CHESAPEAKE UTILITIES CORP - Quarter Report: 2011 March (Form 10-Q)

 

 

 

 

 

 

 

 

 

 

 

 

 

BravePoint

Chesapeake

Company

Eastern Shore

FPU

PESCO

Peninsula Pipeline

Sharp

Xeron

Delaware PSC

EPA

FERC

FDEP

FDOT

Florida PSC

Maryland PSC

MDE

PSC

SEC

GAAP

AS/SVE

BS/SVE

CDD

DSCP

Dts

Dts/d

ECCR

FGT

FRP

GSR

Gulf Power

Gulfstream

HDD

MWH

Mcf

MGP

NYSE

OTC

PIP

RAP

Sanford Group

TETLP

TOU

 

Regulated Energy

Unregulated Energy

Other

 

 

 

Regulated energy cost of sales

Unregulated energy and other cost of sales

Operations

Maintenance

Depreciation and amortization

Other taxes

 

Total operating expenses

 

 

Other income, net of expenses

 

Interest charges

 

 

 

Income tax expense

 

 

 

Basic

Diluted

 

Basic

Diluted

 

Net Income

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

Depreciation and amortization

Depreciation and accretion included in other costs

Deferred income taxes, net

Loss on sale of assets

Unrealized gain on commodity contracts

Unrealized gain on investments

Employee benefits

Share-based compensation

Other, net

Changes in assets and liabilities:

Purchase of investments

Accounts receivable and accrued revenue

Propane inventory, storage gas and other inventory

Regulatory assets

Prepaid expenses and other current assets

Accounts payable and other accrued liabilities

Income taxes receivable

Accrued interest

Customer deposits and refunds

Accrued compensation

Regulatory liabilities

Other liabilities

 

Net cash provided by operating activities

 

 

Property, plant and equipment expenditures

Proceeds from sales of assets

Purchase of investments

Environmental expenditures

 

Net cash used in investing activities

 

 

Common stock dividends

(Purchase) issuance of stock for Dividend Reinvestment Plan

Change in cash overdrafts due to outstanding checks

Net repayment under line of credit agreements

Other Short-term borrowing

Repayment of long-term debt

 

Net cash used in financing activities

 

 

Net Decrease in Cash and Cash Equivalents

Cash and Cash Equivalents — Beginning of Period

 

Cash and Cash Equivalents — End of Period

 

 

Regulated energy

Unregulated energy

Other

 

Total property, plant and equipment

 

Less: Accumulated depreciation and amortization

Plus: Construction work in progress

 

Net property, plant and equipment

 

 

 

 

Cash and cash equivalents

Accounts receivable (less allowance for uncollectible accounts of $1,122 and $1,194, respectively)

Accrued revenue

Propane inventory, at average cost

Other inventory, at average cost

Regulatory assets

Storage gas prepayments

Income taxes receivable

Deferred income taxes

Prepaid expenses

Mark-to-market energy assets

Other current assets

 

Total current assets

 

 

Goodwill

Other intangible assets, net

Long-term receivables

Regulatory assets

Other deferred charges

 

Total deferred charges and other assets

 

 

 

 

Stockholders’ equity

Common stock, par value $0.4867 per share (authorized 25,000,000 shares)

Additional paid-in capital

Retained earnings

Accumulated other comprehensive loss

Deferred compensation obligation

Treasury stock

 

Total stockholders’ equity

 

Long-term debt, net of current maturities

 

Total capitalization

 

 

Current portion of long-term debt

Short-term borrowing

Accounts payable

Customer deposits and refunds

Accrued interest

Dividends payable

Accrued compensation

Regulatory liabilities

Mark-to-market energy liabilities

Other accrued liabilities

 

Total current liabilities

 

 

Deferred income taxes

Deferred investment tax credits

Regulatory liabilities

Environmental liabilities

Other pension and benefit costs

Accrued asset removal cost — Regulatory liability

Other liabilities

 

Total deferred credits and other liabilities

 

 

 

Net Income

Other comprehensive income, net of tax:

Employee Benefit Plans, net of tax:

Amortization of prior service costs ⁽⁴⁾

Net Loss ⁽⁵⁾

 

Total comprehensive income

 

Dividend Reinvestment Plan

Retirement Savings Plan

Conversion of debentures

Tax benefit on share based compensation

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

Deferred Compensation Plan

Purchase of treasury stock

Sale and distribution of treasury stock

Dividends on stock-based compensation

Cash dividends ⁽²⁾

 

Net Income

Other comprehensive income, net of tax:

Employee Benefit Plans, net of tax:

Amortization of prior service costs ⁽⁴⁾

Net Gain ⁽⁵⁾

 

Total comprehensive income

 

Dividend Reinvestment Plan

Retirement Savings Plan

Conversion of debentures

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

Deferred Compensation Plan

Purchase of treasury stock

Sale and distribution of treasury stock

Dividends on stock-based compensation

Cash dividends ⁽²⁾

 

 

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K filed with the SEC on March 8, 2011. 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.

We reclassified certain amounts in the condensed consolidated statements of income and cash flows for the three months ended March 31, 2010 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our consolidated financial statements.

Net Income

Weighted average shares outstanding

 

 

 

Net Income

Effect of 8.25% Convertible debentures

 

Adjusted numerator — Diluted

 

 

Weighted shares outstanding — Basic

Effect of dilutive securities:

Share-based Compensation

8.25% Convertible debentures

 

Adjusted denominator — Diluted

 

 

 

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective Public Service Commission (“PSC”); Eastern Shore Natural Gas Company (“Eastern Shore”), our natural gas transmission operation, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”); and Peninsula Pipeline Company, Inc. (“Peninsula Pipeline”) is subject to regulation by the Florida Public Service Commission (“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.

On September 2, 2008, our Delaware division filed with the Delaware Public Service Commission (“Delaware PSC”) its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, which included the Delaware PSC, our Delaware division and the Division of the Public Advocate. As part of the settlement, the parties agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, Peninsula Energy Services Company, Inc. (“PESCO”). On January 8, 2010, the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which he recommended, among other things, that the Delaware PSC require the Delaware division to refund to its firm service customers the difference between what the Delaware division would have received had the capacity released to PESCO been priced at the maximum tariff rates under asymmetrical pricing principles and the amount actually received by the Delaware division for capacity released to PESCO. The Hearing Examiner 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 were ultimately approved without modification by the Delaware PSC, the Delaware division would have to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division pays for long-term capacity, 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. The parties involved filed opening briefs with the Delaware Superior Court on September 30, 2010, answering briefs on October 20, 2010, and reply briefs on November 3, 2010. Oral arguments were presented on March 14, 2011, in which the parties presented their respective positions. We have not accrued any contingent liability related to potential refunds for past capacity releases. We anticipate that the Court will render a decision sometime in 2011. In addition, due to the ongoing legal proceeding, the parties have not yet opened a separate docket to determine an alternative pricing methodology for future capacity releases. Since the Delaware PSC’s Order on May 18, 2010, the Delaware division has not released any capacity to PESCO.

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 division anticipates a final decision no later than the third quarter of 2011.

On March 10, 2011, the Delaware division filed with the Delaware PSC an application requesting approval to guarantee certain debt of Florida Public Utilities Company (“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 indenture of FPU’s debt. The Delaware PSC granted approval of this guarantee at its regularly scheduled meeting on April 4, 2011.

On December 14, 2010, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the 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 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. No adverse comments have been filed since the Order.

In the Order dated December 15, 2009, approving the rate increase for Chesapeake’s Florida division, the Florida PSC ordered Chesapeake’s Florida division and FPU’s natural gas distribution operation to submit data that details all known benefits, synergies, cost savings and cost increases resulting from the merger in a “Come-Back” filing. We submitted this filing on April 29, 2010 and also 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. We did not request any change to the existing rates previously approved by the Florida PSC.

In 2010, we recorded a $750,000 accrual based on our assessment of FPU’s current earnings and regulatory risk to its earnings associated with possible Florida PSC action related to our requested recovery and the matters set forth in the “Come-Back” filing.

On September 1, 2010, FPU’s electric distribution operation filed its annual Fuel and Purchased Power Cost Recovery Clause, seeking final approval of the levelized fuel adjustment and purchased power cost recovery factors for 2011. On December 20, 2010, the Florida PSC issued an order approving the proposed 2011 fuel rates, effective for meters read on and after January 1, 2011.

On September 10, 2010, FPU’s electric distribution operation filed its annual Energy Conservation Cost Recovery (“ECCR”) Clause, seeking final approval of the 2009 conservation-related revenues and expenses and new ECCR recovery factors for 2011. On November 29, 2010, the Florida PSC issued an order approving the proposed 2011 ECCR recovery factors, effective for meters read on and after January 1, 2011.

On September 13, 2010, Chesapeake’s Florida division, FPU’s Indiantown division and FPU’s natural gas distribution operation separately filed their annual ECCR Clauses, seeking final approval of the 2009 conservation-related revenues and expenses and new ECCR recovery factors for 2011. On November 29, 2010, the Florida PSC issued an order approving all of the proposed 2011 ECCR recovery factors, effective for meters read on or after January 1, 2011.

On September 13, 2010, FPU’s natural gas distribution operation filed its annual Purchased Gas Adjustment (“PGA”) Clause, seeking final approval of its 2009 purchased gas-related revenues and expenses and new PGA cap rate for 2011. On November 29, 2010, the Florida PSC issued an order approving the proposed 2011 PGA cap rate, effective for meters read on or after January 1, 2011.

On, July 7, 2009, the City Commission of Marianna, Florida (“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 that shall be mutually agreed upon by FPU and 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 the corporate limits of the City of Marianna. If the rates are not in effect by February 17, 2011, the City has the right to give notice to FPU within 180 days thereafter of its intent to exercise its option 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 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 impacted from the loss in 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 reasonable TOU and interruptible rates and on December 14, 2010, filed a petition with the Florida PSC for authority to implement such proposed TOU and interruptible rates for approval and implementation on or before February 17, 2011. On February 11, 2011, the Florida PSC issued an order approving the proposed TOU and interruptible rates for a four-year period. The City has objected to the proposed rates and has filed a petition protesting the entry of the Florida PSC’s order.

As disclosed in Note 5, “Other Commitments and Contingencies,” the City, on March 2, 2011, filed a declaratory action 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 of Marianna in accordance with the terms of the Franchise Agreement. FPU filed its answer with the court in the declaratory action on March 28, 2011.

On January 26, 2011, FPU filed a Petition with the Florida PSC for approval of an amendment to the Generation Services Agreement with Gulf Power Corporation. The amendment provides for a reduction in the capacity demand quantity, which provides for the savings necessary to support the TOU and interruptible rates approved in Docket No. 100459-EI. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019. The Florida PSC Staff is expected to issue their recommendation on May 12, 2011. This Petition is scheduled for the May 24, 2011 Florida PSC Agenda Conference.

The following are regulatory activities involving 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, and initiated billing to recover approximately $3.2 million of costs incurred in connection with this project and the related cost of capital over a period of 20 years in accordance with the terms of the precedent agreements executed with the two participating customers and approved by the FERC. One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions. 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 began billing the five-year surcharge effective March 1, 2011.

Mainline Extension and Interconnect Project: On March 5, 2010, Eastern Shore submitted an Application for Certificate of Public Convenience and Necessity to the FERC related to a proposed mainline extension and interconnect project that would tie into the interstate pipeline system of TETLP. Eastern Shore’s project involved building and operating an eight-mile mainline extension from Eastern Shore’s existing facility in Parkesburg, Pennsylvania to the interconnection with TETLP at Honey Brook, Pennsylvania. The estimated capital cost of this project was approximately $19.4 million. On September 3, 2010, the FERC approved Eastern Shore’s application, subject to certain environmental conditions, some of which had to be met prior to the commencement of construction. Eastern Shore accepted the Order Issuing Certificate on October 4, 2010. On October 13, 2010, the FERC issued a Notice to Proceed with the construction of the project’s facilities as all conditions that must be met prior to the commencement of construction were satisfied. The facilities were completed on December 15, 2010, and on December 21, Eastern Shore received FERC approval to place the facilities into service. Eastern Shore commenced billing for the new service on January 1, 2011.

Rate Case Filing: On December 30, 2010, Eastern Shore filed a base rate proceeding in compliance with the terms of the settlement in its prior base rate proceeding. Eastern Shore’s filed rates, proposed to be effective February 1, 2011, reflect an annual increase of $6,748,628 over its current rates. The proposed rate increase reflects increases in operating and maintenance expenses, depreciation expense, and return on existing and new gas plant facilities that are expected to be placed into service before June 30, 2011. Eastern Shore proposed a return on equity of 13.5 percent. 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 FERC Staff performed an on-site audit on March 16-17, 2011. Staff issued their “Top Sheet” on April 7, 2011, summarizing Staff’s initial position on this case, and the first settlement conference was held on April 14, 2011. Eastern Shore expects the base rate proceeding to be completed in 2011.

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 dekatherms per day (“Dts/d”) of natural gas to the Delaware City Refining Company LLC. The FERC published notice of this filing on April 7, 2011; assuming no protest during the 60-day period following the notice, the requested authorization will become effective.

On April 28, 2011, Eastern Shore filed a notice of its intent under its blanket certification 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 will publish notice of this filing within ten days of the date of the filing; assuming no protest during the 60-day period following the notice, the requested authorization will become effective.

Also on April 28, 2011, Eastern Shore file a notice of its intent under its blanket certification 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. The FERC will publish notice of this filing within ten days of the date of the filing; assuming no protest during the 60-day period following the notice, the requested authorization will become effective.

Eastern Shore also had developments in the following FERC matters:

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

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

As of March 31, 2011, we had $324,000 in environmental liabilities related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of the future costs associated with those sites. As of March 31, 2011, we had approximately $1.2 million in regulatory and other assets for future recovery of environmental costs from Chesapeake’s customers through our approved rates. As of March 31, 2011, we had approximately $11.4 million in environmental liabilities related to FPU’s MGP sites in Florida, primarily from the West Palm Beach site, which represents our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs from insurance and from customers through rates. Approximately $7.9 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of March 31, 2011. We also had approximately $6.1 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

The following discussion provides details on each site.

The BS/SVE treatment system at the Winter Haven site does not address impacted soils in the southwest corner of the site. On April 16, 2010, a soil excavation interim RAP describing the proposed excavation of approximately 4,000 cubic yards of impacted soils from the southwest corner of the site was submitted to the FDEP for review. On June 24, 2010, the FDEP provided comments on the soil excavation interim RAP by letter, to which we responded, and a subsequent conditional approval letter was issued by FDEP on August 27, 2010. The cost to implement this excavation plan has been estimated 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 (including treatment and discharge of the pumped water) are likely to be substantial, alternatives to this excavation plan are being evaluated. As a result, we plan to perform the excavation in late 2011 or early 2012.

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

Through March 31, 2011, we have incurred and paid approximately $1.7 million for remedial activities at this site, and we have estimated and accrued for additional future costs of $324,000. We have recovered through rates $1.4 million of the costs to remediate the Winter Haven site and continue to expect that the remaining $602,000, which is included in regulatory assets, will be recoverable from customers through our approved rates.

FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In September 2010, FDEP issued a Preliminary Contamination Assessment Report, for additional soil and groundwater investigation work that was undertaken by FDEP in November 2009 and January 2010, after 17 years of regulatory inactivity. Because FDEP observed that some soil and groundwater standards were exceeded, FDEP is seeking to meet with FPU and the current site owner to discuss additional field work which the FDEP believes is warranted for the site. Potential costs for investigation and remediation are projected to be $153,000.

FPU formerly owned and operated an MGP in Pensacola, Florida. The MGP 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 November 9, 2010, an NFA Proposal was submitted to FDEP, along with a draft restrictive covenant for that portion of the property currently owned by FDOT. At this point, it is anticipated that no further monitoring will be required on the site. FPU’s total remaining consulting and remediation costs for this site are projected to be $7,000.

FPU is the current owner of property in Sanford, Florida, a former MGP site which was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In late September 2006, the United States Environmental Protection Agency (“EPA”) sent a Special Notice Letter, notifying FPU, and the other responsible parties at the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light Company, and the city of Sanford, Florida, collectively with FPU, “the Sanford Group”), of EPA’s selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments) for the site. The total estimated remediation costs for this site were projected at the time by EPA to be approximately $12.9 million.

In January 2007, FPU and other members of the Sanford Group signed a Third Participation Agreement, which provides for funding the final remedy approved by EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13 million, or $650,000. As of March 31, 2011, FPU has paid $650,000 to the Sanford Group escrow account for its share of funding requirements.

The Sanford Group, EPA and the U.S. Department of Justice agreed to a Consent Decree in March 2008, which was entered by the federal court in Orlando, Florida on January 15, 2009. The Consent Decree obligates the Sanford Group to implement the remedy approved by EPA for the site. The total cost of the final remedy is now estimated at approximately $18 million. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

Several members of the Sanford Group have concluded negotiations with two adjacent property owners to resolve damages that the property owners allege they have 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.

As of March 31, 2011, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is estimated to be $20,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13 million to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement.

We are currently evaluating remedial options to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated an MGP. Pursuant to a Consent Order between FPU and the FDEP, effective April 8, 1991, FPU completed the delineation of soil and groundwater impacts at the site. On June 30, 2008, FPU transmitted to the FDEP a revised feasibility study, evaluating appropriate remedies for the site. This revised feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. On April 30, 2009, the FDEP issued a remedial action order, which it subsequently withdrew. In response to the Order and as a condition to its withdrawal, FPU committed to perform additional field work in 2009 and complete an additional engineering evaluation of certain remedial alternatives. The scope of this work has increased in response to FDEP’s requests for additional information.

FPU performed additional field work in August 2010, which included the installation of additional groundwater monitoring wells and performance of a comprehensive groundwater sampling event. FPU also performed vapor intrusion sampling in October 2010. The results of the field work were submitted to the FDEP for their review and comment in October 2010. On November 4, 2010, the FDEP issued its comments on the feasibility study and the proposed remedy. On November 16, 2010, FPU presented to the FDEP a new remedial action plan for the site, and the FDEP agreed with FPU’s proposal to implement a phased approach to remediation. On December 22, 2010, FPU submitted to the FDEP an interim RAP to remediate the east parcel of the site, which the FDEP conditionally approved on February 4, 2011.

FPU is currently implementing the interim RAP for the east parcel of the West Palm Beach site, including the incorporation of FDEP’s conditions for approval. We estimate that the updated costs of remediation will range from approximately $5.1 million to $13.3 million. This estimate does not include any costs associated with relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future re-development of the properties.

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

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

In May 2010, a FPU propane customer filed a class action complaint against FPU in Palm Beach County, Florida, alleging, among other things, that FPU acted in a deceptive and unfair manner related to a particular charge by FPU on its bills to propane customers and the description of such charge. The suit sought to certify a class comprised of FPU propane customers to whom such charge was assessed since May 2006 and requested damages and statutory remedies based on the amounts paid by FPU customers for such charge. FPU vigorously denies any wrongdoing and maintains that the particular charge at issue is customary, proper and fair. Without any admission by FPU of any wrongdoing, validity of the claims or a properly certifiable class for the complaint, FPU entered into a settlement agreement with the plaintiff in September 2010 to avoid the burden and expenses of continued litigation. The court approved the final settlement, and the judgment became final on March 13, 2011. In 2010, we recorded $1.2 million of the total estimated costs related to this litigation. Pursuant to the final settlement, the distribution to the class must be made by May 13, 2011.

On March 2, 2011, the City of Marianna, Florida filed a declaratory action against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging that FPU breached its obligations under its franchise with the City to provide electric service to customers within and without the City by failing: (i) to develop and implement TOU and interruptible rates that were mutually agreed to by the City and FPU; (ii) to have such mutually agreed upon rates in effect by February 17, 2011; and (iii) to 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 to exercise its option under 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 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 the referendum, the closing of the purchase must occur within 12 months after the referendum is approved. On March 17, 2011, FPU filed a Motion to Dismiss the City’s protest and request for hearing. On March 24, 2011, the City filed its response to FPU’s Motion to Dismiss. On March 28, 2011, FPU filed its answer with the court in the declaratory action. FPU intends to vigorously contest this litigation and intends to oppose the adoption of any proposed referendum to approve the purchase of the FPU property in the City of Marianna.

Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. We have a contract with an energy marketing and risk management company to manage a portion of our natural gas transportation and storage capacity. This contract expires on March 31, 2012.

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 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.

PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements before its existing agreements expire in May 2011.

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 requires FPU to comply with the following ratios based on the result of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) fixed charge coverage ratio greater than 1.5. 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 operation 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 action taken or proposed to be taken to be 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, 2011, FPU was in compliance with all of the requirements of its fuel supply contracts.

The Board of Directors has previously authorized the Company to issue up to $35 million of corporate guarantees or letters of credit on behalf of our subsidiaries. On March 2, 2011, the board increased this limit from $35 million to $45 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which are for our propane wholesale marketing subsidiary and our natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at March 31, 2011 was $26.0 million, with the guarantees expiring on various dates through 2011.

In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance company for $441,000, which expires on December 2, 2011. The letter of credit is provided as security to satisfy the deductibles under our various outstanding insurance policies. As a result of the recent change in our primary insurance company, we have issued an additional letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2011. There have been no draws on these letters of credit as of March 31, 2011. 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 $2.1 million to TETLP related to the Precedent Agreement with TETLP, which is further described below.

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 30,000 and 10,000 Dts/d, respectively, to be effective on the service commencement date of the project, which is currently projected to occur in November 2012. Each firm transportation service contract shall, among other things, provide for: (a) the maximum daily quantity of Dts/d described above; (b) a term of 15 years; (c) a receipt point at Clarington, Ohio; (d) a delivery point at Honey Brook, Pennsylvania; and (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 are currently received primarily from the Gulf of Mexico natural gas production region and are 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 us with an additional direct interconnection with Eastern Shore’s transmission system and access to new sources of natural gas supplies 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.

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 $9.6 million as of March 31, 2011. If we were to terminate the Precedent Agreement after TETLP completed its construction of all facilities, which is expected to be in the fourth quarter of 2011, our proportionate share could be as much as approximately $45 million. The actual amount of our proportionate share of such costs could differ significantly and would ultimately be based on the level of pre-service costs at the time of any potential termination. 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 of March 31, 2011, we provided a letter of credit for $2.1 million, as required under the Precedent Agreement with TETLP. This letter of credit will not exceed more than the three-month reservation charge under the firm transportation service contracts, which we currently estimate to be $2.1 million.

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. As discussed in Note 3, “Rates and Other Regulatory Activities,” 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.

TETLP is proceeding with obtaining the necessary approvals, authorizations or exemptions for construction and operation of its portion of the project, including, but not limited to, approval by the FERC. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or Eastern Shore.

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

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 a sales tax audit in Florida. As of March 31, 2011, we maintained an accrual of $698,000 related to additional sales taxes and gross receipts taxes owed to various states.

As of March 31, 2011, we maintained a $750,000 accrual, which was recorded in 2010 based on management’s assessment of FPU’s current earnings and regulatory risk to its earnings associated with possible Florida PSC action related to our requested recovery and the matters set forth in the “Come-Back” filing (See Note 3, “Rates and Other Regulatory Activities,” to the Condensed Consolidated Financial Statements for further discussion).

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:

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

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

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

The following table presents information about our reportable segments.

 

Regulated Energy

Unregulated Energy

Other

 

Total operating revenues, unaffiliated customers

 

 

Regulated Energy

Unregulated Energy

Other

 

Total intersegment revenues

 

 

Regulated Energy

Unregulated Energy

Other and eliminations

 

Total operating income

 

Other income, net of other expenses

Interest

Income taxes

 

Net income

 

 

Regulated energy

Unregulated energy

Other

 

Total identifiable assets

 

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

Net periodic benefit costs for our pension and postretirement benefits plans for the three months ended March 31, 2011 and 2010 are set forth in the following table:

Service Cost

Interest Cost

Expected return on plan assets

Amortization of prior service cost

Amortization of net loss

 

Net periodic cost (benefit)

 

Settlement expense

Amortization of pre-merger regulatory asset

 

Total periodic cost

 

We expect to record pension and postretirement benefit costs of approximately $1.9 million for 2011. Included in that amount is a pension settlement expense of $217,000 recorded in the first quarter of 2011 related to a lump-sum pension distribution of $844,000 from the Chesapeake Pension Plan in January 2011 and $219,000 of an estimated settlement expense in July 2011 related to a lump-sum distribution from the Chesapeake SERP. Also included in that amount is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations of the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the merger. This was deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was $6.5 million and $6.7 million at March 31, 2011 and December 31, 2010, respectively.

During the three months ended March 31, 2011, we contributed $68,000 and $263,000 to the Chesapeake and FPU pension plans, respectively. We expect to contribute $205,000 and $1.3 million to the Chesapeake and FPU pension plans, respectively, during the year 2011.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three months ended March 31, 2011, were $22,000; for the year 2011, such benefits paid are expected to be approximately $853,000, which includes the expected lump-sum distribution of $765,000 as mentioned above. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2011, totaled $24,000; for the year 2011, we have estimated that approximately $96,000 will be paid for such benefits. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2011, totaled $11,000; for the year 2011, we have estimated that approximately $158,000 will be paid for such benefits.

In connection with the lump-sum pension distribution from the Chesapeake Pension Plan in January 2011 and related settlement accounting, we re-measured the assets and obligations of the Chesapeake Pension Plan. The assumptions used for the discount rate to calculate the benefit obligation remained unchanged at five percent. The average expected return on plan assets also did not change and remained at six percent.

The investment balance at March 31, 2011, represents: (a) a Rabbi Trust associated with our Supplemental Executive Retirement Savings Plan, (b) a Rabbi Trust related to a stay bonus agreement with a former executive, and (c) investments in equity securities. We classify these investments as trading securities and report them at their fair value. Any unrealized gains and losses, net of other expenses, are included in other income in the condensed consolidated statements of income. We also have an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Rabbi Trusts. At March 31, 2011 and December 31, 2010, total investments had a fair value of $3.8 million and $4.0 million, respectively.

Our non-employee directors and key employees are awarded share-based awards through our Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), respectively. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is primarily based on the fair value of the grant on the date it was awarded.

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the DSCP and the PIP for the three months ended March 31, 2011 and 2010:

Directors Stock Compensation Plan

Performance Incentive Plan

 

Total compensation expense

Less: tax benefit

 

Share-Based Compensation amounts included in net income

 

Shares granted under the DSCP are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense of the shares issued and amortize the expense equally over a service period of one year. In January 2011, 304 shares were granted to our former Chief Executive Officer John Schimkaitis, under the DSCP as he retired from the Company and began his service as a non-executive Vice Chairman of the Board.

Outstanding — December 31, 2010

 

Granted

Vested

Forfeited

 

Outstanding — March 31, 2011

 

At March 31, 2011, there was $28,000 of unrecognized compensation expense related to the DSCP awards that is expected to be recognized over the remaining directors’ service periods ending April 30, 2011.

The table below presents the summary of the stock activity for the PIP for the three months ended March 31, 2011:

Outstanding — December 31, 2010

Granted

Vested

Fortfeited

Expired

 

Outstanding — March 31, 2011

 

In January 2011, the Board of Directors granted awards under the PIP for 41,664 shares. The shares granted in January 2011 are multi-year awards, of which 10,500 shares will vest at the end of the two-year service period, or December 31, 2012. The remaining 31,164 shares will vest at the end of the three-year service period, or December 31, 2013. These awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprised both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

In conjunction with his retirement, our former Chief Executive Officer forfeited 24,000 shares, which represents the shares awarded under the PIP in January 2009 for the performance period ending December 31, 2011 and in January 2010 for the performance period ending December 31, 2012, that had not vested.

At March 31, 2011, the aggregate intrinsic value of the PIP awards was $1.9 million.