10-Q
Table of Contents

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, 2015
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 $0.486715,268,158 shares outstanding as of October 31, 2015.


Table of Contents

Table of Contents
 
 
 
 
 
 
 
    ITEM 1.
 
 
 
    ITEM 2.
 
 
 
    ITEM 3.
 
 
 
    ITEM 4.
 
 
 
 
 
    ITEM 1.
 
 
 
    ITEM 1A.
 
 
 
    ITEM 2.
 
 
 
    ITEM 3.
 
 
 
    ITEM 5.
 
 
 
    ITEM 6.
 
 



Table of Contents

GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification
ASU: Accounting Standards Update
Aspire Energy of Ohio: Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake into which Gatherco, Inc. merged on April 1, 2015
BravePoint: BravePoint, Inc., our former advanced information services subsidiary, headquartered in Norcross, Georgia, which was sold on October 1, 2014
CDD: Cooling degree-day, 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
CHP: A combined heat and power plant being constructed by Eight Flags in Nassau County, Florida
Company: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure
Credit Agreement: An agreement between Chesapeake, PNC and other participating lenders related to our unsecured revolving credit facility
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
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
Eight Flags: Eight Flags Energy, LLC, a subsidiary of Chesapeake OnSight Services, LLC
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 United States 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


Table of Contents

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
Gatherco: Gatherco, Inc.
GRIP: Gas Reliability Infrastructure Program is a natural gas pipeline replacement program in Florida, pursuant to which we collect a surcharge from certain of our Florida customers to recover capital and other program-related costs associated with the replacement of qualifying distribution mains and services in Florida
Gulf Power: Gulf Power Company
Gulfstream: Gulfstream Natural Gas System, LLC
HDD: Heating degree-day, 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
JEA: The community-owned utility located in Jacksonville, Florida, formerly known as Jacksonville Electric Authority
Lenders: Participating lenders, including PNC, which have committed funds to our Revolver
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
NYSE: New York Stock Exchange
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 were entered into with the Note Holders
OPT ≤ 90 Service: Off Peak ≤ 90 Firm Transportation Service, a new tariff associated with Eastern Shore's firm transportation service that will allow Eastern Shore the right not to schedule service for up to 90 days during the peak months of November through April each year
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
PNC: PNC Bank, National Association, the administrative agent and primary lender for our Revolver
Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which we have entered into the Shelf Agreement for the future purchase of our Shelf Notes
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
RAP: Remedial Action Plan, which is a plan that outlines the procedures taken or being considered in removing contaminants from a MGP formerly owned by Chesapeake or FPU
Revolver: The unsecured revolving credit facility issued to us by the Lenders, including PNC as the primary lender
Sandpiper: Sandpiper Energy, Inc.


Table of Contents

Sanford Group: FPU and other responsible parties involved with the Sanford environmental site
SEC: Securities and Exchange Commission
Sharp: Sharp Energy, Inc., our wholly-owned propane distribution subsidiary
Shelf Agreement: An agreement entered into by Chesapeake and Prudential related to the purchase of the Shelf Notes
Shelf Notes: Unsecured senior promissory notes that we may request Prudential to purchase under the Shelf Agreement
SICP: 2013 Stock and Incentive Compensation Plan
SIR: A system improvement rate adder designed to fund system expansion costs within the city limits of Ocean City, Maryland
TETLP: Texas Eastern Transmission, LP
Xeron: Xeron, Inc., our propane wholesale marketing subsidiary, based in Houston, Texas


Table of Contents

PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
(in thousands, except shares and per share data)
 
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
Regulated Energy
 
$
63,796

 
$
59,356

 
$
235,438

 
$
223,168

Unregulated Energy and other
 
28,117

 
32,263

 
119,238

 
155,286

Total Operating Revenues
 
91,913

 
91,619

 
354,676

 
378,454

Operating Expenses
 
 
 
 
 
 
 
 
Regulated Energy cost of sales
 
23,161

 
23,040

 
101,414

 
102,020

Unregulated Energy and other cost of sales
 
17,959

 
22,935

 
73,465

 
112,702

Operations
 
26,388

 
25,365

 
79,522

 
76,604

Maintenance
 
2,603

 
2,562

 
8,033

 
7,168

Gain from a settlement
 

 

 
(1,500
)
 

Depreciation and amortization
 
7,636

 
6,774

 
22,155

 
20,146

Other taxes
 
3,257

 
3,151

 
10,000

 
9,942

Total Operating Expenses
 
81,004

 
83,827

 
293,089

 
328,582

Operating Income
 
10,909

 
7,792

 
61,587

 
49,872

Other income (loss), net of other expenses
 
36

 
(32
)
 
(3
)
 
380

Interest charges
 
2,492

 
2,495

 
7,425

 
6,954

Income Before Income Taxes
 
8,453

 
5,265

 
54,159

 
43,298

Income taxes
 
3,334

 
2,085

 
21,638

 
17,303

Net Income
 
$
5,119

 
$
3,180

 
$
32,521

 
$
25,995

Weighted Average Common Shares Outstanding:
 
 
 
 
 
 
 
 
Basic
 
15,258,819

 
14,574,678

 
15,035,569

 
14,539,841

Diluted
 
15,306,843

 
14,616,665

 
15,083,641

 
14,588,130

Earnings Per Share of Common Stock:
 
 
 
 
 
 
 
 
Basic
 
$
0.34

 
$
0.22

 
$
2.16

 
$
1.79

Diluted
 
$
0.33

 
$
0.22

 
$
2.16

 
$
1.78

Cash Dividends Declared Per Share of Common Stock
 
$
0.2875

 
$
0.2700

 
$
0.8450

 
$
0.7967

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



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Table of Contents

Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
(in thousands)
 
 
 
 
 
 
 
 
Net Income
 
$
5,119

 
$
3,180

 
$
32,521

 
$
25,995

Other Comprehensive Income (Loss), net of tax:
 
 
 
 
 
 
 
 
Employee Benefits, net of tax:
 
 
 
 
 
 
 
 
Amortization of prior service cost, net of tax of $(7), $(5), $(20) and $(18), respectively
 
(10
)
 
(9
)
 
(30
)
 
(26
)
Net gain, net of tax of $62, $26, $187 and $80, respectively
 
93

 
39

 
278

 
118

Cash Flow Hedges, net of tax:
 
 
 
 
 
 
 
 
Unrealized loss on commodity contract cash flow hedges, net of tax of $(51), $(18), $(29) and $(19), respectively
 
(75
)
 
(27
)
 
(43
)
 
(28
)
Total Other Comprehensive Income
 
8

 
3

 
205

 
64

Comprehensive Income
 
$
5,127

 
$
3,183

 
$
32,726

 
$
26,059

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


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Table of Contents

Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Assets
 
September 30,
2015
 
December 31,
2014
(in thousands, except shares)
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Regulated Energy
 
$
813,145

 
$
766,855

Unregulated Energy
 
141,393

 
84,773

Other businesses and eliminations
 
19,190

 
18,497

Total property, plant and equipment
 
973,728

 
870,125

Less: Accumulated depreciation and amortization
 
(210,979
)
 
(193,369
)
Plus: Construction work in progress
 
56,441

 
13,006

Net property, plant and equipment
 
819,190

 
689,762

Current Assets
 
 
 
 
Cash and cash equivalents
 
3,781

 
4,574

Accounts receivable (less allowance for uncollectible accounts of $1,088 and $1,120, respectively)
 
39,861

 
53,300

Accrued revenue
 
8,797

 
13,617

Propane inventory, at average cost
 
4,211

 
7,250

Other inventory, at average cost
 
4,143

 
3,699

Regulatory assets
 
7,653

 
8,967

Storage gas prepayments
 
3,839

 
4,258

Income taxes receivable
 
6,935

 
18,806

Deferred income taxes
 
338

 

Prepaid expenses
 
7,507

 
6,652

Mark-to-market energy assets
 
286

 
1,055

Other current assets
 
339

 
195

Total current assets
 
87,690

 
122,373

Deferred Charges and Other Assets
 
 
 
 
Goodwill
 
16,048

 
4,952

Other intangible assets, net
 
2,317

 
2,404

Investments, at fair value
 
3,412

 
3,678

Regulatory assets
 
77,332

 
78,136

Receivables and other deferred charges
 
2,453

 
3,164

Total deferred charges and other assets
 
101,562

 
92,334

Total Assets
 
$
1,008,442

 
$
904,469

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

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Table of Contents

Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Capitalization and Liabilities
 
September 30,
2015
 
December 31,
2014
(in thousands, except shares and per share data)
 
 
 
 
Capitalization
 
 
 
 
Stockholders’ equity
 
 
 
 
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)
 
$
7,429

 
$
7,100

Additional paid-in capital
 
189,321

 
156,581

Retained earnings
 
162,036

 
142,317

Accumulated other comprehensive loss
 
(5,471
)
 
(5,676
)
Deferred compensation obligation
 
1,863

 
1,258

Treasury stock
 
(1,863
)
 
(1,258
)
Total stockholders’ equity
 
353,315

 
300,322

Long-term debt, net of current maturities
 
155,909

 
158,486

Total capitalization
 
509,224

 
458,808

Current Liabilities
 
 
 
 
Current portion of long-term debt
 
9,139

 
9,109

Short-term borrowing
 
127,093

 
88,231

Accounts payable
 
41,129

 
44,610

Customer deposits and refunds
 
24,020

 
25,197

Accrued interest
 
3,242

 
1,352

Dividends payable
 
4,388

 
3,939

Deferred income taxes
 

 
832

Accrued compensation
 
8,909

 
10,076

Regulatory liabilities
 
9,346

 
3,268

Mark-to-market energy liabilities
 
154

 
1,018

Other accrued liabilities
 
9,443

 
6,603

Total current liabilities
 
236,863

 
194,235

Deferred Credits and Other Liabilities
 
 
 
 
Deferred income taxes
 
174,247

 
160,232

Regulatory liabilities
 
43,356

 
43,419

Environmental liabilities
 
9,003

 
8,923

Other pension and benefit costs
 
32,619

 
35,027

Deferred investment tax credits and other liabilities
 
3,130

 
3,825

Total deferred credits and other liabilities
 
262,355

 
251,426

Other commitments and contingencies (Note 6)
 

 

Total Capitalization and Liabilities
 
$
1,008,442

 
$
904,469

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


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Table of Contents

Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
 
 
Nine Months Ended
 
 
September 30,
 
 
2015
 
2014
(in thousands)
 
 
 
 
Operating Activities
 
 
 
 
Net income
 
$
32,521

 
$
25,995

Adjustments to reconcile net income to net operating cash:
 
 
 
 
Depreciation and amortization
 
22,155

 
20,146

Depreciation and accretion included in other costs
 
5,280

 
5,152

Deferred income taxes, net
 
(1,155
)
 
(156
)
Realized gain on commodity contracts/sale of assets/investments
 
(411
)
 
(436
)
Unrealized loss (gain) on investments/commodity contracts
 
60

 
(44
)
Employee benefits and compensation
 
901

 
476

Share-based compensation
 
1,445

 
1,519

Other, net
 
13

 
2

Changes in assets and liabilities:
 
 
 
 
Accounts receivable and accrued revenue
 
21,898

 
38,304

Propane inventory, storage gas and other inventory
 
3,166

 
4,137

Regulatory assets/liabilities, net
 
6,467

 
(8,865
)
Prepaid expenses and other current assets
 
(159
)
 
(804
)
Accounts payable and other accrued liabilities
 
(5,145
)
 
(18,704
)
Income taxes receivable/payable
 
14,883

 
510

Customer deposits and refunds
 
(1,177
)
 
(1,169
)
Accrued compensation
 
(1,406
)
 
(1,242
)
Other assets and liabilities, net
 
(652
)
 
198

Net cash provided by operating activities
 
98,684

 
65,019

Investing Activities
 
 
 
 
Property, plant and equipment expenditures
 
(102,051
)
 
(69,111
)
Proceeds from sales of assets
 
109

 
505

Acquisitions, net of cash acquired
 
(20,930
)
 

Environmental expenditures
 
(113
)
 
(134
)
Net cash used in investing activities
 
(122,985
)
 
(68,740
)
Financing Activities
 
 
 
 
Common stock dividends
 
(11,725
)
 
(10,879
)
Issuance of stock for Dividend Reinvestment Plan
 
633

 
300

Change in cash overdrafts due to outstanding checks
 
2,964

 
(503
)
Net borrowing (repayment) under line of credit agreements
 
35,898

 
(33,994
)
Proceeds from issuance of long-term debt
 

 
49,975

Repayment of long-term debt and capital lease obligation
 
(4,262
)
 
(2,249
)
Net cash provided by financing activities
 
23,508

 
2,650

Net Decrease in Cash and Cash Equivalents
 
(793
)
 
(1,071
)
Cash and Cash Equivalents—Beginning of Period
 
4,574

 
3,356

Cash and Cash Equivalents—End of Period
 
$
3,781

 
$
2,285

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

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Table of Contents

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, 2013
14,457,345

 
$
4,691

 
$
152,341

 
$
124,274

 
$
(2,533
)
 
$
1,124

 
$
(1,124
)
 
$
278,773

Net income

 

 

 
36,092

 

 

 

 
36,092

Other comprehensive loss

 

 

 

 
(3,143
)
 

 

 
(3,143
)
Dividend declared ($1.0667 per share)

 

 

 
(15,675
)
 

 

 

 
(15,675
)
Retirement savings plan and dividend reinvestment plan
43,367

 
16

 
1,844

 

 

 

 

 
1,860

Conversion of debentures
47,313

 
15

 
520

 

 

 

 

 
535

Share-based compensation and tax benefit (2) (3)
40,686

 
13

 
1,876

 

 

 

 

 
1,889

Stock split in the form of stock dividend

 
2,365

 

 
(2,374
)
 

 

 

 
(9
)
Treasury stock activities

 

 

 

 

 
134

 
(134
)
 

Balance at December 31, 2014
14,588,711

 
7,100

 
156,581

 
142,317

 
(5,676
)
 
1,258

 
(1,258
)
 
300,322

Net income

 

 

 
32,521

 

 

 

 
32,521

Other comprehensive income

 

 

 

 
205

 

 

 
205

Dividend declared ($0.8450 per share)

 

 

 
(12,802
)
 

 

 

 
(12,802
)
Retirement savings plan and dividend reinvestment plan
36,289

 
18

 
1,849

 

 

 

 

 
1,867

Common stock issued in acquisition
592,970

 
289

 
29,876

 

 

 

 

 
30,165

Share-based compensation and tax benefit (3)
45,703

 
22

 
1,015

 

 

 

 

 
1,037

Treasury stock activities

 

 

 

 

 
605

 
(605
)
 

Balance at September 30, 2015
15,263,673

 
$
7,429

 
$
189,321

 
$
162,036

 
$
(5,471
)
 
$
1,863

 
$
(1,863
)
 
$
353,315

 
(1) 
Includes 70,253 and 57,382 shares at September 30, 2015 and December 31, 2014, respectively, held in a Rabbi Trust related to our 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 nine months ended September 30, 2015, and for the year ended December 31, 2014, we withheld 12,620 and 12,687 shares, respectively, for taxes.

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


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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, 2014. 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.
Reclassifications
As a result of the sale of our advanced information services subsidiary in October 2014, we changed our operating segments (see Note 7, Segment Information). We reclassified certain amounts in the condensed consolidated statements of income for the three and nine months ended September 30, 2014 and condensed consolidated statements of cash flows for the nine months ended September 30, 2014 to conform to the current year's presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.
Gain Contingency
Effective May 29, 2015, we entered into a settlement agreement with a vendor related to the implementation of a customer billing system. Pursuant to the agreement, we received $1.5 million in cash, which is reflected as "Gain from a settlement" in the accompanying condensed consolidated statements of income. Previously, at December 31, 2014, we recorded a $6.5 million pretax, non-cash impairment loss related to the same billing system implementation. We may also receive $750,000 in additional cash and discounts on future services; however, the receipt or retention of additional cash and future discounts is contingent upon engaging this vendor to provide agreed-upon services over the next five years.
Subsequent Events
On October 8, 2015, we entered into the Shelf Agreement with Prudential. See Note 14, Long-Term Debt for further details. On the same date, we also entered into the Credit Agreement with the Lenders for a $150.0 million Revolver for a term of five years. On October 19, 2015, we borrowed $25.0 million under the Revolver. See Note 15, Short-Term Borrowing for further details.

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. On July 9, 2015, the FASB affirmed its proposal to defer the implementation of this standard by one year. For public entities, this standard is effective for 2018 interim and annual financial statements. We are assessing the impact this standard may have on our financial position and results of operations.
Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. As of September 30, 2015, we had $312,000 of unamortized

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debt issuance costs included in the accompanying condensed consolidated balance sheets. Upon adoption of ASU 2015-03, this will be presented as a deduction from long-term debt, net of current maturities.
Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements which were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. This standard is not expected to have a material impact on our financial position and results of operation.
Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The new guidance requires that the cumulative impact of a measurement period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 will be effective for our interim and annual financial statements issued beginning January 1, 2016 and is to be adopted on a prospective basis. Early adoption is permitted for financial statements that have not been previously issued. We are assessing the impact this standard may have on our financial position and results of operation.


2.
Calculation of Earnings Per Share

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
(in thousands, except shares and per share data)
 
 
 
 
 
 
 
 
Calculation of Basic Earnings Per Share:
 
 
 
 
 
 
 
 
Net Income
 
$
5,119

 
$
3,180

 
$
32,521

 
$
25,995

Weighted average shares outstanding
 
15,258,819

 
14,574,678

 
15,035,569

 
14,539,841

Basic Earnings Per Share
 
$
0.34

 
$
0.22

 
$
2.16

 
$
1.79

 
 
 
 
 
 
 
 
 
Calculation of Diluted Earnings Per Share:
 
 
 
 
 
 
 
 
Reconciliation of Numerator:
 
 
 
 
 
 
 
 
Net Income
 
$
5,119

 
$
3,180

 
$
32,521

 
$
25,995

Reconciliation of Denominator:
 
 
 
 
 
 
 
 
Weighted shares outstanding—Basic
 
15,258,819

 
14,574,678

 
15,035,569

 
14,539,841

Effect of dilutive securities:
 
 
 
 
 
 
 
 
Share-based compensation
 
48,024

 
41,987

 
48,072

 
48,289

Adjusted denominator—Diluted
 
15,306,843

 
14,616,665

 
15,083,641

 
14,588,130

Diluted Earnings Per Share
 
$
0.33

 
$
0.22

 
$
2.16

 
$
1.78

 

3.
Acquisitions
Gatherco Acquisition
On April 1, 2015, we completed the merger with Gatherco, in which Gatherco merged with and into Aspire Energy of Ohio, a newly formed, wholly-owned subsidiary of Chesapeake. As a result, Aspire Energy of Ohio provides natural gas midstream services, including natural gas gathering services and natural gas liquid processing services to over 300 producers, through 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio. Aspire Energy of Ohio also supplies natural gas to Columbia Gas of Ohio, regional marketers of natural gas, and over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity, which Aspire Energy of Ohio manages under an operating agreement.

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At closing, we issued 592,970 shares of our common stock, valued at $30.2 million based on the closing price of our common stock as reported on the NYSE on April 1, 2015. In addition, we paid $27.5 million in cash and assumed $1.7 million of existing outstanding debt, which we paid off on the same date. We also acquired $6.8 million of cash on hand at closing.
(in thousands)
 
Chesapeake common stock
$
30,164

Cash
27,494

Acquired debt
1,696

Aggregate amount paid in the acquisition
59,354

Less: cash acquired
(6,806
)
Net amount paid in the acquisition
$
52,548

The merger agreement provides for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities over the next five years.
We incurred $1.3 million in transaction costs associated with this merger, $514,000 of which was expensed in the nine months ended September 30, 2015. Transactions costs are included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net income from this acquisition for the three months ended September 30, 2015, included in our condensed consolidated statement of income, were $5.7 million and $55,000, respectively. The revenue and net loss from this acquisition for the nine months ended September 30, 2015, included in our condensed consolidated statement of income, were $11.0 million and $133,000, respectively. The financial results of Aspire Energy of Ohio are projected to have a minimal impact on our earnings per share in 2015, since the merger was completed after the first quarter. The first quarter includes key winter months, which have historically produced a significant portion of Gatherco's annual earnings. This acquisition is expected to be accretive to our earnings in the first full year of operations, which will include the first quarter of 2016.
The preliminary purchase price allocation of the Gatherco acquisition is as follows:
(in thousands)
 
Purchase price
$
57,658

 
 
Property plant and equipment
52,578

Cash
6,806

Accounts receivable
3,629

Income taxes receivable
3,012

Other assets
247

Total assets acquired
66,272

 
 
Long-term debt
1,696

Deferred income taxes
13,863

Accounts payable
3,837

Other current liabilities
314

Total liabilities assumed
19,710

Net identifiable assets acquired
46,562

Goodwill
$
11,096

The excess of the purchase price over the estimated fair values of the assets acquired and the liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid primarily for opportunities for growth in a new, strategic geographic area. All of the goodwill from this acquisition was recorded in the Unregulated Energy segment and is not expected to be deductible for income tax purposes.
The initial accounting for the Gatherco acquisition is not complete because the valuation necessary to assess the fair values of property, plant and equipment and the related impact on deferred income tax amounts is considered preliminary as we continue to evaluate these assets. The valuation of additional contingent cash consideration and potential

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environmental remediation costs may be adjusted as additional information becomes available. Although the purchase price allocation can be modified up to one year from the date of the acquisition, we intend to finalize the allocation as soon as practicable.
Other acquisitions
On May 7, 2015, we purchased certain propane distribution assets used to serve 253 customers in Citrus County, Florida for approximately $242,000. In connection with this acquisition, we recorded $186,000 in intangible assets related to a non-compete agreement and the customer list to be amortized over six and 10 years, respectively. The remaining purchase price was allocated to property, plant and equipment and accounts receivable. The revenue and net income from this acquisition that were included in our condensed consolidated statements of income for the three and nine months ended September 30, 2015 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 significant rates and other regulatory activities in Delaware during the first nine months of 2015.
Maryland
Ocean City SIR Filing: On July 2, 2015, Sandpiper filed an application with the Maryland PSC, to establish an SIR to further fund system expansion within the city limits of Ocean City, Maryland. The proposed SIR, which would only be charged to customers located within city limits, was supported by Ocean City's local government. On August 5, 2015, the Maryland PSC approved the application.

Florida
On January 16, 2015, Chesapeake's Florida natural gas distribution division filed a petition with the Florida PSC for approval of a contract with its affiliate, Peninsula Pipeline, for additional natural gas transportation services in the vicinity of Haines City, located in Polk County, Florida. This petition was approved by the Florida PSC at its Agenda Conference on May 5, 2015.

On July 1, 2015, FPU's electric division filed an electric depreciation study with the Florida PSC. Depending upon the Florida PSC’s decision in this proceeding, depreciation expense may change for FPU’s electric division as a result of a change in depreciation rates effective January 1, 2015. This action is scheduled for review by the Florida PSC at its Agenda Conference to be held in December 2015.

On September 1, 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through the annual Fuel and Purchased Power Cost Recovery Clause filing. The project will enable FPU's electric division to negotiate a new power purchase agreement that will mitigate fuel costs for its Northeast Division. The hearing on this Docket was held on November 4, 2015. Ruling by the Florida PSC on the docket is expected at the Agenda Conference to be held in December 2015.

Eastern Shore
White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an industrial customer in Kent County, Delaware. Eastern Shore proposes to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additional compression at Eastern Shore’s existing Delaware City Compressor Station in New Castle County, Delaware. The estimated cost of the project is $29.8 million. On January 22, 2015, the FERC issued a Notice of Intent to Prepare an Environmental Assessment for this project. In February, April and May 2015, Eastern Shore filed environmental data in response to comments regarding evaluation of alternate routes for a segment of the pipeline route in the vicinity of the Kemblesville Historic District. On June 2, 2015, a field meeting was conducted to review the proposed route and alternate routes. In response to comments received from the National Park Service and other stakeholders, FERC Staff requested

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that Eastern Shore conduct an additional investigation in relation to Eastern Shore's existing right-of-way. On July 9, 2015, FERC issued a 30-day public scoping notice in advance of issuing an Environmental Assessment in order to solicit comments from the public regarding construction of the Kemblesville loop. On August 18, 2015, Eastern Shore submitted supplemental information to the FERC regarding the results of its investigation of the Kemblesville loop.

System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposes to reinforce critical points on its pipeline system. The total project will benefit all of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days in 2014 and 2015. The estimated cost of the project is $32.1 million. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project, and an order granting the requested authorization by December 2015.
On June 8, 2015, the FERC filed a notice of the application, and the comment period ended on June 29, 2015. Eastern Shore anticipates FERC approval of this project in the fourth quarter of 2015 and estimates that construction will start in the first quarter of 2016.

TETLP Capacity Expansion Project: On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities which will enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/day, for a total capacity of 160,000 Dts/d. Eastern Shore expects the project to be approved by the end of the year.

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, assessment or remediation of, and have exposures at seven former MGP sites. Those sites are located in Salisbury, Maryland, Seaford, Delaware and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.
As of September 30, 2015, we had approximately $10.0 million in environmental liabilities, representing our estimate of the future costs associated with all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to all of its MGP sites, approximately $10.0 million of which has been recovered as of September 30, 2015, leaving approximately $4.0 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
In addition to the FPU MGP sites, we had $389,000 in environmental liabilities at September 30, 2015 related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of September 30, 2015, we had approximately $116,000 in regulatory and other assets for future recovery through Chesapeake’s rates.
During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake’s MGP site in Seaford, Delaware, representing our estimate of future costs associated with this site, and recorded a regulatory asset for the same amount for probable future recovery through Chesapeake’s rates, although we have not yet sought Delaware PSC approval for recovery. As of September 30, 2015, we had approximately $239,000 in environmental liabilities and $273,000 in regulatory and other assets related to this site.
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, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.
West Palm Beach, Florida
We are evaluating remedial options to respond to environmental impacts to soil and groundwater at, and in the immediate vicinity of, a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP.

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FPU is 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. We anticipate that similar remedial actions will ultimately 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 at this site. 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 September 30, 2015, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.
In December 2014, the EPA issued a preliminary close-out report, documenting the completion of all physical remediation construction activities at the Sanford site. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. The total cost of the final remedy is 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, 2015, 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 September 30, 2015.
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 additional 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 on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site.
In October 2012, FDEP issued a RAP approval order, which requires a limited semi-annual monitoring program. The most recent groundwater-monitoring event was conducted on September 14, 2015. Natural Attenuation Default criteria were met at all locations sampled. The next semi-annual sampling event is scheduled for March 2016.
Although the duration of the FDEP-required limited NAM cannot be determined with certainty, we anticipate 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 it would approve a conditional No Further Action determination for the site with the requirement for institutional and engineering controls. On June 16, 2014, FDEP issued a draft memorandum of understanding between FDOT and FDEP

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to implement site closure with approved institutional and engineering controls for the site. We anticipate 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. Groundwater monitoring results have shown a continuing reduction in contaminant concentrations from the sparging system, which has been in operation since 2002. On September 12, 2014, FDEP issued a letter approving shutdown of the sparging operations on the northern portion of the site, contingent upon continued semi-annual monitoring.
Groundwater monitoring results on the southern portion of this site indicate that natural attenuation default criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation was reported in the semi-annual RAP implementation status report submitted on January 8, 2015. Although specific remedial actions have not yet been identified, 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. 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; therefore, we 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.

Seaford, Delaware
In a letter dated December 5, 2013, the DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. We submitted an application to the DNREC on April 2, 2015, which was approved on September 17, 2015, to enter this site into the voluntary cleanup program. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000.
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.

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 natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. Our Delaware and Maryland natural gas distribution divisions have a contract through March 31, 2017, with an unaffiliated energy marketing and risk management company to manage a portion of their 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. Approximately three years, four months remain under this contract. 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.

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Also in May 2013, 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 agreement against those specified in the other agreement.
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 the capacity charge.
In May 2015, PESCO renewed contracts to purchase natural gas from various suppliers. The total monthly purchase commitment ranges from 9,982 to 13,423 Dts/d from June 2015 to May 2016. These contracts expire in May 2016.
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 FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. 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 either of these ratios, 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 also result in FPU having to provide an irrevocable letter of credit. As of September 30, 2015, FPU was in compliance with all of the requirements of its fuel supply contracts.
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 $50.0 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, respectively, in the event that Xeron or PESCO defaults. 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, 2015 was $36.1 million, with the guarantees expiring on various dates through September 22, 2016.
Chesapeake also 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, 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, 2016, 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 $1.2 million which expires on October 31, 2016, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company, we renewed and decreased the letter of credit for $24,000 to our former primary insurance company, which will expire on June 1, 2016. We have also issued a letter of credit of $1.0 million which expires on March 31, 2016, related to PESCO's transactions at the Natural Gas Exchange, Inc.
We provided a letter of credit for $2.3 million to TETLP related to the firm transportation service agreement with our Delaware and Maryland divisions.
There have been no draws on these letters of credit as of September 30, 2015. 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.

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Tax-related Contingencies
We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of September 30, 2015, we maintained a liability of $100,000 related to unrecognized income tax benefits and $404,000 related to contingencies for taxes other than income. As of December 31, 2014, we maintained a liability of $100,000 related to unrecognized income tax benefits and $724,000 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 two reportable segments:
Regulated Energy. The Regulated Energy segment includes natural gas distribution, natural gas transmission 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. Effective April 1, 2015, this segment includes Aspire Energy of Ohio, whose services include natural gas gathering and processing (See Note 3, Acquisitions, regarding the acquisition of Gatherco). 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.
We had previously identified "Other" as a separate reportable segment, which consisted primarily of our advanced information services subsidiary. As a result of the sale of that subsidiary on October 1, 2014, "Other" is no longer a separate reportable segment.

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The following table presents financial information about our reportable segments:
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
(in thousands)
 
 
 
 
 
 
 
 
Operating Revenues, Unaffiliated Customers
 
 
 
 
 
 
 
 
Regulated Energy segment
 
$
63,526

 
$
59,086

 
$
234,608

 
$
222,308

Unregulated Energy segment
 
28,387

 
27,041

 
120,068

 
141,215

Other businesses
 

 
5,492

 

 
14,931

Total operating revenues, unaffiliated customers
 
$
91,913

 
$
91,619

 
$
354,676

 
$
378,454

Intersegment Revenues (1)
 
 
 
 
 
 
 
 
Regulated Energy segment
 
$
270

 
$
270

 
$
830

 
$
860

Unregulated Energy segment
 
1,222

 
30

 
3,095

 
150

Other businesses
 
220

 
258

 
660

 
760

Total intersegment revenues
 
$
1,712

 
$
558

 
$
4,585

 
$
1,770

Operating Income (Loss)
 
 
 
 
 
 
 
 
Regulated Energy segment
 
$
11,828

 
$
9,202

 
$
47,616

 
$
41,004

Unregulated Energy segment
 
(1,022
)
 
(1,972
)
 
13,666

 
8,843

Other businesses and eliminations
 
103

 
562

 
305

 
25

Total operating income
 
10,909

 
7,792

 
61,587

 
49,872

Other income (loss), net of other expenses
 
36

 
(32
)
 
(3
)
 
380

Interest
 
2,492

 
2,495

 
7,425

 
6,954

Income before Income Taxes
 
8,453

 
5,265

 
54,159

 
43,298

Income taxes
 
3,334

 
2,085

 
21,638

 
17,303

Net Income
 
$
5,119

 
$
3,180

 
$
32,521

 
$
25,995

 
(1) 
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
(in thousands)
 
September 30, 2015
 
December 31, 2014
Identifiable Assets
 
 
 
 
Regulated Energy segment
 
$
824,330

 
$
796,021

Unregulated Energy segment
 
156,838

 
84,732

Other businesses and eliminations
 
27,274

 
23,716

Total identifiable assets
 
$
1,008,442

 
$
904,469


Our operations are entirely domestic.
 

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Table of Contents

8.
Accumulated Other Comprehensive Loss
Defined benefit pension and postretirement plan items and unrealized gains (losses) of our propane swap agreements and call options, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive loss. The following tables present the changes in the balance of accumulated other comprehensive loss for the nine months ended September 30, 2015 and 2014. All amounts are presented net of tax.

 
 
Defined Benefit
 
Commodity
 
 
 
 
Pension and
 
Contracts
 
 
 
 
Postretirement
 
Cash Flow
 
 
 
 
Plan Items
 
Hedges
 
Total
(in thousands)
 
 
 
 
 
 
As of December 31, 2014
 
$
(5,643
)
 
$
(33
)
 
$
(5,676
)
Other comprehensive loss before reclassifications
 

 
(76
)
 
(76
)
Amounts reclassified from accumulated other comprehensive loss
 
248

 
33

 
281

Net current-period other comprehensive income
 
248

 
(43
)
 
205

As of September 30, 2015
 
$
(5,395
)
 
$
(76
)
 
$
(5,471
)

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

 
$
(2,533
)
Other comprehensive loss before reclassifications
 

 
(28
)
 
(28
)
Amounts reclassified from accumulated other comprehensive loss
 
92

 

 
92

Net current-period other comprehensive income (loss)
 
92

 
(28
)
 
64

As of September 30, 2014
 
$
(2,441
)
 
$
(28
)
 
$
(2,469
)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2015 and 2014. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.

- 17

Table of Contents

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
(in thousands)
 
 
 
 
 
 
 
 
Amortization of defined benefit pension and postretirement plan items:
 
 
 
 
 
 
 
 
Prior service cost (1)
 
$
17

 
$
14

 
$
50

 
$
44

Net gain (1)
 
(155
)
 
(65
)
 
(465
)
 
(198
)
Total before income taxes
 
(138
)

(51
)
 
(415
)
 
(154
)
Income tax benefit
 
55

 
21

 
167

 
62

Net of tax
 
$
(83
)
 
$
(30
)
 
$
(248
)
 
$
(92
)
 
 
 
 
 
 
 
 
 
Gains and losses on commodity contracts cash flow hedges
 
 
 
 
 
 
 
 
Propane swap agreements (2)
 
$

 
$

 
$

 
$

Call options (2)
 

 

 
(55
)
 

Total before income taxes
 

 

 
(55
)
 

Income tax benefit
 

 

 
22

 

Net of tax
 

 

 
(33
)
 

Total reclassifications for the period
 
$
(83
)
 
$
(30
)
 
$
(281
)
 
$
(92
)
 
(1) These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.
(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.
Amortization of defined benefit pension and postretirement plan items is included in operations expense and gains and losses on propane swap agreements and call options are included in cost of sales 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 nine months ended September 30, 2015 and 2014 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 September 30,
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost
 
$
102

 
$
107

 
$
626

 
$
647

 
$
23

 
$
23

 
$
11

 
$
13

 
$
15

 
$
17

Expected return on plan assets
 
(135
)
 
(133
)
 
(777
)
 
(773
)
 

 

 

 

 

 

Amortization of prior service cost
 

 

 

 

 
2

 
5

 
(19
)
 
(19
)
 

 

Amortization of net loss
 
91

 
37

 
114

 

 
25

 
12

 
17

 
16

 
2

 

Net periodic cost (benefit)
 
58

 
11

 
(37
)
 
(126
)
 
50

 
40

 
9

 
10

 
17

 
17

Amortization of pre-merger regulatory asset
 

 

 
191

 
191

 

 

 

 

 
2

 
2

Total periodic cost
 
$
58

 
$
11

 
$
154

 
$
65

 
$
50

 
$
40

 
$
9

 
$
10


$
19

 
$
19


- 18

Table of Contents

 
 
Chesapeake
Pension Plan
 
FPU
Pension Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
For the Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost
 
$
306

 
$
320

 
$
1,877

 
$
1,941

 
$
68

 
$
69

 
$
33

 
$
39

 
$
45

 
$
50

Expected return on plan assets
 
(405
)
 
(398
)
 
(2,330
)
 
(2,318
)
 

 

 

 

 

 

Amortization of prior service cost
 

 

 

 

 
8

 
14

 
(58
)
 
(58
)
 

 

Amortization of net loss
 
272

 
112

 
341

 

 
74

 
36

 
53

 
50

 
5

 

Net periodic cost (benefit)
 
173

 
34

 
(112
)
 
(377
)
 
150

 
119

 
28

 
31

 
50

 
50

Amortization of pre-merger regulatory asset
 

 

 
571

 
571

 

 

 

 

 
6

 
6

Total periodic cost
 
$
173

 
$
34

 
$
459

 
$
194

 
$
150

 
$
119

 
$
28

 
$
31

 
$
56

 
$
56



We expect to record pension and postretirement benefit costs of approximately $1.2 million for 2015. 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 FPU merger in 2009. 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 $3.1 million and $3.6 million at September 30, 2015 and December 31, 2014, respectively. The amortization included in pension expense is also being added to a net periodic loss of $381,000, which will increase our total expected benefit costs to $1.2 million.
Pursuant to a Florida PSC order, 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 FPU merger. 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 loss. The following table presents the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three and nine months ended September 30, 2015 and 2014:
 
For the Three Months Ended September 30, 2015
 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (credit)
 
$

 
$

 
$
2

 
$
(19
)
 
$

 
$
(17
)
Net loss
 
91

 
114

 
25

 
17

 
2

 
249

Total recognized in net periodic benefit cost
 
$
91

 
$
114

 
$
27

 
$
(2
)
 
$
2

 
$
232

Recognized from accumulated other comprehensive loss (1)
 
$
91

 
$
22

 
$
27

 
$
(2
)
 
$

 
$
138

Recognized from regulatory asset
 

 
92

 

 

 
2

 
94

Total
 
$
91

 
$
114

 
$
27

 
$
(2
)
 
$
2

 
$
232



- 19

Table of Contents

For the Nine Months Ended September 30, 2015
 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (credit)
 
$

 
$

 
$
8

 
$
(58
)
 
$

 
$
(50
)
Net loss
 
272

 
341

 
74

 
53

 
5

 
745

Total recognized in net periodic benefit cost
 
$
272

 
$
341

 
$
82

 
$
(5
)
 
$
5

 
$
695

Recognized from accumulated other comprehensive loss (1)
 
$
272

 
$
65

 
$
82

 
$
(5
)
 
$
1

 
$
415

Recognized from regulatory asset
 

 
276

 

 

 
4

 
280

Total
 
$
272

 
$
341

 
$
82

 
$
(5
)
 
$
5

 
$
695


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