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Rates and Other Regulatory Activities | 6 Months Ended
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Jun. 30, 2012
Rates and Other Regulatory Activities [Abstract] |
Rates and Other Regulatory Activities |
4. | Rates and Other Regulatory Activities
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore Natural Gas Company (“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. The Delaware PSC granted approval of the GSR charges at its regularly scheduled meeting on July 17, 2012. On June 18, 2012, the Delaware division filed an application with the Delaware PSC requesting approval for a Town of Selbyville Franchise Fee Rider. This rider will allow the Delaware division to charge all natural gas customers within the town limits the franchise fee paid by the Delaware division to the Town of Selbyville as a condition to providing natural gas service. We anticipate that the Delaware PSC will grant approval of the Franchise Fee Rider in the third quarter of 2012. On June 25, 2012, the Delaware division filed with the Delaware PSC an application for proposed natural gas expansion service offerings in order to increase the availability of natural gas within its Delaware service areas. In this filing, the Delaware division is seeking approval from the Delaware PSC of the following:
| (i) | a monthly fixed charge to customers in portions of Eastern Sussex County, Delaware, which will enable the Delaware division to extend its distribution system to provide natural gas service to these customers economically without upfront contributions from these customers;
| (ii) | optional service offerings to customers to assist them in conversions, including a conversion finance service to assist customers with their cost of conversion equipment; and
| (iii) | a slight rate increase for all Delaware customers in order to support the additional costs associated with the administration and implementation of the proposed service offerings.
On July 3, 2012, the Delaware PSC officially opened the docket and set a period for formal interventions to be filed. We anticipate that the Delaware PSC will render a final decision on these proposals in the fourth quarter of 2012. Maryland There were no significant regulatory proceedings in Maryland pending during 2012. Florida “Come-Back” Filing: On January 30, 2012, the Florida PSC issued an order, approving, 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 acquisition adjustment permits the recovery, through rates, and inclusion in rate base, of the premium (amount in excess of net book value) paid for the acquisition of FPU. 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. 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 in merger-related 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. Of the $2.2 million of merger-related costs, $1.3 million, which represents 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 of the acquisition adjustment and merger-related costs as an expense in January 2012, and included $1.2 million of the amortization expense in depreciation and amortization in the accompanying condensed consolidated statement of income for the six months ended June 30, 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 would have to expense the corresponding unamortized amount of the disallowed acquisition adjustment. Peninsula Pipeline: At its April 10, 2012 agenda conference, the Florida PSC approved a 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 transmission 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 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 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 of Marianna. 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. By 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. The City of Marianna filed an appeal with the Florida Supreme Court on March 7, 2012 and with the Florida PSC on March 19, 2012, seeking an applicable review of the decisions by the Florida PSC with respect to the protests by the City of Marianna. At this time, this appeal is pending before the Florida Supreme Court. These Florida PSC dockets are currently in litigation status awaiting a decision by the Florida Supreme Court on the administrative appeal. As disclosed in Note 6, “Other Commitments and Contingencies,” to the Condensed 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. 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 of Marianna. 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. 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 of Marianna. On June 1, 2012, the City of Marianna filed a petition with the Florida PSC for resolution of a territorial dispute for natural gas service in Jackson County as well as the surrounding areas included in FPU’s planned expansion. On June 22, 2012, FPU filed a response to the petition defending its planned expansion. The Florida PSC has not yet issued a date for an agenda conference to resolve the matter. 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. 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. The Florida PSC staff is expected to issue a recommendation on this surcharge in early August 2012, and a decision is expected by the Florida PSC at the agenda conference on August 14, 2012. 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. At the agenda conference on July 17, 2012, the Florida PSC approved the contract. On July 12, 2012, FPU filed a petition with the Florida PSC for approval of recognition of a regulatory liability for a one-time tax contingency gain related to FPU’s income tax liability, which originated prior to the acquisition by Chesapeake from excess tax depreciation on vehicles. FPU recently determined that this tax liability was no longer needed because the applicable statute of limitation of the Internal Revenue Service and the tax remittance period related to this tax liability has expired. FPU believes that the treatment most consistent with prior regulatory treatment of one-time gains would be to record the amount as a regulatory liability and amortize that amount over a specified period. FPU is proposing to establish approximately $1.9 million of regulatory liability ($1.2 million in the tax contingency gain and $748,000 in the tax gross-up) and amortize it over a period from January 2012 to October 2014. The agenda conference date for this petition has not yet been set, but FPU expects that a decision on this petition will be made by the end of 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 per day (“Dts/d”) of new transmission 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 dekatherm (“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 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. Mainline Expansion Project: On May 14, 2012, Eastern Shore submitted to the FERC an Application for a Certificate of Public Convenience and Necessity for approval to construct, own and operate the facilities necessary to deliver additional firm service of 15,040 Dts/d to an existing electric power generation customer and to Chesapeake’s Delaware and Maryland divisions. The estimated capital cost of the project is approximately $16.3 million. The filing was publicly noticed on May 25, 2012. Two of Eastern Shore’s existing customers and Chesapeake’s Delaware and Maryland divisions filed motions to intervene in support of the project. One existing customer filed a motion to intervene and protest. On June 28, 2012, Eastern Shore submitted a response to the protest. We expect the FERC ruling on this application by the end of 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. On June 27, 2012, Eastern Shore submitted a combined filing for its Fuel Retention Percentage (“FRP”) and Cash-Out Surcharge to the FERC, which encompassed a 24-month period from April 2010 to March 2012. In the filing, Eastern Shore proposed to maintain its existing zero FRP rate and its existing zero rate for the Cash-Out Surcharge. Eastern Shore also proposed to refund $319,933, inclusive of interest, to its eligible customers in the third quarter of 2012 as a result of combining its over-recovered Gas Required for Operations and its over-recovered Cash-Out Cost.

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