CHESAPEAKE UTILITIES CORP - Quarter Report: 2012 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

For the quarterly period ended: March 31, 2012

OR

For the transition period from             to             

Commission File Number: 001-11590

CHESAPEAKE UTILITIES CORPORATION

(Exact name of registrant as specified in its charter)

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including Zip Code)

(302) 734-6799

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

Common Stock, par value $0.4867 — 9,578,716 shares outstanding as of April 30, 2012.

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GLOSSARY OF KEY TERMS AND DEFINITIONS

Accounting Principles Generally Accepted in the United States of America (GAAP): A standard framework of accounting rules used to prepare and present financial statements in the United States of America.

Acquisition adjustment: The recovery, through rates, and inclusion in rate base, of the premium (amount in excess of net book value) paid for an acquisition as approved by the state PSCs for the regulated operations.

BravePoint^®, Inc. (BravePoint): An advanced information services subsidiary, headquartered in Norcross, Georgia. BravePoint is a wholly owned subsidiary of Chesapeake Services Company, which is a wholly owned subsidiary of Chesapeake.

Chesapeake Utilities Corporation (Chesapeake or the Company): The Registrant, its divisions, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure.

Come-Back filing: The regulatory filing that was required by the Florida PSC within 18 months of the completion of the FPU merger to detail known benefits, synergies, cost savings and cost increases resulting from the merger.

Cooling Degree-Day (CDD): A measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am next day) is above 65 degrees Fahrenheit. This measurement is used to determine the impact of hot weather on our electric distribution operation during the cooling season.

Cost of sales: Includes the purchased cost of natural gas, electricity and propane commodities, pipeline capacity costs needed to transport and store natural gas, transmission costs for electricity, transportation costs to transport propane purchases to our storage facilities and the direct cost of labor spent on direct revenue-producing activities.

Dekatherms (Dts): A natural gas unit of measurement that measures heating value. A dekatherm (or 10 therms) of gas contains 10,000 British thermal units of heat, or the energy equivalent of burning approximately 1,000 cubic feet of natural gas under normal conditions.

Delmarva natural gas distribution operation: Chesapeake’s Delaware and Maryland divisions.

Delmarva Peninsula: A peninsula in the east coast of the United States of America that includes Delaware and portions of Maryland and Virginia. Chesapeake provides natural gas distribution, transmission and marketing services and propane distribution service to its customers on the Delmarva Peninsula.

Eastern Shore Natural Gas Company (Eastern Shore): A wholly owned natural gas transmission subsidiary of Chesapeake. Eastern Shore operates an interstate pipeline system that transports natural gas from various points in Pennsylvania to customers in southern Pennsylvania and on the Delmarva Peninsula.

Federal Energy Regulatory Commission (FERC): An independent agency of the Federal government that regulates the interstate transmission of electricity, natural gas, and oil. The FERC also reviews proposals to build liquefied natural gas terminals and interstate natural gas pipelines. Eastern Shore is regulated by the FERC.

Florida natural gas distribution operation: Chesapeake’s Florida division and the natural gas operation of Florida Public Utilities Company, including its Indiantown division.

Florida Public Utilities Company (FPU): A wholly owned subsidiary of Chesapeake as of October 28, 2009, the date we acquired FPU through the merger. FPU provides natural gas, electric and propane distribution services in Florida.

Gross margin: A non-GAAP measure, which Chesapeake uses to evaluate the performance of its business segments. Gross margin is calculated by deducting the cost of sales from operating revenues.

Heating Degree-Day (HDD): A measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am next day) is below 65 degrees Fahrenheit. This measurement is used to determine the impact of cold weather on our natural gas, electric and propane distribution operations during the heating season.

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Manufactured Gas Plant (MGP): A site that previously used coal to manufacture gaseous fuel used for industrial, commercial and residential use. Some MGPs are currently undergoing remedial action to remove contamination in the soil and water at or near these sites.

Mark-to-Market: The process of adjusting the carrying value of a position held in our forward contracts and derivative instruments to reflect their current fair value.

Normal Weather: The most recent 10–year average of heating and/or cooling degree-days in a particular geographic area.

Peninsula Pipeline Company, Inc. (Peninsula Pipeline): A wholly owned Florida intrastate pipeline subsidiary of Chesapeake.

Peninsula Energy Services Company, Inc. (PESCO): A wholly owned natural gas marketing subsidiary of Chesapeake. PESCO competes with regulated utilities and other unregulated third-party marketers to sell natural gas supplies directly to commercial and industrial customers through competitively-priced contracts.

ProfitZoom™: A new product developed and launched by BravePoint. ProfitZoom™ is an integrated system encompassing financial, job costing and service management modules, which was designed specifically for the fire protection and specialty contracting industries.

Public Service Commission (PSC): The state agency that regulates the rates and services provided by Chesapeake’s natural gas and electric distribution operations in Delaware, Maryland and Florida. Peninsula Pipeline’s transportation service and rates are also regulated by the Florida PSC.

Remedial Action Plan (RAP): Procedures taken or being considered to remove contaminants from MGPs formerly owned or operated by Chesapeake or FPU.

Xeron, Inc. (Xeron): A wholly owned propane wholesale marketing subsidiary of Chesapeake based in Houston, Texas.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

The accompanying notes are an integral part of these financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Basis of Presentation

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 accounting principles generally accepted in the United States of America (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2011, as amended. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

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

Reclassifications

We reclassified certain amounts in the condensed consolidated statement of income for the three months ended March 31, 2011 and in the condensed consolidated balance sheet as of December 31, 2011 to conform to the current year’s presentation. We also reclassified certain segment information as of December 31, 2011, and for the three months ended March 31, 2011 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

Sale of Assets

In September 2011, Florida Public Utilities Company (“FPU”) entered into an agreement with an unaffiliated entity to sell its office building located in West Palm Beach, Florida for $2.2 million. FPU also entered into a separate agreement to lease office space at a different location in West Palm Beach, which commenced in February 2012. The sale of FPU’s West Palm Beach office building was finalized in February 2012. Some of the approximately 70 employees previously located in the West Palm Beach office building moved into the newly-leased office space, and the remaining employees moved into another nearby operations center, which FPU owns, in West Palm Beach. We treated the West Palm Beach office building as an asset held for sale and it was included in other property, plant and equipment at December 31, 2011 in the accompanying condensed consolidated balance sheet. The West Palm Beach office building had a net carrying value of approximately $1.9 million at the time of the sale. As most of the West Palm Beach office building was considered a property within the regulated businesses, most of the $229,000 gain resulting from the sale was deferred and recorded as a regulatory liability.

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Financial Accounting Standards Board (“FASB”) Statements and Other Authoritative Pronouncements

In September 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-08, “Intangibles—Goodwill and Other (Topic 350) Testing Goodwill for Impairment,” which allows an entity to assess qualitatively whether it is necessary to perform step one of the two-step annual goodwill impairment test. Step one would be required if it is more-likely-than-not that a reporting unit’s fair value is less than its carrying amount. This differs from previous guidance, which required entities to perform step one of the test, at least annually, by comparing the fair value of a reporting unit to its carrying amount. An entity may elect to bypass the qualitative assessment and proceed directly to step one, for any reporting unit, in any period. ASU 2011-08 does not change the guidance on when to test goodwill for impairment. The amendments in ASU 2011-08 are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted the guidance of ASU 2011-08 effective January 1, 2012. Adoption of ASU 2011-08 did not have a material impact on our financial position and results of operations.

In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” Amendments in the ASU do not extend the use of fair value accounting but provide guidance on how it should be applied where its use is already required or permitted by other standards within International Financial Accounting Standards (“IFRS”) or U.S. GAAP. ASU 2011-04 supersedes most of the guidance in Topic 820, although many of the changes are clarifications of existing guidance or wording changes to align with IFRS. Certain amendments in ASU 2011-04 change a particular principle or requirement for measuring fair value or disclosing information about fair value measurements. The amendments in ASU 2011-04 are effective for public entities for interim and annual periods beginning after December 15, 2011, and should be applied prospectively. We adopted the guidance of ASU 2011-04, effective January 1, 2012, and provided additional disclosures as required. Adoption of ASU 2011-04 did not have a material impact on our financial position and results of operations.

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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 (“Eastern Shore”), our natural gas transmission subsidiary, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”); and Peninsula Pipeline Company, Inc. (“Peninsula Pipeline”), our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake’s Florida natural gas distribution division and the natural gas and electric operations of FPU continue to be subject to regulation by the Florida PSC as separate entities.

Delaware

On September 1, 2011, the Delaware division filed with the Delaware PSC its annual Gas Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2011. On September 20, 2011, the Delaware PSC authorized the Delaware division to implement the GSR charges, as filed, on November 1, 2011, on a temporary basis, subject to refund, pending the completion of a full evidentiary hearing and a final decision. We anticipate that the Delaware PSC will render a final decision on the GSR charges in the second or third quarter of 2012.

Maryland

There were no significant regulatory proceedings in Maryland pending during the first quarter.

Florida

“Come-Back” Filing: At the December 6, 2011 agenda conference, the Florida PSC approved, among other things, the inclusion in our rate base in Florida of an acquisition adjustment of $34.2 million and merger-related costs of $2.2 million, to be amortized over a 30-year period and a five-year period, respectively, using the straight-line method beginning in November 2009. The Florida PSC also determined that FPU and Chesapeake’s Florida division did not have any excess earnings in 2010 to be refunded to customers. The Florida PSC issued a consummating order on these matters on January 30, 2012.

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The Florida PSC order allows us to classify the acquisition adjustment and merger-related costs as regulatory assets and include them in our investment, or rate base, when determining our Florida natural gas rates. In addition, our rate of return calculation will be based upon this higher level of investment, which enables us to earn a return on this investment. Pursuant to this order, we reclassified to a regulatory asset at December 31, 2011, $31.7 million of the $34.2 million goodwill, which represents the portion of the goodwill allowed to be recovered in future rates after the effective date of the Florida PSC order. We also recorded as a regulatory asset $18.1 million related to the gross-up of the acquisition adjustment for income tax. An amount of $1.3 million of the $2.2 million of merger-related costs, which represent the portion of the merger-related costs allowed to be recovered in future rates after the effective date of the Florida PSC order, had previously been deferred as a regulatory asset. We also recorded as a regulatory asset $349,000 related to the gross-up of the merger-related costs for income tax. Based upon the effective date and outcome of the order, we began reflecting the amortization as an expense in January 2012, and included $588,000 of the amortization expense in depreciation and amortization in the accompanying condensed consolidated statement of income for the three months ended March 31, 2012. We will record $2.4 million ($1.4 million, net of tax) in amortization expense related to these assets in 2012 and 2013, $2.3 million ($1.4 million, net of tax) in 2014 and $1.8 million ($1.1 million, net of tax) annually, thereafter until 2039. These amortization expenses will be non-cash charges, and the net effect of the recovery will be positive cash flow. Over the long-term, inclusion of the acquisition adjustment and merger-related costs in our rate base and the recovery of these regulatory assets through amortization expense will increase our earnings and cash flows above what we would have been able to achieve absent this regulatory authorization.

In FPU’s future rate proceedings, if it is determined that the level of cost savings supporting recovery of the acquisition adjustment no longer exists, the remaining acquisition adjustment may be partially or entirely disallowed by the Florida PSC. In such event, we will have to expense the corresponding amount of the disallowed acquisition adjustment.

Peninsula Pipeline: At its April 10, 2012 agenda conference, the Florida PSC approved the joint territorial agreement between FPU and the Peoples Gas System division of Tampa Electric Company (“Peoples Gas”) and other related agreements among FPU, Peninsula Pipeline and Peoples Gas. These agreements were executed in January 2012 among the parties to enable Peninsula Pipeline and FPU to expand natural gas service into Nassau and Okeechobee Counties, Florida.

One of the agreements provides for the joint construction, ownership and operation of a pipeline extending approximately 16 miles from the Duval/Nassau County line to Amelia Island in Nassau County, Florida. Under the terms of the agreement, Peninsula Pipeline will own approximately 45 percent of this 16-mile pipeline, and its portion of the estimated project cost is expected to be approximately $5.7 million. Peoples Gas will operate the pipeline, and Peninsula Pipeline will be responsible for its portion of the operation and maintenance expenses of the pipeline based on its ownership percentage. The new jointly-owned pipeline is expected to be completed and placed into service in late 2012 or early 2013. Under a separate agreement, Peninsula Pipeline will contract with Peoples Gas for transportation service from the Peoples Gas interconnection point with an unaffiliated upstream interstate pipeline to the new jointly-owned pipeline. Peninsula Pipeline will then utilize the transportation agreement with Peoples Gas and the jointly-owned pipeline capacity to provide transportation service to FPU for its natural gas distribution service in Nassau County.

Marianna Franchise: On July 7, 2009, the City Commission of Marianna, Florida (the “Marianna Commission”) adopted an ordinance granting a franchise to FPU effective February 1, 2010 for a period not to exceed 10 years for the operation and distribution and/or sale of electric energy (the “Franchise Agreement”). The Franchise Agreement provides that FPU will develop and implement new time-of-use (“TOU”) and interruptible electric power rates, or other similar rates, mutually agreeable to FPU and the City of Marianna (the “City”). The Franchise Agreement further provides for the TOU and interruptible rates to be effective no later than February 17, 2011, and available to all customers within FPU’s Northwest Division, which includes the City. If the rates were not in effect by February 17, 2011, the City would have the right to give notice to FPU within 180 days thereafter of its intent to exercise an option in the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City for the approval of the purchase and the operation by the City of an electric distribution facility. If the purchase is approved by the Marianna Commission and by the referendum, the closing of the purchase must occur within 12 months after the referendum is approved. If the City elects to purchase the Marianna property, the Franchise Agreement requires the City to pay FPU the fair market value for such property as determined by three qualified appraisers. Future financial results would be negatively affected by the loss of earnings generated by FPU from its approximately 3,000 customers in the City.

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In accordance with the terms of the Franchise Agreement, FPU developed TOU and interruptible rates and on December 14, 2010, FPU filed a petition with the Florida PSC for authority to implement such proposed TOU and interruptible rates on or before February 17, 2011. On February 11, 2011, the Florida PSC issued an order approving FPU’s petition for authority to implement the proposed TOU and interruptible rates, which became effective on February 8, 2011. The City objected to the proposed rates and filed a petition protesting the entry of the Florida PSC’s order. On January 24, 2012, the Florida PSC dismissed with prejudice the protest by the City.

On January 26, 2011, FPU filed a petition with the Florida PSC for approval of an amendment to FPU’s Generation Services Agreement entered into between FPU and Gulf Power. The amendment provides for a reduction in the capacity demand quantity, which generates the savings necessary to support the TOU and interruptible rates approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019. By its order dated June 21, 2011, the Florida PSC approved the amendment. On July 12, 2011, the City filed a protest of this decision and requested a hearing on the amendment. On January 24, 2012, the Florida PSC dismissed with prejudice the protest by the City.

The City filed an appeal with the Florida Supreme Court on March 7, 2012 and with the Florida PSC on March 19, 2012. At this time, the City’s appeal is pending before the Florida Supreme Court.

As disclosed in Note 5, “Other Commitments and Contingencies,” to the Condensed Consolidated Financial Statements, the City, on March 2, 2011, filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging breaches of the Franchise Agreement by FPU and seeking a declaratory judgment that the City has the right to exercise its option to purchase FPU’s property in the City in accordance with the terms of the Franchise Agreement. On March 28, 2011, FPU filed its answer to the declaratory action by the City, in which it denied the material allegations by the City and asserted affirmative defenses. The litigation remains pending.

On April 7, 2011, FPU filed a petition for approval of a mid-course reduction to its Northwest Division fuel rates based on two factors: (1) the previously discussed amendment to the Generation Services Agreement with Gulf Power, and (2) a weather-related increase in sales resulting in an accelerated collection of the prior year’s under-recovered costs. Pursuant to its order dated July 5, 2011, the Florida PSC approved the petition, which reduced the fuel rates of FPU’s northwest division, which includes the fuel rates charged to customers in the City.

On February 24, 2012, FPU filed a revised petition for approval of a mid-course reduction to its Northwest Division fuel rates based on a reduction in its supplier’s fuel rates, which would significantly lower purchased power costs for FPU’s Northwest Division in 2012. FPU filed for this mid-course reduction in order to ensure that its customers receive these savings in the most timely manner, and the Florida PSC issued an order on March 27, 2012, approving the mid-course correction reduction in fuel rates, effective April 1, 2012. This further reduced the fuel rates of FPU’s northwest division, which includes the fuel rates charged to customers in the City.

We also had developments in the following regulatory matters in Florida:

On June 21, 2011, FPU, in accordance with the Florida PSC rules, filed its 2011 depreciation study and request for new depreciation rates for its electric distribution operation, effective January 1, 2012. The Florida PSC approved the depreciation study at its January 24, 2012 Agenda Conference. The new approved depreciation rates are expected to reduce annual depreciation expense by approximately $227,000.

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On February 3, 2012, FPU’s natural gas distribution operation and the Florida Division of Chesapeake filed a petition with the Florida PSC for approval of a surcharge to customers for a Gas Reliability Infrastructure Program. We are seeking approval to recover costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic (Polyethylene)) in their respective systems. If the petition is approved, we will replace qualifying mains and services over a 10-year period.

On March 21, 2012 FPU filed a Petition with the Florida PSC for approval of a Negotiated Contract for the purchase of renewable energy power between FPU and an unaffiliated company, which is constructing and installing a new Renewable Generating Facility within FPU’s service territory. If constructed and installed, this facility will be capable of interconnecting and selling power to FPU’s northeast electric division. Overall, this contract will provide a significant benefit to FPU’s northeast electric customers, while also promoting the State of Florida’s goal of encouraging energy independence and the growth of renewable energy projects. If the contract is approved, savings will be passed on to customers through lower fuel costs. The Florida PSC is expected to rule on this contract in June 2012.

Eastern Shore

The following are regulatory activities involving FERC orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system:

Rate Case Filing: On December 30, 2010, Eastern Shore filed with the FERC a base rate proceeding in accordance with the terms of the settlement in its prior base rate proceeding. Conferences involving Eastern Shore, the FERC Staff and other interested parties resulted in a settlement based on an annual cost of service of approximately $29.1 million and a pre-tax return of 13.9 percent. Also included in the settlement is a negotiated rate adjustment, effective November 1, 2011, associated with the phase-in of an additional 15,000 dekatherms (“Dts”) per day of new transportation service on Eastern Shore’s eight-mile extension to interconnect with Texas Eastern Transmission LP’s (“TETLP”) pipeline system. This rate adjustment reduces the rate per Dt of the service on this eight-mile extension by reflecting the increased service of 15,000 Dts per day with no additional revenue. This rate adjustment effectively offsets the increased revenue that would have been generated from the 15,000 Dts per day increase in firm service although Eastern Shore may still collect a commodity charge on the increased volume from the phase-in of service. The settlement also provides a five-year moratorium on the parties’ rights to challenge Eastern Shore’s rates and on Eastern Shore’s right to file a base rate increase but allows Eastern Shore to file for rate adjustments during those five years in the event certain costs related to government-mandated obligations are incurred and Eastern Shore’s pre-tax earnings do not equal or exceed 13.9 percent. The FERC approved the settlement on January 24, 2012.

From July 2011 through October 2011, Eastern Shore adjusted its billing to reflect the rates requested in the base rate proceeding, subject to refund to customers upon the FERC’s approval of the new rates. Commencing in November 2011, Eastern Shore adjusted its billing to reflect the settlement rates, subject to refund to customers upon FERC’s approval of the settlement. At December 31, 2011 Eastern Shore had recorded approximately $1.3 million as a regulatory liability related to the refund due to customers as a result of the settlement; the refund was paid in January and February 2012.

Eastern Shore also had developments in the following FERC matters:

On March 7, 2011, Eastern Shore filed certain tariff sheets to amend the creditworthiness provisions contained in its FERC Gas Tariff. On April 6, 2011, the FERC issued an order accepting and suspending Eastern Shore’s filed tariff revisions, effective April 1, 2011, subject to Eastern Shore submitting certain clarifications with regard to several proposed revisions. Eastern Shore responded with a revised filing on January 13, 2012, which the FERC approved on February 24, 2012.

On March 1, 2012, Eastern Shore filed revised tariff sheets to amend certain provisions contained in the Construction of Facilities and Right of First Refusal sections of its FERC Gas Tariff. On April 6, 2012, the FERC issued an order accepting Eastern Shore’s revised tariff sheet, effective April 1, 2012, subject to Eastern Shore submitting two additional revisions proposed by an intervening party during the review period. Eastern Shore responded with a revised filing on April 16, 2012, which the FERC accepted.

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We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy at current and former operating sites the effect on the environment of the disposal or release of specified substances.

We have participated in the investigation, assessment or remediation, and have exposures at six former 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.

As of March 31, 2012, we had approximately $11.0 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates. Approximately $8.4 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of March 31, 2012. We also had approximately $5.6 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had $246,000 in environmental liabilities as of March 31, 2012, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of March 31, 2012, we had approximately $882,000 in regulatory and other assets for future recovery through Chesapeake’s rates.

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

The following discussion provides a brief summary of each MGP site:

West Palm Beach, Florida

Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated an MGP. FPU is currently implementing a remedial plan approved by the Florida Department of Environmental Protection (“FDEP”) for the east parcel of the West Palm Beach site, which includes relocation and removal of structures and installation of monitoring and testing wells. Estimated costs of remediation for the West Palm Beach site range from approximately $4.7 million to $15.8 million, including costs associated with the relocation of FPU’s operations at this site, which may be necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties. We continue to expect that all costs related to these activities will be recoverable from customers through rates.

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In January 2007, FPU and other responsible parties at the Sanford site (collectively with FPU the “Sanford Group”) signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the Environmental Protection Agency (“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, 2012, FPU has paid $650,000 to the Sanford Group escrow account for its share of the funding requirements.

The total cost of the final remedy is now estimated at approximately $18 million, which includes the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. 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.

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As of March 31, 2012, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of March 31, 2012.

Key West, Florida

FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, the FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two new monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. Prior to completion of the monitoring program, we cannot determine to a reasonable degree of certainty the probable costs to resolve FPU’s liability for the Key West MGP Site, although we do not anticipate the cost to exceed $100,000.

Pensacola, Florida

FPU formerly owned and operated an MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation (“FDOT”). In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action (“NFA”) determination for the site, which must include a requirement for institutional and engineering controls. On December 13, 2011, Gulf Power, the City of Pensacola, FDOT and FPU submitted a draft covenant for institutional and engineering controls for the site to the FDEP. Upon FDEP’s approval and the subsequent recording of the institutional and engineering controls, no further work is expected to be required of the parties. Assuming the FDEP approves the draft institutional and engineering controls, it is anticipated that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.

Salisbury, Maryland

We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized ground-water contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. We anticipate that the remaining costs of the one remaining monitoring well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission the one remaining monitoring well.

Winter Haven, Florida

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a Consent Order entered into with the FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. The recent groundwater sampling results show a continuing reduction in contaminant concentrations from the treatment system, which has been in operation since 2002. Currently, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the remediation system. The total expected cost of operating and monitoring the system is approximately $46,000.

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The current treatment system at the Winter Haven site does not address impacted soils in the southwest corner of the site. In 2010, we obtained a conditional approval from FDEP for a soil excavation plan, and we estimate the cost of this excavation at $250,000; however, this estimate does not include costs associated with dewatering or shoreline stabilization, which would be required to complete the excavation. Because the costs associated with shoreline stabilization and dewatering are likely to be substantial, alternatives to this excavation plan are being evaluated.

FDEP has indicated that we may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures discussed by FDEP could cost as much as $1.0 million. We believe that corrective measures for the sediments are not warranted and intend to oppose any requirement that we undertake corrective measures in the offshore sediments. We have not recorded a liability for sediment remediation, as the final resolution of this matter cannot be predicted at this time.

Other

We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

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Litigation

On March 2, 2011, the City of Marianna (the “City”) filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida. In the complaint, the City alleged three breaches of the Franchise Agreement by FPU: (i) FPU failed to develop and implement TOU and interruptible rates that were mutually agreed to by the City and FPU; (ii) mutually agreed upon TOU and interruptible rates by FPU were not effective or in effect by February 17, 2011; and (iii) FPU did not have such rates available to all of FPU’s customers located within and without the corporate limits of the City. The City is seeking a declaratory judgment allowing it to exercise its option under the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City related to the purchase and the operation by the City of an electric distribution facility. If the purchase is approved by the Marianna Commission and the referendum is approved by the voters, the closing of the purchase must occur within 12 months after the referendum is approved. On March 28, 2011, FPU filed its answer to the declaratory action by the City, in which it denied the material allegations by the City and asserted several affirmative defenses. On August 3, 2011, the City notified FPU that it was formally exercising its option to purchase FPU’s property. On August 31, 2011, FPU advised the City that it has no right to exercise the purchase option under the Franchise Agreement and that FPU would continue to oppose the effort by the City to purchase FPU’s property. In December 2011, the City filed a motion for summary judgment. FPU opposed the motion. On April 3, 2012, the court conducted a hearing on the City’s motion for summary judgment. The court has not yet ruled on the motion, but stated that a ruling would be forthcoming in advance of a mediation scheduled in this matter for May 11, 2012. Trial is set for July 30, 2012. Unless resolved through the mediation, we anticipate that the case will be tried and intend to defend this lawsuit vigorously. We also intend to oppose the adoption of any proposed referendum to approve the purchase of the FPU property by the City.

We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal proceedings and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows.

Natural Gas, Electric and Propane Supply

Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. We have a contract with an energy marketing and risk management company to manage a portion of our natural gas transportation and storage capacity. This contract expires on March 31, 2013.

Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System, LLC (“Gulfstream”). Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including Peninsula Energy Services Company, Inc. (“PESCO”). Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay for the service.

In May 2011, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2012. PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements before the existing agreements expire.

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 results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) fixed charge coverage ratio greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU providing an irrevocable letter of credit. As of March 31, 2012, FPU was in compliance with all of the requirements of its fuel supply contracts.

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Corporate Guarantees

The Board of Directors has authorized the Company to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $45 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily for our propane wholesale marketing subsidiary and our natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the condensed consolidated financial statements when incurred. The aggregate amount guaranteed at March 31, 2012 was $28.6 million, with the guarantees expiring on various dates through February 2013.

Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 12, “Long-Term Debt,” to the condensed consolidated financial statements for further details).

In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2012, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $656,000, which expires on December 2, 2012, as security to satisfy the deductibles under our various outstanding insurance policies. As a result of a change in our primary insurance company in 2010, we renewed the letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2012. There have been no draws on these letters of credit as of March 31, 2012. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

We provided a letter of credit for $2.5 million to TETLP related to the Precedent Agreement with TETLP, which is further described below.

Agreements for Access to New Natural Gas Supplies

On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement with TETLP to secure firm transportation service from TETLP in conjunction with its new expansion project, which is expected to expand TETLP’s mainline system by up to 190,000 Dts/d. The Precedent Agreement provides that, upon satisfaction of certain conditions, the parties will execute two firm transportation service contracts, one for our Delaware division and one for our Maryland division, for 34,100 Dts/d and 15,900 Dts/d, respectively. The 34,100 Dts/d for our Delaware division and the 15,900 Dts/d for our Maryland division reflect the additional volume subscribed to by our divisions above the volume originally agreed to by the parties. These contracts will be effective on the service commencement date of the project, which is currently projected to occur in November 2012. Each firm transportation service contract shall, among other things, provide for: (a) the maximum daily quantity of Dts/d described above; (b) a term of 15 years; (c) a receipt point at Clarington, Ohio; (d) a delivery point at Honey Brook, Pennsylvania; and (e) certain credit standards and requirements for security. Commencement of service and TETLP’s and our rights and obligations under the two firm transportation service contracts are subject to satisfaction of various conditions specified in the Precedent Agreement.

Our Delmarva natural gas supplies have been received primarily from the Gulf of Mexico natural gas production region and have been transported through three interstate upstream pipelines, two of which interconnect directly with Eastern Shore’s transmission system. The new firm transportation service contracts between our Delaware and Maryland divisions and TETLP will provide gas supply through an additional direct interconnection with Eastern Shore’s transmission system and provide access to new sources of supply from other natural gas production regions, including the Appalachian production region, thereby providing increased reliability and diversity of supply. They will also provide our Delaware and Maryland divisions with additional upstream transportation capacity to meet current customer demands and to plan for sustainable growth.

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The Precedent Agreement provides that the parties shall promptly meet and work in good faith to negotiate a mutually acceptable reservation rate. Failure to agree upon a mutually acceptable reservation rate would have enabled either party to terminate the Precedent Agreement, and would have subjected us to reimburse TETLP for certain pre-construction costs; however, on July 2, 2010, our Delaware and Maryland divisions executed the required reservation rate agreements with TETLP.

The Precedent Agreement requires us to reimburse TETLP for our proportionate share of TETLP’s pre-service costs incurred to date, if we terminate the Precedent Agreement, are unwilling or unable to perform our material duties and obligations thereunder, or take certain other actions whereby TETLP is unable to obtain the authorizations and exemptions required for this project. If such termination were to occur, we estimate that our proportionate share of TETLP’s pre-service costs could be approximately $8.5 million as of March 31, 2012. If we were to terminate the Precedent Agreement after TETLP completed its construction of all facilities, which is expected to be in the fourth quarter of 2012, our proportionate share could be as much as approximately $50 million. The actual amount of our proportionate share of such costs could differ significantly and would ultimately be based on the level of pre-service costs at the time of any potential termination. As our Delaware and Maryland divisions have now executed the required reservation rate agreements with TETLP, we believe that the likelihood of terminating the Precedent Agreement and having to reimburse TETLP for our proportionate share of TETLP’s pre-service costs is remote.

As previously mentioned, we have provided a letter of credit to TETLP for $2.5 million, which is the maximum amount required under the Precedent Agreement with TETLP.

On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement with Eastern Shore to extend its mainline by eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. Eastern Shore completed the extension project in December 2010 and commenced the service in January 2011. The rate for the transportation service on this extension is Eastern Shore’s current tariff rate for service in that area.

In November 2011, TETLP obtained the necessary authorizations from the FERC for construction and operation of its portion of the project. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or Eastern Shore.

As the Eastern Shore and TETLP firm transportation services commence, our Delaware and Maryland divisions incur costs for those services based on the agreed and FERC-approved reservation rates, which will become an integral component of the costs associated with providing natural gas supplies to our Delaware and Maryland divisions and will be included in the annual GSR filings for each of our respective divisions.

Non-income-based Taxes

From time to time, we are subject to various audits and reviews by the states and other regulatory authorities regarding non-income-based taxes. We are currently undergoing sales tax audits in Florida. As of March 31, 2012 and December 31, 2011, we maintained accruals of $173,000 and $307,000, respectively, related to additional sales taxes and gross receipts taxes that we may owe to various states.

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We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations comprise three operating segments:

The following table presents information about our reportable segments.