Rates and Other Regulatory Activities	12 Months Ended
Dec. 31, 2011
Rates and Other Regulatory Activities [Abstract]
RATES AND OTHER REGULATORY ACTIVITIES	O. RATES AND OTHER REGULATORY ACTIVITIES Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSCs; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric operations continue to be subject to regulation by the Florida PSC as separate entities. *Delaware* Capacity Release: On September 2, 2008, our Delaware division filed with the Delaware PSC its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, which included the Delaware PSC, our Delaware division and the Division of the Public Advocate. As part of the settlement agreement, the parties agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, PESCO. On January 8, 2010, the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which he recommended, among other things, that the Delaware PSC require the Delaware division to refund to its firm service customers the difference between what the Delaware division would have received had the capacity released to PESCO been priced at the maximum tariff rates under asymmetrical pricing principles and the amount actually received by the Delaware division for capacity released to PESCO. The Hearing Examiner also recommended that the Delaware PSC require us to adhere to asymmetrical pricing principles in all future capacity releases by the Delaware division to PESCO, if any. If the Hearing Examiner’s refund recommendation for past capacity releases had ultimately been approved without modification by the Delaware PSC, the Delaware division would have had to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division paid for long-term capacity, which we estimated to be approximately $700,000, even though the temporary releases were made at lower rates based on competitive bidding procedures required by the FERC’s capacity release rules. On February 18, 2010, we filed exceptions to the Hearing Examiner’s recommendations. At the hearing on March 30, 2010, the Delaware PSC agreed with us that the Delaware division had been releasing capacity based on a previous settlement approved by the Delaware PSC and, therefore, did not require the Delaware division to issue any refunds for past capacity releases. The Delaware PSC, however, required the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO until a more appropriate pricing methodology is developed and approved. The Delaware PSC issued an order on May 18, 2010, elaborating its decisions at the March hearing and directing the parties to reconvene in a separate docket to determine if a pricing methodology other than asymmetrical pricing principles should apply to future capacity releases by the Delaware division to PESCO. On June 17, 2010, the Division of the Public Advocate filed an appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to refunds for past capacity releases. On June 28, 2010, the Delaware division filed a Notice of Cross Appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to requiring the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO. On June 13, 2011, the Delaware Superior Court issued its decision affirming all aspects of the Delaware PSC’s Order on May 18, 2010, which included its decision not to require the Delaware division to issue any refunds for past releases. On June 29, 2011, the Delaware Attorney General filed an appeal with the Delaware Supreme Court, asking it to review the Delaware Superior Court’s decision affirming the Delaware PSC decision with regard to refunds for past capacity releases. On July 12, 2011, the Delaware division filed a Notice of Cross Appeal with the Delaware Supreme Court, asking it to overturn the Superior Court’s decision with regard to the Delaware PSC’s decision on future capacity releases to PESCO. On August 3, 2011, the Delaware Attorney General filed a Notice of Dismissal with the Supreme Court withdrawing its appeal. Consequently, on August 4, 2011, the Delaware division filed a Notice of Dismissal with the Supreme Court to withdrawal its cross appeal and the filing of the Notice of Dismissal eliminates any potential liability related to potential refunds for past capacity releases and the matter is officially closed. The parties have not yet opened a separate docket to determine an alternative pricing methodology for future capacity releases by the Delaware division to PESCO or any other affiliates. Our Delaware division also had developments in the following matters with the Delaware PSC: On September 1, 2010, the Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2010. On September 21, 2010, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2010, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware PSC granted approval of the GSR charges at its regularly scheduled meeting on June 7, 2011. On March 10, 2011, the Delaware division filed with the Delaware PSC an application requesting approval to guarantee certain debt of FPU. Specifically, the Delaware division sought approval to execute a Seventeenth Supplemental Indenture, in which Chesapeake guarantees the payment of certain debt of FPU and FPU is permitted to deliver Chesapeake’s consolidated financial statements in lieu of FPU’s stand-alone financial statements to satisfy certain covenants within the indentures of FPU’s debt. The Delaware PSC granted approval of the guarantee of certain debt of FPU at its regularly scheduled meeting on April 4, 2011. On September 1, 2011, the Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2011. On September 20, 2011, the Delaware PSC authorized the Delaware division to implement the GSR charges, as filed, on November 1, 2011, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. We anticipate that the Delaware PSC will render a final decision on the GSR charges in the second or third quarter of 2012. On September 19, 2011, the Delaware division filed with the Delaware PSC two applications seeking approval to begin charging customers for the franchise fees imposed upon the Delaware division by the City of Lewes, Delaware and the Town of Dagsboro, Delaware. On October 3, 2011, the Delaware PSC issued orders on both matters, effectively opening the proceedings and setting evidentiary hearings for November 8, 2011. The Delaware PSC granted approval for the franchise fees at its regularly scheduled meeting on November 8, 2011. *Maryland* On December 14, 2010, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Maryland division during the 12 months ended September 30, 2010. No issues were raised at the hearing, and on December 20, 2010, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. This proposed Order became a final Order of the Maryland PSC on January 20, 2011. On March 2, 2011, the Maryland division filed with the Maryland PSC an application for the approval of a franchise executed between the Maryland division and the Board of County Commissioners of Cecil County, Maryland. In this franchise agreement, the County granted the Maryland division a 50-year, non-exclusive franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Cecil County. On April 11, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Cecil County, subject to no adverse comments being received within 30 days after the issuance of the Order. On May 10, 2011, comments opposing the application were filed by Pivotal Utility Holdings, Inc. d/b/a Elkton Gas (“Pivotal”). Pivotal also provides natural gas service to customers in a portion of Cecil County. On June 8, 2011, the Maryland PSC granted the Maryland division the authority to exercise its franchise in a majority of the area requested in the Maryland division’s application. The approval for a small portion of the area within the requested franchise area, which is closest to the area served by Pivotal, was withheld until an evidentiary hearing could be convened. On August 16, 2011, the Maryland division submitted testimony in support of its proposed boundary with Pivotal. On September 29, 2011, the parties in the proceeding (Maryland division, Pivotal, Maryland PSC Staff, and the Office of People’s Counsel) submitted a proposed settlement agreement for the Maryland PSC’s consideration that outlined an agreed upon boundary between the Maryland division and Pivotal in the small portion of Cecil County that was subject to further review. On October 12, 2011, the assigned Public Utility Law Judge in this matter issued a Proposed Order, approving the proposed settlement agreement as submitted by the parties in the proceeding. The Proposed Order became a final order of the Maryland PSC on November 15, 2011. On May 17, 2011, the Maryland division filed with the Maryland PSC an application for approval of a franchise executed between the Maryland division and the Board of County Commissioners for Worcester County, Maryland. In this franchise agreement, the County granted the Maryland division a 25-year, non-exclusive franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Worcester County. On June 14, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Worcester County, subject to no adverse comments being received within 20 days after the issuance of the Order. No adverse comments were filed within the comment period, and the order became effective on July 5, 2011. On August 12, 2011, the Maryland division submitted a request to the Maryland PSC for approval of a negotiated delivery service rate for a large customer on its system. At its regularly scheduled meeting on September 21, 2011, the Maryland PSC granted approval of the negotiated delivery service rate effective for bills rendered after that date. On December 12, 2011, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Maryland division during the 12 months ended September 30, 2011. No issues were raised at the hearing, and on December 13, 2011, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. This proposed Order became a final Order of the Maryland PSC on December 29, 2011. *Florida* “Come-Back” Filing: As part of our 2010 rate case settlement in Florida, the Florida PSC required us to submit a “Come-Back” filing, detailing all known benefits, synergies, cost savings and cost increases resulting from the merger with FPU. We submitted this filing on April 29, 2011, and requested the recovery, through rates, of approximately $34.2 million in acquisition adjustment (the price paid in excess of the book value) and $2.2 million in merger-related costs. In the past, the Florida PSC has allowed recovery of an acquisition adjustment under certain circumstances to provide an incentive for larger utilities to purchase smaller utilities. The Florida PSC requires a company seeking recovery of the acquisition adjustment and merger-related costs to demonstrate that customers will benefit from the acquisition. They use the following five factor test to determine if the customers are benefiting from the transaction: (a) increased quality of service; (b) lower operating costs; (c) increased ability to attract capital for improvements; (d) lower overall cost of capital; and (e) more professional and experienced managerial, financial, technical and operational resources. With respect to lower costs, the Florida PSC effectively requires that the synergies be sufficient to offset the rate impact of the recovery of the acquisition adjustment and merger-related costs. At the December 6, 2011 agenda conference, the Florida PSC approved the following: (a) FPU and the Florida division of Chesapeake have complied with the reporting requirements in the 2010 rate case settlement; (b) FPU is authorized to reflect an acquisition adjustment of $34.2 million, to be amortized over a 30-year period using the straight-line method beginning in November 2009; (c) FPU is authorized to reflect a regulatory asset of $2.2 million for the merger-related costs, to be amortized over a five-year period using the straight-line method beginning in November 2009; (d) FPU and the Florida division of Chesapeake are not permitted to consolidate the earnings surveillance reporting and accounting records until such time as the rates and tariffs are combined; (e) FPU and the Florida division of Chesapeake are not permitted to establish a combined benchmark for the purpose of evaluating incremental cost increases in their future rate proceedings until those entities are functioning as a single utility for regulatory purposes; and (f) FPU and the Florida division of Chesapeake do not have any 2010 excess earnings to be refunded to customers. The Florida PSC Order allows us to classify the acquisition adjustment and merger-related costs as regulatory assets and include them in our investment, or rate base, when determining our Florida natural gas rates. Additionally, our rate of return calculation will be based upon this higher level of investment, which effectively enables us to earn a return on this investment. Pursuant to the Order, we reclassified to a regulatory asset at December 31, 2011, $31.7 million of the $34.2 million goodwill, which represents the portion of the goodwill allowed to be recovered in future rates after the effective date of the Florida PSC Order. We also recorded as a regulatory asset $18.1 million related to the gross-up of the acquisition adjustment for income tax. The $1.3 million of the $2.2 million of merger-related costs, which represent the portion of the merger-related costs allowed to be recovered in future rates after the effective date of the Florida PSC Order, had previously been deferred as a regulatory asset. We also recorded as a regulatory asset $349,000 related to the gross-up of the merger-related costs for income tax. As a result of this Order, we will record $2.4 million ($1.4 million, net of tax) in amortization expense related to these assets in 2012 and 2013, $2.3 million ($1.4 million, net of tax) in 2014 and $1.8 million ($1.1 million, net of tax) annually, thereafter until 2039. These amortization expenses will be a non-cash charge, and the net effect of the recovery will be positive cash flow. Over the long-term, however, the inclusion of the acquisition adjustment and merger-related costs in our rate base and the recovery of these regulatory assets through amortization expense will increase our earnings and cash flows above what we would have otherwise been able to achieve. In FPU’s future rate proceedings, if it is determined that the level of cost savings supporting the lower operating costs in its request for the recovery of the acquisition adjustment no longer exists, the remaining acquisition adjustment may be partially or entirely disallowed by the Florida PSC. In such event, we will have to expense the corresponding amount of the disallowed acquisition adjustment. The Florida PSC Order also resulted in the reversal in December 2011, of the $750,000 regulatory accrual, which was recorded in 2010 based on management’s assessment of FPU’s earnings and regulatory risk to its earnings associated with possible Florida PSC action related to our requested recovery and the matters set forth in this “Come-Back” filing. The reversal of the $750,000 regulatory accrual was reflected in operating revenue in 2011 in the accompanying consolidated statements of income. Peninsula Pipeline: On September 19, 2011, Peninsula Pipeline filed a petition seeking the Florida PSC’s approval of a Firm Transportation Agreement (“FTA”) between Peninsula Pipeline and FPU, an affiliated company, in accordance with its tariff. On February 8, 2012 Peninsula Pipeline filed a petition with the Florida PSC seeking approval of an amended and revised FTA between Peninsula Pipeline and FPU. This amended and revised FTA provides for upstream interconnection of Peninsula Pipeline’s facilities with the Peoples Gas’ distribution facilities at the Duval/Nassau County line and several downstream interconnections with FPU’s facilities. This amended and revised FTA replaces, in its entirety, the agreement originally filed on September 19, 2011. The revised and amended FTA comes as a result of negotiations between Peoples Gas, FPU, and Peninsula Pipeline, which resulted in a territorial agreement and related service arrangements described below. In January 2012, Peninsula Pipeline executed an agreement with Peoples Gas for the joint construction, ownership and operation of an approximately 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida. Under the terms of the agreement, Peninsula Pipeline will own approximately 45 percent of this 16-mile pipeline. Peninsula Pipeline’s portion of the estimated project cost is $5.7 million. Peoples Gas will operate the pipeline and Peninsula Pipeline will be responsible for its portion of the operation and maintenance expenses of the pipeline based on its ownership percentage. Peninsula Pipeline will contract with Peoples Gas for capacity from the unaffiliated upstream interstate pipeline to this jointly-owned pipeline. Peninsula Pipeline will utilize both the capacity contracted with Peoples Gas and the capacity on the new jointly-owned pipeline to provide transportation service to FPU for its natural gas distribution service in Nassau County. The new jointly-owned pipeline is expected to be completed and placed into service in the second half of 2012. Marianna Franchise: On July 7, 2009, the Marianna Commission adopted an ordinance granting a franchise to FPU effective February 1, 2010 for a period not to exceed 10 years for the operation and distribution and/or sale of electric energy (the “Franchise Agreement”). The Franchise Agreement provides that FPU will develop and implement new TOU and interruptible electric power rates, or other similar rates, mutually agreeable to FPU and the City of Marianna. The Franchise Agreement further provides for the TOU and interruptible rates to be effective no later than February 17, 2011, and available to all customers within FPU’s Northwest Division, which includes the City of Marianna. If the rates were not in effect by February 17, 2011, the City of Marianna would have the right to give notice to FPU within 180 days thereafter of its intent to exercise an option in the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City of Marianna for the approval of the purchase and the operation by the City of Marianna of an electric distribution facility. If the purchase is approved by the Marianna Commission and by the referendum, the closing of the purchase must occur within 12 months after the referendum is approved. If the City of Marianna elects to purchase the Marianna property, the Franchise Agreement requires the City of Marianna to pay FPU the fair market value for such property as determined by three qualified appraisers. Future financial results would be negatively affected by the loss of earnings generated by FPU from its approximately 3,000 customers in the City under the Franchise Agreement. In accordance with the terms of the Franchise Agreement, FPU developed TOU and interruptible rates and on December 14, 2010, FPU filed a petition with the Florida PSC for authority to implement such proposed TOU and interruptible rates on or before February 17, 2011. On February 11, 2011, the Florida PSC issued an Order approving FPU’s petition for authority to implement the proposed TOU and interruptible rates, which became effective on February 8, 2011. The City of Marianna objected to the proposed rates and filed a petition protesting the entry of the Florida PSC’s Order. On January 24, 2012, the Florida PSC dismissed with prejudice the protest by the City of Marianna. On January 26, 2011, FPU filed a petition with the Florida PSC for approval of an amendment to FPU’s Generation Services Agreement entered into between FPU and Gulf Power. The amendment provides for a reduction in the capacity demand quantity, which generates the savings necessary to support the TOU and interruptible rates approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019. Pursuant to its Order dated June 21, 2011, the Florida PSC approved the amendment. On July 12, 2011, the City of Marianna filed a protest of this decision and requested a hearing on the amendment. On January 24, 2012, the Florida PSC dismissed with prejudice the protest by the City of Marianna. On April 7, 2011, FPU filed a petition for approval of a mid-course reduction to its Northwest Division fuel rates based on two factors: (1) the previously discussed amendment to the Generation Services Agreement with Gulf Power, and (2) a weather-related increase in sales resulting in an accelerated collection of the prior year’s under-recovered costs. Pursuant to its Order dated July 5, 2011, the Florida PSC approved the petition, which reduced the fuel rates of FPU’s northwest division. On February 24, 2012, FPU filed a revised petition for approval of a mid-course reduction to its Northwest Division fuel rates based on a mid-course reduction to its supplier’s fuel rates. FPU expects to significantly lower purchased power costs for its Northwest Division in 2012 as a result of this reduction by the supplier. In order to ensure that its customers receive these significant savings in the most timely manner, FPU filed this petition. We anticipate Florida PSC’s decision on this petition in April 2012. As disclosed in Note Q, “Other Commitments and Contingencies,” to the Consolidated Financial Statements, the City of Marianna, on March 2, 2011, filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging breaches of the Franchise Agreement by FPU and seeking a declaratory judgment that the City of Marianna has the right to exercise its option to purchase FPU’s property in the City of Marianna in accordance with the terms of the Franchise Agreement. On March 28, 2011, FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the material allegation by the City of Marianna and asserted affirmative defenses. The litigation remains pending and discovery is still underway. We also had developments in the following regulatory matters in Florida: On June 21, 2011, FPU, in accordance with the Florida PSC rules, filed its 2011 depreciation study and request for new depreciation rates effective January 1, 2012 for its electric distribution operation. The Florida PSC approved the depreciation study at its January 24, 2012 Agenda Conference. The new approved depreciation rates are expected to reduce annual depreciation expense by approximately $227,000. On February 3, 2012, FPU’s natural gas distribution operation and the Florida Division of Chesapeake filed a petition with the Florida PSC for approval of a surcharge to customers for a Gas Reliability Infrastructure Program. We are seeking approval to recover costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic (Polyethylene)) in their respective systems. If the petition is approved, we will replace qualifying mains and services over a 10-year period. *Eastern Shore* The following are regulatory activities involving the FERC Orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system: Energylink Expansion Project: In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural Gas terminal in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would interconnect with Eastern Shore’s existing facilities in Sussex County, Delaware. In April 2009, Eastern Shore terminated this project based on increased construction costs over its original projection. As approved by the FERC, Eastern Shore initiated billing to recover approximately $3.2 million of costs incurred in connection with this project and the related cost of capital over a period of 20 years in accordance with the terms of the precedent agreements executed with the two participating customers. One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions. During 2010, Eastern Shore and the participating customers negotiated to reduce the recovery period of this cost from 20 years to five years. On January 27, 2011, Eastern Shore filed with the FERC the request to amend the cost recovery period, which was approved by the FERC on February 14, 2011. Eastern Shore revised its billing to reflect the five-year surcharge, effective March 1, 2011. Rate Case Filing: On December 30, 2010, Eastern Shore filed with the FERC a base rate proceeding in accordance with the terms of the settlement in its prior base rate proceeding. The rate filing reflected increases in operating and maintenance expenses, depreciation expense, and a return on existing and new gas plant facilities expected to be placed into service before June 30, 2011. The FERC issued a notice of the filing on January 3, 2011. Protests were received from several interested parties, and other parties intervened in the proceeding. On January 31, 2011, the FERC issued its Order accepting the filing and suspending its effectiveness for the full five-month period permitted under the Natural Gas Act. The discovery process commenced on February 22, 2011, and the FERC Staff performed an on-site audit on March 16-17, 2011. Subsequent to the on-site audit, settlement conferences involving Eastern Shore, the FERC Staff and other interested parties resulted in a settlement, which provides a cost of service of approximately $29.1 million and a pre-tax return of 13.9 percent. Also included in the settlement is a negotiated rate adjustment, effective November 1, 2011, associated with the phase-in of an additional 15,000 Dts/d of new transportation service on Eastern Shore’s eight-mile extension to interconnect with TETLP’s pipeline system. This rate adjustment reduces the rate per Dt of the service on this eight-mile extension by reflecting the increased service of 15,000 Dts/d with no additional revenue. This rate adjustment effectively offsets the increased revenue that would have been generated from the 15,000 Dts/d increase in firm service although Eastern Shore may still benefit from the increased commodity charge on the increased volume from the phase-in of service. The settlement also provides a five-year moratorium on the parties’ rights to challenge Eastern Shore’s rates and on Eastern Shore’s right to file a base rate increase. The settlement allows Eastern Shore to file for rate adjustments during those five years in the event certain costs related to government-mandated obligations are incurred and Eastern Shore’s pre-tax earnings do not equal or exceed 13.9 percent. The FERC approved the settlement on January 24, 2011. From July 2011 through October 2011, Eastern Shore adjusted its billing to reflect the rates requested in the base rate proceeding, subject to refund to customers upon the FERC’s approval of the new rates. From November 2011, Eastern Shore adjusted its billing to reflect the settlement rates, subject to refund to customers upon FERC’s approval of the settlement. As of December 31, 2011, Eastern Shore has recorded approximately $1.3 million as a regulatory liability related to the refund due to customers as a result of the settlement, which refund was paid in January and February 2012. Mainline Extension Project: On April 1, 2011, Eastern Shore filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 3,405 Dts/d of natural gas to an existing industrial customer. The FERC published notice of this filing on April 7, 2011. The 60-day comment period subsequent to the FERC notice expired on June 6, 2011, and the requested authorization became effective on that date. On April 28, 2011, Eastern Shore filed a notice of intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 6,250 Dts/d of natural gas to Chesapeake’s Delaware and Maryland divisions and Eastern Shore Gas, an unaffiliated provider of piped propane service in Maryland. The FERC published notice of this filing on May 12, 2011, and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective. Also on April 28, 2011, Eastern Shore filed a notice of intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 4,070 Dts/d of natural gas to Chesapeake’s Maryland division to provide new natural gas service in Cecil County, Maryland. The FERC published notice of this filing on May 12, 2011, and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective. Eastern Shore also had developments in the following FERC matters: On March 7, 2011, Eastern Shore filed certain tariff sheets to amend the creditworthiness provisions contained in its FERC Gas Tariff. On April 6, 2011, the FERC issued an Order accepting and suspending Eastern Shore’s filed tariff revisions for an effective date of April 1, 2011, subject to Eastern Shore submitting certain clarifications with regard to several proposed revisions. On April 18, 2011, Eastern Shore submitted its annual Interruptible Revenue Sharing Report to the FERC. Eastern Shore reported in this filing that its interruptible revenue did not exceed its annual threshold amount, which would trigger sharing of excess interruptible revenues with its firm service customers. Consequently, Eastern Shore is not required to refund to its firm customers any portion of its interruptible revenue received for the period April 2010 through March 2011. On June 24, 2011, Eastern Shore filed certain tariff sheets to amend the General Terms and Conditions and the pro forma FTA contained in its FERC Gas Tariff to allow for specification of minimum delivery pressures and maximum hourly quantity. The FERC published the notice of this filing on June 27, 2011, and no protests or adverse comments opposing this filing were submitted. On July 15, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective July 24, 2011. On August 15, 2011, Eastern Shore filed certain tariff sheets to update certain Delivery Point Area definitions contained in its FERC Gas Tariff. The FERC published notice of this filing on August 16, 2011, and no protests or adverse comments opposing this filing were submitted. On September 13, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective September 14, 2011. On September 7, 2011, Eastern Shore filed certain tariff sheets to reflect a decrease in the Annual Charge Adjustment, which is a surcharge designed to recover applicable program costs incurred by the FERC to discharge its jurisdictional responsibilities. The surcharge decreased from $0.0019 per Dt to $0.0018 per Dt. The FERC published the notice of this filing on September 8, 2011, and no protests or adverse comments opposing this filing were submitted. On September 27, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective October 1, 2011.

Rates and Other Regulatory Activities

12 Months Ended

Dec. 31, 2011

Rates and Other Regulatory Activities [Abstract]

O. RATES AND OTHER REGULATORY ACTIVITIES

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSCs; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric operations continue to be subject to regulation by the Florida PSC as separate entities.

Delaware

Capacity Release: On September 2, 2008, our Delaware division filed with the Delaware PSC its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, which included the Delaware PSC, our Delaware division and the Division of the Public Advocate. As part of the settlement agreement, the parties agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, PESCO. On January 8, 2010, the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which he recommended, among other things, that the Delaware PSC require the Delaware division to refund to its firm service customers the difference between what the Delaware division would have received had the capacity released to PESCO been priced at the maximum tariff rates under asymmetrical pricing principles and the amount actually received by the Delaware division for capacity released to PESCO. The Hearing Examiner also recommended that the Delaware PSC require us to adhere to asymmetrical pricing principles in all future capacity releases by the Delaware division to PESCO, if any. If the Hearing Examiner’s refund recommendation for past capacity releases had ultimately been approved without modification by the Delaware PSC, the Delaware division would have had to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division paid for long-term capacity, which we estimated to be approximately $700,000, even though the temporary releases were made at lower rates based on competitive bidding procedures required by the FERC’s capacity release rules. On February 18, 2010, we filed exceptions to the Hearing Examiner’s recommendations.

At the hearing on March 30, 2010, the Delaware PSC agreed with us that the Delaware division had been releasing capacity based on a previous settlement approved by the Delaware PSC and, therefore, did not require the Delaware division to issue any refunds for past capacity releases. The Delaware PSC, however, required the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO until a more appropriate pricing methodology is developed and approved. The Delaware PSC issued an order on May 18, 2010, elaborating its decisions at the March hearing and directing the parties to reconvene in a separate docket to determine if a pricing methodology other than asymmetrical pricing principles should apply to future capacity releases by the Delaware division to PESCO.

On June 17, 2010, the Division of the Public Advocate filed an appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to refunds for past capacity releases. On June 28, 2010, the Delaware division filed a Notice of Cross Appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to requiring the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO. On June 13, 2011, the Delaware Superior Court issued its decision affirming all aspects of the Delaware PSC’s Order on May 18, 2010, which included its decision not to require the Delaware division to issue any refunds for past releases.

On June 29, 2011, the Delaware Attorney General filed an appeal with the Delaware Supreme Court, asking it to review the Delaware Superior Court’s decision affirming the Delaware PSC decision with regard to refunds for past capacity releases. On July 12, 2011, the Delaware division filed a Notice of Cross Appeal with the Delaware Supreme Court, asking it to overturn the Superior Court’s decision with regard to the Delaware PSC’s decision on future capacity releases to PESCO. On August 3, 2011, the Delaware Attorney General filed a Notice of Dismissal with the Supreme Court withdrawing its appeal. Consequently, on August 4, 2011, the Delaware division filed a Notice of Dismissal with the Supreme Court to withdrawal its cross appeal and the filing of the Notice of Dismissal eliminates any potential liability related to potential refunds for past capacity releases and the matter is officially closed. The parties have not yet opened a separate docket to determine an alternative pricing methodology for future capacity releases by the Delaware division to PESCO or any other affiliates.

Our Delaware division also had developments in the following matters with the Delaware PSC:

On September 1, 2010, the Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2010. On September 21, 2010, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2010, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware PSC granted approval of the GSR charges at its regularly scheduled meeting on June 7, 2011.

On March 10, 2011, the Delaware division filed with the Delaware PSC an application requesting approval to guarantee certain debt of FPU. Specifically, the Delaware division sought approval to execute a Seventeenth Supplemental Indenture, in which Chesapeake guarantees the payment of certain debt of FPU and FPU is permitted to deliver Chesapeake’s consolidated financial statements in lieu of FPU’s stand-alone financial statements to satisfy certain covenants within the indentures of FPU’s debt. The Delaware PSC granted approval of the guarantee of certain debt of FPU at its regularly scheduled meeting on April 4, 2011.

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

On September 19, 2011, the Delaware division filed with the Delaware PSC two applications seeking approval to begin charging customers for the franchise fees imposed upon the Delaware division by the City of Lewes, Delaware and the Town of Dagsboro, Delaware. On October 3, 2011, the Delaware PSC issued orders on both matters, effectively opening the proceedings and setting evidentiary hearings for November 8, 2011. The Delaware PSC granted approval for the franchise fees at its regularly scheduled meeting on November 8, 2011.

Maryland

On December 14, 2010, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Maryland division during the 12 months ended September 30, 2010. No issues were raised at the hearing, and on December 20, 2010, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. This proposed Order became a final Order of the Maryland PSC on January 20, 2011.

On March 2, 2011, the Maryland division filed with the Maryland PSC an application for the approval of a franchise executed between the Maryland division and the Board of County Commissioners of Cecil County, Maryland. In this franchise agreement, the County granted the Maryland division a 50-year, non-exclusive franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Cecil County. On April 11, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Cecil County, subject to no adverse comments being received within 30 days after the issuance of the Order. On May 10, 2011, comments opposing the application were filed by Pivotal Utility Holdings, Inc. d/b/a Elkton Gas (“Pivotal”). Pivotal also provides natural gas service to customers in a portion of Cecil County. On June 8, 2011, the Maryland PSC granted the Maryland division the authority to exercise its franchise in a majority of the area requested in the Maryland division’s application. The approval for a small portion of the area within the requested franchise area, which is closest to the area served by Pivotal, was withheld until an evidentiary hearing could be convened. On August 16, 2011, the Maryland division submitted testimony in support of its proposed boundary with Pivotal. On September 29, 2011, the parties in the proceeding (Maryland division, Pivotal, Maryland PSC Staff, and the Office of People’s Counsel) submitted a proposed settlement agreement for the Maryland PSC’s consideration that outlined an agreed upon boundary between the Maryland division and Pivotal in the small portion of Cecil County that was subject to further review. On October 12, 2011, the assigned Public Utility Law Judge in this matter issued a Proposed Order, approving the proposed settlement agreement as submitted by the parties in the proceeding. The Proposed Order became a final order of the Maryland PSC on November 15, 2011.

On May 17, 2011, the Maryland division filed with the Maryland PSC an application for approval of a franchise executed between the Maryland division and the Board of County Commissioners for Worcester County, Maryland. In this franchise agreement, the County granted the Maryland division a 25-year, non-exclusive franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Worcester County. On June 14, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Worcester County, subject to no adverse comments being received within 20 days after the issuance of the Order. No adverse comments were filed within the comment period, and the order became effective on July 5, 2011.

On August 12, 2011, the Maryland division submitted a request to the Maryland PSC for approval of a negotiated delivery service rate for a large customer on its system. At its regularly scheduled meeting on September 21, 2011, the Maryland PSC granted approval of the negotiated delivery service rate effective for bills rendered after that date.

On December 12, 2011, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Maryland division during the 12 months ended September 30, 2011. No issues were raised at the hearing, and on December 13, 2011, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. This proposed Order became a final Order of the Maryland PSC on December 29, 2011.

Florida

“Come-Back” Filing: As part of our 2010 rate case settlement in Florida, the Florida PSC required us to submit a “Come-Back” filing, detailing all known benefits, synergies, cost savings and cost increases resulting from the merger with FPU. We submitted this filing on April 29, 2011, and requested the recovery, through rates, of approximately $34.2 million in acquisition adjustment (the price paid in excess of the book value) and $2.2 million in merger-related costs. In the past, the Florida PSC has allowed recovery of an acquisition adjustment under certain circumstances to provide an incentive for larger utilities to purchase smaller utilities. The Florida PSC requires a company seeking recovery of the acquisition adjustment and merger-related costs to demonstrate that customers will benefit from the acquisition. They use the following five factor test to determine if the customers are benefiting from the transaction: (a) increased quality of service; (b) lower operating costs; (c) increased ability to attract capital for improvements; (d) lower overall cost of capital; and (e) more professional and experienced managerial, financial, technical and operational resources. With respect to lower costs, the Florida PSC effectively requires that the synergies be sufficient to offset the rate impact of the recovery of the acquisition adjustment and merger-related costs.

At the December 6, 2011 agenda conference, the Florida PSC approved the following: (a) FPU and the Florida division of Chesapeake have complied with the reporting requirements in the 2010 rate case settlement; (b) FPU is authorized to reflect an acquisition adjustment of $34.2 million, to be amortized over a 30-year period using the straight-line method beginning in November 2009; (c) FPU is authorized to reflect a regulatory asset of $2.2 million for the merger-related costs, to be amortized over a five-year period using the straight-line method beginning in November 2009; (d) FPU and the Florida division of Chesapeake are not permitted to consolidate the earnings surveillance reporting and accounting records until such time as the rates and tariffs are combined; (e) FPU and the Florida division of Chesapeake are not permitted to establish a combined benchmark for the purpose of evaluating incremental cost increases in their future rate proceedings until those entities are functioning as a single utility for regulatory purposes; and (f) FPU and the Florida division of Chesapeake do not have any 2010 excess earnings to be refunded to customers.

The Florida PSC Order allows us to classify the acquisition adjustment and merger-related costs as regulatory assets and include them in our investment, or rate base, when determining our Florida natural gas rates. Additionally, our rate of return calculation will be based upon this higher level of investment, which effectively enables us to earn a return on this investment. Pursuant to the Order, we reclassified to a regulatory asset at December 31, 2011, $31.7 million of the $34.2 million goodwill, which represents the portion of the goodwill allowed to be recovered in future rates after the effective date of the Florida PSC Order. We also recorded as a regulatory asset $18.1 million related to the gross-up of the acquisition adjustment for income tax. The $1.3 million of the $2.2 million of merger-related costs, which represent the portion of the merger-related costs allowed to be recovered in future rates after the effective date of the Florida PSC Order, had previously been deferred as a regulatory asset. We also recorded as a regulatory asset $349,000 related to the gross-up of the merger-related costs for income tax. As a result of this Order, we will record $2.4 million ($1.4 million, net of tax) in amortization expense related to these assets in 2012 and 2013, $2.3 million ($1.4 million, net of tax) in 2014 and $1.8 million ($1.1 million, net of tax) annually, thereafter until 2039. These amortization expenses will be a non-cash charge, and the net effect of the recovery will be positive cash flow. Over the long-term, however, the inclusion of the acquisition adjustment and merger-related costs in our rate base and the recovery of these regulatory assets through amortization expense will increase our earnings and cash flows above what we would have otherwise been able to achieve.

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

The Florida PSC Order also resulted in the reversal in December 2011, of the $750,000 regulatory accrual, which was recorded in 2010 based on management’s assessment of FPU’s earnings and regulatory risk to its earnings associated with possible Florida PSC action related to our requested recovery and the matters set forth in this “Come-Back” filing. The reversal of the $750,000 regulatory accrual was reflected in operating revenue in 2011 in the accompanying consolidated statements of income.

Peninsula Pipeline: On September 19, 2011, Peninsula Pipeline filed a petition seeking the Florida PSC’s approval of a Firm Transportation Agreement (“FTA”) between Peninsula Pipeline and FPU, an affiliated company, in accordance with its tariff. On February 8, 2012 Peninsula Pipeline filed a petition with the Florida PSC seeking approval of an amended and revised FTA between Peninsula Pipeline and FPU. This amended and revised FTA provides for upstream interconnection of Peninsula Pipeline’s facilities with the Peoples Gas’ distribution facilities at the Duval/Nassau County line and several downstream interconnections with FPU’s facilities. This amended and revised FTA replaces, in its entirety, the agreement originally filed on September 19, 2011. The revised and amended FTA comes as a result of negotiations between Peoples Gas, FPU, and Peninsula Pipeline, which resulted in a territorial agreement and related service arrangements described below.

In January 2012, Peninsula Pipeline executed an agreement with Peoples Gas for the joint construction, ownership and operation of an approximately 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida. Under the terms of the agreement, Peninsula Pipeline will own approximately 45 percent of this 16-mile pipeline. Peninsula Pipeline’s portion of the estimated project cost is $5.7 million. Peoples Gas will operate the pipeline and Peninsula Pipeline will be responsible for its portion of the operation and maintenance expenses of the pipeline based on its ownership percentage. Peninsula Pipeline will contract with Peoples Gas for capacity from the unaffiliated upstream interstate pipeline to this jointly-owned pipeline. Peninsula Pipeline will utilize both the capacity contracted with Peoples Gas and the capacity on the new jointly-owned pipeline to provide transportation service to FPU for its natural gas distribution service in Nassau County. The new jointly-owned pipeline is expected to be completed and placed into service in the second half of 2012.

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

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

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

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

On February 24, 2012, FPU filed a revised petition for approval of a mid-course reduction to its Northwest Division fuel rates based on a mid-course reduction to its supplier’s fuel rates. FPU expects to significantly lower purchased power costs for its Northwest Division in 2012 as a result of this reduction by the supplier. In order to ensure that its customers receive these significant savings in the most timely manner, FPU filed this petition. We anticipate Florida PSC’s decision on this petition in April 2012.

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

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

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

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

Eastern Shore

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

Energylink Expansion Project: In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural Gas terminal in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would interconnect with Eastern Shore’s existing facilities in Sussex County, Delaware. In April 2009, Eastern Shore terminated this project based on increased construction costs over its original projection. As approved by the FERC, Eastern Shore initiated billing to recover approximately $3.2 million of costs incurred in connection with this project and the related cost of capital over a period of 20 years in accordance with the terms of the precedent agreements executed with the two participating customers. One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions. During 2010, Eastern Shore and the participating customers negotiated to reduce the recovery period of this cost from 20 years to five years. On January 27, 2011, Eastern Shore filed with the FERC the request to amend the cost recovery period, which was approved by the FERC on February 14, 2011. Eastern Shore revised its billing to reflect the five-year surcharge, effective March 1, 2011.

Rate Case Filing: On December 30, 2010, Eastern Shore filed with the FERC a base rate proceeding in accordance with the terms of the settlement in its prior base rate proceeding. The rate filing reflected increases in operating and maintenance expenses, depreciation expense, and a return on existing and new gas plant facilities expected to be placed into service before June 30, 2011. The FERC issued a notice of the filing on January 3, 2011. Protests were received from several interested parties, and other parties intervened in the proceeding. On January 31, 2011, the FERC issued its Order accepting the filing and suspending its effectiveness for the full five-month period permitted under the Natural Gas Act. The discovery process commenced on February 22, 2011, and the FERC Staff performed an on-site audit on March 16-17, 2011. Subsequent to the on-site audit, settlement conferences involving Eastern Shore, the FERC Staff and other interested parties resulted in a settlement, which provides a cost of service of approximately $29.1 million and a pre-tax return of 13.9 percent. Also included in the settlement is a negotiated rate adjustment, effective November 1, 2011, associated with the phase-in of an additional 15,000 Dts/d of new transportation service on Eastern Shore’s eight-mile extension to interconnect with TETLP’s pipeline system. This rate adjustment reduces the rate per Dt of the service on this eight-mile extension by reflecting the increased service of 15,000 Dts/d with no additional revenue. This rate adjustment effectively offsets the increased revenue that would have been generated from the 15,000 Dts/d increase in firm service although Eastern Shore may still benefit from the increased commodity charge on the increased volume from the phase-in of service. The settlement also provides a five-year moratorium on the parties’ rights to challenge Eastern Shore’s rates and on Eastern Shore’s right to file a base rate increase. The settlement allows Eastern Shore to file for rate adjustments during those five years in the event certain costs related to government-mandated obligations are incurred and Eastern Shore’s pre-tax earnings do not equal or exceed 13.9 percent. The FERC approved the settlement on January 24, 2011.

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

Mainline Extension Project: On April 1, 2011, Eastern Shore filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 3,405 Dts/d of natural gas to an existing industrial customer. The FERC published notice of this filing on April 7, 2011. The 60-day comment period subsequent to the FERC notice expired on June 6, 2011, and the requested authorization became effective on that date.

On April 28, 2011, Eastern Shore filed a notice of intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 6,250 Dts/d of natural gas to Chesapeake’s Delaware and Maryland divisions and Eastern Shore Gas, an unaffiliated provider of piped propane service in Maryland. The FERC published notice of this filing on May 12, 2011, and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective.

Also on April 28, 2011, Eastern Shore filed a notice of intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 4,070 Dts/d of natural gas to Chesapeake’s Maryland division to provide new natural gas service in Cecil County, Maryland. The FERC published notice of this filing on May 12, 2011, and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective.

Eastern Shore also had developments in the following FERC matters:

On March 7, 2011, Eastern Shore filed certain tariff sheets to amend the creditworthiness provisions contained in its FERC Gas Tariff. On April 6, 2011, the FERC issued an Order accepting and suspending Eastern Shore’s filed tariff revisions for an effective date of April 1, 2011, subject to Eastern Shore submitting certain clarifications with regard to several proposed revisions.

On April 18, 2011, Eastern Shore submitted its annual Interruptible Revenue Sharing Report to the FERC. Eastern Shore reported in this filing that its interruptible revenue did not exceed its annual threshold amount, which would trigger sharing of excess interruptible revenues with its firm service customers. Consequently, Eastern Shore is not required to refund to its firm customers any portion of its interruptible revenue received for the period April 2010 through March 2011.

On June 24, 2011, Eastern Shore filed certain tariff sheets to amend the General Terms and Conditions and the pro forma FTA contained in its FERC Gas Tariff to allow for specification of minimum delivery pressures and maximum hourly quantity. The FERC published the notice of this filing on June 27, 2011, and no protests or adverse comments opposing this filing were submitted. On July 15, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective July 24, 2011.

On August 15, 2011, Eastern Shore filed certain tariff sheets to update certain Delivery Point Area definitions contained in its FERC Gas Tariff. The FERC published notice of this filing on August 16, 2011, and no protests or adverse comments opposing this filing were submitted. On September 13, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective September 14, 2011.

On September 7, 2011, Eastern Shore filed certain tariff sheets to reflect a decrease in the Annual Charge Adjustment, which is a surcharge designed to recover applicable program costs incurred by the FERC to discharge its jurisdictional responsibilities. The surcharge decreased from $0.0019 per Dt to $0.0018 per Dt. The FERC published the notice of this filing on September 8, 2011, and no protests or adverse comments opposing this filing were submitted. On September 27, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective October 1, 2011.