10-Q 1 cpk930201310-q.htm 10-Q CPK 9.30.2013 10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
 
 
 
 
FORM 10-Q
 
 
 
 

x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: September 30, 2013
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                       to                      
Commission File Number: 001-11590 
 
 
 
CHESAPEAKE UTILITIES CORPORATION
(Exact name of registrant as specified in its charter)
 
 
 

Delaware
 
51-0064146
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer
Identification No.)
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including Zip Code)
(302) 734-6799
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
 
¨
  
Accelerated filer
 
x
 
 
 
 
Non-accelerated filer
 
¨
  
Smaller reporting company
 
¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
Common Stock, par value $0.48679,632,595 shares outstanding as of October 31, 2013.



Table of Contents
 



GLOSSARY OF KEY TERMS AND DEFINITIONS
KEY TERMS
Bulk delivery: Propane delivery to customers based on the level of propane remaining in the tank located at the customer’s premises. We invoice and record revenues for the bulk delivery service at the time of delivery, rather than upon a customer’s actual usage.
Cost of sales: Includes the purchased cost of natural gas, electricity and propane commodities, pipeline capacity costs needed to transport and store natural gas, transmission costs for electricity, transportation costs to transport propane purchases to our storage facilities and the direct cost of labor spent on revenue-producing activities.
Delmarva natural gas distribution operation: Chesapeake’s Delaware and Maryland divisions.
Delmarva Peninsula: A peninsula on the east coast of the United States of America occupied by Delaware and portions of Maryland and Virginia. Chesapeake provides natural gas distribution, transmission and marketing services and propane distribution service to customers on the Delmarva Peninsula.
Electric distribution: Regulated electric distribution utility service. Florida Public Utilities Company provides this service to customers in northeast and northwest Florida. This service is regulated by the Florida Public Service Commission.
Florida natural gas distribution operation: Chesapeake’s Florida division and the natural gas operation of Florida Public Utilities Company, including its Indiantown division.
Gross margin: A non-GAAP measure, which Chesapeake uses to evaluate the performance of its business segments. Gross margin is calculated by deducting the cost of sales from operating revenues. A more detailed description of gross margin, including how we calculate it, is provided in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this Quarterly Report on Form 10-Q.
Interruptible service: Large commercial customers whose regulated utility service can be temporarily interrupted in order for the utility to meet the needs of firm service customers. The interruptible service customers pay lower delivery rates than firm service customers, and they must be able to readily substitute an alternate fuel for natural gas.
Margin per gallon: A measure of profitability for propane distribution sales, calculated for each gallon of propane sold by deducting the cost of propane sold from the propane revenue.
Mark-to-market: The process of adjusting the carrying value of a position held in our forward contracts and derivative instruments to reflect their current fair value.
Natural gas distribution: Regulated natural gas distribution utility service. Both Chesapeake Utilities Corporation, through its Delaware, Maryland and Florida divisions, and Florida Public Utilities Company provide this service, which is regulated by the Public Service Commission of each respective state.
Natural gas marketing: Unregulated natural gas supply and supply management service for the sale of the natural gas commodity directly to residential, commercial and industrial customers through competitively-priced contracts. Peninsula Energy Services Company, Inc. provides this service.
Natural gas transmission: Regulated natural gas transportation service provided by Eastern Shore Natural Gas Company and Peninsula Pipeline Company, Inc. The interstate transportation service provided by Eastern Shore Natural Gas Company is regulated by the Federal Energy Regulatory Commission. The intrastate transportation service provided by Peninsula Pipeline Company, Inc. in Florida is regulated by the Florida Public Service Commission.
Normal Weather: The most recent 10–year average of heating and/or cooling degree-days in a particular geographic area.

Propane distribution: Unregulated propane distribution service to residential, commercial, industrial and wholesale customers. This service can be provided through delivery to a propane tank located on the customer’s premises or through an underground pipeline system.
Propane wholesale marketing: Unregulated service offering where propane is marketed to major independent oil and petrochemical companies, wholesale resellers and retail propane companies located primarily in the southeastern United States of America. This service typically utilizes forward or other option contracts that are financially settled. Xeron, Inc. provides this service.



Regulated energy: The largest operating segment of Chesapeake Utilities Corporation. All operations in this segment are regulated as to their rates and service, by the Public Service Commission having jurisdiction in each state in which the Company operates or by the Federal Energy Regulatory Commission.
DEFINITIONS
ASC: Accounting Standards Codification
ASU: Accounting Standards Update
Austin Cox: Austin Cox Home Services, Inc.
BravePoint: BravePoint®, Inc., Chesapeake's advanced information services subsidiary, headquartered in Norcross, Georgia
Calpine: Calpine Energy Services, L.P.
CDD: Cooling degree-days, which is the measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is above 65 degrees Fahrenheit
Chesapeake or Company: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure
CP: Certificate of Public Convenience and Necessity
DSCP: Directors Stock Compensation Plan
Dts/d: Dekatherms per day
DPA: The Division of the Public Advocate
Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned natural gas transmission subsidiary of Chesapeake
EGWIC: Eastern Gas & Water Investment Company, LLC, an affiliate of Eastern Shore Gas Company
ESG: Eastern Shore Gas Company and its affiliates
EPA: United States Environmental Protection Agency
FASB: Financial Accounting Standards Board
FERC: Federal Energy Regulatory Commission, an independent agency of the Federal government that regulates the interstate transmission of electricity, natural gas, and oil
FDEP: Florida Department of Environmental Protection
FDOT: Florida Department of Transportation
FGT: Florida Gas Transmission Company
FPU: Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake as of October 28, 2009, the date we acquired FPU
FRP: Fuel Retention Percentage
Franchise Agreement: The agreement between the City of Marianna, Florida and Florida Public Utilities Company, which granted a franchise to Florida Public Utilities Company for the operation and distribution and/or sale of electric energy
GAAP: Accounting principles generally accepted in the United States of America
Glades: Glades Gas Co., Inc.
GSR: Gas Service Rates
Gulf Power: Gulf Power Company



Gulfstream: Gulfstream Natural Gas System, LLC
HDD: Heating degree-days, which is a measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is below 65 degrees Fahrenheit
IGC: Indiantown Gas Company
MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use
MDE: Maryland Department of Environment
Marianna Commission: The City Commission of Marianna, Florida
NAM: Natural Attenuation Monitoring
Note Agreement: Note Purchase Agreement entered into by Chesapeake with Note Holders on September 5, 2013
Note Holders: PAR U Hartford Life & Annuity Comfort Trust, The Prudential Insurance Company of America, The Gibraltar Life Insurance Co., Ltd., The Penn Mutual Life Insurance Company, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and Companion Life Insurance Company, which are collectively the lenders that entered into the Note Agreement with Chesapeake on September 5, 2013
Notes: Series A and B unsecured Senior Notes
NRG: NRG Energy Center Dover LLC
OTC: Over-the-counter
PBF Energy: PBF Energy Inc.
PESCO: Peninsula Energy Services Company, Inc., a wholly-owned natural gas marketing subsidiary of Chesapeake
Peninsula Pipeline: Peninsula Pipeline Company, Inc., a wholly-owned Florida intrastate pipeline subsidiary of Chesapeake
PIP: Performance Incentive Plan
PSC: Public Service Commission, which is the state agency that regulates the rates and services provided by Chesapeake’s natural gas and electric distribution operations in Delaware, Maryland and Florida and Peninsula Pipeline in Florida
Sandpiper: Sandpiper Energy, Inc.
Sanford Group: Florida Public Utilities Company and other responsible parties involved with the Sanford environmental site
SEC: Securities and Exchange Commission
Series A Notes: Series A of the unsecured Senior Notes to be issued on December 16, 2013 pursuant to the Note Agreement
Series B Notes: Series B of the unsecured Senior Notes to be issued on May 15, 2014 pursuant to the Note Agreement
SERP: Supplemental Executive Retirement Plan
Sharp: Sharpgas, Inc.
TETLP: Texas Eastern Transmission, LP
TOU: Time-of-use
Xeron: Xeron, Inc., a wholly-owned propane wholesale marketing subsidiary of Chesapeake, based in Houston, Texas



PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
 
 
 
Three Months
 
Nine Months
For the Periods Ended September 30,
 
2013
 
2012
 
2013
 
2012
(in thousands, except shares and per share data)
 
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
Regulated energy
 
$
55,680

 
$
52,196

 
$
192,463

 
$
180,045

Unregulated energy
 
28,262

 
23,259

 
119,278

 
93,323

Other
 
2,603

 
2,720

 
9,678

 
9,619

Total Operating Revenues
 
86,545

 
78,175

 
321,419

 
282,987

Operating Expenses
 
 
 
 
 
 
 
 
Regulated energy cost of sales
 
22,591

 
22,102

 
86,321

 
81,207

Unregulated energy and other cost of sales
 
21,795

 
17,602

 
90,656

 
72,056

Operations
 
21,300

 
20,804

 
65,878

 
60,831

Maintenance
 
2,146

 
1,801

 
5,688

 
5,635

Depreciation and amortization
 
6,274

 
5,767

 
18,071

 
17,413

Other taxes
 
3,719

 
2,535

 
10,383

 
7,753

Total Operating Expenses
 
77,825

 
70,611

 
276,997

 
244,895

Operating Income
 
8,720

 
7,564

 
44,422

 
38,092

Other income (loss), net of other expenses
 
101

 
(136
)
 
413

 
212

Interest charges
 
2,026

 
2,126

 
6,114

 
6,657

Income Before Income Taxes
 
6,795

 
5,302

 
38,721

 
31,647

Income taxes
 
2,916

 
2,083

 
15,617

 
12,641

Net Income
 
$
3,879

 
$
3,219

 
$
23,104

 
$
19,006

Weighted Average Common Shares Outstanding:
 
 
 
 
 
 
 
 
Basic
 
9,625,435

 
9,592,417

 
9,616,269

 
9,583,316

Diluted
 
9,702,334

 
9,676,658

 
9,692,311

 
9,673,681

Earnings Per Share of Common Stock:
 
 
 
 
 
 
 
 
Basic
 
$
0.40

 
$
0.34

 
$
2.40

 
$
1.98

Diluted
 
$
0.40

 
$
0.33

 
$
2.39

 
$
1.97

Cash Dividends Declared Per Share of Common Stock
 
$
0.385

 
$
0.365

 
$
1.135

 
$
1.080

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



- 1


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
 
 
 
Three Months
 
Nine Months
For the Periods Ended September 30,
 
2013
 
2012
 
2013
 
2012
(in thousands)
 
 
 
 
 
 
 
 
Net Income
 
$
3,879

 
$
3,219

 
$
23,104

 
$
19,006

Other Comprehensive Income (Loss), net of tax:
 
 
 
 
 
 
 
 
Employee Benefits, net of tax:
 
 
 
 
 
 
 
 
Amortization of prior service cost, net of tax of ($6), ($6), ($18) and ($19), respectively
 
(9
)
 
(9
)
 
(27
)
 
(28
)
Net gain, net of tax of $43, $51, $124 and $152, respectively
 
64

 
76

 
186

 
228

Total other comprehensive income
 
55

 
67

 
159

 
200

Comprehensive Income
 
$
3,934

 
$
3,286

 
$
23,263

 
$
19,206

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


- 2


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Assets
 
September 30,
2013
 
December 31,
2012
(in thousands, except shares and per share data)
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Regulated energy
 
$
635,859

 
$
585,429

Unregulated energy
 
73,816

 
70,218

Other
 
21,048

 
20,067

Total property, plant and equipment
 
730,723

 
675,714

Less: Accumulated depreciation and amortization
 
(171,060
)
 
(155,378
)
Plus: Construction work in progress
 
50,256

 
21,445

Net property, plant and equipment
 
609,919

 
541,781

Current Assets
 
 
 
 
Cash and cash equivalents
 
1,792

 
3,361

Accounts receivable (less allowance for uncollectible accounts of $1,215 and $826, respectively)
 
60,578

 
53,787

Accrued revenue
 
7,948

 
11,688

Propane inventory, at average cost
 
7,383

 
7,612

Other inventory, at average cost
 
3,452

 
5,841

Regulatory assets
 
2,063

 
2,736

Storage gas prepayments
 
5,309

 
3,716

Income taxes receivable
 
724

 
4,703

Deferred income taxes
 
837

 
791

Prepaid expenses
 
7,357

 
6,020

Mark-to-market energy assets
 
379

 
210

Other current assets
 
160

 
132

Total current assets
 
97,982

 
100,597

Deferred Charges and Other Assets
 
 
 
 
Goodwill
 
4,716

 
4,090

Other intangible assets, net
 
3,075

 
2,798

Investments, at fair value
 
2,788

 
4,168

Regulatory assets
 
76,179

 
77,408

Receivables and other deferred charges
 
2,898

 
2,904

Total deferred charges and other assets
 
89,656

 
91,368

Total Assets
 
$
797,557

 
$
733,746

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

- 3


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Capitalization and Liabilities
 
September 30,
2013
 
December 31,
2012
(in thousands, except shares and per share data)
 
 
 
 
Capitalization
 
 
 
 
Stockholders’ equity
 
 
 
 
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)
 
$
4,685

 
$
4,671

Additional paid-in capital
 
151,676

 
150,750

Retained earnings
 
118,330

 
106,239

Accumulated other comprehensive loss
 
(4,903
)
 
(5,062
)
Deferred compensation obligation
 
1,110

 
982

Treasury stock
 
(1,110
)
 
(982
)
Total stockholders’ equity
 
269,788

 
256,598

Long-term debt, net of current maturities
 
107,344

 
101,907

Total capitalization
 
377,132

 
358,505

Current Liabilities
 
 
 
 
Current portion of long-term debt
 
8,234

 
8,196

Short-term borrowing
 
91,297

 
61,199

Accounts payable
 
41,013

 
41,992

Customer deposits and refunds
 
26,943

 
29,271

Accrued interest
 
2,581

 
1,437

Dividends payable
 
3,706

 
3,502

Accrued compensation
 
6,467

 
7,435

Regulatory liabilities
 
4,397

 
1,577

Mark-to-market energy liabilities
 
124

 
331

Other accrued liabilities
 
10,252

 
7,226

Total current liabilities
 
195,014

 
162,166

Deferred Credits and Other Liabilities
 
 
 
 
Deferred income taxes
 
135,305

 
125,205

Deferred investment tax credits
 
84

 
113

Regulatory liabilities
 
6,808

 
5,454

Environmental liabilities
 
8,838

 
9,114

Other pension and benefit costs
 
33,118

 
33,535

Accrued asset removal cost—Regulatory liability
 
39,156

 
38,096

Other liabilities
 
2,102

 
1,558

Total deferred credits and other liabilities
 
225,411

 
213,075

Other commitments and contingencies (Note 5 and 6)
 

 

Total Capitalization and Liabilities
 
$
797,557

 
$
733,746

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


- 4


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)

For the Nine Months Ended September 30,
 
2013
 
2012
(in thousands)
 
 
 
 
Operating Activities
 
 
 
 
Net Income
 
$
23,104

 
$
19,006

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
18,071

 
17,413

Depreciation and accretion included in other costs
 
4,504

 
4,079

Deferred income taxes, net
 
9,947

 
12,102

(Gain) loss on sale of assets
 
(142
)
 
18

Unrealized (gain) loss on commodity contracts
 
(277
)
 
147

Unrealized (gain) loss on investments
 
217

 
(401
)
Realized gain on sales of investments, net
 
(702
)
 
(20
)
Employee benefits
 
708

 
2,268

Share-based compensation
 
1,246

 
1,111

Other, net
 
(84
)
 
(21
)
Changes in assets and liabilities:
 
 
 
 
Purchase of investments
 
(436
)
 
(292
)
Accounts receivable and accrued revenue
 
(567
)
 
36,523

Propane inventory, storage gas and other inventory
 
(933
)
 
3,722

Regulatory assets
 
(1,158
)
 
(456
)
Prepaid expenses and other current assets
 
(1,361
)
 
(856
)
Accounts payable and other accrued liabilities
 
8,174

 
(20,138
)
Income taxes receivable
 
3,980

 
(1,010
)
Accrued interest
 
1,144

 
1,509

Customer deposits and refunds
 
(2,559
)
 
(1,086
)
Accrued compensation
 
(1,060
)
 
(554
)
Regulatory liabilities
 
4,688

 
(4,097
)
Other assets and liabilities, net
 
(77
)
 
(4,502
)
Net cash provided by operating activities
 
66,427

 
64,465

Investing Activities
 
 
 
 
Property, plant and equipment expenditures
 
(68,579
)
 
(51,351
)
Proceeds from sales of assets
 
154

 
2,281

Proceeds from sale of investments
 
2,300

 

Acquisitions
 
(19,367
)
 
(124
)
Environmental expenditures
 
(276
)
 
(345
)
Net cash used in investing activities
 
(85,768
)
 
(49,539
)
Financing Activities
 
 
 
 
Common stock dividends
 
(9,716
)
 
(9,160
)
Purchase of stock for Dividend Reinvestment Plan
 
(1,001
)
 
(946
)
Change in cash overdrafts due to outstanding checks
 
(2,692
)
 
(1,559
)
Net borrowing (repayment) under line of credit agreements
 
32,790

 
(2,393
)
Proceeds from issuance of long-term debt
 
7,000

 

Repayment of long-term debt
 
(8,609
)
 
(1,459
)
Net cash provided by (used in) financing activities
 
17,772

 
(15,517
)
Net Decrease in Cash and Cash Equivalents
 
(1,569
)
 
(591
)
Cash and Cash Equivalents—Beginning of Period
 
3,361

 
2,637

Cash and Cash Equivalents—End of Period
 
$
1,792

 
$
2,046

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

- 5


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
 
 
Common Stock
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands, except shares and per share data)
Number  of
Shares(1)
 
Par
Value
 
Additional  Paid-In
Capital
 
Retained
Earnings
 
Accumulated  Other Comprehensive
Loss
 
Deferred
Compensation
 
Treasury
Stock
 
Total
Balances at  
 December 31, 2011
9,567,307

 
$
4,656

 
$
149,403

 
$
91,248

 
$
(4,527
)
 
$
817

 
$
(817
)
 
$
240,780

Net Income

 

 

 
28,863

 

 

 

 
28,863

Other comprehensive loss

 

 

 

 
(535
)
 

 

 
(535
)
Dividend Reinvestment Plan

 

 
(7
)
 

 

 

 

 
(7
)
Conversion of debentures
10,975

 
5

 
181

 

 

 

 

 
186

Share-based compensation (2) (3)
19,217

 
10

 
1,001

 

 

 

 

 
1,011

Tax benefit on share-based compensation

 

 
172

 

 

 

 

 
172

Deferred Compensation Plan

 

 

 

 

 
165

 
(165
)
 

Purchase of treasury stock
(1,019
)
 

 

 

 

 

 
(45
)
 
(45
)
Sale and distribution of treasury stock
1,019

 

 

 

 

 

 
45

 
45

Dividends on share-based compensation

 

 

 
(64
)
 

 

 

 
(64
)
Cash dividends (4)

 

 

 
(13,808
)
 

 

 

 
(13,808
)
Balances at  
 December 31, 2012
9,597,499

 
4,671

 
150,750

 
106,239

 
(5,062
)
 
982

 
(982
)
 
256,598

Net Income

 

 

 
23,104

 

 

 

 
23,104

Other comprehensive income

 

 

 

 
159

 

 

 
159

Dividend Reinvestment Plan

 

 
(5
)
 

 

 

 

 
(5
)
Conversion of debentures
5,166

 
3

 
85

 

 

 

 

 
88

Share-based compensation (2) (3)
23,348

 
11

 
846

 

 

 

 

 
857

Deferred Compensation Plan

 

 

 

 

 
128

 
(128
)
 

Purchase of treasury stock
(763
)
 

 

 

 

 

 
(38
)
 
(38
)
Sale and distribution of treasury stock
763

 

 

 

 

 

 
38

 
38

Dividends on share-based compensation

 

 

 
(92
)
 

 

 

 
(92
)
Cash dividends (4)

 

 

 
(10,921
)
 

 

 

 
(10,921
)
Balances at  
 September 30, 2013
9,626,013

 
$
4,685

 
$
151,676

 
$
118,330

 
$
(4,903
)
 
$
1,110

 
$
(1,110
)
 
$
269,788

 
(1) 
Includes 34,224 and 33,461 shares at September 30, 2013 and December 31, 2012, respectively, held in a Rabbi Trust related to the Company's Deferred Compensation Plan.
(2) 
Includes amounts for shares issued for Directors’ compensation.
(3) 
The shares issued under the Performance Incentive Plan (“PIP”) are net of shares withheld for employee taxes. For the nine months ended September 30, 2013 and for the year ended December 31, 2012, the Company withheld 10,411 and 5,670 shares, respectively, for taxes.
(4) 
Cash dividends per share for the periods ended September 30, 2013 and December 31, 2012 were $1.135 and $1.440, respectively.
The accompanying notes are an integral part of these financial statements.


- 6


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
 
1.
Summary of Accounting Policies
Basis of Presentation
References in this document to the “Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.
The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and accounting principles generally accepted in the United States of America (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2012. 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.
During the third quarter of 2013, we recorded an accrual of $698,000 (424,000, net of tax) due to a contingency for taxes other than income, $248,000, $222,000 and $60,000 of which relate to the years ended December 31, 2012, 2011 and 2010, respectively. This reduced our earnings in the third quarter of 2013 and was reflected in other taxes in the accompanying condensed consolidated statements of income for the three and nine months ended September 30, 2013. All of the amounts are related to our unregulated energy segment.
We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.
Reclassifications
We reclassified certain amounts in the condensed consolidated cash flows statement for the nine months ended September 30, 2012 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

Financial Accounting Standards Board (“FASB”) Statements and Other Authoritative Pronouncements
Recent Accounting Standards Yet to be Adopted
Income Taxes (Accounting Standards Codification ("ASC") 740) - In July 2013, the FASB issued Accounting Standards Update (“ASU”) 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists,” which requires the netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of an uncertain tax position. This ASU is effective prospectively beginning on January 1, 2014 for all unrecognized tax benefits existing at the adoption of this new standard. Retrospective implementation and early adoption of this standard are permitted. We expect the adoption of ASU 2013-11 to have no material impact on our financial position and results of operations.
Recently Adopted Accounting Standards
Comprehensive Income (ASC 220) - Effective January 1, 2013, we adopted ASU 2013-02, “Reporting of Amounts Reclassified Out Of Accumulated Other Comprehensive Income,” which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. The adoption of ASU 2013-02 had no impact on our financial position and results of operations. See Note 8, "Accumulated Other Comprehensive Income (Loss)," for additional disclosures required under this new standard.
Balance Sheet (ASC 210) - Effective January 1, 2013, we adopted ASU 2011-11, “Disclosures About Offsetting Assets and Liabilities,” and ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” These new standards require disclosures about offsetting and related arrangements in order to help financial statement users better understand the effect of those arrangements on our financial position. The adoption of ASU 2011-11 and ASU 2013-01 had no material impact on our financial position and results of operations. See Note 12, "Derivative Instruments," for additional disclosures about our offsetting of certain assets and liabilities.

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2.
Calculation of Earnings Per Share

 
 
Three Months
 
Nine Months
For the Periods Ended September 30,
 
2013
 
2012
 
2013
 
2012
(in thousands, except shares and per share data)
 
 
 
 
 
 
 
 
Calculation of Basic Earnings Per Share:
 
 
 
 
 
 
 
 
Net Income
 
$
3,879

 
$
3,219

 
$
23,104

 
$
19,006

Weighted average shares outstanding
 
9,625,435

 
9,592,417

 
9,616,269

 
9,583,316

Basic Earnings Per Share
 
$
0.40

 
$
0.34

 
$
2.40

 
$
1.98

Calculation of Diluted Earnings Per Share:
 
 
 
 
 
 
 
 
Reconciliation of Numerator:
 
 
 
 
 
 
 
 
Net Income
 
$
3,879

 
$
3,219

 
$
23,104

 
$
19,006

Effect of 8.25% Convertible debentures
 
11

 
13

 
33

 
41

Adjusted numerator—Diluted
 
$
3,890

 
$
3,232

 
$
23,137

 
$
19,047

Reconciliation of Denominator:
 
 
 
 
 
 
 
 
Weighted shares outstanding—Basic
 
9,625,435

 
9,592,417

 
9,616,269

 
9,583,316

Effect of dilutive securities:
 
 
 
 
 
 
 
 
Share-based Compensation
 
26,123

 
23,770

 
23,888

 
22,684

8.25% Convertible debentures
 
50,776

 
60,471

 
52,154

 
67,681

Adjusted denominator—Diluted
 
9,702,334

 
9,676,658

 
9,692,311

 
9,673,681

Diluted Earnings Per Share
 
$
0.40

 
$
0.33

 
$
2.39

 
$
1.97

 

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3.
Acquisitions
Eastern Shore Gas Company
On May 31, 2013, upon obtaining the necessary approval from the Maryland Public Service Commission (“PSC”), which is further discussed in Note 4, “Rates and Other Regulatory Activities,” we completed the purchase of the operating assets of Eastern Shore Gas Company and its affiliates (collectively “ESG”). ESG was not related to, or affiliated with, our interstate natural gas transmission subsidiary, Eastern Shore Natural Gas Company ("Eastern Shore"). We paid approximately $16.5 million at the closing of the transaction, which was subject to certain adjustments specified in the asset purchase agreement. During the third quarter of 2013, the purchase price was reduced by $543,000 due to adjustments to property, plant and equipment, propane inventory, accounts receivable and other accrued liabilities. The purchase price included approximately $726,000 of sales tax related to the transaction. We financed the acquisition using unsecured short-term debt.
Approximately 11,000 residential and commercial underground propane distribution system customers and 500 bulk propane delivery customers acquired in the transaction are being served by our new subsidiary, Sandpiper Energy, Inc. (“Sandpiper”) and our propane distribution subsidiary, Sharpgas, Inc. ("Sharp"), respectively. Sandpiper's operations, which cover all of Worcester County, Maryland, are now subject to rate and service regulation by the Maryland PSC. We are evaluating the potential conversion of some of the underground propane distribution systems to natural gas distribution, where such conversion is both economical and feasible.
In connection with this acquisition, we recorded $12.6 million in property, plant and equipment, $344,000 in propane inventory, $2.5 million in accounts receivable and accrued revenue and $227,000 in other current liabilities, which included the effect of the purchase price adjustment in the third quarter of 2013. All but insignificant amounts of assets and liabilities are recorded in the regulated energy segment. No goodwill or intangible asset was recorded from this acquisition. The allocation of the purchase price and valuation of assets are preliminary, and we will complete the final purchase price allocation as soon as practicable but no later than one year from the purchase of the assets.
Sales tax of approximately $726,000 included in the purchase price was expensed as a transaction cost and was reflected in other taxes in the accompanying condensed consolidated statements of income for the nine months ended September 30, 2013. Excluding this $726,000 of sales tax expense, the revenue and net income from this acquisition that were included in our condensed consolidated statements of income for the three months and nine months ended September 30, 2013 were not material.
At closing, we entered into a capacity, supply and operating agreement with Eastern Gas & Water Investment Company, LLC ("EGWIC"), an affiliate of the seller. Pursuant to this agreement, Sandpiper has access to 13 propane storage tanks in Worcester County, Maryland, with total storage capacity of 570,000 gallons for a six-year period. For this access, Sandpiper has agreed to pay a monthly fee of $42,000 for the first annual period and a monthly fee of $125,000 for the remaining term of the agreement. Sandpiper will also purchase propane supply (initially estimated at approximately 7.4 million gallons of annual contract volume) from EGWIC over the same six-year period. Sandpiper has the option to pay a fixed per-gallon price for some or all of the propane purchases under this agreement or a market-based price using one of two local propane pricing indices. As further discussed in Note 4, “Rates and Other Regulatory Activities,” the cost of the capacity, supply and operating agreement will be recovered as a fuel cost in Sandpiper's new annual Gas Service Rate (“GSR”) filing.
Due to the specific property involved and the fixed monthly payments for the use of the storage capacity, the capacity portion of the capacity, supply and operating agreement must be accounted for as a capital lease. As a result, we recorded a capital lease asset and capital lease obligation of $7.1 million at the inception of the agreement. During the three and nine months ended September 30, 2013, we recorded approximately $62,000 and $83,000, respectively, for the interest on the capital lease obligation. During the three and nine months ended September 30, 2013, we recorded approximately $63,000 and $84,000, respectively, for the amortization of the capital lease asset. Since the entire amount of the capacity payments is expected to be recovered through the GSR mechanism, the timing and amount of the expense recognition, as well as the presentation of the expenses, will also follow the regulatory accounting.
Other Acquisitions
On June 7, 2013, we acquired the operating assets of Austin Cox Home Services, Inc. ("Austin Cox") for approximately $600,000. The purchased assets are used to provide heating, ventilation and air conditioning, plumbing and electrical services to residential, commercial and industrial customers throughout the lower Delmarva Peninsula. In connection with this acquisition, we recorded $105,000 in property, plant and equipment, $94,000 in inventory, $250,000 as an intangible asset related to a non-compete agreement to be amortized over five years beginning in July 2013 and $173,000 in goodwill. Valuation of certain property, plant and equipment and the intangible asset is preliminary and may be adjusted in the future based upon the final valuation, but no later than one year from the date of acquisition. All of the goodwill is expected to be deductible for income tax purposes.

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On February 5, 2013, Flo-Gas Corporation, our Florida propane distribution subsidiary, purchased the propane operating assets of Glades Gas Co., Inc. (“Glades”) for approximately $2.9 million. The purchased assets are used to provide propane distribution service to approximately 3,000 residential and commercial customers in Okeechobee, Glades and Hendry Counties, Florida. In connection with this acquisition, we recorded $1.6 million in property, plant and equipment, $502,000 in propane and other inventory, $300,000 in an intangible asset related to Glades’ customer list to be amortized over 12 years beginning in February 2013 and $453,000 in goodwill. Valuation of certain property, plant and equipment and the intangible asset is preliminary and may be adjusted in the future based upon the final valuation, but no later than one year from the date of acquisition. All of the goodwill is expected to be deductible for income tax purposes.

4.
Rates and Other Regulatory Activities
Our natural gas distribution operations in Delaware and Maryland, including Sandpiper, are subject to regulation by their respective PSC; Chesapeake’s Florida natural gas distribution division and the natural gas and electric operations of Florida Public Utilities Company (“FPU”) continue to be subject to regulation by the Florida PSC as separate entities. Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”); and Peninsula Pipeline Company, Inc. (“Peninsula Pipeline”), our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC.
Delaware
Natural Gas Expansion Service Offerings: On June 25, 2012, our Delaware division filed with the Delaware PSC an application for proposed natural gas expansion service offerings in order to increase the availability of natural gas within its Delaware service areas. In this filing, the Delaware division is seeking approval from the Delaware PSC of the following:
(i)
a monthly fixed charge to customers in portions of eastern Sussex County, Delaware, which will enable the Delaware division to extend its distribution system to provide natural gas service to these customers economically without upfront contributions from these customers;
(ii)
optional service offerings to customers to facilitate conversions to natural gas, including a conversion finance service to help customers manage their cost of conversion equipment; and
(iii)
a slight rate increase for all Delaware customers in order to support the additional costs associated with the administration of the proposed service offerings.
On July 3, 2012, the Delaware PSC opened the docket and set a period for formal interventions to be filed. On January 4, 2013, the Division of the Public Advocate (“DPA”) filed a motion to close the docket on the grounds that the proposed expansion service offerings should only be considered in the context of a full base rate case. On February 6, 2013, the Hearing Examiner assigned to the case issued a report recommending that the Delaware PSC deny the DPA’s motion. Subsequently, the DPA, Delaware PSC staff and our Delaware division reached an agreement in principle, which included the key provisions described above, with the exception of the proposed rate increase for Delaware customers residing outside of the expansion area. In July 2013, we filed the terms of this agreement in principle in supplemental testimony. A public comment hearing was held on September 12, 2013. On September 30, 2013, the parties involved in the agreement in principle submitted a signed settlement agreement, and on November 5, 2013, the Delaware PSC approved the settlement agreement.

Maryland

ESG Acquisition: On September 7, 2012, we filed an application with the Maryland PSC for approval of the acquisition of the ESG operating assets and the transfer of the ESG franchises to Chesapeake (see Note 3, “Acquisitions,” for additional information on the ESG acquisition). In this application, we also requested the Maryland PSC to approve the overall regulatory framework we proposed for our operation in Worcester County. The proposed regulatory framework includes: (i) a request for approval of a new gas service tariff and rates applicable to natural gas and propane distribution customers in Worcester County, including the customers currently being served by ESG; (ii) a request for approval of the capacity, supply and operating agreement with ESG for the supply and storage of propane, which will be utilized to serve the ESG system customers; and (iii) a request for approval of the accounting treatment for certain purchased assets.

On April 8, 2013, the parties finalized a settlement agreement, which was approved by the Maryland PSC, effective May 29, 2013. Under the order, the Maryland PSC granted approval of: (i) the ESG acquisition; (ii) the overall regulatory framework requested; and (iii) recovery of the cost of the capacity, supply and operating agreement with ESG. In addition, the Maryland PSC's order requires us to file a depreciation study within the first year after the

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acquisition, at which point, the proper amount of the accumulated depreciation associated with the purchased assets in the rate base and the depreciation rates on those assets will be determined and then applied prospectively. The order also requires us to file a base rate case within two and a half years of Sandpiper's new service in Worcester County. The acquisition of the ESG operating assets was completed on May 31, 2013.

On July 31, 2013, Sandpiper filed an application with the Maryland PSC to revise its tariff to allow, on a temporary basis until the next base rate case, negotiated contract rates for a discrete subset of commercial customers receiving propane service who: (i) experienced rate increases on June 1, 2013, when Sandpiper’s tariff took effect in Worcester County and (ii) do not meet the minimum usage requirement for eligibility for negotiated contract rates under the current tariff. On August 14, 2013, the Maryland PSC considered the application and accepted the proposed tariff revisions, effective August 14, 2013.

Florida
Marianna Franchise: On July 7, 2009, the City Commission of Marianna, Florida (the “Marianna Commission”) adopted an ordinance granting a franchise to FPU, effective February 1, 2010, for a period not to exceed ten years for the operation and distribution and/or sale of electric energy (the “Franchise Agreement”). The Franchise Agreement required FPU to 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, 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 were approved by the Marianna Commission and by the referendum, the closing of the purchase would have had to occur within 12 months after the referendum was approved. If the City of Marianna had elected to purchase the Marianna property, the Franchise Agreement would require the City of Marianna to pay FPU the fair market value for such property as determined by three qualified appraisers.
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 January 26, 2011, FPU filed a petition with the Florida PSC for approval of an amendment to FPU’s Generation Services Agreement between FPU and Gulf Power Company (“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 extended the current agreement by two years, with a new expiration date of December 31, 2019.
On February 11, 2011, the Florida PSC issued an order approving FPU’s petition for authority to implement the proposed TOU and interruptible rates, which became effective on February 8, 2011. The City of Marianna objected to the proposed rates and filed a petition protesting the entry of the Florida PSC’s order. On June 21, 2011, the Florida PSC issued an order approving the amendment to FPU's Generation Services Agreement. On July 12, 2011, the City of Marianna filed a protest of this decision and requested a hearing on the amendment. On January 24, 2012, the Florida PSC dismissed with prejudice the protests by the City of Marianna regarding both the TOU and interruptible rates and the amendment to the Generation Services Agreement.
The City of Marianna filed an appeal with the Florida Supreme Court on March 7, 2012 and with the Florida PSC on March 19, 2012, seeking an appellate review of both of the decisions by the Florida PSC with respect to the protests by the City of Marianna.
As more fully disclosed in Note 6, “Other Commitments and Contingencies,” on March 2, 2011, the City of Marianna 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. Prior to the scheduled trial date, FPU and the City of Marianna reached an agreement in principle to resolve their dispute, which resulted in the City of Marianna dismissing its legal action with prejudice on February 11, 2013. Subsequently, FPU and the City of Marianna entered into a settlement agreement, which contemplated, among other items, the City of Marianna proceeding with a referendum on the purchase of FPU’s facilities. On April 9, 2013, the referendum took place, and the citizens of the City of Marianna voted, by a wide margin, to reject the purchase of FPU's facilities by the City of Marianna. As a result of the outcome of the referendum

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and pursuant to the terms of the settlement agreement, FPU’s franchise with the City of Marianna was extended by ten years. Also pursuant to the settlement agreement, the City of Marianna withdrew its appeals before the Florida Supreme Court of the Florida PSC’s orders regarding the implementation of TOU and interruptible rates and the amendment to the Generation Services Agreement between FPU and Gulf Power.

FPU has incurred approximately $1.9 million of expenses associated with the City of Marianna litigation. In order to seek regulatory recovery of these extraordinary expenses, FPU filed a petition with the Florida PSC on August 27, 2012, for approval to: (i) defer, as a regulatory asset, the expenses associated with the litigation initiated by the City of Marianna; and (ii) amortize over five years, beginning in January 2013, previously expensed as well as future litigation expenses. Although this petition did not request recovery of these expenses, FPU sought deferral treatment of the expenses for regulatory purposes, which could allow future recovery of those expenses. On December 3, 2012, the Florida PSC issued an order approving FPU's request. Since this order does not provide specific recovery of these costs, we did not defer these costs as a regulatory asset at that point until further assurance of recovery can be obtained. Subsequent discussions with the Office of Public Counsel resulted in a settlement agreement on October 11, 2013. Under this settlement agreement, FPU will recover approximately $1.8 million of the total expenses associated with the City of Marianna litigation by retaining the $1.8 million refund received from Gulf Power. This refund represented the higher fuel cost paid by FPU during the City of Marianna franchise dispute as a result of the delay in implementing the amendment to the Generation Service Agreement. Upon reinstatement of the amendment, Gulf Power refunded this amount to FPU pursuant to the terms of the amendment.  The remaining litigation expenses would be amortized over the five-year period beginning in January 2013, as previously approved by the Florida PSC. The Florida PSC approved the settlement agreement on October 24, 2013.
Upon reaching the settlement agreement and obtaining a recommendation from the Florida PSC Staff supporting the approval of this settlement agreement, we established a regulatory asset of approximately$1.9 million at September 30, 2013 by reversing approximately $1.5 million of expenses recognized in 2011 and 2012 and $376,000 of expenses recognized during 2013. The refund of $1.8 million received from Gulf Power was reflected as a regulatory liability at September 30, 2013.
Other Matters: We also had developments in the following regulatory matters in Florida:
On September 28, 2012, FPU provided a letter to the Florida PSC stating its intent to request approval of a $745,800 acquisition adjustment associated with FPU’s purchase of the operating assets of Indiantown Gas Company (“IGC”) in 2010. In this letter, FPU also acknowledged the jurisdiction of the Florida PSC to calculate and dispose of prospective overearnings, if any, occurring after October 1, 2012, as the Florida PSC may determine at the conclusion of the acquisition adjustment proceeding. On December 11, 2012, FPU filed a petition to request approval of this acquisition adjustment associated with FPU’s purchase of IGC’s assets. The Florida PSC has scheduled an agenda on December 3, 2013 for a decision on this matter.
On December 14, 2012, Peninsula Pipeline filed a petition with the Florida PSC, asking for approval of a transportation service agreement with FPU. The agreement provides for an upstream interconnection of Peninsula Pipeline’s facilities with the Florida Gas Transmission Company (“FGT”) system and a downstream interconnection with FPU’s facilities. At the agenda conference on July 30, 2013, the Florida PSC approved this agreement.

On July 2, 2013, FPU filed a petition with the Florida PSC for recognition of a regulatory liability for a one-time curtailment gain associated with a change in the FPU Medical Plan. The change in the FPU Medical Plan was implemented effective January 1, 2012 in an effort to conform the benefits offered to FPU's employees to those offered by Chesapeake. The change in the FPU Medical Plan resulted in a total curtailment gain of $892,000, $722,000 of which was allocated to FPU's regulated operations. Since this gain resulted from the merger integration effort, FPU believes that the treatment most consistent with prior regulatory treatment would be to record the gain allocated to the regulated operations as a regulatory liability and amortize that amount over a specified period. This treatment is similar to how merger-related costs and a one-time tax contingency gain were treated. FPU is requesting approval to record regulatory liabilities of $464,000 and $258,000, respectively, in its natural gas and electric operations. FPU also seeks permission to amortize the proposed regulatory liabilities over a 34-month period, beginning January 1, 2012, and ending October 30, 2014. The Florida PSC approved this petition on October 24, 2013. We will record the amortization of this regulatory liability, including immediate recognition in current period earnings of the amortization related to the period prior to the Florida PSC's approval, beginning in the fourth quarter of 2013. This will reduce depreciation and amortization expense.


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Eastern Shore
The following are regulatory activities involving FERC orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system:
Mainline Expansion Project: On May 14, 2012, Eastern Shore submitted to the FERC an application for a Certificate of Public Convenience and Necessity ("CP") for approval to construct the facilities necessary to deliver additional firm service of 15,040 dekatherms per day (“Dts/d”) to an existing electric power generation customer and to Chesapeake’s Delaware and Maryland divisions. The estimated capital cost of the project is approximately $16.3 million. The filing was publicly noticed on May 25, 2012. Two of Eastern Shore’s existing customers and Chesapeake’s Delaware and Maryland divisions filed motions to intervene in support of the project. One existing customer filed a motion to intervene and protest. On June 28, 2012, Eastern Shore submitted a response to the protest, and on August 31, 2012, the protesting customer filed a reply to Eastern Shore’s response. On October 3, 2012, the US Department of the Interior submitted comments on the FERC’s environmental assessment regarding Eastern Shore’s re-vegetation plan. On October 9, 2012, a non-profit organization also submitted comments on the FERC’s environmental assessment, asserting that the environmental assessment was deficient and requesting the FERC to extend the comment period by 60 days. In February 2013, the FERC approved Eastern Shore’s application and issued a CP. On March 11, 2013, Eastern Shore accepted this CP and filed its environmental compliance plan. On March 21, 2013, the FERC issued a notice to proceed with construction. On November 1, 2013, Eastern Shore commenced service upon completion of construction and receipt of necessary approval by the FERC.
Daleville Compressor Station Upgrade Filing: On October 12, 2012, Eastern Shore submitted to the FERC an application for a CP, seeking authorization to construct a new gas-fired compressor unit at its existing Daleville Compressor Station located in Chester County, Pennsylvania. The new unit will provide 17,500 Dts/d of additional firm transportation service to two of Eastern Shore’s existing customers. In this application, Eastern Shore also included a description of a second new gas fired compressor unit to be installed at the Daleville Compressor Station, which will replace the three existing compressors that serve as back-up units to existing primary compressor units. Eastern Shore also plans to replace the engine exhaust devices of the existing primary compressor units with air emissions control equipment to comply with new environmental regulations. The replacement compressor unit and new engine exhaust devices will result in improved air emissions, reliability and flexibility on Eastern Shore’s system. Eastern Shore does not need specific FERC approval to construct the replacement compressor unit or emission controls; however, Eastern Shore wants the FERC to be fully advised of these improvement efforts. The estimated capital costs of the project are approximately $12.1 million. On March 4, 2013, the FERC approved this application. On April 19, 2013, the FERC issued a notice to proceed with construction. On November 1, 2013, Eastern Shore commenced service upon completion of construction and receipt of necessary approval by the FERC.

White Oak Lateral Project Filing: On June 13, 2013, Eastern Shore submitted to the FERC an application for a CP, seeking authorization to construct the White Oak lateral project located in Kent County, Delaware. The project consists of installing approximately 5.5 miles of 16-inch diameter pipeline, metering facilities and miscellaneous appurtenances extending from Eastern Shore's mainline system near its North Dover City Gate Station to the Garrison Oak Technical Park, all located in Dover, Delaware. This project is designed to provide 55,200 Dts/d of delivery lateral firm transportation service to Calpine Energy Services, L.P. ("Calpine") for its proposed 309 megawatt combined-cycle power plant under development. The total cost of the project is estimated to be approximately $11.2 million. Eastern Shore requested that the FERC issue an order granting the CP by December 14, 2013.

On August 9, 2013, the FERC issued a notice of intent to prepare an environmental assessment for the project. The comment period concluded on September 9, 2013 with no comments being filed in the docket. The environmental assessment was issued on October 4, 2013 and the federal authorization decision deadline is January 2, 2014. Eastern Shore anticipates beginning construction in early 2014 for an in-service date of January 1, 2015.

Other matters: Eastern Shore also had developments in the following FERC matters:

On May 31, 2013, Eastern Shore submitted to the FERC a combined filing of its Fuel Retention Percentage (“FRP”) and Cash-Out Refund for a twelve-month period beginning April 2012 and ending March 2013. In this filing, Eastern Shore proposed an FRP rate of 0.24 percent and continuation of its existing zero percent rate for the Cash-Out Surcharge. During the period, Eastern Shore experienced an under-recovery of $285,000 in its Deferred Gas Required for Operations costs and an over-recovery of $146,000 in its Deferred Cash-Out costs. Eastern Shore proposed to incorporate the Cash-Out Refund into its FRP to mitigate the effect of the increase in the FRP to its customers. On June 27, 2013, the FERC issued an order accepting Eastern Shore's submittal of a combined filing to update both its FRP and Cash-Out Refund mechanisms, effective July 1, 2013.

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5.
Environmental Commitments and Contingencies
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy at current and former operating sites the effect on the environment of the disposal or release of specified substances.
We have participated in the investigation, assessment or remediation, and have exposures at six former manufactured gas plant (“MGP”) sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of Environment (“MDE”) regarding a seventh former MGP site located in Cambridge, Maryland.
As of September 30, 2013, we had approximately $10.3 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 $9.1 million of which has been recovered as of September 30, 2013. We had approximately $4.9 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
In addition to the FPU MGP sites, we had $100,000 in environmental liabilities at September 30, 2013, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of September 30, 2013, we had approximately $339,000 in regulatory and other assets for future recovery through Chesapeake’s rates. Environmental liabilities for all of our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants.
We continue to expect that all costs related to environmental remediation and related activities will be recoverable from customers through rates.
The following discussion provides details on MGP sites:
West Palm Beach, Florida
Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is currently implementing a remedial plan approved by the Florida Department of Environmental Protection (“FDEP”) for the east parcel of the West Palm Beach site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. It is anticipated that similar remedial actions ultimately will be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.
Sanford, Florida
FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In January 2007, FPU and other responsible parties at the Sanford site (collectively with FPU the “Sanford Group”) signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the United States Environmental Protection Agency (“EPA”) for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of September 30, 2013, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.
The total cost of the final remedy is now estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

As of September 30, 2013, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of

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the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million as provided in the Third Participation Agreement 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, 2013.
Key West, Florida
FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two new monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October 4, 2012. FDEP responded via e-mail on October 9, 2012, that based on the data, Natural Attenuation Monitoring (“NAM”) appears to be an appropriate remedy for the site. The FDEP issued a Remedial Action Plan approval order, dated October 12, 2012, which specified that a limited semi-annual monitoring program is to be conducted. The annual cost to conduct the limited NAM program is not expected to exceed $8,000. Although the duration of the FDEP-required limited NAM cannot be determined with certainty, it is anticipated that total costs to complete the remedial action will not exceed $50,000.
Pensacola, Florida
FPU formerly owned and operated a 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 determination for the site, which must include a requirement for institutional and engineering controls. On December 13, 2011, Gulf Power, the City of Pensacola, FDOT and FPU submitted to FDEP a draft covenant for institutional and engineering controls for the site. Upon FDEP’s approval and the subsequent recording of the institutional and engineering controls, no further work is expected to be required of the parties. Assuming FDEP approves the draft institutional and engineering controls, it is anticipated that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.
Winter Haven, Florida
The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. The recent groundwater sampling results show a continuing reduction in contaminant concentrations from the treatment system, which has been in operation since 2002. Currently, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the remediation system. On August 7, 2012, FDEP issued a letter discussing the need to evaluate further remedial options, which could incorporate risk-management options, including natural attenuation and the use of institutional and engineering controls. Modifications to the existing consent order and the remedial action plan modification could be required to incorporate risk-management options into the remedy for the site. A response letter was submitted to FDEP on May 7, 2013, and the most recent groundwater monitoring report was submitted on June 17, 2013. FDEP issued an additional comment letter, dated September 16, 2013, containing various requests and questions, which we responded to on October 10, 2013. If modifications to the existing consent order and remedial action plan are required, we estimate that future remediation costs could be as much as $443,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. If we are required to incur this cost, we continue to believe that the entire amount will be recoverable from customers through our approved rates.

The current treatment system at the Winter Haven site does not address impacted soils in the southwest corner of the site. In 2010, we obtained conditional approval from FDEP for a soil excavation plan; however, because the costs associated with shoreline stabilization and dewatering are likely to be substantial, alternatives to this excavation plan are being evaluated.
FDEP has indicated that we may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures discussed by FDEP could cost as much as $1.0 million. We believe that corrective measures for the

- 15


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.
Salisbury, Maryland
We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized groundwater contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. We anticipate that the remaining costs of the one remaining monitoring well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission the one remaining monitoring well.
Other
We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.
We have investigated a potential environmental matter involving a property we recently purchased in Fernandina Beach, Florida. We determined that there was no contamination at this site; therefore, we have not recorded an environmental liability for this site.


- 16


6.
Other Commitments and Contingencies
Litigation
On March 2, 2011, the City of Marianna 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 sought 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 were approved by the Marianna Commission and the referendum were approved by the voters, the closing of the purchase had to occur within 12 months after the referendum was 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. 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 had 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. In December 2011, the City of Marianna filed a motion for summary judgment. On April 3, 2012, the court conducted a hearing on the City of Marianna’s motion for summary judgment. The court subsequently denied in part and granted in part the City of Marianna’s motion after concluding that issues of fact remained for trial with respect to each of the three alleged breaches of the Franchise Agreement.
Prior to the February 2013 trial date, FPU and the City of Marianna reached an agreement in principle to resolve their dispute, which resulted in the City of Marianna dismissing its legal action with prejudice on February 11, 2013. Subsequently, FPU and the City of Marianna entered into a settlement agreement, which contemplated, among other items, the City of Marianna proceeding with a referendum on the purchase of FPU’s facilities within the City of Marianna. On April 9, 2013, the referendum took place, and the citizens of the City of Marianna voted, by a wide margin, to reject the purchase of FPU’s facilities by the City of Marianna. As a result of the dismissal with prejudice of the legal action by the City of Marianna and the outcome of the referendum on the purchase of FPU’s facilities, we no longer have any contingencies related to claims by the City of Marianna.
We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows.
Natural Gas, Electric and Propane Supply
Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. Our Delaware and Maryland natural gas distribution divisions had a contract with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity, which expired on March 31, 2013. On April 1, 2013, our Delaware and Maryland divisions entered into a new contract with a different company to perform similar asset management functions. The new contract expires on March 31, 2015.
As discussed in Note 3, "Acquisitions," in May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Sandpiper's initial annual commitment is estimated at approximately 7.4 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.
Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream Natural Gas System, LLC (“Gulfstream”). Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including Peninsula Energy Services Company, Inc. (“PESCO”). Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay for the service.
In May 2013, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2014.

- 17


FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA (formerly known as Jacksonville Electric Authority) requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) a 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 having to provide an irrevocable letter of credit. As of September 30, 2013, FPU was in compliance with all of the requirements of its fuel supply contracts.
Sharp, our propane distribution subsidiary, entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term. Sharp's initial annual commitment is estimated at approximately 7.4 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.
Corporate Guarantees
The Board of Directors has authorized the Company to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $45.0 million.
We have issued corporate guarantees to certain vendors of our subsidiaries, primarily 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 subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at September 30, 2013 was $31.1 million, with the guarantees expiring on various dates through September 2014.
Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14, “Long-Term Debt,” to the condensed consolidated financial statements for further details).
In addition to the corporate guarantees, we have renewed a letter of credit for $1.0 million, which now expires on September 12, 2014, 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 $1.1 million, which expires on December 2, 2014, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for $304,000 to our former primary insurance company, which will expire on June 1, 2014. There have been no draws on these letters of credit as of September 30, 2013. 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 $2.3 million to Texas Eastern Transmission, LP (“TETLP”) related to firm transportation service agreements between our Delaware and Maryland divisions and TETLP.
Tax-related Contingencies
We are subject to various audits and reviews by the federal, state and local and other regulatory authorities regarding income taxes and taxes other than income. As of September 30, 2013, we maintained a liability of $300,000 related to unrecognized income tax benefits and $780,000 related to contingencies for taxes other than income. As of December 31, 2012, we maintained a liability of $300,000 related to unrecognized income tax benefits and $82,000 related to contingencies for taxes other than income. We recorded an additional accrual in the third quarter of 2013 related to taxes other than income based on our assessment of this contingency.




- 18


7.
Segment Information
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 are comprised of 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 financial information about our reportable segments.
 
 
 
Three Months
 
Nine Months
For the Periods Ended September 30,
 
2013
 
2012
 
2013
 
2012
(in thousands)
 
 
 
 
 
 
 
 
Operating Revenues, Unaffiliated Customers
 
 
 
 
 
 
 
 
Regulated Energy
 
$
55,387

 
$
51,868

 
$
191,666

 
$
179,139

Unregulated Energy
 
26,103

 
21,861

 
115,367

 
91,001

Other
 
5,055

 
4,446

 
14,386

 
12,846

Total operating revenues, unaffiliated customers
 
$
86,545

 
$
78,175

 
$
321,419

 
$
282,986

Intersegment Revenues (1)
 
 
 
 
 
 
 
 
Regulated Energy
 
$
293

 
$
328

 
$
797

 
$
906

Unregulated Energy
 
2,159

 
1,398

 
3,911

 
2,322

Other
 
274

 
220

 
743

 
675

Total intersegment revenues
 
$
2,726

 
$
1,946

 
$
5,451

 
$
3,903

Operating Income
 
 
 
 
 
 
 
 
Regulated Energy
 
$
10,243

 
$
7,848

 
$
36,169

 
$
33,151

Unregulated Energy
 
(1,803
)
 
(709
)
 
8,013

 
4,044

Other and eliminations
 
280

 
425

 
240

 
897

Total operating income
 
8,720

 
7,564

 
44,422

 
38,092

Other income, net of other expenses
 
101

 
(136
)
 
413

 
212

Interest
 
2,026

 
2,126

 
6,114

 
6,657

Income before Income Taxes
 
6,795

 
5,302

 
38,721

 
31,647

Income taxes
 
2,916

 
2,083

 
15,617

 
12,641

Net Income
 
$
3,879

 
$
3,219

 
$
23,104

 
$
19,006

 
(1) 
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.

- 19


(in thousands)
 
September 30,
2013
 
December 31,
2012
Identifiable Assets
 
 
 
 
Regulated energy
 
$
683,258

 
$
615,438

Unregulated energy
 
88,032

 
79,287

Other
 
26,267

 
39,021

Total identifiable assets
 
$
797,557

 
$
733,746


Our operations are almost entirely domestic. Our advanced information services subsidiary, BravePoint, has infrequent transactions in foreign countries, which are denominated and paid primarily in U.S. dollars. These transactions are immaterial to the consolidated revenues.
 
8.
Accumulated Other Comprehensive Income (Loss)
The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the three and nine months ended September 30, 2013. Defined benefit pension and postretirement plan items are the only component of our accumulated comprehensive income (loss). All amounts in the following table are presented net of tax.
 
For the Periods Ended September 30, 2013
 
Three Months
 
Nine Months
(in thousands)
 
 
 
 
Beginning balance
 
$
(4,958
)
 
$
(5,062
)
Other comprehensive loss before reclassifications
 

 
(6
)
Amounts reclassified from accumulated other comprehensive loss
 
55

 
165

Net current-period other comprehensive income
 
55

 
159

Ending balance
 
$
(4,903
)
 
$
(4,903
)
The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2013.
 
For the Periods Ended September 30, 2013
 
Three Months
 
Nine Months
(in thousands)
 
 
 
 
Amortization of defined benefit pension and postretirement plan items:
 
 
 
 
Prior service cost (1)
 
$
15

 
$
45

Net loss (1)
 
$
(107
)
 
$
(320
)
Total before tax
 
(92
)

(275
)
Tax benefit
 
37

 
110

Net of tax
 
$
(55
)
 
$
(165
)
 
(1) 
These amounts are included in the computation of net periodic costs (benefits). See Note 9, “Employee Benefit Plans,” for additional details.
Amortization of defined benefit pension and postretirement plan items are included in operations expense in the accompanying condensed consolidated statements of income. Tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.
 


- 20


9.
Employee Benefit Plans
Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, 2013 and 2012 are set forth in the following tables:
 
 
 
Chesapeake
Pension Plan
 
FPU
Pension Plan
 
Chesapeake
Pension SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
For the Three Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Service cost
 
$

 
$

 
$

 
$

 
$

 
$

 
$

 
$

 
$

 
$
40

Interest cost
 
102

 
125

 
594

 
638

 
21

 
23

 
12

 
15

 
16

 
45

Expected return on plan assets
 
(126
)
 
(108
)
 
(719
)
 
(658
)
 

 

 

 

 

 

Amortization of prior service cost
 

 
(1
)
 

 

 
5

 
5

 
(19
)
 
(20
)
 

 

Amortization of net loss
 
57

 
85

 
81

 
43

 
16

 
11

 
18

 
18

 

 
23

Net periodic cost (benefit)
 
33

 
101

 
(44
)
 
23

 
42

 
39

 
11

 
13

 
16

 
108

Amortization of pre-merger regulatory asset
 

 

 
191

 
190

 

 

 

 

 
2

 
2

Total periodic cost
 
$
33

 
$
101

 
$
147

 
$
213

 
$
42

 
$
39

 
$
11

 
$
13


$
18

 
$
110

 
 
Chesapeake
Pension Plan
 
FPU
Pension Plan
 
Chesapeake
Pension SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
For the Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Service cost
 
$

 
$

 
$

 
$

 
$

 
$

 
$

 
$

 
$

 
$
120

Interest cost
 
307

 
375

 
1,782

 
1,916

 
62

 
68

 
36

 
45

 
47

 
135

Expected return on plan assets
 
(378
)
 
(326
)
 
(2,156
)
 
(1,973
)
 

 

 

 

 

 

Amortization of prior service cost
 
(1
)
 
(4
)
 

 

 
14

 
15

 
(58
)
 
(60
)
 

 

Amortization of net loss
 
171

 
255

 
243

 
131

 
48

 
34

 
55

 
53

 

 
68

Net periodic cost (benefit)
 
99

 
300

 
(131
)
 
74

 
124

 
117

 
33

 
38

 
47

 
323

Amortization of pre-merger regulatory asset
 

 

 
571

 
571

 

 

 

 

 
6

 
6

Total periodic cost
 
$
99

 
$
300

 
$
440

 
$
645

 
$
124

 
$
117

 
$
33

 
$
38


$
53

 
$
329




We expect to record pension and postretirement benefit costs of approximately $999,000 for 2013. Included in these costs 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 $4.6 million and $5.2 million at September 30, 2013 and December 31, 2012, respectively.
FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the merger pursuant to a Florida PSC order. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake’s operations is recorded to accumulated other comprehensive income/loss. The following table presents the amounts included in the regulatory asset and accumulated other comprehensive income/loss that were recognized as components of net periodic benefit cost during the three and nine months ended September 30, 2013:
 

- 21


For Three Months Ended September 30, 2013
 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 
Chesapeake
Pension SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (credit)
 
$

 
$

 
$
5

 
$
(19
)
 
$

 
(14
)
Net loss
 
57

 
81

 
16

 
18

 

 
172

Total recognized in net periodic benefit cost
 
$
57

 
$
81

 
$
21

 
$
(1
)
 
$

 
$
158

Recognized from accumulated other comprehensive loss (1)
 
$
57

 
$
15

 
$
21

 
$
(1
)
 
$

 
$
92

Recognized from regulatory asset
 

 
66

 

 

 

 
66

Total
 
$
57

 
$
81

 
$
21

 
$
(1
)
 
$

 
$
158


For the Nine Months Ended September 30, 2013
 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 
Chesapeake
Pension SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (credit)
 
$
(1
)
 
$

 
$
14

 
$
(58
)
 
$

 
(45
)
Net loss
 
171

 
243

 
48

 
55

 

 
517

Total recognized in net periodic benefit cost
 
$
170

 
$
243

 
$
62

 
$
(3
)
 
$

 
$
472

Recognized from accumulated other comprehensive loss (1)
 
$
170

 
$
46

 
$
62

 
$
(3
)
 
$

 
$
275

Recognized from regulatory asset
 

 
197

 

 

 

 
197

Total
 
$
170

 
$
243

 
$
62

 
$
(3
)
 
$

 
$
472

 
(1) 
See Note 8, “Accumulated Other Comprehensive Income (Loss).
During the three and nine months ended September 30, 2013, we contributed $142,000 and $233,000, respectively, to the Chesapeake pension plan. We also contributed $211,000 and $421,000, respectively, to the FPU pension plan during the three and nine months ended September 30, 2013. We expect to contribute a total of $364,000 and $842,000 to the Chesapeake and FPU pension plans, respectively, during 2013, representing minimum contribution payments required in 2013.
The Chesapeake Pension Supplemental Executive Retirement Plan (“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 Pension SERP for the three and nine months ended September 30, 2013, were $22,000 and $67,000, respectively. We expect to pay total cash benefits of approximately $88,000 under the Chesapeake Pension SERP in 2013. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three and nine months ended September 30, 2013, were $16,000 and $53,000, respectively. We have estimated that approximately $97,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2013. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, 2013, were $50,000 and $91,000, respectively. We estimate that approximately $258,000 will be paid for such benefits under the FPU Medical Plan in 2013.



- 22


10.
Investments
The investment balances at September 30, 2013 and December 31, 2012, consist of the following:
 
(in thousands)
 
September 30,
2013
 
December 31,
2012
Rabbi trust (associated with Supplemental Executive Retirement Savings Plan)
 
$
2,691

 
$
2,116

Rabbi trust (associated with certain directors' compensation)
 
97

 
39

Investments in equity securities