CHESAPEAKE UTILITIES CORP - FORM 10-Q - May 6, 2015

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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: March 31, 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 $0.4867 — 15,225,683 shares outstanding as of April 30, 2015.


Table of Contents
 



GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification
ASU: Accounting Standards Update
Aspire Energy of Ohio: Aspire Energy of Ohio, LLC, a newly formed, wholly-owned subsidiary of Chesapeake into which Gatherco, Inc. merged.
BravePoint: BravePoint, Inc., our advanced information services subsidiary, headquartered in Norcross, Georgia, which was sold on October 1, 2014
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
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
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
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 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
GAAP: Accounting principles generally accepted in the United States of America
Gatherco: Gatherco, 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
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 have been 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
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
Sharp: Sharp Energy, Inc., our wholly-owned propane distribution subsidiary
SICP: 2013 Stock and Incentive Compensation Plan
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
 
 
March 31,
 
 
2015
 
2014
(in thousands, except shares and per share data)
 
 
 
 
Operating Revenues
 
 
 
 
Regulated Energy
 
$
109,582

 
$
102,166

Unregulated Energy and other
 
60,499

 
84,171

Total Operating Revenues
 
170,081

 
186,337

Operating Expenses
 
 
 
 
Regulated Energy cost of sales
 
57,129

 
54,307

Unregulated Energy and other cost of sales
 
35,234

 
61,325

Operations
 
26,945

 
26,626

Maintenance
 
2,703

 
2,148

Depreciation and amortization
 
6,975

 
6,635

Other taxes
 
3,587

 
3,673

Total Operating Expenses
 
132,573

 
154,714

Operating Income
 
37,508

 
31,623

Other income, net of other expenses
 
133

 
6

Interest charges
 
2,448

 
2,155

Income Before Income Taxes
 
35,193

 
29,474

Income taxes
 
14,084

 
11,793

Net Income
 
$
21,109

 
$
17,681

Weighted Average Common Shares Outstanding:
 
 
 
 
Basic
 
14,604,841

 
14,487,646

Diluted
 
14,656,310

 
14,540,151

Earnings Per Share of Common Stock:
 
 
 
 
Basic
 
$
1.45

 
$
1.22

Diluted
 
$
1.44

 
$
1.22

Cash Dividends Declared Per Share of Common Stock
 
$
0.270

 
$
0.257

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
 
 
March 31,
 
 
2015
 
2014
(in thousands)
 
 
 
 
Net Income
 
$
21,109

 
$
17,681

Other Comprehensive Income (Loss), net of tax:
 
 
 
 
Employee Benefits, net of tax:
 
 
 
 
Amortization of prior service cost, net of tax of $(7), $(6), respectively
 
(10
)
 
(9
)
Net gain, net of tax of $62 and $27, respectively
 
92

 
40

Cash Flow Hedges, net of tax:
 
 
 
 
Unrealized gain on commodity contract cash flow hedges, net of tax of $17 and $0, respectively.
 
26

 
—

Total Other Comprehensive Income
 
108

 
31

Comprehensive Income
 
$
21,217

 
$
17,712

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


- 2

Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Assets
 
March 31,
2015
 
December 31,
2014
(in thousands, except shares)
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Regulated Energy
 
$
779,394

 
$
766,855

Unregulated Energy
 
84,386

 
84,773

Other businesses and eliminations
 
19,459

 
18,497

Total property, plant and equipment
 
883,239

 
870,125

Less: Accumulated depreciation and amortization
 
(198,181
)
 
(193,369
)
Plus: Construction work in progress
 
24,137

 
13,006

Net property, plant and equipment
 
709,195

 
689,762

Current Assets
 
 
 
 
Cash and cash equivalents
 
16,170

 
4,574

Accounts receivable (less allowance for uncollectible accounts of $1,274 and $1,120, respectively)
 
62,062

 
53,300

Accrued revenue
 
12,869

 
13,617

Propane inventory, at average cost
 
4,550

 
7,250

Other inventory, at average cost
 
4,411

 
3,699

Regulatory assets
 
7,472

 
8,967

Storage gas prepayments
 
910

 
4,258

Income taxes receivable
 
—

 
18,806

Prepaid expenses
 
4,510

 
6,652

Mark-to-market energy assets
 
46

 
1,055

Other current assets
 
294

 
195

Total current assets
 
113,294

 
122,373

Deferred Charges and Other Assets
 
 
 
 
Goodwill
 
4,952

 
4,952

Other intangible assets, net
 
2,316

 
2,404

Investments, at fair value
 
3,770

 
3,678

Regulatory assets
 
78,113

 
78,136

Receivables and other deferred charges
 
2,067

 
3,164

Total deferred charges and other assets
 
91,218

 
92,334

Total Assets
 
$
913,707

 
$
904,469

 
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
 
March 31,
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)
 
$
7,119

 
$
7,100

Additional paid-in capital
 
156,749

 
156,581

Retained earnings
 
159,446

 
142,317

Accumulated other comprehensive loss
 
(5,568
)
 
(5,676
)
Deferred compensation obligation
 
1,715

 
1,258

Treasury stock
 
(1,715
)
 
(1,258
)
Total stockholders’ equity
 
317,746

 
300,322

Long-term debt, net of current maturities
 
158,083

 
158,486

Total capitalization
 
475,829

 
458,808

Current Liabilities
 
 
 
 
Current portion of long-term debt
 
9,116

 
9,109

Short-term borrowing
 
66,772

 
88,231

Accounts payable
 
46,284

 
44,610

Customer deposits and refunds
 
22,307

 
25,197

Accrued interest
 
3,109

 
1,352

Dividends payable
 
3,950

 
3,939

Income taxes payable
 
2,946

 
—

Deferred income taxes
 
586

 
832

Accrued compensation
 
4,845

 
10,076

Regulatory liabilities
 
18,621

 
3,268

Mark-to-market energy liabilities
 
20

 
1,018

Other accrued liabilities
 
7,797

 
6,603

Total current liabilities
 
186,353

 
194,235

Deferred Credits and Other Liabilities
 
 
 
 
Deferred income taxes
 
160,055

 
160,232

Regulatory liabilities
 
43,518

 
43,419

Environmental liabilities
 
9,147

 
8,923

Other pension and benefit costs
 
34,798

 
35,027

Deferred investment tax credits and other liabilities
 
4,007

 
3,825

Total deferred credits and other liabilities
 
251,525

 
251,426

Other commitments and contingencies (Note 6)
 

 

Total Capitalization and Liabilities
 
$
913,707

 
$
904,469

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


- 4

Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
 
 
Three Months Ended
 
 
March 31,
 
 
2015
 
2014
(in thousands)
 
 
 
 
Operating Activities
 
 
 
 
Net income
 
$
21,109

 
$
17,681

Adjustments to reconcile net income to net operating cash:
 
 
 
 
Depreciation and amortization
 
6,975

 
6,635

Depreciation and accretion included in other costs
 
1,689

 
1,783

Deferred income taxes, net
 
(496
)
 
(231
)
Realized gain on commodity contracts/sale of assets/investments
 
(840
)
 
(8
)
Unrealized loss on investments/commodity contracts
 
21

 
31

Employee benefits and compensation
 
300

 
162

Share-based compensation
 
537

 
638

Other, net
 
4

 
(1
)
Changes in assets and liabilities:
 
 
 
 
Accounts receivable and accrued revenue
 
(8,014
)
 
(3,647
)
Propane inventory, storage gas and other inventory
 
5,337

 
8,243

Regulatory assets/liabilities, net
 
16,185

 
200

Prepaid expenses and other current assets
 
2,500

 
2,185

Accounts payable and other accrued liabilities
 
2,376

 
4,821

Income taxes receivable/payable
 
21,753

 
11,565

Customer deposits and refunds
 
(2,890
)
 
(1,735
)
Accrued compensation
 
(5,262
)
 
(3,505
)
Other assets and liabilities, net
 
2,753

 
1,246

Net cash provided by operating activities
 
64,037

 
46,063

Investing Activities
 
 
 
 
Property, plant and equipment expenditures
 
(27,508
)
 
(18,528
)
Proceeds from sales of assets
 
198

 
29

Environmental expenditures
 
(49
)
 
(26
)
Net cash used in investing activities
 
(27,359
)
 
(18,525
)
Financing Activities
 
 
 
 
Common stock dividends
 
(3,573
)
 
(3,369
)
Purchase of stock for Dividend Reinvestment Plan
 
27

 
(341
)
Change in cash overdrafts due to outstanding checks
 
(2,191
)
 
(501
)
Net repayment under line of credit agreements
 
(19,269
)
 
(21,696
)
Repayment of long-term debt and capital lease obligation
 
(76
)
 
(196
)
Net cash used in financing activities
 
(25,082
)
 
(26,103
)
Net Increase in Cash and Cash Equivalents
 
11,596

 
1,435

Cash and Cash Equivalents—Beginning of Period
 
4,574

 
3,356

Cash and Cash Equivalents—End of Period
 
$
16,170

 
$
4,791

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, 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 ($1.067 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
—

 
—

 
—

 
21,109

 
—

 
—

 
—

 
21,109

Other comprehensive income
—

 
—

 
—

 
—

 
108

 
—

 
—

 
108

Dividend declared ($0.27 per share) and dividend reinvestment plan
8,059

 
4

 
388

 
(3,980
)
 
—

 
—

 
—

 
(3,588
)
Share-based compensation and tax benefit (3)
31,219

 
15

 
(220
)
 
—

 
—

 
—

 
—

 
(205
)
Treasury stock activities
—

 
—

 
—

 
—

 
—

 
457

 
(457
)
 
—

Balance at March 31, 2015
14,627,989

 
$
7,119

 
$
156,749

 
$
159,446

 
$
(5,568
)
 
$
1,715

 
$
(1,715
)
 
$
317,746

 
(1) 
Includes 53,442 and 53,125 shares at March 31, 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 three months ended March 31, 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.


- 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, 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 income statement and condensed consolidated cash flows statement for the three months ended March 31, 2014 to conform to the current year's presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.
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, August 13, 2014, received one additional share of common stock for every two shares of common stock owned. The additional shares were distributed on September 8, 2014. All share and per share data in this Form 10-Q are presented on a post-split basis. As a result of the stock split, we reclassified approximately $2.4 million from retained earnings to common stock in September of 2014, which represents $0.4867 par value per share of the shares issued in the stock split.

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 April 1, 2015, the FASB proposed to defer the implementation of this standard by one year, which if approved, would result in the new standard being effective for public entities for their 2018 interim and annual financial statements. We are assessing the impact this standard will 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 March 31, 2015, we had $333,000 of unamortized 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.



- 7

2.
Calculation of Earnings Per Share

 
 
Three Months Ended
 
 
March 31,
 
 
2015
 
2014
(in thousands, except shares and per share data)
 
 
 
 
Calculation of Basic Earnings Per Share:
 
 
 
 
Net Income
 
$
21,109

 
$
17,681

Weighted average shares outstanding
 
14,604,841

 
14,487,646

Basic Earnings Per Share
 
$
1.45

 
$
1.22

Calculation of Diluted Earnings Per Share:
 
 
 
 
Reconciliation of Numerator:
 
 
 
 
Net Income
 
$
21,109

 
$
17,681

Reconciliation of Denominator:
 
 
 
 
Weighted shares outstanding—Basic
 
14,604,841

 
14,487,646

Effect of dilutive securities:
 
 
 
 
Share-based compensation
 
51,469

 
52,505

Adjusted denominator—Diluted
 
14,656,310

 
14,540,151

Diluted Earnings Per Share
 
$
1.44

 
$
1.22

 
As discussed in Note 1, Summary of Accounting Policies, previously reported share and per share amounts have been restated in the accompanying condensed consolidated financial statements and related notes to reflect the stock split effected in the form of a stock dividend.

3.
Acquisitions
Gatherco Acquisition
On April 1, 2015, we completed the merger with Gatherco, in which Gatherco merged with Aspire Energy of Ohio, a newly formed, wholly-owned subsidiary of Chesapeake. 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, and paid $27.6 million in cash. We also acquired $6.7 million of Gatherco's cash at the time of the closing and assumed $1.7 million of Gatherco’s debt, which was paid off shortly after closing. We incurred $1.3 million in transaction costs associated with this merger, $514,000 of which was expensed in the three months ended March 31, 2015. Transactions costs are included in operations expense in the accompanying condensed consolidated statement of income. As a result of this merger, Aspire Energy of Ohio provides natural gas midstream services through 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio. Aspire Energy of Ohio provides natural gas gathering services and natural gas liquid processing services to over 300 producers, and supplies natural gas to over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity, which Aspire Energy of Ohio manages under an operating agreement. The 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 represented 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.
We are in the process of finalizing our evaluation of the tangible and intangible assets acquired and liabilities assumed, as well as the initial purchase price allocation as of the acquisition date, including the determination of any resulting goodwill. Therefore, this information cannot be provided at this time.
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.

- 8

Delaware
There were no significant rates and other regulatory activities in Delaware during the first quarter of 2015.
Maryland
There were no significant rates and other regulatory activities in Maryland during the first quarter of 2015.

Florida
On January 16, 2015, Chesapeake's Florida natural gas distribution division filed for approval with the Florida PSC a contract with Peninsula Pipeline, which is one of Chesapeake's subsidiaries, 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 the Agenda Conference on May 5, 2015.
Eastern Shore
White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERC for a CP seeking authorization to construct, own, operate and maintain the White Oak mainline expansion project. The project is 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. The FERC solicited public participation with the comment period ending on February 23, 2015.

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 March 31, 2015, we had approximately $10.1 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 $9.8 million of which has been recovered as of March 31, 2015, leaving approximately $4.2 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
In addition to the FPU MGP sites, we had $369,000 in environmental liabilities at March 31, 2015 related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of March 31, 2015, we had approximately $216,000 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 approval for recovery by the Delaware PSC. As of March 31, 2015, we had approximately $252,000 in environmental liability 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
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,

- 9

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 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 March 31, 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 March 31, 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 March 31, 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 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 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 Remedial Action Plan approval order which specified that a limited semi-annual monitoring program be conducted. The most recent groundwater-monitoring event was conducted on March 23, 2015. Natural attenuation default criteria were met at all locations sampled. The next semi-annual sampling event is scheduled for September 2015.
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.

- 10

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 to implement site closure with approved institutional and engineering controls for the site. 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. 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 shut-down 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 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. 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.

Seaford, Delaware
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. In a report issued during January 2015, DNREC provided the evaluation of this site, which found contaminants impacting the groundwater. We are planning 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 $273,000 to $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.

- 11

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Approximately four years 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.
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 2014, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2015. PESCO is currently obtaining and reviewing proposals from suppliers and anticipates executing new agreements before the existing agreements expire.
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 March 31, 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 March 31, 2015 was $31.1 million, with the guarantees expiring on various dates through February 28, 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, 2015, 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 October 31, 2015, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for $40,000 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 March 31, 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.
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.


- 12


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 March 31, 2015, we maintained a liability of $100,000 related to unrecognized income tax benefits and $578,000 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. 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.

- 13

The following table presents financial information about our reportable segments:
 
 
 
Three Months Ended
 
 
March 31,
 
 
2015
 
2014
(in thousands)
 
 
 
 
Operating Revenues, Unaffiliated Customers
 
 
 
 
Regulated Energy segment
 
$
109,292

 
$
101,874

Unregulated Energy segment
 
60,789

 
79,874

Other businesses
 
—

 
4,589

Total operating revenues, unaffiliated customers
 
$
170,081

 
$
186,337

Intersegment Revenues (1)
 
 
 
 
Regulated Energy segment
 
$
290

 
$
292

Unregulated Energy segment
 
207

 
99

Other businesses
 
221

 
253

Total intersegment revenues
 
$
718

 
$
644

Operating Income
 
 
 
 
Regulated Energy segment
 
$
22,182

 
$
21,091

Unregulated Energy segment
 
15,229

 
10,858

Other businesses and eliminations
 
97

 
(326
)
Total operating income
 
37,508

 
31,623

Other income, net of other expenses
 
133

 
6

Interest
 
2,448

 
2,155

Income before Income Taxes
 
35,193

 
29,474

Income taxes
 
14,084

 
11,793

Net Income
 
$
21,109

 
$
17,681

 
(1) 
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
(in thousands)
 
March 31, 2015
 
December 31, 2014
Identifiable Assets
 
 
 
 
Regulated Energy segment
 
$
788,600

 
$
796,021

Unregulated Energy segment
 
89,950

 
84,732

Other businesses and eliminations
 
35,157

 
23,716

Total identifiable assets
 
$
913,707

 
$
904,469


Our operations are entirely domestic.
 

- 14

8.
Accumulated Other Comprehensive Income (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 income (loss). The following tables present the changes in the balance of accumulated other comprehensive loss for the three months ended March 31, 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
 
—

 
(7
)
 
(7
)
Amounts reclassified from accumulated other comprehensive loss
 
82

 
33

 
115

Net current-period other comprehensive income (loss)
 
82

 
26

 
108

As of March 31, 2015
 
$
(5,561
)
 
$
(7
)
 
$
(5,568
)

 
 
 
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
 
—

 
—

 
—

Amounts reclassified from accumulated other comprehensive loss
 
31

 
—

 
31

Net current-period other comprehensive income
 
31

 
—

 
31

As of March 31, 2014
 
$
(2,502
)
 
$
—

 
$
(2,502
)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months ended March 31, 2015 and 2014. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement

- 15

 
 
Three Months Ended
 
 
March 31,
 
 
2015
 
2014
(in thousands)
 
 
 
 
Amortization of defined benefit pension and postretirement plan items:
 
 
 
 
Prior service cost (1)
 
$
17

 
$
14

Net loss (1)
 
(154
)
 
(66
)
Total before income taxes
 
(137
)

(52
)
Income tax benefit
 
55

 
21

Net of tax
 
$
(82
)
 
$
(31
)
 
 
 
 
 
Gains and losses on commodity contracts cash flow hedges
 
 
 
 
Propane swap agreements (2)
 
$
12

 
$
—

Call options (2)
 
(55
)
 
—

Total before income taxes
 
(43
)
 
—

Income tax benefit
 
17

 
—

Net of tax
 
(26
)
 
—

Total reclassifications for the period
 
$
(108
)
 
$
(31
)
 
(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 months ended March 31, 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 March 31,
 
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
 
90

 
37

 
114

 
—

 
25

 
12

 
17

 
17

 
2

 
—

Net periodic cost (benefit)
 
57

 
11

 
(37
)
 
(126
)
 
50

 
40

 
9

 
11

 
17

 
17

Amortization of pre-merger regulatory asset
 
—

 
—

 
190

 
190

 
—

 
—

 
—

 
—

 
2

 
2

Total periodic cost
 
$
57

 
$
11

 
$
153

 
$
64

 
$
50

 
$
40

 
$
9

 
$
11


$
19

 
$
19



- 16


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 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 $3.4 million and $3.6 million at March 31, 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 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 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 months ended March 31, 2015 and 2014:
 
For the Three Months Ended March 31, 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
 
90

 
114

 
25

 
17

 
2

 
248

Total recognized in net periodic benefit cost
 
$
90

 
$
114

 
$
27

 
$
(2
)
 
$
2

 
$
231

Recognized from accumulated other comprehensive loss (1)
 
$
90

 
$
22

 
$
27

 
$
(2
)
 
$
—

 
$
137

Recognized from regulatory asset
 
—

 
92

 
—

 
—

 
2

 
94

Total
 
$
90

 
$
114

 
$
27

 
$
(2
)
 
$
2

 
$
231



For the Three Months Ended March 31, 2014
 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (credit)
 
$
—

 
$
—

 
$
5

 
$
(19
)
 
$
—

 
$
(14
)
Net loss
 
37

 
—

 
12

 
17

 
—

 
66

Total recognized in net periodic benefit cost
 
$
37

 
$
—

 
$
17

 
$
(2
)
 
$
—

 
$
52

Recognized from accumulated other comprehensive loss (1)
 
$
37

 
$
—

 
$
17

 
$
(2
)
 
$
—

 
$
52

Recognized from regulatory asset
 
—

 
—

 
—

 
—

 
—

 
—

Total
 
$
37

 
$
—

 
$
17


$
(2
)

$
—


$
52


(1) 
See Note 8, Accumulated Other Comprehensive Income (Loss).
During the three months ended March 31, 2015, we contributed $104,000 to the Chesapeake Pension Plan and $343,000 to the FPU Pension Plan. We expect to contribute a total of $475,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2015, which represent the minimum contribution payments required during the year.
The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three months ended March 31, 2015, were $33,000. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2015. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2015, were $15,000. We have estimated that approximately $79,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2015. Cash benefits paid for the FPU Medical Plan, primarily for medical claims

- 17

for the three months ended March 31, 2015, were $92,000. We estimate that approximately $207,000 will be paid for such benefits under the FPU Medical Plan in 2015.
10.
Investments
The investment balances at March 31, 2015 and December 31, 2014, consist of the Rabbi Trust associated with our Deferred Compensation Plan. We classify these investments as trading securities and report them at their fair value. For the three months ended March 31, 2015 and 2014, we recorded a net unrealized gain of $104,000 and $37,000, respectively, in other income in the condensed consolidated statements of income related to these investments. We also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets and is adjusted each month for the gains and losses incurred by the Rabbi Trust.
 
11.
Share-Based Compensation
Since May 2, 2013, our non-employee directors and key employees have been granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period.
The table below presents the amounts included in net income related to share-based compensation expense for the three months ended March 31, 2015 and 2014:
 
 
 
Three Months Ended
 
 
March 31,
 
 
2015
 
2014
(in thousands)
 
 
 
 
Awards to non-employee directors
 
$
150

 
$
124

Awards to key employees
 
387

 
514

Total compensation expense
 
537

 
638

Less: tax benefit
 
(217
)
 
(257
)
Share-based compensation amounts included in net income
 
$
320

 
$
381

Non-employee Directors
Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2014, each of our non-employee directors received an annual retainer of 1,209 shares of common stock under the SICP. At March 31, 2015, there was $50,000 of unrecognized compensation expense related to these awards. This expense was fully recognized over the directors' remaining service periods ending April 30, 2015.

Key Employees
The table below presents the summary of the stock activity for awards to key employees for the three months ended March 31, 2015:
 
 
 
Number of Shares
 
Weighted Average
Fair Value
Outstanding—December 31, 2014
 
123,038

 
$
32.60

Granted
 
29,763

 
$
48.90

Vested
 
(43,839
)
 
$
28.01

Expired
 
(2,520
)
 
$
28.83

Outstanding—March 31, 2015
 
106,442

 
$
38.17

In January 2015, our Board of Directors granted awards of 29,763 shares to key employees under the SICP. The shares granted in January 2015 are multi-year awards that will vest at the end of the three-year service period ending December 31,

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2017. All of these stock awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date each award is granted. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.
At March 31, 2015, the aggregate intrinsic value of the SICP awards granted to key employees was $5.4 million. At March 31, 2015, there was $2.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2015 through 2017.

12.
Derivative Instruments
We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory or cash flow hedges of its future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2015, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2015
In March 2015, Sharp entered into a put option to protect against a decline in propane prices and related potential inventory losses associated with 630,000 gallons committed to be purchased for the propane price cap program in the upcoming heating season. The put option is exercised if propane prices fall below the strike price of $0.4950 per gallon in December 2015 through February 2016. We will receive the difference between the market price and the strike price during those months. We paid $43,000 to purchase the put option. We accounted for the put option as a fair value hedge, and there is no ineffective portion of this hedge. As of March 31, 2015, the put option had a fair value of $38,000. The change in fair value of the put option effectively reduced our propane inventory balance.
In March 2015, Sharp entered into a swap agreement to mitigate the risk of fluctuations in wholesale propane index prices associated with 630,000 gallons expected to be purchased for the upcoming heating season. Under the swap agreement, Sharp receives the difference between the index prices (Mont Belvieu prices in December 2015 through February 2016) and the swap price of $0.5950 per gallon, to the extent the index prices exceed the swap price. If the index prices are lower than the swap price, Sharp will pay the difference. The swap agreement essentially fixes the price of the 630,000 gallons that we expect to purchase for the upcoming heating season. We accounted for the swap agreement as a cash flow hedge, and there is no ineffective portion of this hedge. At March 31, 2015, the swap agreement had a liability fair value of $12,000. The change in the fair value of the swap agreement is recorded as unrealized gain/loss in other comprehensive income (loss).
Hedging Activities in 2014
In August and October 2014, Sharp entered into call options to protect against an increase in propane prices associated with 1.3 million gallons we expected to purchase at market-based prices to supply the demands of our propane price cap program customers. The retail price that we can charge to those customers during the heating season is capped at a pre-determined level. We would have exercised the call options if the propane prices had risen above the strike price of $1.0875 per gallon in December 2014 through February of 2015 and $1.0650 per gallon in January through March 2015. In that event, we would have received the difference between the market price and the strike price during those months. We paid $98,000 to purchase the call options, which expired without exercise as the market prices were below the strike prices. We accounted for the call options as cash flow hedges.
In May 2014, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 630,000 gallons we expected to purchase for the upcoming heating season. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2014 through February 2015) and the swap prices of $1.1350, $1.0975 and $1.0475 per gallon for each swap agreement, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap prices, Sharp would pay the difference. These swap agreements essentially fixed the price of those 630,000 gallons purchased for the upcoming heating season. We had initially accounted for them as cash flow hedges as the swap agreements met all the requirements. We paid $1.1 million, representing the difference between the market prices and strike prices during those months for the swap agreements. At December 31, 2014, we elected to discontinue hedge accounting on the swap agreements and reclassified $735,000 of unrealized loss from other comprehensive loss to propane cost of sales. Subsequently, we

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accounted for them as derivative instruments on a mark-to-market basis with the change in the fair value reflected in current period earnings.
In May 2014, Sharp entered into put options to protect against declines in propane prices and related potential inventory losses associated with 630,000 gallons purchased for the propane price cap program in the upcoming heating season. We exercised the put options because the propane prices fell below the strike prices of $1.0350, $0.9975, and $0.9475 per gallon, for each option agreement in December 2014 through February 2015, respectively. We paid $128,000 to purchase the put options and we received $868,000, representing the difference between the market prices and strike prices during those months. We accounted for them as fair value hedges.
Commodity Contracts for Trading Activities
Xeron engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income for the period of change. As of March 31, 2015, we had the following outstanding trading contracts, which we accounted for as derivatives: 
 
Quantity in
 
Estimated Market
 
Weighted Average
At March 31, 2015
Gallons
 
Prices
 
Contract Prices
Forward Contracts
 
 
 
 
 
Sale
420,000

 
$
0.4788

 
$
0.4788

Purchase
421,000

 
$
0.4775

 
$
0.4789

Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the second quarter of 2015.

Xeron has entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At March 31, 2015, Xeron had a right to offset $1.9 million and $2.3 million of accounts receivable and accounts payable, respectively, with these two counterparties. At December 31, 2014, Xeron had a right to offset $1.6 million and $1.2 million of accounts receivable and accounts payable, respectively, with these two counterparties.
The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency.
The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of March 31, 2015 and December 31, 2014, are as follows: 
 
 
Asset Derivatives
 
 
 
 
Fair Value As Of
(in thousands)
 
Balance Sheet Location
 
March 31, 2015
 
December 31, 2014
Derivatives not designated as hedging instruments
 
 
 
 
 
 
Forward contracts
 
Mark-to-market energy assets
 
$
8

 
$
407

Derivatives designated as fair value hedges
 
 
 
 
 
 
        Put option(s)
 
Mark-to-market energy assets
 
38

 
622

Derivatives designated as cash flow hedges
 
 
 
 
 
 
Call option
 
Mark-to-market energy assets
 
—

 
26

Total asset derivatives
 
 
 
$
46

 
$
1,055


 

- 20

 
 
Liability Derivatives
 
 
 
 
Fair Value As Of
(in thousands)
 
Balance Sheet Location
 
March 31, 2015
 
December 31, 2014
Derivatives not designated as hedging instruments
 
 
 
 
 
 
Forward contracts
 
Mark-to-market energy liabilities
 
$
8

 
$
283

Propane swap agreements
 
Mark-to-market energy liabilities
 
—

 
735

Derivatives designated as cash flow hedges
 
 
 
 
 
 
Propane swap agreement
 
Mark-to-market energy liabilities
 
12

 
—

Total liability derivatives
 
 
 
$
20

 
$
1,018

 

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows: 
  
 
 
 
Amount of Gain (Loss) on Derivatives:
 
 
Location of Gain
 
For the Three Months Ended March 31,
(in thousands)
 
(Loss) on Derivatives
 
2015
 
2014
Derivatives not designated as hedging instruments
 
 
 
 
 
 
Realized gain on forward contracts (1)
 
Revenue
 
$
277

 
$
1,246

Unrealized loss on forward contracts
 
Revenue
 
(125
)
 
(68
)
Call option
 
Cost of sales
 
—

 
137

Propane swap agreements
 
Cost of sales
 
(717
)
 
—

Derivatives designated as fair value hedges
 
 
 
 
 
 
Put options
 
Cost of sales
 
506

 
(20
)
Put option (2)
 
Propane Inventory
 
(3
)
 
—

Derivatives designated as cash flow hedges
 
 
 
 
 
 
Propane swap agreement
 
Other Comprehensive loss
 
(12
)
 
—

Call options
 
Cost of sales
 
(81
)
 
—

Total
 
 
 
$
(155
)
 
$
1,295


(1) 
All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income.
(2) 
As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this put option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory.
 
13.
Fair Value of Financial Instruments
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and
Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).

Financial Assets and Liabilities Measured at Fair Value
The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of March 31, 2015 and December 31, 2014:

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Fair Value Measurements Using:
As of March 31, 2015
 
Fair Value
 
Quoted Prices in
Active Markets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
(in thousands)
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Investments—guaranteed income fund
 
$
280

 
$
—

 
$
—

 
$
280

Investments—other
 
$
3,490

 
$
3,490

 
$
—

 
$
—

Mark-to-market energy assets, incl. put/call options
 
$
46

 
$
—

 
$
46

 
$
—

Liabilities:
 
 
 
 
 
 
 
 
Mark-to-market energy liabilities incl. swap agreements
 
$
20

 
$
—

 
$
20

 
$
—

 
 
 
 
 
Fair Value Measurements Using:
As of December 31, 2014
 
Fair Value
 
Quoted Prices in
Active Markets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
(in thousands)
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Investments—guaranteed income fund
 
$
287

 
$
—

 
$
—

 
$
287

Investments—other
 
$
3,391

 
$
3,391

 
$
—

 
$
—

Mark-to-market energy assets, incl. put/call options
 
$
1,055

 
$
—

 
$
1,055

 
$
—

Liabilities:
 
 
 
 
 
 
 
 
Mark-to-market energy liabilities, incl. swap agreements
 
$
1,018

 
$
—

 
$
1,018

 
$
—


The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of March 31, 2015 and December 31, 2014:
Level 1 Fair Value Measurements:
Investments- equity securities—The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.
Investments- other—The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.
Level 2 Fair Value Measurements:
Mark-to-market energy assets and liabilities—These forward contracts are valued using market transactions in either the listed or OTC markets.
Propane put/call options and swap agreements—The fair value of the propane put/call options and swap agreements are determined using market transactions for similar assets and liabilities in either the listed or OTC markets.
Level 3 Fair Value Measurements:
Investments- guaranteed income fund—The fair values of these investments are recorded at the contract value, which approximates their fair value.

- 22

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the three months ended March 31, 2015 and 2014:
 
 
Three Months Ended 
 March 31,
 
2015
 
2014
(in thousands)
 
 
 
Beginning Balance
$
287

 
$
458

Purchases and adjustments
(5
)
 
(94
)
Transfers
(3
)
 
—

Investment income
1

 
1

Ending Balance
$
280

 
$
365


Investment income from the Level 3 investments is reflected in other income (loss) in the accompanying condensed consolidated statements of income.

At March 31, 2015, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.
Other Financial Assets and Liabilities
Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement).
At March 31, 2015, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $161.4 million. This compares to a fair value of $182.2 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2014, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of $161.5 million, compared to the estimated fair value of $180.7 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.


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14.
Long-Term Debt
Our outstanding long-term debt is shown below: 
 
 
March 31,
 
December 31,
(in thousands)
 
2015
 
2014
FPU secured first mortgage bonds (1) :
 
 
 
 
9.08% bond, due June 1, 2022
 
$
7,971

 
$
7,969

Uncollateralized senior notes:
 
 
 
 
6.64% note, due October 31, 2017
 
8,182

 
8,182

5.50% note, due October 12, 2020
 
12,000

 
12,000

5.93% note, due October 31, 2023
 
27,000