Document and Entity Information (USD $)
In Millions, except Share data, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2011
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Feb. 29, 2012
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Jun. 30, 2011
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Document and Entity Information [Abstract] | |||
Entity Registrant Name | CHESAPEAKE UTILITIES CORP | ||
Entity Central Index Key | 0000019745 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2011 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2011 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 382.8 | ||
Entity Common Stock, Shares Outstanding | 9,576,780 |
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- Definition
If the value is true, then the document as an amendment to previously-filed/accepted document. No definition available.
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- Definition
End date of current fiscal year in the format --MM-DD. No definition available.
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- Definition
This is focus fiscal period of the document report. For a first quarter 2006 quarterly report, which may also provide financial information from prior periods, the first fiscal quarter should be given as the fiscal period focus. Values: FY, Q1, Q2, Q3, Q4, H1, H2, M9, T1, T2, T3, M8, CY. No definition available.
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- Definition
This is focus fiscal year of the document report in CCYY format. For a 2006 annual report, which may also provide financial information from prior periods, fiscal 2006 should be given as the fiscal year focus. Example: 2006. No definition available.
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- Definition
The end date of the period reflected on the cover page if a periodic report. For all other reports and registration statements containing historical data, it is the date up through which that historical data is presented. If there is no historical data in the report, use the filing date. The format of the date is CCYY-MM-DD. No definition available.
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- Definition
The type of document being provided (such as 10-K, 10-Q, N-1A, etc). The document type is limited to the same value as the supporting SEC submission type, minus any "/A" suffix. The acceptable values are as follows: S-1, S-3, S-4, S-11, F-1, F-3, F-4, F-9, F-10, 6-K, 8-K, 10, 10-K, 10-Q, 20-F, 40-F, N-1A, 485BPOS, 497, NCSR, N-CSR, N-CSRS, N-Q, 10-KT, 10-QT, 20-FT, POS AM and Other. No definition available.
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- Definition
A unique 10-digit SEC-issued value to identify entities that have filed disclosures with the SEC. It is commonly abbreviated as CIK. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Indicate number of shares outstanding of each of registrant's classes of common stock, as of latest practicable date. Where multiple classes exist define each class by adding class of stock items such as Common Class A [Member], Common Class B [Member] onto the Instrument [Domain] of the Entity Listings, Instrument No definition available.
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- Definition
Indicate "Yes" or "No" whether registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. This information should be based on the registrant's current or most recent filing containing the related disclosure. No definition available.
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- Definition
Indicate whether the registrant is one of the following: (1) Large Accelerated Filer, (2) Accelerated Filer, (3) Non-accelerated Filer, or (4) Smaller Reporting Company. Definitions of these categories are stated in Rule 12b-2 of the Exchange Act. This information should be based on the registrant's current or most recent filing containing the related disclosure. No definition available.
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- Definition
State aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to price at which the common equity was last sold, or average bid and asked price of such common equity, as of the last business day of registrant's most recently completed second fiscal quarter. The public float should be reported on the cover page of the registrants form 10K. No definition available.
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- Definition
The exact name of the entity filing the report as specified in its charter, which is required by forms filed with the SEC. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Indicate "Yes" or "No" if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. No definition available.
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- Definition
Indicate "Yes" or "No" if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Is used on Form Type: 10-K, 10-Q, 8-K, 20-F, 6-K, 10-K/A, 10-Q/A, 20-F/A, 6-K/A, N-CSR, N-Q, N-1A. No definition available.
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Consolidated Statements of Income (USD $)
In Thousands, except Share data, unless otherwise specified |
12 Months Ended | ||
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Dec. 31, 2011
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Dec. 31, 2010
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Dec. 31, 2009
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Operating Revenues | |||
Regulated Energy | $ 256,773 | $ 269,934 | $ 139,099 |
Unregulated Energy | 149,586 | 146,793 | 119,973 |
Other | 11,668 | 10,819 | 9,713 |
Total operating revenues | 418,027 | 427,546 | 268,785 |
Operating Expenses | |||
Regulated energy cost of sales | 128,111 | 145,207 | 64,803 |
Unregulated energy and other cost of sales | 118,787 | 116,098 | 95,467 |
Operations | 79,810 | 77,227 | 52,184 |
Maintenance | 7,449 | 7,484 | 3,430 |
Depreciation and amortization | 20,153 | 18,536 | 11,588 |
Other taxes | 10,012 | 11,064 | 7,577 |
Total operating expenses | 364,322 | 375,616 | 235,049 |
Operating Income | 53,705 | 51,930 | 33,736 |
Other income, net of other expenses | 906 | 195 | 165 |
Interest charges | 9,000 | 9,146 | 7,086 |
Income Before Income Taxes | 45,611 | 42,979 | 26,815 |
Income taxes | 17,989 | 16,923 | 10,918 |
Net Income | $ 27,622 | $ 26,056 | $ 15,897 |
Weighted Average Common Shares Outstanding: | |||
Basic | 9,555,799 | 9,474,554 | 7,313,320 |
Diluted | 9,651,058 | 9,582,374 | 7,440,201 |
Earnings Per Share of Common Stock: | |||
Basic | $ 2.89 | $ 2.75 | $ 2.17 |
Diluted | $ 2.87 | $ 2.73 | $ 2.15 |
Cash Dividends Declared Per Share of Common Stock | $ 1.365 | $ 1.305 | $ 1.250 |
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- Definition
Operations No definition available.
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- Definition
Regulated energy cost of sales No definition available.
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- Definition
Unregulated energy and other cost of sales No definition available.
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- Definition
Aggregate dividends declared during the period for each share of common stock outstanding. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The aggregate expense recognized in the current period that allocates the cost of tangible assets, intangible assets, or depleting assets to periods that benefit from use of the assets. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Details
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- Definition
The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Sum of operating profit and nonoperating income or expense before Income or Loss from equity method investments, income taxes, extraordinary items, and noncontrolling interest. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The sum of the current income tax expense or benefit and the deferred income tax expense or benefit pertaining to continuing operations. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The cost of borrowed funds accounted for as interest that was charged against earnings during the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Costs incurred and are directly related to generating maintenance revenues. Also includes cost of maintenance on client contracts. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The portion of profit or loss for the period, net of income taxes, which is attributable to the parent. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Generally recurring costs associated with normal operations except for the portion of these expenses which can be clearly related to production and included in cost of sales or services. Includes selling, general and administrative expense. No definition available.
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- Details
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- Definition
The net result for the period of deducting operating expenses from operating revenues. No definition available.
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- Definition
The net amount of other income and expense amounts, the components of which are not separately disclosed on the income statement, resulting from ancillary business-related activities (that is, excluding major activities considered part of the normal operations of the business) also known as other nonoperating income (expense) recognized for the period. Such amounts may include: (a) dividends, (b) interest on securities, (c) net gains or losses on securities, (d) unusual costs, (e) gains or losses on foreign exchange transactions, and (f) miscellaneous other income and expense items. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Revenues from the sale of other goods or rendering of other services, not elsewhere specified in the taxonomy; net of (reduced by) sales adjustments, returns, allowances, and discounts. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The total amount of regulated operating revenues recognized during the period. No definition available.
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- Definition
Aggregate revenue recognized during the period (derived from goods sold, services rendered, insurance premiums, or other activities that constitute an entity's earning process). For financial services companies, also includes investment and interest income, and sales and trading gains. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Details
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- Definition
Taxes, excluding payroll, income and excise taxes, if not included elsewhere, that could include production, real and personal property, and other selling and distribution-related taxes. No definition available.
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- Definition
The amount of unregulated operating revenues recognized during the period. No definition available.
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- Definition
The average number of shares or units issued and outstanding that are used in calculating diluted EPS or earnings per unit (EPU), determined based on the timing of issuance of shares or units in the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Details
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- Definition
Number of [basic] shares or units, after adjustment for contingently issuable shares or units and other shares or units not deemed outstanding, determined by relating the portion of time within a reporting period that common shares or units have been outstanding to the total time in that period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Consolidated Statements of Comprehensive Income (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
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Dec. 31, 2011
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Dec. 31, 2010
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Dec. 31, 2009
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Consolidated Statements of Comprehensive Income [Abstract] | |||
Net Income | $ 27,622 | $ 26,056 | $ 15,897 |
Employee Benefits, net of tax: | |||
Amortization of prior service cost, net of tax of $432, $5 and $5, respectively | 645 | 8 | 7 |
Net Gain (Loss), net of tax of ($1,164), ($541) and $794, respectively | (1,812) | (844) | 1,217 |
Total other comprehensive income (loss) | (1,167) | (836) | 1,224 |
Comprehensive Income | $ 26,455 | $ 25,220 | $ 17,121 |
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- Definition
The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the reporting entity. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, but excludes any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The portion of profit or loss for the period, net of income taxes, which is attributable to the parent. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The adjustment out of other comprehensive income for prior service costs recognized as a component of net period benefit cost during the period, after tax. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Details
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- Definition
This element represents Other Comprehensive Income or Loss, Net of Tax, for the period attributable to the parent entity. Includes deferred gains or losses on qualifying hedges, unrealized holding gains or losses on available-for-sale securities, minimum pension liability, and cumulative translation adjustment. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The adjustment out of other comprehensive income for actuarial gains or losses recognized as a component of net periodic benefit cost during the period, after tax. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Details
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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2011
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Dec. 31, 2010
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Dec. 31, 2009
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Consolidated Statements of Comprehensive Income [Abstract] | |||
Tax expense recognized on the amortization of prior service cost | $ 432 | $ 5 | $ 5 |
Tax expense recognized on the net gain (loss) | $ (1,164) | $ (541) | $ 794 |
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- Definition
Tax effect on adjustment out of other comprehensive income for prior service costs recognized as a component of net period benefit cost during the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
For each annual statement of income presented, the tax effect of the net gain (loss) recognized in other comprehensive income that is a reclassification adjustment of other comprehensive income as a result of being recognized as a component of net periodic benefit cost for the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Details
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- Definition
Accrued asset removal cost - Regulatory liability No definition available.
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- Definition
Accrued revenue No definition available.
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- Definition
Total deferred charges and other assets No definition available.
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- Details
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- Definition
Unregulated energy No definition available.
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- Definition
Carrying value as of the balance sheet date of liabilities incurred (and for which invoices have typically been received) and payable to vendors for goods and services received that are used in an entity's business. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer). Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Amount due from customers or clients, within one year of the balance sheet date (or the normal operating cycle, whichever is longer), for goods or services (including trade receivables) that have been delivered or sold in the normal course of business, reduced to the estimated net realizable fair value by an allowance established by the entity of the amount it deems uncertain of collection. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Amount due from customers or clients, more than one year from the balance sheet date, for goods or services that have been delivered or sold in the normal course of business, reduced to the estimated net realizable fair value by an allowance established by the entity of the amount it deems uncertain of collection. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Carrying value of the obligation (known or estimated) arising from requirements to perform activities to remediate one or more sites, payable after twelve months or beyond the next operating cycle if longer. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The noncurrent portion of the reserve for accumulated deferred investment tax credits as of the balance sheet date. This is the remaining investment credit, which will reduce the cost of services collected from ratepayers by a ratable portion over the investment's regulatory life. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The cumulative amount of depreciation, depletion and amortization (related to property, plant and equipment, but not including land) that has been recognized in the income statement. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Value received from shareholders in common stock-related transactions that are in excess of par value or stated value and amounts received from other stock-related transactions. Includes only common stock transactions (excludes preferred stock transactions). May be called contributed capital, capital in excess of par, capital surplus, or paid-in capital. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Sum of the carrying amounts as of the balance sheet date of all assets that are recognized. Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Sum of the carrying amounts as of the balance sheet date of all assets that are expected to be realized in cash, sold, or consumed within one year (or the normal operating cycle, if longer). Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Details
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- Definition
This element represents the total consolidated (as applicable) capitalization of the entity which is comprised of its long-term debt and equity instruments. The table may be detailed by subsidiary (legal entity) and include information by type of debt or equity detailed by instrument. No definition available.
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- Definition
Includes currency on hand as well as demand deposits with banks or financial institutions. It also includes other kinds of accounts that have the general characteristics of demand deposits in that the Entity may deposit additional funds at any time and also effectively may withdraw funds at any time without prior notice or penalty. Cash equivalents, excluding items classified as marketable securities, include short-term, highly liquid investments that are both readily convertible to known amounts of cash, and so near their maturity that they present minimal risk of changes in value because of changes in interest rates. Generally, only investments with original maturities of three months or less qualify under that definition. Original maturity means original maturity to the entity holding the investment. For example, both a three-month US Treasury bill and a three-year Treasury note purchased three months from maturity qualify as cash equivalents. However, a Treasury note purchased three years ago does not become a cash equivalent when its remaining maturity is three months. Compensating balance arrangements that do not legally restrict the withdrawal or usage of cash amounts may be reported as Cash and Cash Equivalents, while legally restricted deposits held as compensating balances against borrowing arrangements, contracts entered into with others, or company statements of intention with regard to particular deposits are not generally reported as cash and cash equivalents. Includes cash and cash equivalents associated with the entity's continuing operations. Excludes cash and cash equivalents associated with the disposal group (and discontinued operation). Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Represents the caption on the face of the balance sheet to indicate that the entity has entered into (1) purchase or supply arrangements that will require expending a portion of its resources to meet the terms thereof, and (2) is exposed to potential losses or, less frequently, gains, arising from (a) possible claims against a company's resources due to future performance under contract terms, and (b) possible losses or likely gains from uncertainties that will ultimately be resolved when one or more future events that are deemed likely to occur do occur or fail to occur. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Aggregate par or stated value of issued nonredeemable common stock (or common stock redeemable solely at the option of the issuer). This item includes treasury stock repurchased by the entity. Note: elements for number of nonredeemable common shares, par value and other disclosure concepts are in another section within stockholders' equity. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Gross amount, at the balance sheet date, of long-lived assets under construction that include construction costs to date on capital projects that have not been completed and assets being constructed that are not ready to be placed into service. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The current portion of aggregate prepayments received from customers for goods or services to be provided in the future, as well as the current portion of money or property received from customers that are to be returned upon satisfactory contract completion or as partial prepayment for goods or services to be provided in the future. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Value of stock issued under share-based plans to employees or officers which is the unearned portion, accounted for under the fair value method. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Total carrying amount as of the balance sheet date of unearned revenue or income, not otherwise specified in the taxonomy, which is expected to be taken into income in future periods and obligations not separately disclosed in the balance sheet (other liabilities). No definition available.
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X | ||||||||||
- Details
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X | ||||||||||
- Definition
The current portion of the aggregate tax effects as of the balance sheet date of all future tax deductions arising from temporary differences between tax basis and generally accepted accounting principles basis recognition of assets, liabilities, revenues and expenses, which can only be deducted for tax purposes when permitted under enacted tax laws; after deducting the allocated valuation allowance, if any, to reduce such amount to net realizable value. Deferred tax liabilities and assets are classified as current or noncurrent based on the classification of the related asset or liability for financial reporting. A deferred tax liability or asset that is not related to an asset or liability for financial reporting, including deferred tax assets related to carryforwards, are classified according to the expected reversal date of the temporary difference. An unrecognized tax benefit that is directly related to a position taken in a tax year that results in a net operating loss carryforward is presented as a reduction of the related deferred tax asset. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Represents the noncurrent portion of deferred tax liabilities, which result from applying the applicable tax rate to net taxable temporary differences pertaining to each jurisdiction to which the entity is obligated to pay income tax. A noncurrent taxable temporary difference is a difference between the tax basis and the carrying amount of a noncurrent asset or liability in the financial statements prepared in accordance with generally accepted accounting principles. In a classified statement of financial position, an enterprise separates deferred tax liabilities and assets into a current amount and a noncurrent amount. Deferred tax liabilities and assets are classified as current or noncurrent based on the classification of the related asset or liability for financial reporting. A deferred tax liability or asset that is not related to an asset or liability for financial reporting, including deferred tax assets related to carryforwards, are classified according to the expected reversal date of the temporary difference. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Carrying value as of the balance sheet date of dividends declared but unpaid on equity securities issued by the entity and outstanding. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer). Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Total of the carrying values as of the balance sheet date of obligations incurred through that date and payable for obligations related to services received from employees, such as accrued salaries and bonuses, payroll taxes and fringe benefits. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer). Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Current liabilities attributable to energy marketing activities (trading activities). Current energy marketing (trading activities) are when entities engage in both financial and physical trading to increase profits, manage their commodity price risk and enhance system reliability. They may trade electricity, coal, natural gas and oil. These entities typically use a variety of financial instruments, including forward contracts, options and swaps. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Carrying amount as of the balance sheet date of the asset arising from energy trading activities that involves the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts that include exchange futures and options and over the counter options and swaps, which are expected to be converted into cash or otherwise disposed of within a year or the normal operating cycle, if longer. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Carrying amount as of the balance sheet date of natural gas in storage, which is a mixture of gases (liquefied or otherwise), used for fuel and manufacturing purposes, which is ready for sale. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Carrying amount as of the balance sheet date of product derived from petroleum during the processing of oil or natural gas which is then used as a heat source or fuel. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Carrying amount due within one year of the balance sheet date (or one operating cycle, if longer) from tax authorities as of the balance sheet date representing refunds of overpayments or recoveries based on agreed-upon resolutions of disputes. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Sum of the carrying amounts of all intangible assets, excluding goodwill, as of the balance sheet date, net of accumulated amortization and impairment charges. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Carrying value as of the balance sheet date of [accrued] interest payable on all forms of debt, including trade payables, that has been incurred and is unpaid. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer). Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
This element represents the portion of the balance sheet assertion valued at fair value by the entity whether such amount is presented as a separate caption or as a parenthetical disclosure. Additionally, this element may be used in connection with the fair value disclosures required in the footnote disclosures to the financial statements. The element may be used in both the balance sheet and disclosure in the same submission. This item represents investment securities as of the balance sheet date which may include marketable securities, derivative financial instruments, and investments accounted for under the equity method. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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X | ||||||||||
- Definition
Total of all Liabilities and Stockholders' Equity items (or Partners' Capital, as applicable), including the portion of equity attributable to noncontrolling interests, if any. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Total obligations incurred as part of normal operations that are expected to be paid during the following twelve months or within one business cycle, if longer. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Details
|
X | ||||||||||
- Definition
Sum of the carrying values as of the balance sheet date of all long-term debt, which is debt initially having maturities due after one year from the balance sheet date or beyond the operating cycle, if longer, but excluding the portions thereof scheduled to be repaid within one year or the normal operating cycle, if longer plus capital lease obligations due to be paid more than one year after the balance sheet date. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Total of the portions of the carrying amounts as of the balance sheet date of long-term debt, which may include notes payable, bonds payable, debentures, mortgage loans, and commercial paper, which are scheduled to be repaid within one year or the normal operating cycle, if longer, and after deducting unamortized discount or premiums, if any. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Carrying value as of the balance sheet date of obligations incurred through that date and payable arising from transactions not otherwise specified in the taxonomy. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer). Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Aggregate carrying amount, as of the balance sheet date, of current assets not separately disclosed in the balance sheet. Current assets are expected to be realized or consumed within one year (or the normal operating cycle, if longer). Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Net amount of other deferred costs capitalized at the end of the reporting period. Does not include deferred finance costs or deferred acquisition costs of insurance companies. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Carrying amount as of the balance sheet date of inventories of a nature not otherwise specified in the taxonomy. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Aggregate carrying amount, as of the balance sheet date, of noncurrent obligations not separately disclosed in the balance sheet. Noncurrent liabilities are expected to be paid after one year (or the normal operating cycle, if longer). Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
This represents the noncurrent liability for underfunded plans recognized in the balance sheet that is associated with the defined benefit pension plans and other postretirement defined benefit plans. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Sum of the amounts paid in advance for capitalized costs that will be expensed with the passage of time or the occurrence of a triggering event, and will be charged against earnings within one year or the normal operating cycle, if longer. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Gross amount, at the balance sheet date, of long-lived physical assets used in the normal conduct of business and not intended for resale. This can include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Tangible assets that are held by an entity for use in the production or supply of goods and services, for rental to others, or for administrative purposes and that are expected to provide economic benefit for more than one year; net of accumulated depreciation. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Details
|
X | ||||||||||
- Definition
This element represents capitalized assets classified as property, plant and equipment not otherwise defined in the taxonomy. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Period end amount of total gross PPE. No definition available.
|
X | ||||||||||
- Definition
Carrying amount as of the balance sheet date of capitalized costs of regulated entities that are expected to be recovered through revenue sources within one year or the normal operating cycle, if longer. Such costs are capitalized if they meet both of the following criteria: a. It is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for rate-making purposes. b. Based on available evidence, the future revenue will be provided to permit recovery of the previously incurred cost rather than to provide for expected levels of similar future costs. If the revenue will be provided through an automatic rate-adjustment clause, this criterion requires that the regulator's intent clearly be to permit recovery of the previously incurred cost. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Carrying amount as of the balance sheet date of capitalized costs of regulated entities that are not expected to be recovered through revenue sources within one year or the normal operating cycle if longer. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The amount for the individual regulatory liability as itemized in a table of regulatory liabilities as of the end of the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The amount for the individual regulatory current liability as itemized in a table of regulatory current liabilities as of the end of the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The cumulative amount of the reporting entity's undistributed earnings or deficit. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Reflects the total carrying amount as of the balance sheet date of debt having initial terms less than one year or the normal operating cycle, if longer. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Total of all stockholders' equity (deficit) items, net of receivables from officers, directors, owners, and affiliates of the entity which are attributable to the parent. The amount of the economic entity's stockholders' equity attributable to the parent excludes the amount of stockholders' equity which is allocable to that ownership interest in subsidiary equity which is not attributable to the parent (noncontrolling interest, minority interest). This excludes temporary equity and is sometimes called permanent equity. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Details
|
X | ||||||||||
- Definition
The amount allocated to treasury stock. Treasury stock is common and preferred shares of an entity that were issued, repurchased by the entity, and are held in its treasury. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
Consolidated Balance Sheets (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified |
Dec. 31, 2011
|
Dec. 31, 2010
|
---|---|---|
Consolidated Balance Sheets [Abstract] | ||
Allowance for uncollectible accounts receivable | $ 1,090 | $ 1,194 |
Common stock, par value | $ 0.4867 | $ 0.4867 |
Common stock, shares authorized | 25,000,000 | 25,000,000 |
X | ||||||||||
- Definition
A valuation allowance for trade and other receivables due to an Entity within one year (or the normal operating cycle, whichever is longer) that are expected to be uncollectible. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Face amount or stated value of common stock per share; generally not indicative of the fair market value per share. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The maximum number of common shares permitted to be issued by an entity's charter and bylaws. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Details
|
X | ||||||||||
- Definition
Depreciation and accretion included in other costs No definition available.
|
X | ||||||||||
- Definition
Other deferred charges No definition available.
|
X | ||||||||||
- Details
|
X | ||||||||||
- Definition
The cash inflow associated with the acquisition of business during the period (for example, cash that was held by the acquired business). Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Includes currency on hand as well as demand deposits with banks or financial institutions. It also includes other kinds of accounts that have the general characteristics of demand deposits in that the Entity may deposit additional funds at any time and also effectively may withdraw funds at any time without prior notice or penalty. Cash equivalents, excluding items classified as marketable securities, include short-term, highly liquid investments that are both readily convertible to known amounts of cash, and so near their maturity that they present minimal risk of changes in value because of changes in interest rates. Generally, only investments with original maturities of three months or less qualify under that definition. Original maturity means original maturity to the entity holding the investment. For example, both a three-month US Treasury bill and a three-year Treasury note purchased three months from maturity qualify as cash equivalents. However, a Treasury note purchased three years ago does not become a cash equivalent when its remaining maturity is three months. Compensating balance arrangements that do not legally restrict the withdrawal or usage of cash amounts may be reported as Cash and Cash Equivalents, while legally restricted deposits held as compensating balances against borrowing arrangements, contracts entered into with others, or company statements of intention with regard to particular deposits are not generally reported as cash and cash equivalents. Includes cash and cash equivalents associated with the entity's continuing operations. Excludes cash and cash equivalents associated with the disposal group (and discontinued operation). Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in cash and cash equivalents. While for technical reasons this element has no balance attribute, the default assumption is a debit balance consistent with its label. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The component of income tax expense for the period representing the increase (decrease) in the entity's deferred tax assets and liabilities pertaining to continuing operations. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The aggregate expense recognized in the current period that allocates the cost of tangible assets, intangible assets, or depleting assets to periods that benefit from use of the assets. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Costs and payments related to employee benefits and equity-based compensation, such as pension expense and contributions, other postretirement benefits expense and payments, stock or unit options expense, and amortization of restricted stock or unit. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The gains (losses) included in earnings resulting from the sale or disposal of tangible assets. This item does not include any gain (loss) recognized on the sale of oil and gas property or timber property. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in the amounts payable to vendors for goods and services received and the amount of obligations and expenses incurred but not paid. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in amount due within one year (or one business cycle) from customers for the credit sale of goods and services. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the period in the amount of customer money held in customer accounts, including security deposits, collateral for a current or future transactions, initial payment of the cost of acquisition or for the right to enter into a contract or agreement. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in the aggregate amount of obligations related to services received from employees, such as accrued salaries and bonuses, payroll taxes and fringe benefits. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in income taxes receivable, which represents the amount due from tax authorities for refunds of overpayments or recoveries of income taxes paid. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in interest payable, which represents the amount owed to note holders, bond holders, and other parties for interest earned on loans or credit extended to the reporting entity. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in the aggregate value of all inventory held by the reporting entity, associated with underlying transactions that are classified as operating activities. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in the amount due within one year (or one business cycle) of receivables that were originally due beyond one year (or one business cycle). Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Details
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in other liabilities used in operating activities not separately disclosed in the statement of cash flows. May include changes in other current liabilities, other noncurrent liabilities, or a combination of other current and noncurrent liabilities. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in the value of other assets that are created when regulatory agencies permits public utilities to defer costs to the balance sheet. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The change in cash during the period due to the net increase or decrease in outstanding checks, the liability that represents checks that have been issued but that have not cleared. The entity may classify these cash flows as financing or operating activities. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in the value of prepaid expenses and other assets not separately disclosed in the statement of cash flows, for example, deferred expenses, intangible assets,or income taxes. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in regulated liabilities. Regulated liabilities are created when regulatory agency permits an entity to defer revenues to the balance sheet. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The increase (decrease) during the reporting period in the aggregate market value of equity or debt securities that are purchased and held principally for the purpose of selling them in the near future and benefiting from increases in prices. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The net cash inflow or outflow from financing activity for the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Details
|
X | ||||||||||
- Definition
The net cash inflow or outflow from investing activity. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Details
|
X | ||||||||||
- Definition
The net cash from (used in) all of the entity's operating activities, including those of discontinued operations, of the reporting entity. Operating activities generally involve producing and delivering goods and providing services. Operating activity cash flows include transactions, adjustments, and changes in value that are not defined as investing or financing activities. While for technical reasons this element has no balance attribute, the default assumption is a debit balance consistent with its label. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Details
|
X | ||||||||||
- Definition
The portion of profit or loss for the period, net of income taxes, which is attributable to the parent. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Other income (expense) included in net income that results in no cash inflows or outflows in the period. Includes noncash adjustments to reconcile net income (loss) to cash provided by (used in) operating activities that are not separately disclosed. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Cash outflows made during the period for environmental remediation activities. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The net cash paid (received) associated with the acquisition or disposal of all investments, including securities and other assets. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The cash outflow from the distribution of an entity's earnings in the form of dividends to common shareholders. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The cash outflow associated with the acquisition of long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale; includes cash outflows to pay for construction of self-constructed assets. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The cash inflow from a debt initially having maturity due after one year or beyond the operating cycle, if longer. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The net cash inflow or outflow for borrowing having initial term of repayment within one year or the normal operating cycle, if longer. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The net cash inflow or outflow resulting from the entity's share transaction. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The cash inflow from the sale of property, plant and equipment (capital expenditures), software, and other intangible assets. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The cash outflow to pay off an obligation from a contractual arrangement with the lender, including letter of credit, standby letter of credit and revolving credit arrangements, under which borrowings can be made up to a specific amount at any point in time with either short term or long term maturity. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The cash outflow for debt initially having maturity due after one year or beyond the normal operating cycle, if longer. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The aggregate amount of noncash, equity-based employee remuneration. This may include the value of stock or unit options, amortization of restricted stock or units, and adjustment for officers' compensation. As noncash, this element is an add back when calculating net cash generated by operating activities using the indirect method. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The net change in the difference between the fair value and the carrying value, or in the comparative fair values, of open agreements to purchase or sell mineral resources, energy, and agricultural products at some future point held at each balance sheet date, that was included in earnings for the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The net change in the difference between the fair value and the carrying value, or in the comparative fair values, of investments, not including unrealized gains or losses on securities separately or otherwise categorized as trading, available-for-sale, or held-to-maturity, held at each balance sheet date and included in earnings for the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
Consolidated Statements of Stockholders' Equity (USD $)
In Thousands, except Share data |
Total
|
Deferred Compensation
|
Treasury Stock
|
Common Stock
|
Additional Paid-In Capital
|
Retained Earnings
|
Accumulated Other Comprehensive Loss
|
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Beginning balance at Dec. 31, 2008 | $ 123,073 | $ 1,549 | $ (1,549) | $ 3,323 | $ 66,681 | $ 56,817 | $ (3,748) | ||||||||||
Beginning balance, shares at Dec. 31, 2008 | [1] | 6,827,121 | |||||||||||||||
Net Income | 15,897 | 15,897 | |||||||||||||||
Total other comprehensive income (loss) | 1,224 | 1,224 | |||||||||||||||
Dividend Reinvestment Plan, shares | [1] | 31,607 | |||||||||||||||
Dividend Reinvestment Plan | 936 | 15 | 921 | ||||||||||||||
Retirement Savings Plan, shares | [1] | 32,375 | |||||||||||||||
Retirement Savings Plan | 982 | 16 | 966 | ||||||||||||||
Conversion of debentures, shares | [1] | 7,927 | |||||||||||||||
Conversion of debentures | 135 | 4 | 131 | ||||||||||||||
Share-based compensation, shares | [1],[2],[3] | 7,374 | |||||||||||||||
Share-based compensation | [2],[3] | 1,335 | 3 | 1,332 | |||||||||||||
Deferred Compensation Plan | [4] | (810) | 810 | ||||||||||||||
Purchase of treasury stock, shares | [1] | (2,411) | |||||||||||||||
Purchase of treasury stock | (73) | (73) | |||||||||||||||
Sale and distribution of treasury stock, shares | [1] | 2,411 | |||||||||||||||
Sale and distribution of treasury stock | 73 | 73 | |||||||||||||||
Common stock issued in the merger, shares | [1] | 2,487,910 | |||||||||||||||
Common stock issued in the merger | 75,682 | 1,211 | 74,471 | ||||||||||||||
Dividends on share-based compensation | (104) | (104) | |||||||||||||||
Cash dividends | [5] | (9,379) | (9,379) | ||||||||||||||
Ending balance at Dec. 31, 2009 | 209,781 | 739 | (739) | 4,572 | 144,502 | 63,231 | (2,524) | ||||||||||
Ending balance, shares at Dec. 31, 2009 | [1] | 9,394,314 | |||||||||||||||
Net Income | 26,056 | 26,056 | |||||||||||||||
Total other comprehensive income (loss) | (836) | (836) | |||||||||||||||
Dividend Reinvestment Plan, shares | [1] | 53,806 | |||||||||||||||
Dividend Reinvestment Plan | 1,725 | 26 | 1,699 | ||||||||||||||
Retirement Savings Plan, shares | [1] | 27,795 | |||||||||||||||
Retirement Savings Plan | 903 | 14 | 889 | ||||||||||||||
Conversion of debentures, shares | [1] | 11,865 | |||||||||||||||
Conversion of debentures | 202 | 6 | 196 | ||||||||||||||
Share-based compensation, shares | [1],[2],[3] | 36,415 | |||||||||||||||
Share-based compensation | [2],[3] | 637 | 17 | 620 | |||||||||||||
Tax benefit on share-based compensation | 253 | 253 | |||||||||||||||
Deferred Compensation Plan | [4] | 38 | (38) | ||||||||||||||
Purchase of treasury stock, shares | [1] | (1,144) | |||||||||||||||
Purchase of treasury stock | (38) | (38) | |||||||||||||||
Sale and distribution of treasury stock, shares | [1] | 1,144 | |||||||||||||||
Sale and distribution of treasury stock | 38 | 38 | |||||||||||||||
Dividends on share-based compensation | (104) | (104) | |||||||||||||||
Cash dividends | [5] | (12,378) | (12,378) | ||||||||||||||
Ending balance at Dec. 31, 2010 | 226,239 | 777 | (777) | 4,635 | 148,159 | 76,805 | (3,360) | ||||||||||
Ending balance, shares at Dec. 31, 2010 | [1] | 9,524,195 | |||||||||||||||
Net Income | 27,622 | 27,622 | |||||||||||||||
Total other comprehensive income (loss) | (1,167) | (1,167) | |||||||||||||||
Dividend Reinvestment Plan | (22) | (22) | |||||||||||||||
Retirement Savings Plan, shares | [1] | 2,002 | |||||||||||||||
Retirement Savings Plan | 80 | 1 | 79 | ||||||||||||||
Conversion of debentures, shares | [1] | 10,680 | |||||||||||||||
Conversion of debentures | 181 | 5 | 176 | ||||||||||||||
Share-based compensation, shares | [1],[2],[3] | 30,430 | |||||||||||||||
Share-based compensation | [2],[3] | 1,013 | 15 | 998 | |||||||||||||
Tax benefit on share-based compensation | 13 | 13 | |||||||||||||||
Deferred Compensation Plan | [4] | 40 | (40) | ||||||||||||||
Purchase of treasury stock, shares | [1] | (993) | |||||||||||||||
Purchase of treasury stock | (40) | (40) | |||||||||||||||
Sale and distribution of treasury stock, shares | [1] | 993 | |||||||||||||||
Sale and distribution of treasury stock | 40 | 40 | |||||||||||||||
Dividends on share-based compensation | (129) | (129) | |||||||||||||||
Cash dividends | [5] | (13,050) | (13,050) | ||||||||||||||
Ending balance at Dec. 31, 2011 | $ 240,780 | $ 817 | $ (817) | $ 4,656 | $ 149,403 | $ 91,248 | $ (4,527) | ||||||||||
Ending balance, shares at Dec. 31, 2011 | [1] | 9,567,307 | |||||||||||||||
|
X | ||||||||||
- Definition
Deferred Compensation Plan (4) No definition available.
|
X | ||||||||||
- Definition
Dividends on share-based compensation No definition available.
|
X | ||||||||||
- Definition
Retirement Savings Plan, shares No definition available.
|
X | ||||||||||
- Definition
Retirement Savings Plan No definition available.
|
X | ||||||||||
- Definition
Tax benefit associated with any equity-based compensation plan other than an employee stock ownership plan (ESOP). The tax benefit results from the deduction by the entity on its tax return for an award of stock that exceeds the cumulative compensation cost for common stock or preferred stock recognized for financial reporting. Includes any resulting tax benefit that exceeds the previously recognized deferred tax asset (excess tax benefits). Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Equity impact of common stock cash dividends declared by an entity during the period. This element includes paid and unpaid dividends declared during the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
The portion of profit or loss for the period, net of income taxes, which is attributable to the parent. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
This element represents Other Comprehensive Income or Loss, Net of Tax, for the period attributable to the parent entity. Includes deferred gains or losses on qualifying hedges, unrealized holding gains or losses on available-for-sale securities, minimum pension liability, and cumulative translation adjustment. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Number of shares of stock issued as of the balance sheet date, including shares that had been issued and were previously outstanding but which are now held in the treasury. Reference 1: http://www.xbrl.org/2003/role/presentationRef
|
X | ||||||||||
- Definition
Total of all stockholders' equity (deficit) items, net of receivables from officers, directors, owners, and affiliates of the entity which are attributable to the parent. The amount of the economic entity's stockholders' equity attributable to the parent excludes the amount of stockholders' equity which is allocable to that ownership interest in subsidiary equity which is not attributable to the parent (noncontrolling interest, minority interest). This excludes temporary equity and is sometimes called permanent equity. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Number of shares of stock issued during the period pursuant to acquisitions. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Number of shares issued during the period as a result of the conversion of convertible securities. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Number of shares issued during the period from a dividend reinvestment plan (DRIP). A dividend reinvestment plan allows the shareholders to reinvest dividends paid to them by the entity on new issues of stock by the entity. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Number of shares (or other type of equity) issued during the period as a result of any equity-based compensation plan other than an employee stock ownership plan (ESOP), net of any shares forfeited. Shares issued could result from the issuance of restricted stock, the exercise of stock options, stock issued under employee stock purchase plans, and/or other employee benefit plans. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Number of treasury shares (units) reissued during the period, excluding reissuance of shares (units) held in treasury used to satisfy equity-based compensation obligations exercised by the holders of such rights. Upon reissuance of shares (units) from treasury, either the common or preferred stock (unit) reissued is outstanding. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Value of stock issued pursuant to acquisitions during the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
The gross value of stock issued during the period upon the conversion of convertible securities. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Value of stock issued during the period from a dividend reinvestment plan (DRIP). A dividend reinvestment plan allows the holder of the stock to reinvest dividends paid to them by the entity on new issues of stock by the entity. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Value of stock (or other type of equity) issued during the period as a result of any equity-based compensation plan other than an employee stock ownership plan (ESOP), net of stock value of such awards forfeited. Stock issued could result from the issuance of restricted stock, the exercise of stock options, stock issued under employee stock purchase plans, and/or other employee benefit plans. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Equity impact of the value of treasury stock (units) reissued during the period, excluding reissuance of shares (units) held in treasury used to satisfy equity-based compensation obligations exercised by the holders of such rights. Upon reissuance of shares (units) from treasury, either the common or preferred stock (unit) reissued is outstanding. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Number of shares that have been repurchased during the period and have not been retired and are not held in treasury. Some state laws may govern the circumstances under which an entity may acquire its own stock and prescribe the accounting treatment therefore. This element is used when state law does not recognize treasury stock. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Definition
Equity impact of the value of stock that has been repurchased during the period and has not been retired and is not held in treasury. Some state laws may mandate the circumstances under which an entity may acquire its own stock and prescribe the accounting treatment therefore. This element is used when state law does not recognize treasury stock. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Consolidated Statements of Stockholders' Equity (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified |
12 Months Ended | ||
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Dec. 31, 2011
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Dec. 31, 2010
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Dec. 31, 2009
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Consolidated Statements of Stockholders' Equity [Abstract] | |||
Deferred compensation plan held Rabbi Trust | 30,597 | 29,596 | 28,452 |
Shares issued under the performance incentive plan withheld for employee taxes | 12,324 | 17,695 | |
Deferred compensation plan distributions | $ 883 | ||
Cash dividends declared per share of common stock | $ 1.365 | $ 1.305 | $ 1.250 |
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- Definition
Deferred Compensation Plan (4) No definition available.
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- Definition
Balance No definition available.
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- Definition
Shares issued under the performance incentive plan withheld for employee taxes No definition available.
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X | ||||||||||
- Definition
Aggregate dividends declared during the period for each share of common stock outstanding. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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- Details
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Summary of Accounting Policies
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Summary of Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SUMMARY OF ACCOUNTING POLICIES |
A. SUMMARY OF ACCOUNTING POLICIES Nature of Business Chesapeake, incorporated in 1947 in Delaware, is a diversified utility company engaged in regulated energy, unregulated energy and other unregulated businesses. Our regulated energy business delivers natural gas to approximately 122,000 customers located in central and southern Delaware, Maryland’s eastern shore and Florida and electricity to approximately 31,000 customers in northeast and northwest Florida. Our regulated energy business also provides natural gas transmission service primarily through a 402-mile interstate pipeline from various points in Pennsylvania and northern Delaware to our natural gas distribution affiliates in Delaware and Maryland as well as to other utility and industrial customers in Pennsylvania, Delaware and the eastern shore of Maryland. Our unregulated energy business includes natural gas marketing, propane distribution and propane wholesale marketing operations. The natural gas marketing operation sells natural gas supplies directly to commercial and industrial customers in Florida, Delaware and Maryland. Through our propane distribution operation, we distribute propane to approximately 49,000 customers in Delaware, the eastern shore of Maryland and Virginia, southeastern Pennsylvania and Florida. The propane wholesale marketing operation markets propane to wholesale customers including large independent oil and petrochemical companies, resellers and propane distribution companies in the southeastern United States. We also engage in non-energy businesses, primarily through our advanced information services subsidiary, which provides information-technology-related business services and solutions for both enterprise and e-business applications. Principles of Consolidation The Consolidated Financial Statements include the accounts of Chesapeake and its wholly owned subsidiaries. As a result of the merger with FPU on October 28, 2009, FPU’s financial position, results of operations and cash flows have been consolidated into our results from the effective date of the merger. We do not have any ownership interests in investments accounted for using the equity method or any variable interests in a variable interest entity. All intercompany transactions have been eliminated in consolidation. System of Accounts Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by the PSCs in their respective states with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern Shore is an open access pipeline regulated by the FERC. Our financial statements are prepared in accordance with GAAP, which give appropriate recognition to the ratemaking and accounting practices and policies of the various regulatory commissions. Our unregulated energy and other unregulated businesses are not subject to regulation with respect to rates, service or maintenance of accounting records. Reclassifications We reclassified certain amounts in the consolidated statement of income for the year ended December 31, 2010 and in the consolidated statements of cash flows for the years ended December 31, 2010 and 2009, to conform to the current year’s presentation. We also reclassified certain amounts in the consolidated balance sheet as of December 31, 2010, to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our consolidated financial statements. Use of Estimates Our financial statements are prepared in conformity with GAAP, which requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates.
Property, Plant, Equipment and Depreciation Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Property, plant and equipment acquired in the merger were stated at fair value at the time of the merger. Costs include direct labor, materials and third-party construction contractor costs, allowance for capitalized interest and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged against income as incurred, and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of property owned by the unregulated businesses, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. The provision for depreciation is computed using the straight-line method at rates that amortize the unrecovered cost of depreciable property over the estimated remaining useful life of the asset. Depreciation and amortization expenses for the regulated energy operations are provided at various annual rates, as approved by the regulators.
The regulated operations compute depreciation in accordance with rates approved by either the state PSC or the FERC. These rates are based on depreciation studies and may change periodically upon receiving approval from the appropriate regulatory body. The depreciation rates shown above are based on the remaining useful lives of the assets at the time of the depreciation study, rather than the original lives of the assets. The depreciation rates are composite, straight-line rates applied to the average investment for each class of depreciable property and are adjusted for anticipated cost of removal less salvage value. The non-regulated operations compute depreciation using the straight-line method over the estimated useful life of the asset.
Plant in service includes $1.4 million of assets owned by one of our natural gas transmission subsidiaries, which it uses to provide natural gas transmission service under a contract with a third party. This contract is accounted for as an operating lease due to exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and provides $264,000 in annual revenues for a term of 20 years. Accumulated depreciation for these assets total $218,000 at December 31, 2011.
In July 2011, we sold an Internet Protocol address asset to an unaffiliated entity for approximately $553,000. This particular Internet Protocol address was not used by us and did not have any net carrying value at the time of the sale. We recognized a non-operating pre-tax gain of $553,000 from this sale, which is included in other income in the accompanying consolidated statements of income. In September 2011, FPU entered into an agreement with an unaffiliated entity to sell its office building located in West Palm Beach, Florida for $2.2 million. FPU also entered into a separate agreement to lease office space at a different location in West Palm Beach, which commenced in February 2012. The sale of FPU’s West Palm Beach office building was finalized in February 2012. Some of the approximately 70 employees previously located in the West Palm Beach office building moved into the newly leased office space and the remaining employees moved into another nearby operations center, which FPU owns, in West Palm Beach. We treated the West Palm Beach office building as an asset held for sale and it was included in other property, plant and equipment at December 31, 2011 in the accompanying consolidated balance sheet. The West Palm Beach office building had a net carrying value of approximately $2.0 million at December 31, 2011. Since the sale price, less costs to consummate the sale, exceeded the net carrying value of the building, no impairment was recorded. As most of the West Palm Beach office building was considered a property within the regulated businesses, most of the gain resulting from the sale was charged to accumulated depreciation when the sale was completed in February 2012. Cash and Cash Equivalents Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates market value. Investments with an original maturity of three months or less when purchased are considered cash equivalents. Inventories We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values.
Regulatory Assets, Liabilities and Expenditures We account for our regulated operations in accordance with ASC Topic 980, “Regulated Operations.” This Topic includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company for amounts previously collected from customers, and for recovery of costs that are expected to be incurred in the future as regulatory liabilities. If we were required to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in the statement of income at that time, which could have a material impact on our financial position, results of operations and cash flows. At December 31, 2011 and 2010, the regulated utility operations had recorded the following regulatory assets and liabilities on our consolidated balance sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.
We monitor our regulatory and competitive environment to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that provisions of ASC Topic 980, “Regulated Operations,” continue to apply to our regulated operations and that the recovery of our regulatory assets is probable. Goodwill and Other Intangible Assets Goodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note H, “Goodwill and Other Intangible Assets,” for additional discussion of this subject. Other Deferred Charges Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt issuance costs are deferred and then are amortized to interest expense over the original lives of the respective debt issuances. Pension and Other Postretirement Plans Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. Management annually reviews the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates and the expected returns on plan assets are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.
The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When estimating our discount rates, we consider high quality corporate bond rates, such as the Moody’s Aa bond index and the Citigroup yield curve, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options. The expected long-term rates of return on assets are utilized in calculating the expected returns on plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets of each of our plans by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on assets. We estimate the assumed health care cost trend rates used in determining our postretirement net expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date. Actual changes in the fair value of plan assets and the differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension and postretirement benefit costs that we ultimately recognize. A 0.25 percent change in the discount rate could change our pension and postretirement costs by approximately $34,000. A 0.25 percent change in the rate of return could change our pension cost by approximately $108,000 and will not have an impact on the postretirement and supplemental pension plans because these plans are not funded. Income Taxes and Investment Tax Credit Adjustments Deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the financial statement bases and tax bases of assets and liabilities and are measured using the enacted tax rates in effect in the years in which the differences are expected to reverse. The portions of our deferred tax liabilities applicable to regulated energy operations, which have not been reflected in current service rates, represent income taxes recoverable through future rates. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property. We account for uncertainty in income taxes in the financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income. Financial Instruments Xeron, our propane wholesale marketing subsidiary, engages in trading activities using forward and futures contracts, which have been accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, our trading contracts are recorded at fair value. The changes in market price are recognized as gains or losses in revenues on the consolidated statements of income in the period of change. Trading liabilities are recorded as mark-to-market energy liabilities. Trading assets are recorded as mark-to-market energy assets. Our natural gas, electric and propane distribution operations and natural gas marketing operations enter into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts 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 enter into derivative transactions, such as swaps and puts, in order to mitigate the impact of wholesale price fluctuations on its inventory valuation. These transactions may be designated as fair value hedges if they meet all of the accounting requirements pursuant to ASC 815 and we elect to designate the instruments as fair value hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap or put, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of propane inventory. The ineffective portion of the gain or loss is recorded in earnings. If the instrument is not designated as a fair value hedge or does not meet the accounting requirements of a fair value hedge, it is recorded at fair value with the gain or loss being recorded in earnings. Earnings Per Share Basic earnings per share are computed by dividing income available for common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share are computed by dividing income available for common stockholders by the weighted average number of shares of common stock outstanding during the period adjusted for the exercise and/or conversion of all potentially dilutive securities, such as convertible debt and share-based compensation. The calculations of both basic and diluted earnings per share are presented in the following chart.
In 2009, common stock issued in connection with the FPU merger (See Note B, “Acquisitions,” to the Consolidated Financial Statements) was outstanding for only two months (from the merger closing on October 28, 2009 to December 31, 2009). Operating Revenues Revenues for our natural gas and electric distribution operations are based on rates approved by the PSCs in the states in which they operate. Eastern Shore’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to negotiated rates.
For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. In connection with this accrual, we must estimate the amounts of natural gas and electricity that have been delivered to our systems but have not been accounted for (commonly known as “unaccounted for” gas and electricity). We estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers, and natural gas marketing customers, whose billing cycles do not coincide with our accounting periods. The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in our consolidated statement of income. For propane distribution customers without meters and advanced information services customers, we record revenue in the period the products are delivered and/or services are rendered. Each of our natural gas distribution operations in Delaware and Maryland, our FPU natural gas operation and our electric distribution operation in Florida has a purchased fuel cost recovery mechanism. This mechanism provides a method of adjusting the billing rates to reflect changes in the cost of purchased fuel. The difference between the current cost of fuel purchased and the cost of fuel recovered in billed rates is deferred and accounted for as either unrecovered purchased fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year. Chesapeake’s Florida natural gas distribution division provides only unbundled delivery service. We charge flexible rates to our natural gas distribution industrial interruptible customers to compete with prices of alternative fuels, which these customers are able to use. Neither we nor our interruptible customers are contractually obligated to deliver or receive natural gas on a firm service basis. We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis. Cost of Sales Cost of sales includes the direct costs attributable to the products sold or services we provide for our regulated and unregulated energy segments. These costs include primarily the variable cost of natural gas, electricity and propane commodities, pipeline capacity costs needed to transport and store natural gas, transmission costs for electricity, transportation costs to transport propane purchases to our storage facilities, and the direct cost of labor for our advanced information services operation. Operations and Maintenance Expenses Operations and maintenance expenses are costs associated with the operation and maintenance of our regulated and unregulated operations. Major cost components include operation and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of cost of removal for future retirements of utility assets, and other administrative expenses. Depreciation and Accretion Included in Operations Expenses We report certain depreciation and accretion in operations expense rather than depreciation and amortization expense in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expenses consist of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2011, 2010 and 2009, $5.1 million, $4.4 million and $2.8 million, respectively, of depreciation and accretion were reported in operations expenses.
Allowance for Doubtful Accounts An allowance for doubtful accounts is recorded against amounts due to reduce the net receivables balance to the amount we reasonably expect to collect based upon our collections experiences and management’s assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, the level of natural gas, electricity and propane prices and general economic conditions. Accounts are written off when they are deemed to be uncollectible. Subsequent Events We have assessed and reported on subsequent events through the date of issuance of these Consolidated Financial Statements. FASB Statements and Other Authoritative Pronouncements Recent Accounting Amendments Yet to be Adopted by the Company In May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” Amendments in the ASU do not extend the use of fair value accounting but provide guidance on how it should be applied where its use is already required or permitted by other standards within International Financial Accounting Standards (“IFRS”) or U.S. GAAP. ASU 2011-04 supersedes most of the guidance in Topic 820, although many of the changes are clarifications of existing guidance or wording changes to align with IFRS. Certain amendments in ASU 2011-04 change a particular principle or requirement for measuring fair value or disclosing information about fair value measurements. The amendments in ASU 2011-04 are effective for public entities for interim and annual periods beginning after December 15, 2011, and should be applied prospectively. Early adoption is not permitted for public entities. We expect the adoption of ASU 2011-04 to have no material impact on our financial position and results of operations. In September 2011, the FASB issued ASU 2011-08, “Intangibles – Goodwill and Other (Topic 350) Testing Goodwill for Impairment.” ASU 2011-08 allows an entity to assess qualitatively whether it is necessary to perform step one of the two-step annual goodwill impairment test. Step one would be required if it is more-likely-than-not that a reporting unit’s fair value is less than its carrying amount. This is different than previous guidance, which required entities to perform step one of the test, at least annually, by comparing the fair value of a reporting unit to its carrying amount. An entity may elect to bypass the qualitative assessment and proceed directly to step one, for any reporting unit, in any period. ASU 2011-08 does not change the guidance on when to test goodwill for impairment. The amendments in ASU 2011-08 are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We expect the adoption of ASU 2011-08 to have no material impact on our financial position and results of operations.
Other Accounting Amendments Adopted by the Company in 2011 In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income.” ASU 2011-05 amends the guidance in Topic 220, “Comprehensive Income,” by eliminating the option to present components of other comprehensive income (“OCI”) in the statement of stockholders’ equity. Instead, the new guidance now requires entities to present all non-owner changes in stockholders’ equity either as a single continuous statement of comprehensive income or as two separate but consecutive statements of income and comprehensive income. The components of OCI have not changed nor has the guidance on when OCI items are reclassified to net income. Similarly, ASU 2011-05 does not change the guidance to disclose OCI components gross or net of the effect of income taxes, provided that the tax effects are presented on the face of the statement in which OCI is presented, or disclosed in the notes to the financial statements. For public entities, the amendments in ASU 2011-05 are effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2011 with early adoption permitted. In December 2011, the FASB indefinitely deferred provisions of ASU 2011-05 that require entities to present all reclassification adjustments from OCI to net income on the face of the statement of comprehensive income. On December 31, 2011, we voluntarily adopted ASU 2011-05 early, except for the provisions deferred indefinitely. As a result of our early adoption of ASU 2011-05, we are now presenting a separate statement of comprehensive income, following the statement of income. The change is for presentation only, and the early adoption of ASU 2011-05 did not impact our financial position, results of operations or cash flows. |
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The entire disclosure for all significant accounting policies of the reporting entity. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Acquisitions
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Acquisitions [Abstract] | |
ACQUISITONS |
B. ACQUISITIONS FPU On October 28, 2009, we completed a merger with FPU, pursuant to which FPU became a wholly owned subsidiary of Chesapeake. The merger was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer for accounting purposes. In consummating the merger, we issued 2,487,910 shares of Chesapeake common stock at a price per share of $30.42 in exchange for all outstanding common stock of FPU. We also paid approximately $16,000 in lieu of issuing fractional shares in the exchange. There was no contingent consideration in the merger. The total value of consideration transferred by Chesapeake in the merger was approximately $75.7 million. The assets acquired and liabilities assumed in the merger were recorded at their respective fair values at the completion of the merger. For certain assets acquired and liabilities assumed, such as pension and post-retirement benefit obligations, income taxes and contingencies without readily determinable fair values, for which GAAP provides specific exception to the fair value recognition and measurement, we applied other specified GAAP or accounting treatment as appropriate. Goodwill from the merger was $34.2 million. Pursuant to the approval by the Florida PSC in January 2012 to include the $34.2 million premium paid in this merger in the rate base and amortize it over a 30-year period beginning in November 2009 (see Note O, “Rates and Other Regulatory Activities”), we reclassified to a regulatory asset at December 31, 2011, $31.7 million of the goodwill, which represents the portion of the goodwill allowed to be recovered in future rates after the effective date of the Florida PSC order. The acquisition method of accounting requires acquisition-related costs to be expensed in the period, in which those costs are incurred, rather than including them as a component of consideration transferred. As we intended to seek recovery in future rates in Florida of the merger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining the proper accounting treatment for those costs. We deferred approximately $1.3 million as a regulatory asset, which represented our best estimate of the costs we expected to be permitted to recover when we completed the appropriate rate proceedings. In January 2012, the Florida PSC approved the recovery of the $1.3 million deferred merger-related costs in future rates (see Note O, “Rates and Other Regulatory Activities”).
Virginia LP Gas On February 4, 2010, Sharp, our propane distribution subsidiary, purchased the operating assets of Virginia LP Gas, Inc. (“Virginia LP”), a propane distributor serving approximately 1,000 retail customers in Northampton and Accomack Counties in Virginia. The total consideration for the purchase was $600,000, $300,000 of which was paid at the closing and the remaining $300,000 is to be paid over 60 months. Based on our valuation, we allocated $188,000 of the purchase price to intangible assets, which consist of customer lists and non-compete agreements. These intangible assets are being amortized over a seven-year period. There was no goodwill recorded in connection with this acquisition. The revenue and net income from this acquisition, which were included in our consolidated statement of income for the year ended December 31, 2010, were not material. Indiantown Gas Company On August 9, 2010, FPU purchased the natural gas operating assets of IGC, which provides natural gas distribution services to approximately 700 customers including two large industrial customers in Indiantown, Florida. FPU paid approximately $1.2 million for these assets. FPU recorded $742,000 in goodwill in connection with this acquisition, all of which is deductible for income tax purposes. There was no intangible asset recorded in connection with this acquisition. The revenue and net income from this acquisition, which were included in our consolidated statement of income for the year ended December 31, 2010, were not material. Crescent Propane On December 12, 2011, Flo-Gas Corporation, the propane distribution subsidiary of FPU, purchased the operating assets of Crescent Propane, Inc. (“Crescent”) for approximately $790,000. These assets are used to provide propane distribution services to approximately 800 customers in north central Florida. In connection with this acquisition, we recorded $200,000 in goodwill, all of which is deductible for income tax purposes. There was no intangible asset recorded in connection with this acquisition. The revenue and net income from this acquisition, which were included in our consolidated statement of income for the year ended December 31, 2011, were not material. |
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The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable). Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Segment Information
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SEGMENT INFORMATION |
C. 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 of three operating segments:
The following table presents information about our reportable segments.
Our operations are almost entirely domestic. Our advanced information services subsidiary, BravePoint, has infrequent transactions with foreign companies, located primarily in Canada. These transactions, which are denominated and paid in U.S. dollars, are immaterial to the consolidated revenues.
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The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Supplemental Cash Flow Disclosures
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SUPPLEMENTAL CASH FLOW DISCLOSURES |
D. SUPPLEMENTAL CASH FLOW DISCLOSURES Cash paid for interest and income taxes during the years ended December 31, 2011, 2010 and 2009 were as follows:
Non-cash investing and financing activities during the years ended December 31, 2011, 2010, and 2009 were as follows:
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The entire disclosure for supplemental cash flow activities, including cash, noncash, and part noncash transactions, for the period. Noncash is defined as information about all investing and financing activities of an enterprise during a period that affect recognized assets or liabilities but that do not result in cash receipts or cash payments in the period. "Part noncash" refers to that portion of the transaction not resulting in cash receipts or cash payments in the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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DERIVATIVE INSTRUMENTS |
E. DERIVATIVE INSTRUMENTS Xeron, our propane wholesale and marketing subsidiary, 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. As of December 31, 2011, we had the following outstanding trading contracts which we accounted for as derivatives:
Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the first quarter of 2012. In August 2011, Sharp, our Delmarva propane distribution subsidiary, entered into a put option to protect against the decline in propane prices and related potential inventory losses associated with 630,000 gallons purchased for the propane price cap program in the upcoming heating season. This put option is exercised if the propane prices fall below the strike price of $1.445 per gallon in January through March of 2012, and we will receive the difference between the market price and the strike price during those months. We paid $91,000 to purchase the put option. We account for this put option as a fair value hedge. As of December 31, 2011, the put option had a fair value of $68,000. The change in the fair value of the put option effectively reduced our propane inventory balance. There was no ineffective portion of this fair value hedge in 2011.
In October 2010, Sharp entered into put options to protect against the decline in propane prices and related potential inventory losses associated with 1,470,000 gallons purchased for the propane price cap program in the upcoming heating season. This put option would be exercised if the propane prices fell below the strike prices of $1.251 per gallon and $1.230 per gallon in January and February of 2011, respectively, at which point we would have received the difference between the market price and the strike price during those months. We paid $168,000 to purchase the put option. Although the put option met the accounting requirements for fair value hedge, we elected not to designate it as a fair value hedge and accounted for it on a mark-to-market basis. As of December 31, 2010, the put option had no fair value. The change in the fair value of the put option reduced our earnings in 2010. 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. Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2011 and 2010, are the following:
The effects of gains and losses from derivative instruments are the following:
The effects of trading activities on the Consolidated Statements of Income are the following:
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The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Fair Value of Financial Instruments
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FAIR VALUE OF FINANCIAL INSTRUMENTS |
F. 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).
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 used at December 31, 2011:
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 used at December 31, 2010:
The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of December 31, 2011 and 2010: 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 option – The fair value of the propane put option is valued using market transactions for similar assets and liabilities in either the listed or OTC markets. At December 31, 2011, 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 carrying value of these financial assets and liabilities approximates fair value due to their short maturities and because interest rates approximate current market rates for short-term debt. At December 31, 2011, long-term debt, which includes the current maturities of long-term debt, had a carrying value of $118.5 million, compared to a fair value of $142.3 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, with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered Level 3 measurement. |
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The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Investments
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Investments [Abstract] | |
INVESTMENTS |
G. INVESTMENTS The investment balance at December 31, 2011, represents: (a) a Rabbi Trust associated with our Supplemental Executive Retirement Savings Plan; (b) a Rabbi Trust related to a stay bonus agreement with a former executive; and (c) investments in equity securities. We classify these investments as trading securities and report them at their fair value. We recorded $282,000 for an unrealized gain, net of other expenses, in other income in the consolidated statements of income. We also have an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Rabbi Trusts. At December 31, 2011 and 2010, total investments had a fair value of $4.0 million.
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Tabular disclosure of investments in certain debt and equity securities (and certain other trading assets) which include all debt and equity securities (other than those equity securities accounted for under the equity or cost methods of accounting) with readily determinable fair values. Other trading assets include assets that are carried on the balance sheet at fair value and held for trading purposes. A debt security represents a creditor relationship with an enterprise that is in the form of a security. Debt securities include, among other items, US Treasury securities, US government securities, municipal securities, corporate bonds, convertible debt, commercial paper, and all securitized debt instruments. An equity security represents an ownership interest in an enterprise or the right to acquire or dispose of an ownership interest in an enterprise at fixed or determinable prices. Equity securities include, among other things, common stock, certain preferred stock, warrant rights, call options, and put options, but do not include convertible debt. An entity may opt to provide the reader with additional narrative text to better understand the nature of investments in debt and equity securities (and other trading assets). Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Goodwill and Other Intangible Assets
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GOODWILL AND OTHER INTANGIBLE ASSETS |
H. GOODWILL AND OTHER INTANGIBLE ASSETS The carrying value of goodwill as of December 31, 2011 and 2010 was as follows:
Goodwill in the regulated energy segment is comprised of approximately $2.5 million from the FPU merger and $746,000 from the purchase of operating assets from IGC. Goodwill in the unregulated energy segment is comprised of $200,000 from the purchase of the operating assets from Crescent on December 12, 2011, and $674,000 related to the premium paid by Sharp in its acquisitions in the late 1980s and 1990s. As discussed in Note B, “Acquisitions,” we reclassified to a regulatory asset during 2011, $31.7 million of the $34.2 million goodwill previously recorded in connection with the FPU acquisition. We test for impairment of goodwill at least annually. The impairment testing for 2011 and 2010 indicated no impairment of goodwill. The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2011 and 2010 are as follows:
The customer list is an intangible asset which was acquired in the FPU merger in October 2009 and is being amortized over a 12-year period. Other intangible assets include customer lists and a non-compete agreement acquired in the purchase of the operating assets of Virginia LP in February 2010 and customer lists and acquisition costs from our acquisitions in the late 1980s and 1990s. These intangible assets are being amortized over a period ranging from seven to 40 years. For the years ended December 31, 2011, 2010 and 2009, amortization expense of intangible assets was $332,000, $679,000 and $232,000, respectively. Amortization expense of intangible assets for 2012 to 2016 is: $329,000 for 2012 and, $325,000 for 2013-2016.
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The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Income Taxes
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Income Taxes [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
INCOME TAXES |
I. INCOME TAXES We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. FPU has been included in our consolidated federal return since the completion of the merger on October 28, 2009. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. FPU continues to file a separate state income tax return in Florida. During 2011, the Internal Revenue Service (“IRS”) performed its examination of FPU’s consolidated federal returns for 2008 and for the period from January 1, 2009 to October 28, 2009 (the pre-merger period in 2009, during which FPU was required to file a separate federal tax return) and proposed a disallowance of approximately $135,000 and $256,000, respectively, of the environmental expenditure deductions taken by FPU related to one of the environmental remediation sites. We disagreed with the IRS finding and filed an appeal, which is currently underway. The IRS finding is based on the failure of FPU to follow a technical requirement to label these environmental expenditures in a specific way on the returns. The IRS has granted relief in the past to other companies in a similar situation, which allowed those companies to correctly label such expenditures. We have requested this relief with the IRS and upon receiving this relief, we believe that those deductions will likely be sustained during the appeal process. Accordingly, we did not record any accrual as of December 31, 2011, related to the examination by the IRS of the FPU returns. In January 2012, the IRS informed us that Chesapeake’s consolidated federal return for 2009 has been selected for examination. The IRS previously examined our 2005 and 2006 consolidated federal returns, which resulted in a total adjustment of $27,000 in our tax liability. The IRS is currently performing its examination and we cannot predict the outcome at this time. We did not record any accrual for uncertain income tax positions in 2009, 2010 and 2011. We generated net operating losses of $1.5 million in 2011, for federal income tax purposes, primarily from increased book-to-tax timing differences authorized by The Tax Relief Unemployment Insurance Reauthorization, and Job Creation Act of 2010, which allowed bonus depreciation for certain assets. The federal net operating losses are available to offset future taxable income and will expire in 2026. We had previously generated net operating losses in 2008 for federal income tax purposes, which were carried forward to fully offset our taxable income in 2009 and partially offset our taxable income in 2010. None of the federal net operating losses from 2008 remained at December 31, 2010. We also had tax net operating losses in various states totaling $19.0 million as of December 31, 2011, almost all of which will expire in 2028. We have recorded a deferred tax asset of $991,000 and $1.3 million related to the federal and state net operating loss carry-forwards at December 31, 2011 and 2010, respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax net operating losses because we believe they will all be fully utilized. The following tables provide: (a) the components of income tax expense in 2011, 2010 and 2009; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2011, 2010 and 2009; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2011 and 2010.
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The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Long-Term Debt
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LONG-TERM DEBT |
J. LONG-TERM DEBT Our outstanding long-term debt is as shown below.
Annual maturities of consolidated long-term debt are as follows: $8,196 for 2012; $8,196 for 2013; $11,196 for 2014; $10,275 for 2015 and $80,683 thereafter. Secured First Mortgage Bonds FPU’s secured first mortgage bonds are guaranteed by Chesapeake and are secured by a lien covering all of FPU’s property. The 9.57 percent bond and 10.03 percent bond require annual sinking fund payments of $909,000 and $500,000, respectively. Uncollateralized Senior Notes On June 23, 2011, we issued $29.0 million of 5.68 percent unsecured senior notes to Metropolitan Life Insurance Company and New England Life Insurance Company, pursuant to an agreement we entered into with them on June 29, 2010. These notes have similar covenants and default provisions as Chesapeake’s existing senior notes, and they require annual principal payments of $2.9 million beginning in the sixth year after the issuance. We used the proceeds to permanently finance the redemption of the 6.85 percent and 4.90 percent series of FPU first mortgage bonds. These redemptions occurred in January 2010 and were previously financed by Chesapeake’s short-term loan facilities. Under the same agreement, we may issue an additional $7.0 million of unsecured senior notes prior to May 3, 2013, at a rate ranging from 5.28 percent to 6.43 percent based on the timing of the issuance. These notes, if issued, will have similar covenants and default provisions as the senior notes issued in June 2011. Convertible Debentures The convertible debentures may be converted, at the option of the holder, into shares of our common stock at a conversion price of $17.01 per share. During 2011 and 2010, debentures totaling $181,000 and $202,000, respectively, were converted to stock. The debentures are also redeemable for cash at the option of the holder, subject to an annual non-cumulative maximum limitation of $200,000. In 2011, debentures totaling $2,000 were redeemed for cash. In 2010, no debentures were redeemed for cash. At our option, the debentures may be redeemed at stated amounts.
Debt Covenants Indentures to our long-term debt contain various restrictions. The most stringent restrictions state that we must maintain equity of at least 40 percent of total capitalization, and the fixed charge coverage ratio must be at least 1.2 times. In connection with the merger, the uncollateralized senior notes were amended to include an additional covenant requiring us to maintain no more than a 20-percent ratio of secured and subsidiary long-term debt to consolidated tangible net worth by October 2011. Failure to comply with those covenants could result in accelerated due dates and/or termination of the uncollateralized senior note agreements. As of December 31, 2011, we are in compliance with all of our debt covenants. With the redemption of FPU’s 6.85 percent and 4.90 percent secured first mortgage bonds in January 2010, the additional covenant requiring us to maintain no more than a 20-percent ratio of secured and subsidiary long-term debt to consolidated tangible net worth was met. Each of Chesapeake’s uncollateralized senior notes contains a “Restricted Payments” covenant as defined in the note agreements. The most restrictive covenants of this type are included within the 7.83 percent Unsecured Senior Notes, due January 1, 2015. The covenant provides that we cannot pay or declare any dividends or make any other Restricted Payments (such as dividends) in excess of the sum of $10.0 million, plus our consolidated net income accrued on and after January 1, 2001. As of December 31, 2011, the cumulative consolidated net income base was $156.5 million, offset by Restricted Payments of $89.2 million, leaving $67.3 million of cumulative net income free of restrictions. Each series of FPU’s first mortgage bonds contains a similar restriction that limits the payment of dividends by FPU. The most restrictive covenants of this type are included within the series that is due in 2022, which provides that FPU cannot make dividend or other restricted payments in excess of the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. As of December 31, 2011, FPU’s cumulative net income base was $74.0 million, offset by restricted payments of $37.6 million, leaving $36.4 million of cumulative net income for FPU free of restrictions pursuant to this covenant. The dividend restrictions by FPU’s first mortgage bonds resulted in approximately $57.2 million of the net assets of our consolidated subsidiaries to be restricted at December 31, 2011. This represents approximately 24 percent of our consolidated net assets. Other than the dividend restrictions by FPU’s first mortgage bonds, there are no legal, contractual or regulatory restrictions on the net assets of our consolidated subsidiaries for the purposes of determining the disclosure of parent-only financial statements. |
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The entire disclosure for long-term debt. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Short-Term Borrowings
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Dec. 31, 2011
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Long-Term Debt and Short-Term Borrowings [Abstract] | |||||||||
SHORT-TERM BORROWINGS |
K. SHORT-TERM BORROWING At December 31, 2011 and 2010, we had $34.7 million and $64.0 million, respectively, of short-term borrowings outstanding. The annual weighted average interest rates on our short-term borrowings were 1.57 percent and 1.77 percent for 2011 and 2010, respectively. We incurred commitment fees of $85,000 and $86,000 in 2011 and 2010, respectively. The outstanding short-term borrowings at December 31, 2011 were composed of $30.5 million in borrowings from bank lines of credit and $4.2 million in book overdrafts, which if presented would be funded through the bank lines of credit. The outstanding short-term borrowings at December 31, 2010 included $30.8 million in borrowings from the bank lines of credit, $29.1 million in borrowings from a term loan, which matured in June 2011, and $4.1 million in book overdrafts. As of December 31, 2011, we had four unsecured bank lines of credit with two financial institutions, totaling $100.0 million, none of which requires compensating balances. These bank lines are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. We maintain both committed and uncommitted credit facilities. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. We are currently authorized by our Board of Directors to borrow up to $85.0 million of short-term debt, as required, from these short-term lines of credit. Committed credit facilities As of December 31, 2011, we had two committed revolving credit facilities totaling $60.0 million. The first facility is an unsecured $30.0 million revolving line of credit that bears interest at the respective LIBOR rate, plus 1.25 percent per annum. At December 31, 2011, there was $2.0 million available under this credit facility. The second facility is a $30.0 million committed revolving line of credit that bears interest at a base rate plus 1.25 percent, if requested and advanced on the same day, or LIBOR for the applicable period plus 1.25 percent if requested three days prior to the advance date. At December 31, 2011, there was $27.5 million available under this credit facility.
The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our revolving credit facilities to maintain, at the end of each fiscal year:
We are in compliance with all of our debt covenants. Uncommitted credit facilities As of December 31, 2011, we had two uncommitted line-of-credit facilities totaling $40.0 million. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The first facility is an uncommitted $20.0 million line of credit that bears interest at a rate per annum as offered by the bank for the applicable period. At December 31, 2011, the entire borrowing capacity of $20.0 million was available under this credit facility. The second facility is a $20.0 million uncommitted line of credit that bears interest at a rate per annum as offered by the bank for the applicable period. We have issued $4.9 million in letters of credit under this credit facility. There have been no draws on these letters of credit as of December 31, 2011. 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. At December 31, 2011, there was $15.1 million available under this credit facility, which was reduced by $4.9 million for letters of credit issued. In addition to the four unsecured bank lines of credit, we entered into a new term loan for $29.1 million with an existing lender in March 2010 to temporarily finance the early redemption of the 6.85 percent and 4.90 percent series of FPU’s secured first mortgage bonds. On June 23, 2011, we issued $29.0 million of 5.68 percent Chesapeake unsecured senior notes to repay the new short-term credit facility and permanently finance the FPU first mortgage bonds. |
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The entire disclosure for short-term debt. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Lease Obligations
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Dec. 31, 2011
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Lease Obligations [Abstract] | |
LEASE OBLIGATIONS |
L. LEASE OBLIGATIONS We have entered into several operating lease arrangements for office space, equipment and pipeline facilities. Rent expense related to these leases for 2011, 2010 and 2009 was $1.2 million, $1.1 million and $997,000, respectively. Future minimum payments under our current lease agreements for the years 2012 through 2016 are $1.1 million, $866,000, $860,000, $733,000 and $733,000, respectively; and approximately $2.7 million thereafter, with an aggregate total of approximately $7.0 million. |
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The entire disclosure for lessee entity's leasing arrangements including, but not limited to, all of the following: (a.) The basis on which contingent rental payments are determined, (b.) The existence and terms of renewal or purchase options and escalation clauses, (c.) Restrictions imposed by lease agreements, such as those concerning dividends, additional debt, and further leasing. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Employee Benefit Plans
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Employee Benefit Plans [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
EMPLOYEE BENEFIT PLANS |
M. EMPLOYEE BENEFIT PLANS Retirement Plans We sponsor a defined benefit pension plan (“Chesapeake Pension Plan”), an unfunded pension supplemental executive retirement plan (“Chesapeake SERP”), and an unfunded postretirement health care and life insurance plan (“Chesapeake Postretirement Plan”). As a result of the merger with FPU, we now also sponsor and maintain a separate defined benefit pension plan for FPU (“FPU Pension Plan”) and a separate unfunded postretirement medical plan for FPU (“FPU Medical Plan”). We measure the assets and obligations of the defined benefit pension plans and other postretirement benefits plans to determine the plans’ funded status as of the end of the year as an asset or a liability on our consolidated balance sheets. We record as a component of other comprehensive income/loss or a regulatory asset the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs.
The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive income/loss or as a regulatory asset as of December 31, 2011:
The pre-merger regulatory asset of $5.9 million at December 31, 2011 represents the portion attributable to FPU’s regulated energy operations of the changes in the funded status in the FPU Pension Plan and FPU Medical Plan that occurred but were not recognized, as part of the net periodic benefit costs prior to the merger. This portion was deferred as a regulatory asset prior to the merger by FPU pursuant to a previous order by the Florida PSC and continues to be amortized over the remaining service period of the participants at the time of the merger. During the second half of 2011, we experienced a significant decline in interest and other corporate bond rates, and as a result, we used lower discount rates for our pension and other postretirement plans at December 31, 2011 to estimate the benefit obligations of those plans. We also experienced a decline in plan asset values during 2011, which, in conjunction with the higher benefit obligations, resulted in higher unrecognized costs at December 31, 2011. The total unrecognized cost of our pension and postretirement benefits plans was $23.1 million at December 31, 2011, compared to $13.9 million at December 31, 2010. The amounts in accumulated other comprehensive income/loss and regulatory asset for our pension and postretirement benefits plans that are expected to be recognized as a component of net benefit cost in 2012 are set forth in the following table:
In January 2011, our former Chief Executive Officer retired and received a lump-sum pension distribution of $844,000 and $765,000 from the Chesapeake Pension Plan and Chesapeake SERP, respectively. In connection with these lump-sum payment distributions, we recorded $436,000 in pension settlement losses in addition to the net benefit cost in 2011. Based upon the current funding status of the Chesapeake Pension Plan, which does not meet or exceed 110 percent of the benefit obligation as required per the regulations, our former executive officer was required to deposit property equal to 125 percent of the restricted portion of his lump sum distribution into an escrow. Each year, an amount equal to the value of payments that would have been paid to him if he had elected the life annuity form of distribution will become unrestricted. Property equal to the life annuity amount will be returned to him from the escrow account. These same regulations will apply to the top 20 highest compensated employees taking distributions from the Pension Plan. Defined Benefit Pension Plans The Chesapeake Pension Plan was closed to new participants effective January 1, 1999, and was frozen with respect to additional years of service and additional compensation effective January 1, 2005. Benefits under the Chesapeake Pension Plan were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan.
The FPU Pension Plan covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. Prior to the merger, the FPU Pension Plan was frozen with respect to additional years of service and additional compensation effective December 31, 2009. Our funding policy provides that payments to the trustee of each plan shall be equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2011, 2010 and 2009:
In December 2011, we changed the investments and investment asset allocation of our pension assets to better align them with the investment goals and objectives. This change also resulted in the pension assets of the Chesapeake Pension Plan and FPU Pension Plan being invested in similar investments. The investment policy of both the Chesapeake and FPU Pension Plans is designed to provide the capital assets necessary to meet the financial obligations of the Plans. Investment assets are intended to provide a level of return generating sufficient capital to meet those obligations. The investment goals and objectives are to achieve investment returns that together with contributions will provide funds adequate to pay promised benefits to present and future beneficiaries of the Plans, earn a long-term investment return in excess of the growth of the Plans’ retirement liabilities, minimize pension expense and cumulative contributions resulting from liability measurement and asset performance and maintain a diversified portfolio to reduce the risk of large losses.
The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the plans’ goals and objectives:
Due to periodic contributions and different asset classes producing different returns, the actual asset values may temporarily move outside of the intended ranges. The investments are monitored on a quarterly basis, at a minimum, for asset allocation and performance. At December 31, 2011, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:
At December 31, 2011, all of the investments classified under Level 1 of the fair value measurement hierarchy were recorded at fair value based on unadjusted quoted prices in active markets for identical investments. The Level 2 investments were recorded at fair value based on net asset value per unit of the investments, which used significant observable inputs although those investments were not traded publicly and did not have quoted market prices in active markets. The level 3 investments were guaranteed deposit accounts, which were valued based on liquidation value of those accounts, including the effect of the balance and interest guarantee and liquidation restriction.
Prior to the change in the pension asset investments and investment allocation in December 2011, all of the equity securities held by the Chesapeake Pension Plan were classified under Level 1 of the fair value hierarchy and were recorded at fair value based on unadjusted quoted prices in active markets for identical securities. All of the debt securities and other assets held by the Chesapeake Pension Plan were classified under Level 2 of the fair value hierarchy and were recorded at fair value based on quoted market prices in active markets for similar assets or closing prices reported in active markets for those assets. All of the assets held by the FPU Pension Plan were also classified under Level 2 of the fair value hierarchy and are recorded at fair value based on net asset value per unit of those assets. The following schedule sets forth the funded status at December 31, 2011 and 2010:
Net periodic pension cost (benefit) for the plans for 2011, 2010 and 2009 include the components shown below:
Pension Supplemental Executive Retirement Plan The Chesapeake SERP was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the Chesapeake SERP were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan. The accumulated benefit obligation for the Chesapeake SERP, which is unfunded, was $2.2 million and $2.7 million, at December 31, 2011 and 2010, respectively.
Net periodic pension costs for the Chesapeake SERP for 2011, 2010, and 2009 include the components shown below:
Other Postretirement Benefits Plans The following schedule sets forth the status of other postretirement benefit plans:
Net periodic postretirement benefit costs for 2011, 2010, and 2009 include the following components:
In addition, we recorded $8,000 and $9,000 in expense in 2011 and 2010, respectively, related to continued amortization of FPU’s pre-merger postretirement benefit regulatory asset. Assumptions The assumptions used for the discount rate to calculate the benefit obligations of all the plans were based on the interest rates of high-quality bonds in 2011, reflecting the expected lives of the plans. In determining the average expected return on plan assets for each applicable plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since Chesapeake’s plans and FPU’s plans have different expected plan lives and investment policies, particularly in light of the lump-sum-payment option provided in the Chesapeake Pension Plan, different assumptions regarding discount rate and expected return on plan assets were selected for Chesapeake’s plans and FPU’s plans. Since all of the pension plans are frozen with respect to additional years of service and compensation, the rate of assumed compensation increases is not applicable. The health care inflation rate for 2011 used to calculate the benefit obligation is 6.5 percent for medical and 7.5 percent for prescription drugs for the Chesapeake Postretirement Plan; and 9.5 percent for the FPU Medical Plan. A one–percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated postretirement benefit obligation by approximately $602,000 as of January 1, 2011, and would increase the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2011 by approximately $46,000. A one-percentage point decrease in the health care inflation rate from the assumed rate would decrease the accumulated postretirement benefit obligation by approximately $515,000 as of January 1, 2011, and would decrease the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2011 by approximately $39,000.
Estimated Future Benefit Payments In 2012, we expect to contribute $443,000 and $2.0 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, and $88,000 to the Chesapeake SERP. We also expect to contribute $87,000 and $193,000 to the Chesapeake Postretirement Plan and FPU Medical Plan, respectively, in 2012. The schedule below shows the estimated future benefit payments for each of the plans previously described:
On March 23, 2010, the Patient Protection and Affordable Care Act was signed into law. On March 30, 2010, a companion bill, the Health Care and Education Reconciliation Act of 2010, was also signed into law. Among other things, these new laws, when taken together, reduce the tax benefits available to an employer that receives the Medicare Part D subsidy. The deferred tax effects of the reduced deductibility of the postretirement prescription drug coverage must be recognized in the period these new laws were enacted. The FPU Medical Plan receives the Medicare Part D subsidy. We assessed the deferred tax effects on the reduced deductibility as a result of these new laws and determined that the deferred tax effects were not material to our financial results.
Retirement Savings Plan Effective January 1, 2012, we sponsor one 401(k) retirement savings plan and one non-qualified supplemental employee retirement savings plan. Our 401(k) plan is offered to all eligible employees who have completed three months of service, except for employees represented by a collective bargaining agreement that does not specifically provide for participation in the plan, non-resident aliens with no U.S. source income and individuals classified as consultants, independent contractors or leased employees. Effective January 1, 2011, we match 100 percent of eligible participants’ pre-tax contributions to the Chesapeake 401(k) plan up to a maximum of six percent of the eligible compensation, including pre-tax contributions made by BravePoint employees. In addition, we may make a supplemental contribution to participants in the plan, without regard to whether or not they make pre-tax contributions. Beginning January 1, 2011, the employer matching contribution is made in cash and is invested based on a participant’s investment directions. Any supplemental employer contribution is generally made in Chesapeake stock. With respect to the employer match and supplemental employer contribution, employees are 100 percent vested after two years of service or upon reaching 55 years of age while still employed by Chesapeake. Employees with one year of service are 20 percent vested and will become 100 percent vested after two years of service. Employees who do not make an election to contribute or do not opt out of the Chesapeake 401(k) plan will be automatically enrolled at a deferral rate of three percent and the automatic deferral rate will increase by one percent per year up to a maximum of six percent. Effective January 1, 1999, we began offering a non-qualified supplemental employee retirement savings plan (“401(k) SERP”) to our executive officers over a specific income threshold. Participants receive a cash-only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds can be invested among the mutual funds available for investment. These same funds are available for investment of employee contributions within Chesapeake’s 401(k) plan. All obligations arising under the 401(k) SERP are payable from our general assets, although we have established a Rabbi Trust for the 401(k) SERP. Assets held in the Rabbi Trust for the 401(k) SERP had a fair value of $1.7 million and $2.4 million at December 31, 2011 and 2010, respectively. (See Note G, “Investments,” to the Consolidated Financial Statements for further details). The assets of the Rabbi Trust are at all times subject to the claims of our general creditors. Prior to January 1, 2012, we sponsored two separate 401(k) retirement savings plans, one for FPU employees and the second one covering all other Chesapeake employees. From January 1, 2011 to December 31, 2011, benefits offered under the two separate 401(k) retirement savings plans were substantially the same. Those benefits were also similar to the benefits offered under the one combined 401(k) retirement savings plan effective January 1, 2012. Prior to January 1, 2011, FPU’s 401(k) plan provided a matching contribution of 50 percent of an employee’s pre-tax contributions, up to six percent of the employee’s salary, for a maximum company contribution of up to three percent. For non-union employees the plan provided a company match of 100 percent for the first two percent of an employee’s contribution, and a match of 50 percent for the next four percent of an employee’s contribution, for a total company match of up to four percent. Employees were automatically enrolled at the three percent contribution, with the option of opting out, and were eligible for the company match after six months of continuous service, with vesting of 100 percent after three years of continuous service. Prior to January 1, 2011, we made matching contributions up to six percent of employee’s eligible pre-tax compensation for Chesapeake legacy businesses, except for BravePoint, as further explained below. The match was between 100 percent and 200 percent of the employee’s contribution (up to six percent of eligible compensation), based on the employee’s age and years of service. The first 100 percent was matched with Chesapeake common stock; the remaining match was invested in Chesapeake’s 401(k) Plan according to each employee’s investment direction. Employees were automatically enrolled at a two-percent contribution, with the option of opting out, and were eligible for the company match after three months of continuing service, with vesting of 20 percent per year.
From July 1, 2006 to December 31, 2010, our contribution made on behalf of BravePoint employees was a 50 percent matching contribution, for up to six percent of each employee’s annual compensation contributed to the plan. The matching contribution was funded in Chesapeake common stock. The plan was also amended at the same time to enable it to receive discretionary profit-sharing contributions in the form of employee pre-tax deferrals. The extent to which BravePoint had funds available for profit-sharing was dependent upon the extent to which the segment’s actual earnings exceeded budgeted earnings. Any profit-sharing dollars made available to employees could be deferred into the plan and/or paid out in the form of a bonus. Contributions to all of our 401(k) plans totaled $2.0 million for the year ended December 31, 2011, $1.7 million for the year ended December 31, 2010, and $1.6 million for the year ended December 31, 2009. As of December 31, 2011, there are 580,484 shares reserved to fund future contributions to the 401(k) plans. Deferred Compensation Plan On December 7, 2006, the Board of Directors approved the Chesapeake Utilities Corporation Deferred Compensation Plan (“Deferred Compensation Plan”), as amended, effective January 1, 2007. The Deferred Compensation Plan is a non-qualified, deferred compensation arrangement under which certain executives and members of the Board of Directors are able to defer payment of all or a part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors’ retainers and fees. At December 31, 2011, the Deferred Compensation Plan consisted solely of shares of common stock related to the deferral of executive performance shares and directors’ stock retainers. Participants in the Deferred Compensation Plan are able to elect the payment of benefits to begin on a specified future date after the election is made in the form of a lump sum or annual installments. Deferrals of executive cash bonuses and directors’ cash retainers and fees are paid in cash. All deferrals of executive performance shares and directors’ stock retainers are paid in shares of our common stock, except that cash is paid in lieu of fractional shares. We established a Rabbi Trust in connection with the Deferred Compensation Plan. The value of our stock held in the Rabbi Trust is classified within the stockholders’ equity section of the Balance Sheet and has been accounted for in a manner similar to treasury stock. The amounts recorded under the Deferred Compensation Plan totaled $817,000 and $777,000 at December 31, 2011 and 2010, respectively.
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The entire disclosure for pension and other postretirement benefits. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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SHARE-BASED COMPENSATION PLANS |
N. SHARE-BASED COMPENSATION PLANS Our non-employee directors and key employees are awarded share-based awards through our Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), respectively. 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 on the fair value of the grant on the date it was granted. The table below presents the amounts included in net income related to share-based compensation expense, for the restricted stock awards issued under the DSCP and the PIP for the years ended December 31, 2011, 2010 and 2009:
Stock Options We did not have any stock options outstanding at December 31, 2011 or 2010, nor were any stock options issued during 2011, 2010 and 2009. Directors Stock Compensation Plan Under the DSCP, each of our non-employee directors received in May 2011 an annual retainer of 900 shares of common stock. Shares granted under the DSCP are issued in advance of the directors’ service period; therefore, these shares are fully vested as of the grant date. We record a prepaid expense as of the date of the grant equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. A summary of stock activity under the DSCP is presented below:
We recorded compensation expense of $407,000, $283,000 and $191,000 related to DSCP awards for the years ended December 31, 2011, 2010 and 2009, respectively. The weighted average grant-date fair value of DSCP awards granted during 2011 and 2010 was $41.02 and $29.99, per share, respectively. The intrinsic values of the DSCP awards are equal to the fair value of these awards on the date of grant. At December 31, 2011, there was $148,000 of unrecognized compensation expense related to DSCP awards that is expected to be recognized over the first four months of 2012.
As of December 31, 2011, there were 23,111 shares reserved for issuance under the DSCP. Performance Incentive Plan Our Compensation Committee is authorized to grant key employees of the Company the right to receive awards of shares of our common stock, contingent upon the achievement of established performance goals. These awards are subject to certain post-vesting transfer restrictions. In 2007, the Board of Directors granted each executive officer equity incentive awards, which entitled each to earn shares of common stock to the extent that we achieved pre-established performance goals at the end of a one-year performance period. In 2008, we adopted multi-year performance plans to be used in lieu of the one-year awards. Similar to the one-year plans, the multi-year plans provide incentives based upon the successful achievement of long-term goals, growth and financial results, and they are comprised of both market-based and performance-based conditions or targets. The multi-year shares granted under the PIP in 2008 vested in 2011, and the fair value of each share is equal to the market price of our common stock on the date of the grant. The shares granted under the 2009, 2010 and 2011 long-term plans have not vested as of December 31, 2011, and the fair value of each performance-based condition or target is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted. In conjunction with his retirement, our former Chief Executive Officer forfeited 24,000 shares, which represents the shares awarded under the PIP in January 2009 for the performance period ending December 31, 2011 and in January 2010 for the performance period ending December 31, 2012, that had not vested. A summary of stock activity under the PIP is presented below:
In 2011 and 2010 (in 2009, no shares under the PIP vested), we withheld shares with value at least equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes, and remitted the cash to the appropriate taxing authorities with the executives receiving the net shares. The total number of shares withheld of 12,324 and 17,695 for 2011 and 2010, respectively, was based on the value of the PIP shares on their vesting date, determined by the average of the high and low of our stock price. No payments for the employee’s tax obligations were made to taxing authorities in 2009 as no shares vested during this period. Total payments for the employees’ tax obligations to the taxing authorities were approximately $496,000 and $538,000 in 2011 and 2010, respectively. We recorded compensation expense of $1.0 million, $872,000 and $1.1 million related to the PIP for the years ended December 31, 2011, 2010, and 2009, respectively.
The weighted average grant-date fair value of PIP awards granted during 2011, 2010 and 2009 was $40.16, $29.38 and $29.19, per share, respectively. The intrinsic value of the PIP awards was $1.9 million, $2.7 million and $2.1 million for 2011, 2010 and 2009, respectively. As of December 31, 2011, there were 325,952 shares reserved for issuance under the PIP. |
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The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Rates and Other Regulatory Activities
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Rates and Other Regulatory Activities [Abstract] | |
RATES AND OTHER REGULATORY ACTIVITIES |
O. RATES AND OTHER REGULATORY ACTIVITIES Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSCs; 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 operations continue to be subject to regulation by the Florida PSC as separate entities. Delaware Capacity Release: On September 2, 2008, our Delaware division filed with the Delaware PSC its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, which included the Delaware PSC, our Delaware division and the Division of the Public Advocate. As part of the settlement agreement, the parties agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, PESCO. On January 8, 2010, the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which he recommended, among other things, that the Delaware PSC require the Delaware division to refund to its firm service customers the difference between what the Delaware division would have received had the capacity released to PESCO been priced at the maximum tariff rates under asymmetrical pricing principles and the amount actually received by the Delaware division for capacity released to PESCO. The Hearing Examiner also recommended that the Delaware PSC require us to adhere to asymmetrical pricing principles in all future capacity releases by the Delaware division to PESCO, if any. If the Hearing Examiner’s refund recommendation for past capacity releases had ultimately been approved without modification by the Delaware PSC, the Delaware division would have had to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division paid for long-term capacity, which we estimated to be approximately $700,000, even though the temporary releases were made at lower rates based on competitive bidding procedures required by the FERC’s capacity release rules. On February 18, 2010, we filed exceptions to the Hearing Examiner’s recommendations. At the hearing on March 30, 2010, the Delaware PSC agreed with us that the Delaware division had been releasing capacity based on a previous settlement approved by the Delaware PSC and, therefore, did not require the Delaware division to issue any refunds for past capacity releases. The Delaware PSC, however, required the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO until a more appropriate pricing methodology is developed and approved. The Delaware PSC issued an order on May 18, 2010, elaborating its decisions at the March hearing and directing the parties to reconvene in a separate docket to determine if a pricing methodology other than asymmetrical pricing principles should apply to future capacity releases by the Delaware division to PESCO. On June 17, 2010, the Division of the Public Advocate filed an appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to refunds for past capacity releases. On June 28, 2010, the Delaware division filed a Notice of Cross Appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to requiring the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO. On June 13, 2011, the Delaware Superior Court issued its decision affirming all aspects of the Delaware PSC’s Order on May 18, 2010, which included its decision not to require the Delaware division to issue any refunds for past releases.
On June 29, 2011, the Delaware Attorney General filed an appeal with the Delaware Supreme Court, asking it to review the Delaware Superior Court’s decision affirming the Delaware PSC decision with regard to refunds for past capacity releases. On July 12, 2011, the Delaware division filed a Notice of Cross Appeal with the Delaware Supreme Court, asking it to overturn the Superior Court’s decision with regard to the Delaware PSC’s decision on future capacity releases to PESCO. On August 3, 2011, the Delaware Attorney General filed a Notice of Dismissal with the Supreme Court withdrawing its appeal. Consequently, on August 4, 2011, the Delaware division filed a Notice of Dismissal with the Supreme Court to withdrawal its cross appeal and the filing of the Notice of Dismissal eliminates any potential liability related to potential refunds for past capacity releases and the matter is officially closed. The parties have not yet opened a separate docket to determine an alternative pricing methodology for future capacity releases by the Delaware division to PESCO or any other affiliates. Our Delaware division also had developments in the following matters with the Delaware PSC: On September 1, 2010, the Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2010. On September 21, 2010, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2010, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware PSC granted approval of the GSR charges at its regularly scheduled meeting on June 7, 2011. On March 10, 2011, the Delaware division filed with the Delaware PSC an application requesting approval to guarantee certain debt of FPU. Specifically, the Delaware division sought approval to execute a Seventeenth Supplemental Indenture, in which Chesapeake guarantees the payment of certain debt of FPU and FPU is permitted to deliver Chesapeake’s consolidated financial statements in lieu of FPU’s stand-alone financial statements to satisfy certain covenants within the indentures of FPU’s debt. The Delaware PSC granted approval of the guarantee of certain debt of FPU at its regularly scheduled meeting on April 4, 2011. On September 1, 2011, the Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2011. On September 20, 2011, the Delaware PSC authorized the Delaware division to implement the GSR charges, as filed, on November 1, 2011, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. We anticipate that the Delaware PSC will render a final decision on the GSR charges in the second or third quarter of 2012. On September 19, 2011, the Delaware division filed with the Delaware PSC two applications seeking approval to begin charging customers for the franchise fees imposed upon the Delaware division by the City of Lewes, Delaware and the Town of Dagsboro, Delaware. On October 3, 2011, the Delaware PSC issued orders on both matters, effectively opening the proceedings and setting evidentiary hearings for November 8, 2011. The Delaware PSC granted approval for the franchise fees at its regularly scheduled meeting on November 8, 2011.
Maryland On December 14, 2010, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Maryland division during the 12 months ended September 30, 2010. No issues were raised at the hearing, and on December 20, 2010, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. This proposed Order became a final Order of the Maryland PSC on January 20, 2011. On March 2, 2011, the Maryland division filed with the Maryland PSC an application for the approval of a franchise executed between the Maryland division and the Board of County Commissioners of Cecil County, Maryland. In this franchise agreement, the County granted the Maryland division a 50-year, non-exclusive franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Cecil County. On April 11, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Cecil County, subject to no adverse comments being received within 30 days after the issuance of the Order. On May 10, 2011, comments opposing the application were filed by Pivotal Utility Holdings, Inc. d/b/a Elkton Gas (“Pivotal”). Pivotal also provides natural gas service to customers in a portion of Cecil County. On June 8, 2011, the Maryland PSC granted the Maryland division the authority to exercise its franchise in a majority of the area requested in the Maryland division’s application. The approval for a small portion of the area within the requested franchise area, which is closest to the area served by Pivotal, was withheld until an evidentiary hearing could be convened. On August 16, 2011, the Maryland division submitted testimony in support of its proposed boundary with Pivotal. On September 29, 2011, the parties in the proceeding (Maryland division, Pivotal, Maryland PSC Staff, and the Office of People’s Counsel) submitted a proposed settlement agreement for the Maryland PSC’s consideration that outlined an agreed upon boundary between the Maryland division and Pivotal in the small portion of Cecil County that was subject to further review. On October 12, 2011, the assigned Public Utility Law Judge in this matter issued a Proposed Order, approving the proposed settlement agreement as submitted by the parties in the proceeding. The Proposed Order became a final order of the Maryland PSC on November 15, 2011. On May 17, 2011, the Maryland division filed with the Maryland PSC an application for approval of a franchise executed between the Maryland division and the Board of County Commissioners for Worcester County, Maryland. In this franchise agreement, the County granted the Maryland division a 25-year, non-exclusive franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Worcester County. On June 14, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Worcester County, subject to no adverse comments being received within 20 days after the issuance of the Order. No adverse comments were filed within the comment period, and the order became effective on July 5, 2011. On August 12, 2011, the Maryland division submitted a request to the Maryland PSC for approval of a negotiated delivery service rate for a large customer on its system. At its regularly scheduled meeting on September 21, 2011, the Maryland PSC granted approval of the negotiated delivery service rate effective for bills rendered after that date. On December 12, 2011, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Maryland division during the 12 months ended September 30, 2011. No issues were raised at the hearing, and on December 13, 2011, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. This proposed Order became a final Order of the Maryland PSC on December 29, 2011.
Florida “Come-Back” Filing: As part of our 2010 rate case settlement in Florida, the Florida PSC required us to submit a “Come-Back” filing, detailing all known benefits, synergies, cost savings and cost increases resulting from the merger with FPU. We submitted this filing on April 29, 2011, and requested the recovery, through rates, of approximately $34.2 million in acquisition adjustment (the price paid in excess of the book value) and $2.2 million in merger-related costs. In the past, the Florida PSC has allowed recovery of an acquisition adjustment under certain circumstances to provide an incentive for larger utilities to purchase smaller utilities. The Florida PSC requires a company seeking recovery of the acquisition adjustment and merger-related costs to demonstrate that customers will benefit from the acquisition. They use the following five factor test to determine if the customers are benefiting from the transaction: (a) increased quality of service; (b) lower operating costs; (c) increased ability to attract capital for improvements; (d) lower overall cost of capital; and (e) more professional and experienced managerial, financial, technical and operational resources. With respect to lower costs, the Florida PSC effectively requires that the synergies be sufficient to offset the rate impact of the recovery of the acquisition adjustment and merger-related costs. At the December 6, 2011 agenda conference, the Florida PSC approved the following: (a) FPU and the Florida division of Chesapeake have complied with the reporting requirements in the 2010 rate case settlement; (b) FPU is authorized to reflect an acquisition adjustment of $34.2 million, to be amortized over a 30-year period using the straight-line method beginning in November 2009; (c) FPU is authorized to reflect a regulatory asset of $2.2 million for the merger-related costs, to be amortized over a five-year period using the straight-line method beginning in November 2009; (d) FPU and the Florida division of Chesapeake are not permitted to consolidate the earnings surveillance reporting and accounting records until such time as the rates and tariffs are combined; (e) FPU and the Florida division of Chesapeake are not permitted to establish a combined benchmark for the purpose of evaluating incremental cost increases in their future rate proceedings until those entities are functioning as a single utility for regulatory purposes; and (f) FPU and the Florida division of Chesapeake do not have any 2010 excess earnings to be refunded to customers. The Florida PSC Order allows us to classify the acquisition adjustment and merger-related costs as regulatory assets and include them in our investment, or rate base, when determining our Florida natural gas rates. Additionally, our rate of return calculation will be based upon this higher level of investment, which effectively enables us to earn a return on this investment. Pursuant to the Order, we reclassified to a regulatory asset at December 31, 2011, $31.7 million of the $34.2 million goodwill, which represents the portion of the goodwill allowed to be recovered in future rates after the effective date of the Florida PSC Order. We also recorded as a regulatory asset $18.1 million related to the gross-up of the acquisition adjustment for income tax. The $1.3 million of the $2.2 million of merger-related costs, which represent the portion of the merger-related costs allowed to be recovered in future rates after the effective date of the Florida PSC Order, had previously been deferred as a regulatory asset. We also recorded as a regulatory asset $349,000 related to the gross-up of the merger-related costs for income tax. As a result of this Order, we will record $2.4 million ($1.4 million, net of tax) in amortization expense related to these assets in 2012 and 2013, $2.3 million ($1.4 million, net of tax) in 2014 and $1.8 million ($1.1 million, net of tax) annually, thereafter until 2039. These amortization expenses will be a non-cash charge, and the net effect of the recovery will be positive cash flow. Over the long-term, however, the inclusion of the acquisition adjustment and merger-related costs in our rate base and the recovery of these regulatory assets through amortization expense will increase our earnings and cash flows above what we would have otherwise been able to achieve. In FPU’s future rate proceedings, if it is determined that the level of cost savings supporting the lower operating costs in its request for the recovery of the acquisition adjustment no longer exists, the remaining acquisition adjustment may be partially or entirely disallowed by the Florida PSC. In such event, we will have to expense the corresponding amount of the disallowed acquisition adjustment. The Florida PSC Order also resulted in the reversal in December 2011, of the $750,000 regulatory accrual, which was recorded in 2010 based on management’s assessment of FPU’s earnings and regulatory risk to its earnings associated with possible Florida PSC action related to our requested recovery and the matters set forth in this “Come-Back” filing. The reversal of the $750,000 regulatory accrual was reflected in operating revenue in 2011 in the accompanying consolidated statements of income.
Peninsula Pipeline: On September 19, 2011, Peninsula Pipeline filed a petition seeking the Florida PSC’s approval of a Firm Transportation Agreement (“FTA”) between Peninsula Pipeline and FPU, an affiliated company, in accordance with its tariff. On February 8, 2012 Peninsula Pipeline filed a petition with the Florida PSC seeking approval of an amended and revised FTA between Peninsula Pipeline and FPU. This amended and revised FTA provides for upstream interconnection of Peninsula Pipeline’s facilities with the Peoples Gas’ distribution facilities at the Duval/Nassau County line and several downstream interconnections with FPU’s facilities. This amended and revised FTA replaces, in its entirety, the agreement originally filed on September 19, 2011. The revised and amended FTA comes as a result of negotiations between Peoples Gas, FPU, and Peninsula Pipeline, which resulted in a territorial agreement and related service arrangements described below. In January 2012, Peninsula Pipeline executed an agreement with Peoples Gas for the joint construction, ownership and operation of an approximately 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida. Under the terms of the agreement, Peninsula Pipeline will own approximately 45 percent of this 16-mile pipeline. Peninsula Pipeline’s portion of the estimated project cost is $5.7 million. Peoples Gas will operate the pipeline and Peninsula Pipeline will be responsible for its portion of the operation and maintenance expenses of the pipeline based on its ownership percentage. Peninsula Pipeline will contract with Peoples Gas for capacity from the unaffiliated upstream interstate pipeline to this jointly-owned pipeline. Peninsula Pipeline will utilize both the capacity contracted with Peoples Gas and the capacity on the new jointly-owned pipeline to provide transportation service to FPU for its natural gas distribution service in Nassau County. The new jointly-owned pipeline is expected to be completed and placed into service in the second half of 2012. Marianna Franchise: On July 7, 2009, the Marianna Commission adopted an ordinance granting a franchise to FPU effective February 1, 2010 for a period not to exceed 10 years for the operation and distribution and/or sale of electric energy (the “Franchise Agreement”). The Franchise Agreement provides that FPU will develop and implement new TOU and interruptible electric power rates, or other similar rates, mutually agreeable to FPU and the City of Marianna. The Franchise Agreement further provides for the TOU and interruptible rates to be effective no later than February 17, 2011, and available to all customers within FPU’s Northwest Division, which includes the City of Marianna. If the rates were not in effect by February 17, 2011, the City of Marianna would have the right to give notice to FPU within 180 days thereafter of its intent to exercise an option in the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City of Marianna for the approval of the purchase and the operation by the City of Marianna of an electric distribution facility. If the purchase is approved by the Marianna Commission and by the referendum, the closing of the purchase must occur within 12 months after the referendum is approved. If the City of Marianna elects to purchase the Marianna property, the Franchise Agreement requires the City of Marianna to pay FPU the fair market value for such property as determined by three qualified appraisers. Future financial results would be negatively affected by the loss of earnings generated by FPU from its approximately 3,000 customers in the City under the Franchise Agreement. In accordance with the terms of the Franchise Agreement, FPU developed TOU and interruptible rates and on December 14, 2010, FPU filed a petition with the Florida PSC for authority to implement such proposed TOU and interruptible rates on or before February 17, 2011. On February 11, 2011, the Florida PSC issued an Order approving FPU’s petition for authority to implement the proposed TOU and interruptible rates, which became effective on February 8, 2011. The City of Marianna objected to the proposed rates and filed a petition protesting the entry of the Florida PSC’s Order. On January 24, 2012, the Florida PSC dismissed with prejudice the protest by the City of Marianna. On January 26, 2011, FPU filed a petition with the Florida PSC for approval of an amendment to FPU’s Generation Services Agreement entered into between FPU and Gulf Power. The amendment provides for a reduction in the capacity demand quantity, which generates the savings necessary to support the TOU and interruptible rates approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019. Pursuant to its Order dated June 21, 2011, the Florida PSC approved the amendment. On July 12, 2011, the City of Marianna filed a protest of this decision and requested a hearing on the amendment. On January 24, 2012, the Florida PSC dismissed with prejudice the protest by the City of Marianna. On April 7, 2011, FPU filed a petition for approval of a mid-course reduction to its Northwest Division fuel rates based on two factors: (1) the previously discussed amendment to the Generation Services Agreement with Gulf Power, and (2) a weather-related increase in sales resulting in an accelerated collection of the prior year’s under-recovered costs. Pursuant to its Order dated July 5, 2011, the Florida PSC approved the petition, which reduced the fuel rates of FPU’s northwest division.
On February 24, 2012, FPU filed a revised petition for approval of a mid-course reduction to its Northwest Division fuel rates based on a mid-course reduction to its supplier’s fuel rates. FPU expects to significantly lower purchased power costs for its Northwest Division in 2012 as a result of this reduction by the supplier. In order to ensure that its customers receive these significant savings in the most timely manner, FPU filed this petition. We anticipate Florida PSC’s decision on this petition in April 2012. As disclosed in Note Q, “Other Commitments and Contingencies,” to the Consolidated Financial Statements, the City of Marianna, on March 2, 2011, filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging breaches of the Franchise Agreement by FPU and seeking a declaratory judgment that the City of Marianna has the right to exercise its option to purchase FPU’s property in the City of Marianna in accordance with the terms of the Franchise Agreement. On March 28, 2011, FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the material allegation by the City of Marianna and asserted affirmative defenses. The litigation remains pending and discovery is still underway. We also had developments in the following regulatory matters in Florida: On June 21, 2011, FPU, in accordance with the Florida PSC rules, filed its 2011 depreciation study and request for new depreciation rates effective January 1, 2012 for its electric distribution operation. The Florida PSC approved the depreciation study at its January 24, 2012 Agenda Conference. The new approved depreciation rates are expected to reduce annual depreciation expense by approximately $227,000. On February 3, 2012, FPU’s natural gas distribution operation and the Florida Division of Chesapeake filed a petition with the Florida PSC for approval of a surcharge to customers for a Gas Reliability Infrastructure Program. We are seeking approval to recover costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic (Polyethylene)) in their respective systems. If the petition is approved, we will replace qualifying mains and services over a 10-year period. Eastern Shore The following are regulatory activities involving the FERC Orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system: Energylink Expansion Project: In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural Gas terminal in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would interconnect with Eastern Shore’s existing facilities in Sussex County, Delaware. In April 2009, Eastern Shore terminated this project based on increased construction costs over its original projection. As approved by the FERC, Eastern Shore initiated billing to recover approximately $3.2 million of costs incurred in connection with this project and the related cost of capital over a period of 20 years in accordance with the terms of the precedent agreements executed with the two participating customers. One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions. During 2010, Eastern Shore and the participating customers negotiated to reduce the recovery period of this cost from 20 years to five years. On January 27, 2011, Eastern Shore filed with the FERC the request to amend the cost recovery period, which was approved by the FERC on February 14, 2011. Eastern Shore revised its billing to reflect the five-year surcharge, effective March 1, 2011.
Rate Case Filing: On December 30, 2010, Eastern Shore filed with the FERC a base rate proceeding in accordance with the terms of the settlement in its prior base rate proceeding. The rate filing reflected increases in operating and maintenance expenses, depreciation expense, and a return on existing and new gas plant facilities expected to be placed into service before June 30, 2011. The FERC issued a notice of the filing on January 3, 2011. Protests were received from several interested parties, and other parties intervened in the proceeding. On January 31, 2011, the FERC issued its Order accepting the filing and suspending its effectiveness for the full five-month period permitted under the Natural Gas Act. The discovery process commenced on February 22, 2011, and the FERC Staff performed an on-site audit on March 16-17, 2011. Subsequent to the on-site audit, settlement conferences involving Eastern Shore, the FERC Staff and other interested parties resulted in a settlement, which provides a cost of service of approximately $29.1 million and a pre-tax return of 13.9 percent. Also included in the settlement is a negotiated rate adjustment, effective November 1, 2011, associated with the phase-in of an additional 15,000 Dts/d of new transportation service on Eastern Shore’s eight-mile extension to interconnect with TETLP’s pipeline system. This rate adjustment reduces the rate per Dt of the service on this eight-mile extension by reflecting the increased service of 15,000 Dts/d with no additional revenue. This rate adjustment effectively offsets the increased revenue that would have been generated from the 15,000 Dts/d increase in firm service although Eastern Shore may still benefit from the increased commodity charge on the increased volume from the phase-in of service. The settlement also provides a five-year moratorium on the parties’ rights to challenge Eastern Shore’s rates and on Eastern Shore’s right to file a base rate increase. The settlement allows Eastern Shore to file for rate adjustments during those five years in the event certain costs related to government-mandated obligations are incurred and Eastern Shore’s pre-tax earnings do not equal or exceed 13.9 percent. The FERC approved the settlement on January 24, 2011. From July 2011 through October 2011, Eastern Shore adjusted its billing to reflect the rates requested in the base rate proceeding, subject to refund to customers upon the FERC’s approval of the new rates. From November 2011, Eastern Shore adjusted its billing to reflect the settlement rates, subject to refund to customers upon FERC’s approval of the settlement. As of December 31, 2011, Eastern Shore has recorded approximately $1.3 million as a regulatory liability related to the refund due to customers as a result of the settlement, which refund was paid in January and February 2012. Mainline Extension Project: On April 1, 2011, Eastern Shore filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 3,405 Dts/d of natural gas to an existing industrial customer. The FERC published notice of this filing on April 7, 2011. The 60-day comment period subsequent to the FERC notice expired on June 6, 2011, and the requested authorization became effective on that date. On April 28, 2011, Eastern Shore filed a notice of intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 6,250 Dts/d of natural gas to Chesapeake’s Delaware and Maryland divisions and Eastern Shore Gas, an unaffiliated provider of piped propane service in Maryland. The FERC published notice of this filing on May 12, 2011, and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective. Also on April 28, 2011, Eastern Shore filed a notice of intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 4,070 Dts/d of natural gas to Chesapeake’s Maryland division to provide new natural gas service in Cecil County, Maryland. The FERC published notice of this filing on May 12, 2011, and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective. Eastern Shore also had developments in the following FERC matters: On March 7, 2011, Eastern Shore filed certain tariff sheets to amend the creditworthiness provisions contained in its FERC Gas Tariff. On April 6, 2011, the FERC issued an Order accepting and suspending Eastern Shore’s filed tariff revisions for an effective date of April 1, 2011, subject to Eastern Shore submitting certain clarifications with regard to several proposed revisions. On April 18, 2011, Eastern Shore submitted its annual Interruptible Revenue Sharing Report to the FERC. Eastern Shore reported in this filing that its interruptible revenue did not exceed its annual threshold amount, which would trigger sharing of excess interruptible revenues with its firm service customers. Consequently, Eastern Shore is not required to refund to its firm customers any portion of its interruptible revenue received for the period April 2010 through March 2011.
On June 24, 2011, Eastern Shore filed certain tariff sheets to amend the General Terms and Conditions and the pro forma FTA contained in its FERC Gas Tariff to allow for specification of minimum delivery pressures and maximum hourly quantity. The FERC published the notice of this filing on June 27, 2011, and no protests or adverse comments opposing this filing were submitted. On July 15, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective July 24, 2011. On August 15, 2011, Eastern Shore filed certain tariff sheets to update certain Delivery Point Area definitions contained in its FERC Gas Tariff. The FERC published notice of this filing on August 16, 2011, and no protests or adverse comments opposing this filing were submitted. On September 13, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective September 14, 2011. On September 7, 2011, Eastern Shore filed certain tariff sheets to reflect a decrease in the Annual Charge Adjustment, which is a surcharge designed to recover applicable program costs incurred by the FERC to discharge its jurisdictional responsibilities. The surcharge decreased from $0.0019 per Dt to $0.0018 per Dt. The FERC published the notice of this filing on September 8, 2011, and no protests or adverse comments opposing this filing were submitted. On September 27, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective October 1, 2011. |
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The entire disclosure for public utilities. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES |
P. 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 remedy 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, and have exposures at six former MGP sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding a seventh former MGP site located in Cambridge, Maryland. As of December 31, 2011, we had approximately $11.0 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates. Approximately $8.3 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of December 31, 2011. We also had approximately $5.7 million in regulatory assets for future recovery of environmental costs from FPU’s customers. In addition to the FPU MGP sites, we had $254,000 in environmental liabilities at December 31, 2011, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of December 31, 2011, we had approximately $991,000 in regulatory and other assets for future recovery through Chesapeake’s rates. We continue to expect that all costs related to environmental remediation and related activities will be recoverable from customers through rates.
The following discussion provides details on MGP sites: West Palm Beach, Florida Remedial options are being evaluated 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 an MGP. Pursuant to a Consent Order between FPU and the FDEP, effective April 8, 1991, FPU is required to complete the delineation of soil and groundwater impacts at the site and implement an effective remedy. On June 30, 2008, FPU transmitted to the FDEP a revised feasibility study, evaluating appropriate remedies for the site. This revised feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. On April 30, 2009, the FDEP issued a remedial action order, which it subsequently withdrew. In response to the Order and as a condition to its withdrawal, FPU committed to perform additional field work in 2009 and complete an additional engineering evaluation of certain remedial alternatives. The scope of this work has increased in response to FDEP’s requests for additional information. FPU performed additional fieldwork in August 2010, which included the installation of additional groundwater monitoring wells and performance of a comprehensive groundwater sampling event. FPU also performed vapor intrusion sampling in October 2010. The results of the fieldwork were submitted to FDEP for their review and comment in October 2010. On November 4, 2010, FDEP issued its comments on the feasibility study and the proposed remedy. On November 16, 2010, FPU presented to FDEP a new remedial action plan for the site, and FDEP agreed with FPU’s proposal to implement a phased approach to remediation. On December 22, 2010, FPU submitted to FDEP an interim RAP to remediate the east parcel of the site, which FDEP conditionally approved on February 4, 2011. Subsequent modifications to the interim RAP, dated March 12, 2011 and April 18, 2011, were submitted to address potential concerns raised by FDEP. An Approval Order for the interim RAP was issued by FDEP on May 2, 2011, and subsequently modified by FDEP on May 18, 2011. FPU is currently implementing the interim RAP for the east parcel of the West Palm Beach site, including the incorporation of FDEP’s conditions for approval. The operations on the east parcel have been relocated, and the structures removed. New monitoring wells and Bio Sparging and Soil-Vapor Extraction (“BS/SVE”) test wells were installed on the east parcel in May 2011. The initial round of SVE and sparging pilot testing was conducted in June 2011, and a subsequent round of testing was conducted in July of 2011. A supplement to the interim RAP was prepared to present the findings of the pilot testing and the proposed design details for a full-scale remediation system, and was submitted to FDEP on October 31, 2011. On December 22, 2011, FDEP issued conditional approval for full-scale implementation of BS/SVE on the east parcel. Estimated costs of remediation for the West Palm Beach site range from approximately $4.7 million to $15.8 million. We have revised our estimated maximum cost of $13.1 million to $15.8 million to include costs associated with the relocation of FPU’s operations at this site, which may be necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties. We continue to expect that all costs related to these activities will be recoverable from customers through rates.
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. In late September 2006, the EPA sent a Special Notice Letter, notifying FPU, and the other responsible parties at the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light Company, and the city of Sanford, Florida, collectively with FPU, “the Sanford Group”), of EPA’s selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments) for the site. The EPA projected the total estimated remediation costs for this site to be approximately $12.9 million. In January 2007, FPU and other members of the Sanford Group signed a Third Participation Agreement, which provides for funding the final remedy approved by 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 million, or $650,000. As of December 31, 2011, FPU has paid $650,000 to the Sanford Group escrow account for its share of the funding requirements. The Sanford Group, EPA and the U.S. Department of Justice agreed to a Consent Decree in March 2008, which was entered by the Federal Court in Orlando, Florida on January 15, 2009. The Consent Decree obligates the Sanford Group to implement the remedy approved by EPA for the site. The total cost of the final remedy is now estimated at approximately $18 million. 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. Several members of the Sanford Group have concluded negotiations with two adjacent property owners to resolve damages that the property owners allege they have 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. As of December 31, 2011, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is 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 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 December 31, 2011. Key West, Florida FPU formerly owned and operated an 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 September 2010, FDEP issued a Preliminary Contamination Assessment Report, for additional soil and groundwater investigation work that was undertaken by FDEP in November 2009 and January 2010, after 17 years of regulatory inactivity. Because FDEP observed that some soil and groundwater standards were exceeded, FDEP is requesting implementation of additional fieldwork, which FDEP believes is warranted for the site. FPU and the current site owner have had several discussions regarding the approach to be taken with FDEP and the proposed scope of work. Representatives of FPU, FDEP and the current site owner participated in a teleconference on July 7, 2011. During that call, the scope of work was tentatively agreed upon, and FDEP agreed to proceed without using a Consent Order. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. FPU and the current site owner, Suburban Propane, submitted a work plan and schedule to FDEP on September 30, 2011. FDEP conditionally approved the work plan in a letter dated October 19, 2011, and further clarified the conditions of approval in an e-mail dated October 24, 2011. The two new monitoring wells were installed in November of 2011, and groundwater monitoring was begun in December 2011.
FPU and Suburban Propane have entered into a cost-sharing agreement, whereby Suburban Propane has agreed to contribute $15,000 to complete the agreed-upon scope of work. FPU’s estimated share of the cost to complete the work is $21,000. Prior to completion of the monitoring program, we cannot determine to a reasonable degree of certainty the probable costs to resolve FPU’s liability for the Key West MGP Site, although we do not anticipate the cost to exceed $100,000. Pensacola, Florida FPU formerly owned and operated an 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 Florida Department of Transportation (“FDOT”). In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action (“NFA”) determination for the site, which must include a requirement for institutional and engineering controls. On December 13, 2011, Gulf Power, City of Pensacola, FDOT and FPU submitted a draft covenant for institutional and engineering controls for the site to the FDEP. Upon FDEP’s approval and the subsequent recording of the institutional and engineering controls, no further work will be required of the parties. Assuming the FDEP approves the draft institutional and engineering controls, it is anticipated that FPU’s share of remaining legal and cleanup costs will not exceed $5,000. Salisbury, Maryland We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized ground-water contamination. During 1996, we completed construction of an Air Sparging and Soil/Vapor Extraction system and began remediation procedures. We have reported the remediation and monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to permanently decommission the Air Sparging and Soil/Vapor Extraction system 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 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. 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 the FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. In 2001, FDEP approved a RAP requiring construction and operation of a BS/SVE treatment system to address soil and groundwater impacts at a portion of the site. The BS/SVE treatment system has been in operation since October 2002. Modifications and upgrades to the BS/SVE treatment system were completed in October 2009. The Eighteenth Semi-Annual RAP Implementation Status Report was submitted to FDEP in December 2011. The groundwater sampling results through December 2011 show a continuing reduction in contaminant concentrations and indicate that the recent treatment system modifications and upgrades have had a beneficial impact on the rate of reduction. At present, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the BS/SVE treatment system. The total expected cost of operating and monitoring the system is approximately $46,000.
The BS/SVE treatment system at the Winter Haven site does not address impacted soils in the southwest corner of the site. On April 16, 2010, a soil excavation interim RAP describing the proposed excavation of approximately 4,000 cubic yards of impacted soils from the southwest corner of the site was submitted to FDEP for review. On June 24, 2010, FDEP provided comments on the soil excavation interim RAP by letter, to which we responded, and a subsequent conditional approval letter was issued by FDEP on August 27, 2010. The cost to implement this excavation plan has been estimated at $250,000; however, this estimate does not include costs associated with dewatering or shoreline stabilization, which would be required to complete the excavation. Because the costs associated with shoreline stabilization and dewatering (including treatment and discharge of the pumped water) are likely to be substantial, alternatives to this excavation plan are being evaluated. One alternative currently being evaluated involves sparging into the southwest portion of the property to treat soils rather than excavating the soils. Two new sparge points were installed in the southwest portion of the property in February of 2011. Sparging into these points has been initiated, and operational and monitoring data over the next few quarters should provide the information needed to make this evaluation. FDEP has indicated that we may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures discussed by FDEP could cost as much as $1.0 million. We believe that corrective measures for the sediments are not warranted and intend to oppose any requirement that we undertake corrective measures in the offshore sediments. We have not recorded a liability for sediment remediation, as the final resolution of this matter cannot be predicted at this time. 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. |
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The entire disclosure for environmental loss contingencies, such as presence of hazardous waste, relevant information from reports issued by regulators, and estimated costs to achieve compliance with regulatory requirements. This element may be used for all of an entity's disclosures about environmental loss contingencies. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Other Commitments and Contingencies
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Other Commitments and Contingencies [Abstract] | |
OTHER COMMITMENTS AND CONTINGENCIES |
Q. OTHER COMMITMENTS AND CONTINGENCIES Litigation In May 2010, an FPU propane customer filed a class action complaint against FPU in Palm Beach County, Florida, alleging, among other things, that FPU acted in a deceptive and unfair manner related to a particular charge by FPU on its bills to propane customers and the description of such charge. The suit sought to certify a class comprised of FPU propane customers to whom such charge was assessed since May 2006 and requested damages and statutory remedies based on the amounts paid by FPU customers for such charge. FPU vigorously denied any wrongdoing and maintained that the particular charge at issue is customary, proper and fair. Without admitting any wrongdoing, validity of the claims or a properly certifiable class for the complaint, FPU entered into a settlement agreement with the plaintiff in September 2010 to avoid the burden and expense of continued litigation. The court approved the final settlement agreement, and the judgment became final on March 13, 2011. In 2010, we recorded $1.2 million of the total estimated costs related to this litigation. Pursuant to the final settlement agreement, the distribution to the class was completed by May 13, 2011.
On March 2, 2011, the City of Marianna, Florida filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida. In the complaint, the City of Marianna alleged three breaches of the Franchise Agreement by FPU: (i) FPU failed to develop and implement TOU and interruptible rates that were mutually agreed to by the City of Marianna and FPU; (ii) mutually agreed upon TOU and interruptible rates by FPU were not effective or in effect by February 17, 2011; and (iii) FPU did not have such rates available to all of FPU’s customers located within and without the corporate limits of the City of Marianna. The City of Marianna is seeking a declaratory judgment allowing it to exercise its option under the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City of Marianna related to the purchase and the operation by the City of Marianna of an electric distribution facility. If the purchase is approved by the Marianna Commission and the referendum is approved by the voters, the closing of the purchase must occur within 12 months after the referendum is approved. On March 28, 2011, FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the material allegations by the City of Marianna and asserted several affirmative defenses. On August 3, 2011, the City of Marianna notified FPU that it was formally exercising its option to purchase FPU’s property. On August 31, 2011, FPU advised the City of Marianna that it has no right to exercise the purchase option under the Franchise Agreement and that FPU would continue to oppose the effort by the City of Marianna to purchase FPU’s property. At a hearing on January 10, 2012 the judge presiding over this case set plaintiff’s motion for summary judgment for hearing on April 2, 2012. The court directed the parties to complete by March 23, 2012, depositions necessary for consideration at the summary judgment hearing. The court also set the case for trial commencing July 30, 2012. We anticipate that the case will be tried at this time. FPU intends to continue its vigorous defense of the lawsuit filed by the City of Marianna and intends to oppose the adoption of any proposed referendum to approve the purchase of the FPU property in the City of Marianna. We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal proceedings 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. Natural Gas, Electric and Propane Supply Our natural gas, electric and propane distribution operations and propane wholesale marketing operation have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. We have a contract with an energy marketing and risk management company to manage a portion of our natural gas transportation and storage capacity. This contract expires on March 31, 2013. 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 for the service. In May 2011, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2012. PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements before the existing agreements expire. As discussed in Note O “Rates and Other Regulatory Activities,” on January 25, 2011, FPU entered into an amendment to its Generation Services Agreement with Gulf Power, which reduces the capacity demand quantity and provides the savings necessary to support the TOU and interruptible rates for the customers in the City of Marianna, both of which were approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019.
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 result of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) fixed charge coverage ratio greater than 1.5. If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operation interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of action taken or proposed to be taken to be compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU providing an irrevocable letter of credit. FPU was in compliance with these requirements as of December 31, 2011. The total purchase obligations for natural gas, electric and propane supplies are $99.2 million for 2012, $70.6 million for 2013 – 2014, $61.1 million for 2015 – 2016 and $122.9 million thereafter. Corporate Guarantees The Board of Directors has authorized the Company to issue up to $45 million of corporate guarantees on behalf of our subsidiaries and for letters of credit. We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which are for our propane wholesale marketing subsidiary and our natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 2011 was $27.6 million, with the guarantees expiring on various dates through December 2012. Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal and accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note J, “Long-Term Debt,” to the Consolidated Financial Statements 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, 2012, 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 $656,000, which expires on December 2, 2012, as security to satisfy the deductibles under our various outstanding insurance policies. As a result of a change in our primary insurance company in 2010, we renewed the letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2012. There have been no draws on these letters of credit as of December 31, 2011. 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. We provided a letter of credit for $2.5 million to TETLP related to the Precedent Agreement with TETLP, which is further described below. Agreements for Access to New Natural Gas Supplies On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement with TETLP to secure firm transportation service from TETLP in conjunction with its new expansion project, which is expected to expand TETLP’s mainline system by up to 190,000 Dts/d. The Precedent Agreement provides that, upon satisfaction of certain conditions, the parties will execute two firm transportation service contracts, one for our Delaware division and one for our Maryland division, for 34,100 Dts/d and 15,900 Dts/d, respectively. The 34,000 Dts/d for our Delaware division and15,900 Dts/d for our Maryland division reflect the additional volume subscribed to by our divisions above the volume originally agreed to by the parties. These contracts will be effective on the service commencement date of the project, which is currently projected to occur in November 2012. Each firm transportation service contract shall, among other things, provide for: (a) the maximum daily quantity of Dts/d described above; (b) a term of 15 years; (c) a receipt point at Clarington, Ohio; (d) a delivery point at Honey Brook, Pennsylvania; and (e) certain credit standards and requirements for security. Commencement of service and TETLP’s and our rights and obligations under the two firm transportation service contracts are subject to satisfaction of various conditions specified in the Precedent Agreement.
Our Delmarva natural gas supplies have been received primarily from the Gulf of Mexico natural gas production region and have been transported through three interstate upstream pipelines, two of which interconnect directly with Eastern Shore’s transmission system. The new firm transportation service contracts between our Delaware and Maryland divisions and TETLP will provide gas supply through an additional direct interconnection with Eastern Shore’s transmission system and provide access to new sources of supply from other natural gas production regions, including the Appalachian production region, thereby providing increased reliability and diversity of supply. They will also provide our Delaware and Maryland divisions with additional upstream transportation capacity to meet current customer demands and to plan for sustainable growth. The Precedent Agreement provides that the parties shall promptly meet and work in good faith to negotiate a mutually acceptable reservation rate. Failure to agree upon a mutually acceptable reservation rate would have enabled either party to terminate the Precedent Agreement, and would have subjected us to reimburse TETLP for certain pre-construction costs; however, on July 2, 2010, our Delaware and Maryland divisions executed the required reservation rate agreements with TETLP. The Precedent Agreement requires us to reimburse TETLP for our proportionate share of TETLP’s pre-service costs incurred to date, if we terminate the Precedent Agreement, are unwilling or unable to perform our material duties and obligations thereunder, or take certain other actions whereby TETLP is unable to obtain the authorizations and exemptions required for this project. If such termination were to occur, we estimate that our proportionate share of TETLP’s pre-service costs could be approximately $6.1 million as of December 31, 2011. If we were to terminate the Precedent Agreement after TETLP completed its construction of all facilities, which is expected to be in the fourth quarter of 2012, our proportionate share could be as much as approximately $50 million. The actual amount of our proportionate share of such costs could differ significantly and would ultimately be based on the level of pre-service costs at the time of any potential termination. As our Delaware and Maryland divisions have now executed the required reservation rate agreements with TETLP, we believe that the likelihood of terminating the Precedent Agreement and having to reimburse TETLP for our proportionate share of TETLP’s pre-service costs is remote. As previously mentioned, we have provided a letter of credit to TETLP for $2.5 million, which is the maximum amount required under the Precedent Agreement with TETLP. On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement with Eastern Shore to extend its mainline by eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. As discussed in Note O, “Rates and Other Regulatory Activities,” to Consolidated Financial Statements, Eastern Shore completed the extension project in December 2010 and commenced the service in January 2011. The rate for the transportation service on this extension is Eastern Shore’s current tariff rate for service in that area. In November 2011, TETLP obtained the necessary approvals, authorizations or exemptions for construction and operation of its portion of the project from the FERC. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or Eastern Shore. As the Eastern Shore and TETLP firm transportation services commence, our Delaware and Maryland divisions incur costs for those services based on the agreed and FERC-approved reservation rates, which will become an integral component of the costs associated with providing natural gas supplies to our Delaware and Maryland divisions and will be included in the annual GSR filings for each of our respective divisions. Non-income-based Taxes From time to time, we are subject to various audits and reviews by the states and other regulatory authorities regarding non-income-based taxes. We are currently undergoing sales tax audits in Florida. As of December 31, 2011 and 2010, we maintained accruals of $307,000 and $698,000, respectively, related to additional sales taxes and gross receipts taxes that we may owe to various states.
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R. QUARTERLY FINANCIAL DATA (UNAUDITED) In our opinion, the quarterly financial information shown below includes all adjustments necessary for a fair presentation of the operations for such periods. Due to the seasonal nature of our business, there are substantial variations in operations reported on a quarterly basis.
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The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Valuation and Qualifying Accounts
Schedule II Valuation and Qualifying Accounts
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The entire disclosure for any allowance and reserve accounts (their beginning and ending balances, as well as a reconciliation by type of activity during the period). Alternatively, disclosure of the required information may be within the footnotes to the financial statements or a supplemental schedule to the financial statements. Reference 1: http://www.xbrl.org/2003/role/presentationRef
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