Chesapeake

Company

ESNG

PESCO

PIPECO

Xeron

Delaware PSC

FASB

FERC

FDEP

Maryland PSC

MDE

SEC

AS/SVE

ASC

ASU

CGS

DSCP

Dts

E3 Project

Florida PSC

FPU

FSP

GAAP

GSR

HDD

PIP

RAP

SFAS

 

Cost of sales, excluding costs below

Operations

Transaction-related costs

Maintenance

Depreciation and amortization

Other taxes

 

Total operating expenses

 

Other loss, net of other income

Interest charges

 

Income tax expense (benefits)

 

 

 

Basic

Diluted

 

Basic

Diluted

 

 

Cost of sales, excluding costs below

Operations

Transaction-related costs

Maintenance

Depreciation and amortization

Other taxes

 

Total operating expenses

 

Other income (loss), net of other expenses

Interest charges

 

Income taxes

 

 

 

Basic

Diluted

 

Basic

Diluted

 

 

Net Income

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

Depreciation and accretion included in other costs

Deferred income taxes, net

Unrealized loss on commodity contracts

Unrealized loss (gain) on investments

Employee benefits

Share-based compensation

Changes in assets and liabilities:

Accounts receivable and accrued revenue

Propane inventory, storage gas and other inventory

Regulatory assets

Prepaid expenses and other current assets

Other deferred charges

Accounts payable and other accrued liabilities

Income taxes receivable

Accrued interest

Customer deposits and refunds

Accrued compensation

Regulatory liabilities

Other liabilities

 

Net cash provided by operating activities

 

 

Property, plant and equipment expenditures

Environmental expenditures

 

Net cash used by investing activities

 

 

Common stock dividends

Issuance of stock for Dividend Reinvestment Plan

Change in cash overdrafts due to outstanding checks

Net borrowing (repayment) under line of credit agreements

Repayment of long-term debt

 

Net cash provided (used) by financing activities

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

Cash and Cash Equivalents — Beginning of Period

 

Cash and Cash Equivalents — End of Period

 

 

Natural gas

Propane

Advanced information services

Other plant

 

Total property, plant and equipment

Less: Accumulated depreciation and amortization

Plus: Construction work in progress

 

Net property, plant and equipment

 

 

 

 

Cash and cash equivalents

Accounts receivable (less allowance for uncollectible accounts of $1,246 and $1,159, respectively)

Accrued revenue

Propane inventory, at average cost

Other inventory, at average cost

Regulatory assets

Storage gas prepayments

Income taxes receivable

Deferred income taxes

Prepaid expenses

Mark-to-market energy assets

Other current assets

 

Total current assets

 

 

Goodwill

Other intangible assets, net

Long-term receivables

Regulatory assets

Other deferred charges

 

Total deferred charges and other assets

 

 

 

 

Stockholders’ equity

Common stock, par value $0.4867 per share (authorized 12,000,000 shares)

Additional paid-in capital

Retained earnings

Accumulated other comprehensive loss

Deferred compensation obligation

Treasury stock

 

Total stockholders’ equity

 

Long-term debt, net of current maturities

 

Total capitalization

 

 

Current portion of long-term debt

Short-term borrowing

Accounts payable

Customer deposits and refunds

Accrued interest

Dividends payable

Accrued compensation

Regulatory liabilities

Mark-to-market energy liabilities

Other accrued liabilities

 

Total current liabilities

 

 

Deferred income taxes

Deferred investment tax credits

Regulatory liabilities

Environmental liabilities

Other pension and benefit costs

Accrued asset removal cost

Other liabilities

 

Total deferred credits and other liabilities

 

 

Balances at December 31, 2007

Net earnings

Other comprehensive income, net of tax:

Employee Benefit Plans, net of tax:

Amortization of prior service costs ⁽⁴⁾

Net loss ⁽⁵⁾

 

Total comprehensive income

 

Dividend Reinvestment Plan

Retirement Savings Plan

Conversion of debentures

Share based compensation ^{(1) (3)}

Tax benefit on stock warrants

Deferred Compensation Plan

Purchase of treasury stock

Sale and distribution of treasury stock

Dividends on stock-based compensation

Cash dividends ⁽²⁾

 

Net earnings

Other comprehensive income, net of tax:

Employee Benefit Plans, net of tax:

Amortization of prior service costs ⁽⁴⁾

Net Gain ⁽⁵⁾

 

Total comprehensive income

 

Dividend Reinvestment Plan

Retirement Savings Plan

Conversion of debentures

Share based compensation ^{(1) (3)}

Deferred Compensation Plan ⁽⁶⁾

Purchase of treasury stock

Sale and distribution of treasury stock

Dividends on stock-based compensation

Cash dividends ⁽²⁾

 

 

References in this document to “the Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in the Company’s latest Annual Report on Form 10-K filed with the SEC on March 9, 2009. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of the Company’s results of operations, financial position and cash flows for the interim periods presented.

The Company reclassified certain amounts reported in the statement of cash flows for the nine months ended September 30, 2008 to conform to current period classifications. In addition, the Company revised its 2008 segment information by reclassifying transaction costs, which were previously allocated to the natural gas, propane and advanced information services segments, to the “other and eliminations” segment. These reclassifications are considered immaterial to the overall presentation of the Company’s condensed consolidated financial statements.

The Company has assessed and reported on subsequent events through November 6, 2009, the date of issuance of these condensed consolidated financial statements.

Beginning in this third quarter 2009 Form 10-Q, the Company adopted the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification^TM (“Codification”), which is now the single source of authoritative accounting principles recognized by the FASB. The adoption of the Codification did not have a material impact on the Company’s financial position and results of operations. As a result of this adoption, the Company updated all references to accounting and reporting standards included in this Form 10-Q and in some instances provided references to both pre-and post-Codification standards, as appropriate.

In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S. issuers of financial statements prepared in accordance with International Financial Reporting Standards (“IFRS”), a comprehensive series of accounting standards published by the International Accounting Standards Board (“IASB”). Under the proposed roadmap, the Company may be required to prepare financial statements in accordance with IFRS as early as 2014. The SEC will make a determination in 2011 regarding the mandatory adoption of IFRS. In July 2009, the IASB issued an exposure draft of “Rate-regulated Activities,” which sets out the scope, recognition and measurement criteria, and accounting disclosures for assets and liabilities that arise in the context of cost-of-service regulation, to which the Company is subject to in its rate-regulated businesses. The Company will continue to monitor the development of the potential implementation of IFRS.

In December 2008, the FASB issued FASB Staff Position (“FSP”) on Statement of Financial Accounting Standard (“SFAS”) 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP is codified within FASB Accounting Standards Codification^TM (“ASC”) Section 715-20-65, of the Topic, “Compensation — Retirement Benefits.” It expands the disclosure requirements of a defined benefit pension or other postretirement plan by including the following discussions about plan assets: (i) how investment allocation decisions are made, including the plan’s investment policies and strategies; (ii) the major categories of plan assets; (iii) the inputs and valuation techniques used to measure the fair value of plan assets; (iv) the effect of fair value measurements, using significant unobservable inputs on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets. The Company will comply with the required disclosures, which are effective for the fiscal years ending after December 15, 2009.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 was codified within FASB ASC Sections 815-10-15 and 65, of the Topic, “Derivatives and Hedging,” and it requires enhanced disclosures for derivative instruments and hedging activities about: (i) how and why a company uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under the Derivatives and Hedging Topic, and (iii) how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows. Disclosures required by this standard were adopted by the Company, effective January 1, 2009. Adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations. These disclosures are discussed in Note 9, “Derivative Instruments,” to the condensed consolidated financial statements.

In April 2008, the FASB issued FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets,” which is codified within FASB ASC Sections 350-30-50, 55 and 65 of the Topic, “Intangibles — Goodwill and Other,” and FASB ASC Section 275-10-50, of the Topic, “Risks and Uncertainties.” It amended factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The intent of these provisions is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. This standard was adopted by the Company, effective January 1, 2009. Adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In May 2008, the FASB issued FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement),” FSP APB 14-1 was codified within: (i) FASB ASC Sections 470-20-10, 15, 25, 30, 35, 40, 45, 50, 55 and 65 of the Topic, “Debt,” (ii) FASB ASC Section 815-15-55, of the Topic, “Derivatives and Hedging,” (iii) FASB ASC Section 825-10-15, of the Topic, “Financial Instruments.” It clarifies that convertible debt instruments, which may be settled in cash upon either mandatory or optional conversion (including partial cash settlement), should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. This standard was adopted by the Company effective, January 1, 2009. The adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In September 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP, codified within FASB ASC Sections 260-10-45, 55 and 65, of the Topic, “Earnings Per Share,” clarifies that holders of outstanding unvested share-based payment awards containing rights to nonforfeitable dividends participate with common shareholders in undistributed earnings. Awards of this nature are considered participating securities, and the two-class method of computing basic and diluted earnings per share must be applied. This standard was adopted by the Company, effective January 1, 2009. The adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP, codified within FASB ASC Section 825-10-65, of the Topic, “Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. The provisions of this standard are effective for interim and annual reporting periods ending after June 15, 2009, and they did not have an impact on the Company’s condensed consolidated financial position and results of operations. The disclosures required by this standard are discussed in Note 10, “Fair Value of Financial Instruments,” to the condensed consolidated financial statements.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which the Company adopted in the second quarter of 2009. The provisions of this standard, now residing in FASB ASC Sections 855-10-05, 15, 25, 45, 50 and 55, of the Topic, “Subsequent Events,” establish general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In August 2009, the FASB issued FASB Accounting Standards Update (“ASU”) No. 2009-05, “Fair Value Measurement and Disclosures — Measuring Liabilities at Fair Value.” The ASU provides clarification that in circumstances in which a quoted price in an active market for an identical liability is not available, a reporting entity is required to measure fair value, using: (i) a valuation technique that uses the quoted price of the identical liability when traded as an asset or quoted prices for similar liabilities when traded as assets; or (ii) another valuation technique that is consistent with the principles of the Topic, “Fair Value Measurements and Disclosures.” This ASU, adopted by the Company in the third quarter of 2009, did not have an impact on the Company’s condensed consolidated financial position and results of operations.

On April 20, 2009, Chesapeake and Florida Public Utilities Company (“FPU”) announced a definitive merger agreement, pursuant to which FPU will merge with a wholly-owned subsidiary of Chesapeake, with FPU being the surviving corporation and operating as a wholly-owned subsidiary of Chesapeake after the merger. On October 22, 2009, shareholders of both Chesapeake and FPU approved the merger, which became effective on October 28, 2009 and each outstanding share of FPU common stock was converted into a 0.405 share of Chesapeake’s common stock. At closing, FPU had 6,140,592 common shares outstanding, and Chesapeake’s common stock was valued at $30.42 per share, which resulted in total consideration of approximately $75.7 million paid by Chesapeake. The total consideration is based upon the closing price of Chesapeake’s common stock on October 27, 2009, the last trading day prior to the effective date of the merger. Immediately after the merger, Chesapeake’s stockholders owned approximately 73.5 percent of the combined company, and FPU’s stockholders owned approximately 26.5 percent of the combined company.

On September 29, 2009, a putative class action lawsuit, which had been filed on May 8, 2009 in Palm Beach County, Florida, challenging the merger, purportedly on behalf of the shareholders of FPU, against FPU, each member of FPU’s board of directors and Chesapeake, was dismissed without prejudice.

The merger is intended to qualify as a reorganization, within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended, and is accounted for under the acquisition method of accounting under GAAP, with Chesapeake being treated as the acquirer. Under this method, the assets acquired and liabilities assumed are recorded at their respective fair values and added to those of Chesapeake. Chesapeake is in the process of finalizing its evaluation of the tangible and intangible assets acquired and liabilities assumed, as well as the initial purchase price allocation as of the acquisition date, including the determination of any resulting goodwill. Therefore, this information cannot be provided at this time.

In connection with the merger, Chesapeake has incurred $1.9 million in transaction-related costs during the nine months ended September 30, 2009. Chesapeake has begun the process of seeking regulatory approval to defer a portion of these costs related to regulated operations for future rate recovery. Based on precedents established by the Florida Public Service Commission (“Florida PSC”) in previous business combinations involving natural gas utilities in Florida, the Company determined that future rate recovery of the acquisition-related transaction costs for regulated operations is probable and deferred $1.4 million of the transaction-related costs as a regulatory asset as of September 30, 2009. This regulatory asset of $1.4 million includes deferrals of $89,000 and $850,000 incurred during the first and second quarters of 2009, respectively, that were previously accounted for as expenses. The reversal of these amounts is presented as a credit to transaction-related costs in the accompanying condensed and consolidated statement of income for the three months ended September 30, 2009. Transaction-related costs not subject to future rate recovery ($265,000 and $530,000 for the three and nine months ended September 30, 2009, respectively), are also included in transaction-related costs in the accompanying condensed and consolidated statements of income. Future regulatory developments may require Chesapeake to re-assess the probability of future rate recovery with regard to the costs deferred as a regulatory asset.

FPU distributes natural gas, propane and electricity to residential, commercial and industrial customers in Florida. FPU also sells merchandise and other service-related products as a complement to its natural gas and propane operations. FPU serves approximately 96,000 customers, employs 348 people and generated $168.5 million in revenues for 2008.

Net Income (Loss)

Weighted average shares outstanding

 

 

 

Net Income (Loss)

Effect of 8.25% Convertible debentures (1)

 

Adjusted numerator — Diluted

 

 

Weighted shares outstanding — Basic

Effect of dilutive securities: (1)

Share-based Compensation

8.25% Convertible debentures

 

Adjusted denominator — Diluted

 

 

 

The Company’s natural gas distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective Public Service Commission; Eastern Shore Natural Gas Company (“ESNG”), the Company’s natural gas transmission operation, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”).

Delaware. On September 2, 2008, the Company’s Delaware division filed with the Delaware Public Service Commission (“Delaware PSC”) its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On September 16, 2008, the Delaware PSC authorized the Delaware division to implement the GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware division was required by its natural gas tariff to file a revised application if its projected over-collection of gas costs for the determination period of November 2007 through October 2008 exceeded four and one-half percent (4.5 percent) of total firm gas costs. As a result of a significant decrease in the cost of natural gas, on January 8, 2009, the Delaware division filed with the Delaware PSC a supplemental GSR Application, seeking approval to change its GSR, effective February 1, 2009. On January 29, 2009, the Delaware PSC authorized the Delaware division to implement the revised GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, the Delaware PSC, the Company’s Delaware division and the Division of the Public Advocate. Pursuant to the settlement agreement, the Company’s Delaware division, commencing in November 2009, will adjust the margin-sharing mechanism related to its Asset Management Agreement to reduce its proportionate share of such margin. The Company anticipates a net margin reduction of approximately $8,000 per year from this change. As part of the settlement, the parties also 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 the Company’s natural gas marketing subsidiary, Peninsula Energy Services Company (“PESCO”). This later proceeding may be completed by the end of 2009. An unfavorable outcome of this later proceeding may affect PESCO’s spot-sale opportunities and profitability on the Delmarva Peninsula in the future.

On December 2, 2008, the Company’s Delaware division filed two applications with the Delaware PSC, requesting approval for a Town of Milton Franchise Fee Rider and a City of Seaford Franchise Fee Rider. These Riders allow the division to recover from natural gas customers located within the Town of Milford or the City of Seaford a proportionate share of the franchise fees paid by the division. The Delaware PSC granted approval of both Franchise Fee Riders on January 29, 2009.

On September 4, 2009, the Company’s Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2009. On October 6, 2009, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2009, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware division anticipates a final decision by the Delaware PSC on this application in the second quarter of 2010.

Maryland. On December 16, 2008, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Company’s Maryland division during the twelve months ended September 30, 2008. No issues were raised at the hearing, and on December 19, 2008, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings, which became a final Order of the Maryland PSC on January 21, 2009.

On April 24, 2009, the Maryland PSC issued an Order defining utilities’ payment plan parameters and termination procedures that would increase the likelihood that customers could pay their past due amounts to avoid termination of natural gas service. This Order requires the Company’s Maryland division to: (a) provide customers in writing, prior to issuing a termination notice, certain details about their past due balance and information about available payment plans, and (b) continue to offer flexible and tailored payment plans. The Company’s Maryland division has implemented procedures to comply with this Order.

Florida. On July 14, 2009, the Company’s Florida division filed with the Florida PSC its petition for a rate increase and request for interim rate relief. In the application, the Florida division seeks approval of: (a) an interim rate increase of $417,555; (b) a permanent rate increase of $2,965,398, which represents an average base rate increase, excluding fuel costs, of approximately twenty-five percent for the Florida division’s customers; (c) implementation or modification of certain surcharge mechanisms; (d) restructuring of certain rate classifications; and (e) deferral of certain costs and the purchase premium associated with the pending merger with FPU. On August 18, 2009, the Florida PSC approved the full amount of the Florida division’s interim rate request, subject to refund, applicable to all meters read on or after September 1, 2009. A final decision on the permanent rate increase is expected during the fourth quarter of 2009, as the docket is tentatively scheduled on December 15, 2009 agenda for the Florida PSC.

On September 11, 2009, the Florida division filed its annual Energy Conservation Cost Recovery Clause, which seeks final approval of the division’s 2008 conservation-related revenues and expenses and new conservation surcharge rates for 2010. A final decision by the Florida PSC on the proposed 2010 conservation surcharge rates is expected in November 2009.

ESNG. The following activities related to certain FERC Orders and the expansions of its transmission system were undertaken by ESNG:

System Expansion 2006 — 2008. In accordance with the requirements in the FERC’s Order Issuing Certificate for the 2006 — 2008 System Expansion, ESNG had until June 13, 2009, to construct the remaining facilities that were authorized in the project filing. On February 3, 2009, ESNG requested authorization to modify the previously required completion date and to commence construction of the facilities, which provide for the remaining 7,200 dekatherms (“Dts”) of additional firm service capacity previously approved by the FERC. On March 13, 2009, the FERC granted the requested authorization. On October 30, 2009, ESNG received approval from the FERC to commence services on these expansion facilities in November 2009, which will permit ESNG to realize an additional annualized gross margin of approximately $1.0 million.

Energylink Expansion Project (“E3 Project”). In 2006, ESNG 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 ESNG’s existing facilities in Sussex County, Delaware.

In April 2009, ESNG terminated the E3 Project and initiated billing to recover specified project costs in accordance with the terms of the precedent agreements executed with the two participating customers, one of which is Chesapeake, through its Delaware and Maryland divisions. These billings will reimburse ESNG for the $3.17 million of costs incurred in connection with the E3 Project, including the cost of capital, over a period of 20 years.

FERC Order Nos. 712 and 712-A. In June and November 2008, the FERC issued Order Nos. 712 and 712-A, which revised its regulations regarding interstate natural gas pipeline capacity release programs. The Orders: (a) remove the rate ceiling on capacity release transactions of one year or less; (b) facilitate the use of asset management arrangements for certain capacity releases; and (c) facilitate state-approved retail open access programs. The Orders required interstate gas pipeline companies to remove any inconsistent tariff provisions within 180 days of the effective date of the rule. On February 2, 2009, ESNG submitted revised tariff sheets to comply with the requirements set forth in the Orders. Amended tariff sheets were subsequently filed on February 26, 2009, which made minor clarifications and corrections. On March 27, 2009, ESNG received FERC approval of these amended tariff sheets with an effective date of March 1, 2009.

On April 30, 2009, ESNG submitted its annual Interruptible Revenue Sharing Report to the FERC. ESNG reported in this filing that it refunded a total of $245,500, inclusive of interest, in the second quarter of 2009 to its eligible firm customers.

On May 29, 2009, ESNG submitted its annual Fuel Retention Percentage (“FRP”) and Cash-Out Surcharge filings to the FERC. In these filings, ESNG proposed to implement an FRP rate of 0.12 percent and a zero rate for its Cash-Out Surcharge. ESNG also proposed to refund a total of $294,540, inclusive of interest, to its eligible customers in the second quarter of 2009 by netting its over-recovered fuel cost against its under-recovered cash-out cost. The FERC approved these proposals, and ESNG refunded $294,540 to customers in July 2009.

On June 1, 2009, ESNG submitted revised tariff sheets to comply with FERC Order No. 587-T, which adopted Version 1.8 of the North American Energy Standards Board Wholesale Gas Quadrant’s standards. FERC found this rule necessary to increase the efficiency of the pipeline grid, make pipelines’ electronic communications more secure and provide consistency with the mandate that agencies provide for electronic disclosure of information. ESNG’s revised tariff sheets were approved on August 11, 2009, by the FERC, which will have no financial impact on ESNG.

On August 21, 2009, ESNG filed revised tariff sheets to reflect an increase in the Annual Charge Adjustment (“ACA”) surcharge from $0.0017 per Dt to $0.0019 per Dt. The ACA surcharge is designed to recover applicable program costs incurred by the FERC. The tariff sheets were accepted as proposed and were made effective on October 1, 2009. As the ACA is passed-through to ESNG’s customers, there will be no financial impact on ESNG.

In cooperation with the MDE, the Company has completed remediation of the Salisbury Town Gas Light site, located in Salisbury, Maryland, where it was determined that a former manufactured gas plant had caused localized ground-water contamination. During 1996, the Company completed construction of an Air Sparging and Soil-Vapor Extraction (“AS/SVE”) system and began remediation procedures. Chesapeake has reported the remediation and monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to decommission permanently the AS/SVE system and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for continued product monitoring and recovery. On November 4, 2002, Chesapeake requested, and is awaiting, a No Further Action determination from the MDE.

Through September 30, 2009, the Company has incurred and paid approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount, approximately $2.1 million has been recovered through insurance proceeds or in rates pursuant to an Order from the Maryland PSC issued on September 26, 2006. As of September 30, 2009, a regulatory asset of approximately $812,000 has been recorded to represent the portion of the clean-up costs not yet recovered.

The Winter Haven Coal Gas site is located in Winter Haven, Florida. Chesapeake has been working with the Florida Department of Environmental Protection (“FDEP”) in assessing this coal gas site. In May 1996, the Company filed with the FDEP an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas site. After discussions with the FDEP, the Company filed a modified Work Plan, which contained a description of the scope of work to complete the site assessment activities and a report describing a limited sediment investigation performed in 1997. In December 1998, the FDEP approved the modified Work Plan, which the Company completed during the third quarter of 1999. In February 2001, the Company filed a Remedial Action Plan (“RAP”) with the FDEP to address the contamination of the subsurface soil and ground-water in a portion of the site. The FDEP approved the RAP on May 4, 2001. Construction of the AS/SVE system was completed in the fourth quarter of 2002, and the system remains fully operational.

Through September 30, 2009, the Company has accrued $1.8 million of environmental costs associated with this site. At September 30, 2009, the Company had accrued a liability of $425,000 related to this site, offsetting: (a) a regulatory asset of approximately $726,000, representing the uncollected portion of the estimated clean-up costs, and (b) approximately $301,000 collected through rates in excess of costs incurred. The Company expects to recover the remaining clean-up costs through rates.

The FDEP has indicated that the Company may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the Winter Haven Coal Gas site. Based on studies performed to date, the Company objects to the FDEP’s suggestion that the sediments have been contaminated and will require remediation. The Company’s early estimates indicate that some of the corrective measures discussed by the FDEP could cost as much as $1.0 million. Given the Company’s view as to the absence of ecological effects, the Company believes that cost expenditures of this magnitude are unwarranted and intends to oppose any requirement that it undertake corrective measures in the offshore sediments. The Company anticipates that it will be several years before this issue is resolved. At this time, the Company has not recorded a liability for sediment remediation. The outcome of this matter cannot be predicted at this time.

During 1999, the MDE queried with the Company regarding a manufactured gas plant site located in Cambridge, Maryland. The Company responded, and no further discussions ensued. The outcome of this matter cannot be determined at this time; therefore, the Company has not recorded an environmental liability for this location.

The Company’s natural gas and propane distribution operations have entered into contractual commitments to purchase natural gas and propane from various suppliers. The contracts have various expiration dates. In March 2009, the Company renewed its contract with an energy marketing and risk management company to manage a portion of the Company’s natural gas transportation and storage capacity. This contract expires on March 31, 2012.

In May 2009, the Company’s natural gas marketing subsidiary, PESCO, renewed contracts to purchase natural gas from various suppliers. These contracts expire on May 31, 2010.

The Company has issued corporate guarantees to certain vendors of its subsidiaries, primarily its propane wholesale marketing subsidiary, Xeron, and its natural gas marketing subsidiary, PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of either subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the condensed consolidated financial statements when incurred. The aggregate amount guaranteed at September 30, 2009 was $22.4 million, with the guarantees expiring on various dates in 2009 and 2010.

In addition to the corporate guarantees, the Company has issued a letter of credit to its primary insurance company for $775,000, which expires on May 31, 2010. The letter of credit is provided as security to satisfy the deductibles under the Company’s various insurance policies. There have been no draws on this letter of credit as of September 30, 2009, and the Company does not anticipate that this letter of credit will be drawn upon by the counterparty in the future.

The Company accounts for its regulated operations in accordance with the FASB ASC 980, “Regulated Operations.” In applying provisions of this Topic, the Company’s regulated operations may defer costs or revenues in different periods than its unregulated operations would recognize, resulting in assets or liabilities on the balance sheet. If the Company were required to terminate the application of these provisions to its regulated operations, all such deferred amounts would be recognized in the income statement at that time. This would result in a charge to earnings, net of applicable income taxes, which could be material.

The Company uses the management approach to identify operating segments. The Company organizes its business around differences in products or services, and the operating results of each segment are regularly reviewed by the Company’s chief operating decision-maker in order to make decisions about the allocation of resources and to assess performance.

During 2009, the Company revised the 2008 segment information by reclassifying transaction costs, previously allocated to the natural gas, propane and advanced information services segments, to the “other and eliminations” segment. These costs, related to an unconsummated acquisition in 2008, were not directly attributable to operations of the Company’s natural gas, propane and advanced information services segments, but were allocated to those segments as corporate overhead costs in 2008. In conjunction with the merger in 2009 and related acquisition costs (see Note 2), the Company reassessed its previous practice of allocating transaction costs that are not attributable to operations to each of its reportable segments and decided not to allocate those costs for the purpose of analyzing segment profitability. As a result of this change, $890,000, $273,000 and $64,000 of transaction costs allocated to the natural gas, propane and advanced information services segments, respectively, in the nine months ended September 30, 2008, were reclassified to the “other and eliminations” segment.

The following table presents information about the Company’s reportable segments.

Natural gas

Propane

Advanced information services

 

Total operating revenues, unaffiliated customers

 

 

Natural gas

Propane

Advanced information services

Other

 

Total intersegment revenues

 

 

Natural gas

Propane

Advanced information services

Other and eliminations ⁽²⁾

 

Total operating income

 

Other income (loss), net of other expenses

Interest

Income taxes (benefits)

 

Net income (loss)

 

Natural gas

Propane

Advanced information services

Other

 

Total identifiable assets

 

The Company’s operations are primarily domestic. The advanced information services segment has infrequent transactions with foreign companies, located primarily in Canada, which are denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated operating revenues.

Net periodic benefit costs for the defined benefit pension plan, the pension supplemental executive retirement plan and other post-retirement benefits are shown below:

Service Cost

Interest Cost

Expected return on plan assets

Amortization of prior service cost

Amortization of net loss

 

Net periodic (benefit) cost

 

Service Cost

Interest Cost

Expected return on plan assets

Amortization of prior service cost

Amortization of net loss

 

Net periodic (benefit) cost

 

The Company expects to recognize increased pension costs of approximately $483,000 in 2009 as a result of the decline in market values of the defined pension plan assets during 2008. In addition, the Company expects to contribute $450,000 to the defined benefit pension plan during the fourth quarter of 2009. The pension supplemental executive retirement plan and the other post-retirement benefit plan are unfunded and are expected to be paid out of the general funds of the Company. Cash benefits paid under the pension supplemental executive retirement plan for the three months and nine months ended September 30, 2009, were $22,000 and $67,000, respectively; for the year 2009, such benefits paid are expected to be approximately $88,000. Cash benefits paid for other post-retirement benefits, primarily for medical claims, for the three and nine months ended September 30, 2009, totaled $57,000 and $91,000, respectively. Based on actuarial assumptions and historical data, the Company has estimated that approximately $225,000 will be paid for such benefits during 2009.

The investment balance at September 30, 2009, represents a Rabbi Trust associated with the Company’s Supplemental Executive Retirement Savings Plan. The Company classifies these investments as trading securities and reports them at their fair value. Any unrealized gains and losses, net of other expenses, are included in other income in the condensed consolidated statements of income. The Company also has an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Rabbi Trust. At September 30, 2009, total investments had a fair value of $1.8 million.

The Company’s non-employee directors and key employees are awarded share-based awards through the Company’s Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), respectively. The Company records 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 awarded.

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the DSCP and the PIP for the three and nine months ended September 30, 2009 and 2008.

Directors Stock Compensation Plan

Performance Incentive Plan

 

Total compensation expense

Less: tax benefit

 

Share-Based Compensation amounts included in net income

 

Shares granted under the DSCP are issued in advance of the directors’ service period and are fully vested as of the date of the grant. The Company records a prepaid expense of the shares issued and amortizes the expense equally over a service period of one year. In May 2009, 6,500 shares were granted to the directors of the Company. A summary of stock activity under the DSCP for the nine months ended September 30, 2009, is presented below: