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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, allowance for funds used during construction (“AFUDC”), 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. A summary of property, plant and equipment by classification as of December 31, 2012 and 2011 is provided in the following table:


	December 31,			December 31,
(in thousands)	2012			2011
Property, plant and equipment
Regulated Energy
Natural gas distribution – Delmarva	$	149,558		$	140,800
Natural gas distribution – Florida		170,943			158,341
Natural gas transmission		202,968			173,810
Electric distribution – Florida		61,960			55,839
Unregulated Energy
Propane distribution—Delmarva		53,156			51,250
Propane distribution – Florida		16,823			15,839
Other unregulated energy		239			238
Other		20,067			19,988

Total property, plant and equipment		675,714			616,105
Less: Accumulated depreciation and amortization		(155,378	)		(137,784	)
Plus: Construction work in progress		21,445			9,383

Net property, plant and equipment	$	541,781		$	487,704

Contributions or Advances in Aid of Construction

Customer contributions or advances in aid of construction reduce property, plant and equipment unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. The amounts that are determined to be non-refundable reduce property, plant and equipment at the time of such determination. During the years ended December 31, 2012 and 2011, there were $1.1 million and $286,000, respectively, of non-refunded contributions or advances reducing property, plant and equipment.

Allowed Funds Used During Construction

Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in rate base for rate making purposes when the completed projects are placed in service. During the years ended December 31, 2012 and 2011, we recorded $111,000 and $25,000, respectively, of AFUDC, all of which were related to short-term debt and reflected as a reduction of interest charges.

Asset Used in Leases

Property, plant and equipment for the natural gas transmission operation includes $1.4 million of assets, consisting primarily of mains, measuring equipment and regulation station equipment used by Peninsula Pipeline to provide natural gas transmission service pursuant to a contract with a third party. This contract is accounted for as an operating lease due to the exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and generates $264,000 in annual revenue for a term of 20 years. Accumulated depreciation for these assets totaled $291,000 and $218,000 at December 31, 2012 and 2011, respectively.

Property, plant and equipment for the natural gas transmission operation also includes $6.7 million of assets, which consists of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, jointly owned by Peninsula Pipeline and Peoples Gas. The amount included in property, plant and equipment represents Peninsula Pipeline’s 45-percent ownership of this pipeline. This 16-mile pipeline was placed in service in December 2012. Accumulated depreciation for this pipeline totaled $28,000 at December 31, 2012.

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, which was finalized in February 2012 and did not result in a material gain. 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.

In June and July 2012, FPU entered into contracts to exchange land located in West Palm Beach, Florida for a different parcel of land located in the same city. Under the same contracts, FPU also agreed to purchase a second parcel of land located in the same city for approximately $600,000. In early 2013, FPU terminated these contracts.

Depreciation and Accretion Included in Operations Expenses

Depreciation and Accretion Included in Operations Expenses

We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the regulators. The following table shows the average depreciation rates used during the years ended December 31, 2012, 2011 and 2010:


	2012			2011			2010
Natural gas distribution – Delmarva		2.6	%		2.5	%		2.5	%
Natural gas distribution – Florida		3.5	%		3.5	%		3.2	%
Natural gas transmission		2.5	%		2.6	%		2.7	%
Electric distribution – Florida		4.2	%		4.2	%		3.8	%

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


Asset Description	Useful Life
Propane distribution mains		10-37 years
Propane bulk plants and tanks		7-40 years
Liquified petroleum gas equipment		5-40 years
Meters and meter installations		5-33 years
Measuring and regulating station equipment		5-37 years
Office furniture and equipment		3-10 years
Transportation equipment		3-20 years
Structures and improvements		3-45 years
Other		Various

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 expense consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2012, 2011 and 2010, $5.5 million, $5.1 million and $4.4 million, respectively, of depreciation and accretion were reported in operations expenses.

Regulated Operations

Regulated Operations

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, 2012 and 2011, the regulated utility operations had recorded the following regulatory assets and liabilities included in our consolidated balance sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.


	December 31,		December 31,
	2012		2011
(in thousands)
Regulatory Assets
Underrecovered purchased fuel costs ⁽¹⁾	$	2,219	$	911
Deferred post retirement benefits ⁽²⁾		17,755		15,640
Deferred transaction and transition costs ⁽³⁾		1,035		1,600
Deferred conversion and development costs ⁽¹⁾		842		1,143
Environmental regulatory assets and expenditures ⁽⁴⁾		5,432		6,131
Acquisition adjustment ⁽⁵⁾		48,724		50,546
Loss on reacquired debt ⁽⁶⁾		1,484		1,576
Other		2,653		3,555

Total Regulatory Assets	$	80,144	$	81,102

Regulatory Liabilities
Self insurance ⁽¹⁰⁾	$	1,212	$	1,010
Overrecovered purchased fuel costs ⁽¹⁾		218		4,664
Conservation cost recovery ⁽¹⁾		356		12
Rate Refund ⁽⁷⁾		—		1,250
Storm reserve ⁽¹⁰⁾		2,742		2,812
Accrued asset removal cost ⁽⁹⁾		38,096		36,584
Deferred gains ⁽⁸⁾		1,977		—
Other		526		469

Total Regulatory Liabilities	$	45,127	$	46,801

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

⁽²⁾	The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715 related to its regulated operations. See Note 15, “Employee Benefit Plans,” for additional information.

⁽³⁾

The Florida PSC approved the inclusion of the FPU merger-related costs in our rate base and the recovery of those costs in rates. The balances at December 31, 2012 and 2011 include the gross-up of this regulatory asset for income tax because a portion of the merger-related costs is not tax-deductible.

⁽⁴⁾	All of our environmental expenditures incurred to date and current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 18, “Environmental Commitments and Contingencies,” for additional information on our environmental contingencies.

⁽⁵⁾

The Florida PSC approved the inclusion of approximately $1.3 million of the premium paid by FPU for an acquisition of another natural gas utility in 2002 (prior to Chesapeake’s acquisition of FPU) in its rate base and the recovery of it in rates. The Florida PSC also approved the inclusion of approximately $34.2 million of the premium paid by Chesapeake in its acquisition of FPU in the rate base and the recovery of it in rates. During 2012, we reclassified to a regulatory asset that portion of the goodwill related to the FPU acquisition, which was approved for recovery in future rates, along with the related gross-up for income taxes. See Note 17, “Rates and Other Regulatory Activities,” for additional information.

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

⁽⁷⁾	Eastern Shore refunded this amount to customers in February 2012 as a result of a rate case settlement. See Note 17, “Rates and Other Regulatory Activities,” for additional information.

⁽⁸⁾

Deferred gains represent: (i) a one-time contingency gain and a tax gross-up related to FPU’s income tax liability, which originated prior to the acquisition by Chesapeake from excess tax depreciation on vehicles (see Note 17, “Rates and Other Regulatory Activities,” for additional information); and (ii) a deferral of a curtailment gain related to FPU’s postretirement medical benefit associated with a change in plan provisions that became effective January 1, 2012 (see Note 15, “Employee Benefit Plans,” for additional information).

⁽⁹⁾

In accordance with regulatory treatment our depreciation rates are comprise of two components – historical cost and the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through depreciation expense with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs meet the requirements of authoritative guidance related to regulated operations, we have accounted for them as a regulatory liability and have reclassified them from accumulated depreciation to accumulated removal costs in our consolidated balance sheets.

⁽¹⁰⁾	We have self insurance and storm reserves that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

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

Operating Revenues

Operating Revenues

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

For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, 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 bulk delivery 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 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 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 to its customers, whereby the customers are permitted to purchase their gas requirements directly from competitive natural gas marketers.

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

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

Cost of Sales

Cost of Sales

Cost of sales includes the direct costs attributable to the products sold or services we provide for our regulated energy, unregulated energy and other 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

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.

Cash and Cash Equivalents

Cash and Cash Equivalents

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

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable consist primarily of amounts due for distribution sales of natural gas, electricity and propane and transportation services to customers. An allowance for doubtful accounts is recorded against amounts due to reduce the 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.

Inventories

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.

Goodwill and Other Intangible Assets

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 10, “Goodwill and Other Intangible Assets,” for additional discussion of this subject.

Other Deferred Charges

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

We estimate the 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 decrease in the discount rate could increase our annual pension and postretirement costs by approximately $11,000, and a 0.25 percent increase could decrease our annual pension and postretirement costs by approximately $13,000. A 0.25 percent change in the rate of return could change our annual pension cost by approximately $124,000 and would not have an impact on the postretirement and supplemental executive retirement plans because these plans are not funded.

Income Taxes and Investment Tax Credit Adjustments

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

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.

Recent Accounting Standards Yet to be Adopted

FASB Statements and Other Authoritative Pronouncements

Recent Accounting Standards Yet to be Adopted

In February 2013, the FASB issued Accounting Standards Update (“ASU”) 2013-02, “Comprehensive Income (Topic 220) Reporting Amounts Reclassified Out Of Accumulated Other Comprehensive Income.” ASU 2013-02 requires entities to report either on their income statement or disclose in footnotes to the financial statements the effects on net income from significant items that are classified out of the accumulated other comprehensive income for all reporting periods (annual and interim) covered by the financial statements. The standard also requires cross-reference to other disclosures currently required under GAAP for other reclassification items that are not required to be reclassified directly to net income. This standard is effective for us for fiscal periods beginning after December 15, 2012 and we expect the adoption of ASU 2013-02 to have no material impact on our financial position and results of operations

In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” The FASB issued ASU 2013-01 in response to concerns raised by constituents regarding the potential broad scope of disclosure requirements upon adoption of ASU 2011-11. It limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions to the extent that they are (1) offsetting in the financial statements or (2) subject to an enforceable master netting arrangement or similar agreement. ASU 2013-01 will be effective for us on January 1, 2013. We expect the adoption of this standard to have no material effect on our financial position and results of operations.

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet (Topic 210): Disclosures About Offsetting Assets and Liabilities.” This standard amends the disclosure requirements on offsetting by requiring enhanced disclosures about financial instruments and derivative instruments that are either: (i) offset in accordance with existing guidance, or (ii) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. ASU 2011-11 will be effective for us on January 1, 2013. We expect the adoption of this standard to have no material effect on our financial position and results of operations.

Recently Adopted Accounting Standards

Recently Adopted Accounting Standards

In September 2011, the FASB issued ASU 2011-08, “Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment,” which 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 differs from 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 adopted ASU 2011-08, effective January 1, 2012. The adoption of ASU 2011-08 had no material impact on our financial position and results of operations.

Fair Value Measurement

In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” ASU 2011-04 does not extend the use of fair value accounting but provides guidance on how fair value accounting should be applied where its use is already required or permitted by other standards within International Financial Accounting Standards (“IFRS”) or GAAP. ASU 2011-04 supersedes most of the guidance in Topic 820, although many of the changes are clarifications of existing guidance or changes in wording 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. We adopted ASU 2011-04, effective January 1, 2012, and provided additional disclosures as required. The adoption of ASU 2011-04 had no material impact on our financial position and results of operations.