BravePoint

Chesapeake

Company

Eastern Shore

FPU

PESCO

Peninsula Pipeline

Sharp

Xeron

 

Delaware PSC

EPA

FERC

FDEP

FDOT

Florida PSC

Maryland PSC

MDE

PSC

SEC

 

FASB

GAAP

 

AS/SVE

BS/SVE

CDD

DSCP

Dts

Dts/d

ECCR

FGT

FRP

GSR

Gulf Power

Gulfstream

HDD

MWH

Mcf

MGP

NYSE

OCI

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

 

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

(Gain) 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:

Sale (purchase) of investments

Accounts receivable and accrued revenue

Propane inventory, storage gas and other inventory

Regulatory assets

Prepaid expenses and other current assets

Accounts payable and other accrued liabilities

Income taxes receivable

Accrued interest

Customer deposits and refunds

Accrued compensation

Regulatory liabilities

Other liabilities

 

Net cash provided by operating activities

 

 

Property, plant and equipment expenditures

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

Proceeds from issuance of long-term debt

Repayment of long-term debt

 

Net cash used in financing activities

 

 

Net Increase (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 $906 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

 

 

Other commitments and contingencies (Note 4 and 5)

 

 

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

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

Tax benefit on share based compensation

Deferred Compensation Plan

Purchase of treasury stock

Sale and distribution of treasury stock

Dividends on share-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 share-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.

In July 2011, we sold an Internet Protocol address asset to an unaffiliated entity for approximately $553,000. This particular Internet Protocol address was not used by us and did not have any net carrying value at the time of the sale. We recognized a non-operating gain of $553,000 from this sale, which is included in other income in the accompanying condensed consolidated statements of income.

In September 2011, we entered into an agreement with an unaffiliated entity to sell our office building located in West Palm Beach, Florida for $2.2 million. We also entered into a separate agreement to lease an office space at a different location in West Palm Beach, which is expected to commence in February 2012. The sale of our West Palm Beach office building is expected to be finalized in February 2012, at which point we expect to move some of the approximately 70 employees currently located in this building into the newly leased office space and the remaining employees into another nearby operational center in West Palm Beach, which we own. We are treating the West Palm Beach office building as an asset held for sale. The office building is included in other property, plant and equipment in the accompanying condensed consolidated balance sheets and had a net carrying value of approximately $2.0 million at September 30, 2011. Since the expected sales price, less costs to consummate the sale, exceed the net carrying value of the building, there was no impairment related to the West Palm Beach office building when we committed to the sale. As most of the West Palm Beach building is considered a property within the regulated businesses, most of the gain resulted from the sale will be charged to accumulated depreciation.

We reclassified certain amounts in the condensed consolidated statements of income for the three and nine months ended September 30, 2010, and the condensed consolidated statement of cash flows for the nine months ended September 30, 2010, to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

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

In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income.” ASU 2011-05 amends the guidance in Topic 220 “Comprehensive Income,” by eliminating the option to present components of other comprehensive income (“OCI”) in the statement of stockholders’ equity. Instead, the new guidance now requires entities to present all non-owner changes in stockholders’ equity either as a single continuous statement of comprehensive income or as two separate but consecutive statements. The components of OCI have not changed nor has the guidance on when OCI items are reclassified to net income; however, the amendments require entities to present all reclassification adjustments from OCI to net income on the face of the statement of comprehensive income. Similarly, ASU 2011-05 does not change the guidance to disclose OCI components gross or net of the effect of income taxes, provided that the tax effects are presented on the face of the statement in which OCI is presented, or disclosed in the notes to the financial statements. For public entities, the amendments in ASU 2011-05 are effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2011. The amendments should be applied retrospectively, and early adoption is permitted. We plan to comply with the new OCI presentation at the end of 2011.

In September 2011, the FASB issued ASU 2011-08, “Intangibles — Goodwill and Other (Topic 350) Testing Goodwill for Impairment.” ASU 2011-08 allows an entity to assess qualitatively whether it is necessary to perform step one of the two-step annual goodwill impairment test. Step one would be required if it is more-likely-than-not that a reporting unit’s fair value is less than its carrying amount. This is different than previous guidance, which required entities to perform step one of the test, at least annually, by comparing the fair value of a reporting unit to its carrying amount. An entity may elect to bypass the qualitative assessment and proceed directly to step one, for any reporting unit, in any period. ASU 2011-08 does not change the guidance on when to test goodwill for impairment. The amendments in ASU 2011-08 are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We expect the adoption of ASU 2011-08 to have no material impact on our financial position and results of operations.

Net Income

Weighted average shares outstanding

 

 

 

Net Income

Effect of 8.25% Convertible debentures (1)

 

Adjusted numerator — Diluted

 

 

Weighted shares outstanding — Basic

Effect of dilutive securities (1):

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 PSC. Chesapeake’s Florida natural gas distribution division and the natural gas and electric distribution operations of Florida Public Utilities Company (“FPU”) continue to be subject to regulation by the Florida PSC as separate entities.

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, 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. 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 in which the Delaware Attorney General withdrew its appeal. Consequently, on August 4, 2011, the Delaware division filed a Notice of Dismissal with the Supreme Court to withdrawal its cross appeal. This officially closes the case and eliminates any potential liability related to potential refunds for past capacity releases. Due to the ongoing legal proceedings, the parties have not yet opened a separate docket to determine an alternative pricing methodology for future capacity releases.

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. These applications are very similar to requests the Delaware PSC has already approved for six other local governments. On October 3, 2011, the Delaware PSC issued orders on both matters, effectively opening the proceedings and setting evidentiary hearings for November 8, 2011. We anticipate that the Delaware PSC will render a decision in the fourth quarter of 2011.

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, has been withheld until an evidentiary hearing is 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 outlines 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 will become a final order of the Maryland PSC on November 15, 2011, unless an appeal is noted with the Maryland PSC before that date by any party to this proceeding, or the Maryland PSC modifies or reverses the Proposed Order or initiates further proceedings into this matter.

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.

“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. We are requesting 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. The Florida PSC is expected to address our request for recovery of the acquisition adjustment and merger-related costs at the November 2011 agenda conference.

If the Florida PSC approves recovery of the acquisition adjustment and merger-related costs, we would be able to classify these amounts as regulatory assets and include them in our investment, or rate base, when determining our Florida natural gas rates. Additionally, we would calculate our rate of return based upon this higher level of investment, which would effectively enable us to earn a return on this investment. We would also be able to amortize the acquisition adjustment and merger-related costs over 30 and five years, respectively. Amortization expense would be included in the calculation of our rates.

If recovery of the acquisition adjustment and merger-related costs is approved, our earnings may be reduced by as much as $1.6 million annually for the amortization expense (approximately $1.3 million is non-tax-deductible) until 2014 and $1.1 million annually (non-tax deductible) thereafter until 2039. This amortization expense would be a non-cash charge, and the net effect of the recovery would 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.

If the Florida PSC does not allow recovery of the acquisition adjustment and merger-related costs, there is some likelihood that we would have to reduce rates in the State of Florida, which would adversely affect our future earnings.

We continue to maintain a $750,000 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 filing.

Marianna Franchise: 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, 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 has objected to the proposed rates and has filed a petition protesting the entry of the Florida PSC’s Order. On March 17, 2011, FPU filed a Motion to Dismiss the petition by the City of Marianna and requested oral argument. On June 14, 2011, the Florida PSC granted FPU’s request for oral argument and on July 5, 2011, issued an Order approving FPU’s Motion to Dismiss the protest by the City of Marianna, without prejudice. On July 25, 2011, the City of Marianna filed an amended petition protesting the entry of the Florida PSC’s Order. On August 12, 2011, FPU filed a new Motion to Dismiss the petition by the City of Marianna and requested oral argument. The Florida PSC’s decision with respect to the amended petition by the City of Marianna is expected in December 2011.

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 Corporation (“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 July 28, 2011, FPU filed a Motion to Dismiss the petition by the City of Marianna and requested oral argument. The Florida PSC’s decision with respect to the protest filed by the City of Marianna is expected in December 2011.

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 is projected to reduce customers’ fuel rates for the remaining months of 2011 by approximately 10 percent.

As disclosed in Note 5, “Other Commitments and Contingencies,” to the unaudited 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. 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 several affirmative defenses. The litigation remains pending and discovery is still underway.

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. 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 reflects 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 FERC Staff performed an on-site audit on March 16-17, 2011. Settlement conferences involving Eastern Shore, FERC Staff and other interested parties have resulted in a settlement in principle, which provides a cost of service of approximately $29.1 million and a pre-tax return of 13.9 percent. This represents an annual rate increase of approximately $805,000, effective July 29, 2011. The settlement also includes a rate reduction, effective November 1, 2011, associated with the 15,000 Dekatherms per day (“Dts/d”) phase-in of new transportation services on Eastern Shore’s eight-mile extension to interconnect with the Texas Eastern Transmission LP (“TETLP”) pipeline system. This rate reduction fully offsets the increased revenue that would have been generated from the 15,000 Dts/d increase in firm 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. Eastern Shore expects to finalize the settlement with the parties in November 2011 and submit it to the FERC for approval. The FERC’s approval is expected by late 2011 or early 2012.

Starting in July 2011, Eastern Shore adjusted its billing to reflect the rates requested in the base rate proceeding, subject to refund to customers upon the conclusion of this proceeding. Eastern Shore recorded approximately $911,000 as a regulatory liability as of September 30, 2011, to fully reserve any incremental revenues generated by the new rates until the settlement is filed and approved by the FERC.

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 Firm Transportation Service Agreement 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 the 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. 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.

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

We have participated in the investigation, assessment or remediation, and have 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.

As of September 30, 2011, we had approximately $11.1 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates. Approximately $8.2 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of September 30, 2011. We also had approximately $5.8 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated an MGP. Pursuant to a Consent Order between FPU and the Florida Department of Environmental Protection (“FDEP”), effective April 8, 1991, FPU is required to complete the delineation of soil and groundwater impacts at the site, and implement an effective remedy.

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 FDEP for their review and comment in October 2010. On November 4, 2010, FDEP issued its comments on the feasibility study and the proposed remedy.

On November 16, 2010, FPU presented to FDEP a new remedial action plan for the site, and FDEP agreed with FPU’s proposal to implement a phased approach to remediation. On December 22, 2010, FPU submitted to FDEP an interim Remedial Action Plan (“RAP”) to remediate the east parcel of the site, which FDEP conditionally approved on February 4, 2011. Subsequent modifications to the interim RAP, dated March 12, 2011 and April 18, 2011, were submitted to address potential concerns raised by FDEP. An Approval Order for the interim RAP was issued by FDEP on May 2, 2011, and subsequently modified by FDEP on May 18, 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. The operations on the east parcel have been relocated, and the structures removed. New monitoring wells and Air Sparging and Soil-Vapor Extraction (“AS/SVE”) test wells were installed on the east parcel in May 2011. The initial round of SVE and sparging pilot testing was conducted in June 2011, and a subsequent round of testing was conducted in July of 2011. A supplement to the interim RAP is being prepared to present to FDEP the findings of the pilot testing and proposed design details for a full-scale remediation system.

Estimated costs of remediation for the West Palm Beach site range from approximately $4.7 million to $15.8 million. We have revised our estimated maximum cost of $13.1 million to $15.8 million to include costs associated with relocation of FPU’s operations at this site, which may be necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.

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

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In 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 EPA projected the total estimated remediation costs for this site 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 September 30, 2011, FPU has paid $650,000 to the Sanford Group escrow account for its share of the 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 September 30, 2011, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of September 30, 2011.

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 requesting implementation of additional fieldwork which FDEP believes is warranted for the site.

FPU and the current site owner have had several discussions regarding the approach to be taken with FDEP and the proposed scope of work. Representatives of FPU, FDEP and the current site owner participated in a teleconference on July 7, 2011. During that call, the scope of work was tentatively agreed upon, and FDEP agreed to proceed without using a consent order. FPU and the current site owner submitted a work plan and schedule to FDEP on September 30, 2011. Potential costs for investigation and remediation are projected to be $118,000.

FPU formerly owned and operated an MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation (“FDOT”). In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action (“NFA”) determination for the site, which must include a requirement for institutional and engineering controls. On 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. FPU, FDOT and the City of Pensacola are working together to obtain a restrictive covenant that is acceptable to FDEP to complete closure of the site, and 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.

In addition, we had $284,000 in environmental liabilities at September 30, 2011, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of September 30, 2011, we had approximately $1.1 million in regulatory and other assets for future recovery through rates. The following discussion provides details on MGP sites for Chesapeake’s Maryland and Florida divisions:

We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized ground-water contamination. During 1996, we completed construction of an AS/SVE system and began remediation procedures. We have reported the remediation and monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to permanently decommission the AS/SVE system and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery.

Through September 30, 2011, we have incurred and paid approximately $2.9 million for remedial actions and environmental studies related to this site. We have recovered approximately $2.3 million through insurance proceeds or in rates, and $580,000 is expected to be recovered through future rates.

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a Consent Order entered into with the FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. In 2001, FDEP approved a RAP requiring construction and operation of a Bio-Sparging and Soil/Vapor Extraction (“BS/SVE”) treatment system to address soil and groundwater impacts at a portion of the site. The BS/SVE treatment system has been in operation since October 2002. Modifications and upgrades to the BS/SVE treatment system were completed in October 2009. The Seventeenth Semi-Annual RAP Implementation Status Report was submitted to FDEP in June 2011. The groundwater sampling results through June 2011 show a continuing reduction in contaminant concentrations and indicate that the recent treatment system modifications and upgrades have had a beneficial impact on the rate of reduction. At present, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the BS/SVE treatment system. The total expected cost of operating and monitoring the system is approximately $46,000.

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 FDEP for review. On June 24, 2010, 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. One alternative currently being evaluated involves sparging into the southwest portion of the property to treat soils rather than excavating the soils. Two new sparge points were installed in the southwest portion of the property in February of 2011. Sparging into these points has been initiated and operational and monitoring data over the next few quarters should provide the information needed to make this evaluation.

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

Through September 30, 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 $284,000. We have recovered through rates $1.5 million of the costs to remediate the Winter Haven site and continue to expect that the remaining $481,000, which is included in regulatory assets, will be recoverable from customers through our approved 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, an 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 denied any wrongdoing and maintained that the particular charge at issue is customary, proper and fair. Without admitting 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 expense of continued litigation. The court approved the final settlement agreement, 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 agreement, the distribution to the class was made by May 13, 2011.

On March 2, 2011, the City of Marianna, Florida filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida. In the complaint, the City of Marianna alleged three breaches of the Franchise Agreement by FPU: (i) FPU failed to develop and implement TOU and interruptible rates that were mutually agreed to by the City of Marianna and FPU; (ii) mutually agreed upon TOU and interruptible rates by FPU were not effective or in effect by February 17, 2011; and (iii) FPU did not have such rates available to all of FPU’s customers located within and without the corporate limits of the City of Marianna. The City of Marianna is seeking a declaratory judgment allowing it to exercise its option under the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City 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 related to 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 the referendum is approved by the voters, the closing of the purchase must occur within 12 months after the referendum is approved. On March 28, 2011, FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the material allegations by the City of Marianna and asserted several affirmative defenses. The litigation remains pending and discovery is still underway. On August 3, 2011, the City of Marianna notified FPU that it was formally exercising its option to purchase FPU’s property. On August 31, 2011, FPU advised the City of Marianna that it has no right to exercise the purchase option under the Franchise Agreement and that FPU would continue to oppose the effort by the City of Marianna to purchase FPU’s property. FPU intends to continue its vigorous defense of the lawsuit filed by the City of Marianna 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, 2013.

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

In May 2011, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2012.

As discussed in Note 3 “Rates and Other Regulatory Activities,” on January 25, 2011, FPU entered into an amendment to its Generation Services Agreement with Gulf Power, which reduces the capacity demand quantity and provides the savings necessary to support the TOU and interruptible rates for the customers in the City of Marianna, both of which were approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019.

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 results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) fixed charge coverage ratio greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU providing an irrevocable letter of credit. As of September 30, 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 September 30, 2011 was $26.7 million, with the guarantees expiring on various dates through December 2012.

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

In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2012, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $656,000, which expires on December 2, 2011, as security to satisfy the deductibles under our various outstanding insurance policies. As a result of a change in our primary insurance company in 2010, we renewed the letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2012. There have been no draws on these letters of credit as of September 30, 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 $2.5 million to TETLP related to the Precedent Agreement, 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 34,100 and 15,900 Dts/d, respectively, including the additional volume subscribed in a subsequent agreement, 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 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 $3.8 million as of September 30, 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 2012, our proportionate share could be as much as approximately $50 million. The actual amount of our proportionate share of such costs could differ significantly and would ultimately be based on the level of pre-service costs at the time of any potential termination. As our Delaware and Maryland divisions have now executed the required reservation rate agreements with TETLP, we believe that the likelihood of terminating the Precedent Agreement and having to reimburse TETLP for our proportionate share of TETLP’s pre-service costs is remote.

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

On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement with Eastern Shore to extend its mainline by eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. As discussed in Note 3, “Rates and Other Regulatory Activities,” to the unaudited condensed consolidated financial statements, 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. TETLP is expecting the FERC approval by the end of 2011. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or Eastern Shore.

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

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 September 30, 2011, we maintained an accrual of $578,000 related to additional sales taxes and gross receipts taxes owed to various states, all of which were recorded in 2010.

As of September 30, 2011, we maintained a $750,000 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 the “Come-Back” filing (See Note 3, “Rates and Other Regulatory Activities,” to the unaudited 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 charges for their 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