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EX-32.2 - EXHIBIT 32.2 - CHESAPEAKE UTILITIES CORPcpk6302014ex-322.htm
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EX-31.2 - EXHIBIT 31.2 - CHESAPEAKE UTILITIES CORPcpk6302014ex-312.htm
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EXCEL - IDEA: XBRL DOCUMENT - CHESAPEAKE UTILITIES CORPFinancial_Report.xls

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: June 30, 2014
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 $0.4867 9,714,994 shares outstanding as of July 31, 2014.



Table of Contents
 




GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification
ASU: Accounting Standards Update
Austin Cox: Austin Cox Home Services, Inc.
BravePoint: BravePoint®, Inc., our advanced information services subsidiary, headquartered in Norcross, Georgia
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: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure
Chesapeake Pension Plan: A defined benefit pension plan sponsored by Chesapeake
Chesapeake Postretirement Plan: An unfunded postretirement health care and life insurance plan sponsored by Chesapeake
Chesapeake SERP: An unfunded supplemental executive retirement pension plan sponsored by Chesapeake
Company: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure
CP: Certificate of Public Convenience and Necessity
Deferred Compensation Plan: A non-qualified, deferred compensation arrangement under which certain of our executives and members of the Board of Directors are able to defer payment of all or a part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors’ retainers and fees
Delmarva Peninsula: A peninsula on the east coast of the United States of America occupied by Delaware and portions of Maryland and Virginia
DNREC: Delaware Department of Natural Resources and Environmental Control
DSCP: Directors Stock Compensation Plan
Dts/d: Dekatherms per day
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
EPA: United States Environmental Protection Agency
ESG: Eastern Shore Gas Company and its affiliates
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
FPU Medical Plan: A separate unfunded postretirement medical plan for FPU sponsored by Chesapeake
FPU Pension Plan: A separate defined benefit pension plan for FPU sponsored by Chesapeake
FRP: Fuel Retention Percentage



GAAP: Accounting principles generally accepted in the United States of America
Glades: Glades Gas Co., Inc.
GRIP: Gas Reliability Infrastructure Program, which is a surcharge to natural gas customers designed to recover capital and other program-related costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services in Florida
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
MDE: Maryland Department of Environment
MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use
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 that have been or will be entered into with the Note Holders
OTC: Over-the-counter
Peninsula Pipeline: Peninsula Pipeline Company, Inc., our wholly-owned Florida intrastate pipeline subsidiary
PESCO: Peninsula Energy Services Company, Inc., our wholly-owned natural gas marketing subsidiary
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: FPU 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 issued on December 16, 2013 pursuant to the Note Agreement
Series B Notes: Series B of the unsecured Senior Notes issued on May 15, 2014 pursuant to the Note Agreement
Sharp: Sharp Energy, Inc., our wholly-owned propane distribution subsidiary
SICP: 2013 Stock and Incentive Compensation Plan, which replaced DSCP and PIP effective May 2, 2013
TETLP: Texas Eastern Transmission, LP
Xeron: Xeron, Inc., our propane wholesale marketing subsidiary, 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 Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
(in thousands, except shares and per share data)
 
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
Regulated energy
 
$
61,646

 
$
55,216

 
$
163,812

 
$
136,783

Unregulated energy
 
34,321

 
36,025

 
114,294

 
91,016

Other
 
4,530

 
2,905

 
8,728

 
7,075

Total Operating Revenues
 
100,497

 
94,146

 
286,834

 
234,874

Operating Expenses
 
 
 
 
 
 
 
 
Regulated energy cost of sales
 
24,672

 
22,115

 
78,979

 
63,730

Unregulated energy and other cost of sales
 
28,442

 
28,773

 
89,766

 
68,861

Operations
 
24,615

 
22,822

 
51,242

 
44,577

Maintenance
 
2,457

 
1,820

 
4,606

 
3,542

Depreciation and amortization
 
6,736

 
5,977

 
13,371

 
11,797

Other taxes
 
3,118

 
3,487

 
6,791

 
6,665

Total Operating Expenses
 
90,040

 
84,994

 
244,755

 
199,172

Operating Income
 
10,457

 
9,152

 
42,079

 
35,702

Other income, net of other expenses
 
405

 
24

 
413

 
312

Interest charges
 
2,303

 
2,016

 
4,459

 
4,088

Income Before Income Taxes
 
8,559

 
7,160

 
38,033

 
31,926

Income taxes
 
3,425

 
2,804

 
15,218

 
12,701

Net Income
 
$
5,134

 
$
4,356

 
$
22,815

 
$
19,225

Weighted Average Common Shares Outstanding:
 
 
 
 
 
 
 
 
Basic
 
9,704,161

 
9,621,580

 
9,681,422

 
9,611,610

Diluted
 
9,737,852

 
9,695,470

 
9,715,762

 
9,687,253

Earnings Per Share of Common Stock:
 
 
 
 
 
 
 
 
Basic
 
$
0.53

 
$
0.45

 
$
2.36

 
$
2.00

Diluted
 
$
0.53

 
$
0.45

 
$
2.35

 
$
1.99

Cash Dividends Declared Per Share of Common Stock
 
$
0.405

 
$
0.385

 
$
0.790

 
$
0.750

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 Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
(in thousands)
 
 
 
 
 
 
 
 
Net Income
 
$
5,134

 
$
4,356

 
$
22,815

 
$
19,225

Other Comprehensive Income, net of tax:
 
 
 
 
 
 
 
 
Employee Benefits, net of tax:
 
 
 
 
 
 
 
 
Amortization of prior service cost, net of tax of ($6), ($6), ($12), and ($12) respectively
 
(9
)
 
(9
)
 
(18
)
 
(18
)
Net gain, net of tax of $27, $43, $53 and $81, respectively
 
40

 
64

 
79

 
122

Cash Flow Hedges, net of tax:
 
 
 
 
 
 
 
 
Unrealized loss on commodity contract cash flow hedges, net of tax of ($1), $0, ($1) and $0, respectively.
 
(1
)
 

 
(1
)
 

Total other comprehensive income
 
30

 
55

 
60

 
104

Comprehensive Income
 
$
5,164

 
$
4,411

 
$
22,875

 
$
19,329

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


- 2


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Assets
 
June 30,
2014
 
December 31,
2013
(in thousands, except shares)
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Regulated energy
 
$
710,444

 
$
691,522

Unregulated energy
 
78,616

 
76,267

Other
 
21,677

 
21,002

Total property, plant and equipment
 
810,737

 
788,791

Less: Accumulated depreciation and amortization
 
(186,663
)
 
(174,148
)
Plus: Construction work in progress
 
36,615

 
16,603

Net property, plant and equipment
 
660,689

 
631,246

Current Assets
 
 
 
 
Cash and cash equivalents
 
2,529

 
3,356

Accounts receivable (less allowance for uncollectible accounts of $1,819 and $1,635, respectively)
 
44,858

 
75,293

Accrued revenue
 
7,631

 
13,910

Propane inventory, at average cost
 
6,836

 
10,456

Other inventory, at average cost
 
3,382

 
4,880

Storage gas prepayments
 
3,131

 
4,318

Prepaid expenses
 
4,229

 
6,910

Income taxes receivable
 

 
2,609

Mark-to-market energy assets
 
136

 
385

Regulatory assets
 
5,822

 
2,436

Deferred income taxes
 
1,657

 
1,696

Other current assets
 
203

 
160

Total current assets
 
80,414

 
126,409

Deferred Charges and Other Assets
 
 
 
 
Investments, at fair value
 
3,542

 
3,098

Regulatory assets
 
66,300

 
66,584

Goodwill
 
4,625

 
4,354

Other intangible assets, net
 
2,775

 
2,975

Receivables and other deferred charges
 
2,740

 
2,856

Total deferred charges and other assets
 
79,982

 
79,867

Total Assets
 
$
821,085

 
$
837,522

 
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
 
June 30,
2014
 
December 31,
2013
(in thousands, except shares and per share data)
 
 
 
 
Capitalization
 
 
 
 
Stockholders’ equity
 
 
 
 
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)
 
$
4,727

 
$
4,691

Additional paid-in capital
 
154,619

 
152,341

Retained earnings
 
139,350

 
124,274

Accumulated other comprehensive loss
 
(2,473
)
 
(2,533
)
Deferred compensation obligation
 
1,202

 
1,124

Treasury stock
 
(1,202
)
 
(1,124
)
Total stockholders’ equity
 
296,223

 
278,773

Long-term debt, net of current maturities
 
165,370

 
117,592

Total capitalization
 
461,593

 
396,365

Current Liabilities
 
 
 
 
Current portion of long-term debt
 
11,117

 
11,353

Short-term borrowing
 
47,870

 
105,666

Accounts payable
 
30,184

 
53,482

Accrued compensation
 
5,495

 
8,394

Accrued interest
 
1,352

 
1,235

Dividends payable
 
3,933

 
3,710

Income taxes payable
 
695

 

Mark-to-market energy liabilities
 
32

 
127

Regulatory liabilities
 
5,875

 
4,157

Customer deposits and refunds
 
23,482

 
26,140

Other accrued liabilities
 
9,978

 
7,678

Total current liabilities
 
140,013

 
221,942

Deferred Credits and Other Liabilities
 
 
 
 
Deferred income taxes
 
142,766

 
142,597

Deferred investment tax credits
 
57

 
74

Regulatory liabilities
 
3,975

 
4,402

Accrued asset removal cost—Regulatory liability
 
39,991

 
39,510

Environmental liabilities
 
9,076

 
9,155

Other pension and benefit costs
 
20,123

 
21,000

Other liabilities
 
3,491

 
2,477

Total deferred credits and other liabilities
 
219,479

 
219,215

Other commitments and contingencies (Note 6)
 

 

Total Capitalization and Liabilities
 
$
821,085

 
$
837,522

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


- 4


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
 
 
Six Months Ended
 
 
June 30,
 
 
2014
 
2013
(in thousands)
 
 
 
 
Operating Activities
 
 
 
 
Net income
 
$
22,815

 
$
19,225

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
13,371

 
11,797

Depreciation and accretion included in other costs
 
3,447

 
3,030

Deferred income taxes, net
 
166

 
5,796

Gain on sale of assets
 
(420
)
 
(39
)
Unrealized (gain) loss on commodity contracts
 
62

 
(153
)
Unrealized gain on investments
 
(152
)
 
(42
)
Realized gain on sales of investments, net
 

 
(310
)
Employee benefits
 
319

 
458

Share-based compensation
 
1,065

 
861

Other, net
 
(1
)
 
(22
)
Changes in assets and liabilities:
 
 
 
 
Purchase of investments
 
(293
)
 
(398
)
Accounts receivable and accrued revenue
 
36,713

 
(6,268
)
Propane inventory, storage gas and other inventory
 
6,074

 
2,180

Regulatory assets
 
(5,250
)
 
1,721

Prepaid expenses and other current assets
 
3,183

 
2,312

Accounts payable and other accrued liabilities
 
(22,491
)
 
8,074

Income taxes receivable and payable
 
3,305

 
6,599

Accrued interest
 
118

 
(316
)
Customer deposits and refunds
 
(2,658
)
 
(3,958
)
Accrued compensation
 
(2,975
)
 
(2,060
)
Regulatory liabilities
 
1,761

 
5,588

Other assets and liabilities, net
 
63

 
(12
)
Net cash provided by operating activities
 
58,222

 
54,063

Investing Activities
 
 
 
 
Property, plant and equipment expenditures
 
(42,753
)
 
(41,220
)
Proceeds from sales of assets
 
459

 
45

Acquisitions
 

 
(19,541
)
Environmental expenditures
 
(79
)
 
(209
)
Net cash used in investing activities
 
(42,373
)
 
(60,925
)
Financing Activities
 
 
 
 
Common stock dividends
 
(6,754
)
 
(6,356
)
Purchase of stock for Dividend Reinvestment Plan
 
(392
)
 
(655
)
Change in cash overdrafts due to outstanding checks
 
(806
)
 
(1,240
)
Net borrowing (repayment) under line of credit agreements
 
(56,990
)
 
15,532

Proceeds from issuance of long-term debt
 
50,000

 
7,000

Repayment of long-term debt and capital lease obligation
 
(1,734
)
 
(8,570
)
Net cash provided by (used in) financing activities
 
(16,676
)
 
5,711

Net Decrease in Cash and Cash Equivalents
 
(827
)
 
(1,151
)
Cash and Cash Equivalents—Beginning of Period
 
3,356

 
3,361

Cash and Cash Equivalents—End of Period
 
$
2,529

 
$
2,210

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
Balance at December 31, 2012
9,597,499

 
$
4,671

 
$
150,750

 
$
106,239

 
$
(5,062
)
 
$
982

 
$
(982
)
 
$
256,598

Net Income

 

 

 
32,787

 

 

 

 
32,787

Other comprehensive income

 

 

 

 
2,529

 

 

 
2,529

Dividend declared ($1.520 per share)

 

 
(6
)
 
(14,752
)
 

 

 

 
(14,758
)
Conversion of debentures
17,383

 
8

 
287

 

 

 

 

 
295

Share-based compensation and tax benefit (2) (3)
23,348

 
12

 
1,310

 

 

 

 

 
1,322

Treasury stock activities

 

 

 

 

 
142

 
(142
)
 

Balance at December 31, 2013
9,638,230

 
4,691

 
152,341

 
124,274

 
(2,533
)
 
1,124

 
(1,124
)
 
278,773

Net Income

 

 

 
22,815

 

 

 

 
22,815

Other comprehensive income

 

 

 

 
60

 

 

 
60

Dividend declared ($0.790 per share)
5,193

 
3

 
318

 
(7,739
)
 

 

 

 
(7,418
)
Retirement Savings Plan
9,834

 
5

 
597

 

 

 

 

 
602

Conversion of debentures
31,542

 
15

 
520

 

 

 

 

 
535

Share-based compensation and tax benefit (2) (3)
26,772

 
13

 
843

 

 

 

 

 
856

Treasury stock activities

 

 

 

 

 
78

 
(78
)
 

Balance at June 30, 2014
9,711,571

 
$
4,727

 
$
154,619

 
$
139,350

 
$
(2,473
)
 
$
1,202

 
$
(1,202
)
 
$
296,223

 
(1) 
Includes 34,960 and 34,495 shares at June 30, 2014 and December 31, 2013, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan.
(2) 
Includes amounts for shares issued for Directors’ compensation.
(3) 
The shares issued under the SICP are net of shares withheld for employee taxes. For the quarter ended June 30, 2014 and for the year ended December 31, 2013, we withheld 8,458 and 10,411 shares, respectively, for taxes.

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 SEC and 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, 2013. 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.
Stock Dividend
On July 2, 2014, our Board of Directors approved a three-for-two stock split of our outstanding common stock to be effected in the form of a stock dividend. Each stockholder as of the close of business on the record date of August 13, 2014 will receive one additional share of common stock for every two shares of common stock owned. The stock dividend will be issued on September 8, 2014.

FASB Statements and Other Authoritative Pronouncements
Recent Accounting Standards Yet to be Adopted
Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. ASU 2014-09 is effective for reporting periods (interim and annual) beginning after December 15, 2016. We are currently assessing the impact this standard will have on our financial position and results of operations.
Recently Adopted Accounting Standards
Income Taxes (ASC 740) - In July 2013, the FASB issued 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. ASU 2013-11 became effective for us on January 1, 2014. The adoption of ASU 2013-11 had no material impact on our financial position and results of operations.



- 7


2.
Calculation of Earnings Per Share

 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
(in thousands, except shares and per share data)
 
 
 
 
 
 
 
 
Calculation of Basic Earnings Per Share:
 
 
 
 
 
 
 
 
Net Income
 
$
5,134

 
$
4,356

 
$
22,815

 
$
19,225

Weighted average shares outstanding
 
9,704,161

 
9,621,580

 
9,681,422

 
9,611,610

Basic Earnings Per Share
 
$
0.53

 
$
0.45

 
$
2.36

 
$
2.00

Calculation of Diluted Earnings Per Share:
 
 
 
 
 
 
 
 
Reconciliation of Numerator:
 
 
 
 
 
 
 
 
Net Income
 
$
5,134

 
$
4,356

 
$
22,815

 
$
19,225

Effect of 8.25% Convertible debentures (1)
 

 
11

 

 
22

Adjusted numerator—Diluted
 
$
5,134

 
$
4,367

 
$
22,815

 
$
19,247

Reconciliation of Denominator:
 
 
 
 
 
 
 
 
Weighted shares outstanding—Basic
 
9,704,161

 
9,621,580

 
9,681,422

 
9,611,610

Effect of dilutive securities:
 
 
 
 
 
 
 
 
Share-based Compensation
 
33,691

 
22,454

 
34,340

 
22,789

8.25% Convertible debentures (1)
 

 
51,436

 

 
52,854

Adjusted denominator—Diluted
 
9,737,852

 
9,695,470

 
9,715,762

 
9,687,253

Diluted Earnings Per Share
 
$
0.53

 
$
0.45

 
$
2.35

 
$
1.99

 (1) As of March 1, 2014, we no longer have any outstanding convertible debentures. See Note 14, Long-term debt for additional information.

3.
Acquisitions
Eastern Shore Gas Company
On May 31, 2013, the Maryland PSC approved the acquisition of ESG. Upon receiving this approval, we completed the purchase of certain operating assets of ESG, which was not related to, or affiliated with, our interstate natural gas transmission subsidiary, 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, and our propane distribution subsidiary, 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 and have begun to convert some of the acquired customers. Although most of these customers are currently being served with propane, we classify Sandpiper's operations as natural gas distribution in the Regulated Energy segment.
In connection with this acquisition, we recorded $12.6 million in property, plant and equipment, $384,000 in propane inventory, $2.5 million in accounts receivable and accrued revenue and $227,000 in other current liabilities, which included the effect of purchase price adjustments in the third quarter of 2013 and the second quarter of 2014. 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 final, as the final purchase price allocation was completed.
The revenue from this acquisition for the three and six months ended June 30, 2014, included in our condensed consolidated statement of income, were $4.2 million and $14.4 million, respectively. The net income from this acquisition for the three and six months ended June 30, 2014, included in our condensed consolidated statement of income, were $123,000 and $1.8 million, respectively.

- 8


Other Acquisitions
On December 2, 2013, we acquired certain operating assets of the City of Fort Meade, Florida, for approximately $792,000. The purchased assets are used to provide natural gas distribution service in the City of Fort Meade, Florida. In connection with this acquisition, we recorded $670,000 in property, plant and equipment, $14,000 in inventory, $150,000 in goodwill and $42,000 in other current liabilities. Valuation of certain property, plant and equipment 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. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three and six months ended June 30, 2014 were not material.
On February 5, 2013, we purchased the propane operating assets of 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, $231,000 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 $724,000 in goodwill. All of the goodwill is expected to be deductible for income tax purposes. These amounts reflect an adjustment to the allocation of the purchase price during the first quarter of 2014 based on our final valuation, which decreased the value of propane inventory by $271,000 and increased goodwill by the same amount. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three and six months ended June 30, 2014 were not material.

4.
Rates and Other Regulatory Activities
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities.
Delaware
There were no rates and other regulatory activities in Delaware during the first six months of 2014.
Maryland
On March 24, 2014, Sandpiper filed a depreciation study with the Maryland PSC regarding the assets purchased in the ESG acquisition. This depreciation study was filed in accordance with the order dated May 29, 2013, which allowed Sandpiper to recommend the proper depreciation rates and accumulated depreciation associated with the acquired assets. Sandpiper recommended slightly lower depreciation rates to be applied prospectively and a reduction of $4.5 million in accumulated depreciation. On June 20, 2014, the Maryland PSC staff recommended lower depreciation rates than those recommended by Sandpiper and a reduction of $5.5 million in accumulated depreciation. The Office of People’s Counsel also recommended lower depreciation rates and no adjustment to accumulated depreciation. The parties are currently discussing a potential settlement in advance of an evidentiary hearing in August 2014.

Florida
On April 28, 2014, FPU filed a base rate proceeding for its electric distribution operation. FPU requested interim rate relief of approximately $2.4 million and final rate relief of approximately $5.9 million. The interim rate relief requested is based on the twelve-month period ended September 30, 2013. At the July 10, 2014 Agenda Conference, the Florida PSC approved interim rate relief of approximately $2.2 million, as recommended by the Florida PSC staff. The interim rates are effective for meter readings on or after August 10, 2014. Any increase to our rates as a result of this interim rate relief may be subject to refund, depending on the outcome of the final rate relief request. The base rate proceeding hearing is currently scheduled for September 15-18, 2014. The revenue requirement will be determined at the Agenda Conference, currently scheduled for November 25, 2014, and final rates will be determined at the Agenda Conference, currently scheduled for December 16, 2014. Final rates are expected to be effective in January 2015.
On January 13, 2014, FPU's natural gas divisions and Chesapeake's Florida natural gas distribution division filed a consolidated natural gas depreciation study with the Florida PSC. We also filed for approval to establish a regulatory asset and related amortization to address the costs associated with the development of this study. Depending on the results of this proceeding, we may be required to change depreciation expense for our Florida natural gas distribution operations. The PSC agenda date for the depreciation study has not yet been set.

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On November 15, 2013, Chesapeake's Florida natural gas distribution division petitioned the Florida PSC for an extension to its surcharge to recover an additional $381,000 in estimated remaining environmental cleanup costs that have not yet been recovered. This extension would be effective for two years, beginning January 1, 2014. The Florida PSC approved the extension of the surcharge and the additional amount for recovery at the Agenda Conference on January 7, 2014.

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

TETLP Expansion Project: On January 31, 2014, Eastern Shore submitted to the FERC a request for prior notice authorization regarding a project that included certain improvements at Eastern Shore’s existing interconnection with TETLP near Honey Brook, Pennsylvania. This project will allow Eastern Shore to increase its capacity to receive natural gas from TETLP by 57,000 Dts/d to a total capacity of 107,000 Dts/d, but this requested improvement will not result in an increase in Eastern Shore’s overall system capacity. On April 8, 2014, the FERC approved Eastern Shore’s prior notice application, and Eastern Shore made this additional receipt point capacity available to an existing industrial customer.

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 an industrial customer facility currently under construction. The total cost of the project is estimated to be approximately $11.5 million.

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 FERC staff recommended a finding of no significant impact. Eastern Shore filed the implementation plan and acceptance of conditions, stating that it will comply with all environmental conditions as set forth in the order. On November 27, 2013, the FERC issued a CP for this project. On January 17, 2014, the FERC issued its notice to allow construction to proceed, and Eastern Shore began construction activities for this project on January 22, 2014, for a planned in-service date of January 1, 2015.

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

On May 30, 2014, Eastern Shore submitted to the FERC a combined filing of its FRP and Cash-Out Refund for a twelve-month period from April 2013 to March 2014. In this filing, Eastern Shore proposed an FRP rate of 0.62 percent. During the period, Eastern Shore experienced an under-recovery of $494,000 in its Deferred Gas Required for Operations costs and an over-recovery of $160,000 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.


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 remediate 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 and assessment of, and have remediation exposures at, six former 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 MDE regarding a seventh former MGP site located in Cambridge, Maryland. We were notified in December of 2013 by the DNREC that it would be conducting a facility evaluation of an eighth former MGP site located in Seaford, Delaware.
As of June 30, 2014, we had approximately $10.2 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 $9.4 million of which has been recovered as of June 30, 2014. We had approximately $4.6 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

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In addition to the FPU MGP sites, we had $454,000 in environmental liabilities at June 30, 2014, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of June 30, 2014, we had approximately $503,000 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 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 the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the 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 June 30, 2014, 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 June 30, 2014, 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 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, as provided in the Third Participation Agreement, 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 June 30, 2014.
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, 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 most recent groundwater-monitoring event was conducted on March

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13, 2014. The results were reported in a letter to FDEP dated April 26, 2014. Natural Attenuation Default Criteria were met at all locations sampled. The next semi-annual sampling event is scheduled for September of 2014.
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. The annual cost to conduct the limited NAM program is not expected to exceed $8,000.
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 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. 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. FDEP issued an additional comment letter, dated September 16, 2013, containing various requests and questions, which we responded to on October 10, 2013.
An exploratory drilling program was conducted in November of 2013. The most recent groundwater monitoring event was conducted on April 11, 2014, and results were reported in a letter to FDEP dated June 6, 2014. A meeting was held with FDEP on June 12, 2014 to discuss the results of the drilling program, the groundwater conditions, and potential future remedial actions. FDEP indicated that it may be possible to close out the site with institutional controls without modifying the existing consent order. FDEP is currently evaluating its administrative options.
Even if modifications to the existing consent order and remedial action plan are required, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $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 rates.
FDEP previously indicated that we could also be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, and our recent meeting with FDEP, we believe that corrective measures for lake sediments are not warranted and will not be required by FDEP. We therefore have not recorded a liability for sediment remediation.
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.
In a letter dated December 5, 2013, the DNREC notified us that it will be conducting a facility evaluation of a former MGP site in Seaford, Delaware. The facility evaluation has not been conducted, and the outcome of this evaluation cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

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6.
Other Commitments and Contingencies
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. For our Delaware and Maryland natural gas distribution divisions, we have a contract, which expires on March 31, 2015, with an unaffiliated energy marketing and risk management company to manage a portion of the divisions' natural gas transportation and storage capacity.
In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Sandpiper's current annual commitment is estimated at approximately 6.5 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. 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 2014, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2015.
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) 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 June 30, 2014, FPU was in compliance with all of the requirements of its fuel supply contracts.
Sharp 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 current annual commitment is estimated at approximately 6.5 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 against those specified in the other.
Corporate Guarantees
The Board of Directors has authorized us 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, the largest portion of which is for Xeron and PESCO. 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 when incurred. The aggregate amount guaranteed at June 30, 2014 was $31.6 million, with the guarantees expiring on various dates through June 2015.
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 issued a letter of credit for $1.0 million, which 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

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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, 2015. There have been no draws on these letters of credit as of June 30, 2014. 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 TETLP related to the precedent agreement and firm transportation service agreement between our Delaware and Maryland divisions.
On July 25, 2014, we provided a letter to the Florida PSC guaranteeing potential refunds from interim rates to be charged by our Florida electric operation. The interim rates, which provide a rate relief of approximately $2.2 million of revenue on an annual basis, were approved by the Florida PSC in July 2014 in connection with the base rate proceeding currently in progress. This guarantee will expire upon the release by the Florida PSC at the conclusion of the base rate proceeding. See Note 4, Rates and Other Regulatory Activities, for further details on the base rate proceeding involving the Florida electric operation.
Tax-related Contingencies
We are subject to various audits and reviews by the federal, state, local and other regulatory authorities regarding income taxes and taxes other than income. As of June 30, 2014, we maintained a liability of $300,000 related to unrecognized income tax benefits and $905,000 related to contingencies for taxes other than income. As of December 31, 2013, we maintained a liability of $300,000 related to unrecognized income tax benefits and $1.0 million related to contingencies for taxes other than income.
Other
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.

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 comprise three operating segments:
Regulated Energy. The Regulated Energy segment includes natural gas distribution, natural gas transmission operations and electric distribution 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 propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services.
Other. The “Other” segment consists primarily of our advanced information services subsidiary, as well as our unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

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The following table presents financial information about our reportable segments:
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
(in thousands)
 
 
 
 
 
 
 
 
Operating Revenues, Unaffiliated Customers
 
 
 
 
 
 
 
 
Regulated Energy
 
$
61,348

 
$
54,975

 
$
163,222

 
$
136,279

Unregulated Energy
 
34,299

 
34,273

 
114,173

 
89,264

Other
 
4,850

 
4,898

 
9,439

 
9,331

Total operating revenues, unaffiliated customers
 
$
100,497

 
$
94,146

 
$
286,834

 
$
234,874

Intersegment Revenues (1)
 
 
 
 
 
 
 
 
Regulated Energy
 
$
298

 
$
241

 
$
590

 
$
504

Unregulated Energy
 
22

 
1,752

 
121

 
1,752

Other
 
248

 
227

 
502

 
470

Total intersegment revenues
 
$
568

 
$
2,220

 
$
1,213

 
$
2,726

Operating Income
 
 
 
 
 
 
 
 
Regulated Energy
 
$
10,711

 
$
8,619

 
$
31,802

 
$
25,925

Unregulated Energy
 
(43
)
 
447

 
10,815

 
9,816

Other and eliminations
 
(211
)
 
86

 
(538
)
 
(39
)
Total operating income
 
10,457

 
9,152

 
42,079

 
35,702

Other income, net of other expenses
 
405

 
24

 
413

 
312

Interest
 
2,303

 
2,016

 
4,459

 
4,088

Income before Income Taxes
 
8,559

 
7,160

 
38,033

 
31,926

Income taxes
 
3,425

 
2,804

 
15,218

 
12,701

Net Income
 
$
5,134

 
$
4,356

 
$
22,815

 
$
19,225

 
(1) 
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
(in thousands)
 
June 30, 2014
 
December 31, 2013
Identifiable Assets
 
 
 
 
Regulated energy
 
$
716,126

 
$
708,950

Unregulated energy
 
77,800

 
100,585

Other
 
27,159

 
27,987

Total identifiable assets
 
$
821,085

 
$
837,522


Our operations are almost entirely domestic. 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.
 

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8.
Accumulated Other Comprehensive Income (Loss)
Defined benefit pension and postretirement plan items and unrealized gains (losses) of our propane swap agreements designated as commodity contracts cash flow hedges are the components of our accumulated comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive income (loss), net of related tax effects, for each component of other comprehensive income for the six months ended June 30, 2014 and 2013.

 
 
Defined Benefit
 
Commodity
 
 
 
 
Pension and
 
Contracts
 
 
 
 
Postretirement
 
Cash Flow
 
 
 
 
Plan Items
 
Hedges
 
Total
(in thousands)
 
 
 
 
 
 
December 31, 2013
 
$
(2,533
)
 
$

 
$
(2,533
)
Other comprehensive loss before reclassifications
 

 
(1
)
 
(1
)
Amounts reclassified from accumulated other comprehensive loss
 
61

 

 
61

Net current-period other comprehensive income (loss)
 
61

 
(1
)
 
60

June 30, 2014
 
$
(2,472
)
 
$
(1
)
 
$
(2,473
)

 
 
 
Defined Benefit
 
Commodity
 
 
 
 
Pension and
 
Contracts
 
 
 
 
Postretirement
 
Cash Flow
 
 
 
 
Plan Items
 
Hedges
 
Total
(in thousands)
 
 
 
 
 
 
December 31, 2012
 
$
(5,062
)
 
$

 
$
(5,062
)
Other comprehensive loss before reclassifications
 
(6
)
 

 
(6
)
Amounts reclassified from accumulated other comprehensive loss
 
110

 

 
110

Net current-period other comprehensive income
 
104

 

 
104

June 30, 2013
 
$
(4,958
)
 
$

 
$
(4,958
)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013. The only such amounts for those periods were defined benefit pension and postretirement plan items. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
(in thousands)
 
 
 
 
 
 
 
 
Amortization of defined benefit pension and postretirement plan items:
 
 
 
 
 
 
 
 
Prior service cost (1)
 
$
15

 
$
15

 
$
30

 
$
30

Net loss (1)
 
(67
)
 
(107
)
 
(132
)
 
(213
)
Total before income taxes
 
(52
)

(92
)
 
(102
)
 
(183
)
Income tax benefit
 
21

 
37

 
41

 
73

Net of tax
 
$
(31
)
 
$
(55
)
 
$
(61
)
 
$
(110
)
 
(1) These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.

- 16


Amortization of defined benefit pension and postretirement plan items is included in operations expense in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.
 

9.
Employee Benefit Plans
Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2014 and 2013 are set forth in the following tables:
 
 
 
Chesapeake
Pension Plan
 
FPU
Pension Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
For the Three Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost
 
$
106

 
$
103

 
$
647

 
$
594

 
$
23

 
$
20

 
$
13

 
$
12

 
$
16

 
$
16

Expected return on plan assets
 
(132
)
 
(126
)
 
(772
)
 
(718
)
 

 

 

 

 

 

Amortization of prior service cost
 

 

 

 

 
5

 
5

 
(20
)
 
(20
)
 

 

Amortization of net loss
 
38

 
57

 

 
81

 
12

 
16

 
17

 
19

 

 

Net periodic cost (benefit)
 
12

 
34

 
(125
)
 
(43
)
 
40

 
41

 
10

 
11

 
16

 
16

Amortization of pre-merger regulatory asset
 

 

 
191

 
191

 

 

 

 

 
2

 
2

Total periodic cost
 
$
12

 
$
34

 
$
66

 
$
148

 
$
40

 
$
41

 
$
10

 
$
11


$
18

 
$
18


 
 
Chesapeake
Pension Plan
 
FPU
Pension Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
For the Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost
 
$
213

 
$
205

 
$
1,294

 
$
1,188

 
$
46

 
$
41

 
$
26

 
$
24

 
$
33

 
$
32

Expected return on plan assets
 
(265
)
 
(252
)
 
(1,545
)
 
(1,437
)
 

 

 

 

 

 

Amortization of prior service cost
 

 
(1
)
 

 

 
9

 
10

 
(39
)
 
(39
)
 

 

Amortization of net loss
 
75

 
114

 

 
162

 
24

 
32

 
33

 
36

 

 

Net periodic cost (benefit)
 
23

 
66

 
(251
)
 
(87
)
 
79

 
83

 
20

 
21

 
33

 
32

Amortization of pre-merger regulatory asset
 

 

 
381

 
381

 

 

 

 

 
4

 
4

Total periodic cost
 
$
23

 
$
66

 
$
130

 
$
294

 
$
79

 
$
83

 
$
20

 
$
21

 
$
37

 
$
36


We expect to record pension and postretirement benefit costs of approximately $578,000 for 2014. 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 for 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 $4.0 million and $4.4 million at June 30, 2014 and December 31, 2013, respectively. The amortization included in pension expense is being offset by a net periodic benefit of $191,000, which will reduce our total expected benefit costs to $578,000.
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 six months ended June 30, 2014 and 2013:
 

- 17


For the Three Months Ended June 30, 2014
 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (credit)
 
$

 
$

 
$
5

 
$
(20
)
 
$

 
(15
)
Net loss
 
38

 

 
12

 
17

 

 
67

Total recognized in net periodic benefit cost
 
$
38

 
$

 
$
17

 
$
(3
)
 
$

 
$
52

Recognized from accumulated other comprehensive loss (1)
 
$
38

 
$

 
$
17

 
$
(3
)
 
$

 
$
52

Recognized from regulatory asset
 

 

 

 

 

 

Total
 
$
38

 
$

 
$
17

 
$
(3
)
 
$

 
$
52


For the Six Months Ended June 30, 2014
 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (credit)
 
$

 
$

 
$
9

 
$
(39
)
 
$

 
(30
)
Net loss
 
75

 

 
24

 
33

 

 
132

Total recognized in net periodic benefit cost
 
$
75

 
$

 
$
33

 
$
(6
)
 
$

 
$
102

Recognized from accumulated other comprehensive loss (1)
 
$
75

 
$

 
$
33

 
$
(6
)
 
$

 
$
102

Recognized from regulatory asset
 

 

 

 

 

 

Total
 
$
75

 
$

 
$
33

 
$
(6
)
 
$

 
$
102


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

 
$

 
$
5

 
$
(20
)
 
$

 
(15
)
Net loss
 
57

 
81

 
16

 
19

 

 
173

Total recognized in net periodic benefit cost