London Interbank Offered Rate (LIBOR) [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Interest Rate During Period | 125.00% | ||
Base Rate [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Interest Rate During Period | 25.00% |