CHESAPEAKE UTILITIES CORP - Quarter Report: 2010 March (Form 10-Q)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BravePoint

Chesapeake

Company

ESNG

FPU

PESCO

PIPECO

Sharp

Xeron

Delaware PSC

EPA

FASB

FERC

FDEP

Florida PSC

IASB

Maryland PSC

MDE

PSC

SEC

AS/SVE

BS/SVE

CGS

DSCP

Dts

Dts/d

GSR

HDD

Mcf

MWH

MGP

NYSE

PIP

RAP

ASC

ASU

GAAP

IFRS

 

Regulated Energy

Unregulated Energy

Other

 

 

 

Regulated energy cost of sales

Unregulated energy and other cost of sales

Operations

Transaction-related costs

Maintenance

Depreciation and amortization

Other taxes

 

 

Total operating expenses

 

 

 

Other income, net of expenses

 

Interest charges

 

 

 

Income tax expense

 

 

 

 

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 (gain) on commodity contracts

Unrealized loss (gain) on investments

Employee benefits

Share-based compensation

Other, net

Changes in assets and liabilities:

Sale (purchase) of investments

Accounts receivable and accrued revenue

Propane inventory, storage gas and other inventory

Regulatory assets

Prepaid expenses and other current assets

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

Purchase of investments

Environmental expenditures

 

Net cash used in investing activities

 

 

Common stock dividends

Issuance (purchase) of stock for Dividend Reinvestment Plan

Change in cash overdrafts due to outstanding checks

Net repayment under line of credit agreements

Repayment of long-term debt

 

Net cash used in financing activities

 

 

Net Increase in Cash and Cash Equivalents

Cash and Cash Equivalents — Beginning of Period

 

Cash and Cash Equivalents — End of Period

 

 

Regulated energy

Unregulated energy

Other

 

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 $1,460 and $1,609, 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

Income taxes 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 — Regulatory liability

Other liabilities

 

Total deferred credits and other liabilities

 

 

 

Net Income

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

Common stock issued in the merger

Dividends on stock-based compensation

Cash dividends ⁽²⁾

 

Net Income

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

Tax benefit on share based compensation

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 our latest Annual Report on Form 10-K filed with the SEC on March 8, 2010. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

As a result of the merger with Florida Public Utilities Company (“FPU”) in October 2009, we changed our operating segments (see Note 5, “Segment Information,” for further discussion). We revised the segment information as of and for the three months ended March 31, 2009, to reflect the new segments. We also revised certain presentations and reclassified certain amounts reported in the condensed consolidated statements of income and cash flows for the three months ended March 31, 2009 to conform to current period presentations and classifications. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.

We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.

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, we may be required to prepare our 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 our rate-regulated businesses are subject. We will continue to monitor the development of the potential implementation of IFRS.

In January 2010, the Financial Accounting Standards Board (“FASB”) issued FASB Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” This ASU requires certain new disclosures and clarifies certain existing disclosure requirements about fair value measurement, as set forth in FASB Accounting Standards Codification (“ASC”) Subtopic 820-10. The FASB’s objective is to improve these disclosures and, thus, increase the transparency in financial reporting. Specifically, ASU 2010-06 amends ASC Subtopic 820-10 to now require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and, in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separate information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies certain requirements of the existing disclosures. We adopted the disclosures required by this ASU in the first quarter of 2010, except for disclosures about purchases, sales, issuances, and settlements in the roll-forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. We currently do not have any assets or liabilities that would require Level 3 fair value measurements. Adoption of this ASU did not have an impact on our condensed consolidated financial position and results of operations.

In April 2010, the FASB issued FASB ASU 2010-12 — Income Taxes (Topic 740), “Accounting for Certain Tax effects of the 2010 Health Care Reform Acts.” This ASU codifies the SEC staff announcement relating to the accounting for the Health Care and Education Reconciliation Act and the Patient Protection and Affordable Care Act, which allows the two Acts to be considered together for accounting purposes. We adopted this ASU in the first quarter of 2010 and have determined that these Acts did not have a material impact on our income tax accounting (see Note 6, “Employee Benefits,” to these unaudited condensed consolidated financial statements for further discussion).

On October 28, 2009, we completed the previously announced 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.

The merger allowed us to become a larger energy company serving approximately 200,000 customers in the Mid-Atlantic and Florida markets, which is twice the number of energy customers we served previously. The merger increased our overall presence in Florida by adding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing Florida operations. It also introduced us to the electric distribution business as we incorporated FPU’s approximately 31,000 electric customers in northwest and northeast Florida.

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 is no contingent consideration in the merger. Total value of considerations 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 value, for which GAAP provides specific exception to the fair value recognition and measurement, we applied other specified GAAP or accounting treatment as appropriate.

The following table summarizes an adjusted allocation of the purchase price to the assets acquired and liabilities assumed at the date of the merger. Estimates of deferred income taxes, recovery of certain regulatory assets, and certain accruals are subject to change, pending the finalization of income tax returns and availability of additional information about the facts and circumstances that existed as of the merger closing. We will complete the purchase price allocation as soon as practicable but no later than one year from the merger closing.

Purchase price

 

Current assets

Property, plant and equipment

Regulatory assets

Investments and other deferred charges

Intangible assets

 

Total assets acquired

 

Long term debt

Borrowings from line of credit

Other current liabilities

Other regulatory liabilities

Pension and post retirement obligations

Environmental liabilities

Deferred income taxes

Customer deposits and other liabilities

 

Total liabilities assumed

 

Net identifiable assets acquired

 

Goodwill

 

During the first quarter of 2010, we adjusted the allocation of purchase price based on additional information available. The adjustments are related to certain accruals, regulatory assets and deferred tax assets. These adjustments also resulted in a change in fair value of propane property, plant and equipment. Goodwill from the merger increased to $34.1 million after incorporating these adjustments, compared to $33.4 million prior to the adjustments.

None of the $34.1 million in goodwill recorded in connection with the merger is deductible for tax purposes. All of the goodwill recorded in connection with the merger is related to the regulated energy segment. We believe the goodwill recognized is attributable primarily to the strength of FPU’s regulated energy businesses and the synergies and opportunities in the combined company. The intangible assets acquired in connection with the merger are related to propane customer relationships ($3.5 million) and favorable propane contracts ($519,000). The intangible value assigned to FPU’s existing propane customer relationships will be amortized over a 12-year period based on the expected duration of benefit arising from the relationships. The intangible value assigned to FPU’s favorable propane contracts will be amortized over a period ranging from one to 14 months based on contractual terms.

Current assets of $26.8 million acquired during the merger include notes receivable of approximately $5.8 million, for which we received payment in March 2010, and accounts receivable of approximately $3.1 million, $6.0 million and $891,000 for FPU’s natural gas, electric and propane distribution businesses, respectively.

The financial position and results of operations and cash flows of FPU from the effective date of the merger are included in our consolidated financial statements. The revenue and net income from FPU for the three months ended March 31, 2010, included in our condensed consolidated statements of income, were $54.2 million and $4.5 million, respectively.

The following table shows the actual results of combined operations for the three months ended March 31, 2010 and pro forma results of combined operations for the three months ended March 31, 2009, as if the merger had been completed at January 1, 2009. Since the effects of the merger for the three months ended March 31, 2010 were already included in the actual results of our consolidated operations, there is no pro forma adjustment for the three months ended March 31, 2010.

 

Operating Revenues

Operating Income

Net income

 

Earnings per share — basic

Earnings per share — diluted

Pro forma results are presented for informational purposes only, and are not necessarily indicative of what the actual results would have been had the acquisition actually occurred on January 1, 2009.

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. It also prohibits an accrual of certain restructuring costs at the time of the merger. As we intend to seek recovery in future rates in Florida of a certain portion of the purchase premium paid and merger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining the proper accounting treatment for the merger-related costs. As of March 31, 2010, we incurred approximately $3.0 million in costs to consummate the merger, including the cost associated with merger-related litigation, and integrating operations following the merger. This includes $40,000 incurred during the three months ended March 31, 2010. We deferred approximately $1.5 million of the total costs incurred as a regulatory asset at March 31, 2010, which represents our estimate, based on similar proceedings in Florida in the past, of the costs which we expect to be permitted to recover when we complete the appropriate rate proceedings.

Included in the $3.0 million merger-related costs incurred as of March 31, 2010 were approximately $28,000 of severance and other restructuring charges for our efforts to integrate the operations of the two companies. We expect to incur an additional $300,000 in severance and other restructuring costs related to that effort during the second quarter of 2010.

On February 4, 2010, Sharp Energy, Inc. (“Sharp”), our propane distribution subsidiary, purchased the operating assets of Virginia LP Gas, Inc., a regional propane distributor serving approximately 1,000 retail customers in Northampton and Accomack Counties in Virginia. The total consideration for the purchase was $600,000, of which $300,000 was paid at the closing and the remaining $300,000 will be paid over 60 months. Based on our preliminary valuation, we allocated $412,000 of the purchase price to property, plant and equipment and the remaining $188,000 to intangible assets. There was no goodwill recorded in connection with this acquisition. The intangible assets acquired include customer relationships ($85,000) and non-compete agreements ($103,000), which will both be amortized over a seven-year period. The revenue and net income from this acquisition that are included in our condensed consolidated statement of income for the three months ended March 31, 2010 were not material. The allocation of purchase price is preliminary and we will complete the purchase price allocation as soon as practicable but no later than one year from the purchase of the assets.

Net Income

Weighted average shares outstanding

 

 

 

Net Income

Effect of 8.25% Convertible debentures

 

Adjusted numerator — Diluted

 

 

Weighted shares outstanding — Basic

Effect of dilutive securities:

Share-based Compensation

8.25% Convertible debentures

 

Adjusted denominator — Diluted

 

 

 

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective Public Service Commission (“PSC”); Eastern Shore Natural Gas Company (“ESNG”), our natural gas transmission operation, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”). Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric operations continue to be subject to regulation by the Florida Public Service Commission (“Florida PSC”) as separate entities.

Delaware. On September 2, 2008, our 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 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, 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, Peninsula Energy Services Company, Inc. (“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 has also recommended

that the Delaware PSC require us to adhere to asymmetrical pricing principles by applying the maximum tariff rates regarding all future capacity releases by the Delaware division to PESCO, if any. Accordingly, if the Hearing Examiner’s recommendation were approved without modification by the Delaware PSC and if the Delaware division temporarily released any capacity to PESCO, the Delaware division would have to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division pays for long-term capacity, even though the temporary releases were made at lower rates based on competitive bidding procedures required by the FERC’s capacity release rules. We disagreed with the Hearing Examiner’s recommendations and filed exceptions to those recommendations on February 18, 2010. 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. We expect the Delaware PSC to issue an order in May 2010 outlining its decisions at the March hearing. The Delaware PSC’s decision with regard to future capacity releases to PESCO contemplates that the parties will reconvene in a separate docket to determine if a pricing methodology other than asymmetrical pricing principles should apply to future capacity release by the Delaware division to PESCO.

On September 4, 2009, our 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 first evidentiary hearing in this matter is scheduled for May 19, 2010. The Delaware division anticipates a final decision by the Delaware PSC on this application late in the second quarter or early in the third quarter of 2010.

On December 17, 2009, our Delaware division filed an application with the Delaware PSC, requesting approval for an Individual Contract Rate for service to be rendered to a potential large industrial customer. The Delaware PSC granted approval of the Individual Contract Rate on February 18, 2010.

Maryland. On December 1, 2009, 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 our Maryland division during the 12 months ended September 30, 2009. No issues were raised at the hearing, and on December 9, 2009, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. On January 8, 2010, the Maryland PSC issued an Order substantially affirming the Hearing Examiner’s decision in the matter.

Florida. On July 14, 2009, Chesapeake’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 sought approval of: (a) an interim rate increase of $417,555; (b) a permanent rate increase of $2,965,398, which represented an average base rate increase, excluding fuel costs, of approximately 25 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 then 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. On December 15, 2009, the Florida PSC: (a) approved a $2,536,307 permanent rate increase (86 percent of the requested amount) applicable to all meters read on or after January 14, 2010; (b) determined that there is no refund required of the interim rate increase; and (c) ordered Chesapeake’s Florida division and FPU’s natural gas distribution operations to submit data no later than April 29, 2011 (which is 18 months after the merger) that details all known benefits, synergies and cost savings and cost increases that have resulted from the merger.

Also on December 15, 2009, the Florida PSC approved the settlement agreement for a final natural gas rate increase of $7,969,000 for FPU’s natural gas distribution operation, which represents approximately 80 percent of the requested base rate increase of $9,917,690 filed by FPU in the fourth quarter of 2008. The Florida PSC had approved an annual interim rate increase of $984,054 on February 10, 2009 and approved the permanent rate increase of $8,496,230 in an order issued on May 5, 2009, with the new rates to be effective beginning on June 4, 2009. On June 17, 2009, however, the Office of Public Counsel entered a protest to the Florida PSC’s order and its final natural gas rate increase ruling, which the protest required a full hearing to be held within eight months. Subsequent negotiations led to the settlement agreement between the Office of Public Counsel and FPU, which the Florida PSC approved on December 15, 2009. The rates authorized pursuant to the order approving the settlement agreement became effective on January 14, 2010. In February 2010, FPU refunded to its natural gas customers approximately $290,000, representing revenues in excess of the amount provided by the settlement agreement that had been billed to customers from June 2009 through January 14, 2010.

On September 1, 2009, FPU’s electric distribution operation filed its annual Fuel and Purchased Power Recovery Clause, which seeks final approval of its 2008 fuel-related revenues and expenses and new fuel rates for 2010. On January 4, 2010, the Florida PSC approved the proposed 2010 fuel rates, effective on or after January 1, 2010.

On September 11, 2009, Chesapeake’s Florida division and FPU’s natural gas distribution operation separately filed their respective annual Energy Conservation Cost Recovery Clauses, seeking final approval of their 2008 conservation-related revenues and expenses and new conservation surcharge rates for 2010. On November 2, 2009, the Florida PSC approved the proposed 2010 conservation surcharge rates for both the Florida division and FPU, effective for meters read on or after January 1, 2010.

Also on September 11, 2009, FPU’s natural gas distribution operation filed its annual Purchased Gas Adjustment Clause, seeking final approval of its 2008 purchased gas-related revenues and expenses and new purchased gas adjustment cap rate for 2010. On November 4, 2009, the Florida PSC approved the proposed 2010 purchased gas adjustment cap, effective on or after January 1, 2010.

The City of Marianna Commissioners voted on July 7, 2009 to enter into a new 10-year franchise agreement with FPU, effective February 1, 2010. The agreement provides that new interruptible and time-of-use rates shall become available for certain customers prior to February 2011, or, at the option of the City, the franchise agreement could be voided nine months after that date. The new franchise agreement contains a provision that permits the City to purchase the Marianna portion of FPU’s electric system. Should FPU fail to make available the new interruptible and time-of-use rates, and if the franchise agreement is then voided by the City and the City elects to purchase the Marianna portion of the distribution system, the agreement would require the City to pay FPU severance/reintegration costs, the fair market value for the system, and an initial investment in the infrastructure to operate this limited facility. If the City purchased the electric system, FPU would have a gain in the year of the disposition; but, ongoing financial results would be negatively impacted from the loss of the Marianna area from its electric operations.

ESNG. The following are regulatory activities involving FERC Orders applicable to ESNG and the expansions of ESNG’s transmission system:

Energylink Expansion 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 this project based on inadequate market support and 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 and approved by the FERC. One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions.

Prior Notice Request: On November 25, 2009, ESNG filed a prior notice request, proposing to construct, own and operate new mainline facilities to deliver additional firm entitlements of 1,594 Mcfs per day of natural gas to Chesapeake’s Delaware division. The FERC published the notice of this filing on December 7, 2009 and with no protest having been filed during the 60-day period following the notice, the proposed activity became effective on February 6, 2010. ESNG expects to realize an annualized margin of approximately $343,000 upon its completion of the facilities and implementation of the new service, which is expected in May 2010.

Mainline Extension Interconnect Project: On March 5, 2010, ESNG submitted an Application for Certificate of Public Convenience and Necessity to the FERC related to its mainline extension interconnect project that would tie into the new expansion project undertaken by Texas Eastern Transmission, LP (“TETLP”). ESNG’s project involves building and operating the eight-mile mainline extension from Honey Brook, Pennsylvania to ESNG’s existing facility in Parkesburg, Pennsylvania. The estimated capital costs associated with construction of the mainline extension by ESNG is approximately $19.4 million. FERC noticed the application on March 15, 2010 and the comment period ended on April 5, 2010. There were three protests to this application. ESNG filed an answer to the protests on April 28, 2010.

On December 11, 2009, ESNG filed revised tariff sheets to reflect a new section 42, Consolidation of Service Agreements, to the General Terms and Conditions of its FERC Gas Tariff. Section 42 states that shippers may, at their option and subject to certain conditions, consolidate multiple service agreements under a rate schedule into a new service agreement(s) under that rate schedule. The tariff sheets were accepted by the FERC on January 7, 2010, as proposed and were made effective January 15, 2010. As this new section allows for consolidation of existing service agreements only, there will be no financial impact on ESNG.

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 the effect on the environment of the disposal or release of specified substances at current and former operating sites.

We have participated in the investigation, assessment or remediation and have certain exposures at six former Manufactured Gas Plant (“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 Maryland Department of the Environment (“MDE”) regarding a seventh former MGP site located in Cambridge, Maryland. The Key West, Pensacola, Sanford and West Palm Beach sites are related to FPU, for which we assumed in the merger any existing and future contingencies.

As of March 31, 2010, we had recorded $468,000 in environmental liabilities related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of the future costs associated with those sites. As of March 31, 2010, we have recorded approximately $1.6 million in regulatory and other assets for future recovery of environmental costs from Chesapeake’s customers through its approved rates. As of March 31, 2010, we had recorded approximately $11.9 million in environmental liabilities related to FPU’s MGP sites in Florida, primarily from the West Palm Beach site, which represents our estimate of the future costs associated with those sites. FPU is approved to recover its environmental costs up to $14.0 million from insurance and customers through rates. Approximately $7.5 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of March 31, 2010. We also had recorded approximately $6.5 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

The following discussion provides details on each site.

We have completed remediation of this 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 (“AS/SVE”) 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 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. We have requested and are awaiting a No Further Action determination from the MDE.

Through March 31, 2010, we have incurred and paid approximately $2.9 million for remedial actions and environmental studies at this site and do not expect to incur any additional costs. We have recovered approximately $2.1 million through insurance proceeds or in rates and have $754,000 of the clean-up costs not yet recovered.

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 Florida Department of Environmental Protection (“FDEP”), we are obligated to assess and remediate environmental impacts at this former MGP site. In 2001, the FDEP approved a Remedial Action Plan (“RAP”) requiring construction and operation of a bio-sparge/soil vapor extraction (“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. The Fourteenth Semi-Annual RAP Implementation Status Report was submitted to the FDEP in January 2010. The groundwater sampling results through October 2009 show, in general, a reduction in contaminant concentrations, although the rate of reduction has declined recently. Modifications and upgrades to the BS/SVE treatment system were completed in October 2009. At present, we predict that remedial action objectives may be met for the area being treated by the BS/SVE treatment system in approximately three years.

The BS/SVE treatment system does not address impacted soils in the southwest corner of the site. We are currently completing additional soil and groundwater sampling at this location for the purpose of designing a remedy for this portion of the site. Following the completion of this field work, we will submit a soil excavation plan to the FDEP for its review and approval.

The 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 the 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.

Through March 31, 2010, we have incurred and paid approximately $1.5 million for this site and estimate an additional cost of $468,000 in the future, which has been accrued. We have recovered through rates $1.1 million of the costs and continue to expect that the remaining $829,000, which is included in regulatory assets, will be recoverable from customers through our approved rates.

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. The FDEP has not required any further work at the site as of this time. Our portion of the consulting/remediation costs which may be incurred at this site is projected to be $93,000.

FPU formerly owned and operated an MGP in Pensacola, Florida. The MGP was also owned by Gulf Power Corporation (“Gulf Power”). Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation. In October 2009, the FDEP informed Gulf Power that FDEP would approve a conditional No Further Action determination for the site, which must include a requirement for institutional/engineering controls. The group, consisting of Gulf Power, City of Pensacola, Florida Department of Transportation and FPU, is proceeding with preparation of the necessary documentation to submit the No Further Action justification. Consulting/remediation costs are projected to be $13,000.

FPU is the current owner of property in Sanford, Florida, a former MGP site which was operated by several other entities before FPU acquired the property. FPU was never an owner/operator of the MGP. In late September 2006, the U.S. Environmental Protection Agency (“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 total estimated remediation costs for this site were projected at the time by EPA 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 March 31, 2010, FPU has paid $650,000 to the Sanford Group escrow account for its share of 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 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/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 March 31, 2010, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is estimated to be $36,000. 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 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 funded under the Third Participation Agreement.

We are currently evaluating remedial options to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated an MGP. Pursuant to a Consent Order between FPU and the FDEP, effective April 8, 1991, FPU completed the delineation of soil and groundwater impacts at the site. On June 30, 2008, FPU transmitted a revised feasibility study, evaluating appropriate remedies for the site, to the FDEP. 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 demands for additional information. The total projected cost of this work is approximately $763,000.

The feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. Based on the likely acceptability of proven remedial technologies described in the feasibility study and implemented at similar sites, management believes that consulting and remediation costs to address the impacts now characterized at the West Palm Beach site will range from $7.4 million to $18.9 million. This range of costs covers such remedies as in situ solidification for deeper soil impacts, excavation of superficial soil impacts, installation of a barrier wall with a permeable biotreatment zone, monitored natural attenuation of dissolved impacts in groundwater, or some combination of these remedies.

Negotiations between FPU and the FDEP on a final remedy for the site continue. Prior to the conclusion of those negotiations, we are unable to determine, to a reasonable degree of certainty, the full extent or cost of remedial action that may be required. As of March 31, 2010, and subject to the limitations described above, we estimate the remediation expenses, including attorneys’ fees and costs, will range from approximately $7.8 million to $19.4 million for this site.

We continue to expect that all costs related to these activities will be recoverable from customers through rates.

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.

Our natural gas, electric and propane distribution operations 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, 2012.

PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements before the existing agreements expire in May 2010.

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 (formerly known as Jacksonville Electric Authority) 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; and (b) fixed charge coverage greater than 1.5. If either of the ratios is not met by FPU, we have 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 Company requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operation interest coverage (minimum of 2 to 1); and (b) total debt to total capital (maximum of 0.65 to 1). If FPU fails to meet the requirements, we have 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 agreement with Gulf Power Company could result in FPU having to provide an irrevocable letter of credit. FPU was in compliance with these requirements as of March 31, 2010.

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 our financial statements when incurred. The aggregate amount guaranteed at March 31, 2010 was $24.2 million, with the guarantees expiring on various dates through 2011.

In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance company for $725,000, which expires on August 31, 2010. The letter of credit is provided as security to satisfy the deductibles under our various insurance policies. There have been no draws on this letter of credit as of March 31, 2010. We do not anticipate that this letter of credit will be drawn upon by the counterparty, and we expect that it will be renewed to the extent necessary in the future.

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 dekatherms per day (“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 30,000 and 10,000 Dts/d, respectively, to 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 (f) 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 present sources of natural gas supplies are received primarily from the Gulf of Mexico natural gas production region and transported through two interstate upstream pipelines, which interconnect with the ESNG pipeline. These new contracts will provide our Delaware and Maryland divisions with access to new supplies of natural gas, providing increased reliability and diversity. They will also provide our Delaware and Maryland divisions additional upstream transportation capacity, which is essential to meet their current customer demands and to plan for sustainable growth.

On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement with our natural gas transmission subsidiary, ESNG, to extend ESNG’s mainline by eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. The estimated capital costs associated with construction of the mainline extension by ESNG is approximately $19.4 million, and the proposed rate for transmission service on this extension is ESNG’s current tariff rate for service in that area.

ESNG and TETLP are proceeding with obtaining the necessary approvals, authorizations or exemptions for construction and operation of their respective projects, including, but not limited to, approval by the FERC. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or ESNG.

As the final scope of TETLP’s expansion facilities is not known at this time, the reservation rates for service under the firm transportation service contracts were not specified in the Precedent Agreement with TETLP. TETLP is required to provide our Delaware and Maryland divisions a good faith estimate of the reservation rate by no later than June 30, 2010.

Once the TETLP firm transportation service contracts commence, our Delaware and Maryland divisions will incur costs from those services based on the agreed reservation rate, which will become an integral component of the costs associated with providing natural gas supplies to our Delaware and Maryland divisions. The costs from the TETLP firm transportation service contracts will be included in the annual GSR filings for each of our respective divisions.

If the reservation rate provided by TETLP in June 2010 is higher than the range of rates included in the TETLP Precedent Agreement, and we determine that the higher rate causes the value of service to be uneconomic to us, the Precedent Agreement provides that the parties shall promptly meet and work in good faith to negotiate a mutually acceptable reservation rate. If, however, the parties are unable to agree upon a mutually acceptable reservation rate, either party may terminate the Precedent Agreement and the related firm transportation service contracts. In the unlikely event of such termination, we may be required to reimburse TETLP for our proportionate share (prorated based on our total commitment of 40,000 Dts/d and the project total of 190,000 Dts/d) of TETLP’s pre-service costs incurred as of the date of the termination. We estimate that our proportionate share could be approximately $363,000 upon such termination.

After our Delaware and Maryland divisions execute the negotiated rate agreements with TETLP, we would only be required 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. We believe that the likelihood of our Delaware and Maryland divisions terminating the Precedent Agreement after executing the negotiated rate agreements and having to reimburse TETLP for our proportionate share of TETLP’s pre-service costs is remote. If such termination were to occur, we estimate that our proportionate share of TETLP’s pre-service costs could be approximately $4.7 million by December 31, 2010. 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 2011, our proportionate share could be as much as approximately $45 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.

We provided a letter of credit for $363,000 under the Precedent Agreement with TETLP in April 2010 as required. The letter of credit is expected to increase quarterly as TETLP’s pre-service costs increases. The letter of credit will not exceed more than the three-month reservation charge under the firm transportation service contracts, which we currently estimate to be $2.1 million.

We are involved in certain 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.

We use the management approach to identify operating segments, and we organize our business around differences in regulatory environment and/or products or services. 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.

As a result of the merger with FPU in October 2009, we changed our operating segments to better reflect how the chief operating decision maker reviews the various operations of our Company. Our three operating segments are now composed of the following:

Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of ESNG.

Unregulated Energy. The unregulated energy segment includes natural gas marketing, propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and services.

Other. The “Other” segment consists primarily of the advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

The following table presents information about our reportable segments.

Regulated Energy

Unregulated Energy

Other

 

Total operating revenues, unaffiliated customers

 

 

Regulated Energy

Unregulated Energy

Other

 

Total intersegment revenues

 

 

Regulated Energy

Unregulated Energy

Other and eliminations

 

Total operating income

 

Other income, net of other expenses

Interest

Income taxes

 

Net income

 

Regulated energy

Unregulated energy

Other

 

Total identifiable assets

 

Our operations are almost entirely domestic. Our advanced information services subsidiary, BravePoint, has infrequent transactions in foreign countries, primarily Canada, which are denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated revenues.

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2010 and 2009 are set forth in the following table:

Service Cost

Interest Cost

Expected return on plan assets

Amortization of prior service cost

Amortization of net loss

 

Net periodic cost

 

We expect to record pension and postretirement benefit costs of approximately $1.0 million for 2010 of which $320,000 is attributable to FPU’s pension and medical plans. In addition, we expect to contribute $450,000 and $1.6 million to the Chesapeake and FPU pension plans, respectively, in 2010, of which $377,000 has been contributed for the FPU pension plan during the three months ended March 31, 2010. The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three months ended March 31, 2010, were $22,000; for the year 2010, such benefits paid are expected to be approximately $88,000. Cash benefits paid for the Chesapeake Postretirement Plan and the FPU Medical Plan, primarily for medical claims, for the three months ended March 31, 2010, totaled $17,000 and $20,000, respectively; for the year 2010, we have estimated that approximately $115,000 and $144,000, respectively, will be paid for such benefits.

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 during the three months ended March 31, 2010 and determined that the deferred tax effects were not material to our financial results.

The investment balance at March 31, 2010 represents a Rabbi Trust associated with our Supplemental Executive Retirement Savings Plan and a Rabbi Trust related to a stay bonus agreement with a former executive. We classify these investments as trading securities and report 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. We also have an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Rabbi Trusts. At March 31, 2010 and December 31, 2009, total investments had a fair value of $2.0 million.

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 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 months ended March 31, 2010 and 2009.

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 periods and are fully vested as of the date of the grant. We record a prepaid expense of the shares issued and amortize the expense equally over a service period of one year. No additional shares were granted under the DSCP during the three months ended March 31, 2010.

The table below presents the summary of the stock activity for the PIP for the three months ended March 31, 2010:

Outstanding — December 31, 2009

 

Granted

Vested

Fortfeited

Expired

 

Outstanding — March 31, 2010

 

In January 2010, the Board of Directors granted awards under the PIP for 40,875 shares. The shares granted in January 2010 are multi-year awards, 8,000 shares of which will vest at the end of the two-year service period, or December 31, 2011. The remaining 32,875 shares will vest at the end of the three-year service period, or December 31, 2012. These awards are based upon the achievement of long-term goals, development and our success, and they comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Monte-Carlo pricing model to estimate the fair value of each market-based award granted.

At March 31, 2010, the aggregate intrinsic value of the PIP awards was $1.5 million.